Form 8-K EARTHSTONE ENERGY INC For: May 01
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E-mailUNITED 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: May 1, 2019
(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)) | |
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. ☐
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) |
Item 1.01 Entry into a Material Definitive Agreement.
On May 1, 2019, Earthstone Energy Holdings, LLC (“EEH” or the “Borrower”), a subsidiary of Earthstone Energy, Inc. (the “Company”), each of Earthstone Operating, LLC, EF Non-Op, LLC, Sabine River Energy, LLC, Earthstone Legacy Properties, LLC, Lynden USA Operating, LLC, Bold Energy III LLC, Bold Operating, LLC, as guarantors (the “Guarantors”), BOKF, NA dba Bank Of Texas, as Administrative Agent, and the lenders party thereto (the “Lenders”), entered into an amendment (the “Amendment”) to the Credit Agreement dated May 9, 2017, by and among EEH, as Borrower, the Guarantors, BOKF, NA dba Bank Of Texas, as Agent and Lead Arranger, Wells Fargo Bank, National Association, as Syndication Agent, and the Lenders (together with all amendments or other modifications, the “Credit Agreement”). Among other things, the Amendment increases the borrowing base from $275.0 million to $325.0 million and adds lenders to the banking group.
The foregoing description of the Amendment does not purport to be complete and is qualified in its entirety by reference to the full text of the Amendment, which is attached as Exhibit 10.1 to this Current Report on Form 8-K and incorporated in this Item 1.01 by reference.
Item 2.02 Results of Operations and Financial Condition.
On May 6, 2019, the Company issued a press release announcing its financial and operating results for the quarter ended March 31, 2019. A copy of the press release is furnished herewith as Exhibit 99.1.
The information in this Current Report on Form 8-K furnished pursuant to Item 2.02, including Exhibit 99.1, 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 (the “Securities Act”), or the Exchange Act, except as shall be expressly set forth by specific reference in such filing.
Item 7.01 Regulation FD Disclosure.
On May 6, 2019, 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 operations and performance. 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.
The information contained in the Presentation Materials is summary information that should be considered in the context of the Company’s filings with the Securities and Exchange Commission and other public announcements that the Company may make by press release or otherwise from time to time. The Presentation Materials speak as of the date of this Current Report on Form 8-K. While the Company may elect to update the Presentation Materials in the future or reflect events and circumstances occurring or existing after the date of this Current Report on Form 8-K, the Company specifically disclaims any obligation to do so. The Presentation Materials are attached as Exhibit 99.2 to this Current Report on Form 8-K and are incorporated herein by reference.
The information in this Current Report on Form 8-K furnished pursuant to Item 7.01, including Exhibit 99.2, shall not be deemed to be “filed” for the purposes of Section 18 of 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 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 99.2, 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 | ||
10.1 | |||
99.1 | |||
99.2 | |||
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: | May 6, 2019 | By: | /s/ Tony Oviedo |
Tony Oviedo | |||
Executive Vice President - Accounting and Administration | |||
Exhibit 10.1
FOURTH AMENDMENT TO CREDIT AGREEMENT
This FOURTH AMENDMENT TO CREDIT AGREEMENT (this “Amendment”) entered into on May 1, 2019, is among EARTHSTONE ENERGY HOLDINGS, LLC, a Delaware limited liability company (“Borrower”), EARTHSTONE OPERATING, LLC, a Texas limited liability company (“EO”), EF NON-OP, LLC, a Texas limited liability company (“EF”), SABINE RIVER ENERGY, LLC, a Texas limited liability company (“Sabine”), EARTHSTONE LEGACY PROPERTIES, LLC, a Texas limited liability company (“ELP”), LYNDEN USA OPERATING, LLC, a Texas limited liability company (“LUO”), BOLD ENERGY III LLC, a Texas limited liability company (“BE”) and BOLD OPERATING, LLC, a Texas limited liability company (“BO”), as guarantors (EO, EF, Sabine, ELP, LUO, BE and BO, each a “Guarantor” and collectively, the “Guarantors”); each Lender (defined below) who is a signatory hereto and BOKF, NA dba BANK OF TEXAS, a national banking association, as administrative agent (“Agent”) for the Lenders. The party or parties are sometimes individually referred to herein as a “Party” or collectively referred to as “Parties.”
R E C I T A L S
WHEREAS, Borrower, Agent and the lenders from time to time party thereto (each a “Lender” and collectively, the “Lenders”) are parties to that certain Credit Agreement dated as of May 9, 2017, as amended by that certain First Amendment to Credit Agreement dated as of October 11, 2017, that certain Second Amendment to Credit Agreement dated as of December 1, 2017 and that certain Third Amendment to Credit Agreement dated as of May 23, 2018 (as may be further amended, modified or restated from time to time prior to the date hereof, the “Existing Credit Agreement”, and as amended by this Amendment and as further amended, modified or restated from time to time, the “Credit Agreement”), whereby the Lenders agreed to make available to Borrower a credit facility upon the terms and conditions set forth therein; and
WHEREAS, Borrower has requested that Agent and the Lenders amend certain provisions of the Credit Agreement as provided herein; and
WHEREAS, subject to the terms hereof, the Agent and the Lenders are willing to agree to the amendment of certain provisions of the Credit Agreement as set forth herein.
NOW, THEREFORE, for and in consideration of the mutual covenants and agreements contained herein, and other good and valuable consideration, the receipt and sufficiency of which are
hereby acknowledged , the Parties to this Amendment hereby agree as follows:
SECTION 1. Defined Terms. Except as may otherwise be provided herein, all capitalized terms which are defined in the Credit Agreement shall have the same meaning herein as therein, all of such terms and their definitions being incorporated herein by reference. For the purposes of this Amendment, (a) “Existing Lender” means each institution that is a party hereto that is a Lender under the Existing Credit Agreement and (b) “New Lender” means each institution that is a party hereto that is not a Lender under the Existing Credit Agreement.
SECTION 2. Amendments to Credit Agreement. Subject to the conditions precedent set forth in Section 3 hereof:
(a) Section 1.02 of the Credit Agreement is amended by adding the following new defined terms in proper alphabetical order:
“Beneficial Ownership Certification” means a certification regarding beneficial ownership required by the Beneficial Ownership Regulation, which certification shall be substantially similar in form and substance to the form of Certification Regarding Beneficial Owners of Legal Entity Customers published jointly, in May 2018, by the Loan Syndications and Trading Association and Securities Industry and Financial Markets Association.
“Beneficial Ownership Regulation” means 31 C.F.R. § 1010.230.
(b) Article I of the Credit Agreement is amended by adding the following as a new Section 1.05:
“Section 1.05 Divisions. For all purposes under the Loan Documents, in connection with any division or plan of division under Delaware law (or any comparable event under a different jurisdiction’s laws): (a) if any asset, right, obligation or liability of any Person becomes the asset, right, obligation or liability of a different Person, then it shall be deemed to have been transferred from the original Person to the subsequent Person, and (b) if any new Person comes into existence, such new Person shall be deemed to have been organized on the first date of its existence by the holders of its equity interests at such time.”
(c) Section 7.11 of the Credit Agreement is amended by adding the following as a new sentence to the end thereof: “All information set forth or disclosed in any Beneficial Ownership Certification is true and correct in all respects.”
(d) Section 8.01(l) of the Credit Agreement is amended by adding the following as a new sentence to the end thereof: “From time to time all documentation and other information required by regulatory authorities under the Beneficial Ownership Regulation.”
(e) Annex I to the Credit Agreement is hereby replaced with Annex I to this Amendment.
SECTION 3. Conditions of Effectiveness. The obligations of Agent and the Lenders to amend the Credit Agreement as provided herein are subject to the fulfillment of the following conditions precedent:
(a) Agent shall have received counterparts of this Amendment, which shall have been executed by the Lenders, Borrower and the Guarantors.
(b) Borrower shall have made payment of all fees and expenses due and owing under the Credit Agreement including such fees and expenses specified in Section 8 hereof.
(c) All representations and warranties set forth in each of the Loan Documents shall be true and correct.
(d) No Material Adverse Effect shall have occurred.
(e) No Default or Event of Default shall have occurred.
SECTION 4. Borrowing Base Redetermination. The Lenders have agreed that the amount of the Borrowing Base shall be increased to $325,000,000 and the Monthly Reduction Amount shall be reaffirmed at $0, until the Borrowing Base and Monthly Reduction Amount are further redetermined pursuant to the terms of Section 2.08 of the Credit Agreement.
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SECTION 5. New Lenders; Reallocation of Maximum Credit Amount.
(a) The Agent, the Borrower, the Lenders and Issuing Bank consent to the following: (i) each New Lender becoming a “Lender” under and as defined in the Credit Agreement, (ii) the reallocation of the Maximum Credit Amounts so that each Lender’s Maximum Credit Amount and Percentage Share is as set forth on Annex I attached hereto, and (iii) the reallocation of the participations in Letters of Credit and Swing Line Loans in accordance with each Lender’s Percentage Share as set forth on Annex I attached hereto. On the date of this Amendment, after giving effect to such reallocation of the Maximum Credit Amounts, the Maximum Credit Amount and Percentage Share of each Lender shall be as set forth on Annex I attached hereto. The reallocation of the Maximum Credit Amounts among the Lenders, including any assignment by an Existing Lender of a portion of its rights, interests, liabilities and obligations under the Credit Agreement to New Lenders, shall be deemed to have been consummated on the date of this Amendment pursuant to the terms of the Assignment Agreement attached as Exhibit E to the Credit Agreement as if the Lenders had executed an Assignment Agreement with respect to such reallocation. The Administrative Agent hereby waives the $3,500.00 processing fee set forth in Section 12.06(b)(iv) of the Credit Agreement with respect to the assignments and reallocations contemplated by this Section 5.
