UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-K

 

(Mark One)

For the Fiscal Year Ended December 31, 2017

Or

Commission File No. 001-35049  

 

EARTHSTONE ENERGY, INC.

(Exact name of registrant as specified in its charter)

 

 

1400 Woodloch Forest Drive, Suite 300

The Woodlands, Texas 77380

(Address of principal executive offices)

Registrant’s telephone number, including area code: (281) 298-4246

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

 

Securities registered under Section 12(g) of the Act:

None

 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐ No ☑

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Exchange Act. Yes ☐ No ☑

Indicate by check mark whether the issuer (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the past 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to the filing requirements for the past 90 days. Yes ☑ No ☐

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to post such filed). Yes ☑ No ☐

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See definitions of “large accelerated filer”, “accelerated filer”, “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act (check one):

 

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.

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☑

The aggregate market value of voting and non-voting common equity held by non-affiliates computed by reference to the price of $10.01 per share at which the common equity was last sold, as of the last business day of the registrant’s most recently completed second fiscal quarter was approximately $181,689,218.

As of March 5, 2018, 27,828,773 shares of the registrant’s Class A Common Stock and 35,858,123 shares of Class B Common Stock were outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Registrant’s Definitive Proxy Statement for its 2018 Annual Meeting of Stockholders (the “Proxy Statement”), are incorporated by reference into Part III of this Annual Report on Form 10-K.

 

 

 

 

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TABLE OF CONTENTS

 

 

 

 

 

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CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS

Certain statements contained in this report may contain “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”). All statements other than statements of historical facts contained in this report are forward-looking statements. These forward-looking statements can generally be identified by the use of words such as “may,” “will,” “could,” “should,” “project,” “intends,” “plans,” “pursue,” “target,” “continue,” “believes,” “anticipates,” “expects,” “estimates,” “predicts,” or “potential,” the negative of such terms or variations thereon, or other comparable terminology. Statements that describe our future plans, strategies, intentions, expectations, objectives, goals, potential acquisitions or mergers or prospects are also forward-looking statements. Actual results could differ materially from those anticipated in this filing or these forward-looking statements. Readers should consider carefully the risks described under the “Risk Factors” section of this report and other sections of this report which describe factors that could cause our actual results to differ from those anticipated in forward-looking statements, including, but not limited to, the following factors:

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All forward-looking statements are expressly qualified in their entirety by the cautionary statements in this section and elsewhere in this report. Other than as required under the securities laws, we do not assume a duty to update these forward-looking statements, whether as a result of new information, subsequent events or circumstances, changes in expectations or otherwise.  You should not place undue reliance on these forward-looking statements.  All forward-looking statements speak only as of the date of this report or, if earlier, as of the date they were made.

For further information regarding these and other factors, risks and uncertainties affecting us, see Part I, Item 1A. Risk Factors of this report.

 

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GLOSSARY OF CERTAIN OIL AND NATURAL GAS TERMS

The following are abbreviations and definitions of terms commonly used in the oil and natural gas industry and within this report.

3-D seismic – An advanced technology method of detecting accumulation of hydrocarbons identified through a three-dimensional picture of the subsurface created by the collection and measurement of the intensity and timing of sound waves transmitted into the earth as they reflect back to the surface.

Bbl – One barrel or 42 U.S. gallons liquid volume of oil or other liquid hydrocarbons.

BOE – Barrel of oil equivalent, determined using a ratio of six Mcf of natural gas equal to one barrel of oil equivalent. The ratio does not assume price equivalency and, given price differentials, the price for a barrel of oil equivalent for natural gas differs significantly from the price for a barrel of oil.  A barrel of NGLs also differs significantly in price from a barrel of oil.

Btu – British thermal unit, the quantity of heat required to raise the temperature of one pound of water by one-degree Fahrenheit.

Completion – The process of treating and hydraulically fracturing a drilled well followed by the installation of permanent equipment for the production of oil or natural gas, or in the case of a dry hole, the reporting of abandonment to the appropriate regulatory agency.

Developed acreage – The number of acres which are allotted or assignable to producing wells or wells capable of production.

Development activities – Activities following exploration including the drilling and completion of additional wells and the installation of production facilities.

Development well – A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

Dry hole or well – A well found to be incapable of producing hydrocarbons economically.

Exploitation – A development or other project which may target proven or unproven reserves (such as probable or possible reserves), but which generally has a lower risk than that associated with exploration projects.

Exploratory well – A well drilled to find and produce oil or natural gas reserves in an area or a potential reservoir not classified as proved.

Farm-in or Farm-out – An agreement whereby the owner of a working interest in an oil and natural gas lease assigns or contractually conveys subject to future assignment the working interest or a portion thereof to another party who desires to drill on the leased acreage. Generally, the farmee is required to drill one or more wells in order to earn its interest in the acreage. The farmor usually retains a royalty and/or an after-payout interest in the lease. The interest received by the farmee is a “farm-in” while the interest transferred by the farmor is a “farm-out.”

Field – An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

Gross acres or gross wells – The total acres or wells, as the case may be, in which a working interest is owned.

HBP – Held by production, a mineral lease provision that extends the right to operate and maintain a lease as long as the property produces a minimum quantity of oil and/or natural gas.

Horizontal drilling – A drilling technique that permits the operator to drill horizontally within a specified targeted reservoir and thus exposes a larger portion of the producing horizon to a wellbore than would otherwise be exposed through conventional vertical drilling techniques.

Hydraulic fracture or Frac – A well stimulation method by which fluid, comprised largely of water and proppant (purposely sized particles used to hold open an induced fracture) are injected downhole and into the producing formation at high pressures and rates in order to exceed the rock strength and create a fracture such that the proppant material can be placed into the fracture to enhance the productive capability of the formation.

Injection well – A well which is used to inject gas, water, or liquefied petroleum gas under high pressure into a producing formation to maintain sufficient pressure to produce the recoverable reserves.

Joint Development Agreement or JDA – An agreement that provides for the joint development of a tract of land typically utilized after the leasing phase has concluded or when minerals are HBP.

Joint Operating Agreement or JOA – Any agreement between working interest owners concerning the duties and responsibilities of the operator and rights and obligations of the non-operators.

MBbls – One thousand barrels of crude oil or other liquid hydrocarbons.

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MBOE – One thousand barrels of oil equivalent, determined using a ratio of six Mcf of natural gas equal to one barrel of oil equivalent.

MMBtu – One million Btu.

Mcf – One thousand cubic feet.

MMcf – One million cubic feet.

Net acres or net wells – The sum of the fractional working interests owned in gross acres or gross wells.

NGLs – Natural gas liquids measured in barrels. NGLs are made up of ethane, propane, isobutane, normal butane and natural gasoline, each of which have different uses and different pricing characteristics.

NYMEX – The New York Mercantile Exchange.

Plugging and abandonment or P&A – Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another stratum or to the surface.

PV-10 – The present value of estimated future revenues, discounted at 10% annually, to be generated from the production of proved reserves determined in accordance with the SEC guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, without giving effect to (i) non-property related expenses such as general and administrative expenses, debt service and future income tax expense, or (ii) depreciation, depletion and amortization.

Productive well – A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceeds production expenses and taxes.

Proppant – A solid material, typically treated sand or man-made ceramic materials, designed to keep an induced hydraulic fracture open, during or following a fracturing treatment.

Proved developed nonproducing reserves or PDNP – Hydrocarbons in a potentially producing horizon penetrated by a wellbore, the production of which has been postponed pending completion activities and the installation of surface equipment or gathering facilities or pending the production of hydrocarbons from another formation penetrated by the wellbore. The hydrocarbons are classified as proved developed but nonproducing reserves.

Proved developed producing reserves or PDP – Reserves that can be expected to be recovered from existing wells and completions with existing equipment and operating methods.

Proved developed reserves or PD – The estimated quantities of oil, natural gas and NGLs that geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions.

Proved reserves – Those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. The area of the reservoir considered as proved includes (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (“LKH”), as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil (“HKO”), elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

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Proved undeveloped reserves or PUD – Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are schedule to be drilled within five years unless specific circumstances justify a longer time. Under no circumstances shall estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

Recompletion – The completion for production of an existing well bore in another formation from that in which the well has been previously completed.

Re-engineering – A process involving a comprehensive review of the mechanical conditions associated with wells and equipment in producing fields. Our re-engineering practices typically result in a capital expenditure plan which is implemented over time to workover (see below) and re-complete wells and modify down hole artificial lift equipment and surface equipment and facilities. The programs are designed specifically for individual fields to increase and maintain production, reduce down-time and mechanical failures, lower per-unit operating expenses, and therefore, improve field economics.

Reservoir – A permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

Royalty interest – An interest in an oil and natural gas property entitling the owner to a share of oil or natural gas production free of costs of production.

SEC – United States Securities and Exchange Commission.

Shut-in reserves – Those reserves expected to be recovered from completion intervals that were open at the time the reserve was estimated but were not producing due to market conditions, mechanical difficulties or because production equipment or pipelines were not yet installed. These reserves are included in the PDNP category in our reserve report.

Slickwater – A method of hydraulic fracturing that predominately uses water and chemicals, with sand, that is injected into an oil or natural gas reservoir to create a fracture in the reservoir rock and create or enhance fluid flow.

Undeveloped acreage – Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.

Working interest or WI – The ownership interest, generally defined in a JOA, that gives the owner the right to drill, produce and/or conduct operating activities on the property and share in the sale of production, subject to all royalties, overriding royalties and other burdens and obligates the owner of the interest to share in all costs of exploration, development operations and all risks in connection therewith.

Workover – Operations on a producing well to restore or increase production.

 

 

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PART I

Item 1.  Business

Overview

Earthstone Energy, Inc., a Delaware corporation (together with our consolidated subsidiaries, the “Company,” “our,” “we,” “us,” “Earthstone” or similar terms), is a growth-oriented independent oil and gas company engaged in the acquisition and development of oil and gas reserves through activities that include the acquisition, drilling and development of undeveloped leases, asset and corporate acquisitions and mergers and, to a lesser extent, exploration activities. Our operations are all in the upstream segment of the oil and natural gas industry and all our properties are onshore in the United States.  At present, our primary assets are located in the Midland Basin of west Texas and the Eagle Ford Trend of south Texas.

Historically, we have operated in multiple basins in order to enable us to benefit from regional differences in realized prices and the availability and cost of equipment and services.  Starting in May 2017, with the closing of the Bold Transaction (more fully described below), our focus has been primarily in the Midland Basin of west Texas where our acreage has multiple stacked pay intervals in the Wolfcamp and, to a lesser extent the Spraberry formations. We believe the area is characterized by high oil and liquids-rich natural gas content, multiple vertical and horizontal target horizons and high drilling success rates. Since May 2017, we have used one drilling rig and successfully drilled nine wells in the Midland Basin. With approximately 943 potential gross drilling locations in the Midland Basin, our future development will be focused predominately on horizontal development drilling in the area. We currently intend to run one rig continuously in the Midland Basin and are considering deploying another rig in the second half of 2018, depending on commodity prices and the cost and availability of quality services. Our second area of focus is the Eagle Ford Trend where we have locations in the Eagle Ford and Austin Chalk formations. During 2017, we used one drilling rig and successfully drilled 11 Eagle Ford wells. We plan to have a similar drilling program in 2018 which should allow us to maintain our acreage positions. We have approximately 161 potential gross operated drilling locations in the Eagle Ford Trend for future development. In order to allow us to focus on the Midland Basin, during 2017, we divested our Bakken and other non-core properties and reduced our working interest in certain wells that we drilled in the Eagle Ford through joint development agreements while maintaining operatorship and our acreage positions.  

Currently, our reserve portfolio primarily consists of assets in the Midland Basin of west Texas and the Eagle Ford Trend of south Texas. We have 26,665 net acres in the core of the Midland Basin, of which 77% is operated and 23% is non-operated.  We hold an approximately 87% working interest in our operated acreage and an approximately 38% working interest in our non-operated acreage.  Our operated acreage in the Midland Basin is primarily located in Reagan, Upton and Midland counties. Our non-operated acreage in the Midland Basin is located primarily in Howard, Glasscock, Martin and Midland counties. In total, we have an interest in approximately 195 gross producing wells in the Midland Basin.  We have 19,856 net leasehold acres in the Eagle Ford Trend of south Texas, including 16,045 operated net leasehold acres in the crude oil window in Fayette, Gonzales and Karnes counties, with working interests ranging from approximately 16% to 50%, and 2,863 non-operated net leasehold acres located in the natural gas and condensate window in La Salle County, with an average working interest of approximately 13%. Our 948 remaining net leasehold acres located in the Eagle Ford Trend, reside in Frio and Wilson counties. In total, we have an interest in approximately 165 gross producing wells in the Eagle Ford Trend.  

At December 31, 2017, our estimated proved oil and natural gas reserves were approximately 79,976 MBOE based on the reserve report prepared by Cawley, Gillespie & Associates, Inc. (“CG&A”), our independent reserve engineers. Based on this report, at December 31, 2017, our proved reserve quantities were approximately 59% oil, 19% natural gas, 22% NGLs and 25% classified as proved developed. The calculated percentages include proved developed non-producing reserves. Of these interests, approximately 45,346 MBOE are attributable to noncontrolling interests. See Note 8. Noncontrolling Interests in the Notes to Consolidated Financial Statements.

Our Business Strategy

Our current business strategy is to focus on the economic development of our existing acreage, increase our acreage and well locations in oil-rich areas of the Midland Basin and increase stockholder value through the following:

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Our Strengths

We believe that the following strengths will be beneficial in achieving our business goals:

Recent Developments

Bold Contribution Agreement

In May, 2017, Earthstone completed a contribution agreement dated as of November 7, 2016 and as amended on March 21, 2017 (the “Bold Contribution Agreement”), by and among Earthstone, Earthstone Energy Holdings, LLC (“EEH”), Lynden US, Lynden USA Operating, LLC, a Texas limited liability company (“Lynden Op”), Bold Energy Holdings, LLC, a Texas limited liability company (“Bold Holdings”), and Bold Energy III LLC, a Texas limited liability company (“Bold”). The purpose of the Bold Contribution Agreement was to provide for, among other things described below, the business combination between Earthstone and Bold, which owned significant developed and undeveloped oil and natural gas properties in the Midland Basin of Texas (the “Bold Transaction”).

The Bold Transaction was structured in a manner commonly known as an “Up-C.” Under this structure and the Bold Contribution Agreement, (i) Earthstone recapitalized its common stock into two classes – Class A common stock, $0.001 par value per share (the “Class A Common Stock”), and Class B common stock, $0.001 par value per share (the “Class B Common Stock”), and all of Earthstone’s existing outstanding common stock, $0.001 par value per share (the “Common Stock”), was recapitalized on a one-for-one basis for Class A Common Stock (the “Recapitalization”); (ii) Earthstone transferred all of its membership interests in Earthstone Operating, LLC, Sabine River Energy, LLC, EF Non-Op, LLC and Earthstone Legacy Properties, LLC (formerly Earthstone GP, LLC) and $36,071 in cash from the sale of Class B Common Stock to Bold Holdings (collectively, the “Earthstone Assets”) to EEH, in exchange for 16,791,296 membership units of EEH (the “EEH Units”); (iii) Lynden US transferred all of its membership interests in Lynden Op to EEH in exchange for 5,865,328 EEH Units; (iv) Bold Holdings transferred all of its membership interests in Bold to EEH in exchange for 36,070,828 EEH Units and purchased 36,070,828 shares of Class B Common Stock issued by Earthstone for $36,071; and (v) Earthstone granted an aggregate of 150,000 fully vested shares of Class A Common Stock under Earthstone’s 2014 Long-Term Incentive Plan, as amended (the “2014 Plan”), to certain employees of Bold. Each EEH Unit, together with one share of Class B Common Stock, are convertible into one share of Class A Common Stock. 

Upon closing of the Bold Transaction on May 9, 2017, Bold Holdings owned approximately 61.4% of the outstanding shares of Class A Common Stock, on a fully diluted, as converted basis. The EEH Units and the shares of Class B Common Stock issued to Bold Holdings were not registered under the Securities Act but were issued by EEH and Earthstone in reliance on the exemption provided under Section 4(a)(2) of the Securities Act.

Pursuant to the terms of the Bold Contribution Agreement, at the closing of the Bold Transaction, Earthstone, Bold Holdings, and the unitholders of Bold Holdings entered into a registration rights agreement (the “Registration Rights Agreement”) relating to the shares of Class A Common Stock issuable upon the exchange of the EEH Units and Class B Common Stock held by Bold Holdings or its unitholders. In accordance with the Registration Rights Agreement, Earthstone filed a registration statement (the “Registration Statement”) with the SEC to permit the public resale of the shares of Class A Common Stock issued by Earthstone to Bold Holdings or its unitholders in connection with the exchange of Class B Common Stock and EEH Units in accordance with the terms of the First Amended and Restated Limited Liability Company Agreement of EEH (the “EEH LLC Agreement”). On October 18, 2017, the Registration Statement was declared effective by the SEC.

On May 9, 2017, in connection with the closing of the Bold Contribution Agreement, Earthstone, EnCap Investments L.P. (“EnCap”), Oak Valley Resources, LLC (“OVR”), and Bold Holdings entered into a voting agreement (the “Voting Agreement”), pursuant to which EnCap, OVR, and Bold Holdings agreed not to vote any shares of Class A Common Stock or Class B Common Stock held by them in favor of any action, or take any action that would in any way alter the composition of the board of directors of Earthstone (the “Board”) from its composition immediately following the closing of the Bold Contribution Agreement as long as the Voting Agreement is in effect.

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Immediately following the closing of the Bold Contribution Agreement, the Board was increased to nine members from eight members, four of which are designated by EnCap, three of which are independent, and two of which are members of our management, including Earthstone’s Chief Executive Officer. At any time during the effectiveness of the Voting Agreement during which EnCap’s collective ownership of Earthstone exceeds 50% of the total issued and outstanding voting stock, EnCap may remove and replace one director that was not originally designated by EnCap, and his or her successors. Any such removal and replacement must be conducted in accordance with the provisions of Earthstone’s certificate of incorporation and bylaws then in effect. The Voting Agreement terminates on the earlier of (i) the fifth anniversary of the closing date of the Bold Contribution Agreement and (ii) the date upon which EnCap, OVR, and Bold Holdings collectively own, of record and beneficially, less than 20% of Earthstone’s outstanding voting stock.

On May 9, 2017, the closing sale price of the Class A Common Stock was $13.58 per share. On May 10, 2017, the Class A Common Stock was uplisted from the NYSE American, LLC (formerly the NYSE MKT) (the “NYSE American”) to the New York Stock Exchange (the “NYSE”) where it is listed under the symbol “ESTE.”

Credit Agreement

On May 9, 2017, in connection with the closing of the Bold Transaction, the Company exited its credit agreement dated December 19, 2014, by and among Earthstone and its subsidiaries, BOKF, NA dba Bank of Texas, and the Lenders party thereto (as amended, modified or restated from time to time, the “ESTE Credit Agreement”). At that time, all outstanding borrowings of $10.0 million under the ESTE Credit Agreement were repaid and $0.5 million of remaining unamortized deferred financing costs were expensed and included in Write-off of deferred financing costs in the Consolidated Statements of Operations.  

On May 9, 2017, EEH (the “Borrower”), Earthstone Operating, LLC, EF Non-Op, LLC, Sabine River Energy, LLC, Earthstone Legacy Properties, LLC, Lynden Op, Bold, Bold Operating, LLC (the “Guarantors”), BOKF, NA dba Bank of Texas, as Agent and Lead Arranger, Wells Fargo Bank, National Association as Syndication Agent and the Lenders party thereto (the “Lenders”), entered into a credit agreement (as amended, modified or restated from time to time, the “EEH Credit Agreement”).

The borrowing base under the EEH Credit Agreement is currently $185.0 million and is subject to redetermination on or about November 1st and May 1st of each year. The amounts borrowed under the EEH Credit Agreement bear annual interest rates at either (a) the London Interbank Offered Rate (“LIBOR”) plus 2.25% to 3.25% or (b) the prime lending rate of the Bank of Texas plus 1.25% to 2.25%, depending on the amounts borrowed under the EEH Credit Agreement. Principal amounts outstanding under the EEH Credit Agreement are due and payable in full at maturity on May 9, 2022. All of the obligations under the EEH Credit Agreement, and the guarantees of those obligations, are secured by substantially all of EEH’s assets. Additional payments due under the EEH Credit Agreement include paying a commitment fee of 0.50% per year to the Lenders in respect of the unutilized commitments thereunder, as well as certain other customary fees.

The EEH Credit Agreement contains a number of covenants that, among other things, restrict, subject to certain exceptions, EEH’s ability to incur additional indebtedness, create liens on assets, make investments, enter into sale and leaseback transactions, pay dividends and make distributions or repurchase its limited liability interests, engage in mergers or consolidations, sell certain assets, sell or discount any notes receivable or accounts receivable and engage in certain transactions with affiliates.

In addition, the EEH Credit Agreement requires EEH to maintain the following financial covenants: a current ratio of not less than 1.0 to 1.0 and a leverage ratio of not greater than 4.0 to 1.0. Leverage ratio means the ratio of (i) the aggregate debt of EEH and its consolidated subsidiaries as at the last day of the fiscal quarter (excluding any debt from obligations relating to non-cash losses under Financial Accounting Standards Board (“FASB”) ASC 815, Derivatives and Hedging (FASB ASC 815”) as a result of changes in the fair market value of derivatives) to (ii) the product of EBITDAX for such fiscal quarter multiplied by four. The term “EBITDAX” means, for any period, the sum of consolidated net income for such period plus (a) the following expenses or charges to the extent deducted from consolidated net income in such period: (i) interest, (ii) taxes, (iii) depreciation, (iv) depletion, (v) amortization, (vi) non-cash losses under FASB ASC 815 as a result of changes in the fair market value of derivatives, (vii) exploration expenses, (viii) impairment expenses, and (ix) non-cash compensation expenses and minus (b) to the extent included in consolidated net income in such period, non-cash gains under FASB ASC 815 as a result of changes in the fair market value of derivatives.

The EEH Credit Agreement contains customary affirmative covenants and defines events of default to include failure to pay principal or interest, breach of covenants, breach of representations and warranties, insolvency, judgment default, and if Frank A. Lodzinski ceases to serve and function as Chief Executive Officer of EEH and the majority of the Lenders do not approve of Mr. Lodzinski’s successor. Upon the occurrence and continuance of an event of default, the Lenders have the right to accelerate repayment of the loans and exercise their remedies with respect to the collateral.

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On December 1, 2017, EEH entered into an amendment (the “Amendment”) to the EEH Credit Agreement. Among other things, the Amendment (i) increased the borrowing base from $150.0 million to $185.0 million; (ii) eliminated the limitation on the Borrower to request a loan when the consolidated cash held by the Company exceeds a certain threshold; (iii) reduced the frequency of reporting of hedging agreements by the Borrower to the Lenders; (iv) allows for the sale or transfer of any oil and gas property or any interest in any oil and natural gas property in excess of 5% of the value of the Company’s proved developed producing reserves, subject to a redetermination of the borrowing base; and (v) allows the Borrower to enter into hedging agreements pertaining to oil and natural gas properties to be acquired pursuant to a proposed acquisition and, if terminated, liquidated within ten business days.

Class A Common Stock Offering

In October 2017, we completed a public offering of 4,500,000 shares of Class A Common Stock, at a public offering price of $9.25 per share, receiving net proceeds of $39.4 million, after deducting underwriters’ fees and offering expenses of $2.2 million. The net proceeds were used to repay outstanding indebtedness under the EEH Credit Agreement.

Bakken Divestiture

In December 2017, we closed the sale of all of our oil and natural gas leases, oil and natural gas wells and associated assets located in the Williston Basin in North Dakota (the “Bakken Sale”) for a net cash consideration of approximately $26.4 million after normal and customary purchase price adjustments of $0.9 million to account for net cash flows from the effective date to the closing date. The sale resulted in a net gain of approximately $3.0 million recorded in Gain on sale of oil and gas properties in the Consolidated Statements of Operations. The effective date of the sale was December 1, 2017.  The net proceeds were used to repay $25.0 million of outstanding borrowings under the EEH Credit Agreement and the remaining $1.4 million retained in cash for current operating funds.

Organizational Structure

Earthstone is the sole managing member of EEH, with a controlling interest in EEH. Earthstone, together with its wholly-owned subsidiary, Lynden Energy Corp., a corporation organized under the laws of British Columbia (“Lynden Corp”), and Lynden Corp’s wholly-owned consolidated subsidiary, Lynden US and also a member of EEH, consolidates the financial results of EEH and records a noncontrolling interest in the Consolidated Financial Statements representing the economic interests of EEH's members other than Earthstone and Lynden US.     

Our Operations

We are currently the operator of properties containing approximately 70% of our proved oil and natural gas reserves and 73% of our proved PV-10 as of December 31, 2017 (see reconciliation of PV-10 to the standardized measure of discounted future net cash flows in Item 2. Properties). As operator, we manage and are able to directly influence development and production of operations of our operated properties. Independent contractors engaged by us provide all the equipment and personnel associated with these activities.  We employ petroleum engineers, geologists and land professionals who work on improving operating cost, production rates and reserves. Our producing properties have reasonably predictable production profiles and cash flows, subject to commodity price fluctuations. Our status as an operator has allowed us to pursue the development of undeveloped acreage, further develop existing properties and generate new projects.

As is common in our industry, we participate in non-operated properties on a selective basis. Decisions to participate in non-operated properties are dependent upon the technical and economic nature of the projects and the operating expertise and financial standing of the operators.

Operational Risks

Oil and natural gas exploitation, development and production involve a high degree of risk, which even a combination of experience, knowledge and careful evaluation may not be able to overcome. There is no assurance that we will acquire, discover or produce additional oil and natural gas in commercial quantities. Oil and natural gas operations also involve the risk that well fires, blowouts, equipment failure, human error and other events may cause accidental leakage or spills of toxic or hazardous materials, such as petroleum liquids or drilling fluids into the environment or cause significant injury to persons or property. In such event, substantial liabilities to third parties or governmental entities may be incurred, the satisfaction of which could substantially reduce our available cash and possibly result in loss of oil and natural gas properties. Such hazards may also cause damage to or destruction of wells, producing formations, production facilities and pipeline or other processing facilities.

