Attached files
| file | filename |
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| 8-K - 8-K - EARTHSTONE ENERGY INC | form8-kq4x2019earningsrele.htm |
| EX-99.1 - EXHIBIT 99.1 - EARTHSTONE ENERGY INC | ex991q42019earningsrelease.htm |
Exhibit 99.2 Investor Presentation March 11, 2020 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 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 2020 production, capital expenditure and operating expense guidance. The actual levels of production, capital expenditures and operating expenses may be higher or lower than these estimates due to, among other things, uncertainty in drilling schedules, changes in market demand and unanticipated delays in production. These estimates are based on numerous assumptions. All or any of these assumptions may not prove to be accurate, which could result in actual results differing materially from estimates. No assurance can be made that any new wells will produce in line with historical performance, or that existing wells will continue to produce in line with expectations. Earthstone’s ability to fund its 2020 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 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: Leading Small-Cap, Permian Focused Producer Top Investment Criteria Earthstone’s Qualifications Basin & Acreage High quality, Midland Basin acreage position Position ✓ Low Leverage ✓ Conservative balance sheet with ~1.0x leverage(1) High Commodity Price 78% of 2020 oil production hedges at fixed price of ~$60 per barrel Protection ✓ WTI price ($80.3mm MTM of hedge book as of 3/9/20) High Margin, Low Cost Top quartile cash margins & leading cost structure with ~$13.50 per Production ✓ Boe of all-in cash costs(2) “Do the right thing” commitment to stakeholders, employees and Commitment & Focus ✓ environment (1) Reflects 4Q19 total debt / 4Q19 Annualized EBITDAX of 0.9x (2) All-in cash costs measured for full year 2019 and includes lease operating expenses, ad valorem and production taxes, transportation expense, cash G&A expense and interest 3 expense. Excludes impact of income taxes
Delivering Results – 2019 Results vs. Guidance Total Oil CAPEX LOE Cash G&A Production Production +14% +11% +3% -2% -19% 13,429 8,463 $210.4 11,750 7,638 $205.0 $6.50 $4.75 $6.40 $3.87 (Boepd) (Bopd) ($MM) ($/Boe) (2) ($/Boe) Guidance (1) Actual (1) Based on midpoint of FY2019 guidance where applicable (2) Reflects lease operating expenses calculated based on prior methodology (including ad valorem tax). Reported LOE is $0.55 lower due to accounting change by removing ad valorem tax 4
Oil Price Volatility Requires Focused Business Strategy . WTI trading in range of $40-70 per barrel vs. $80-110 per barrel since OPEC / Shale standoff commenced in 2H 2014 — Industry re-geared cost structure and improved efficiencies to create sustainability / profitability . Commodity cycle velocity has doubled: 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 WTI Crude Oil Spot Price Since 2009 $140 Post Financial Crisis – OPEC/Shale Standoff $120 Bear market $110 every 7 months $100 OPEC/Shale Standoff - Current $80 $80 -34% -29% $70 $60 -25% Bear market every 17 months -21% -23% $40 $40 -22% -43% -61% -23% -37% -51% -47% $20 Feb-09 Feb-10 Feb-11 Feb-12 Feb-13 Feb-14 Feb-15 Feb-16 Feb-17 Feb-18 Feb-19 Feb-20 Source: Factset data as of 3/9/2020 5