(b) Each New Lender represents and agrees as follows: (i) it has received a copy of the Existing Credit Agreement, and has received or has been accorded the opportunity to receive copies of the most recent financial statements delivered pursuant to Section 8.01 thereof, and such other documents and information as it deems appropriate to make its own credit analysis and decision to enter into this Amendment, (ii) it has, independently and without reliance upon the Agent, any other agent, any Lender or any arranger, and based on such documents and information as it has deemed appropriate, made its own credit analysis and decision to enter into this Amendment, (iii) it will perform in accordance with their terms all of the obligations which by the terms of the Loan Documents are required to be performed by it as a Lender and agrees that on the date of this Amendment, it will become a party to the Credit Agreement and be bound by all the terms and provisions thereof.
SECTION 6. Representations and Warranties. Borrower and each Guarantor represents and warrants to Agent and the Lenders, with full knowledge that Agent and the Lenders are relying on the following representations and warranties in executing this Amendment, as follows:
(a) It has the power and authority to execute, deliver and perform this Amendment, and all organizational action on the part of itself, as applicable, requisite for the due execution, delivery and performance of this Amendment has been duly and effectively taken.
(b) This Amendment and each other document executed and delivered in connection herewith constitute its legal, valid and binding obligation, to the extent it is a party thereto, enforceable against it in accordance with their respective terms, except as enforceability may be limited by applicable bankruptcy, insolvency, or similar laws affecting the enforcement of creditors’ rights generally or by equitable principles relating to enforceability.
(c) This Amendment does not and will not violate any provisions of (i) its Charter Documents; (ii) any contract, agreement, or instrument to which it is a party; or (iii) any requirement of any governmental authority to which it is subject. Its execution of this Amendment will not result in the creation or imposition of any lien upon its properties other than those permitted by the Credit Agreement and this Amendment.
(d) Its execution, delivery and performance of this Amendment does not require the consent or approval of any other Person, including, without limitation, any regulatory authority or governmental body
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of the United States of America or any state thereof or any political subdivision of the United States of America or any state thereof.
(e) As of the date of this Amendment, it is solvent and has taken no action such as may invoke applicable bankruptcy, insolvency, or similar laws affecting the enforcement of creditors’ rights generally or by equitable principles relating to enforceability.
(f) No Default or Event of Default exists, and all of the representations and warranties made by it contained in the Credit Agreement are true and correct in all material respects on and as of this date (except to the extent such representations and warranties expressly refer to an earlier or other date, in which case they shall be true and correct as of such earlier or other date). The conditions set forth in Section 3(c) through (e) of this Amendment have been satisfied.
Except to the extent expressly set forth herein to the contrary, nothing in this Section 6 is intended to amend any of the representations or warranties contained in the Agreement.
SECTION 7. Reference to and Effect on the Credit Agreement.
(a) Upon and after the execution of this Amendment by each of the parties hereto, each reference in the Credit Agreement to “this Agreement”, “hereunder”, “hereof” or words of like import referring to the Credit Agreement, and each reference in the other Loan Documents to “the Credit Agreement”, “thereunder”, “thereof” or words of like import referring to the Credit Agreement, shall mean and be a reference to the Credit Agreement as modified hereby. This Amendment shall constitute a Loan Document.
(b) Except as specifically amended by this Amendment, the Credit Agreement shall remain in full force and effect and is hereby ratified and confirmed.
SECTION 8. Fees, Cost, and Expenses. Borrower agrees to pay all reasonable legal fees and expenses to be incurred in connection with the preparation, reproduction, execution and delivery of this Amendment and the other instruments and documents to be delivered in connection with the transactions associated herewith, including reasonable attorneys’ fees and out-of-pocket expenses of Agent, and agrees to save Agent harmless from and against any and all liabilities with respect to or resulting from any delay in paying or omission to pay such fees. Borrower agrees to pay any fees required to be paid in connection with this Amendment pursuant to the Fee Letter.
SECTION 9. Extent of Amendment. Except as otherwise expressly provided herein, neither the Credit Agreement nor the other Loan Documents are amended, modified or affected by this Amendment. Borrower and each Guarantor hereby ratifies and confirms that (i) except as expressly amended hereby, all of the terms, conditions, covenants, representations, warranties and all other provisions of the Credit Agreement, as applicable, remain in full force and effect, (ii) each of the other Loan Documents to which it is a party are and remain in full force and effect in accordance with their respective terms, and (iii) the Collateral granted by it is unimpaired by this Amendment.
Nothing contained in this Amendment nor any past indulgence by Agent and/or the Lenders, nor any other action or inaction on behalf of Agent and/or the Lenders (i) shall constitute or be deemed to constitute a waiver of any unknown or future Defaults or Events of Default which may now or in the future exist under the Credit Agreement or the other Loan Documents, or (ii) shall constitute or be deemed to constitute an election of remedies by Agent and/or the Lenders or a waiver of any of the rights or remedies
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of Agent and/or the Lenders provided in the Credit Agreement or the other Loan Documents or otherwise afforded at law or in equity.
SECTION 10. Grant and Affirmation of Security Interest. Borrower and each Guarantor hereby confirms and agrees that (i) any and all liens, security interests and other security or Collateral granted by it and now or hereafter held by Lenders as security for payment and performance of the Obligations are hereby renewed and carried forth to secure payment and performance of all of the Obligations, and (ii) the Loan Documents, as such may be amended in accordance herewith, are and remain legal, valid and binding obligations, enforceable in accordance with their respective terms, except as enforceability may be limited by applicable bankruptcy, insolvency, or similar laws affecting the enforcement of creditors’ rights generally or by equitable principles relating to enforceability.
SECTION 11. Claims; Release. As additional consideration to the execution, delivery, and performance of this Amendment by the parties hereto and to induce Agent and the Lenders to enter into this Amendment, Borrower and each Guarantor hereby represents and warrants that it does not know of any defenses, counterclaims or rights of setoff to the payment of any Obligations of Borrower or any Guarantor to Agent and/or the Lenders. In consideration of the amendments contained herein, Borrower and each Guarantor hereby waives and releases each of the Lenders and Agent from any and all claims and defenses, known or unknown, with respect to the Credit Agreement and the other Loan Documents and the transactions contemplated thereby.
SECTION 12. Execution and Counterparts. This Amendment may be executed in any number of counterparts and by different Parties hereto in separate counterparts, each of which when so executed and delivered shall be deemed to be an original and all of which taken together shall constitute but one and the same instrument. Delivery of an executed counterpart of this Amendment by facsimile or other electronic transmission (such as Portable Document Format) and other Loan Documents shall be equally as effective as delivery of a manually executed counterpart of this Amendment and such other Loan Documents.
SECTION 13. Governing Law. This Amendment shall be governed by and construed in accordance with the laws of the State of Texas.
SECTION 14. Headings. Section headings in this Amendment are included herein for convenience and reference only and shall not constitute a part of this Amendment for any other purpose.
SECTION 15. NO ORAL AGREEMENTS. THE RIGHTS AND OBLIGATIONS OF EACH OF THE PARTIES TO THE LOAN DOCUMENTS SHALL BE DETERMINED SOLELY FROM WRITTEN AGREEMENTS, DOCUMENTS, AND INSTRUMENTS, AND ANY PRIOR ORAL AGREEMENTS BETWEEN SUCH PARTIES ARE SUPERSEDED BY AND MERGED INTO SUCH WRITINGS. THIS AMENDMENT AND THE OTHER WRITTEN LOAN DOCUMENTS EXECUTED BY BORROWER, GUARANTOR, AGENT AND/OR THE LENDERS (TOGETHER WITH ANY FEE LETTERS AS THEY RELATE TO THE PAYMENT OF FEES AFTER THE CLOSING DATE) REPRESENT THE FINAL AGREEMENT BETWEEN SUCH PARTIES, AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS, OR SUBSEQUENT ORAL AGREEMENTS BY SUCH PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS BETWEEN SUCH PARTIES.
[signature pages to follow]
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IN WITNESS WHEREOF, the Parties hereto have caused this Amendment to be duly executed and delivered by their proper and duly authorized officers as of the date first written above.
BORROWER:
EARTHSTONE ENERGY HOLDINGS, LLC
a Delaware limited liability company
By: | /s/ Mark Lumpkin, Jr. | ||
Mark Lumpkin, Jr. | |||
Executive Vice President and Chief Financial Officer | |||
GUARANTORS:
EARTHSTONE OPERATING, LLC,
a Texas limited liability company
EF NON-OP, LLC,
a Texas limited liability company
SABINE RIVER ENERGY, LLC,
a Texas limited liability company
EARTHSTONE LEGACY PROPERTIES, LLC,
a Texas limited liability company
LYNDEN USA OPERATING, LLC,
a Texas limited liability company
BOLD ENERGY III LLC,
a Texas limited liability company
BOLD OPERATING, LLC,
a Texas limited liability company
Each by: | /s/ Mark Lumpkin, Jr. | ||
Mark Lumpkin, Jr. | |||
Executive Vice President and Chief Financial Officer | |||
Signature Page to Fourth Amendment to Credit Agreement
LENDER AND AGENT:
BOKF, NA dba BANK OF TEXAS,
as Agent and Lender
By: | /s/ Martin W. Wilson |
Martin W. Wilson | |
Senior Vice President | |
Signature Page to Fourth Amendment to Credit Agreement
LENDER:
WELLS FARGO BANK, NATIONAL ASSOCIATION,
as Lender
By: | /s/ Greg Smothers |
Greg Smothers | |
Director | |
Signature Page to Fourth Amendment to Credit Agreement
LENDER:
ROYAL BANK OF CANADA,
as Lender
By: | /s/ Kristan Spivey |
Kristan Spivey | |
Authorized Signatory | |
Signature Page to Fourth Amendment to Credit Agreement
LENDER:
SUNTRUST BANK,
as Lender
By: | /s/ Arize Agumadu |
Arize Agumadu | |
Vice President | |
Signature Page to Fourth Amendment to Credit Agreement
LENDER:
KEYBANK NATIONAL ASSOCIATION,
as Lender
By: | /s/ David M. Bornstein |
David M. Bornstein | |
Senior Vice President | |
Signature Page to Fourth Amendment to Credit Agreement
LENDER:
IBERIABANK,
as Lender
By: | /s/ Blakey Norris |
Blakey Norris | |
Vice President | |
Signature Page to Fourth Amendment to Credit Agreement
LENDER:
PNC BANK, NATIONAL ASSOCIATION,
as Lender
By: | /s/ Denise S. Davis |
Denise S. Davis | |
Vice President | |
Signature Page to Fourth Amendment to Credit Agreement
LENDER:
CITIZENS BANK, NATIONAL ASSOCIATION,
as Lender
By: | /s/ David Slye |
David Slye | |
Managing Director | |
Signature Page to Fourth Amendment to Credit Agreement
Exhibit 99.1
Earthstone Energy, Inc. Reports First Quarter 2019 Financial Results
The Woodlands, Texas, May 6, 2019 – Earthstone Energy, Inc. (NYSE: ESTE) (“Earthstone”, the “Company”, “we” or “us”), today announced financial and operating results for the quarter ended March 31, 2019.