As is common in the oil and natural gas industry, we do not insure fully against all risks associated with our business either because such insurance is not available or because we believe the premium costs are prohibitive. A loss not fully covered by insurance could have a material effect on our operating results, financial position and cash flows. For further discussion of these risks see Item 1A. Risk Factors of this report.

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Marketing and Customers

We market the majority of the production from properties we operate for both our account and the account of the other working interest owners in these properties. We sell our production to purchasers at market prices.

We normally sell production to a relatively small number of customers, as is customary in the exploration, development and production business. For the year ended December 31, 2017, three purchasers accounted for 18%, 14% and 14%, respectively, of our revenue during the period. For the year ended December 31, 2016, two purchasers accounted for 41% and 19%, respectively, of our revenue during the period. For the year ended December 31, 2015, one purchaser accounted for 62% of our revenue during the period. No other customer accounted for more than 10% of our revenue during these periods. If a major customer decided to stop purchasing oil and natural gas from us, revenue could decline and our operating results and financial condition could be harmed. However, we believe that the loss of any one or all of our major purchasers would not have a materially adverse effect on our financial condition or results of operations, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers.

Transportation

During the planning stage of our fields, we consider all gathering and delivery infrastructure in the areas of our production. Our oil is transported from the wellhead to our tank batteries by our gathering systems. The purchaser of our oil takes delivery of the oil at the tank batteries and transports the oil by truck on a frequent interval, from which point it is transported by various modes by the purchaser to the eventual refining facility. Our natural gas is transported from the wellhead to the purchaser’s meter and pipeline interconnection point through our gathering systems.

In addition, we move the majority of our produced water by pipeline connected to our operated salt water disposal wells rather as wells as by truck to a final disposal destination. 

Competition

The domestic oil and natural gas industry is intensely competitive in the exploration for and acquisition of reserves and in the producing and marketing of its production. Our competitors include national oil companies, major oil and natural gas companies, independent oil and natural gas companies, drilling partnership programs, individual producers, natural gas marketers, and major pipeline companies, as well as participants in other industries supplying energy and fuel to consumers. Many of our competitors are large, well-established companies. They may be able to pay more for seismic information and lease rights on oil and natural gas properties and to define, evaluate, bid for and purchase a greater number of properties, than our financial or human resources permit. Our ability to acquire additional properties in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate related transactions in a highly competitive environment.

There is also competition between oil and natural gas producers and other industries producing energy and fuel. Furthermore, competitive conditions may be substantially affected by various forms of energy legislation and/or regulation considered from time to time by the governments of the United States and the jurisdictions in which we operate. It is not possible to predict the nature of any such legislation or regulation which may ultimately be adopted or its effects upon our future operations. Such laws and regulations may substantially increase the costs of exploring for, developing or producing oil and natural gas and may prevent or delay the commencement or continuation of a given operation. Our larger competitors may be able to absorb the burden of existing and any changes to, federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position.

Segment Information and Geographic Area

Operating segments are defined under accounting principles generally accepted in the United States (“GAAP”) as components of an enterprise that (i) engage in activities from which it may earn revenues and incur expenses (ii) for which separate operational financial information is available and is regularly evaluated by the chief operating decision maker for the purpose of allocating resources and assessing performance.

Based on our organization and management, we have only one reportable operating segment, which is oil and natural gas acquisition, exploration and production. We consider drilling rig services ancillary to our oil and natural gas exploration and producing activities and manage these services to support such activities. All of our operations are currently conducted in Texas.

Seasonality of Business

Weather conditions often affect the demand for, and prices of, natural gas and can also delay oil and natural gas drilling activities, disrupting our overall business plans. Demand for natural gas is typically higher during the winter, resulting in higher natural gas prices for our natural gas production during our first and fourth fiscal quarters. Due to these seasonal fluctuations, our results of operations for individual quarterly periods may not be indicative of the results that we may realize on an annual basis.

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Markets for Sale of Production

Our ability to market oil and natural gas found and produced, if any, will depend on numerous factors beyond our control, the effect of which cannot be accurately predicted or anticipated. Some of these factors include, without limitation, the availability of other domestic and foreign production, the marketing of competitive fuels, the proximity and capacity of pipelines, fluctuations in supply and demand, the availability of a ready market, the effect of United States federal and state regulation of production, refining, transportation and sales and general national and worldwide economic conditions. Additionally, we may experience delays in marketing natural gas production and fluctuations in natural gas prices and our marketing professionals may experience short-term delays in marketing oil due to trucking and refining constraints. There is no assurance that we will be able to market any oil or natural gas produced, or, if such oil or natural gas is marketed, that favorable prices can be obtained.  

The United States natural gas market has undergone several significant changes over the past few decades. The majority of federal price ceilings were removed in 1985 and the remainder were lifted by the Natural Gas Wellhead Decontrol Act of 1989. Thus, currently, the United States natural gas market is operating in a free market environment in which the price of gas is determined by market forces rather than by regulations. At the same time, the domestic natural gas industry has also seen a dramatic change in the manner in which gas is bought, sold and transported. In most cases, natural gas is no longer sold to a pipeline company. Instead, the pipeline company now primarily serves the role of transporter and gas producers are free to sell their product to marketers, local distribution companies, end users or a combination thereof.

In recent years, oil, natural gas and NGLs prices have been under considerable pressure due to oversupply and other market conditions. Specifically, increased foreign production and increased efficiencies in horizontal drilling, combined with exploration of newly developed shale fields in North America, have dramatically increased global oil and natural gas production, which has led to significantly lower market prices for these commodities. In view of the many uncertainties affecting the supply and demand for oil, natural gas and NGLs, we are unable to accurately predict future oil, natural gas and NGLs prices or the overall effect, if any, that the decline in demand for and the oversupply of such products will have on our financial condition or results of operations.

Title to Properties

We believe that the title to our oil and natural gas properties is good and defensible in accordance with standards generally accepted in the oil and natural gas industry, subject to such exceptions which, in our opinion, are not so material as to detract substantially from the use or value of our oil and natural gas properties. Our oil and natural gas properties are typically subject, in one degree or another, to one or more of the following:

To the extent that such burdens and obligations affect our rights to production revenues, they have been taken into account in calculating our net revenue interests and in estimating the quantity and value of our reserves. We believe that the burdens and obligations affecting our oil and natural gas properties are common in our industry with respect to the types of properties we own.

Operational Regulations

All of the jurisdictions in which we own or operate producing oil and natural gas properties have statutory and regulatory provisions affecting drilling, completion, and production activities, including provisions related to permits for the drilling of wells, bonding requirements to drill or operate wells, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, sourcing and disposal of water used in the drilling and completion process, and the plugging and abandonment of wells. Our operations are also subject to various conservation laws and regulations. These laws and regulations govern the size of drilling and spacing units, the density of wells that may be drilled in oil and natural gas properties and the unitization or pooling of oil and natural gas properties. In this regard, while some states allow the forced pooling or integration of land and leases to facilitate development, other states including Texas, where we operate, rely primarily or exclusively on voluntary pooling of land and leases. Accordingly, it may be difficult for us to form spacing units and therefore difficult to develop a project if

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we own or control less than 100% of the leasehold. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas, and impose specified requirements regarding the ratability of production. On some occasions, local authorities have imposed moratoria or other restrictions on exploration, development and production activities pending investigations and studies addressing potential local impacts of these activities before allowing oil and natural gas exploration, development and production to proceed.

The effect of these regulations is to limit the amount of oil and natural gas that we can produce from our wells and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing. Failure to comply with applicable laws and regulations can result in substantial penalties. The regulatory burden on the industry increases the cost of doing business and affects profitability. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction.

Regulation of Transportation of Natural Gas

The transportation and sale, or resale, of natural gas in interstate commerce are regulated by the Federal Energy Regulatory Commission (“FERC”) under the Natural Gas Act of 1938 (“NGA”), the Natural Gas Policy Act of 1978 (“NGPA”) and regulations issued under those statutes. FERC regulates interstate natural gas transportation rates and service conditions, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.

Intrastate natural gas transportation is also subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.

Regulation of Sales of Oil, Natural Gas and Natural Gas Liquids

The prices at which we sell oil, natural gas and natural gas liquids are not currently subject to federal regulation and, for the most part, are not subject to state regulation. FERC, however, regulates interstate natural gas transportation rates, and terms and conditions of transportation service, which affects the marketing of the natural gas we produce, as well as the prices we receive for sales of our natural gas. Similarly, the price we receive from the sale of oil and natural gas liquids is affected by the cost of transporting those products to market.  FERC regulates the transportation of oil and liquids on interstate pipelines under the provision of the Interstate Commerce Act, the Energy Policy Act of 1992 and regulations issued under those statutes.  Intrastate transportation of oil, natural gas liquids, and other products, is dependent on pipelines whose rates, terms and conditions of service are subject to regulation by state regulatory bodies under state statutes. In addition, while sales by producers of natural gas and all sales of crude oil, condensate, and natural gas liquids can currently be made at uncontrolled market prices, Congress could reenact price controls in the future. 

Changes in law and to FERC policies and regulations may adversely affect the availability and reliability of firm and/or interruptible transportation service on interstate pipelines, and we cannot predict what future action FERC will take. We do not believe, however, that any regulatory changes will affect us in a way that materially differs from the way they will affect other natural gas producers, gatherers and marketers with which we compete.

Environmental Regulations

Our operations are also subject to stringent federal, state and local laws regulating the discharge of materials into the environment or otherwise relating to health and safety or the protection of the environment. Numerous governmental agencies, such as the United States Environmental Protection Agency (the “EPA”) issue regulations to implement and enforce these laws, which often require difficult and costly compliance measures. Among other things, environmental regulatory programs typically govern the permitting, construction and operation of a well or production related facility. Many factors, including public perception, can materially impact the ability to secure an environmental construction or operation permit. Failure to comply with environmental laws and regulations may result in the assessment of substantial administrative, civil and criminal penalties, as well as the issuance of injunctions limiting or prohibiting our activities. In addition, some laws and regulations relating to protection of the environment may, in certain circumstances, impose strict liability for environmental contamination, which could result in liability for environmental damages and cleanup costs without regard to negligence or fault on our part.

Beyond existing requirements, new programs and changes in existing programs, may affect our business including oil and natural gas exploration and production, air emissions, waste management, and underground injection of waste material. Environmental laws and regulations have been subject to frequent changes over the years, and the imposition of more stringent requirements could have a material adverse effect on our financial condition and results of operations. The following is a summary of the more significant existing environmental, health and safety laws and regulations to which our business operations are subject and for which compliance in the future may have a material adverse impact on our capital expenditures, earnings and competitive position.

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Hazardous Substances and Wastes

The federal Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (“CERCLA”), also known as the Superfund law, and comparable state laws impose liability, without regard to fault or the legality of the original conduct on certain categories of persons that are considered to be responsible for the release of a hazardous substance into the environment. These persons may include the current or former owner or operator of the site or sites where the release occurred and companies that disposed or arranged for the disposal of hazardous substances found at the site. Under CERCLA, these potentially responsible persons may be subject to strict, joint and several liability for the costs of investigating and cleaning up hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. We are able to control directly the operation of only those wells with respect to which we act as operator. Notwithstanding our lack of direct control over wells operated by others, the failure of an operator other than us to comply with applicable environmental regulations may, in certain circumstances, be attributed to us. We generate materials in the course of our operations that may be regulated as hazardous substances but we are not presently aware of any liabilities for which we may be held responsible that would materially or adversely affect us.

The Resource Conservation and Recovery Act of 1976 (“RCRA”), and comparable state statutes, regulate the generation, treatment, storage, transportation, disposal and clean-up of hazardous and solid (non-hazardous) wastes. With the approval of the EPA, the individual states can administer some or all of the provisions of RCRA, and some states have adopted their own, more stringent requirements. Drilling fluids, produced waters and most of the other wastes associated with the exploration, development and production of oil and natural gas are currently regulated under RCRA’s solid (non-hazardous) waste provisions. However, legislation has been proposed from time to time and various environmental groups have filed lawsuits that, if successful, could result in the reclassification of certain oil and natural gas exploration and production wastes as “hazardous wastes,” which would make such wastes subject to much more stringent handling, disposal and clean-up requirements. For example, in response to a lawsuit filed in the U.S. District Court for the District of Columbia by several non-governmental environmental groups against the EPA for the agency’s failure to timely assess its RCRA Subtitle D criteria regulations for oil and natural gas wastes, the EPA and the environmental groups entered into an agreement that was finalized in a consent decree issued by the District Court on December 28, 2016. Under the decree, the EPA is required to propose no later than March 15, 2019, a rulemaking for revision of certain Subtitle D criteria regulations pertaining to oil and natural gas wastes or sign a determination that revision of the regulations is not necessary. If the EPA proposes a rulemaking for revised oil and natural gas waste regulations, the consent decree requires that the EPA take final action following notice and comment rulemaking no later than July 15, 2021. A loss of the RCRA exclusion for drilling fluids, produced waters and related wastes could result in an increase in our, as well as the oil and natural gas E&P industry’s, costs to manage and dispose of generated wastes, which could have a material adverse effect on the industry as well as on our business.

From time to time, releases of materials or wastes have occurred at locations we own or at which we have operations. These properties and the materials or wastes released thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, we have been and may be required to remove or remediate such materials or wastes.

Water Discharges

The federal Clean Water Act and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States. The discharge of pollutants into regulated waters, including jurisdictional wetlands, is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. In September 2015, a new EPA and U.S. Army Corps of Engineers rule defining the scope of federal jurisdiction over wetlands and other waters became effective. To the extent the rule expands the range of properties subject to the Clean Water Act’s jurisdiction, certain energy companies could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas. The rule has been challenged in court on the grounds that it unlawfully expands the reach of Clean Water Act programs, and implementation of the rule has been stayed pending resolution of the court challenge. In addition, following the issuance of a presidential executive order to review the rule, on July 27, 2017, the EPA proposed to repeal the rule and also separately announced its intent to conduct a substantive re-evaluation of the definition of “waters of the United States” in a future rulemaking. As a result, future implementation of the rule is uncertain at this time.

The process for obtaining permits has the potential to delay our operations. Spill prevention, control and countermeasure requirements of federal laws require appropriate containment berms and similar structures to help prevent the contamination of navigable waters by a petroleum hydrocarbon tank spill, rupture or leak. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. Federal and state regulatory agencies can impose administrative, civil and criminal penalties as well as other enforcement mechanisms for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations. The Clean Water Act and analogous state laws provide for administrative, civil and criminal penalties for unauthorized discharges and, together with the Oil Pollution Act of 1990 (“OPA”), impose rigorous requirements for spill prevention and response planning, as well as substantial potential liability for the costs of removal, remediation, and damages in connection with any unauthorized discharges.

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Our oil and natural gas production also generates salt water, which we dispose of by underground injection. The federal Safe Drinking Water Act (“SDWA”) regulates the underground injection of substances through the Underground Injection Control (“UIC”) program, and related state programs regulate the drilling and operation of salt water disposal wells. The EPA directly administers the UIC program in some states, and in others it is delegated to the state for administering. Permits must be obtained before drilling salt water disposal wells, and casing integrity monitoring must be conducted periodically to ensure the casing is not leaking salt water to groundwater. Contamination of groundwater by oil and natural gas drilling, production, and related operations may result in fines, penalties, and remediation costs, among other sanctions and liabilities under the SDWA and state laws. In addition, third party claims may be filed by landowners and other parties claiming damages for alternative water supplies, property damages, and bodily injury.

Hydraulic Fracturing

Our completion operations are subject to regulation, which may increase in the short- or long-term. In particular, the well completion technique known as hydraulic fracturing is used to stimulate production of oil and natural gas has come under increased scrutiny by the environmental community, and many local, state and federal regulators. Hydraulic fracturing involves the injection of water, sand and additives under pressure, usually down casing that is cemented in the wellbore, into prospective rock formations at depths to stimulate oil and natural gas production. We engage third parties to provide hydraulic fracturing or other well stimulation services to us in connection with substantially all of the wells for which we are the operator.

The SDWA regulates the underground injection of substances through the UIC program. Hydraulic fracturing is generally exempt from regulation under the UIC program, and the hydraulic fracturing process is typically regulated by state oil and gas commissions. However, legislation has been proposed in recent sessions of Congress to amend the SDWA to repeal the exemption for hydraulic fracturing from the definition of “underground injection,” to require federal permitting and regulatory control of hydraulic fracturing, and to require disclosure of the chemical constituents of the fluids used in the fracturing process.

Furthermore, several federal agencies have asserted regulatory authority over certain aspects of the fracturing process. For example, the EPA has taken the position that hydraulic fracturing with fluids containing diesel fuel is subject to regulation under the UIC program, specifically as “Class II” UIC wells.

In addition, the EPA previously announced plans to develop a Notice of Proposed Rulemaking by June 2018, which would describe a proposed mechanism, regulatory, voluntary, or a combination of both, to collect data on hydraulic fracturing chemical substances and mixtures. Also, on June 28, 2016, the EPA published a final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants. The EPA is also conducting a study of private wastewater treatment facilities (also known as centralized waste treatment (“CWT”) facilities) accepting oil and natural gas extraction wastewater. The EPA is collecting data and information related to the extent to which CWT facilities accept such wastewater, available treatment technologies (and their associated costs), discharge characteristics, financial characteristics of CWT facilities, and the environmental impacts of discharges from CWT facilities.

In addition, on March 26, 2015, the Bureau of Land Management (the “BLM”) published a final rule governing hydraulic fracturing on federal and Indian lands. Also, on November 15, 2016, the BLM finalized a rule to reduce the flaring, venting and leaking of methane from oil and natural gas operations on federal and Indian lands. On March 28, 2017, President Trump signed an executive order directing the BLM to review the above rules and, if appropriate, to initiate a rulemaking to rescind or revise them. Accordingly, on December 29, 2017, the BLM published a final rule to rescind the 2015 hydraulic fracturing rule. Also, on December 8, 2017, the BLM published a final rule to suspend or delay certain requirements of the 2016 methane rule until January 17, 2019. Further legal challenges are expected. At this time, it is uncertain when, or if, the rules will be implemented or modified, and what impact they would have on our operations.

Furthermore, there are certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. On December 13, 2016, the EPA released a study examining the potential for hydraulic fracturing activities to impact drinking water resources, finding that, under some circumstances, the use of water in hydraulic fracturing activities can impact drinking water resources. Also, on February 6, 2015, the EPA released a report with findings and recommendations related to public concern about induced seismic activity from disposal wells. The report recommends strategies for managing and minimizing the potential for significant injection-induced seismic events. Other governmental agencies, including the U.S. Department of Energy, the U.S. Geological Survey, and the U.S. Government Accountability Office, have evaluated or are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies could spur initiatives to further regulate hydraulic fracturing and could ultimately make it more difficult or costly for us to perform fracturing and increase our costs of compliance and doing business.

Some states and local jurisdictions in which we operate or hold oil and natural gas interests have adopted or are considering adopting regulations that could restrict or prohibit hydraulic fracturing in certain circumstances, impose more stringent operating standards and/or require the disclosure of the composition of hydraulic fracturing fluids. If new or more stringent state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development or production activities, and perhaps even be precluded from drilling wells.

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There has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, induced seismic activity, impacts on drinking water supplies, use of water and the potential for impacts to surface water, groundwater and the environment generally. A number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic fracturing practices. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, if hydraulic fracturing is further regulated at the federal, state or local level, our fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. Such legislative changes could cause us to incur substantial compliance costs, and compliance or the consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal, state or local laws governing hydraulic fracturing.

Air Emissions

The federal Clean Air Act and comparable state laws restrict emissions of various air pollutants through permitting programs and the imposition of other requirements. In addition, the EPA has developed and continues to develop stringent regulations governing emissions of toxic air pollutants at specified sources, including oil and natural gas production. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the Clean Air Act and associated state laws and regulations. Our operations, or the operations of service companies engaged by us, may in certain circumstances and locations be subject to permits and restrictions under these statutes for emissions of air pollutants.

In 2012 and 2016, the EPA issued New Source Performance Standards to regulate emissions of sources of volatile organic compounds (“VOCs”), sulfur dioxide, air toxics and methane from various oil and natural gas exploration, production, processing and transportation facilities. In particular, on May 12, 2016, the EPA amended its regulations to impose new standards for methane and volatile organic compounds emissions for certain new, modified, and reconstructed equipment, processes, and activities across the oil and natural gas sector.  However, in a March 28, 2017 executive order, President Trump directed the EPA to review the 2016 regulations and, if appropriate, to initiate a rulemaking to rescind or revise them consistent with the stated policy of promoting clean and safe development of the nation’s energy resources, while at the same time avoiding regulatory burdens that unnecessarily encumber energy production. On June 16, 2017, the EPA published a proposed rule to stay for two years certain requirements of the 2016 regulations, including fugitive emission requirements. These standards, as well as any future laws and their implementing regulations, may require us to obtain pre-approval for the expansion or modification of existing facilities or the construction of new facilities expected to produce air emissions, impose stringent air permit requirements, or mandate the use of specific equipment or technologies to control emissions. We cannot predict the final regulatory requirements or the cost to comply with such requirements with any certainty.

In October 2015, the EPA announced that it was lowering the primary national ambient air quality standards (“NAAQS”) for ozone from 75 parts per billion to 70 parts per billion. The EPA did not meet an October 2017 deadline for designating non-attainment areas but has indicated that it continues to work with states to make the required designations. If implemented in the future, the changes will take place over several years; however, the new standard could result in a significant expansion of ozone non-attainment areas across the United States, including areas in which we operate. Oil and natural gas operations in ozone non-attainment areas would likely be subject to increased regulatory burdens in the form of more stringent emission controls, emission offset requirements, and increased permitting delays and costs.

Climate Change

In December 2009, the EPA issued an Endangerment Finding that determined that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”), present an endangerment to public health and the environment because, according to the EPA, emissions of such gases contribute to warming of the earth’s atmosphere and other climatic changes. In May 2010, the EPA adopted regulations establishing new GHG emissions thresholds that determine when stationary sources must obtain permits under the Prevention of Significant Deterioration, or PSD, and Title V programs of the Clean Air Act. On June 23, 2014, in Utility Air Regulatory Group v. EPA, the Supreme Court held that stationary sources could not become subject to PSD or Title V permitting solely by reason of their GHG emissions. The Court ruled, however, that the EPA may require installation of best available control technology for GHG emissions at sources otherwise subject to the PSD and Title V programs. On August 26, 2016, the EPA proposed changes needed to bring EPA’s air permitting regulations in line with the Supreme Court’s decision on GHG permitting. The proposed rule was published in the Federal Register on October 3, 2016 and the public comment period closed on December 2, 2016.

In addition, the U.S. Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Although the U.S. Congress has not adopted such legislation at this time, it may do so in the future and many states continue to pursue regulations to reduce greenhouse gas emissions.

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In December 2015, the United States participated in the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France. The resulting Paris Agreement calls for the parties to undertake “ambitious efforts” to limit the average global temperature, and to conserve and enhance sinks and reservoirs of GHGs. The Agreement went into effect on November 4, 2016. The Agreement establishes a framework for the parties to cooperate and report actions to reduce GHG emissions. However, on June 1, 2017, President Trump announced that the United States would withdraw from the Paris Agreement, and begin negotiations to either re-enter or negotiate an entirely new agreement with more favorable terms for the United States. The Paris Agreement sets forth a specific exit process, whereby a party may not provide notice of its withdrawal until three years from the effective date, with such withdrawal taking effect one year from such notice. It is not clear what steps the Trump Administration plans to take to withdraw from the Paris Agreement, whether a new agreement can be negotiated, or what terms would be included in such an agreement. Furthermore, in response to the announcement, many state and local leaders have stated their intent to intensify efforts to uphold the commitments set forth in the international accord.

Restrictions on emissions of methane or carbon dioxide that may be imposed could adversely impact the demand for, price of and value of our products and reserves. As our operations also emit greenhouse gases directly, current and future laws or regulations limiting such emissions could increase our own costs. Currently, our operations are not adversely impacted by existing federal, state and local climate change initiatives and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our business.

National Environmental Policy Act

Oil and natural gas exploration, development and production activities on federal lands are subject to the National Environmental Policy Act (“NEPA”). NEPA requires federal agencies, including the Department of the Interior, to evaluate major agency actions that have the potential to significantly impact the environment. The process involves the preparation of either an environmental assessment or environmental impact statement depending on whether the specific circumstances surrounding the proposed federal action will have a significant impact on the human environment. The NEPA process involves public input through comments which can alter the nature of a proposed project either by limiting the scope of the project or requiring resource-specific mitigation. NEPA decisions can be appealed through the court system by process participants. This process may result in delaying the permitting and development of projects, increase the costs of permitting and developing some facilities and could result in certain instances in the cancellation of existing leases.

Threatened and endangered species, migratory birds and natural resources

Various federal and state statutes prohibit certain actions that adversely affect endangered or threatened species and their habitat, migratory birds, wetlands, and natural resources. These statutes include the Endangered Species Act (“ESA”), the Migratory Bird Treaty Act and the Clean Water Act. The U.S. Fish and Wildlife Service may designate critical habitat areas that it believes are necessary for survival of threatened or endangered species. On February 11, 2016, the U.S. Fish and Wildlife Service published a final policy which alters how it identifies critical habitat for endangered and threatened species. A critical habitat designation could result in further material restrictions on federal land use or on private land use and could delay or prohibit land access or development. Where takings of or harm to species or damages to wetlands, habitat, or natural resources occur or may occur, government entities or at times private parties may act to prevent or restrict oil and natural gas exploration activities or seek damages for any injury, whether resulting from drilling or construction or releases of oil, wastes, hazardous substances or other regulated materials, and in some cases, criminal penalties may result. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. While some of our operations may be located in areas that are designated as habitats for endangered or threatened species or that may attract migratory birds we believe that we are in substantial compliance with the ESA and the Migratory Bird Treaty Act, and we are not aware of any proposed ESA listings that will materially affect our operations. The federal government in the past has issued indictments under the Migratory Bird Treaty Act to several oil and natural gas companies after dead migratory birds were found near reserve pits associated with drilling activities. The identification or designation of previously unprotected species as threatened or endangered in areas where underlying property operations are conducted could cause us to incur increased costs arising from species protection measures or could result in limitations on our development activities that could have an adverse impact on our ability to develop and produce our oil and natural gas reserves. If we were to have a portion of our leases designated as critical or suitable habitat, it could adversely impact the value of our leases.

