8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d)

of the Securities Exchange Act of 1934

Date of Report: March 17, 2020

(Date of earliest event reported)

(Exact name of registrant as specified in its charter)

Delaware	001-35049	84-0592823
(State or other jurisdiction of incorporation)	(Commission File Number)	(IRS Employer Identification No.)

1400 Woodloch Forest Drive, Suite 300

The Woodlands, Texas 77380

(Address of principal executive offices) (Zip Code)

(281) 298-4246

(Registrant’s telephone number, including area code)

(Former name or former address, if changed since last report)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

☐ Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

☐ Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

☐ Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

☐ Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Class A Common Stock, $0.001 par value per share	ESTE	New York Stock Exchange (NYSE)

Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (§230.405 of this chapter) or Rule 12b-2 of the Securities Exchange Act of 1934 (§240.12b-2 of this chapter).

Emerging growth company ☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.  ☐

Item 7.01 Regulation FD Disclosure.

On March 17, 2020, Earthstone Energy, Inc. (the “Company”) issued a press release providing an update to its 2020 capital plan and guidance. Please note that, after publication of the press release, the Company discovered and corrected a column title and added a column that was inadvertently omitted to the 2020 Updated Guidance Overview table on page 2 of Exhibit 99.1. The corrected version of the press release is attached to this Current Report on Form 8-K as Exhibit 99.1 and is incorporated herein by reference.

Additionally, on March 17, 2020, the Company posted to its website a company presentation (the “Presentation Materials”) that management intends to use from time to time about the Company’s 2020 guidance. The Company may use the Presentation Materials, possibly with modifications, in presentations to current and potential investors, lenders, creditors, vendors, customers and others with an interest in the Company and its business.  A copy of the Presentation Materials is attached to this Current Report on Form 8-K as Exhibit 99.2 and is incorporated herein by reference.

The information in this Current Report on Form 8-K furnished pursuant to Item 7.01, including Exhibit 99.1 and Exhibit 99.2, shall not be deemed to be “filed” for the purposes of Section 18 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), or otherwise subject to liability under that section, and they shall not be deemed incorporated by reference in any filing under the Securities Act of 1933, as amended, or the Exchange Act, except as shall be expressly set forth by specific reference in such filing. By filing this Current Report on Form 8-K and furnishing this information pursuant to Item 7.01, the Company makes no admission as to the materiality of any information in this Current Report on Form 8-K, including Exhibit 99.1 and Exhibit 99.2, that is required to be disclosed solely by Regulation FD.

Item 9.01 Financial Statements and Exhibits.

(d) Exhibits.

The following exhibits are included with this Current Report on Form 8-K:

Exhibit No.	Description
99.1	Press Release dated March 17, 2020
99.2	Presentation Materials dated March 17, 2020

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

	EARTHSTONE ENERGY, INC.
Date: March 17, 2020	By:	/s/ Tony Oviedo
		Tony Oviedo
		Executive Vice President - Accounting and Administration

EX-99.1

Exhibit 99.1

Earthstone Provides Updated 2020 Capital Plan and Guidance

Capital Expenditures Reduced by 67%

The Woodlands, Texas, March 17, 2020 – Earthstone Energy, Inc. (NYSE: ESTE) (“Earthstone”, the “Company”, “our” or “we”), today provided an update to its 2020 operating plan and guidance based on the recent dramatic drop in oil prices.

2020 Updated Guidance

With the recent drop in oil prices, the Company plans to run one rig into the second quarter of 2020 and operated completion activity will be limited to three wells currently in progress. This reduction in activity will result in an adjusted capital budget for 2020 of $50 – $60 million. Along with non-operated completions, all brought online in the first quarter, our adjusted budget would result in bringing 3 gross / 3.0 net operated wells and 3.1 net non-operated wells online in 2020. We would also have 11 gross / 9.7 net operated wells drilled and waiting on completion. With a reduction in projected capital expenditures and fewer new wells coming online, we would expect lease operating expenses on a per Boe basis to increase modestly. A portion of this increase would also result from acceleration of certain remedial well work which, to a limited extent, would offset expected production declines.