First Quarter 2019 Highlights
• | Average daily production of 11,209 Boepd(1) |
◦ | Increased by 7% from the fourth quarter of 2018 |
◦ | Increased by 16% from the first quarter of 2018 |
• | Revenues of $40.7 million |
◦ | Flat as compared to the fourth quarter of 2018, resulting from increased production, offset by decreased oil prices |
◦ | Flat as compared to the first quarter of 2018, resulting from increased production, offset by decreased oil prices |
• | Adjusted EBITDAX(2) of $32.4 million |
◦ | Increased by 35% from the fourth quarter of 2018, primarily resulting from increased cash hedge settlements in the current year period |
◦ | Increased by 28% from the first quarter of 2018, primarily resulting from increased cash hedge settlements in the current year period |
• | Net loss of $38.4 million, which includes a net loss on derivative contracts of $47.9 million |
◦ | Compared to net income of $81.0 million in the fourth quarter of 2018, which includes a net gain on derivative contracts of $94.6 million |
◦ | Compared to net income of $12.2 million in the first quarter of 2018, which includes a net loss on derivative contracts of $5.3 million |
• | Net loss attributable to Earthstone Energy, Inc. of $17.2 million, or $0.60 per diluted share |
◦ | Compared to net income attributable to Earthstone Energy, Inc. of $36.1 million, or $1.26 per combined diluted share, in the fourth quarter of 2018 |
◦ | Compared to net income attributable to Earthstone Energy, Inc. of $5.3 million, or $0.19 per combined diluted share, in the first quarter of 2018 |
• | Capital expenditures of $42.7 million |
(1) | Represents reported sales volumes. |
(2) | Adjusted EBITDAX is a non-GAAP financial measure. See “Reconciliation of Non-GAAP Financial Measure” section below. |
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Management Comments
Robert J. Anderson, President of Earthstone Energy, Inc., commented, “We continue to be pleased with the results of our Midland Basin drilling program, which is making solid progress at furthering production growth and demonstrating the high quality of our acreage. In the first quarter, we achieved record production and record quarterly adjusted EBITDAX of over $32 million. Although first quarter oil prices were the lowest we have received since the third quarter of 2017, our robust hedge program allowed us to realize an adjusted average oil price of $59.81 per barrel, also contributing to the higher EBITDAX.
“Our leverage continues to remain low with debt of less than one times annualized quarterly Adjusted EBITDAX, and we have significant liquidity to provide for our capital program or growth opportunities while maintaining our low leverage ratio. We remain focused on operational excellence as we evaluate opportunities to increase our scale through acreage additions and trades, as well as accretive acquisitions and merger opportunities.”
Operational Update
Midland Basin - In the Midland Basin, we completed three operated wells in February and March of 2019. In Reagan County, we completed our Malone 1-3 1A well (89% working interest) in the Wolfcamp A with an 11,206-foot lateral. In Upton County, we completed two Ratliff wells (100% working interest) with an average lateral of 10,375 feet from two different target zones in the Wolfcamp B. We commenced drilling in the first quarter on a five well program in Midland County on our Mid-States project (67% working interest). These wells are targeting the Wolfcamp A and B intervals with 10,000-foot laterals. Completions on this project are expected to begin in June.
Non-operated activity in the quarter consisted of completing two wells (50% working interest) in Reagan County and one well in Howard County (35% working interest). We are participating in projects in various stages of drilling and completions across our position in Howard, Martin and Midland counties with interests ranging from 2.6% to 46%.
In the Midland Basin, our total operated and non-operated production in the 2019 first quarter averaged approximately 9,706 Boepd (65% oil).
Eagle Ford - In the Eagle Ford, we have initiated drilling on a seven-well project in southern Gonzales County, Texas (44% working interest). These wells will average approximately 7,000-foot laterals with completions anticipated to begin by the end of the third quarter. Total operated and non-operated production in the first quarter averaged approximately 1,503 Boepd (84% oil).
Selected Financial Data (unaudited)
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($000s except where noted) | Three Months Ended March 31, | |||||
2019 | 2018 | |||||
Total Revenues | 40,728 | 40,895 | ||||
Lease operating expense | 6,667 | 4,657 | ||||
General and administrative expense (excluding stock-based compensation) | 5,058 | 4,639 | ||||
Stock-based compensation (non-cash) | 2,212 | 1,940 | ||||
General and administrative expense | 7,270 | 6,579 | ||||
Net (loss) income | (38,443) | 12,191 | ||||
Less: Net (loss) income attributable to noncontrolling interest | (21,239) | 6,870 | ||||
Net (loss) income attributable to Earthstone Energy, Inc. | (17,204) | 5,321 | ||||
Net (loss) income per common share(1) | ||||||
Basic | (0.60 | ) | 0.19 | |||
Diluted | (0.60 | ) | 0.19 | |||
Adjusted EBITDAX(2) | 32,373 | 25,293 | ||||
Production(3): | ||||||
Oil (MBbls) | 678 | 546 | ||||
Gas (MMcf) | 827 | 1,044 | ||||
NGL (MBbls) | 193 | 150 | ||||
Total (MBoe)(4) | 1,009 | 870 | ||||
Average Daily Production (Boepd) | 11,209 | 9,664 | ||||
Average Prices: | ||||||
Oil ($/Bbl) | 52.30 | 63.07 | ||||
Gas ($/Mcf) | 1.32 | 2.57 | ||||
NGL ($/Bbl) | 21.66 | 25.30 | ||||
Total ($/Boe) | 40.37 | 47.02 | ||||
Adj. for Realized Derivatives Settlements: | ||||||
Oil ($/Bbl)(5) | 59.81 | 55.11 | ||||
Gas ($/Mcf)(5) | 1.66 | 2.63 | ||||
NGL ($/Bbl) | 21.66 | 25.30 | ||||
Total ($/Boe)(5) | 45.69 | 42.10 | ||||
(1) | Net (loss) income per common share attributable to Earthstone Energy, Inc. |
(2) | See “Reconciliation of Non-GAAP Financial Measure” section below. |
(3) | Represents reported sales volumes. |
(4) | Barrels of oil equivalent have been calculated on the basis of six thousand cubic feet (Mcf) of natural gas equals one barrel of oil equivalent (BOE). |
(5) | Includes $2.1 million of cash proceeds related to hedges unwound during the first quarter of 2019. |
Borrowing Base and Liquidity Update
On May 1, 2019, the borrowing base under our senior secured revolving credit facility was increased from $275 million to $325 million in connection with its regularly scheduled redetermination.
As of March 31, 2019, we had $0.4 million in cash and $120.8 million of long-term debt outstanding under our credit facility with a borrowing base of $275 million. Adjusting for the recent increase in the borrowing base to $325 million,
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we had approximately $204.2 million of undrawn borrowing base capacity plus $0.4 million of cash for total liquidity of approximately $205 million.
Capital Expenditures
During the three months ended March 31, 2019, we incurred capital expenditures of approximately $42.7 million, on an accrual basis, primarily consisting of drilling and completion costs.
As previously reported, we established a 2019 capital expenditure budget of $190 million.
Hedging Update
Subsequent to March 31, 2019, we entered into additional hedges consisting of Crude Oil Swaps on 366 MBbls at a price of $59.75/Bbl for 2020 and WTI Midland Argus Crude Basis Swaps on 366 MBbls at a price of $0.25/Bbl for 2020.
The following tables set forth our outstanding derivative contracts as of May 1, 2019 and March 31, 2019. When aggregating multiple contracts, the weighted average contract price is disclosed.