Hazard communications and community right to know

We are subject to federal and state hazard communication and community right to know statutes and regulations. These regulations, including, but not limited to, the federal Emergency Planning & Community Right-to-Know Act, govern record keeping and reporting of the use and release of hazardous substances and may require that information be provided to state and local government authorities, as well as the public.

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Occupational Safety and Health Act

We are subject to the requirements of the federal Occupational Safety and Health Act, as amended (“OSHA”), and comparable state statutes that regulate the protection of the health and safety of workers. In addition, OSHA hazard communication standard requires that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and citizens.

State Regulation

Texas regulates the drilling for, and the production, gathering and sale of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. Texas currently imposes a 4.6% severance tax on oil production and a 7.5% severance tax on natural gas production. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and natural gas resources. States may regulate rates of production and may establish maximum daily production allowables from oil and natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but we cannot assure our stockholders that they will not do so in the future. The effect of these regulations may be to limit the amount of oil and natural gas that may be produced from our wells and to limit the number of wells or locations we can drill.

The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect on us.

Related Insurance

We maintain insurance against some risks associated with above or underground contamination that may occur as a result of our exploration, development and production activities. However, this insurance is limited to activities at the well site, and there can be no assurance that this insurance will continue to be commercially available or that this insurance will be available at premium levels that justify its purchase by us. The occurrence of a significant event that is not fully insured or indemnified against could have a materially adverse effect on our financial condition and operations.

Although we have not experienced any material adverse effect from compliance with environmental requirements, there is no assurance that this will continue. We did not have any material capital or other non-recurring expenditures in connection with complying with environmental laws or environmental remediation matters in 2017, nor do we anticipate that such expenditures will be material in 2018.

Employees

As of December 31, 2017, we had 58 full-time employees, of which nine are management, 19 are technical personnel, 16 are administrative personnel and 14 are field operations employees. Our employees are not covered under a collective bargaining agreement nor are any employees represented by a union. We consider all relations with our employees to be satisfactory.

Office Leases

We lease office space as set forth in the following table:

 

During 2017, aggregate rental payments for our office facilities totaled approximately $0.9 million.

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Executive Officers of the Company

The following table sets forth, as of March 1, 2018, certain information regarding the executive officers of Earthstone:

 

 

 

The following biographies describe the business experience of our executive officers:

 

Frank A. Lodzinski has served as our Chairman, President and Chief Executive Officer since December 2014.  Previously, he served as President and Chief Executive Officer of OVR from its formation in December 2012 until the closing of its strategic combination with Earthstone in December 2014.  Prior to his service with OVR, Mr. Lodzinski was Chairman, President and Chief Executive Officer of GeoResources, Inc. from April 2007 until its merger with Halcón Resources Corporation (“Halcón”) in August 2012 and from September 2012 until December 2012 he conducted pre-formation activities for OVR.  He has over 45 years of oil and gas industry experience.  In 1984, he formed Energy Resource Associates, Inc., which acquired management and controlling interests in oil and gas limited partnerships, joint ventures and producing properties.  Certain partnerships were exchanged for common shares of Hampton Resources Corporation in 1992, which Mr. Lodzinski joined as a director and President.  Hampton was sold in 1995 to Bellwether Exploration Company.  In 1996, he formed Cliffwood Oil & Gas Corp. and in 1997, Cliffwood shareholders acquired a controlling interest in Texoil, Inc., where Mr. Lodzinski served as Chief Executive Officer and President.  In 2001, Mr. Lodzinski was appointed Chief Executive Officer and President of AROC, Inc., to direct the restructuring and ultimate liquidation of that company.  In 2003, AROC completed a monetization of oil and gas assets with an institutional investor and began a plan of liquidation in 2004.  In 2004, Mr. Lodzinski formed Southern Bay Energy, LLC, the general partner of Southern Bay Oil & Gas, L.P., which acquired the residual assets of AROC, Inc., and he served as President of Southern Bay Energy, LLC upon its formation.  The Southern Bay entities were merged into GeoResources in April 2007. Mr. Lodzinski has served as a director and member of the compensation committee of Yuma Energy, Inc. since October 2016 and previously served on its audit committee from September 2014 to October 2016. He holds a BSBA degree in Accounting and Finance from Wayne State University in Detroit, Michigan.

 

Robert J. Anderson is a petroleum engineer with over 30 years of diversified domestic and international oil and gas experience. He has served as our Executive Vice President, Corporate Development and Engineering since December 2014.  Previously, he served in a similar capacity with OVR from March 2013 until the closing of its strategic combination with Earthstone in December 2014.  Prior to joining OVR, he served from August 2012 to February 2013 as Executive Vice President and Chief Operating Officer of Halcón. Mr. Anderson was employed by GeoResources, Inc. from April 2007 until its merger with Halcón in August 2012, ultimately serving as a director and Executive Vice President, Chief Operating Officer – Northern Region. He was involved in the formation of Southern Bay Energy in September 2004 as Vice President, Acquisitions until its merger with GeoResources in April 2007. From March 2004 to August 2004, Mr. Anderson was employed by AROC, a predecessor company to Southern Bay Energy, as Vice President, Acquisitions and Divestitures. From September 2000 to February 2004, he was employed by Anadarko Petroleum Corporation as a petroleum engineer. In addition, he has worked with major oil companies, including ARCO International/Vastar Resources, and independent oil companies, including Hunt Oil, Hugoton Energy, and Pacific Enterprises Oil Company. His professional experience includes acquisition evaluation, reservoir and production engineering, field development, project economics, budgeting and planning, and capital markets. His domestic acquisition and divestiture experience includes Texas and Louisiana (offshore and onshore), Mid-Continent, and the Rocky Mountain states, and his international experience includes Canada, South America, and Russia. Mr. Anderson has a B.S. degree in Petroleum Engineering from the University of Wyoming and an MBA from the University of Denver.

 

Tony Oviedo has served as our Executive Vice President – Accounting and Administration (Principal Accounting Officer) since February 10, 2017.  Mr. Oviedo has over 30 years of professional experience with both private and public companies.  Prior to joining Earthstone, he was employed by GeoMet, Inc., where, since 2006, he served as the Senior Vice President, Chief Financial Officer, Chief Accounting Officer and Controller.  In addition, prior to joining GeoMet, Mr. Oviedo was employed by Resolution Performance Products, LLC, where he was Compliance Director and has held positions as Chief Accounting Officer, Controller, and Director of Financial Reporting with various companies in the oil and gas industry.   Prior to the aforementioned experience, he served in the audit practice of KPMG LLP’s Energy Group.  Mr. Oviedo holds a Bachelor’s degree in Business Administration with a concentration in accounting and tax from the University of Houston and is a Certified Public Accountant in the state of Texas.

 

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Mark Lumpkin, Jr. has over 20 years of experience including over 13 years of oil and gas finance experience. He has served as our Executive Vice President and Chief Financial Officer since August 2017. Immediately prior to joining Earthstone, he served as Managing Director at RBC Capital Markets in the Oil and Gas Corporate Banking group, beginning in 2011 with a focus on upstream and midstream debt financing. From 2006 until 2011, he was employed by The Royal Bank of Scotland (“RBS”) in the Oil and Gas group within the Corporate and Investment Banking division, focusing primarily on the upstream subsector. Prior to RBS, he spent two years focused on capital markets and mergers and acquisitions primarily in the upstream sector at a boutique investment bank. Mr. Lumpkin graduated with a B.A. degree in Economics from Louisiana State University and graduated with a Master of Business Administration degree with a Finance concentration from Tulane University.

 

Steven C. Collins is a petroleum engineer with over 28 years of operations and related experience.  He has served as our Executive Vice President, Completions and Operations since December 2014. Previously, he served in a similar capacity with OVR from its formation in December 2012 until the closing of its strategic combination with Earthstone in December 2014. Prior to employment by OVR, he served from August 2012 to November 2012 as a consultant to Halcón.  Mr. Collins was employed by GeoResources, Inc. from April 2007 until its merger with Halcón in August 2012 and directed field operations, including well completion, production and workover operations. Prior to employment by GeoResources, he served as Vice President of Operations for Southern Bay, AROC, and Texoil, and as a petroleum and operations engineer at Hunt Oil Company and Pacific Enterprises Oil Company.  His experience includes Texas, Louisiana (onshore and offshore), North Dakota, Montana, and the Mid-Continent. Mr. Collins graduated with a B.S. degree in Petroleum Engineering from the University of Texas.

 

Timothy D. Merrifield has over 37 years of oil and gas industry experience. He has served as our Executive Vice President, Geology and Geophysics since December 2014. Previously, he served in a similar capacity with OVR from its formation in December 2012 until the closing of its strategic combination with Earthstone in December 2014.  Prior to employment by OVR, he served from August 2012 to November 2012 as a consultant to Halcón upon its merger with GeoResources, Inc. in August 2012. From April 2007 to August 2012, Mr. Merrifield led all geology and geophysics efforts at GeoResources. He has held previous roles at AROC, Force Energy, Great Western Resources and other independents.  His domestic experience includes Texas, Louisiana (onshore and offshore), North Dakota, Montana, New Mexico, Rocky Mountain States, and the Mid-Continent. In addition, he has international experience in Peru and the East Irish Sea. Mr. Merrifield attended Texas Tech University.

 

Francis M. Mury has over 42 years of oil and gas industry experience. He has served as our Executive Vice President, Drilling and Development since December 2014. Previously, he served in a similar capacity with OVR from its formation in December 2012 until the closing of its strategic combination with Earthstone in December 2014. Prior to employment by OVR, he was employed by GeoResources, Inc. from April 2007 until its merger with Halcón in August 2012, ultimately serving as an Executive Vice President, Chief Operating Officer–Southern Region. He has held prior roles at AROC, Texoil, Hampton Resources, Wainoco Oil & Gas Company, Diasu Exploration Company, and Texaco, Inc. His experience extends to all facets of petroleum engineering, including reservoir engineering, drilling and production operations, petroleum economics, geology, geophysics, land, and joint operations. Geographical areas of experience include Texas and Louisiana (offshore and onshore), North Dakota, Montana, Mid-Continent, Florida, New Mexico, Oklahoma, Wyoming, Pennsylvania and Michigan. Mr. Mury graduated from Nicholls State University with a degree in Computer Science.

 

Ray Singleton is a petroleum engineer with over 38 years of experience in the oil and gas industry.  He has been one of our directors since July 1989 and was our President and Chief Executive Officer from March 1993 until December 2014. Since December 2014, he has served as our Executive Vice President, Northern Region. Mr. Singleton joined us in 1988 as a Production Manager/Petroleum Engineer. From 1983 until 1988, he owned and operated an engineering consulting firm (Singleton & Associates) serving the needs of 40 small oil and gas clients.  During this period, he was engaged by the Company on various projects in south Texas and the Rocky Mountain region.  Mr. Singleton began his career with Amoco Production Company in 1973 as a production engineer in Texas. He was subsequently employed by the predecessor of Union Pacific Resources as a drilling, completion and production engineer from 1980 to 1983. His professional experience includes acquisition evaluation and economics, reserve engineering and drilling, completion and production engineering in both Texas and the Rocky Mountain region.   Mr. Singleton received a B.S. degree in Petroleum Engineering from Texas A&M University in 1973 and received an MBA from Colorado State University’s Executive MBA Program in 1992.

Available Information

Our principal executive offices are located at 1400 Woodloch Forest Drive, Suite 300, The Woodlands, Texas 77380. Our telephone number is (281) 298-4246. You can find more information about us at our website located at www.earthstoneenergy.com. Our Annual Report on Form 10-K, our Quarterly Reports on Form 10-Q, our Current Reports on Form 8-K and any amendments to those reports are available free of charge on or through our website, which is not part of this report. These reports are available as soon as reasonably practicable after we electronically file these materials with, or furnish them to, the SEC. Information filed with the SEC may be read or copied at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. Information on operation of the Public Reference Room may be obtained by calling the SEC at 1-800-SEC-0330 (1-800-732-0330). The SEC also maintains a website at www.sec.gov that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC, including us.

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Item 1A.  Risk Factors

Our business is subject to various risks and uncertainties in the course of our business. The following summarizes significant risks and uncertainties that may adversely affect our business, financial condition or results of operations. We cannot assure you that any of the events discussed in the risk factors below will not occur. Further, the risks and uncertainties described below are not the only ones we face. Additional risks not presently known to us or that we currently deem immaterial may also materially affect our business. When considering an investment in our shares of Class A Common Stock, you should carefully consider the risk factors included below as well as those matters referenced in this report under “Cautionary Statement Concerning Forward-Looking Statements” and other information included and incorporated by reference into this report.

We are a holding company and the sole manager of EEH. Our only material asset is our equity interest in EEH and, accordingly, we are dependent upon distributions from EEH to cover our corporate and other overhead expenses and pay taxes.

Upon the closing of the Contribution Agreement on May 9, 2017, we became a holding company and the sole manager of EEH and have no material assets other than our equity interest in EEH. We have no independent means of generating revenue. We expect EEH to reimburse us for our corporate and other overhead expenses, and to the extent EEH has available cash, we intend to cause EEH to make distributions to the holders of EEH Units, including us, in an amount sufficient to cover all applicable U.S. federal, state and local income taxes and non-U.S. tax liabilities of Earthstone, Lynden Corp and Lynden US, if any, at assumed tax rates. We will likely be limited, however, in our ability to cause EEH and its subsidiaries to make these and other distributions due to the restrictions under an agreement providing for our senior secured revolving credit facility (the “EEH Credit Agreement”). To the extent that we need funds, and EEH or its subsidiaries are restricted from making such distributions under applicable law or regulation or under the terms of their financing arrangements, or are otherwise unable to provide such funds, it could materially adversely affect our liquidity and financial condition.

Oil, natural gas and natural gas liquids prices are volatile. Their prices since 2014 have adversely affected, and in the future may adversely affect, our business, financial condition and results of operations and our ability to meet our capital expenditure obligations and financial commitments. Volatile and lower prices may also negatively impact our stock price.

The prices we receive for our oil, natural gas and natural gas liquids production heavily influence our revenues, profitability, access to capital and future rate of growth. These hydrocarbons are commodities, and therefore, their prices may be subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the market for oil, natural gas and natural gas liquids has been volatile. For example, during the period from January 1, 2014 through December 31, 2017, the West Texas Intermediate (“WTI”) futures price for oil declined from a high of $107.26 per Bbl on June 20, 2014 to $26.21 per Bbl on February 11, 2016, and subsequently increased to reach a high of $60.01 per Bbl in December 2017; and the Henry Hub futures price for natural gas has declined from a high of $6.15 per MMBtu on February 19, 2014 to a low of $1.64 per MMBtu on March 3, 2016, and subsequently increased to reach a high of $3.69 per MMBtu in December 2017. Likewise, natural gas liquids, which are made up of ethane, propane, isobutane, normal butane and natural gasoline, each of which have different uses and different pricing characteristics, have experienced significant declines in realized prices since the fall of 2014. The prices we receive for oil, natural gas and natural gas liquids we produce and our production levels depend on numerous factors beyond our control, including:

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Lower oil, natural gas and natural gas liquids prices have and may continue to reduce our cash flows and borrowing capacity. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in our hydrocarbon reserves as existing reserves are depleted. A decrease in prices could render development projects and producing properties uneconomic, potentially resulting in a loss of mineral leases.   Low commodity prices have, at times, caused significant downward adjustments to our estimated proved reserves, and may cause us to make further downward adjustments in the future. Furthermore, our borrowing capacity could be significantly affected by decreased prices.  Under the EEH Credit Agreement, our borrowing base is subject to semi-annual redeterminations (May 1 and November 1) and our lenders have the right to call for an interim determination of the borrowing base under certain circumstances. A sustained decline in oil, natural gas and natural gas liquids prices could adversely impact our borrowing base in future borrowing base redeterminations, which could trigger repayment obligations under the EEH Credit Agreement to the extent our outstanding borrowings exceed the redetermined borrowing base and could otherwise materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures. In addition, lower oil, natural gas and natural gas liquids gas prices may cause a decline in the market price of our shares.

As a result of low prices for oil, natural gas and natural gas liquids, we have taken and may be required to take significant future write-downs of the financial carrying values of our properties.

Accounting rules require that we periodically review the carrying value of our properties for possible impairment. Based on prevailing commodity prices and specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we have been required to, and may be required to significantly write-down the financial carrying value of our oil and natural gas properties, which constitutes a non-cash charge to earnings.  We may incur impairment charges in the future, which could have a material adverse effect on our results of operations for the periods in which such charges are recorded.

A write-down could occur when oil and natural gas prices are low or if we have substantial downward adjustments to our estimated proved oil and natural gas reserves, if operating costs or development costs increase over prior estimates, or if exploratory drilling is unsuccessful.

The capitalized costs of our oil and natural gas properties, on a field-by-field basis, may exceed the estimated future net cash flows of that field. If so, we would record impairment charges to reduce the capitalized costs of such field to our estimate of the field’s fair market value. Unproved properties are evaluated at the lower of cost or fair market value. These types of charges will reduce our earnings and stockholders’ equity and could adversely affect our stock price.

We periodically assess our properties for impairment based on future estimates of proved and non-proved reserves, oil and natural gas prices, production rates and operating, development and reclamation costs based on operating budget forecasts. Once incurred, an impairment charge cannot be reversed at a later date even if price increases of oil and/or natural gas occur and in the event of increases in the quantity of our estimated proved reserves.

If oil, natural gas and natural gas liquids prices fall below current levels for an extended period of time and all other factors remain equal, we may incur impairment charges in the future. Such charges could have a material adverse effect on our results of operations for the periods in which they are recorded. See Note 6. Oil and Natural Gas Properties to our Consolidated Financial Statements included in this report for additional information.

Any significant reduction in our borrowing base under the EEH Credit Agreement as a result of a periodic borrowing base redetermination or otherwise may negatively impact our liquidity and, consequently, our ability to fund our operations, including capital expenditures, and we may not have sufficient funds to repay borrowings under the EEH Credit Agreement or any other obligation if required as a result of a borrowing base redetermination.

Availability under the EEH Credit Agreement is currently subject to a borrowing base of $185.0 million. The borrowing base is subject to scheduled semiannual redeterminations (May 1 and November 1), as well as other elective borrowing base redeterminations. The lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under the EEH Credit Agreement. Reductions in estimates of our oil, natural gas and natural gas liquids reserves may result in a reduction in our borrowing base under the EEH Credit Agreement (if prices are kept constant). Reductions in our borrowing base under the EEH Credit Agreement could also arise from other factors, including but not limited to:

 

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As of December 31, 2017, we had $25.0 million of borrowings outstanding under the EEH Credit Agreement. We may make further borrowings under the EEH Credit Agreement in the future. Any significant reduction in our borrowing base under the EEH Credit Agreement as a result of borrowing base redeterminations or otherwise will negatively impact our liquidity and our ability to fund our operations and, as a result, could have a material adverse effect on our financial position, results of operations and cash flows. Further, if the outstanding borrowings under the EEH Credit Agreement were to exceed the borrowing base as a result of any such redetermination, we could be required to repay the excess.

Unless we replace our reserves, our production and estimated reserves will decline, which may adversely affect our financial condition, results of operations and/or cash flows.

Producing oil and natural gas reservoirs are generally characterized by declining production rates that may vary depending upon reservoir characteristics and other factors. Decline rates are typically greatest early in the productive life of a well, particularly horizontal wells. Estimates of the decline rate of an oil or natural gas well are inherently imprecise and may be less precise with respect to new or emerging oil and natural gas formations with limited production histories than for more developed formations with established production histories. Our production levels and the reserves that we currently expect to recover from our wells will change if production from our existing wells declines in a different manner than we have estimated and can change under other circumstances. Thus, our estimated future oil and natural gas reserves and production and, therefore, our cash flows and results of operations are highly dependent upon our success in efficiently developing and exploiting our current properties and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire additional reserves to replace our current and future production at acceptable costs. If we are unable to replace our current and future production, our cash flows and the value of our reserves may decrease, adversely affecting our business, financial condition and results of operations.

Estimates of proved oil and natural gas reserves involve assumptions and any material inaccuracies in these assumptions will materially affect the quantities and the value of those reserves.

This report contains estimates of our proved oil and natural gas reserves. These estimates are based upon various assumptions, including assumptions required by SEC regulations relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating oil and natural gas reserves is complex and requires significant decisions, complex analyses and assumptions in evaluating available geological, geophysical, engineering and economic data for each reservoir. Therefore, these estimates are inherently imprecise.

Our actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will vary from those estimated. Any significant variance will likely materially affect the estimated quantities and the estimated value of our reserves. In addition, we may later adjust estimates of proved reserves to reflect production history, results of exploration and development activities, prevailing oil and natural gas prices and other factors, many of which are beyond our control.

Quantities of estimated proved reserves are based on economic conditions in existence during the period of assessment. Changes to oil, natural gas and natural gas liquids prices in the markets for these commodities may shorten the economic lives of certain fields because it may become uneconomical to produce all recoverable reserves in such fields, which may reduce proved reserves estimates.

Negative revisions in the estimated quantities of proved reserves have the effect of increasing the rates of depletion on the affected properties, which decrease earnings or result in losses through higher depletion expense. These revisions, as well as revisions in the assumptions of future estimated cash flows of those reserves, may also trigger impairment losses on certain properties, which may result in non-cash charges to earnings. See Note 6. Oil and Natural Gas Properties, to our consolidated financial statements included in this report.

The development of our estimated proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our estimated proved undeveloped reserves may not be ultimately developed or produced.

At December 31, 2017, approximately 75% of our estimated reserves were classified as proved undeveloped. The development of our estimated proved undeveloped reserves of 60,015 MBOE will require an estimated $665.9 million of development capital over the next five years.

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Development of these reserves may take longer and require higher levels of capital expenditures than we currently anticipate. The future development of our proved undeveloped reserves is dependent on successful drilling and completion results, future commodity prices, costs and economic assumptions that align with our internal forecasts, as well as access to liquidity sources, such as the capital markets, the EEH Credit Agreement and derivative contracts. Delays in the development of our reserves, increases in costs to drill and develop such reserves, or decreases in commodity prices will reduce the PV-10 value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. Moreover, under the SEC regulations, we may be required to write down our proved undeveloped reserves if we do not drill or have a development plan to drill wells within a prescribed five-year period. The estimated reserve data assumes that we will make specified capital expenditures to timely develop our reserves. The estimates of these oil and natural gas reserves and the costs associated with development of these reserves have been prepared in accordance with SEC regulations; however, actual capital expenditures may vary from estimated capital expenditures, development may not occur as scheduled and actual results may not be as estimated.

The standardized measure of discounted future net cash flows from our estimated proved reserves may not be the same as the current market value of our estimated oil and natural gas reserves.

You should not assume that the standardized measure of discounted future net cash flows from our estimated proved reserves set forth in this report is the current market value of our estimated oil and natural gas reserves. In accordance with SEC requirements in effect at December 31, 2017, 2016 and 2015, we based the discounted future net cash flows from our proved reserves on the 12-month first-day-of-the-month oil and natural gas arithmetic average prices without giving effect to derivative transactions. Actual future net cash flows from our oil and natural gas properties will be affected by factors such as:

The timing of both our production and incurring expenses related to developing and producing oil and natural gas properties will affect the timing and amount of actual future net revenues from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating standardized measure may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with our business or the oil and natural gas industry in general. As a corporation, we are treated as a taxable entity for statutory income tax purposes and our future income taxes will be dependent on our future taxable income. Actual future prices and costs may differ materially from those used in the estimates included in this report which could have a material effect on the value of our estimated reserves.

Our development and exploratory drilling efforts and our well operations may not be profitable or achieve our targeted returns.

We have acquired significant amounts of unproved property in order to further our development efforts and expect to continue to undertake acquisitions in the future. Development and exploratory drilling and production activities are subject to many risks, including the risk that no commercially productive reservoirs will be discovered. We acquire unproved properties and lease undeveloped acreage that we believe will enhance our growth potential and increase our results of operations over time. However, we cannot assure you that all prospects will be economically viable or that we will not abandon our leaseholds. Additionally, we cannot assure you that unproved property acquired by us or undeveloped acreage leased by us will be profitably developed, that wells drilled by us in prospects that we pursue will be productive or that we will recover all or any portion of our investment in such unproved property or wells.

Properties we acquire may not produce as projected and we may be unable to determine reserve potential, identify liabilities associated with the properties that we acquire or obtain protection from sellers against such liabilities.

Acquiring oil and natural gas properties requires us to assess reservoir and infrastructure characteristics, including recoverable reserves, development and operating costs and potential environmental and other liabilities. Such assessments are inexact and inherently uncertain. In connection with the assessments, we perform a review of the subject properties, but such a review will not reveal all existing or potential problems. In the course of our due diligence, we may not inspect every well or pipeline. We cannot necessarily observe structural and environmental problems, such as pipe corrosion, when an inspection is made. We may not be able to obtain contractual indemnities from the seller for liabilities created prior to our purchase of a property. We may be required to assume the risk of the physical condition of properties in addition to the risk that they may not perform in accordance with our expectations.

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Future drilling and completion activities associated with identified drilling locations may be adversely affected by factors that could materially alter the occurrence or timing of their drilling and completion, which in certain instances could prevent production prior to the expiration date of mineral leases for such locations.

Although our management team has  identified  numerous  potential drilling locations as a part of our long-range planning related to future drilling activities on our existing acreage, our ability to drill and develop these locations depends on a number of factors, which are beyond our control, including, the availability and cost of capital, oil, natural gas and natural gas liquids prices, drilling and production costs, the availability of drilling services and equipment, drilling results (including the impact of increased horizontal drilling density and longer laterals), lease expirations, gathering systems, marketing and pipeline transportation constraints, regulatory approvals and other factors.  As such, our actual drilling and completion activities, may materially differ from those presently anticipated. Accordingly, it is uncertain to what degree that these potential drilling locations will be developed or if we will be able to produce significant oil, natural gas and natural gas liquids from these or any other potential drilling locations.  Unless production is established, in accordance with the terms of mineral leases that are associated with these locations, such leases could expire.