Managing Through Oil Price Volatility May 2017 October 2017 December 2017 Acquired 20,900 Net $40MM Divested Bakken Acres from Bold Energy, December 2015 June 2016 Common Assets for $27MM Announces Acquisition of $45MM Common LLC in Midland Basin Equity Lynden Energy Corp.; ESTE Equity Offering Offering $80 20,000 Enters the Midland Basin 17,571 $70 16,000 $60 12,699 12,181 $50 ($/Bbl) WTI 12,000 11,209 10,766 10,454 9,671 9,664 $40 9,071 8,845 7,932 8,000 $30 Total Daily Production(Boe/d) Daily Total 4,517 4,646 4,685 4,735 $20 3,849 3,872 3,759 3,979 4,000 3,576 $10 0 $0 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18 4Q18 1Q19 2Q19 3Q19 4Q19 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18 4Q18 1Q19 2Q19 3Q19 4Q19 EBITDAX ($MM) $5 $9 $8 $4 $2 $5 $3 $7 $5 $15 $19 $22 $25 $21 $26(3) $24 $32 $34 $30 $50 Capex ($MM) (1) $19 $29 $18 $3 $2 $4 $9 $13 $4 $6 $20 $39 $33 $35 $52 $30 $48 $31 $78 $58 Total Debt / LQA EBITDAX 0.5x 0.3x 0.4x 0.6x 1.4x 0.8x 1.3x 0.5x 0.7x 1.2x 1.0x 0.3x 0.3x 0.3x 0.3x 0.8x 0.9x 0.8x 1.0x 0.9x Liquidity ($MM) (2) $128 $113 $110 $92 $74 $84 $89 $80 $80 $97 $91 $183 $166 $207 $203 $197 $155 $221 $210 $169 Liquidity % 92% 91% 91% 89% 87% 89% 90% 89% 89% 58% 57% 88% 85% 90% 85% 71% 56% 67% 63% 50% Source: ESTE management, FactSet, public filings (1) Reflects additions to oil and gas properties (2) Liquidity defined as revolver availability plus cash (3) 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 6 settlement 3Q’2018 adjusted EBITDAX of $31.2MM by three and adding $26.4MM
Company Overview The Woodlands, Texas based E&P company focused on development and production of oil and natural gas with current operations in the Midland Basin Asset Overview Midland Basin (~29,100 core net acres) and the Eagle Ford (~14,500 core net acres) Strategy of growing through the drill bit, organic leasing, and attractive asset acquisitions and business combinations (1) 2019 4Q production of 17,571 Boe/d (66% oil, 86% liquids) Market Statistics(2) ($ in millions, except share price) Class A Common Stock (MM) 29.5 Class B Common Stock (MM) 35.3 Total Common Stock Oustanding (MM) 64.8 Stock Price (as of 3/9/20) $2.48 Market Capitalization $160.6 Plus: Total Debt (as of 12/31/19) $170.0 Less: Cash (as of 12/31/19) (13.8) Enterprise Value $316.8 Production Summary(1) 4Q19 Net Sales Volumes: 17,571 Boe/d Eagle Ford ESTE Operated 2,294 ESTE Operated ESTE Non-Operated ESTE Non-Operated Midland Basin 15,277 (1) Reflects reported sales volumes (2) Class A and Class B Common Stock outstanding as of 3/5/20. Total debt and cash balances as of 12/31/19 7
Midland Basin Growth Story . Since entering the Midland Basin in 2016, Earthstone has substantially increased production, proved reserves and core acreage while maintaining low leverage and preserving financial flexibility . The Company has meaningfully derisked its current position through the drill bit while significantly increasing its production Average Daily Production (Boe/d)(1) Adjusted EBITDAX ($MM) $180.0 20,000 $146.3 16,000 $150.0 15,000 13,429 $120.0 $97.0 9,937 $90.0 10,000 7,869 $60.6 $60.0 11,846 5,000 4,002 7,999 $30.0 $18.7 4,696 0 1,180 $0.0 FY16A FY17A FY18A FY19A 2020 (2) FY16A FY17A FY18A FY19A Guidance Midland Basin Other Lease Operating Expense and Cash G&A ($/Boe)(3) Debt / LTM EBITDAX 2.0x $20.00 $16.72 1.6x $13.97 $15.00 1.2x $6.43 $11.47 1.2x $9.72 $9.25 0.9x $10.00 $7.13 0.8x $5.81 0.8x $3.87 $3.50 0.4x $5.00 $10.29 0.4x $6.84 $5.66 $5.85 $5.75 $0.00 – FY16AFY17AFY18AFY19AFY20(2) FY16AFY17AFY18AFY19A Guidance Lease Operating Expenses ($/Boe) Cash G&A ($/Boe) (1) Represents reported sales volumes (2) Reflects midpoint of FY2020 guidance. Guidance subject to change (3) Excludes stock-based compensation 8