As of May 1, 2019:
Price Swaps | |||||||||
Period | Commodity | Volume (Bbls / MMBtu) | Weighted Average Price ($/Bbl / $/MMBtu) | ||||||
Q2 - Q4 2019 | Crude Oil | 1,769,100 | $ | 65.60 | |||||
Q1 - Q4 2020 | Crude Oil | 1,830,000 | $ | 64.65 | |||||
Q2 - Q4 2019 | Crude Oil Basis Swap(1) | 1,512,500 | $ | (5.29 | ) | ||||
Q2 - Q4 2019 | Crude Oil (Basis Swap)(2) | 275,000 | $ | 4.50 | |||||
Q1 - Q4 2020 | Crude Oil Basis Swap(1) | 1,830,000 | $ | (2.14 | ) | ||||
Q2 - Q4 2019 | Natural Gas | 2,795,500 | $ | 2.86 | |||||
Q1 - Q4 2020 | Natural Gas | 2,562,000 | $ | 2.85 | |||||
Q2 - Q4 2019 | Natural Gas Basis Swap (3) | 2,795,500 | $ | (1.14 | ) | ||||
Q1 - Q4 2020 | Natural Gas Basis Swap (3) | 2,562,000 | $ | (1.07 | ) | ||||
(1) | The basis differential price is between WTI Midland Argus Crude and the WTI NYMEX. |
(2) | The basis differential price is between LLS Argus Crude and the WTI NYMEX. |
(3) | The basis differential price is between W. Texas (WAHA) and the Henry Hub NYMEX. |
As of March 31, 2019:
Price Swaps | |||||||||
Period | Commodity | Volume (Bbls / MMBtu) | Weighted Average Price ($/Bbl / $/MMBtu) | ||||||
Q2 - Q4 2019 | Crude Oil | 1,769,100 | $ | 65.60 | |||||
Q1 - Q4 2020 | Crude Oil | 1,464,000 | $ | 65.87 | |||||
Q2 - Q4 2019 | Crude Oil Basis Swap(1) | 1,512,500 | $ | (5.29 | ) | ||||
Q2 - Q4 2019 | Crude Oil (Basis Swap)(2) | 275,000 | $ | 4.50 | |||||
Q1 - Q4 2020 | Crude Oil Basis Swap(1) | 1,464,000 | $ | (2.74 | ) | ||||
Q2 - Q4 2019 | Natural Gas | 2,795,500 | $ | 2.86 | |||||
Q1 - Q4 2020 | Natural Gas | 2,562,000 | $ | 2.85 | |||||
Q2 - Q4 2019 | Natural Gas Basis Swap (3) | 2,795,500 | $ | (1.14 | ) | ||||
Q1 - Q4 2020 | Natural Gas Basis Swap (3) | 2,562,000 | $ | (1.07 | ) | ||||
4
(1) | The basis differential price is between WTI Midland Argus Crude and the WTI NYMEX. |
(2) | The basis differential price is between LLS Argus Crude and the WTI NYMEX. |
(3) | The basis differential price is between W. Texas (WAHA) and the Henry Hub NYMEX. |
Conference Call Details
Earthstone is hosting a conference call on Monday, May 6, 2019 at 11:00 a.m. Eastern (10:00 a.m. Central) to discuss the Company’s operational and financial results for the first quarter of 2019 and its outlook for the remainder of 2019. Prepared remarks by Frank A. Lodzinski, Chief Executive Officer, Robert J. Anderson, President, and Mark Lumpkin, Jr., Executive Vice President and Chief Financial Officer will be followed by a question and answer session.
Investors and analysts are invited to participate in the call by dialing 877-407-6184 for domestic calls or 201-389-0877 for international calls, in both cases asking for the Earthstone conference call. A webcast will also be available through the Company's website (www.earthstoneenergy.com). Please select "Events & Presentations" under the "Investors" section of the Company's website and log on at least 10 minutes in advance to register.
A replay of the call will be available on the Company’s website and by telephone until 11:00 a.m. Eastern (10:00 a.m. Central), Monday, May 20, 2019. The number for the replay is 877-660-6853 for domestic calls or 201-612-7415 for international calls, using Replay ID: 13690518.
About Earthstone Energy, Inc.
Earthstone Energy, Inc. is a growth-oriented, independent energy company engaged in the development and operation of oil and natural gas properties. Its primary assets are located in the Midland Basin of west Texas and the Eagle Ford Trend of south Texas. Earthstone is listed on the New York Stock Exchange 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, 2018, quarterly reports on Form 10-Q, recent current reports on Form 8-K, and other Securities and Exchange Commission (“SEC”) 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
5
Scott Thelander
Vice President of Finance
Earthstone Energy, Inc.
1400 Woodloch Forest Drive, Suite 300
The Woodlands, TX 77380
281-298-4246
6
EARTHSTONE ENERGY, INC.
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
(In thousands, except share and per share amounts)
March 31, | December 31, | |||||||
ASSETS | 2019 | 2018 | ||||||
Current assets: | ||||||||
Cash | $ | 426 | $ | 376 | ||||
Accounts receivable: | ||||||||
Oil, natural gas, and natural gas liquids revenues | 19,433 | 13,683 | ||||||
Joint interest billings and other, net of allowance of $133 and $134 at March 31, 2019 and December 31, 2018, respectively | 19,740 | 4,166 | ||||||
Derivative asset | 6,605 | 43,888 | ||||||
Prepaid expenses and other current assets | 3,679 | 1,443 | ||||||
Total current assets | 49,883 | 63,556 | ||||||
Oil and gas properties, successful efforts method: | ||||||||
Proved properties | 797,964 | 755,443 | ||||||
Unproved properties | 266,289 | 266,140 | ||||||
Land | 5,382 | 5,382 | ||||||
Total oil and gas properties | 1,069,635 | 1,026,965 | ||||||
Accumulated depreciation, depletion and amortization | (141,077 | ) | (127,256 | ) | ||||
Net oil and gas properties | 928,558 | 899,709 | ||||||
Other noncurrent assets: | ||||||||
Goodwill | 17,620 | 17,620 | ||||||
Office and other equipment, net of accumulated depreciation and amortization of $2,674 and $2,490 at March 31, 2019 and December 31, 2018, respectively | 1,380 | 662 | ||||||
Derivative asset | 6,300 | 21,121 | ||||||
Operating lease right-of-use assets | 1,049 | — | ||||||
Other noncurrent assets | 1,539 | 1,640 | ||||||
TOTAL ASSETS | $ | 1,006,329 | $ | 1,004,308 | ||||
LIABILITIES AND EQUITY | ||||||||
Current liabilities: | ||||||||
Accounts payable | $ | 28,964 | $ | 26,452 | ||||
Revenues and royalties payable | 23,365 | 28,748 | ||||||
Accrued expenses | 21,362 | 22,406 | ||||||
Asset retirement obligation | 494 | 557 | ||||||
Advances | 1,293 | 3,174 | ||||||
Derivative liability | 2,204 | 528 | ||||||
Operating lease liabilities | 658 | — | ||||||
Finance lease liabilities | 354 | — | ||||||
Total current liabilities | 78,694 | 81,865 | ||||||
Noncurrent liabilities: | ||||||||
Long-term debt | 120,825 | 78,828 | ||||||
Deferred tax liability | 13,029 | 13,489 | ||||||
Asset retirement obligation | 1,748 | 1,672 | ||||||
Derivative liability | 1,367 | 1,891 | ||||||
Operating lease liabilities | 442 | — | ||||||
7
Finance lease liabilities | 193 | — | ||||||
Other noncurrent liabilities | — | 71 | ||||||
Total noncurrent liabilities | 137,604 | 95,951 | ||||||
Equity: | ||||||||
Preferred stock, $0.001 par value, 20,000,000 shares authorized; none issued or outstanding | — | — | ||||||
Class A Common Stock, $0.001 par value, 200,000,000 shares authorized; 28,862,461 issued and outstanding at March 31, 2019 and 28,696,321 issued and outstanding at December 31, 2018 | 29 | 29 | ||||||
Class B Common Stock, $0.001 par value, 50,000,000 shares authorized; 35,452,178 issued and outstanding at March 31, 2019 and December 31, 2018 | 35 | 35 | ||||||
Additional paid-in capital | 518,889 | 517,073 | ||||||
Accumulated deficit | (199,634 | ) | (182,497 | ) | ||||
Total Earthstone Energy, Inc. equity | 319,319 | 334,640 | ||||||
Noncontrolling interest | 470,712 | 491,852 | ||||||
Total equity | 790,031 | 826,492 | ||||||
TOTAL LIABILITIES AND EQUITY | $ | 1,006,329 | $ | 1,004,308 | ||||
8
EARTHSTONE ENERGY, INC.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)
(In thousands, except share and per share amounts)
Three Months Ended March 31, | ||||||||
2019 | 2018 | |||||||
REVENUES | ||||||||
Oil | $ | 35,447 | $ | 34,417 | ||||
Natural gas | 1,094 | 2,684 | ||||||
Natural gas liquids | 4,187 | 3,794 | ||||||
Total revenues | 40,728 | 40,895 | ||||||
OPERATING COSTS AND EXPENSES | ||||||||
Lease operating expense | 6,667 | 4,657 | ||||||
Severance taxes | 1,988 | 2,037 | ||||||
Depreciation, depletion and amortization | 14,005 | 9,708 | ||||||
General and administrative expense | 7,270 | 6,579 | ||||||
Transaction costs | 175 | — | ||||||
Accretion of asset retirement obligation | 54 | 41 | ||||||
Total operating costs and expenses | 30,159 | 23,022 | ||||||
(Loss) gain on sale of oil and gas properties | (125 | ) | 449 | |||||
Income from operations | 10,444 | 18,322 | ||||||
OTHER INCOME (EXPENSE) | ||||||||
Interest expense, net | (1,449 | ) | (613 | ) | ||||
Loss on derivative contracts, net | (47,894 | ) | (5,275 | ) | ||||
Other income (expense), net | (4 | ) | 6 | |||||
Total other income (expense) | (49,347 | ) | (5,882 | ) | ||||
(Loss) income before income taxes | (38,903 | ) | 12,440 | |||||
Income tax benefit (expense) | 460 | (249 | ) | |||||
Net (loss) income | (38,443 | ) | 12,191 | |||||
Less: Net (loss) income attributable to noncontrolling interest | (21,239 | ) | 6,870 | |||||
Net (loss) income attributable to Earthstone Energy, Inc. | $ | (17,204 | ) | $ | 5,321 | |||
Net (loss) income per common share attributable to Earthstone Energy, Inc.: | ||||||||
Basic | $ | (0.60 | ) | $ | 0.19 | |||
Diluted | $ | (0.60 | ) | $ | 0.19 | |||
Weighted average common shares outstanding: | ||||||||
Basic | 28,719,542 | 27,783,805 | ||||||
Diluted | 28,719,542 | 27,911,924 | ||||||
9
EARTHSTONE ENERGY, INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
(In thousands)
For the Three Months Ended March 31, | ||||||||
2019 | 2018 | |||||||
Cash flows from operating activities: | ||||||||
Net (loss) income | $ | (38,443 | ) | $ | 12,191 | |||
Adjustments to reconcile net (loss) income to net cash provided by operating activities: | ||||||||
Depreciation, depletion and amortization | 14,005 | 9,708 | ||||||
Accretion of asset retirement obligations | 54 | 41 | ||||||
Settlement of asset retirement obligations | (62 | ) | (52 | ) | ||||
Loss (gain) on sale of oil and gas properties | 125 | (449 | ) | |||||
Total loss on derivative contracts, net | 47,894 | 5,275 | ||||||
Operating portion of net cash received (paid) in settlement of derivative contracts | 5,362 | (4,275 | ) | |||||
Stock-based compensation | 2,212 | 1,940 | ||||||
Deferred income taxes | (460 | ) | 249 | |||||
Amortization of deferred financing costs | 103 | 69 | ||||||
Changes in assets and liabilities: | ||||||||
(Increase) decrease in accounts receivable | (6,811 | ) | 737 | |||||
(Increase) decrease in prepaid expenses and other current assets | (2,236 | ) | (314 | ) | ||||
Increase (decrease) in accounts payable and accrued expenses | (7,427 | ) | (17,611 | ) | ||||
Increase (decrease) in revenues and royalties payable | (5,383 | ) | 8,595 | |||||
Increase (decrease) in advances | (1,882 | ) | 662 | |||||
Net cash provided by operating activities | 7,051 | 16,766 | ||||||
Cash flows from investing activities: | ||||||||
Additions to oil and gas properties | (48,412 | ) | (33,372 | ) | ||||
Additions to office and other equipment | (75 | ) | (15 | ) | ||||
Proceeds from sales of oil and gas properties | — | 195 | ||||||
Net cash used in investing activities | (48,487 | ) | (33,192 | ) | ||||
Cash flows from financing activities: | ||||||||
Proceeds from borrowings | 85,244 | 20,000 | ||||||
Repayments of borrowings | (43,247 | ) | (15,000 | ) | ||||
Cash paid related to the exchange and cancellation of Class A Common Stock | (397 | ) | (468 | ) | ||||
Cash paid for finance leases | (114 | ) | — | |||||
Deferred financing costs | — | (3 | ) | |||||
Net cash provided by financing activities | 41,486 | 4,529 | ||||||
Net increase (decrease) in cash | 50 | (11,897 | ) | |||||
Cash at beginning of period | 376 | 22,955 | ||||||
Cash at end of period | $ | 426 | $ | 11,058 | ||||
Supplemental disclosure of cash flow information | ||||||||
Cash paid for: | ||||||||
Interest | $ | 1,255 | $ | 383 | ||||
Non-cash investing and financing activities: | ||||||||
Accrued capital expenditures | $ | 17,040 | $ | 8,967 | ||||
Lease asset additions - ASC 842 | $ | 1,801 | $ | — | ||||
Asset retirement obligations | $ | 21 | $ | (181 | ) | |||
10
Earthstone Energy, Inc.