Our acquisition, development and exploitation projects require substantial capital expenditures. We may be unable to obtain required capital or financing on satisfactory terms, which could lead to a decline in our reserves.

The oil and natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures for the acquisition and development of oil and natural gas reserves. We expect to fund our 2018 capital expenditures with cash on hand, cash generated by operations, borrowings under the EEH Credit Agreement and possibly through additional capital market transactions. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, oil and natural gas prices, actual drilling results, the availability of drilling rigs and other services and equipment and regulatory, technological and competitive developments. A reduction in commodity prices from current levels may result in a decrease in our actual capital expenditures, which would negatively impact our ability to grow production.

Our cash flow from operations and access to capital are subject to a number of variables, including:

If our revenues or the borrowing base under the EEH Credit Agreement decrease as a result of low oil and natural gas prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations and growth at current levels. If additional capital is needed, we may not be able to obtain debt or equity financing on terms acceptable to us, if at all. The failure to obtain additional financing could result in a curtailment of our operations relating to development of our properties, which in turn could lead to a decline in our reserves and production and would adversely affect our business, financial condition and results of operations.

We have incremental cash inflows and outflows as a result of our hedging activities. To the extent we are unable to obtain future hedges at attractive prices or our derivative activities are not effective, our cash flows and financial condition may be adversely impacted.

In an effort to achieve more predictable cash flows and reduce our exposure to adverse fluctuations in the prices of oil and natural gas, we often enter into derivative instrument contracts for a portion of our oil and natural gas production, including swaps, collars, puts and basis swaps. We recognize all derivatives as either assets or liabilities, measured at fair value, and recognize changes in the fair value of derivatives in current earnings. Accordingly, our earnings may fluctuate significantly and our results of operations may be significantly and adversely affected because of changes in the fair market value of our derivative instruments. As our derivative instrument contracts expire, there is no assurance that we will be able to replace them comparably.

Derivative instruments can expose us to the risk of financial loss in varying circumstances, including, but not limited to, when:

 

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For additional information regarding our hedging activities, please see Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations and Note 5. Derivative Instruments in the Notes to Consolidated Financial Statements included in this report for additional information.

Derivatives reform legislation and related regulations could have an adverse effect on our ability to hedge risks associated with our business.

The Dodd-Frank Wall Street Reform and Consumer Protection Act (the "Dodd-Frank Act") provides for federal oversight of the over-the-counter derivatives market and entities that participate in that market and mandates that the Commodity Futures Trading Commission (the "CFTC"), the SEC, and federal regulators of financial institutions adopt rules or regulations implementing the Dodd-Frank Act and providing definitions of terms used in the Dodd-Frank Act.

The CFTC has finalized other regulations implementing the Dodd-Frank Act's provisions regarding trade reporting, margin, clearing, and trade execution; however, some regulations remain to be finalized and it is not possible at this time to predict when the CFTC will adopt final rules. For example, the CFTC has re-proposed regulations setting position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. Certain bona fide hedging transactions are expected to be made exempt from these limits. Also, it is possible that under recently adopted margin rules, some registered swap dealers may require us to post initial and variation margins in connection with certain swaps not subject to central clearing.

The Dodd-Frank Act and any additional implementing regulations could significantly increase the cost of some commodity derivative contracts (including through requirements to post collateral, which could adversely affect our available liquidity), materially alter the terms of some commodity derivative contracts, limit our ability to trade some derivatives to hedge risks, reduce the availability of some derivatives to protect against risks we encounter, and reduce our ability to monetize or restructure our existing commodity derivative contracts. If we reduce our use of derivatives as a consequence, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Increased volatility may make us less attractive to certain types of investors. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. If the implementing regulations result in lower commodity prices, our revenues could be adversely affected. Any of these consequences could adversely affect our business, financial condition and results of operations.

The oil and natural gas industry is highly competitive, and our small size puts us at a disadvantage in competing for resources.

The oil and natural gas industry is highly competitive. We compete with major integrated and larger independent oil and natural gas companies in seeking to acquire desirable oil and natural gas properties and leases and for the equipment and services required to develop and operate properties. Many of our competitors have financial and other resources that are substantially greater than ours, which makes acquisitions of acreage or producing properties at economic prices difficult. Significant competition also exists in attracting and retaining technical personnel, including geologists, geophysicists, engineers, landmen and other specialists, as well as financial and administrative personnel hence we may be at a competitive disadvantage to companies with larger financial resources than ours.

Failure to complete additional acquisitions could limit our potential growth.

Our future success is highly dependent on our ability to acquire and develop mineral leases and oil and gas properties with economically recoverable oil and natural gas reserves. Without continued successful acquisition, of economic development projects, our current estimated oil and natural gas reserves will decline due to continued production activities. Acquiring additional oil and natural gas properties, or businesses that own or operate such properties is an important component of our business strategy. If we identify an appropriate acquisition candidate, management may be unable to negotiate mutually acceptable terms with the seller, finance the acquisition or obtain the necessary regulatory approvals. Our limited access to financial resources compared to larger, better capitalized companies may limit our ability to make future acquisitions. If we are unable to complete suitable acquisitions, it may be more difficult to replace and increase our reserves, and an inability to replace our reserves may have a material adverse effect on our financial condition and results of operations.

Acquisitions involve a number of risks, including the risk that we will discover unanticipated liabilities or other problems associated with the acquired business or property.

In assessing potential acquisitions, we consider information available in the public domain and information provided by the seller. In the event publicly available data is limited, then, by necessity, we may rely to a large extent on information that may only be available from the seller, particularly with respect to drilling and completion costs and practices, geological, geophysical and petrophysical data, detailed production data on existing wells, and other technical and cost data not available in the public domain. Accordingly, the review and evaluation of businesses or properties to be acquired may not uncover all existing or relevant data, obligations or actual or contingent liabilities that could adversely impact any business or property to be acquired and, hence, could adversely affect us as a result of the acquisition. These issues may be material and could include, among other things, unexpected environmental liabilities, title defects, unpaid royalties, taxes or other liabilities. If we acquire properties on an “as-is” basis, we may have limited or no remedies against the seller with respect to these types of problems.

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The success of any acquisition that we complete will depend on a variety of factors, including our ability to accurately assess the reserves associated with the acquired properties, assumptions related to future oil and natural gas prices and operating costs, potential environmental and other liabilities and other factors. These assessments are often inexact and subjective. As a result, we may not recover the purchase price of a property from the sale of production from the property or recognize an acceptable return from such sales or operations.

Our ability to achieve the benefits that we expect from an acquisition will also depend on our ability to efficiently integrate the acquired operations. Management may be required to dedicate significant time and effort to the integration process, which could divert its attention from other business opportunities and concerns. The challenges involved in the integration process may include retaining key employees and maintaining employee morale, addressing differences in business cultures, processes and systems and developing internal expertise regarding acquired properties.

We may incur substantial losses and be subject to substantial liability claims as a result of our oil and natural gas operations, including our drilling operations.

Oil and natural gas exploration, development and production activities are subject to numerous significant operating risks, including the possibility of:

Any of these operating hazards could cause damage to properties, reduced cash flows, serious injuries, fatalities, oil spills, discharge of hazardous materials, remediation and clean-up costs and other environmental damages, which could expose us to significant liabilities. We may elect not to obtain insurance for any or all of these risks if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. The occurrence of an event that is not fully covered by insurance could have a material adverse effect on our business, financial condition and results of operations.

The nature of our business and assets exposes us to significant compliance costs and liabilities.

Our operations involving the exploration, development and production of hydrocarbons are subject to stringent federal, state, and local laws and regulations governing the discharge of materials into the environment as well as protection of the environment, operational safety, and related employee health and safety matters. Laws and regulations applicable to us include those relating but not limited to the following:

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Compliance with these laws and regulations is a significant cost of doing business. Failure to comply with applicable laws and regulations may result in the assessment of administrative, civil, and criminal penalties; the imposition of investigatory and remedial liabilities; the issuance of injunctions that may restrict, inhibit or prohibit our operations; and claims of damages to property or persons.

Some environmental laws and regulations impose strict liability, which means that in some situations we could be exposed to liability for clean-up costs and other damages as a result of conduct that was lawful at the time it occurred or for the conduct of prior operators of properties we acquired or of other third parties. Similarly, some environmental laws and regulations impose joint and several liability, meaning that we could be held responsible for more than our share of a particular reclamation or other obligation, and potentially the entire obligation, where other parties were involved in the activity giving rise to the liability. In addition, we may be required to make large and unanticipated capital expenditures to comply with applicable laws and regulations, for example by installing and maintaining pollution control devices. Similarly, our actual plugging and abandonment obligations may be more than our estimates. It is not possible for us to estimate reliably the amount and timing of all future expenditures related to environmental matters, but we estimate that they will be material. Environmental risks are generally not fully insurable.

Federal, state and local legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

We engage third parties to provide hydraulic fracturing or other well stimulation services to us in connection with many of the wells for which we are the operator. Federal, state and local governments have been adopting or considering restrictions on or prohibitions of fracturing in areas where we currently conduct operations, or in the future plan to conduct operations. Consequently, we could be subject to additional levels of regulation, operational delays or increased operating costs and could have additional regulatory burdens imposed upon us that could make it more difficult to perform hydraulic fracturing and increase our costs of compliance and doing business.

From time to time, for example, legislation has been proposed in Congress to amend the federal Safe Drinking Water Act (“SDWA”) to require federal permitting of hydraulic fracturing and the disclosure of chemicals used in the hydraulic fracturing process. Further, the EPA completed a study finding that hydraulic fracturing could potentially harm drinking water resources under adverse circumstances such as injection directly into groundwater or into production wells lacking mechanical integrity. Other governmental reviews have also been recently conducted or are under way that focus on environmental aspects of hydraulic fracturing. For example, a federal Bureau of Land Management (the “BLM”) rulemaking for hydraulic fracturing practices on federal and Indian lands resulted in a March 2015 final rule that requires public disclosure of chemicals used in hydraulic fracturing, confirmation that the wells used in fracturing operations meet proper construction standards and development of plans for managing related flowback water. In June 2016, a federal district court judge in Wyoming struck down the final rule, finding that the BLM lacked congressional authority to promulgate the rule. The BLM appealed that ruling. However, in July 2017, the BLM initiated a rulemaking to rescind the final rule and reinstate the regulations that existed immediately before the published effective date of the rule. In light of the BLM’s proposed rulemaking, in September 2017, the U.S. Court of Appeals for the Tenth Circuit dismissed the appeal and remanded with directions to vacate the lower court’s opinion, leaving the final rule in place. On December 29, 2017, the BLM published a final rule rescinding the March 2015 final rule. Further, legislation to amend the SDWA to repeal the exemption for hydraulic fracturing (except when diesel fuels are used) from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, have been proposed in recent sessions of Congress. Several states and local jurisdictions in which we operate also have adopted or are considering adopting regulations that could restrict or prohibit hydraulic fracturing in certain circumstances, impose more stringent operating standards and/or require the disclosure of the composition of hydraulic fracturing fluids.

More recently, federal and state governments have begun investigating whether the disposal of produced water into underground injection wells has caused increased seismic activity in certain areas. For example, in December 2016, the EPA released its final report regarding the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources under certain circumstances such as water withdrawals for fracturing in times or areas of low water availability, surface spills during the management of fracturing fluids, chemicals or produced water, injection of fracturing fluids into wells with inadequate mechanical integrity, injection of fracturing fluids directly into groundwater resources, discharge of inadequately treated fracturing wastewater to surface waters, and disposal or storage of fracturing wastewater in unlined pits. The results of these studies could lead federal and state governments and agencies to develop and implement additional regulations.

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The proliferation of regulations may limit our ability to operate. If the use of hydraulic fracturing is limited, prohibited or subjected to further regulation, these requirements could delay or effectively prevent the extraction of oil and natural gas from formations which would not be economically viable without the use of hydraulic fracturing. This could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Extreme weather conditions could adversely affect our ability to conduct drilling and production activities in the areas where we operate.

Our exploration, exploitation and development activities and equipment could be adversely affected by extreme weather conditions, such as hurricanes, which may cause a loss of production from temporary cessation of activity or lost or damaged facilities and equipment. Such extreme weather conditions could also impact access to our drilling and production facilities for routine operations, maintenance and repairs and the availability of and our access to, necessary third-party services, such as gathering, processing, compression and transportation services. These constraints and the resulting shortages or high costs could delay or temporarily halt our operations and materially increase our operation and capital costs, which could have a material adverse effect on our business, financial condition and results of operations.

Climate change legislation or regulations restricting emissions of "greenhouse gases" could result in increased operating costs and reduced demand for the oil, natural gas and natural gas liquids we produce.

Studies over recent years have indicated that emissions of certain gases may be contributing to warming of the Earth's atmosphere. In response, increasingly governments have been adopting domestic and international climate change regulations that require reporting and reductions of the emission of such greenhouse gases. Methane, a primary component of natural gas, and carbon dioxide, a byproduct of burning oil, natural gas and refined petroleum products, are considered greenhouse gases. Internationally, the United Nations Framework Convention on Climate Change, the Kyoto Protocol and the Paris Agreement address greenhouse gas emissions, and international negotiations over climate change and greenhouse gases are continuing. Meanwhile, several countries, including those comprising the European Union, have established greenhouse gas regulatory systems.

In the United States, many states, either individually or through multi-state regional initiatives, have begun implementing legal measures to reduce emissions of greenhouse gases, primarily through emission inventories, emission targets, greenhouse gas cap and trade programs or incentives for renewable energy generation, while others have considered adopting such greenhouse gas programs.

At the federal level, the Obama Administration pledged for the Paris Agreement to meet an economy-wide target in 2025 of reducing greenhouse gas emissions by 26-28% below the 2005 level. To help achieve these reductions, federal agencies have been addressing climate change through a variety of administrative actions. The EPA thus issued greenhouse gas monitoring and reporting regulations that cover oil and natural gas facilities, among other industries. Beyond measuring and reporting, the EPA issued an “Endangerment Finding” under Section 202(a) of the Clean Air Act, concluding certain greenhouse gas pollution threatens the public health and welfare of current and future generations. The finding served as the first step to issuing regulations that require permits for and reductions in greenhouse gas emissions for certain facilities. In March 2014, moreover, then President Obama released a Strategy to Reduce Methane Emissions that included consideration of both voluntary programs and targeted regulations for the oil and natural gas sector. Consistent with that strategy, the EPA issued final rules in 2016 for new and modified oil and natural gas production sources (including hydraulically fractured oil wells, natural gas well sites, natural gas processing plants, natural gas gathering and boosting stations and natural gas transmission sources) to reduce emissions of methane as well as volatile organic compound and toxic pollutants. However, in May 2017 the EPA temporarily stayed implementing portions of the new rule and in June 2017 proposed a two year stay of new requirements, and more recently the head of the EPA has announced the current administration's intent to roll back or repeal most, if not all, of the Obama administration's regulations restricting future greenhouse gas emissions. In June 2017, President Trump announced that the United States intends to withdraw from the Paris Agreement and to seek negotiations either to reenter the Paris Agreement on different terms or a separate agreement. In August 2017, the U.S. Department of State officially informed the United Nations of the intent of the United States to withdraw from the Paris Agreement. The Paris Agreement provides for a four-year exit process beginning when it took effect in November 2016, which would result in an effective exit date of November 2020. The United States' adherence to the exit process and/or the terms on which the United States may re-enter the Paris Agreement or a separately negotiated agreement are unclear at this time.

In the courts, several decisions have been issued that may increase the risk of claims being filed by governments and private parties against companies that have significant greenhouse gas emissions. Such cases may seek to challenge air emissions permits that greenhouse gas emitters apply for and seek to force emitters to reduce their emissions or seek damages for alleged climate change impacts to the environment, people, and property.

The direction of future U.S. climate change regulation is difficult to predict given the current uncertainties surrounding the policies of the Trump Administration. The EPA may or may not continue developing regulations to reduce greenhouse gas emissions from the oil and natural gas industry. Even if federal efforts in this area slow, states may continue pursuing climate regulations. Any laws or regulations that may be adopted to restrict or reduce emissions of greenhouse gases could require us to incur additional operating costs, such as costs to purchase and operate emissions controls, to obtain emission allowances or to pay emission taxes, and reduce demand for our oil and natural gas.

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Our oil, natural gas and natural gas liquids are sold in a limited number of geographic markets so an oversupply in any of those areas could have a material negative effect on the price we receive.

Our oil, natural gas and natural gas liquids is sold in a limited number of geographic markets which each have a fixed amount of storage and processing capacity. As a result, if such markets become oversupplied with oil, natural gas and/or natural gas liquids, it could have a material negative effect on the prices we receive for our products and therefore an adverse effect on our financial condition and results of operations. There is a risk that refining capacity in the U.S. Gulf Coast may be insufficient to refine all of the light sweet crude oil being produced in the United States. If light sweet crude oil production remains at current levels or continues to increase, demand for our light crude oil production could result in widening price discounts to the world crude prices and potential shut-in of production due to a lack of sufficient markets despite the lift on prior restrictions on the exporting of oil and natural gas.

We may incur more taxes and certain of our projects may become uneconomic if certain federal income tax deductions currently available with respect to oil and natural gas exploration and development are eliminated as a result of future legislation.

In past years, legislation has been proposed that would, if enacted into law, make significant changes to U.S. tax laws, including to certain key U.S. federal income tax provisions currently available to oil and natural gas exploration, development and production companies. Such legislative changes have included, but not limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain domestic production activities, and (iv) an extension of the amortization period for certain geological and geophysical expenditures. The Tax Cuts and Jobs Act of 2017 (the “TCJA”) did not directly affect deductions currently available to the oil and natural gas industry but any future changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that currently are available with respect to oil and natural gas development, or increase costs, and any such changes could have an adverse effect on our financial position, results of operations and cash flows.

The recently passed comprehensive tax reform bill could adversely affect our business and financial condition.

On December 22, 2017, President Trump signed into law the TCJA that significantly changes the federal income taxation of business entities. The TCJA, among other things, reduces the corporate income tax rate to 21%, partially limits the deductibility of business interest expense and net operating losses, imposes a one-time tax on unrepatriated earnings from certain foreign subsidiaries, taxes offshore earnings at reduced rates regardless of whether they are repatriated and allows the immediate deduction of certain capital expenditures instead of deductions for depreciation expense over time. We are still evaluating the overall impact of the TCJA to us. Notwithstanding the reduction in the corporate income tax rate, we cannot yet conclude that the overall impact of the TCJA to us is positive.

Our operations are substantially dependent on the availability, use and disposal of water. New legislation and regulatory initiatives or restrictions relating to water disposal wells could have a material adverse effect on our future business, financial condition, operating results and prospects.

Water is an essential component of our drilling and hydraulic fracturing processes. If we are unable to obtain water to use in our operations from local sources, we may be unable to economically produce oil, natural gas and natural gas liquids, which could have an adverse effect on our business, financial condition and results of operations. Wastewaters from our operations typically are disposed of via underground injection. Some studies have linked earthquakes in certain areas to underground injection, which is leading to greater public scrutiny of disposal wells. Any new environmental initiatives or regulations that restrict injection of fluids, including, but not limited to, produced water, drilling fluids and other wastes associated with the exploration, development or production of oil and gas, or that limit the withdrawal, storage or use of surface water or ground water necessary for hydraulic fracturing of our wells, could increase our operating costs and cause delays, interruptions or cessation of our operations, the extent of which cannot be predicted, and all of which would have an adverse effect on our business, financial condition, results of operations and cash flows.

Any change to government regulation or administrative practices may have a negative impact on our ability to operate and our profitability.

Oil and natural gas operations are subject to substantial regulation under federal, state and local laws relating to the exploration for, and the development, upgrading, marketing, pricing, taxation, and transportation of, oil and natural gas and related products and other associated matters. Amendments to current laws and regulations governing operations and activities of oil and natural gas exploration and development operations could have a material adverse impact on our business. In addition, there can be no assurance that income tax laws, royalty regulations and government programs related to our oil and natural gas properties and the oil and natural gas industry generally will not be changed in a manner which may adversely affect our progress or cause delays.

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Permits, leases, licenses, and approvals are required from a variety of regulatory authorities at various stages of exploration and development. There can be no assurance that the various government permits, leases, licenses and approvals sought will be granted in respect of our activities or, if granted, will not be cancelled or will be renewed upon expiration. There is no assurance that such permits, leases, licenses, and approvals will not contain terms and provisions which may adversely affect our exploration and development activities.

The marketability of our production is dependent upon gathering systems, transportation facilities and processing facilities that we do not own or control. If these facilities or systems are unavailable, our oil and natural gas production can be interrupted and our revenues reduced.

The marketability of our oil and natural gas production is dependent upon the availability, proximity and capacity of pipelines, natural gas gathering systems, transportation and processing facilities owned by third parties. In general, we will not control these facilities, and our access to them may be limited or denied due to circumstances beyond our control. A significant disruption in the availability of these facilities could adversely impact our ability to deliver to market the hydrocarbons we produce and thereby cause a significant interruption in our operations. In some cases, our ability to deliver to market our hydrocarbons is dependent upon coordination among third parties that own transportation and processing facilities we use, and any inability or unwillingness of those parties to coordinate efficiently could also interrupt our operations. The lack of availability or the lack of capacity on these systems and facilities could result in the curtailment of production or the delay or discontinuance of drilling plans. This is more likely in areas with recent increased production, such as our Permian Basin area where we have significant development activities. These are risks for which we generally will not maintain insurance.

We operate or participate in oil and natural gas leases with third parties who may not be able to fulfill their commitments to our projects.

In some cases, we operate but own less than 100% of the working interest in the oil and natural gas leases on which we conduct operations, and other parties own the remaining portion of the working interest. Financial risks are inherent in any operation where the cost of drilling, equipping, completing and operating wells is shared by more than one person. We could be held liable for joint activity obligations of other working interest owners, such as nonpayment of costs and liabilities arising from the actions of other working interest owners. In addition, declines in oil, natural gas and natural gas liquids prices may increase the likelihood that some of these working interest owners, particularly those that are smaller and less established, are not able to fulfill their joint activity obligations. A partner may be unable or unwilling to pay its share of project costs, and, in some cases, a partner may declare bankruptcy. In the event any of our project partners do not pay their share of such costs, we would likely have to pay those costs, and we may be unsuccessful in any efforts to recover these costs from our partners, which could materially adversely affect our financial position.

Use of debt financing may adversely affect our strategy.

We may use debt to fund a portion of our future acquisition, development and/or operating activities. Any temporary or sustained inability to service or repay such debt will likely have a material adverse effect on our ability to access financing markets and pursue our operating strategies, as well as impair our ability to respond to adverse economic changes in oil and natural gas markets and the economy in general.

Non-operated properties are controlled by third parties that may not allow us to proceed with our planned capital expenditures. Activities on our operated properties could also be limited or subject to penalties.

We currently are not the operator of some of our existing properties and, therefore, may not be able to influence production operations or further development activities. Joint ownership is customary in the oil and natural gas industry and is generally conducted under the terms of a joint operating agreement (“JOA”), where one of the working interest owners is designated as the “operator” of the property. For non-operated properties, subject to the specific terms and conditions of the applicable JOA, if we disagree with the decision of a majority of working interest owners, we may be required, among other things, to postpone proposed activity or decline to participate in drilling and completing of wells. If we decline to participate, we might be forced to relinquish our interest through “in-or-out” elections or may be subject to certain non-consent penalties, as provided in a JOA. In-or-out elections may require a joint owner to participate or forever relinquish its position, typically only in specific wells or drilling units, although such relinquished positions could be of a larger scope. Non-consent penalties typically allow participating working interest owners to recover from the proceeds of production, if any, an amount equal to 200% to 500% of the non-participating working interest owner’s share of the cost of such operations. Further, even for properties operated by us, there may be instances where decisions related to drilling, completion and operating cannot be made in our sole discretion. In such instances, we could be limited in our development operations and subject to penalties as specified above if we choose not to participate in operations proposed by a majority of working interest owners.

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Because we cannot control activities on properties we do not operate, we cannot directly control the timing of exploration and development projects. If we are unable to fund required capital expenditures with respect to non-operated properties, our interests in those properties may be reduced or forfeited.

Our ability to exercise influence over operations and costs for the properties we do not operate is limited. Our dependence on the operator and other working interest owners for these projects and our limited ability to influence operations and associated costs could prevent the realization of our targeted returns on capital with respect to acquisition, exploration or development activities. The success and timing of exploration, acquisition and development activities on properties operated by others depend upon a number of factors that may be outside our control, including but not limited to:

Where we are not the majority owner or operator of a particular oil and natural gas project, we may have no control over the timing or amount of capital expenditures associated with the project. If we are not willing or able to fund required capital expenditures relating to a project when required by the majority owner(s) or operator, our interests in the project may be reduced or forfeited. Also, we could be responsible for plugging and abandonment costs, as well as other liabilities in excess of our proportionate interest in the property.

A cyber incident could result in information theft, data corruption, operational disruption and/or financial loss.

The oil and natural gas industry has become increasingly dependent on digital technologies to conduct day-to-day operations including certain exploration, development and production activities. For example, software programs are used to interpret seismic data, manage drilling rigs, production equipment and gathering and transportation systems, as well as conduct reservoir modeling and reserve estimation for compliance reporting.

We are dependent on digital technologies including information systems and related infrastructure, to process and record financial and operating data, communicate with our employees, business partners, and stockholders, analyze seismic and drilling information, estimate quantities of oil and natural gas reserves as well as other activities related to our business. Our business partners, including vendors, service providers, purchasers of our production and financial institutions are also dependent on digital technology. The technologies needed to conduct oil and natural gas exploration, development and production activities make certain information the target of theft or misappropriation.

As dependence on digital technologies has increased, cyber incidents, including deliberate attacks or unintentional events, have also increased. A cyber-attack could include gaining unauthorized access to digital systems for the purposes of misappropriating assets or sensitive information, corrupting data, causing operational disruption, or result in denial-of-service on websites.

Our technologies, systems, networks, and those of our business partners may become the target of cyber-attacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or other disruption of our business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period of time. A cyber incident involving our information systems and related infrastructure, or that of our business partners, could disrupt our business plans and negatively impact our operations.

We are subject to litigation relating to Bold and the Bold Transaction, and we may be subject to additional litigation, any of which could adversely affect our business, financial condition and operating results.