Low Cost Production Generates Leading Cash Margins FY19 All-in Cash Costs ($/Boe) (1) $40.00 ESTE: Large-Cap (2) Avg: Mid-Cap (2) Avg: Small-Cap (2) Avg: $13.48 $11.96 $15.03 $16.36 $30.00 $24.59 $19.41 $20.00 $17.50 $16.75 $15.11 $16.01 $13.48 $15.02 $14.63 $12.39 $13.29 $11.87 $10.20 $10.30 $9.47 $10.00 $0.00 ESTE Peer Peer Peer Peer Peer Peer Peer Peer Peer Peer Peer Peer Peer Peer 1 2 3 4 5 6 7 8 9 10 11 12 13 14 LOE (incl Workovers) Ad Val. & Prod. Taxes Transportation Cash G&A Interest Expense FY19 All-in Cash Margin ($/Boe) (1) $60.00 ESTE: Large-Cap (2) Avg: Mid-Cap (2) Avg: Small-Cap (2) Avg: $28.78 $26.22 $20.12 $20.81 $45.00 $28.78 $30.00 $26.96 $27.80 $26.86 $23.90 $24.86 $25.04 $22.22 $21.79 $18.79 $19.59 $18.62 $17.64 $15.98 $15.00 $12.68 $0.00 ESTE Peer Peer Peer Peer Peer Peer Peer Peer Peer Peer Peer Peer Peer Peer 1 2 3 4 5 6 7 8 9 10 11 12 13 14 (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, CXO, FANG, and MTDR (2) Large-Cap includes: CXO, FANG, PXD. Mid-Cap includes: CDEV, CPE, MTDR, SM, PE, WPX, XEC. Small-Cap includes: AXAS, LPI, ROSE, REI. AXAS, ROSE and REI have not reported 4Q19 financials and are based on YTD3Q19 results; all other peers based on reported FY19 financial results 9
Leading Leverage Metrics but Undervalued Equity Trading YE19 Total Debt / LTM EBITDAX 6.0x ESTE: Large-Cap (1) Avg: Mid-Cap (1)(2) Avg: Small-Cap (1) Avg: 1.2x 1.2x 2.1x 2.4x 4.5x 3.1x 2.9x 3.0x 2.6x 2.6x 2.5x 2.1x 1.8x 1.8x 1.9x 1.5x 1.6x 1.3x 1.5x 1.2x 1.3x 0.6x – ESTE Peer Peer Peer Peer Peer Peer Peer Peer Peer Peer Peer Peer Peer Peer 1 2 3 4 5 6 7 8 9 10 11 12 13 14 Enterprise Value to 2020E EBITDAX 8.0x ESTE: Large-Cap (1) Avg: Mid-Cap (1) Avg: Small-Cap (1) Avg: 1.9x 3.5x 2.5x 3.0x 6.0x 4.1x 3.9x 4.0x 3.6x 3.2x 3.2x 2.8x 2.9x 3.0x 2.5x 2.6x 2.2x 2.4x 1.9x 2.1x 2.0x 1.7x – ESTE Peer Peer Peer Peer Peer Peer Peer Peer Peer Peer Peer Peer Peer Peer 1 2 3 4 5 6 7 8 9 10 11 12 13 14 Source: Factset, Wall Street research. Market Data as of 3/9/20 (1) Large-Cap includes: CXO, FANG, PXD. Mid-Cap includes: CDEV, CPE, MTDR, SM, PE, WPX, XEC. Small-Cap includes: AXAS, LPI, ROSE, REI. AXAS, ROSE and REI have not reported 4Q19 financials and are based on YTD3Q19 results; all other peers based on reported FY19 financial results (2) CPE’s LTM EBITDAX is adjusted for its acquisition of CRZO 10
Continuous Focus on Operational Improvement . A continued focus on driving down costs and increased efficiencies achieved by developing larger pads and driving down drilling and completion days Actual Drilling, Completions & Equip. Cost ($/Lat Ft.) (1) Average Number of Wells Per Pad $1,500 5.0 $1,200 4.0 3.8 $1,008 $926 $900 $845 3.0 2.4 $600 2.0 1.7 1.8 $300 1.0 $0 0.0 2H17 FY18 FY19 2017 2018 2019 2020 All-in Frac Costs per Stage ($/Stage) Spud to Rig Release Days per 1,000’ (1)(2) $100,000 3.0 2.6 $80,854 $77,167 $75,000 2.0 2.0 $61,884 2.0 $56,600 $50,000 1.0 $25,000 $0 0.0 1H18 2H18 1H19 2H19 2H17 FY18 FY19 (1) Excludes wells that required additional casing string or pilot well test. Includes operated Midland Basin wells only 11 (2) Spud to rig release days = average spud to rig release days / (average completed lateral foot/1000)