Reconciliation of Non-GAAP Financial Measure
Unaudited
Reconciliation of Non-GAAP Financial Measure
Unaudited
I. Adjusted EBITDAX
The non-GAAP financial measures 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 accounting principles generally accepted in the United States (“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 (loss) income because of its wide acceptance by the investment community as a financial indicator.
We define “Adjusted EBITDAX” as net (loss) income plus, when applicable, accretion of asset retirement obligations; impairment expense; depletion, depreciation and amortization; interest expense, net; transaction costs; loss (gain) on sale of oil and gas properties; unrealized loss on derivatives; stock-based compensation; and income tax (benefit) 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 (loss) 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 (loss) income to Adjusted EBITDAX for the periods indicated:
($000s) | Three Months Ended March 31, | |||||
2019 | 2018 | |||||
Net (loss) income | (38,443 | ) | 12,191 | |||
Accretion of asset retirement obligations | 54 | 41 | ||||
Depletion, depreciation and amortization | 14,005 | 9,708 | ||||
Interest expense, net | 1,449 | 613 | ||||
Transaction costs | 175 | — | ||||
Loss (gain) on sale of oil and gas properties | 125 | (449 | ) | |||
Unrealized loss on derivative contracts | 53,256 | 1,000 | ||||
Stock based compensation (non-cash)(1) | 2,212 | 1,940 | ||||
Income tax (benefit) expense | (460 | ) | 249 | |||
Adjusted EBITDAX | 32,373 | 25,293 | ||||
(1) | Included in General and administrative expense in the Condensed Consolidated Statements of Operations. |
11
Exhibit 99.2 Investor Presentation May 6, 2019 1
Disclaimer Forward-Looking Statements This presentation contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Statements that are not strictly historical statements constitute forward-looking statements and may often, but not always, be identified by the use of such words such as “expects,” “believes,” “intends,” “anticipates,” “plans,” “estimates,” “guidance,” “target,” “potential,” “possible,” or “probable” or statements that certain actions, events or results “may,” “will,” “should,” or “could” be taken, occur or be achieved. The forward-looking statements include statements about the expected future reserves, production, financial position, business strategy, revenues, earnings, costs, capital expenditures and debt levels of the Company, and plans and objectives of management for future operations. Forward-looking statements are based on current expectations and assumptions and analyses made by Earthstone and its management in light of experience and perception of historical trends, current conditions and expected future developments, as well as other factors appropriate under the circumstances. However, whether actual results and developments will conform to expectations is subject to a number of material risks and uncertainties, including but not limited to: further and substantial declines in oil, natural gas liquids or natural gas prices; risks relating to any unforeseen liabilities; the level of success in exploration, development and production activities; adverse weather conditions that may negatively impact development or production activities; the timing of exploration and development expenditures; inaccuracies of reserve estimates or assumptions underlying them; revisions to reserve estimates as a result of changes in commodity prices; impacts to financial statements as a result of impairment write- downs; risks related to levels of indebtedness and periodic redeterminations of the borrowing base under the Company’s credit agreement; Earthstone’s ability to generate sufficient cash flows from operations to meet the internally funded portion of its capital expenditures budget; Earthstone’s ability to obtain external capital to finance exploration and development operations and acquisitions; the ability to successfully complete any potential acquisitions and the risks related thereto; the impacts of hedging on results of operations; uninsured or underinsured losses resulting from oil and natural gas operations; Earthstone’s ability to replace oil and natural gas reserves; and any loss of senior management or key technical personnel. Earthstone’s 2018 Annual Report on Form 10-K, quarterly reports on Form 10-Q, 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 statementsexceptasrequiredbylaw. This presentation contains Earthstone’s 2019 production, capital expenditure and operating expense guidance. The actual levels of production, capital expenditures and operating expenses may be higher or lower than these estimates due to, among other things, uncertainty in drilling schedules, changes in market demand and unanticipated delays in production. These estimates are based on numerous assumptions. All or any of these assumptions may not prove to be accurate, which could result in actual results differing materially from estimates. No assurance can be made that any new wells will produce in line with historic performance, or that existing wells will continue to produce in line with expectations. For additional discussion of the factors that may cause us not to achieve our production estimates, see Earthstone’s filings with the SEC, including its Form 10-K and any amendments thereto. We do not undertake any obligation to release publicly the results of any future revisions we may make to this prospective data or to update this prospective data to reflect events or circumstances after the date of this presentation. Therefore, you are cautioned not to place undue reliance on this information. Industry and Market Data This presentation has been prepared by Earthstone and includes market data and other statistical information from third-party sources, including independent industry publications, government publications or other published independent sources. Although Earthstone believes these third-party sources are reliable as of their respective dates, Earthstone has not independently verified the accuracy or completeness of this information. Some data are also based on Earthstone’s good faith estimates, which are derived from its review of internal sources as well as the third-party sources described above. Estimated Ultimate Recovery and Locations Management’s use of the term estimated ultimate recovery (“EUR”) in this presentation describes estimates of potentially recoverable hydrocarbons that the SEC rules prohibit from being included in filings with the SEC. These are more speculative than estimates of proved, probable and possible reserves and accordingly are subject to substantially greater risk of being actually realized, particularly in areas or zones where there has been limited or no drilling history. We include EUR to demonstrate what we believe to be the potential for future drilling and production by Earthstone. Actual quantities that may be ultimately recovered may differ substantially from estimates. Factors affecting ultimate recovery include the scope of the operators' ongoing drilling programs, which will be directly affected by the availability of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, transportation constraints, regulatory approvals and other factors, and actual drilling results, including geological and mechanical factors affecting recovery rates. Estimates of potential resources may also change significantly as the development of the properties underlying Earthstone's mineral interests provides additional data. This presentation also contains Earthstone’s internal estimates of its potential drilling locations, which may prove to be incorrect in a number of material ways. The actual number of locations that may be drilled may differ substantially. 2
Investment Highlights Actively growing in the Midland Basin Midland Basin Focused Growth through drill bit, acquisitions and significant business combinations Company with Growing Inventory ~870 total gross drilling locations across core play in Midland Basin Upside from additional benches in the Spraberry and Wolfcamp Conservative balance sheet with low leverage Prudent Financial Traditional reserve-based credit facility with standard covenants Management Significant liquidity Favorable hedge position Visible Production Midland Basin wells-in-progress provide ability to ramp up production Growth & Drilling Majority of acreage in key areas is HBP Program with Substantial Optionality Minimal obligation drilling in 2019 and 2020 Four prior successful public entities Proven Management Operational excellence Team Repeat institutional investors Management recognition from investors and sellside research analysts 3