On June 7, 2017, litigation captioned Olenik v. Lodzinksi et al. was filed in the Delaware Court of Chancery seeking class action status, claiming a breach of fiduciary duty by our Board and others and challenging the fairness of the Bold Transaction. The plaintiff has requested an award of damages in an unspecified amount. The Company and the other defendants believe the suit is without merit and have mounted a vigorous defense. In addition, we may be subject to additional litigation relating to Bold or the Bold Transaction in the future. We cannot predict the outcome of the ongoing litigation or any litigation that may arise in the future, nor can we predict the amount of time and expense that will be required to resolve the ongoing litigation or any other litigation. While we will evaluate and defend against the ongoing litigation and any other litigation vigorously, the costs of the defense, including legal fees of directors under indemnification obligations, and other effects of such litigation could have an adverse effect on our business, financial condition and results of operations.

On August 18, 2017, litigation captioned Trinity Royal Partners, LP v. Bold Energy III LLC, et al. was filed with the 142nd Judicial District of the District Court in Midland County, Texas, asserting breach of contract and indemnity claims for alleged damages from loss of property relating to two oil and natural gas wells in which Bold was the operator. Trinity Royalty Partners,

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LP (“Trinity”) alleges that Bold is required to indemnify Trinity under the terms of an Assignment and a Participation and Joint Development Agreement between Bold and Trinity. Damages are alleged to include costs incurred in attempting to repair and restore an oil and natural gas well and for the loss of future reserves attributable to both wells. Trinity is seeking approximately $7.2 million in damages and attorneys’ fees. Earthstone and Bold believe the suit is without any merit and Bold intends to mount a vigorous defense.

Hurricanes, earthquakes and other natural disasters could have an adverse effect on our business, financial condition and results of operations.

Some of our properties are located in areas that are susceptible to hurricanes, earthquakes and other natural disasters. These natural disasters could potentially damage our assets and disrupt our production of oil and natural gas. In the third quarter of 2017, Hurricane Harvey caused disruptions in our operations and, as of December 31, 2017, we had incurred $0.2 million in losses. For more information regarding the impact of Hurricane Harvey on operating results, see Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” Natural disasters can similarly affect our facilities as well. In either case, losses could exceed our insurance coverage and our business, financial condition and results of operations could be adversely affected, perhaps materially.

The loss or unavailability of any of our executive officers or other key employees could have a material adverse effect on our business.

We depend greatly on the efforts of our executive officers and other key employees to manage our operations. The loss or unavailability of any of our executive officers or other key employees could have a material adverse effect on our business.

Risks Related to the Ownership of our Class A Common Stock

We are a “controlled company” within the meaning of the NYSE rules and, as a result, qualify for and rely on exemptions from certain corporate governance requirements.

EnCap controls a majority of the combined voting power of all classes of our outstanding voting stock. As a result, we are a controlled company within the meaning of the NYSE corporate governance standards. Under the NYSE rules, a company of which more than 50% of the voting power is held by another person or group of persons acting together is a controlled company and may elect not to comply with certain NYSE corporate governance requirements, including the requirements that:

These requirements will not apply to us as long as we remain a controlled company. Accordingly, you may not have the same protections afforded to stockholders of companies that are subject to all of the corporate governance requirements of the NYSE.

Our principal stockholders hold a substantial majority of the voting power of our Class A Common Stock and Class B Common Stock.

Holders of Class A Common Stock and Class B Common Stock will vote together as a single class on all matters presented to our stockholders for their vote or approval, except as otherwise required by applicable law or our Third Amended and Restated Certificate of Incorporation. EnCap, through its ownership of Bold Holdings, may be deemed to beneficially own approximately 63% of our voting interests. In addition, certain affiliates controlled by EnCap directly own approximately 8% of our Class A Common Stock. As a significant stockholder, EnCap and certain of its affiliates could limit the ability of our other stockholders to approve transactions that they may deem to be in the best interests of our Company or delaying or preventing changes in control or changes in our management.

So long as EnCap and certain of its affiliates continue to control a significant amount of our outstanding voting securities, they will continue to be able to have significant influence over all matters requiring stockholder approval, regardless of whether or not other stockholders believe that a potential transaction is in their own best interests. Also, in any of these matters, the interests of our management team may differ or conflict with the interests of our other stockholders. In addition, EnCap and its affiliates may, from time to time, acquire interests in businesses that directly or indirectly compete with our business, as well as businesses that are significant existing or potential acquisition candidates or industry partners. EnCap and its affiliates may acquire or seek to acquire assets that we seek to acquire and, as a result, those acquisition opportunities may not be available to us or may be more expensive for us to pursue. Moreover, this concentration of stock ownership may also adversely affect the trading price of our Class A Common Stock to the extent investors perceive a disadvantage in owning stock of a company with a controlling stockholder.

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Future sales of our Class A Common Stock in the public market, or the perception that such sales may occur, could reduce our stock price, and any additional capital raised by us through the sale of equity may dilute your ownership in us.

We may sell additional shares of Class A Common Stock or securities convertible into shares of our Class A Common Stock in subsequent offerings. We cannot predict the size of future issuances of our Class A Common Stock or securities convertible into Class A Common Stock or the effect, if any, that future issuances and sales of shares of our Class A Common Stock will have on the market price of our Class A Common Stock. Sales of substantial amounts of our Class A Common Stock (including shares issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices of our Class A Common Stock.

Bold Holdings and its permitted transferees have the right to exchange their EEH Units and shares of Class B Common Stock for our Class A Common Stock pursuant to the terms of the EEH LLC Agreement.

As of March 1, 2018, there were approximately 35.9 million shares of our Class A Common Stock that are issuable upon redemption or exchange of EEH Units and shares of Class B Common Stock that are held by Bold Holdings or its permitted transferees. Pursuant to the EEH LLC Agreement, subject to certain restrictions therein, holders of EEH Units and our Class B Common Stock are entitled to exchange such EEH Units and shares of Class B Common Stock for shares of our Class A Common Stock at any time. We also entered into a registration rights agreement pursuant to which the shares of Class A Common Stock which may be issued upon redemption or exchange of EEH Units and shares of Class B Common Stock, subject to certain limitations set forth therein, have been registered for subsequent offers and sales by Bold Holdings and its permitted transferees.

We have no plans to pay dividends on our Class A Common Stock. Stockholders may not receive funds without selling their shares.

We do not anticipate paying any cash dividends on our Class A Common Stock in the foreseeable future. We currently intend to retain future earnings, if any, to finance the expansion of our business. Our future dividend policy is within the discretion of our Board and will depend upon various factors, including our business, financial condition, results of operations, capital requirements, and investment opportunities. In addition, the EEH Credit Agreement does not allow EEH to make any significant payments to us, which makes it highly unlikely that we would be in a position to pay cash dividends on our Class A Common Stock.

Our Board can, without stockholder approval, cause preferred stock to be issued on terms that could adversely affect our common stockholders.

Under our Third Amended and Restated Certificate of Incorporation, our Board is authorized to cause the Company to issue up to 20,000,000 shares of preferred stock, of which none are issued and outstanding as of the date of this report. Also, our Board, without stockholder approval, may determine the price, rights, preferences, privileges, and restrictions, including voting rights, of those shares. If the Board causes shares of preferred stock to be issued, the rights of the holders of our Class A Common Stock and Class B Common Stock would likely be subordinate to those of preferred holders and therefore could be adversely affected. The Board’s ability to determine the terms of preferred stock and to cause its issuance, while providing desirable flexibility in connection with possible acquisitions and other corporate purposes, could have the effect of making it more difficult for a third party to acquire a majority of our outstanding voting stock or otherwise seek to acquire us. Shares of preferred stock issued by us could include voting rights, or even super voting rights, which could shift the ability to control the Company to the holders of the preferred stock. Preferred stock could also have conversion rights into shares of Class A Common Stock at a discount to the market price of the Class A Common Stock which could negatively affect the market for our Class A Common Stock. In addition, preferred stock could have preference in the event of liquidation of the Company, which means that the holders of preferred stock would be entitled to receive the net assets of the Company distributed in liquidation before the Class A common stockholders receive any distribution of the liquidated assets. We have no current plans to issue any shares of preferred stock.

The price of our Class A Common Stock may fluctuate significantly, which could negatively affect us and holders of our Class A Common Stock.

The trading price of our Class A Common Stock may fluctuate significantly in response to a number of factors, many of which are beyond our control. For instance, if our financial results are below the expectations of securities analysts and investors, the market price of our Class A Common Stock could decrease, perhaps significantly. Other factors that may affect the market price of our Class A Common Stock include:

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In addition, U.S. securities markets have experienced significant price and volume fluctuations. These fluctuations often have been unrelated to the operating performance of companies in these markets. Market fluctuations and broad market, economic, and industry factors may negatively affect the price of our Class A Common Stock, regardless of our operating performance. Any volatility or a significant decrease in the market price of our Class A Common Stock could also negatively affect our ability to make acquisitions using Class A Common Stock. Further, if we were to be the object of securities class action litigation as a result of volatility in our Class A Common Stock price or for other reasons, it could result in substantial costs and diversion of our management’s attention and resources, which could negatively affect our financial results.

We are subject to certain requirements of Section 404 of the Sarbanes-Oxley Act. If we fail to comply with the requirements of Section 404 or if we or our auditors identify and report material weaknesses in internal control over financial reporting, our investors may lose confidence in our reported information and our stock price may be negatively affected.

As of December 31, 2017, we are required to comply with certain provisions of Section 404 of the Sarbanes-Oxley Act of 2002 (the “Sarbanes-Oxley Act”). Section 404 requires that we document and test our internal control over financial reporting and issue our management’s assessment of our internal control over financial reporting. This section also requires that our independent registered public accounting firm issue an attestation report on such internal control. If we fail to comply with the requirements of Section 404 of the Sarbanes-Oxley Act, or if we or our auditors identify and report material weaknesses in our internal control over financial reporting, the accuracy and timeliness of the filing of our annual and quarterly reports may be materially adversely affected and could cause investors to lose confidence in our reported financial information, which could have a negative effect on the trading price of our Class A Common Stock. In addition, a material weakness in the effectiveness of our internal control over financial reporting could result in an increased chance of fraud and the loss of customers, reduce our ability to obtain financing and require additional expenditures to comply with these requirements, each of which could have a material adverse effect on our business, results of operations and financial condition.

Anti-takeover provisions could make a third-party acquisition difficult.

Our Third Amended and Restated Certificate of Incorporation provides for a classified board of directors, with each member serving a three-year term. Provisions in our Third Amended and Restated Certificate of Incorporation could make it more difficult for a third party to acquire us without the approval of our Board. In addition, the Delaware corporate statutes also contain certain provisions that could make an acquisition by a third party more difficult.

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Our stockholders may act by unilateral written consent.

Under our Third Amended and Restated Certificate of Incorporation, any action required to be taken at any annual or special meeting of our stockholders, or any action which may be taken at any annual or special meeting of such stockholders, may be taken without a meeting, without prior notice and without a vote, if a consent in writing, setting forth the action so taken, is signed by the holders of outstanding stock having not less than the minimum number of votes that would be necessary to authorize or take such action at a meeting at which all shares entitled to vote thereon were present and voted. Thus, consents of this type can be effected without the participation or input of minority stockholders.

Item 1B.  Unresolved Staff Comments

None.

Item 2.  Properties

Summary of Oil and Gas Properties

Midland Basin

We have an operated position of 20,498 net acres in the core of the Midland Basin of west Texas across Reagan, Upton, and Midland counties with an average working interest of approximately 87%.  As of December 31, 2017, we had approximately 13 gross vertical and 26 gross horizontal operated producing wells. Current internal estimates indicate approximately 526 potential gross, largely de-risked, operated drilling locations, the vast majority of which are in various benches of the Wolfcamp and the Spraberry formations. Of these 526 operated locations, 466 locations are expected to have an average working interest of 79%, whereas 60 locations are expected to be operated units where we would hold less than a 50% working interest. We are actively pursuing trades and acquisitions of additional acreage that would increase our working interest in these 60 locations. At this time, we expect that these 60 locations would have an average working interest of approximately 28%.

We also have a non-operated position of 6,167 net acres in the Midland Basin of west Texas, located in Howard, Glasscock, Martin and Midland counties, Texas. As of December 31, 2017, we had an interest in approximately 134 gross vertical and 26 gross horizontal non-operated producing wells with an average working interest of approximately 37%.

We have identified approximately 417 potential gross horizontal locations in various benches of the Wolfcamp and Spraberry formations with an estimated average working interest of approximately 28%. We have also identified approximately 117 potential gross vertical well locations in the Clearfork, Spraberry, Wolfcamp, Strawn and Fussleman formations with an estimated average working interest of approximately 41%.

Eagle Ford Trend

As of December 31, 2017, we held 33,557 gross (16,045 net) operated leasehold acres in Fayette, Gonzales and Karnes counties, Texas. The acreage is located in the crude oil window of the Eagle Ford shale trend of south Texas and is prospective for the Eagle Ford, Austin Chalk and Upper Eagle Ford formations. We serve as the operator with a range of approximately 16% to 50% undivided ownership interest in substantially all of the acreage.

As of December 31, 2017, we operated 91 gross Eagle Ford wells and 12 gross Austin Chalk wells and had non-operated interests in five gross producing Eagle Ford wells and one gross producing Austin Chalk well. We have identified a total of approximately 165 potential gross Eagle Ford drilling locations in this acreage. In addition, because our acreage position is prospective for the Austin Chalk and Upper Eagle Ford formations, we may have additional future economic locations. The majority of our acreage is covered by an approximately 173 square mile 3-D seismic survey.

We have a non-operated position in 25,097 gross (2,863 net) acres within La Salle County, Texas. The acreage is prone to natural gas and condensate produced from the Eagle Ford formation. The two areas are summarized below:

Additionally, we have a non-operated position in 2,055 gross (948 net) acres within Frio and Wilson counties of Texas.

Other

Our other 2017 operations primarily related to our recently divested Bakken properties, and other non-core oil and natural gas properties.  

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Oil and Natural Gas Reserves

As of December 31, 2017, primarily all of our oil and natural gas reserves were located in the state of Texas. We expect to further develop these properties through additional drilling and completion operations. Our reserve estimates have been prepared by Cawley, Gillespie & Associates, Inc. (“CG&A”), an independent petroleum engineering firm. The scope and results of CG&A’s procedures are summarized in a letter which is included as an exhibit to this report. For further information on estimated reserves, including information on estimated future net cash flows and the standardized measure of discounted future net cash flows, please refer to the Supplemental Information on Oil and Gas Exploration and Production Activities (Unaudited) in Part II, Item 8 of the Notes to Consolidated Financial Statements of this report.

As of December 31, 2017, our estimated proved reserves totaled 79,976 MBOE and had a PV-10 value of approximately $598.6 million and a Standardized Measure of Discounted Future Net Cash Flows of approximately $592.7 million, all of which relate to our properties in Texas. In addition to the completion of the Bold Transaction in May 2017, we incurred approximately $81.1 million in capital expenditures, primarily drilling and completion costs, during 2017. We expect to further develop our properties through additional drilling.

2017 Activity in Proved Reserves

From January 1, 2017 to December 31, 2017, our total estimated proved reserves increased 564% from 12,051 MBOE to 79,976 MBOE. Of that, estimated proved developed reserves increased 113% from 9,361 MBOE to 19,961 MBOE and estimated proved undeveloped reserves increased 2,131% from 2,690 MBOE to 60,015 MBOE. These increases are primarily attributable to the Bold Transaction that closed in May 2017.

Proved Reserves as of December 31, 2017

The below table sets forth a summary of our estimated crude oil, natural gas and natural gas liquids reserves as of December 31, 2017, based on the annual reserve estimate prepared by CG&A. In preparing this reserve report, CG&A evaluated 100% of our properties at December 31, 2017.  Proved reserves are estimated based on the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period for the year. All prices and costs associated with operating wells were held constant in accordance with the SEC guidelines.  

Our proved reserve categories as of December 31, 2017 are summarized in the table below:

 

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 its 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.

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The table below provides a reconciliation of PV-10 to the standardized measure of discounted future net cash flows (in thousands):

 

Drilled But Uncompleted Wells

In order to achieve efficiencies from a pricing and logistics standpoint, our customary sequence of drilling and completion operations is to drill a group of wells and defer completion operations until all drilling operations for the group are concluded and then commence completion activities.  

As of December 31, 2017, we had 16.2 net wells (1,789 MBOE) included in PDNP which included 13 gross (4.8 net wells) (1,673 MBOE) that were drilled but uncompleted. The costs associated with the drilled but uncompleted wells totaled $9.5 million.  Subsequent to December 31, 2017, we have completed 10 gross (3.3 net) wells (1,092 MBOE) and completion operations are ongoing with the remaining 1.5 net wells (502 MBOE). We anticipate completion of all the remaining drilled but uncompleted wells by April 2018.

Reserve Quantity Information

The following table illustrates our estimated net proved reserves, including changes, and proved developed and proved undeveloped reserves for the periods indicated. The oil prices as of December 31, 2017, 2016, and 2015 are based on the respective 12-month unweighted average of the first of the month prices of the West Texas Intermediate spot prices which equates to $51.34 per barrel, $42.75 per barrel, and $50.28 per barrel, respectively. The natural gas prices as of December 31, 2017, 2016 and 2015 are based on the respective 12-month unweighted average of the first of month prices of the Henry Hub spot price which equates to $2.98 per MMBtu, $2.48 per MMBtu and $2.59 per MMBtu, respectively. The natural gas liquids prices used to value reserves as of December 31, 2017, 2016 and 2015 averaged $22.59 per barrel, $13.21 per barrel and $14.11 per barrel, respectively. All prices are adjusted by lease or field for energy content, transportation fees, and market differentials. All prices are held constant in accordance with SEC guidelines.        

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A summary of the changes in the quantities of our proved oil, natural gas and natural gas liquids reserves for the years ended December 31, 2017, 2016 and 2015 are as follows:      

 

Notable changes in proved reserves for the year ended December 31, 2017 included the following:

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Notable changes in proved reserves for the year ended December 31, 2016 included the following:

Notable changes in proved reserves for the year ended December 31, 2015 included the following:

Proved Undeveloped Reserves

Proved undeveloped reserves increased from 2,690 MBOE to 60,015 MBOE or 2,131%, for the year ended December 31, 2017 compared to the year ended December 31, 2016. Proved undeveloped reserves represent 75% of our total proved reserves. Certain previously booked PUDs were reclassified as proved developed reserves due to successful drilling efforts. Revisions of prior estimates include certain PUDs that were reclassified to unproved categories due to development plan changes. In accordance with our 2017 year-end independent engineering reserve report, we plan to drill all of our individual PUD drilling locations within the next five years.

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Changes in our PUD reserves for the years ended December 31, 2017, 2016 and 2015 were as follows (in MBOE):

 

2017 Changes in PUD reserves

Conversions to developed. In our year-end 2016 plan to develop our PUDs within five years, we estimated that $6.9 million of capital would be incurred in 2017 and that we would convert 732 MBOE.  Because of the improvement in commodity prices and the change in our development plan for 2017, we actually incurred $8.5 million to convert 622 MBOE to developed. Our plan changed in that we developed more oil PUDs and elected not to participate in natural gas PUDs which included the above mentioned 443 MBOE associated with the Eagle Ford non-participation.  The capital to develop our oil PUDs was higher on a per unit basis than the natural gas PUDs, however, the margins are higher for oil PUDs.  The oil PUDs further benefited our longer-term operated development plans.  Since the Bold Transaction closed in May 2017, the associated capital plan for the Bold properties was not considered in our year-end 2016 report. We did however incur $63.4 million to convert 2,134 MBOE of purchased PUD reserves to Developed.  We intend to convert our proved undeveloped reserves into proved developed producing reserves in accordance with our estimates as of the date of our year-end 2017 reserve report.

Extensions and discoveries. Additionally, 27,977 MBOE were added as extensions and discoveries due to successful drilling results on our acreage positions because of the wells we drilled.  The increase was also supported by successful drilling results by other operators directly offsetting and in close proximity to our acreage.  All of these drilling results increased the confidence of the reservoir continuity and performance of the associated reservoirs which increased the number of PUDs primarily in the Midland Basin.

Sales of minerals in place.  Sales of minerals in place totaled 391 MBOE during 2017 and were primarily related to the disposition of our Bakken properties, as further described in Note 3. Acquisitions and Divestitures in the Notes to Consolidated Financial Statements.

Purchases of minerals in place. During 2017, 37,327 MBOE were added to PUD reserves upon the closing of the Bold Transaction.

Revision to previous estimates. Revisions of 4,832 MBOE were primarily due to (1) removal of approximately 2,011 MBOE of reserves due to delayed development plans of other operators in the Midland Basin that management previously expected to be developed within five years, (2) reduction of 2,378 MBOE upon the closing of the Bold Transaction and making adjustments to development plans and PUD reserve assignments, and (3) non-participation in three Eagle Ford natural gas PUDs that were expected to develop 443 MBOE. This non-participation has no impact on our ability to participate in future wells in this acreage position.  

2016 Changes in PUD reserves

In early 2016, due primarily to depressed prices of oil and natural gas, we placed a lower emphasis on the conversion of our PUDs into proved developed producing reserves. In our plan to convert these reserves over a five-year period, we estimated that $3.1 million of capital expenditure would be incurred in 2016, and the bulk of capital expenditures would occur over the following four years. Our actual 2016 capital expenditures for conversion of proved undeveloped reserves were $3.2 million, in line with our estimates. We also had estimated that these capital expenditures would result in 258 MBOE of proved developed producing reserves. Our actual estimated conversions were 169 MBOE. The difference was due primarily to one less location being drilled than we had estimated and lower initial reserve estimates for wells in certain units where all wells in the units had not been developed. This resulted in lower reserve estimates until the remaining wells in the units are drilled.

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As of December 31, 2016, our estimated proved undeveloped reserves were significantly lower than as of December 31, 2015, due to lower oil and natural gas prices used in making our 2016 estimates.

Extensions and Discoveries during the year ended December 31, 2016, were from our operated Eagle Ford and non-operated Bakken properties.

2015 Changes in PUD reserves

All of our purchases of minerals in place reserves during the year ended December 31, 2015, occurred in our Eagle Ford property in Gonzales County, Texas.

Estimated Costs Related to Conversion of Proved Undeveloped Reserves to Proved Developed Reserves

 

The following table sets forth the estimated timing and cash flows of developing our proved undeveloped reserves at December 31, 2017 ($ in thousands):

 

Historically, our drilling programs have been substantially funded from our cash flow and borrowings under our credit facility. Based on current commodity prices and our current expectations over the next five years of our cash flows and drilling programs, which includes drilling of proved undeveloped and unproven locations, we believe that we can continue to substantially fund our drilling activities from our cash flow and with borrowings under the EEH Credit Agreement. In addition, historically, we have been able to take advantage of the capital markets, as needed, when opportunities arose.

Preparation of Reserve Estimates

We engaged an independent petroleum engineering consulting firm, CG&A, to prepare our annual reserve estimates and we have relied on CG&A’s expertise to ensure that our reserve estimates are prepared in compliance with SEC guidelines.

The technical person primarily responsible for the preparation of the reserve report is Mr. W. Todd Brooker, President of CG&A. He graduated with honors from the University of Texas at Austin in 1989 with a Bachelor of Science degree in Petroleum engineering. Mr. Brooker is a Registered Professional Engineer in the State of Texas (License No. 83462) and has more than 25 years of experience in the estimation and evaluation of oil and natural gas reserves. He is also a member of the Society of Petroleum Engineers.

Robert J. Anderson, our Executive Vice President responsible for reservoir engineering, is a qualified reserve estimator and auditor and is primarily responsible for overseeing CG&A during the preparation of our annual reserve estimates. His professional qualifications meet or exceed the qualifications of reserve estimators and auditors set forth in the “Standards Pertaining to Estimation and Auditing of Oil and Natural Gas Reserves Information” promulgated by the Society of Petroleum Engineers. His qualifications include a Bachelor of Science degree in Petroleum Engineering from the University of Wyoming in 1986; a Master of Business Administration degree from the University of Denver in 1988; member of the Society of Petroleum Engineers since 1985; and more than 31 years of practical experience in estimating and evaluating reserve information with more than five of those years being in charge of estimating and evaluating reserves.

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We maintain adequate and effective internal controls over our reserve estimation process as well as the underlying data upon which reserve estimates are based. The primary inputs to the reserve estimation process are technical information, financial data, ownership interest and production data. The relevant field and reservoir technical information, which is updated, at least, annually, is assessed for validity when CG&A has technical meetings with our engineers, geologists, operations and land personnel. Current revenue and expense information is obtained from our accounting records, which are subject to external quarterly reviews, annual audits and our own set of internal controls over financial reporting. Internal controls over financial reporting are assessed for effectiveness annually using criteria set forth in Internal Control – Integrated Framework, (2013 Version) issued by the Committee of Sponsoring Organizations of the Treadway Commission. All current financial data such as commodity prices, lease operating expenses, production taxes and field level commodity price differentials are updated in the reserve database and then analyzed to ensure that they have been entered accurately and that all updates are complete. Our current ownership in mineral interests and well production data are also subject to our internal controls over financial reporting, and they are incorporated in our reserve database as well and verified internally by our personnel to ensure their accuracy and completeness. Once the reserve database has been updated with current information, and the relevant technical support material has been assembled, CG&A meets with our technical personnel to review field performance and future development plans in order to further verify the validity of estimates. Following these reviews, the reserve database is furnished to CG&A so that it can prepare its independent reserve estimates and final report. The reserve estimates prepared by CG&A are reviewed and compared to our internal estimates by our Executive Vice President responsible for reservoir engineering. Material reserve estimation differences are reviewed between CG&A and us, and additional data is provided to address the differences. If the supporting documentation will not justify additional changes, the CG&A reserves are accepted. In the event that additional data supports a reserve estimation adjustment, CG&A will analyze the additional data, and may make changes it solely deems necessary. Additional data is usually comprised of updated production information on new wells. Once the review is completed and all material differences are reconciled, the reserve report is finalized and our reserve database is updated with the final estimates provided by CG&A.