Based on this adjusted 2020 operating plan, existing service costs and an assumed $30/Bbl WTI oil price, the Company expects to generate free cash flow, beginning in the second quarter of 2020. Free cash flow would be utilized to reduce borrowings currently outstanding under our revolving credit facility.

Management Comments

Robert J. Anderson, President of Earthstone, stated, “With the recent and very dramatic drop in oil prices, we have taken action to reduce our capital program swiftly. We are in an enviable position with no long-term contracts, low leverage, and very strong hedge position, which affords us the flexibility to adjust our capital plan quickly with no adverse impact on our balance sheet or current financial position.”

Mr. Anderson commented further, “This revised plan will allow the Company to generate free cash flow in the second quarter of 2020, without the assumption of any reductions in other operating costs. We expect to reduce our debt throughout the year and expect to end the year with net debt to Adjusted EBITDAX significantly lower than our year-end 2019 level of 1.1x. Even with a 67% reduction to our prior 2020 capital program, our reduced capital budget still provides for about a 6% increase in estimated production over 2019. Should oil prices improve in the near-term, we have the flexibility to maintain the rig longer and could quickly ramp up production with the eleven wells we have waiting on completion.”

Note: Adjusted EBITDAX, Net Debt to Adjusted EBITDAX and Free Cash Flow are non-GAAP measures reconciled below.

2020 Updated Guidance Overview

2020 Capital Expenditures	$ millions (Net)	Gross / Net Operated Wells Drilled and Waiting on Completion	Gross / Net Operated Wells On Line	Net Non-Operated Wells On Line
Drilling and Completions	$45 – 55	11 / 9.7	3 / 3.0	3.1
Land / Infrastructure	5
2020 Total Capital Expenditures	$50 – 60
2020 Average Daily Production (Boepd)	13,750 – 14,750
% Oil	60% – 64%
% Liquids	80% – 84%
2020 Operating Costs
Lease Operating ($/Boe)	$6.00 – $6.50
Cash G&A ($/Boe)	$3.25 – $3.75
Production and Ad Valorem Taxes (% of Revenue)	6.25% – 7.25%

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” section below.

Hedge Position Update

The Company restructured certain of its oil swaps to add protection to its 2021 cash flows by adding 1,000 Bopd of WTI swaps in 2021 at $55.65 per Bbl. Simultaneously, the Company reduced 2020 hedge volumes from 8,000 Bopd to 7,000 Bopd beginning in March 2020. All aforementioned hedges are fixed price swaps that afford the maximum downside protection. After adjusting for these changes, our oil swap position for the full year of 2020 is 7,164 Bopd, hedged at a WTI price of $60.99/Bbl, which is approximately 81% of the midpoint of our estimated oil production guidance. The following table presents our outstanding derivative contracts at March 13, 2020. When aggregating multiple contracts, the weighted average contract price is shown.

As of March 13, 2020:
Period	Commodity	Volume (Bbls / MMBtu)	Price ($/Bbl / $/MMBtu)
2020	Crude Oil Swap	2,622,000	$60.99
2020	Crude Oil Basis Swap (1)	366,000	$2.55
2020	Crude Oil Basis Swap (2)	2,562,000	$(1.40)
2020	Natural Gas Swap	2,562,000	$2.85
2020	Natural Gas Basis Swap (3)	2,562,000	$(1.07)
2021	Crude Oil Swap	1,460,000	$55.16
2021	Crude Oil Basis Swap (2)	1,825,000	$1.05

(1) The basis differential price is between WTI Houston and the WTI NYMEX.

(2) The basis differential price is between WTI Midland Argus Crude and the WTI NYMEX.

(3) The basis differential price is between W. Texas (WAHA) and the Henry Hub NYMEX.

About Earthstone

Earthstone Energy, Inc. is a growth-oriented, independent energy company engaged in developing and operating oil and gas properties. The Company’s primary assets are located in the Midland Basin of west

Texas and the Eagle Ford trend of south Texas. Earthstone is traded on the NYSE under the symbol “ESTE.” For more information, visit the Company’s website at www.earthstoneenergy.com.