Proven Leadership and Track Record of Value Creation Operating team has extensive experience running multi-rig development programs across various basins Leadership Team Years of Experience Years Working Together Title Frank Lodzinski 47 31 CEO Robert Anderson 32 15 President Steve Collins 31 23 Operations Mark Lumpkin 22 2 CFO Tim Merrifield 43 18 Geology and Geophysics Francis Mury 45 31 Drilling and Development Tony Oviedo 38 2 Accounting and Administration Track Record of Value Creation 1992-1996 2001-2004 2007-2012 Q2 2017 Hampton Resources Corp. (“HPTR”) AROC, Inc. (Private) GeoResources, Inc. (“GEOI”) Earthstone Acquired 20,900 Net Gulf Coast Gulf Coast, Permian Basin, Mid-Con. Eagle Ford, Bakken / Three Forks, Gulf Acres from Bold Energy III LLC in Initial investors – 7x return Initial investors – 4x return Coast, Austin Chalk Midland Basin Initial investors – 4.8x return 1992 1997 2001 2005 2007 2014 2017 2018 1997-2001 Texoil, Inc. (“TXLI”) 2005-2007 2014 Earthstone Q1 2019 Gulf Coast, Permian Basin Southern Bay Energy, LLC (Private) Bakken (662 Boe/d) Earthstone Initial investors – 10x return Gulf Coast, Permian Basin Acquired Eagle Ford interests from Oak Midland Basin, Eagle Ford 11,209 Boe/d Initial Investors – 40% IRR Valley Resources 4
Midland Basin Growth Story . Since entering the Midland Basin in 2016, Earthstone has substantially increased production, proved reserves and core acreage while maintaining low leverage and preserving financial flexibility . The Company has meaningfully derisked its current position through the drill bit while significantly increasing its operated production Average Daily Production (Boe/d)(1) Total Proved Reserves (MMBoe)(2) 16,000 120 11,209 12,000 99 9,937 80 7,869 80 8,000 4,002 9,706 93 4,000 7,999 40 73 4,696 12 0 1,180 0 FY16A FY17A FY18A 1Q'19A FY16A FY17A FY18A Midland Basin Other Midland Basin Other Midland Basin Net Acres 1P PV-10 Growth ($MM)(2) 40,000 $1,200 $1,009 30,200 30,000 26,665 $900 $599 20,000 $600 $904 23,500 10,000 5,900 20,498 $300 $524 $86 0 $0 FY16A FY17A FY18A FY16A FY17A FY18A Operated Non‐Operated Midland Basin Other (1) Represents reported sales volumes (2) Reserve reports based on SEC pricing prepared by Cawley, Gillespie & Associates 5
Consistent Growth and Margin Expansion While Maintaining a Strong Balance Sheet Adjusted EBITDAX ($MM) Unhedged Debt-Adjusted CFPS(3) $2.40 3.0x $150.0 2Q'16-1Q'19 CAGR $129.6 Maintained leverage below 1.5x since 2016 49.6% $120.0 $96.2 $2.00 $2.00 4Q’17: ESTE Sale of Bakken 2.5x $90.0 2Q’17: ESTE Acquires assets for $27 million 20,900 Net Acres from $60.6 $1.74 Bold Energy TotalDebt /LQA EBITDA(X) $60.0 $1.60 2Q’16: ESTE Acquires $1.50 2.0x $30.0 $18.7 Lynden Energy $1.16 $1.26 $1.26 $0.0 $1.19 $1.20 1.5x FY16A FY17A FY18A 1Q'19A $1.08 $0.94 1.2x Annualized 1.3x $0.85 1.0x 0.9x Unhedged CFPS / Debt-Adjusted Share Debt-Adjusted / CFPS Unhedged $0.80 0.8x 1.0x 0.8x 0.7x (1) $0.56 Lease Operating Expenses ($/Boe) 0.5x $0.40 $0.33 0.5x $12.00 0.3x 0.3x 0.3x $10.29 0.3x $9.00 $0.00 0.0x $6.84 $6.61 $5.66 $6.00 ESTE Leverage $3.00 $0.00 Track record of growing debt-adjusted cash flow per share while FY16A FY17A FY18A 1Q'19A maintaining a low leverage profile drives greater overall shareholder returns Cash G&A ($/Boe)(2) $9.00 $7.13 $6.43 $5.81 $6.00 $5.01 $3.00 $0.00 FY16A FY17A FY18A 1Q'19A (1) Includes workovers and ad valorem taxes (2) Excludes stock-based compensation (3) CFPS represents annualized quarterly debt-adjusted cash flow per share 6
Company Overview The Woodlands, Texas based E&P company focused on development and production of oil and natural gas with current operations in the Midland Basin Asset Overview Midland Basin (~30,200 core net acres) and the Eagle Ford (~14,300 core net acres) Strategy of growing through the drill bit, organic leasing, and attractive asset acquisitions and business combinations (1) 2019 1Q production of 11,209 Boe/d (67% oil, 86% liquids) Market Statistics(2) ($ in millions, except share price) Class A Common Stock (MM) 28.9 Class B Common Stock (MM) 35.4 Total Common Stock Oustanding (MM) 64.3 Stock Price (as of 5/1/19) $6.29 Market Capitalization $404.6 Plus: Total Debt $120.8 Less: Cash (0.4) Enterprise Value $525.0 Production Summary(1) Q1’19 Net Sales Volumes: 11,209 Boe/d Eagle Ford, 1,503 Midland Basin, 9,706 (1) Reflects reported sales volumes (2) Class A and Class B Common Stock outstanding as of April 26, 2019. Total debt and cash balances as of March 31, 2019 7
Earthstone by the Numbers: Increased Size, Scale and Core Inventory Midland Basin Net Acres 30,200 Midland Basin Locations (Gross / Net) 866 / 496 Operated Midland Basin Locations (Gross / Net) 500 / 398 Eagle Ford Net Acres 14,300 Operations Eagle Ford Locations (Gross / Net) 68 / 17 Q1 2019 Production (Boe/d)(1) 11,209 Q1 2019 Production (% Oil / % Liquids)(1) 67% / 86% PD Reserves (Mmboe) 23.6 (2) PD PV-10 ($mm) $436 1P Reserves (Mmboe) 98.8 1P PV-10 ($mm) $1,009 12/31/18 Reserves 1P % Oil / % Liquids 60% / 81% Q1 2019 Revenue ($mm) $40.7 Q1 2019 Adjusted EBITDAX ($mm)(3) $32.4 Q1 2019 LOE ($/boe)(4) $6.61 Q1 2019 G&A ($/boe)(5) $5.01 Q1 2019Financial Borrowing Base ($mm)(6) $325 (1) Represents reported sales volumes (2) Reserve quantities based on SEC pricing. See appendix for SEC reserves, non-GAAP reconciliation and a constant price case at $55 Oil / $2.75 Gas (3) See “Reconciliation of Non-GAAP Financial Measure” on page 23 (4) Includes workovers and ad valorem taxes (5) Excludes non-cash stock-based compensation 8 (6) Borrowing base was increased from $275mm to $325mm on May 1, 2019
Areas of Operations (1) Total Midland Basin (1) 1P Reserves 98.8 1P Reserves 93.4 % PD 24% % PD 21% % Oil 60% % Oil 58% PV-10 ($mm) $1,009 PV-10 ($mm) $904 Q1 2019 Net Production (Boe/d)(2) 11,209 Q1 2019 Net Production (Boe/d)(2) 9,706 Gross Producing Wells 304 Gross Producing Wells 192 Core Net Acres 44,500 Core Net Acres 30,200 Core Gross Drilling Locations 934 Core Gross Drilling Locations 866 Eagle Ford (1) 1P Reserves 5.4 % PD 71% % Oil 84% PV-10 ($mm) $104 Q1 2019 Net Production (Boe/d)(2) 1,503 Gross Producing Wells 112 Core Net Acres 14,300 Core Gross Drilling Locations 68 (1) Reserve quantities based on SEC pricing. See appendix for SEC reserves, non-GAAP reconciliation and a constant price case at $55 Oil / $2.75 Gas 9 (2) Represents reported sales volumes
Continuous Focus on Operational Improvement . Meaningful improvements in drilling days and prudent Actual Drilling, Completions & Equipment Cost / Foot (1) service cost management over past year $1,800 8 ― D&C / lateral foot flat despite inflationary 7 environment in the last 12 months; however, current $1,500 service costs are trending down $1,252 6 $1,200 5 fWells W of # . Continue to see improvement in completion efficiencies $1,077 5 4 $924 $900 $835 4 ― Over the last 12 months, improved completions $774 $928 $794 $ / Lateral Foot $ / Lateral efficiency from 5 stages per day to 9 stages per day 3 $600 3 . Larger inventory of extended lateral locations also 2 expected to drive improved efficiencies $300 2 2 2 1 1 . Earthstone’s completion evolution is setting the stage for $0 0 Q3' 17 Q4' 17 Q1' 18 Q2' 18 Q3' 18 Q4' 18 Q1' 19 further well performance improvement Wells Spud to Rig Release Days (1)(2) ― Use of in-basin sand to help drive down costs while not affecting well performance 3.5 11,206 12,000 10,375 ― Continue to evaluate new completion techniques to 3.0 2.9 10,000 cost effectively enhance well performance 8,888 8,627 8,204 2.4 2.5 Length Lateral Average 2.3 8,000 2.0 2.0 2.0 7,585 1.8 6,000 6,237 Track record of driving down costs through improved 1.5 1.4 operational efficiencies to drive returns 4,000 1.0 Days per 1000 Lateral Lateral 1000 per Foot Days 2,000 0.5 0.0 0 Q3' 17 Q4' 17 Q1' 18 Q2' 18 Q3' 18 Q4' 18 Q1' 19 Average Lateral Length (1) Excludes wells that required additional casing string or pilot well test (2) Spud to rig release days = average spud to rig release days / (average lateral foot/1000) 10
Asset Overview 11
Significant Position in the Midland Basin 30,200 Total Net Acres in Core of Midland Basin Midland Basin Overview 866 gross locations Significant Operated Position in Midland Basin(1) 23,300 net acres, 94% average working interest, 500 gross locations Q1 2019 Net Production of 9,706 Boe/d(2) (65% oil, 85% liquids) Wells in progress drive immediate production growth Attractive Rates of Returns (“ROR”)(3) Single well RORs of 60% to +100% Position Delineated In Multiple Benches Strong offset results in the Wolfcamp A and B, Lower Spraberry, Additional Spraberry and Wolfcamp Benches Completion Evolution Sets Stage for Further Well Performance Improvement (1) Does not include non-operated position (2) Represents reported sales volumes for both operated and non-operated properties 12 (3) Single well rates of return based on flat price deck of Oil – $60.00/Bbl, Gas - $3.00/Mcf before deductions for transportation, gathering and quality differential