Highly Focused Environmental Stewardship Key Environmental Priorities Focus on Responsible Operatorship Installation of Vapor Recovery Units (“VRUs”) in conjunction with tank battery construction minimizes air emissions Target Zero Flaring: Connect natural gas pipelines ahead of flowback and first production negates need for flaring Started implementation of Leak Detection & Repair (“LDAR”) program in 2019 to further minimize air emissions Seek to increase Midland Basin oil on pipelines from the wellhead from 12% of production in 2019 to 46% of production in 2020 Plan for 100% of water disposal on pipeline in the Midland Basin to reduce truck hauls At Earthstone, maintaining environmentally sustainable business practices is a top priority 12
Asset Overview 13
Areas of Operations Total (1) Midland Basin (1) Total Proved Reserves (Mmboe) 94.3 Total Proved Reserves (Mmboe) 89.5 % Proved Developed 33% % Proved Developed 30% % Oil 56% % Oil 54% Total Proved PV-10 ($mm) $820 Total Proved PV-10 ($mm) $725 4Q19 Net Production (Boe/d)(2) 17,571 4Q19 Net Production (Boe/d)(2) 15,277 Gross Producing Wells(3) 354 Gross Producing Wells(3) 230 Net Acres(3) 43,600 Net Acres(3) 29,100 Gross Drilling Locations(3) 512 Gross Drilling Locations(3) 450 Eagle Ford (1) Total Proved Reserves (Mmboe) 4.8 % Proved Developed 100% % Oil 85% Total Proved PV-10 ($mm) $95 4Q19 Net Production (Boe/d)(2) 2,294 Gross Producing W ells(3) 124 Net Acres(3) 14,500 Gross Drilling Locations(3) 62 (1) Reserves and PV10 based on SEC 12/31/19 CGA reserve report (2) Represents reported sales volumes (3) As of 12/31/19 14
Differentiated, Balanced Inventory in Midland Basin Midland Basin Overview Gross Locations by Lateral Length and Target . Contiguous acreage positions provide significant development advantage Gross Locations by Lateral Length 5,000' - 7,500' - Target 10,000'+ Total % Total . Long lateral development increases capital efficiency 7,500' 10,000' Wolfcamp A 7 47 67 121 27% . Over 90% of Midland horizontal locations have laterals of ~7,500 feet or greater Wolfcamp B Upper 11 16 68 95 21% Wolfcamp B Lower 9 46 54 109 24% . Additional upside from: All Other Targets 1 37 87 125 28% – Middle Spraberry Total Gross Locations 28 146 276 450 100% – Jo Mill Total Net Locations 23 103 146 273 – Additional Lower Spraberry Targets % Total (Gross) 6% 32% 61% 100% – Additional benches in Wolfcamp B – Wolfcamp D . Actively pursuing acreage and acquisition bolt-on opportunities to Midland Basin Locations by Op / Non-Op increase lateral lengths and ownership Gross Net Average Average % of Gross . Near-term drilling focused in the Wolfcamp A and the Wolfcamp B based on positive offset results, but we are optimistic about the Locations Locations LL WI Locations in WC A+B upside potential in other zones Operated 269 221 8,773 82% 80% Non-Operated 181 51 9,446 28% 60% Total 450 273 9,044 61% 72% Note: Gross location count includes only economic locations in 12/31/19 CGA reserve report 15
Midland Basin Type Curve Summary Generating attractive returns across the acreage position 2020 drilling program focused in Upton and Midland Counties Type curves take into account impact from parent/child and co-development Midland County (1) Upton County (1) Reagan County (1) 500,000 500,000 500,000 400,000 400,000 400,000 300,000 300,000 300,000 200,000 200,000 200,000 2-Stream BOE Normalized 2-Stream to BOE Normalized 10,000' 100,000 100,000 100,000 to 2-Stream BOE Normalized 10,000' 2-Stream BOE Normalized to Normalized 2-Stream BOE 10,000' 0 0 0 0 100 200 300 400 500 600 700 800 0 100 200 300 400 500 600 700 800 0 100 200 300 400 500 600 700 800 Days on Production Normalized to Time Zero Days on Production Normalized to Time Zero Days