Forward-Looking Statements

This release 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. 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 that involve various risks and uncertainties that could cause actual results to differ materially from those reflected in the statements. These risks include, but are not limited to, those set forth in Earthstone’s annual report on Form 10-K for the year ended December 31, 2019, subsequent quarterly reports on Form 10-Q and current reports on Form 8-K, and other Securities and Exchange Commission filings. Earthstone undertakes no obligation to revise or update publicly any forward-looking statements except as required by law.

Contact

Mark Lumpkin, Jr.

Executive Vice President – Chief Financial Officer

Earthstone Energy, Inc.

1400 Woodloch Forest Drive, Suite 300

The Woodlands, TX 77380

281-298-4246

mark.lumpkin@earthstoneenergy.com

Scott Thelander

Vice President of Finance

Earthstone Energy, Inc.

1400 Woodloch Forest Drive, Suite 300

The Woodlands, TX 77380

281-298-4246

scott@earthstoneenergy.com

Earthstone Energy, Inc.
Non-GAAP Financial Measures
Unaudited

The non-GAAP financial measures of Adjusted EBITDAX, Net Debt to Adjusted EBITDAX and Free Cash Flow, as defined and presented below, are intended to provide readers with meaningful information that supplements our financial statements prepared in accordance with accounting principles generally accepted in the United States (“GAAP”). Further, these non-GAAP measures should only be considered in conjunction with financial statements and disclosures prepared in accordance with GAAP and should not be considered in isolation or as a substitute for GAAP measures, such as net income or loss, operating income or loss or any other GAAP measure of financial position or results of operations.

I. Adjusted EBITDAX

The non-GAAP financial measure of Adjusted EBITDAX (as defined below), as calculated by us below, is intended to provide readers with meaningful information that supplements our financial statements prepared in accordance with GAAP. Further, this non-GAAP measure should only be considered in conjunction with financial statements and disclosures prepared in accordance with GAAP and should not be considered in isolation or as a substitute for GAAP measures, such as net income or loss, operating income or loss or any other GAAP measure of financial position or results of operations. Adjusted EBITDAX is presented herein and reconciled from the GAAP measure of net income because of its wide acceptance by the investment community as a financial indicator.

We define “Adjusted EBITDAX” as net income plus, when applicable, accretion of asset retirement obligations; impairment expense; depletion, depreciation and amortization; interest expense, net; transaction costs; (gain) on sale of oil and gas properties, net; exploration expense; unrealized loss on derivative contracts; stock-based compensation (non-cash); and income tax expense.

Our Adjusted EBITDAX measure provides additional information that may be used to better understand our operations. Adjusted EBITDAX is one of several metrics that we use as a supplemental financial measurement in the evaluation of our business and should not be considered as an alternative to, or more meaningful than, net income as an indicator of operating performance. 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 cost of depreciable and depletable assets. Adjusted EBITDAX, as used by us, may not be comparable to similarly titled measures reported by other companies. We believe that Adjusted EBITDAX is a widely followed measure of operating performance and is one of many metrics used by our management team and by other users of our consolidated financial statements. For example, Adjusted EBITDAX can be used to assess our operating performance and return on capital in comparison to other independent exploration and production companies without regard to financial or capital structure and to assess the financial performance of our assets and our company without regard to capital structure or historical cost basis.

The following table provides a reconciliation of Net income to Adjusted EBITDAX for the year ended December 31, 2019:

($000s)
Net income	$	1,580
Accretion of asset retirement obligations	214
Depletion, depreciation and amortization	69,243
Interest expense, net	6,566
Transaction costs	1,077
(Gain) on sale of oil and gas properties, net	(3,222		)
Exploration expense	653
Unrealized loss on derivative contracts	59,849
Stock based compensation (non-cash)(1)	8,648
Income tax expense	1,665
Adjusted EBITDAX	$	146,273

(1) Included in General and administrative expense in the Condensed Consolidated Statements of Operations.

II. Net Debt to Adjusted EBITDAX

We define “Net Debt to Adjusted EBITDAX” as Long-term debt, less cash, both as of period end, divided by Adjusted EBITDAX for the period then ended.