High Quality Pay Across Multiple Zones Reagan County Type Section Proven Multi-Zone Development . Current Reagan inventory ― 1 Wolfcamp A target Dean ― 2 Wolfcamp B targets ― 1 Wolfcamp C target Wolfcamp . 8 targets across 5 benches tested by industry A . ESTE development focused on Wolfcamp A, BU, and BL . Effectively co-developing all three focus zones where returns in Wolfcamp each bench are attractive B Upper ― New 3 well Sinclair pad co-developed in A, BU, and BL on lease with existing BU and BL parent wells Wolfcamp B Lower Quality Geology Across Thick Interval . Reagan County Wolfcamp ― Thickest Wolfcamp shale section in Midland Basin . Thermal maturity in oil window with low gas/oil ratios (“GOR”) ― Tmax values 440-450 across ESTE acreage Wolfcamp C ― Average 80% Liquids, 20% Gas . Significant Oil in Place ― Wolfcamp A to Wolfcamp B Lower contains 90-120 MMbo/sec . Shallower true vertical depth (“TVD”) than northern end of Midland Basin ― D&C costs are lower Cline ― Target TVDs are between 7,300-8,500’ Primary ESTE Landing Targets Development Focus Interval 13
Recent Southern Midland Basin Results Southern Midland Basin Activity Map Recent Well Results Well Name Operator IPW2 (Boe/d) IP/1000' (Boe) % Oil Industry Well 1 Torpedo 1048 B #5HA Apache 1,410 153 82% Earthstone Well 2 University 3-310 PU #9H Pioneer 1,242 127 84% Earthstone Operated Acreage 3 University 35-19 40 #104HA Hunt 1,030 101 91% Earthstone Non-Operated Acreage 4 Eaglehead C A4 #36AH Callon 1,306 179 83% 5 Cope 107-108 #31HS Sable 1,002 106 92% 6 Morgan A 25-26A-A #4201H Parsley 1,626 157 86% 7 Ratliff 9-7 B #2BU Earthstone 1,603 153 94% 8 Torpedo 1048 A #2HU Apache 1,944 211 89% 5 9 Fantasy #717WB Henry 1,075 177 89% 10 Sequoia #1H Driftwood 1,114 107 91% 14 6 15 11 Dogwood #1H Driftwood 1,449 144 87% 17 16 22 12 WTG 5-233 #1BU Earthstone 1,280 102 84% 4 13 1 8 23 13 Rocker B #137H Pioneer 1,491 155 91% 19 7 24 14 Sugg C #1915SM Laredo 2,070 232 72% 9 18 20 15 Aldwell 0544 #12HU Apache 1,726 226 85% 2 25 3 16 Lucy Lindsay 1-36-H #4315 Parsley 1,281 169 87% 10 17 Morgan A 25-26A-A #4401H Parsley 1,270 122 85% 18 Ratliff 9-7 A #1BL Earthstone 1,283 125 92% 11 19 Torpedo 1048 B #11HM Apache 3,011 328 93% 21 12 20 Benedum 3-6 #1BL Earthstone 1,828 245 88% 21 WTG 4-232 A #2BL Earthstone 1,746 169 88% 22 North Creek B #431CN Discovery 1,052 106 86% 23 Lucy Lindsay 1-36-H #4415 Parsley 888 115 86% 24 Torpedo 1048 A #8HL Apache 2,179 221 83% 25 University 2-20 #76H Pioneer 2,998 308 82% Wolfcamp A Wolfcamp BU Wolfcamp BL Wolfcamp C Wolfcamp D Source: Company filings, Investor presentations, DrillingInfo, RRC Note: Well completions filed since Jan 2018; IP tests are 24 hour tests from RRC W2 14
Differentiated, Balanced Inventory in Midland Basin Midland Basin Overview Gross Locations by Lateral Length and Target . Contiguous acreage positions provide significant development Gross Locations by Lateral Length advantage Target 5,000' - 6,250' 6,250' - 8,750' 8,750' - 10,000'+ Total % Total Wolfcamp A 9 109 138 256 30% . Long lateral development increases capital efficiency Wolfcamp B Upper 16 95 123 234 27% Wolfcamp B Lower 15 86 95 196 23% All Other Targets – 88 92 180 21% . Over 95% of Midland horizontal locations have laterals of ~6,250 feet Total Gross Locations 40 378 448 866 100% or greater Total Net Locations 28 226 242 496 % Total (Gross) 5% 44% 52% 100% – Over 50% of horizontal locations 8,750 feet or greater . Expect to complete 13 wells in 2019 with an average working Midland Basin Locations by Op / Non-Op interest of 86% and an average lateral length of ~9,600 ft Gross Net Average Average % of Gross Locations Locations LL WI Locations in WC A+B – Increasing average completed lateral length from ~8,000 ft and Operated 500 398 8,930 80% 92% ~7,900 ft in 2017 and 2018, respectively Non-Operated 366 97 8,884 27% 63% Total 866 496 8,910 57% 79% . Additional upside from: – Middle Spraberry – Jo Mill – Additional Lower Spraberry – Additional benches in Wolfcamp B – Wolfcamp D . Actively pursuing acreage and acquisition bolt-on opportunities to increase lateral lengths and ownership . Near-term drilling focused in the Wolfcamp A and the Wolfcamp B based on positive offset results, but we are optimistic about the upside potential in other zones Note: Gross location count includes only economic locations in 12/31/18 CGA reserve report 15
Midland Basin Performance Review Outperforming initial expectations and generating attractive returns at strip prices Improved internal rate of return (“IRR”) due to initial production outperforming previous type curves Reagan County Results(1) Midland and Upton County Results(2) 150 200 Reagan TC Midland/Upton TC 2017 Reagan Co Avg. (16 wells) 2017 Midland & Upton Co Avg. (6 wells) 2018 Reagan Co Avg. (13 wells) 175 2018 Midland & Upton Co Avg. (3 wells) 2019 Reagan Co Avg. (6 wells) 2019 Midland &Upton Co Avg. (2 wells) 120 150 125 90 100 60 75 50 30 7,500' Norm CUMULATIVE PRODUCTION, MBOE (2 STREAM) 7,500' Norm CUMULATIVE PRODUCTION, MBOE (2 STREAM) 25 0 0 0123456 0123456 TIME, MONTHS TIME, MONTHS Type Curve Summary (100% WI, 75% NRI 7,500' Laterals) (3) (4) (4) (5) Lateral Length DC & E EUR Oil NGL IRR Type Curve Area (ft) ($M) (MBoe) (%) (%) $50/$2.50 $60/$2.50 Midland / Upton 7,500 $7,200 1,000 67% 20% 74% >100% Reagan 7,500 $7,200 850 59% 22% 40% 58% Source: ESTE management, investor presentations (1) Reflects average cumulative production of wells completed in 2017 and 2018 in Reagan County; production data adjusted for downtime (2) Reflects average cumulative production of wells completed in 2017 and 2018 in Upton and Midland Counties (3) EUR calculated on a 2-stream basis (4) Percent oil and NGL calculated on a 3-stream basis (5) Single well rates of return assumes 3-stream economics on flat price deck of Oil - $50.00 and $60.00/Bbl, Gas - $2.50/Mcf before deductions for transportation, gathering, and 16 quality differential. Assumes 3 month delay from spud to first sales
Acreage Trade – Central Reagan County Acreage Trade Highlights Pre-Trade Post-Trade In October 2018, ESTE traded non-operated working interests in Glasscock County and paid $27.8 million in cash for operated working interests in Reagan County with an offset operator Added 3,899 operated net acres to Reagan County position (~100% working interest) Includes 14 PDP wells (8 horizontal, 6 vertical) Net increase of 350 Boe/d and 2,677 acres Additionally, ESTE finalized an additional lease acquisition which will add ~760 net acres in Reagan County in April 2019 With these acreage transactions, ESTE’s total net acreage in the Midland Basin has increased to ~30,200 acres, of which ~23,300 acres are operated ― ~14,000 contiguous net acres with 85% working interest in Central Reagan County ESTE Acreage Trade Added Acreage – 10/2018 Acreage Acquisition – 4/2019 17
Eagle Ford Asset Overview Karnes, Gonzales, and Fayette Counties, Texas . Operated Karnes, Gonzales, and Fayette Counties Tr av is Lee Washington Hays – 29,000 gross / 14,100 net leasehold acres Bastrop Austin Fa yet te – Working interests range from 17% to 67% Caldwell – 86% held-by-production Colorado Guadalupe . 112 gross / 47.9 net producing wells (106 operated / 6 non-op) Gonzales Lavaca . 68 identified gross Eagle Ford drilling locations Wilson Wharton Earthstone Acreage Gas Condensate Oil Window . Other Potential: Upper Eagle Ford, Austin Chalk, DeWitt Volatile Oil Jackson Buda, Wilcox, and Edwards Karnes Wet Gas Victoria 01020 . Recent increased offset activity suggests additional Goliad Miles upside Earthstone Lonestar Penn Virginia – Updated frac designs and longer laterals in the Bastrop Eagle Ford – Test of lower Austin Chalk Fayette s t n e t . Currently drilling 7 gross (1.5 net) wells on the Pen n x E o s a il t W a D Ranch Unit in Southern Gonzales County ic m is e S D - 3 Gonzales t it W G e o D K n a z rn a e le s s Lavaca Offset operators include EOG, Encana and Marathon 18
Financial Overview 19
Capital Budget, Guidance and Liquidity ESTE 2019 Capital Budget(1) 2019 FY Guidance(1) (3) Gross / Net Well Count 2019 Average Daily Production (Boepd) 11,000 - 12,000 ($ in millions) Wells Spudded On-Line % Oil 65% Drilling and Completion: % Gas 16% Operated Midland Basin (1 Rig) $118 16 / 13.5 13 / 11.2 % NGL 19% Non-Operated Midland Basin $47 20 / 5 19 / 5.6 Operating Costs: Operated Eagle Ford $10 7 / 1.5 7 / 1.5 Lease Operating and Workover ($/Boe) $5.25 - $5.75 Land / Infrastructure $15 Production Taxes (% of Revenue) 5.0% - 5.3% Total $190 (2) Cash G&A ($/Boe) $5.00 - $5.50 2019 Capex by Project Area(1) Liquidity (3/31/2019) ($mm) 3/31/2019 8% 6% Cash $0.4 5% Revolver Borrowings 120.8 25% Total Debt $120.8 62% Revolver Borrowing Base(4) 325.0 94% Less: Revolver Borrowings (120.8) Operated Midland Basin (1 Rig) Plus: Cash 0.4 Midland Basin Eagle Ford Non-Operated Midland Basin Operated Eagle Ford Liquidity $204.6 Land / Infrastructure (1) Assumes a 1-rig program for the operated Midland Basin acreage (2) Management estimates that approximately $50 million of the Company’s total capital budget is applicable to production growth for 2020 rather than 2019 (3) Based on 2019 Guidance provided on 1/16/2019, which is subject to numerous assumptions and risks 20 (4) Borrowing base was increased from $275mm to $325mm on May 1, 2019