on Production Normalized to Time Zero Midland County - Actuals (11 ESTE Operated Wells, 2016+) Upton County - Actuals (5 ESTE Operated Wells, 2016+) Reagan County - Actuals (36 ESTE Operated Wells, 2016+) Midland County - Type Curve Upton County - Type Curve Reagan County - Type Curve Type Curve Summary (100% WI / 75% NRI) (2) Lat. Length DC & E 3-Stream EUR Oil Gas NGL IRR IRR Type Curve Area (ft) ($M) (Mboe) (%) (%) (%) $50/$2.00 $60/$2.00 Midland 10,000 $8,000 1,170 64% 15% 21% 57% 89% Upton 10,000 $8,000 930 60% 16% 24% 40% 64% Reagan 10,000 $7,500 1,170 42% 24% 35% 30% 47% (1) Cumulative 2-stream BOE normalized to 10,000 feet. Reflects average cumulative production of operated wells completed in 2016-2019 (2) Single well rates of return assumes 3-stream economics on flat price deck of Oil - $50.00 and $60.00/Bbl, Gas - $2.00/Mcf before deductions for transportation, gathering, and quality differential. Assumes NGL differential realizations to be 25% of WTI. Assumes three months from spud to first production 16
Financial Overview 17
Capital Budget, Guidance and Liquidity . 2020 Capital Budget and Guidance (provided in January 2020) currently being re-evaluated and subject to change . No long-term service contracts and currently negotiating drilling obligation deferrals into 2021 ESTE 2020 Capital Budget 2020 FY Guidance 2020 Average Daily Production (Boe/d) 15,500 - 16,500 Gross / Net Net Operated Non-Op % Oil 63% - 65% ($ in millions) Wells On Line Wells On Line % Liquids 82% - 84% Drilling and Completion $145 - $155 19 / 16.2 3.1 Land / Infrastructure $15 Operating Costs: Total $160 - $170 Lease Operating(2) ($/Boe) $5.50 - $6.00 Cash G&A ($/Boe) $3.25 - $3.75 (2) Production and Ad Valorem Taxes (% of Revenue) 6.25% - 7.25% 2020 Capital Budget Breakdown(1) Liquidity (12/31/2019) ($mm) 12/31/2019 9% Cash $13.8 Revolver Borrowings 170.0 Total Debt $170.0 Revolver Borrowing Base 325.0 91% Less: Revolver Borrowings (170.0) Plus: Cash 13.8 Drilling and Completion Land / Infrastructure Liquidity $168.8 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” (1) Reflects midpoint of FY2020E Guidance 18
Hedge Book Summary – 100% 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 FY 2020 2,928,000 8,000 $60.31 FY 2020 2,562,000 7,000 $2.850 FY 2021 1,095,000 3,000 $55.00 WTI Midland Argus Crude Basis Swaps WAHA Differential Basis Swaps Period Volume (Bbls) Volume (Bbls/d) $/Bbl (Differential) Period Volume (MMBtu) Volume (MMBtu/d) $/MMBtu FY 2020 2,562,000 7,000 ($1.40) FY 2020 2,562,000 7,000 ($1.065) FY 2021 1,825,000 5,000 $1.05 MEH Crude Oil Basis Swaps Period Volume (Bbls) Volume (Bbls/d) $/Bbl (Differential) FY 2020 366,000 1,000 $2.55 Oil Production Swaps(1) Gas Production Swaps (Volumes in Bbls/d) (Volumes in MMBtu/d) Oil ~78% Hedged Gas ~43% Hedged (2) of FY20 Guidance (2) 10,000 12,000 of FY20 Guidance 8,000 8,000 7,500 9,000 7,000 7,000 5,000 5,000 6,000 3,000 2,500 3,000 0 0 FY20 FY21 FY20 Oil Swaps Crude Basis Swaps Gas Swaps WAHA Basis Swaps ESTE hedge book mark-to-market value (as of 3/9/20): ~$80.3mm (1) Crude basis swaps reflect Midland Argus, LLS Argus and MEH crude basis swaps (2) Based on midpoint of 2020 guidance (15,500 – 16,500 Boe/d; 64% oil, 17% gas) 19