Net Oil, Natural Gas and Natural Gas Liquids Production, Average Price and Average Production Cost

The net quantities of oil, natural gas and natural gas liquids produced and sold by us for the years ended December 31, 2017, 2016, and 2015, the average sales price per unit sold and the average production cost per unit are presented below:

 

 

The following tables below summarize the net quantities of oil, natural gas and natural gas liquids produced and sold by us, the average sales price per unit sold and the average production cost per unit for each of our core areas for the years ended December 31, 2017, 2016, and 2015.

 

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Midland Basin

 

No results for 2015 have been presented below as they represent the operating results of properties acquired in the Bold Transaction completed in May 2017 and in the Lynden Arrangement completed in May 2016.

 

Eagle Ford Trend

 

 

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Gross and Net Productive Wells

The following table summarizes our gross and net productive oil and natural gas wells by area as of December 31, 2017.  A net well represents our percentage of ownership of a gross well.

 

Acreage

The following table summarizes our gross and net developed and undeveloped acreage by state as of December 31, 2017. Net acreage represents our percentage ownership of gross acreage.

 

 

The following table summarizes, as of December 31, 2017, the portion of our gross and net acreage subject to expiration over the next three years if not successfully developed or renewed.

 

We have development agreements related to certain of our operated leases in the Midland Basin which require us to drill 42 gross wells (31 net wells) over the next five years. If we do not drill the required wells, we would be in default of the agreements. All of the aforementioned wells are included in management’s development plan.

Exploratory Wells and Development Wells

Set forth below for the three years ended December 31, 2017 is information concerning the number of wells we drilled during the years indicated.

 

 

Present Activities

As of March 1, 2018, we had 7 gross (5.3 net) operated wells and 4 gross (0.8 net) non-operated wells in the process of drilling or completing.

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Item 3.  Legal Proceedings

In the ordinary course of business, we may be involved in litigation and claims arising out of our operations. As of December 31, 2017, and through the filing date of this report, we do not believe the ultimate resolution of any such actions or potential actions of which we are currently aware will have a material effect on our consolidated financial position or results of operations.

A description of our legal proceedings is included in Note. 15. Commitments and Contingencies in the Notes to Consolidated Financial Statements included in Item 8 of this report.

Item 4.  Mine Safety Disclosures

Not applicable.

 

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PART II

Item 5.  Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Market Information for Common Stock

Shares of our Class A Common Stock are listed on the NYSE under the symbol “ESTE.” The following table sets forth the reported high and low sales prices of our Class A Common Stock for the periods indicated:

 

 

Holders

As of March 1, 2018, there were approximately 2,000 holders of record of our Class A Common Stock and approximately 30 holders of record of our Class B Common Stock.  

Dividends

 

We have never paid dividends on our Class A Common Stock or Class B Common Stock and do not intend to pay a dividend in the foreseeable future. Furthermore, the EEH Credit Agreement restricts the payment of cash dividends. The payment of future cash dividends on our Class A Common Stock, if any, will be reviewed periodically by our Board and will depend upon, but not be limited to, our financial condition, funds available for operations, the amount of anticipated capital and other expenditures, our future business prospects and any restrictions imposed by our present or future financing arrangements. 

Repurchase of Equity Securities

The following table sets forth information regarding our acquisition of shares of Class A Common Stock for the periods presented:

 

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Performance Graph

The following graph reflects a comparison of the cumulative total stockholder return of our Class A Common Stock beginning December 31, 2013 through December 31, 2017, relative to the cumulative total returns of the S&P 500 Index and the S&P Oil & Gas Exploration & Production Select Industry Index.  The graph assumes the investment of $100 on December 31, 2012 in our Class A Common Stock and each index and the reinvestment of all dividends, if any.  The identity of the companies included in the S&P Oil & Gas Exploration & Production Select Industry Index will be provided upon request.

 

 

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Item 6.  Selected Financial Data

The following selected financial data should be read in conjunction with Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, and our Consolidated Financial Statements and the accompanying notes thereto included elsewhere in this report.  In accordance with GAAP, the consolidated financial information and consolidated financial statements included herein for 2014 and prior period, are those of OVR and its subsidiaries. Prior to our acquisition of three operating subsidiaries of OVR in exchange for shares of our common stock in December 2014 (the “Exchange”). OVR, and its subsidiaries were pass through entities for income tax purposes and therefore no income tax expense was recorded for the historical periods prior to the year ended December 31, 2014. OVR was formed in December 2012 and was initially capitalized through the contribution of producing properties, acreage and working capital as well as cash commitments from investors. Upon initial capitalization, the contributed properties, acreage and working capital resulted in one owner retaining a controlling interest in OVR, and despite a change in management, GAAP required OVR to record the contributed properties at their historical cost basis even though such cost basis was in excess of the valuation agreed upon by members at the time of capitalization. GAAP required reporting higher DD&A provisions and significant impairments, in all years presented below, than would have been reported otherwise had the properties been recorded at the agreed upon valuation approximating fair value.    

 

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Item 7.  Management’s Discussion and Analysis of Financial Condition and Results of Operations

This discussion and other items in this Annual Report on Form 10-K contain forward-looking statements and information that are based on management’s beliefs, as well as assumptions made by, and information currently available to, management. When used in this document, the words “believe,” “anticipate,” “estimate,” “expect,” “intend,” “may,” “will,” “project,” “forecast,” “plan,” and similar expressions are intended to identify forward-looking statements. Although management believes that the expectations reflected in these forward-looking statements are reasonable, it can give no assurance that these expectations will prove to have been correct. These statements are subject to numerous risks, uncertainties and assumptions.  See Cautionary Statement Concerning Forward-Looking Statements in this report. Certain of these risks are summarized in this report under Item 1A. Risk Factors, which you should read carefully in connection with our forward-looking statements.  Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results may vary materially from those anticipated. We undertake no obligation to release publicly any revisions to these forward-looking statements that may be made to reflect events or circumstances after the date hereof or to reflect the occurrence of unanticipated events.

Overview

We are a growth-oriented independent oil and gas company engaged in the acquisition and development of oil and gas reserves through activities that include the acquisition, drilling and development of undeveloped leases, assets and corporate acquisitions and mergers and, to a lesser extent, exploration activities. Our operations are all in the upstream segment of the oil and natural gas industry and all of our properties are onshore in the United States.  At present, our primary assets are located in the Midland Basin of west Texas and the Eagle Ford trend of south Texas.

Earthstone is the sole managing member of Earthstone Energy Holdings, LLC, a Delaware limited liability company (together with its wholly-owned consolidated subsidiaries, “EEH”), with a controlling interest in EEH. Earthstone, together with its wholly-owned subsidiary, Lynden Corp, and Lynden Corp’s wholly-owned consolidated subsidiary, Lynden US and also a member of EEH, consolidates the financial results of EEH and records a noncontrolling interest in the Consolidated Financial Statements representing the economic interests of EEH's members other than Earthstone and Lynden US (collectively, the “Company” “our,” “we,” “us,” or similar terms).

Areas of Operation

Our primary focus is concentrated in the Midland Basin of west Texas, a high oil and liquids rich resource which provides us with multiple horizontal target horizons, extensive production histories, long-lived reserves and historically high drilling success rates.  

Midland Basin

We believe that the Midland Basin continues to have attractive economics and we expect to continue to focus our attention on growing our footprint through development drilling, acreage trades, asset acquisitions, and corporate merger and acquisition opportunities. We are intensely focused on expansion in the Midland Basin and production results continue to be as good or better than we projected.

We have been operating a one drilling rig program in the Midland Basin and plan to maintain a one rig program throughout 2018, with a view toward adding a second rig at some point in 2018 predicated upon commodity prices, availability of quality services, our drilling results and liquidity. In February 2018, we completed drilling our 11th Midland Basin well. We currently have a rig drilling the first well of a two-well pad in Reagan County. At present we have five wells waiting on completion and expect to have an inventory of seven wells when we initiate completion operations in April 2018.

We continue to be active in acreage trades and acquisitions in the Midland Basin which generally allow for longer laterals, increased operated inventory and greater operating efficiency.

Eagle Ford Trend

We recently completed an 11 well drilling program in southern Gonzales County, Texas. Completion operations on the 11 wells began in November 2017 and were concluded in January 2018. We currently expect our 2018 drilling program to be consistent with our 2017 program in this area. During each of the second and third quarters of 2017, we entered into Joint Development Agreements ("JDA") for these wells. In each of the two JDA’s, the financial partner is obligated to pay a promoted (higher) share of the capital expenditures to earn 50% of our interest in these units and adjacent acreage. The two JDA’s reduced our overall capital expenditures

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by approximately $17 million in 2017, allowing us to shift capital resources from the Eagle Ford to the Midland Basin while still maintaining operating control over our Eagle Ford program.

Recent Developments

Bold Contribution Agreement

On May 9, 2017, Earthstone completed the Bold Contribution Agreement. The primary purpose of the Bold Contribution Agreement was to provide for the business combination between Earthstone and Bold, which owned significant developed and undeveloped oil and natural gas properties in the Midland Basin of west Texas (the “Bold Transaction”).

The Bold Transaction was structured in a manner commonly known as an “Up-C.” Under this structure and the Bold Contribution Agreement, (i) Earthstone recapitalized its common stock into two classes – Class A Common Stock and Class B Common Stock, and all of Earthstone’s existing outstanding Common Stock was recapitalized on a one-for-one basis for Class A Common Stock (the “Recapitalization”); (ii) Earthstone transferred all of its membership interests in Earthstone Operating, LLC, Sabine River Energy, LLC, EF Non-Op, LLC and Earthstone Legacy Properties, LLC (formerly Earthstone GP, LLC) and $36,071 in cash from the sale of Class B Common Stock to Bold Holdings (collectively, the “Earthstone Assets”) to EEH, in exchange for 16,791,296 EEH Units; (iii) Lynden US transferred all of its membership interests in Lynden Op to EEH in exchange for 5,865,328 EEH Units; (iv) Bold Holdings transferred all of its membership interests in Bold to EEH in exchange for 36,070,828 EEH Units and purchased 36,070,828 shares of Class B Common Stock issued by Earthstone for $36,071; and (v) Earthstone granted an aggregate of 150,000 fully vested shares of Class A Common Stock under the 2014 Plan to certain employees of Bold. Each EEH Unit, together with one share of Class B Common Stock, are convertible into one share of Class A Common Stock.

Upon closing of the Bold Transaction on May 9, 2017, Bold Holdings owned approximately 61.4% of the outstanding shares of Class A Common Stock, on a fully diluted, as converted basis. The EEH Units and the shares of Class B Common Stock issued to Bold Holdings were not registered under the Securities Act, but were issued by EEH and Earthstone in reliance on the exemption provided under Section 4(a)(2) of the Securities Act.

Pursuant to the terms of the Bold Contribution Agreement, at the closing of the Bold Transaction, Earthstone, Bold Holdings, and the unitholders of Bold Holdings entered into the Registration Rights Agreement relating to the shares of Class A Common Stock issuable upon the exchange of the EEH Units and Class B Common Stock held by Bold Holdings or its unitholders. In accordance with the Registration Rights Agreement, Earthstone filed the Registration Statement with the SEC to permit the public resale of the shares of Class A Common Stock issued by Earthstone to Bold Holdings or its unitholders in connection with the exchange of Class B Common Stock and EEH Units in accordance with the terms of the EEH LLC Agreement. On October 18, 2017, the Registration Statement was declared effective by the SEC.

On May 9, 2017, in connection with the closing of the Bold Contribution Agreement, Earthstone, EnCap, OVR, and Bold Holdings entered into the Voting Agreement, pursuant to which EnCap, OVR, and Bold Holdings agreed not to vote any shares of Class A Common Stock or Class B Common Stock held by them in favor of any action, or take any action that would in any way alter the composition of the Board from its composition immediately following the closing of the Bold Contribution Agreement as long as the Voting Agreement is in effect.

Immediately following the closing of the Bold Contribution Agreement, the Board was increased to nine members from eight members, four of which are designated by EnCap, three of which are independent, and two of which are members of management, including Earthstone’s Chief Executive Officer. At any time during the effectiveness of the Voting Agreement during which EnCap’s collective ownership of Earthstone exceeds 50% of the total issued and outstanding voting stock, EnCap may remove and replace one director that was not originally designated by EnCap, and his or her successors. Any such removal and replacement will be conducted in accordance with the provisions of Earthstone’s certificate of incorporation and bylaws then in effect. The Voting Agreement terminates on the earlier of (i) the fifth anniversary of the closing date of the Bold Contribution Agreement and (ii) the date upon which EnCap, OVR, and Bold Holdings collectively own, of record and beneficially, less than 20% of Earthstone’s outstanding voting stock.

On May 9, 2017, the closing sale price of the Class A Common Stock was $13.58 per share. On May 10, 2017, the Class A Common Stock was uplisted from the NYSE American to the NYSE where it is listed under the symbol “ESTE.”

Credit Agreement

On May 9, 2017, in connection with the closing of the Bold Transaction, the Company exited the ESTE Credit Agreement. At that time, all outstanding borrowings of $10.0 million under the ESTE Credit Agreement were repaid and $0.5 million of remaining unamortized deferred financing costs were expensed and included in Write-off of deferred financing costs in the Consolidated Statements of Operations.  

On May 9, 2017, EEH entered into the EEH Credit Agreement.

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The borrowing base under the EEH Credit Agreement is $185.0 million and is subject to redetermination on or about November 1st and May 1st of each year. The amounts borrowed under the EEH Credit Agreement bear annual interest rates at either (a) LIBOR plus 2.25% to 3.25% or (b) the prime lending rate of Bank of Texas plus 1.25% to 2.25%, depending on the amounts borrowed under the EEH Credit Agreement. Principal amounts outstanding under the EEH Credit Agreement are due and payable in full at maturity on May 9, 2022. All of the obligations under the EEH Credit Agreement, and the guarantees of those obligations, are secured by substantially all of EEH’s assets. Additional payments due under the EEH Credit Agreement include paying a commitment fee of 0.50% per year to the Lenders in respect of the unutilized commitments thereunder, as well as certain other customary fees.

The EEH Credit Agreement contains a number of covenants that, among other things, restrict, subject to certain exceptions, EEH’s ability to incur additional indebtedness, create liens on assets, make investments, enter into sale and leaseback transactions, pay dividends and make distributions or repurchase its limited liability interests, engage in mergers or consolidations, sell certain assets, sell or discount any notes receivable or accounts receivable and engage in certain transactions with affiliates.

In addition, the EEH Credit Agreement requires EEH to maintain the following financial covenants: a current ratio of not less than 1.0 to 1.0 and a leverage ratio of not greater than 4.0 to 1.0. Leverage ratio means the ratio of (i) the aggregate debt of EEH and its consolidated subsidiaries as at the last day of the fiscal quarter (excluding any debt from obligations relating to non-cash losses under FASB ASC 815 as a result of changes in the fair market value of derivatives) to (ii) the product of EBITDAX for such fiscal quarter multiplied by four. The term “EBITDAX” means, for any period, the sum of consolidated net income for such period plus (a) the following expenses or charges to the extent deducted from consolidated net income in such period: (i) interest, (ii) taxes, (iii) depreciation, (iv) depletion, (v) amortization, (vi) non-cash losses under FASB ASC 815 as a result of changes in the fair market value of derivatives, (vii) exploration expenses, (viii) impairment expenses, and (ix) non-cash compensation expenses and minus (b) to the extent included in consolidated net income in such period, non-cash gains under FASB ASC 815 as a result of changes in the fair market value of derivatives.

The EEH Credit Agreement contains customary affirmative covenants and defines events of default to include failure to pay principal or interest, breach of covenants, breach of representations and warranties, insolvency, judgment default, and if Frank A. Lodzinski ceases to serve and function as Chief Executive Officer of EEH and the majority of the Lenders do not approve of Mr. Lodzinski’s successor. Upon the occurrence and continuance of an event of default, the Lenders have the right to accelerate repayment of the loans and exercise their remedies with respect to the collateral. As of December 31, 2017, EEH was in compliance with these covenants under the EEH Credit Agreement.

Uplisting of Class A Common Stock

On May 8, 2017, the Board approved (i) the transfer of the listing of the Common Stock from the NYSE American to the NYSE, and (ii) the voluntary delisting of the Common Stock from the NYSE American. In connection with the closing of the Bold Transaction, all of the outstanding Common Stock was converted into Class A Common Stock, on a one-for-one basis. The Class A Common Stock began trading on the NYSE on May 10, 2017. The ticker symbol for the Class A Common Stock is “ESTE.”

Closing of Denver Office

On July 31, 2017, we closed our Denver office and provided severance to our employees working there.

Class A Common Stock Offering

In October 2017, Earthstone completed a public offering of 4,500,000 shares of Class A Common Stock, at a public offering price of $9.25 per share, receiving net proceeds of $39.4 million, after deducting underwriters’ fees and offering expenses of $2.4 million. The net proceeds were used to repay outstanding indebtedness under the EEH Credit Agreement.

Bakken Sale

In December 2017, we closed the Bakken Sale for a net cash consideration of approximately $26.4 million. The sale resulted in a net gain of approximately $3.0 million recorded in Gain on sale of oil and gas properties in the Consolidated Statements of Operations. The effective date of the sale was December 1, 2017.  The net proceeds were used to repay $25.0 million of outstanding borrowings under the EEH Credit Agreement and the remaining $1.4 million was retained in cash for current operating funds.

Divestiture of Non-Core Assets

During 2017, we sold certain non-core properties for a total cash consideration of approximately $7.5 million, while eliminating approximately $4.0 million of future abandonment obligations. The sales resulted in a net gain of approximately $6.1 million recorded in Gain on sale of oil and gas properties in the Consolidated Statements of Operations.

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Results of Operations

Year ended December 31, 2017, compared to the year ended December 31, 2016

 

 

NM – Not meaningful

Oil revenues

For the year ended December 31, 2017, oil revenues increased by approximately $54.2 million or 158% relative to the comparable period in 2016. Of the increase, approximately $8.2 million was attributable to an increase in our realized price and $46.0 million was attributable to increased volume. Our average realized price per Bbl increased from $39.13 for the year ended December 31, 2016 to $48.43 or 24% for the year ended December 31, 2017. We had a net increase in the volume of oil sold of 950 MBbls or 108%, primarily due to the Midland Basin properties we acquired in the Bold Transaction.

Natural gas revenues

For the year ended December 31, 2017, natural gas revenues increased by $3.7 million or 74% relative to the comparable period in 2016. Of the increase, approximately $0.8 million was attributable to an increase in our realized price and $2.9 million was attributable to increased volume. Our average realized price per Mcf increased from $2.32 for the year ended December 31, 2016 to $2.69 or 16% for the year ended December 31, 2017. The total volume of natural gas produced and sold increased 1,089 MMcf or 50% primarily due to the Midland Basin properties we acquired in the Bold Transaction.

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Natural gas liquids revenues

For the year ended December 31, 2017, natural gas liquids revenues increased by $7.9 million or 276% relative to the comparable period in 2016. Of the increase, approximately $2.0 million was attributable to an increase in our realized price and $5.9 million was attributable to increased volume. The volume of natural gas liquids produced and sold increased by 276 MBbls or 123%, primarily due to the Midland Basin properties we acquired in the Bold Transaction.

Lease operating expense (“LOE”)

LOE includes all costs incurred to operate wells and related facilities for both operated and non-operated properties. In addition to direct operating costs such as labor, repairs and maintenance, re-engineering and workovers, equipment rentals, materials and supplies, fuel and chemicals, LOE includes product marketing and transportation fees, insurance, ad valorem taxes and overhead charges provided for in operating agreements.

LOE increased by $4.6 million or 30% for the year ended December 31, 2017 relative to the comparable period in 2016, primarily due to costs to operate the producing assets acquired in the Bold Transaction and added from drilling and completion operations that were not present in the prior year period.

Severance taxes

Severance taxes for the year ended December 31, 2017 increased by $3.9 million or 176% relative to the comparable period in 2016, primarily due to the increase in oil and natural gas prices. However, as a percentage of revenues from oil, natural gas, and natural gas liquids, severance taxes remained flat when compared to the prior year period.

Rig idle and contract termination expense

 

We incurred rig idle and termination expenses of $5.1 million during the year ended December 31, 2016. In July 2016, we entered into an agreement with a rig contractor to terminate our contract with the contractor. Per the terms of the agreement, a termination fee for the remaining commitment on the contract was due and the termination fees were retroactively applied to January 2016, when we suspended drilling and temporarily idled the drilling rig. In connection with the termination, we issued a three-year amortizing promissory note with a principal amount of $5.1 million, which was equivalent to the idle charges and contract termination fee.

Impairment

As a result of significant forward commodity price declines, as described below in Liquidity and Capital Resources, Commodity Prices, and the recording of certain acreage expirations, we recognized $72.2 million of non-cash asset impairments during the year ended December 31, 2017 that have negatively impacted our results of operations and equity. These impairments consisted of $63.1 million to our proved oil and natural gas properties and $9.1 million to our unproved oil and natural gas properties, primarily to our properties located in the Eagle Ford Trend of south Texas. See Note 6. Oil and Natural Gas Properties in the Notes to Consolidated Financial Statements for a discussion of how impairments are measured.

Depreciation, depletion and amortization (“DD&A”)

 

DD&A increased for the year ended December 31, 2017 by $11.0 million, or 42% relative to the comparable period in 2016, due to the addition of the assets acquired in the Bold Transaction and the Lynden Arrangement to the depletable base, as well as increased production volumes.

General and administrative expense (“G&A”)

These expenses consist primarily of employee remuneration, professional and consulting fees and other overhead expenses. G&A increased by $11.1 million for the year ended December 31, 2017 relative to the comparable period in 2016, primarily due to both the retention of certain employees of Bold, as well as the payment and accrual of transition and severance totaling approximately $1.1 million to certain Bold and Denver office employees. Additionally, legal expenses increased due to litigation described in Note 15. Commitments and Contingencies in the Notes to Consolidated Financial Statements.

Stock-based compensation

Stock-based compensation includes the expense associated with grants under the 2014 Plan of restricted stock units (“RSUs”) to employees and non-employee directors. Stock-based compensation was $6.6 million for the year ended December 31, 2017, as compared to $3.3 million in the prior year. However, the 2017 period is not comparable to the prior year period as the initial grant was made on May 20, 2016. The $3.3 million increase in stock-based compensation was primarily due to a $1.9 million increase during the current period due to the smaller amortization period beginning May 20, 2016 in the prior year and $1.4 million due to the 2017 grants.

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Transaction costs

Transaction costs consist primarily of financial advisory, professional and consulting fees associated with the Bold Transaction.

Interest expense, net

Interest expense includes commitment fees, amortization of deferred financing costs, and interest on outstanding indebtedness. Interest expense for the year ended December 31, 2017 was $2.7 million compared to $1.3 million for the comparable period in 2016. The $1.4 million increase in interest expense was primarily due to increased borrowings during the current period.

Gain on sale of oil and gas properties

During the year ended December 31, 2017, we sold all of our oil and natural gas leases, oil and natural gas wells and associated assets located in the Williston Basin in North Dakota.  We also sold certain of our non-core oil and natural gas properties in Texas, Montana, Oklahoma and North Dakota. In connection with these sales, we recorded gains totaling $9.1 million. See Note 3. Acquisitions and Divestitures in the Notes to Consolidated Financial Statements.

Loss on derivative contracts, net

For the year ended December 31, 2017, we recorded a net loss on derivative contracts of $8.0 million, consisting of net realized losses on settlements of $0.7 million and unrealized mark-to-market losses of $7.3 million. For the year ended December 31, 2016, we recorded a net loss on derivative contracts of $6.6 million, consisting of net realized gains on settlements of $3.2 million and unrealized mark-to-market losses of $9.8 million.

Income tax benefit (expense)

Following the closing of the Bold Transaction, we continue to record an income tax provision consistent with our status as a corporation. Our corporate structure requires the filing of two separate consolidated U.S. Federal income tax returns and one Canadian income tax return resulting from the Lynden Arrangement that includes Lynden US, Earthstone, and Lynden Corp. As such, taxable income of Earthstone cannot be offset by tax attributes, including net operating losses, of Lynden US, nor can taxable income of Lynden US be offset by tax attributes of Earthstone. Following the Bold Transaction, Earthstone and Lynden US record a tax provision, respectively, for their share of the book income or loss of EEH, net of the noncontrolling interest, as well as any standalone income or loss generated by each company. As EEH is treated as a partnership for U.S. Federal income tax purposes, it is not subject to income tax at the federal level and only recognizes the Texas Margin Tax.

During the year ended December 31, 2017, we recorded a total tax benefit of $16.4 million which is primarily driven by the change in valuation allowance associated with the Bold Transaction. For Lynden US, we recorded an income tax benefit of $8.6 million, of which $4.8 million related to the reduction of that amount in Lynden US’s deferred tax liability resulting from the federal corporate income tax rate reduction to 21% as described below. Additionally, we recorded an income tax benefit for Earthstone of $7.7 million which resulted from a change in assessment of the realization of its net deferred tax assets due to the deferred tax liability that was recorded with respect to its investment in EEH as part of the Bold Transaction as an adjustment to Additional paid-in capital within the Consolidated Balance Sheets. Additionally, Earthstone recorded income tax expense of $12.6 million related to the reduction of that amount in its deferred tax asset resulting from the federal corporate income tax rate reduction to 21% as described below, which was fully offset by the reduction in its valuation allowance for that amount because the future realization of such loss cannot be reasonably assured and is subject to a full valuation allowance.

On December 22, 2017, the United States enacted tax reform legislation commonly known as the TCJA, resulting in significant modifications to existing law. Our consolidated financial statements for the year ended December 31, 2017, reflect certain effects of the TCJA, which includes a reduction in our corporate tax to 21%. Consistent with Staff Accounting Bulletin No. 118 issued by the SEC, which provides for a measurement period of one year from the enactment date to finalize the accounting for effects of the TCJA, the Company provisionally recorded income tax expense of $7.8 million related to the TCJA. In accordance with SEC guidance, provisional amounts may be refined as a result of additional guidance from, and interpretations by, U.S. regulatory and standard-setting bodies, and changes in assumptions. In the subsequent period, provisional amounts will be adjusted for the effects, if any, of interpretative guidance issued after December 31, 2017, by the U.S. Department of the Treasury. The effects of the TCJA may be subject to changes for items that were previously reported as provisional amounts, as well as any element of the TCJA for which a provisional estimate could not be made, and such changes could be material.