Our Net Debt to Adjusted EBITDAX measure provides additional information that may be used to further understand our liquidity. Net Debt to Adjusted EBITDAX is one of several metrics that we use as a supplemental financial measurement in the evaluation of our business.

The following table provides a reconciliation of Net Debt to Adjusted EBITDAX:

Long-term debt as of December 31, 2019	170,000
Less: Cash as of December 31, 2019	(13,822	)
Net Debt as of December 31, 2019	156,178
Divided by: Adjusted EBITDAX for the year ended December 31, 2019	146,273
Net Debt to Adjusted EBITDAX	1.1

III. Free Cash Flow

Free cash flow is a 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.

EX-99.2

Exhibit 99.2 Investor Presentation March 17, 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 81% of 2020 oil production hedges at fixed price of ~$61 per barrel Protection ✓ WTI price ($90.3mm MTM of hedge book as of 3/16/20) 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 3/16/20) $1.87 Market Capitalization $121.1 Plus: Total Debt (as of 12/31/19) $170.0 Less: Cash (as of 12/31/19) (13.8) Enterprise Value $277.3 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) 20,000 $180.0 $146.3 $150.0 14,250 15,000 13,429 $120.0 $97.0 9,937 10,000 7,869 $90.0 $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 $20.00 2.0x $16.72 $15.00 $13.97 1.6x $6.43 $11.47 1.2x $9.72 $9.75 1.2x $10.00 $7.13 0.9x $5.81 0.8x $3.87 $3.50 0.8x $5.00 $10.29 0.4x 0.4x $6.84 $5.66 $5.85 $6.25 $0.00 – (2) FY16A FY17A FY18A FY19A FY20 FY16AFY17AFY18AFY19A Lease Operating Expenses ($/Boe) Cash G&A ($/Boe) Guidance (1) Represents reported sales volumes (2) Reflects midpoint of FY2020 revised guidance (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: 1.8x 3.5x 2.8x 3.3x 6.0x 4.4x 3.9x 3.8x 4.0x 3.4x 3.4x 3.2x 3.2x 2.9x 2.9x 2.6x 2.7x 2.7x 2.3x 1.8x 1.8x 2.0x – 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 3/16/20 (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 $1,008 4.0 $926 $900 $845 3.0 2.4 $600 2.0 1.7 1.8 $300 1.0 $0 0.0 2H17 FY18 FY19 FY17 FY18 FY19 All-in Frac Costs per Stage ($/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 ~60% 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 only in Upton County  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

Revised Capital Budget, Guidance and Year-End Liquidity . No long-term service contracts . Negotiated drilling obligations to be deferred to 2021 ESTE 2020 Revised Capital Budget 2020 FY Revised Guidance Gross / Net 2020 Average Daily Production (Boe/d) 13,750 - 14,750 Operated Wells Drilled Gross / Net Net % Oil 60% - 64% and Waiting on Operated Non-Op % Liquids 80% - 84% ($ in millions) Completion Wells On Line Wells On Line Drilling and Completion $45 - $55 11 / 9.7 3 / 3.0 3.1 Land / Infrastructure $5 Operating Costs: Total $50 - $60 Lease Operating ($/Boe) $6.00 - $6.50 Cash G&A ($/Boe) $3.25 - $3.75 (2) Production and Ad Valorem Taxes (% of Revenue) 6.25% - 7.25% 2020 Revised Capital Budget Breakdown(1) Liquidity (12/31/2019) ($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 revised 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 2,622,000 7,164 $60.99 FY 2020 2,562,000 7,000 $2.850 FY 2021 1,460,000 4,000 $55.16 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 ~81% Hedged Gas ~45% Hedged of FY20 Revised Guidance (2) of FY20 Revised Guidance (2) 12,000 10,000 8,000 7,164 9,000 7,000 7,000 7,500 5,000 6,000 5,000 4,000 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 3/16/20): ~$90.3mm (1) Crude basis swaps reflect Midland Argus, LLS Argus and MEH crude basis swaps (2) Based on midpoint of 2020 revised guidance (13,750 – 14,750 Boe/d; 62% oil, 18% 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 Tom Hughes / 212-214-5022 / thomas.hughes@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