Analyst Coverage Firm Analyst Contact Info Alliance Global Partners Bhakti Pavani / 949-296-3196 / bpavani@allianceg.com Baird Joseph Allman / 646-557-3209 / jdallman@rwbaird.com Coker Palmer Noel Parks / 215-913-7320 / parks@cokerpalmer.com Imperial Capital Jason Wangler / 713-892-5603 / jwangler@imperialcapital.com Johnson Rice Dun McIntosh / 504-584-1217 / dun@jrco.com Northland Jeff Grampp / 949-600-4150 / jgrampp@northlandcapitalmarkets.com RBC Brad Heffern / 512-708-6311 / brad.heffern@rbccm.com Roth John White / 949-720-7115 / jwhite@roth.com Stephens Gail Nicholson / 301-904-7466 / gail.nicholson@stephens.com SunTrust Neal Dingmann / 713-247-9000 / neal.dingmann@suntrust.com Wells Fargo Nitin Kumar / 212-214-8022 / nitin.kumar2@wellsfargo.com 20
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 21
Appendix 22
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 income plus, when applicable, loss (gain) on sale of oil and gas properties, net; accretion of asset retirement obligations; impairment expense; depletion, depreciation and amortization; transaction costs; interest expense, net; exploration expense; unrealized loss (gain) on derivative contracts; stock based compensation (non-cash); and income tax expense (benefit). Earthstone excludes the foregoing items from net income (loss) in arriving at Adjusted EBITDAX because these amounts can vary substantially from company to company within their industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDAX should not be considered as an alternative to, or more meaningful than, net income (loss) as determined in accordance with GAAP or as an indicator of Earthstone’s operating performance or liquidity. Certain items 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: 4Q19 Adjusted EBITDAX ($ in 000s) FY 2019 Adjusted EBITDAX ($ in 000s) 4Q 19 FY 19 Net (loss) income ($5,640) Net (loss) income $1,580 Accretion of asset retirement obligations $54 Accretion of asset retirement obligations $214 Impairment expense $0 Impairment expense $0 Depletion, depreciation and amortization $26,962 Depletion, depreciation and amortization $69,243 Interest expense, net $1,831 Interest expense, net $6,566 Transaction costs $279 Transaction costs $1,077 (Gain) loss on sale of oil and gas properties, net ($3,668) (Gain) loss on sale of oil and gas properties, net ($3,222) Exploration expense $653 Exploration expense $653 Unrealized loss (gain) on derivative contracts $26,517 Unrealized loss (gain) on derivative contracts $59,849 Stock based compensation (non-cash) (1) $1,968 Stock based compensation (non-cash) (1) $8,648 Income tax expense $937 Income tax expense $1,665 Adjusted EBITDAX $49,893 Adjusted EBITDAX $146,273 (1) Included in General and administrative expense in the Consolidated Statements of Operations 23
Reserves Summary Earthstone’s proved reserves as of December 31, 2019 were independently estimated by Cawley, Gillespie & Associates, Inc. (“CGA”), independent petroleum engineers, utilizing SEC prescribed oil and gas prices of $55.69/bbl and $2.578/mmbtu, respectively, calculated for December 31, 2019. SEC prices net of differentials were $52.60/bbl and $0.91/Mcf for oil and gas, respectively. Year-End 2019 SEC Proved Reserves Oil Gas NGL Total PV-10 Reserves Category (Mbbls) (MMcf) (Mbbls) (Mboe) ($ in thousands) Proved Developed 18,220 35,120 7,447 31,521 $448,533 Proved Undeveloped 34,430 72,870 16,241 62,815 $371,459 Total 52,650 107,990 23,688 94,336 $819,992 Note: PV-10 is a non-GAAP financial measure. See “Non-GAAP Financial Measure – PV-10” 24
Non-GAAP Financial Measure – PV-10 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) $819,992 Future income taxes, discounted at 10% ($30,415) Standardized measure of discounted future net cash flows $789,577 25