The Company has made provisional computations of the impact of the TCJA as provided for under SAB 118, including transition tax on the mandatory deemed repatriation of foreign earnings and executive compensation limitations under Internal Revenue Code Section 162(m), among others. The Internal Revenue Service is expected to issue additional guidance clarifying provisions of the Act. As additional guidance is issued one or more of the provisional amounts may change.

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Year ended December 31, 2016 compared to the year ended December 31, 2015

 

NM – Not meaningful

Oil revenues

For the year ended December 31, 2016, oil revenues decreased by approximately $5.5 million or 14% relative to the comparable period in 2015. Of the decrease, approximately $4.5 million was attributable to a decrease in our realized price and $1.0 million was attributable to decreased volume. Our average realized price per Bbl decreased from $44.09 for the year ended December 31, 2015 to $39.13 or 11% for the year ended December 31, 2016. We had net decrease in the volume of oil sold of 26 MBbls. The Midland Basin properties we acquired in the Lynden Arrangement provided an additional 139 MBbls and our southern Gonzales and northern Karnes county assets that we acquired and began development on provided an additional 56 MBbls.  These increases however, were offset by declines on our operated Eagle Ford properties of 197 MBbls, our non-operated Eagle Ford properties of 6 MBbls and Bakken/Three Forks properties of 10 MBbls. The remaining volume decrease was due to normal production declines and variability in sales volumes on our other properties mainly in Texas and North Dakota.

Natural gas revenues

For the year ended December 31, 2016, natural gas revenues decreased by $0.4 million or 8% relative to the comparable period in 2015. Substantially all of the $0.4 million decrease was attributable to the decrease in our realized price. Our average realized price per Mcf decreased from $2.55 for the year ended December 31, 2015 to $2.32 or 9% for the year ended December 31, 2016. The total volume of natural gas produced and sold remained relatively consistent and increased by only 28 MMcf in total.

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Natural gas liquids revenues

For the year ended December 31, 2016, natural gas liquids revenues increased by $0.7 million or 33% relative to the comparable period in 2015. Substantially all of the $0.7 million increase was attributable to the increase in volumes produced and sold. The volume of natural gas liquids produced and sold increased by 49 MBbls or 28%. The Midland Basin properties we acquired in the Lynden Arrangement and our southern Gonzales and northern Karnes county assets that we acquired and began development on provided an additional 72 MBbls. These increases were primary offset by declines on our non-operated Eagle Ford property.

Lease operating expense

LOE decreased by $0.4 million or 2% for the year ended December 31, 2016 relative to the comparable period in 2015. The decrease was due to our continued focus on reducing operating costs, economies of scale on our operated Eagle Ford property, and a decrease in the cost of oil field services in general.

Severance taxes

Severance taxes for the year ended December, 2016 decreased by $0.4 million or 15% relative to the comparable period in 2015, primarily due to the decline in oil and natural gas prices. As a percentage of revenues from oil, natural gas, and natural gas liquids, severance taxes remained relative flat and increased by only 1% due to the mix of production and revenues.

Rig idle and contract termination expense

We incurred rig idle and termination expenses of $5.1 million during the year ended December 31, 2016. In July 2016, we entered into an agreement with a rig contractor to terminate our contract with the contractor. Per the terms of the agreement, a termination fee for the remaining commitment on the contract was due and the termination fees were retroactively applied to January 2016, when we suspended drilling and temporarily idled the drilling rig. In connection with the termination, we issued a three-year amortizing promissory note with a principal amount of $5.1 million, which was equivalent to the idle charges and contract termination fee.

Impairment

As a result of large commodity price declines and in spite of our operating achievements, we recognized $24.3 million of noncash asset impairments in 2016 that negatively impacted our results of operations and equity. The impairments recorded in 2016 consisted of $3.9 million to unproved properties, $2.9 million to proved properties and $17.5 million to goodwill.

Depreciation, depletion and amortization (“DD&A”)

DD&A decreased for the year ended December 31, 2016 by $5.3 million, or 17% relative to the comparable period in 2015, due to lower production volumes and reduced net book value in the 2016 period as a result of the significant impairments recognized at the end of 2015. The reserve decreases that lead to the impairments were primarily attributable to lower average oil and natural gas prices in 2016.

General and administrative expense (“G&A”)

G&A decreased by $0.3 million for the year ended December 31, 2016 relative to the comparable period in 2015. The decrease was primarily due to salary and benefits reductions taken during 2016.

Stock-based compensation

For the year ended December 31, 2016 we recognized expense of $3.3 million related to the RSU grants. The comparable prior period had no stock-based compensation expense since there were not any previously granted RSUs or other equity-based compensation granted.

Transaction costs

Transaction costs consist primarily of professional and consulting fees associated with the Bold Transaction and the Lynden Arrangement.

Interest expense, net

Interest expense for the year ended December 31, 2016 was $1.3 million compared to $0.7 million for the comparable period in 2015. The $0.6 million increase in interest expense was due to higher amortization of deferred financing costs and increased fees due to a larger credit facility.

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(Loss) gain on derivative contract, net

For the ended December 31, 2016, we recorded a net loss on derivative contracts of $6.6 million, consisting of net realized gains on settlements of $3.2 million and unrealized mark-to-market losses of $9.8 million. For the ended December 31, 2015, we recorded a net gain on derivative contracts of $6.4 million, consisting of net realized gains on settlements of $6.3 million and unrealized mark-to-market gains of $0.1 million. The primary reason for the current period loss as compared to the prior year gain is due to in improved commodity price environment in the latter part of 2016.

Income tax (expense) benefit

For the year ended December 31, 2016, we recorded $0.5 million of income tax expense related to Lynden Corp. Our corporate structure requires the filing of two separate consolidated U.S. Federal income tax returns. Taxable income of Earthstone, excluding the Lynden Corp. subsidiaries cannot be offset by tax attributes, including net operating losses of the Lynden Corp. subsidiaries, nor can taxable income of the Lynden Corp. subsidiaries be offset by tax attributes of Earthstone, excluding the Lynden Corp. subsidiaries. Excluding the Lynden Corp. subsidiaries, we have recorded significant income tax benefits in 2016 and 2015 resulting from property impairments which has resulted in a deferred tax asset. Because the future realization of this deferred tax asset could not be assured, we recorded a valuation allowance against our deferred tax asset of $12.2 million and $23.8 million in years ended December 31, 2016 and 2015, respectively.

Liquidity and Capital Resources

With the Bold Transaction, we acquired significant undeveloped acreage and future drilling locations. Drilling horizontal wells, generally consisting of 7,500 to 10,000-foot lateral lengths, in the Midland Basin is capital intensive. At December 31, 2017, we had approximately $23.0 million in cash and $160.0 million in unused borrowing capacity under the EEH Credit Agreement for a total of $183.0 million in liquidity. We currently estimate 2018 capital expenditures to be approximately $170.0 million, which assumes an approximate 20 well program running one rig for our operated acreage in the Midland Basin and an approximate 10 well program for our operated Eagle Ford acreage as well as some activity for our non-operated Midland Basin properties and land and infrastructure activities. We likely will outspend our cash flows provided by operating activities over at least the next twelve months from the date of this report based on current assumptions; however, we believe we will have sufficient liquidity with cash flows from operations and borrowings under the EEH Credit Agreement for the next 12 months to meet our cash requirements. We will continue to evaluate and prepare operationally for the possible deployment of a second rig in our operated Midland Basin acreage.  

We expect to finance future acquisition and development activities through available working capital, cash flows from operating activities, borrowings under the EEH Credit Agreement, various means of corporate and project financing, assuming we can access debt and equity markets. In addition, we may continue to partially finance our drilling activities through the sale of participating rights to industry partners or financial institutions, and we could structure such arrangements on a promoted basis, whereby we may earn working interests in reserves and production greater than our proportionate share of capital costs.

Cash Flows from Operating Activities

Cash flows provided by operating activities for the year ended December 31, 2017 were $51.0 million compared to $1.7 million for the year ended December 31, 2016. The increase in operating cash flows from the prior period was primarily due to changes in our working capital resulting from commodity price volatility and the producing assets acquired in the Bold Transaction and the Lynden Arrangement. We believe we have sufficient liquidity and capital resources to execute our business plan over the next 12 months and for the foreseeable future.

We had working capital, defined as Total current assets less Total current liabilities, as set forth in our Consolidated Balance Sheets, as a deficit of $21.8 million as of December 31, 2017 compared to a deficit of $11.5 million as of December 31, 2016. The working capital deficit, as defined above, is a result of the two-step drilling and completion process. Typically, we will drill numerous wells per pad and, once all the wells are drilled, they are completed and begin production. This process inherently involves timing differences between ultimate cash outflows and cash inflows.

Cash Flows from Investing Activities

Cash flows used in investing activities for the year ended December 31, 2017 and 2016 were $86.3 million and $59.9 million, respectively. Cash flows used in investing activities for the year ended December 31, 2017 included $55.6 million required to complete the Bold Transaction and $65.3 million in capital expenditures primarily related to the drilling and completion of wells in the Midland Basin on acreage acquired in the Bold Transaction, offset by $34.7 million in proceeds from the divestiture of certain non-core assets. Cash flows used in investing activities for the year ended December 31, 2016 related primarily to the cash required to complete the Lynden Arrangement.

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Cash Flows from Financing Activities

Cash flows provided by financing activities for the year ended December 31, 2017 were $48.1 million which consisted primarily of borrowings under the EEH Credit Agreement which were used to repay all outstanding borrowings under Bold’s credit agreement assumed by EEH in the Bold Transaction and proceeds from the Class A Common Stock offering completed in October 2017. Cash flows provided by financing activities for the year ended December 31, 2016 were $45.1 million which consisted primarily of proceeds from the common stock offering completed in June 2016.

Capital Expenditures

We have set our 2018 capital budget, which currently assumes a one-rig program for our operated acreage in the Midland Basin and a 10 well program for our operated Eagle Ford acreage. We will continue to evaluate and prepare operationally for the possible deployment of a second rig in our operated Midland Basin acreage in the latter half of 2018. Our anticipated capital expenditures for 2018 are currently estimated at $170 million.

Our accrual basis capital expenditures for the years ended December 31, 2017, 2016 and 2015 were as follows:

 

Public Offering

In October 2017, we completed a public offering of 4,500,000 shares of Class A Common Stock, at a public offering price of $9.25 per share, receiving net proceeds of $39.4 million, after deducting underwriters’ fees and offering expenses of $2.2 million. The net proceeds from the offering were used to repay outstanding indebtedness under the EEH Credit Agreement.

Credit Agreement

In May 2017, in connection with the closing of the Bold Transaction, we became party to the EEH Credit Agreement. As of December 31, 2017, we had a $185.0 million borrowing base under the EEH Credit Agreement, of which $25.0 million was outstanding, bearing an annual interest rate of 3.7611%, resulting in an additional $160.0 million of borrowing base availability under the EEH Credit Agreement.

Impairments to Oil and Natural Gas Properties

During 2017, we recognized $72.2 million of non-cash asset impairments that negatively impacted our results of operations and equity. These impairments consisted of $63.1 million to our proved oil and natural gas properties and $9.1 million to our unproved oil and natural gas properties, primarily to our properties located in the Eagle Ford Trend of south Texas. See Note 6. Oil and Natural Gas Properties in the Notes to Consolidated Financial Statements for a discussion of how impairments are measured.

Hedging Activities

As of December 31, 2017, we had hedged a total of 1,483 MBbls of 2018 oil production at an average price of $51.38/Bbl and 548 MBbls of 2019 oil production at an average price of $52.32/Bbl. As of December 31, 2017, we had hedged a total of 810,000 MMBtu of 2018 natural gas production at an average price of $3.066/MMBtu.

In January 2018, we entered into additional fixed price oil and natural gas swap agreements, hedging an additional 365 MBbls of 2019 oil production at a price of $58.38/Bbl and 1,552,000 MMBtu of 2018 natural gas production at a price of $2.96/MMBtu.

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Obligations and Commitments

We had the following contractual obligations and commitments as of December 31, 2017:

 

 

Environmental Regulations

Our operations are subject to risks normally associated with the exploration for and the production of oil and natural gas, including blowouts, fires, and environmental risks such as oil spills or natural gas leaks that could expose us to liabilities associated with these risks.

In our acquisition of existing or previously drilled well bores, we may not be aware of prior environmental safeguards, if any, that were taken at the time such wells were drilled or during such time the wells were operated. We maintain comprehensive insurance coverage that we believe is adequate to mitigate the risk of any adverse financial effects associated with these risks.

However, should it be determined that a liability exists with respect to any environmental cleanup or restoration, the liability to cure such a violation could still accrue to us. No claim has been made, nor are we aware of any liability which we may have, as it relates to any environmental cleanup, restoration, or the violation of any rules or regulations relating thereto.

Critical Accounting Policies and Estimates

Our discussion of financial condition and results of operations is based upon the information reported in our consolidated financial statements. The preparation of these statements requires us to make certain assumptions and estimates that affect the reported amounts of assets, liabilities, revenues and expenses as well as the disclosure of contingent assets and liabilities at the date of our financial statements. We base our assumptions and estimates on historical experience and other sources that we believe to be reasonable at the time. Actual results may vary from our estimates due to changes in circumstances, weather, politics, global economics, mechanical problems, general business conditions and other risks. We have outlined below certain of these policies as being of particular importance to the portrayal of our financial position and results of operations and which require the application of significant judgment by our management.

Oil and Natural Gas Properties

We use the successful efforts method of accounting for oil and natural gas operations. Under this method, costs to acquire oil and natural gas properties, drill successful exploratory wells, drill and equip development wells, and install production facilities are capitalized. Exploration costs, including unsuccessful exploratory wells, geological and geophysical are charged to operations as incurred. Depreciation, depletion and amortization of the leasehold and development costs that are capitalized for proved oil and natural gas properties are computed using the units-of-production method, at the field level, based on total proved reserves and proved developed reserves, respectively, as estimated by independent petroleum engineers. Oil and natural gas properties are periodically assessed for impairment whenever changes in facts and circumstances indicate a possible significant deterioration in the future cash flows expected to be generated by an asset group, but at least annually. Individual assets are grouped for impairment purposes at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets, generally on a field-by-field basis. All of our properties are located within the continental United States.

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Oil and Natural Gas Reserve Quantities

Reserve quantities and the related estimates of future net cash flows affect our periodic calculations of depletion, impairment of our oil and natural gas properties, and asset retirement obligations. Proved oil and natural gas reserves are the estimated quantities of oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future periods from known reservoirs under existing economic and operating conditions. Reserve quantities and future cash flows included in this report are prepared in accordance with guidelines established by the SEC and the Financial Accounting Standards Board (“FASB”). The accuracy of our reserve estimates is a function of:

Our proved reserves information included in this report is based on estimates prepared by our independent petroleum engineers, CG&A. The independent petroleum engineers evaluated 100% of our estimated proved reserve quantities and their related future net cash flows as of December 31, 2017. Estimates prepared by others may be higher or lower than our estimates. Because these estimates depend on many assumptions, all of which may differ substantially from actual results, reserve estimates may be different from the quantities of oil and natural gas that are ultimately recovered. We make revisions to reserve estimates throughout the year as additional information becomes available. We make changes to depletion rates, impairment calculations, and asset retirement obligations in the same period that changes to reserve estimates are made.

Depreciation, Depletion and Amortization

Our rate of recording DD&A is dependent upon our estimates of total proved and proved developed reserves, which estimates incorporate various assumptions and future projections. If the estimates of total proved or proved developed reserves decline, the rate at which we record DD&A expense increases, reducing our net income. Such a decline in reserves may result from lower commodity prices, which may make it uneconomic to drill for and produce higher cost fields. We are unable to predict changes in reserve quantity estimates as such quantities are dependent on the success of our exploitation and development program, as well as future economic conditions.

Impairment of Oil and Natural Gas Properties

We review the value of our oil and natural gas properties whenever management judges that events and circumstances indicate that the recorded carrying value of properties may not be recoverable. Impairments of producing properties are determined by comparing the pretax future net undiscounted cash flows to the net book value at the end of each period. If the net capitalized cost exceeds undiscounted future cash flows, the cost of the property is written down to “fair value,” which is determined based on expected future cash flows using discount rates commensurate with the risks involved, using prices and costs consistent with those used for internal decision making. Different pricing assumptions or discount rates could result in a different calculated impairment. We provide for impairments on significant undeveloped properties when we determine that the property will not be developed or a permanent impairment in value has occurred.

Asset Retirement Obligation

Our asset retirement obligations (“AROs”) consist primarily of estimated future costs associated with the plugging and abandonment of oil and natural gas wells, removal of equipment and facilities from leased acreage, and land restoration in accordance with applicable local, state and federal laws. The discounted fair value of an ARO liability is required to be recognized in the period in which it is incurred, with the associated asset retirement cost capitalized as part of the carrying cost of the oil and natural gas asset. The recognition of an ARO requires that management make numerous assumptions regarding such factors as the estimated probabilities, amounts and timing of settlements; the credit-adjusted risk-free rate to be used; inflation rates; and future advances in technology. In periods subsequent to the initial measurement of the ARO, we must recognize period-to-period changes in the liability resulting from the passage of time and revisions to either the timing or the amount of the original estimate of undiscounted cash flows. Increases in the ARO liability due to passage of time impact net income as accretion expense. The related capitalized cost, including revisions thereto, is charged to expense through DD&A over the life of the field.

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Derivative Instruments and Hedging Activity

We are exposed to certain risks relating to our ongoing business operations, such as commodity price risk. Derivative contracts are utilized to economically hedge our exposure to price fluctuations and reduce the variability in our cash flows associated with anticipated sales of future oil and natural gas production. We follow FASB ASC Topic 815, Derivatives and Hedging, to account for our derivative financial instruments. We do not enter into derivative contracts for speculative trading purposes. It is our policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive. We did not post collateral under any of these contracts.

Our crude oil and natural gas derivative positions consist of swaps. Swaps are designed so that we receive or make payments based on a differential between fixed and variable prices for crude oil and natural gas. We have elected to not designate any of our derivative contracts for hedge accounting. Accordingly, we record the net change in the mark-to-market valuation of these derivative contracts, as well as all payments and receipts on settled derivative contracts, in “(Loss) gain on derivative contracts, net” on the Consolidated Statements of Operations. All derivative contracts are recorded at fair market value and are included in the Consolidated Balance Sheets as assets or liabilities.

Income Taxes and Uncertain Tax Positions

We are a U.S. company operating primarily in Texas, as of December 31 2017, as well as one foreign legal entity, Lynden Corp, which is a Canadian company. Consequently, our tax provision is based upon the tax laws and rates in effect in the applicable jurisdiction in which our operations are conducted and income is earned. The income tax rates imposed and methods of computing taxable income in these jurisdictions vary. Therefore, as a part of the process of preparing the consolidated financial statements, we are required to estimate the income taxes in each of these jurisdictions. This process involves estimating the actual current tax exposure together with assessing temporary differences resulting from differing treatment of items, such as depreciation, amortization and certain accrued liabilities for tax and accounting purposes. Our effective tax rate for financial statement purposes will continue to fluctuate from year to year as our operations are conducted in different taxing jurisdictions.

Following the closing of the Bold Transaction, we continue to record an income tax provision consistent with our status as a corporation. Our corporate structure requires the filing of two separate consolidated U.S. Federal income tax returns and one Canadian income tax return resulting from the Lynden Arrangement that includes Lynden US, Earthstone, and Lynden Corp. As such, taxable income of Earthstone cannot be offset by tax attributes, including net operating losses, of Lynden US, nor can taxable income of Lynden US be offset by tax attributes of Earthstone. Following the Bold Transaction, Earthstone and Lynden US record a tax provision, respectively, for their share of the book income or loss of EEH, net of the noncontrolling interest, as well as any standalone income or loss generated by each company. As EEH is treated as a partnership for U.S. Federal income tax purposes, it is not subject to income tax at the federal level and only recognizes the Texas Margin Tax.

Our deferred tax expense or benefit represents the change in the balance of deferred tax assets or liabilities reported in our Consolidated Balance Sheets. Valuation allowances are established to reduce deferred tax assets when it is more likely than not that some portion or all of the deferred tax assets will not be realized. At December 31, 2017 and 2016, the Company has recorded a valuation allowance for its deferred tax assets in the Consolidated Balance Sheets.  

We apply the accounting standards related to uncertainty in income taxes. This accounting guidance clarifies the accounting for uncertainties in income taxes by prescribing a minimum recognition threshold that a tax position is required to meet before being recognized in the consolidated financial statements. It requires that we recognize in the consolidated financial statements the financial effects of a tax position, if that position is more likely than not of being sustained upon examination, including resolution of any appeals or litigation processes, based upon the technical merits of the position. It also provides guidance on measurement, classification, interest, penalties and disclosure. Our tax positions related to our pass-through status and state income tax liability, including deductibility of expenses, have been reviewed by our management and they believe those positions would more likely than not be sustained upon examination. Accordingly, we have not recorded an income tax liability for uncertain tax positions at December 31, 2017, 2016 or 2015.

On December 22, 2017, the United States enacted tax reform legislation commonly known as the TCJA, resulting in significant modifications to existing law. Our consolidated financial statements for the year ended December 31, 2017, reflect certain effects of the TCJA, which includes the federal corporate income tax rate reduction to 21%. Consistent with Staff Accounting Bulletin No. 118 issued by the SEC, which provides for a measurement period of one year from the enactment date to finalize the accounting for effects of the TCJA, the Company provisionally recorded income tax expense of $7.8 million related to the TCJA. In accordance with SEC guidance, provisional amounts may be refined as a result of additional guidance from, and interpretations by, U.S. regulatory and standard-setting bodies, and changes in assumptions. In the subsequent period, provisional amounts will be adjusted for the effects, if any, of interpretative guidance issued after December 31, 2017, by the U.S. Department of the Treasury. The effects of the TCJA may be subject to changes for items that were previously reported as provisional amounts, as well as any element of the TCJA for which a provisional estimate could not be made, and such changes could be material.

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The Company has made provisional computations of the impact of the TCJA as provided for under SAB 118, including transition tax on the mandatory deemed repatriation of foreign earnings and executive compensation limitations under Internal Revenue Code Section 162(m), among others. The Internal Revenue Service is expected to issue additional guidance clarifying provisions of the Act. As additional guidance is issued one or more of the provisional amounts may change.

Revenue Recognition

We predominantly derive our revenue from the sale of produced oil, natural gas and natural gas liquids. Revenues are recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, title has been transferred, and collectability is probable. We receive payment from one to three months after delivery. At the end of each quarter, we estimate the amount of production delivered to purchasers and the price we will receive. Variances between our estimated revenue and actual payment are recorded in the month the payment is received. Historically, however, differences have been insignificant.

Accounting for Business Combinations

Our business has grown substantially through acquisitions, and our business strategy is to continue to pursue acquisitions as opportunities arise. We have accounted for all of our business combinations to date using the purchase method.

Under the purchase method of accounting, a business combination is accounted for at a purchase price based upon the fair value of the consideration given. The assets and liabilities acquired are measured at their fair value including the recognition of acquisition-related costs that are separate from the acquired net assets. The purchase price is allocated to the assets and liabilities based upon these fair values. The excess of the cost of an acquired entity, if any, over the net amounts assigned to assets acquired and liabilities assumed is recognized as goodwill. The excess of the fair value of assets acquired and liabilities assumed over the cost of an acquired entity, if any, is allocated as a pro rata reduction of the amounts that otherwise would have been assigned to certain acquired assets.

Determining the fair values of the assets and liabilities acquired involves the use of judgment, since some of the assets and liabilities acquired do not have fair values that are readily determinable. Different techniques may be used to determine fair values, including market prices (where available), appraisals, and comparison to transactions for similar assets and liabilities, and present value of estimated future cash flows, among others. Since these estimates involve the use of significant judgment, they can change as new information becomes available.

Goodwill

We account for goodwill in accordance with FASB ASC Topic 350, Intangibles – Goodwill and Other. Goodwill represents the excess of the purchase price over the estimated fair value of the assets acquired net of the fair value of the liabilities assumed in an acquisition. ASC Topic 350 requires that goodwill be evaluated on an annual basis for impairment or more frequently if an event occurs or circumstances change that could potentially result in an impairment.

We conduct a qualitative goodwill impairment assessment by examining relevant events and circumstances which could have a negative impact on our goodwill such as, industry and market conditions, including commodity prices, costs factors, and other company specific events. If we conclude that it is not more likely than not that the fair value of a reporting unit is less than its carrying value, then we do not have to perform the two-step impairment test. If after assessing the totality of events or circumstances described, we determine that it is more likely than not that the fair value of a reporting unit is less than its carrying amount, the two-step goodwill test is performed. The two-step goodwill impairment test is also performed whenever events or changes in circumstances indicate that the carrying value may not be recoverable. If, after performing the two-step goodwill test, it is determined that the carrying value of goodwill is impaired, the amount of goodwill is reduced and a corresponding charge is made to earnings in the period in which the goodwill is determined to be impaired  

Noncontrolling Interest

We account for noncontrolling interest in accordance with FASB ASC Topic 810, Consolidation, which requires the recording of a noncontrolling interest component of Net income (loss), as well as a noncontrolling interest component within equity.   Noncontrolling interest represents third-party equity ownership of EEH and is presented as a component of equity in the Consolidated Balance Sheet as of December 31, 2017, as well as an adjustment to Net loss in the Consolidated Statement of Operations for the year ended December 31, 2017.

As of December 31, 2017, Earthstone and Lynden US held 43.3% of the outstanding membership interests in EEH while Bold Holdings, the noncontrolling party, held the remaining 56.7%. See further discussion in Note 8. Noncontrolling Interest in the Notes to Consolidated Financial Statements.

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Recently Issued Accounting Standards

See Note 2. Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements under Item 8 of this report for a discussion of recently issued accounting standards affecting us.

Item 7A.  Quantitative and Qualitative Disclosures About Market Risk

We are exposed to market risks associated with interest rate risks, commodity price risk and credit risk. We have established risk management processes to monitor and manage these market risks.

Commodity Price Risk, Derivative Instruments and Hedging Activity

We are exposed to various risks including energy commodity price risk. When oil, natural gas and natural gas liquids prices decline significantly our ability to finance our capital budget and operations may be adversely impacted. We expect energy prices to remain volatile and unpredictable. Our hedging activities consist of derivative instruments entered into in order to hedge against changes in oil and natural gas prices through the use of fixed price swap agreements. Swaps exchange floating price risk in the future for a fixed price at the time of the hedge.