Hedge Book Summary Oil Production Hedged Gas Production Hedged Period Volume (Bbls) Volume (Bbls/d) $/Bbl Period Volume (MMBtu) Volume (MMBtu/d) $/MMBtu Q2 2019 591,500 6,500 $65.53 Q2 2019 955,500 10,500 $2.857 Q3 2019 598,000 6,500 $65.53 Q3 2019 920,000 10,000 $2.856 Q4 2019 579,600 6,300 $65.74 Q4 2019 920,000 10,000 $2.856 Q2-Q4 2019 1,769,100 6,433 $65.60 Q2-Q4 2019 2,795,500 10,165 $2.856 FY 2020 1,830,000 5,000 $64.65 FY 2020 2,562,000 7,000 $2.850 WTI Midland Argus Crude Basis Swaps WAHA Differential Basis Swaps Period Volume (Bbls) Volume (Bbls/d) $/Bbl (Differential) Period Volume (MMBtu) Volume (MMBtu/d) $/MMBtu Q2 2019 500,500 5,500 ($5.29) Q2 2019 955,500 10,500 ($1.138) Q3 2019 506,000 5,500 ($5.29) Q3 2019 920,000 10,000 ($1.141) Q4 2019 506,000 5,500 ($5.29) Q4 2019 920,000 10,000 ($1.141) Q2-Q4 2019 1,512,500 5,500 ($5.29) Q2-Q4 2019 2,795,500 10,165 ($1.140) FY 2020 1,830,000 5,000 ($2.14) FY 2020 2,562,000 7,000 ($1.065) LLS Argus Crude Oil Basis Swaps Period Volume (Bbls) Volume (Bbls/d) $/Bbl (Differential) Q2 2019 91,000 1,000 $4.50 Q3 2019 92,000 1,000 $4.50 Q4 2019 92,000 1,000 $4.50 Q2-Q4 2019 275,000 1,000 $4.50 Oil Production Hedged(1) Gas Production Hedged (Volumes in Bbls) Oil ~84% Hedged (Volumes in MMBtu) Gas ~93% Hedged 4,000,000 of FY19 Guidance (2) 6,000,000 of FY19 Guidance (2) 3,000,000 4,500,000 1,769,100 1,787,500 1,830,000 1,830,000 2,795,500 2,795,500 2,562,000 2,562,000 2,000,000 3,000,000 1,000,000 1,500,000 0 0 Q2-Q4 '19 FY20 Q2-Q4 '19 FY20 Oil Swaps Crude Basis Swaps Gas Swaps WAHA Basis Swaps (1) Crude basis swaps reflect Midland Argus and LLS Argus crude basis swaps for Q2-Q4 ‘19 and FY20 (2) Based on midpoint of current guidance (11,000 – 12,000 boepd; 65% oil, 16% gas) 21
Analyst Coverage Firm Analyst Contact Info Alliance Global Partners Joel Musante / 203-349-4782 / [email protected] Baird Joseph Allman / 646-557-3209 / [email protected] Coker Palmer David Beard / 631-725-8810 / [email protected] Imperial Capital Jason Wangler / 713-892-5603 / [email protected] Johnson Rice Ron Mills / 504-584-1217 / [email protected] Northland Jeff Grampp / 949-600-4150 / [email protected] RBC Brad Heffern / 512-708-6311 / [email protected] Roth John White / 949-720-7115 / [email protected] Seaport Global John Aschenbeck / 713-658-6343 / [email protected] Stephens Gail Nicholson / 301-904-7466 / [email protected] SunTrust Neal Dingmann / 713-247-9000 / [email protected] Wells Fargo Gordon Douthat / 303-863-6880 / [email protected] 22
Contact Information Mark Lumpkin, Jr. EVP, Chief Financial Officer Scott Thelander Vice President of Finance Corporate Offices Houston 1400 Woodloch Forest Drive | Suite 300 | The Woodlands, TX 77380 | (281) 298-4246 Midland 600 N. Marienfeld | Suite 1000 | Midland, TX 79701 | (432) 686-1100 Website www.earthstoneenergy.com 23
Reconciliation of Non-GAAP Financial Measure Earthstone uses Adjusted EBITDAX, a financial measure that is not presented in accordance with United States generally accepted accounting principles (“GAAP”). Adjusted EBITDAX is a supplemental non- GAAP financial measure that is used by Earthstone’s management team and external users of its financial statements, such as industry analysts, investors, lenders and rating agencies. Earthstone’s management team believes Adjusted EBITDAX is useful because it allows Earthstone to more effectively evaluate its operating performance and compare the results of its operations from period to period without regard to its financing methods or capital structure. Earthstone defines Adjusted EBITDAX as net income (loss) plus, when applicable, loss (gain) on sale of oil and gas properties; accretion of asset retirement obligations; impairment expense; depletion, depreciation and amortization; transaction costs; interest expense, net; exploration expense; unrealized loss (gain) on mark-to-market of hedges; non-cash stock based compensation; and income tax (benefit). Earthstone excludes the foregoing items from net income (loss) in arriving at Adjusted EBITDAX because these amounts can vary substantially from company to company within their industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDAX should not be considered as an alternative to, or more meaningful than, net income (loss) as determined in accordance with GAAP or as an indicator of Earthstone’s operating performance or liquidity. Certain items excluded from Adjusted EBITDAX are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDAX. Earthstone’s computation of Adjusted EBITDAX may not be comparable to other similarly titled measures of other companies or to similar measures in Earthstone’s revolving credit facility. The following table provides a reconciliation of Net income to Adjusted EBITDAX for: 1Q’19 Adjusted EBITDAX ($ in 000s) FY 2018 Adjusted EBITDAX ($ in 000s) 1Q'19 FY 2018 Net income (loss) ($38,443) Net income (loss) (1) $95,213 Accretion of asset retirement obligations 54 Accretion of asset retirement obligations 169 Impairment expense - Impairment expense 4,581 Depletion, depreciation and amortization 14,005 Depletion, depreciation and amortization 47,568 Interest expense, net 1,449 Interest expense, net 2,898 Transaction costs 175 Transaction costs 13,524 Loss/(Gain) on sale of oil and gas properties 125 Loss/(Gain) on sale of oil and gas properties (1,919) Exploration expense - Exploration expense 630 Unrealized loss (gain) on derivative contracts 53,256 Unrealized loss (gain) on derivative contracts (76,038) Stock based compensation (non-cash)(2) 2,212 Stock based compensation (non-cash)(2) 7,071 Income tax expense (benefit) (460) Income tax expense (benefit) 2,470 Adjusted EBITDAX $32,373 Adjusted EBITDAX $96,167 (1) Net income includes a $4.8 million charge to expense accrual representing management’s estimate of a pending lawsuit settlement 24 (2) Included in General and administrative expense in the Consolidated Statements of Operations
Reserves Summary Earthstone’s proved reserves as of December 31, 2018 were independently estimated by Cawley, Gillespie & Associates, Inc. (“CGA”), independent petroleum engineers, utilizing SEC prescribed oil and gas prices of $65.56/bbl and $3.100/mmbtu, respectively, calculated for December 31, 2018. SEC prices net of differentials were $61.52/bbl and $2.16/Mcf for oil and gas, respectively. Earthstone is also providing an alternative summary of proved reserves, calculated in accordance with SEC rules, with the exception of using constant oil and gas prices of $55.00/bbl and $2.75/mmbtu, respectively, as shown in the table below. Year-End 2018 SEC Proved Reserves Oil Gas NGL Total PV-10 Reserves Category (Mbbls) (MMcf) (MBbls) (MBoe) ($ in thousands) Proved Developed 14,325 26,110 4,969 23,646 $435,736 Proved Undeveloped 44,709 87,107 15,974 75,201 572,764 Total 59,034 113,217 20,943 98,847 $1,008,500 Year-End 2018 Proved Reserves ($55.00 Oil / $2.75 Gas) Oil Gas NGL Total PV-10 Reserves Category (Mbbls) (MMcf) (MBbls) (MBoe) ($ in thousands) Proved Developed 13,957 25,393 4,830 23,019 $351,024 Proved Undeveloped 39,252 72,821 13,294 64,683 347,477 Total 53,209 98,214 18,124 87,702 $698,501 Note: PV-10 is a non-GAAP financial measure. See “Non-GAAP Financial Measure – PV-10” 25
Non-GAAP Financial Measure – PV-10 PV-10 is derived from the standardized measure of discounted future net cash flows (“Standardized Measure”), which is the most directly comparable financial measure under GAAP. PV-10 is a computation of the Standardized Measure on a pre-tax basis. PV-10 is equal to the Standardized Measure at the applicable date, before deducting future income taxes, discounted at 10%. We believe that the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to our estimated net proved reserves prior to taking into account future corporate income taxes, and it is a useful measure for evaluating the relative monetary significance of our oil and natural gas properties. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies. We use this measure when assessing the potential return on investment related to our oil and natural gas properties. PV-10, however, is not a substitute for the Standardized Measure. Our PV-10 measure and the Standardized Measure do not purport to present the fair value of our oil and natural gas reserves. The following table provides a reconciliation of PV-10 of the Company’s estimated proved properties to the Standardized Measure (in thousands): Reconciliation of PV-10 Present Value of estimated future net revenues (PV-10) $1,008,500 Future income taxes, discounted at 10% (49,048) Standardized measure of discounted future net cash flows $959,452 26
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