In connection with the closing of the Bold Transaction on May 9 2017, all oil and natural gas derivative contracts were novated to EEH. We have entered into a series of derivative instruments to hedge a significant portion of our expected oil and natural gas production through December 31, 2019. Typically, these derivative instruments require payments to (receipts from) counterparties based on specific indices as required by the derivative agreements. Although not risk free, we believe these instruments reduce our exposure to oil and natural gas price fluctuations and, thereby, allow us to achieve a more predictable cash flow.

The following is a summary of our open oil and natural gas derivative contracts as of December 31, 2017:

 

In January 2018, we entered into additional fixed price oil and natural gas swap agreements, hedging an additional 365,000 Bbls of 2019 oil production at a price of $58.38/Bbl and 1,552,000 MMBtu of 2018 natural gas production at a price of $2.96/MMBtu.

Changes in fair value of commodity derivative instruments are reported in earnings in the period in which they occur. Our open commodity derivative instruments were in a net liability position with a fair value of $13.4 million at December 31, 2017. Based on the published commodity futures price curves for the underlying commodity as of December 31, 2017, a 10% increase in per unit commodity prices would cause the total fair value of our commodity derivative financial instruments to decrease by approximately $12.3 million to an overall net liability position of $25.7 million. A 10% decrease in per unit commodity prices would cause the total fair value of our commodity derivative financial instruments to increase by approximately $11.5 million to an overall net liability position of $1.9 million. There would also be a similar increase or decrease in (Loss) gain on derivative contracts, net in the Consolidated Statements of Operations.

Interest Rate Sensitivity

We are also exposed to market risk related to adverse changes in interest rates. Our interest rate risk exposure results primarily from fluctuations in short-term rates, which are based on LIBOR and the prime rate and may result in reductions of earnings or cash flows due to increases in the interest rates we pay on these obligations.

At December 31, 2017, the outstanding borrowings under the EEH Credit Agreement were $25.0 million bearing interest at rates described in Note 12. Long-Term Debt in the Notes to Consolidated Financial Statements. Fluctuations in interest rates will cause our annual interest costs to fluctuate. At December 31, 2017, the interest rate on borrowings under the EEH Credit Agreement was 3.7611% per year. If borrowings at December 31, 2017 were to remain constant, a 10% change in interest rates would impact our future cash flows by approximately $0.1 million per year.

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Disclosure of Limitations

Because the information above included only those exposures that existed at December 31, 2017, it does not consider those exposures or positions which could arise after that date. As a result, our ultimate realized gain or loss with respect to interest rate and commodity price fluctuations will depend on the exposures that arise during future periods.

Item 8.  Financial Statements and Supplementary Data

See Index to Consolidated Financial Statements and Supplementary Information on Page F-1.

Item 9.  Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Item 9A.  Controls and Procedures

Internal Control Over Financial Reporting

Evaluation of Disclosure Controls and Procedures

(a) Disclosure Controls and Procedures

We maintain disclosure controls and procedures that are designed to provide reasonable assurance that information required to be disclosed by us in the reports that we file or submit to the SEC under the Exchange Act, is recorded, processed, summarized and reported within the time periods specified by the SEC’s rules and forms, and that information is accumulated and communicated to our management, including our Chief Executive Officer and Principal Accounting Officer, as appropriate to allow timely decisions regarding required disclosure.

In accordance with Rules 13a-15(b) and 15d-15(b) under the Exchange Act, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Principal Accounting Officer, of the effectiveness of our disclosure controls and procedures (as defined by Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Annual Report on Form 10-K. As described below under paragraph (b) within Management’s Annual Report on Internal Control over Financial Reporting, our Chief Executive Officer and Principal Accounting Officer have concluded that, as of the end of the period covered by this Annual Report on Form 10-K, our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed by us in the reports that we file or submit to the SEC under the Exchange Act is recorded, processed, summarized and reported within the time periods specified by the SEC’s rules and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Principal Accounting Officer, as appropriate to allow timely decisions regarding required disclosure.

The audit report of our independent registered public accounting firm, which is included in this Annual Report on Form 10-K, expressed an unqualified opinion on our consolidated financial statements.

(b) Management’s Annual Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act. Our internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Our internal control over financial reporting includes those policies and procedures that:

While “reasonable assurance” is a high level of assurance, it does not mean absolute assurance. Because of its inherent limitations, internal control over financial reporting may not prevent or detect every misstatement and instance of fraud. Controls are susceptible to manipulation, especially in instances of fraud caused by collusion of two or more people. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

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Under the supervision and with the participation of our Chief Executive Officer and Principal Accounting Officer, our management conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2017. In making this evaluation, management used the Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). Based on the results of our evaluation, our management concluded that our internal control over financial reporting was effective, at the reasonable assurance level, as of December 31, 2017.

Our independent registered public accounting firm that audited our consolidated financial statements, has also issued its own audit report on the effectiveness of our internal control over financial reporting as of December 31, 2017, which is included herein.

(c) Changes in Internal Control over Financial Reporting

There have not been any changes in our internal control over financial reporting during the quarter ended December 31, 2017 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Shareholders

Earthstone Energy, Inc.

Opinion on internal control over financial reporting

We have audited the internal control over financial reporting of Earthstone Energy, Inc. (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2017, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017, based on criteria established in the 2013 Internal Control—Integrated Framework issued by COSO.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated financial statements of the Company as of and for the year ended December 31, 2017, and our report dated March 15, 2018 expressed an unqualified opinion on those financial statements.

Basis for opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Controls over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and limitations of internal control over financial reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ GRANT THORNTON LLP

Houston, Texas

March 15, 2018

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Item 9B.  Other Information

None.

PART III

Item 10. Directors, Executive Officers and Corporate Governance

The information required by this item is incorporated herein by reference to the 2018 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2017.

Item 11. Executive Compensation

The information required by this item is incorporated herein by reference to the 2018 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2017.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

The information required by this item is incorporated herein by reference to the 2018 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2017.

Item 13. Certain Relationships and Related Transactions, and Director Independence

The information required by this item is incorporated herein by reference to the 2018 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2017.

Item 14. Principal Accounting Fees and Services

The information required by this item is incorporated herein by reference to the 2018 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2017.

 

 

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PART IV

Item 15.  Exhibits, Financial Statements Schedules

 

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71

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72

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Item 16.  Form 10-K Summary

None.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

 

 

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

 

 

 

 

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EARTHSTONE ENERGY, INC.

Index to Consolidated Financial Statements and Supplementary Information

 

 

 

 

F-1

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 

Board of Directors and Shareholders

Earthstone Energy, Inc.

 

Opinion on the financial statements

We have audited the accompanying consolidated balance sheets of Earthstone Energy, Inc. (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2017 and 2016, the related consolidated statements of operations, equity,  and cash flows for each of the two years in the period ended December 31, 2017, and the related notes (collectively referred to as the “financial statements”).  In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2017, in conformity with accounting principles generally accepted in the United States of America.

 

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Company’s internal control over financial reporting as of December 31, 2017, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”), and our report dated March 15, 2018 expressed an unqualified opinion.

 

Basis for opinion

These financial statements are the responsibility of the Company’s management.  Our responsibility is to express an opinion on the Company’s financial statements based on our audits.  We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

 

We conducted our audits in accordance with the standards of the PCAOB.  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud.  Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks.  Such procedures included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements.  Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements.  We believe that our audits provide a reasonable basis for our opinion.

 

/s/ GRANT THORNTON LLP

 

We have served as the Company’s auditor since 2016.

 

Houston, Texas

March 15, 2018

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

F-2

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F-3

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 

Board of Directors and Stockholders

Earthstone Energy, Inc.

 

We have audited the accompanying consolidated statements of operations, equity, and cash flows of Earthstone Energy, Inc. and subsidiaries (formerly Oak Valley Resources, LLC) for the year ended December 31, 2015. These consolidated financial statements are the responsibility of the entity’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audit.

 

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall consolidated financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

 

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the results of operations and cash flows of Earthstone Energy, Inc. and subsidiaries (formerly Oak Valley Resources, LLC) for the year ended December 31, 2015, in conformity with accounting principles generally accepted in the United States of America.

 

/s/ Weaver and Tidwell, L.L.P.

 

Houston, Texas

March 11, 2016

 

 

 

F-4

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EARTHSTONE ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(In thousands, except share and per share amounts) 

 

 

The accompanying notes are an integral part of these consolidated financial statements.

F-5

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EARTHSTONE ENERGY, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except share and per share amounts)

 

 

The accompanying notes are an integral part of these consolidated financial statements.

 

 

F-6

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EARTHSTONE ENERGY, INC.

CONSOLIDATED STATEMENTS OF EQUITY

(In thousands, except share amounts)

 

 

The accompanying notes are an integral part of these consolidated financial statements.

 

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EARTHSTONE ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands) 

 

 

The accompanying notes are an integral part of these consolidated financial statements.

 

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EARTHSTONE ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

 

Note 1. – Organization and Basis of Presentation

Earthstone Energy, Inc., a Delaware corporation (“Earthstone” and together with its consolidated subsidiaries, the “Company”), is a growth-oriented independent oil and natural gas development and production company.  In addition, the Company is active in corporate mergers and the acquisition of oil and natural gas properties that have production and future development opportunities.  The Company’s operations are all in the up-stream segment of the oil and natural gas industry and all its properties are onshore in the United States.  

Earthstone is the sole managing member of Earthstone Energy Holdings, LLC, a Delaware limited liability company (together with its wholly-owned consolidated subsidiaries, “EEH”), with a controlling interest in EEH. Earthstone, together with its wholly-owned subsidiary, Lynden Energy Corp., a corporation organized under the laws of British Columbia (“Lynden Corp”), and Lynden Corp’s wholly-owned consolidated subsidiary, Lynden USA Inc., a Utah corporation (“Lynden US”) and also a member of EEH, consolidates the financial results of EEH and records a noncontrolling interest in the Consolidated Financial Statements representing the economic interests of EEH's members other than Earthstone and Lynden US.     

Certain prior period amounts have been reclassified to conform to current period presentation within the Consolidated Financial Statements. Prior period Re-engineering and workovers in the Consolidated Statements of Operations have been reclassified from its own line item and included in Lease operating expenses, within Operating Costs and Expenses, to conform to current period presentation. This reclassification had no effect on Loss from operations or any other subtotal in the Consolidated Statements of Operations.

Bold Contribution Agreement

On May 9, 2017, Earthstone completed a contribution agreement dated as of November 7, 2016 and as amended on March 21, 2017 (the “Bold Contribution Agreement”), by and among Earthstone, EEH, Lynden US, Lynden USA Operating, LLC, a Texas limited liability company (“Lynden Op”), Bold Energy Holdings, LLC, a Texas limited liability company (“Bold Holdings”), and Bold Energy III LLC, a Texas limited liability company (“Bold”). The purpose of the Bold Contribution Agreement was to provide for, among other things described below, the business combination between Earthstone and Bold, which owned significant developed and undeveloped oil and natural gas properties in the Midland Basin of Texas (the “Bold Transaction”).

The Bold Transaction was structured in a manner commonly known as an “Up-C.” Under this structure and the Bold Contribution Agreement, (i) Earthstone recapitalized its common stock into two classes – Class A common stock, $0.001 par value per share (the “Class A Common Stock”), and Class B common stock, $0.001 par value per share (the “Class B Common Stock”), and all of Earthstone’s existing outstanding common stock, $0.001 par value per share (the “Common Stock”), was recapitalized on a one-for-one basis for Class A Common Stock (the “Recapitalization”); (ii) Earthstone transferred all of its membership interests in Earthstone Operating, LLC, Sabine River Energy, LLC, EF Non-Op, LLC and Earthstone Legacy Properties, LLC (formerly Earthstone GP, LLC) and $36,071 in cash from the sale of Class B Common Stock to Bold Holdings (collectively, the “Earthstone Assets”) to EEH, in exchange for 16,791,296 membership units of EEH (the “EEH Units”); (iii) Lynden US transferred all of its membership interests in Lynden Op to EEH in exchange for 5,865,328 EEH Units; (iv) Bold Holdings transferred all of its membership interests in Bold to EEH in exchange for 36,070,828 EEH Units and purchased 36,070,828 shares of Class B Common Stock issued by Earthstone for $36,071; and (v) Earthstone granted an aggregate of 150,000 fully vested shares of Class A Common Stock under Earthstone’s 2014 Long-Term Incentive Plan, as amended (the “2014 Plan”), to certain employees of Bold. Each EEH Unit, together with one share of Class B Common Stock, are convertible into one share of Class A Common Stock. 

Upon closing of the Bold Transaction on May 9, 2017, Bold Holdings owned approximately 61.4% of the outstanding shares of Class A Common Stock, on a fully diluted, as converted basis. The EEH Units and the shares of Class B Common Stock issued to Bold Holdings were not registered under the Securities Act of 1933, as amended (the “Securities Act”), but were issued by EEH and Earthstone in reliance on the exemption provided under Section 4(a)(2) of the Securities Act.

On May 9, 2017, the closing sale price of the Class A Common Stock was $13.58 per share. On May 10, 2017, the Class A Common Stock was uplisted from the NYSE American, LLC (formerly the NYSE MKT) (the “NYSE American”) to the New York Stock Exchange (the “NYSE”) where it is listed under the symbol “ESTE.”

On May 9, 2017, in connection with the closing of the Bold Transaction, Earthstone, EnCap Investments L.P. (“EnCap”), Oak Valley Resources, LLC (“OVR”), and Bold Holdings entered into a voting agreement (the “Voting Agreement”), pursuant to which EnCap, OVR, and Bold Holdings agreed not to vote any shares of Class A Common Stock or Class B Common Stock held by them in favor of any action, or take any action that would in any way alter the composition of the board of directors of Earthstone (the “Board”) from its composition immediately following the closing of the Bold Transaction as long as the Voting Agreement is in effect. The Voting Agreement terminates on the earlier of (i) the fifth anniversary of the closing date of the Bold Contribution Agreement and (ii) the date upon which EnCap, OVR and Bold Holdings collectively own, of record and beneficially, less than 20% of Earthstone’s outstanding voting stock.

F-8

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EARTHSTONE ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

 

Pursuant to the terms of the Bold Contribution Agreement, at the closing of the Bold Transaction, Earthstone, Bold Holdings, and the unitholders of Bold Holdings entered into a registration rights agreement (the “Registration Rights Agreement”) relating to the shares of Class A Common Stock issuable upon the exchange of the EEH Units and Class B Common Stock held by Bold Holdings or its unitholders. In accordance with the Registration Rights Agreement, Earthstone filed a registration statement (the “Registration Statement”) with the Securities and Exchange Commission (the “SEC”) to permit the public resale of the shares of Class A Common Stock issued by Earthstone to Bold Holdings or its unitholders in connection with the exchange of Class B Common Stock and EEH Units in accordance with the terms of the First Amended and Restated Limited Liability Company Agreement of EEH (the “EEH LLC Agreement”). On October 18, 2017, the Registration Statement was declared effective by the SEC.

The Bold Transaction was recorded in accordance with Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 805, Business Combinations, and is consolidated in these financial statements in accordance with FASB ASC Topic 810, Consolidation, which requires the recording of a noncontrolling interest component of net income (loss), as well as a noncontrolling interest component within equity, including changes to additional paid-in capital to reflect the noncontrolling interest within equity in the Consolidated Balance Sheet as of December 31, 2017 at the noncontrolling interest’s respective membership interest in EEH.

 

Note 2. – Summary of Significant Accounting Policies

Principles of Consolidation

The consolidated financial statements include the accounts and balances of the Company and have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”). All intercompany accounts and transactions, including revenues and expenses, are eliminated in consolidation.

Use of Estimates

The preparation of the Company’s consolidated financial statements in conformity with GAAP requires the Company’s management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods then ended.

Estimated quantities of crude oil, natural gas and natural gas liquids reserves are the most significant of our estimates. All reserve data included in these Consolidated Financial Statements are based on estimates. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil, natural gas and natural gas liquids. There are numerous uncertainties inherent in estimating quantities of proved crude oil, natural gas and natural gas liquids reserves. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, reserve estimates may be different from the quantities of crude oil, natural gas and natural gas liquids that are ultimately recovered.

Other items subject to estimates and assumptions include, but are not limited to, the carrying amounts of property, plant and equipment, goodwill, asset retirement obligations, valuation allowances for deferred income tax assets, and valuation of derivative instruments. Management evaluates estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment. The volatility of commodity prices results in increased uncertainty inherent in such estimates and assumptions. See Supplemental Information on Oil and Gas Exploration and Production Activities (Unaudited).

Accounts Receivable

Accounts receivable include amounts due from crude oil, natural gas, and natural gas liquids purchasers, other operators for which the Company holds an interest, and from non-operating working interest owners. Accrued crude oil, natural gas, and natural gas liquids sales from purchasers and operators consist of accrued revenues due under normal trade terms, generally requiring payment within 60 days of production.

An allowance for doubtful accounts is established based on reviews of individual customer accounts, recent loss experience, current economic conditions, and other pertinent factors. Accounts deemed uncollectible are charged to the allowance.

Provisions for bad debts and recoveries on accounts previously charged off are added to the allowance. The Company routinely assesses the recoverability of all material trade receivables and other receivables to determine their collectability.  Allowance for uncollectible accounts receivable was $0.1 million at and $0.2 million at December 31, 2017 and 2016, respectively.

F-9

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EARTHSTONE ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

 

Derivative Instruments

The Company utilizes derivative instruments in order to manage exposure to commodity price risk associated with future oil and natural gas production. The Company recognizes all derivatives as either assets or liabilities, measured at fair value, and recognizes changes in the fair value of derivatives in current earnings. The Company has elected to not designate any of its positions under the hedge accounting rules. Accordingly, these derivative contracts are mark-to-market and any changes in the estimated values of derivative contracts held at the balance sheet date are recognized in (Loss) gain on derivative contracts, net in the Consolidated Statements of Operations as unrealized gains or losses on derivative contracts.  Realized gains or losses on derivative contracts are also recognized in (Loss) gain on derivative contracts, net in the Consolidated Statements of Operations.

Oil and Natural Gas Properties

The method of accounting for oil and natural gas properties determines what costs are capitalized and how these costs are ultimately matched with revenues and expenses. The Company uses the successful efforts method of accounting for oil and natural gas properties as prescribed by the SEC. For more information see Note 6. Oil and Natural Gas Properties.

Goodwill

Goodwill represents the excess of the purchase price of assets acquired over the fair value of those assets and is tested for impairment annually, or more frequently if events or changes in circumstances dictate that the carrying value of goodwill may not be recoverable. Such test includes an assessment of qualitative and quantitative factors. There were no impairments to Goodwill recorded in the year ended December 31, 2017. During the years ended December 31, 2016 and 2015, impairments to Goodwill of $17.5 million and $1.5 million, respectively, were recorded. For further discussion, see Note 7. Goodwill.

Noncontrolling Interest

Noncontrolling Interest represents third-party equity ownership of EEH and is presented as a component of equity in the Consolidated Balance Sheet as of December 31, 2017, as well as an adjustment to Net loss in the Consolidated Statement of Operations for the year ended December 31, 2017. As of December 31, 2017, Earthstone and Lynden US owned a 43.3% membership interest in EEH while Bold Holdings, the noncontrolling third party, owned the remaining 56.7%. See further discussion in Note 8. Noncontrolling Interest.

Segment Reporting

Operating segments are defined under FASB ASC Topic 280, Segment Reporting, as components of an enterprise that (i) engage in activities from which it may earn revenues and incur expenses (ii) for which separate operational financial information is available and is regularly evaluated by the chief operating decision maker for the purpose of allocating resources and assessing performance.

Based on our organization and management, we have only one reportable operating segment, which is oil and natural gas exploration and production. We consider drilling rig services ancillary to our oil and natural gas exploration and producing activities and manage these services to support such activities.

Asset Retirement Obligations

Asset retirement obligations associated with the retirement of long-lived assets are recognized as liabilities with an increase to the carrying amounts of the related long-lived assets in the period incurred. The cost of the asset, including the asset retirement cost, is depreciated over the useful life of the asset. Asset retirement obligations are recorded at estimated fair value, measured by reference to the expected future cash outflows required to satisfy the retirement obligations discounted at the Company’s credit-adjusted risk-free interest rate. Accretion expense is recognized over time as the discounted liabilities are accreted to their expected settlement value. If estimated future costs of asset retirement obligations change, an adjustment is recorded to both the asset retirement obligations and the long-lived asset. Revisions to estimated asset retirement obligations can result from changes in retirement cost estimates, revisions to estimated inflation rates, and changes in the estimated timing of abandonment. For further discussion, see Note 13. Asset Retirement Obligations.

Business Combinations

The Company accounts for the acquisition of oil and gas properties not commonly controlled based on the requirements of FASB ASC Topic 805, which requires an acquiring entity to recognize the assets acquired and liabilities assumed at fair value under the acquisition method of accounting, provided such assets and liabilities qualify for acquisition accounting under the standard. The Company accounts for property acquisitions of proved developed oil and gas properties as business combinations.

F-10

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EARTHSTONE ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

 

Revenue Recognition

Oil, natural gas, and natural gas liquids revenues represent income from the production and delivery of oil, natural gas, and natural gas liquids, recorded net of royalties. Revenues are recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, title has been transferred, and collectability of the revenue is probable. The Company follows the sales method of accounting for gas imbalances. The Company had no significant gas imbalances as of December 31, 2017, 2016, or 2015.

Concentration of Credit Risk

Credit risk represents the actual or perceived financial loss that the Company would record if its purchasers, operators, or counterparties failed to perform pursuant to contractual terms.

The purchasers of the Company’s oil, natural gas, and natural gas liquids production consist primarily of independent marketers, major oil and natural gas companies and natural gas pipeline companies. Historically, the Company has not experienced any significant losses from uncollectible accounts. In 2017, three purchasers accounted for 18%, 14% and 14%, respectively, of the Company’s oil, natural gas, and natural gas liquids revenues.  In 2016, two purchasers accounted for 41% and 19%, respectively, of the Company’s oil, natural gas, and natural gas liquids revenues.  In 2015, one purchaser accounted for 62% of the Company’s oil, natural gas, and natural gas liquids revenues. No other purchaser accounted for 10% or more of the Company’s oil, natural gas, and natural gas liquids revenues during 2017, 2016, and 2015. Additionally, at December 31, 2017, three purchasers accounted for 20%, 13% and 12%, respectively, of the Company’s oil, natural gas and natural gas liquids receivables.  At December 31, 2016, two purchasers accounted for 28% and 12%, respectively, of the Company’s oil, natural gas, and natural gas liquids receivables. No other purchaser accounted for 10% or more of the Company’s oil, natural gas, and natural gas liquids receivables at December 31, 2017 and 2016.

The Company holds working interests in oil and natural gas properties for which a third party serves as operator. The operator sells the oil, natural gas, and NGLs to the purchaser, collects the cash, and distributes the cash to the Company. In 2017, 2016 and 2015, one operator distributed 10%, 19% and 12%, respectively, of the Company’s oil, natural gas and natural gas liquids revenues. No other operator accounted for 10% or more of the Company’s oil, natural gas, and natural gas liquids revenues during 2017, 2016, and 2015.

The derivative instruments of the Company are with a small number of counterparties and, from time-to-time, may represent material assets in the Consolidated Balance Sheets. At December 31, 2017 and 2016, the Company had no derivative contracts that were in a material asset position.

The Company regularly maintains its cash in bank deposit accounts. Balances held by the Company at its banks typically exceed Federal Deposit Insurance Corporation (“FDIC”) insurance coverage and, as a result, there is a concentration of credit risk related to the amounts of deposit in excess of FDIC insurance coverage.

Income Taxes

The Company is a U.S. company operating primarily in Texas, as of December 31, 2017, as well as one foreign legal entity, Lynden Corp, which is a Canadian company. Consequently, the Company’s tax provision is based upon the tax laws and rates in effect in the applicable jurisdiction in which its operations are conducted and income is earned. The income tax rates imposed and methods of computing taxable income in these jurisdictions vary. Therefore, as a part of the process of preparing the consolidated financial statements, the Company is required to estimate the income taxes in each of these jurisdictions. This process involves estimating the actual current tax exposure together with assessing temporary differences resulting from differing treatment of items, such as depreciation, amortization and certain accrued liabilities for tax and accounting purposes. The Company’s effective tax rate for financial statement purposes will continue to fluctuate from year to year as its operations are conducted in different taxing jurisdictions.

Following the closing of the Bold Transaction, the Company continues to record an income tax provision consistent with its status as a corporation. The Company’s corporate structure requires the filing of two separate consolidated U.S. Federal income tax returns and one Canadian income tax return resulting from Earthstone’s acquisition of Lynden Corp in May 2016 (the “Lynden Arrangement”) that includes Lynden US, Earthstone, and Lynden Corp. As such, taxable income of Earthstone cannot be offset by tax attributes, including net operating losses, of Lynden US, nor can taxable income of Lynden US be offset by tax attributes of Earthstone. Following the Bold Transaction, Earthstone and Lynden US record a tax provision, respectively, for their share of the book income or loss of EEH, net of the noncontrolling interest, as well as any standalone income or loss generated by each company. As EEH is treated as a partnership for U.S. Federal income tax purposes, it is not subject to income tax at the federal level and only recognizes the Texas Margin Tax.

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EARTHSTONE ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

 

The Company’s deferred tax expense or benefit represents the change in the balance of deferred tax assets or liabilities reported in the Consolidated Balance Sheets. Valuation allowances are established to reduce deferred tax assets when it is more likely than not that some portion or all of the deferred tax assets will not be realized. At December 31, 2017 and 2016, the Company has recorded a valuation allowance for its deferred tax assets in the Consolidated Balance Sheets.  

The Company applies the accounting standards related to uncertainty in income taxes. This accounting guidance clarifies the accounting for uncertainties in income taxes by prescribing a minimum recognition threshold that a tax position is required to meet before being recognized in the consolidated financial statements. It requires that the Company recognize in the consolidated financial statements the financial effects of a tax position, if that position is more likely than not of being sustained upon examination, including resolution of any appeals or litigation processes, based upon the technical merits of the position. It also provides guidance on measurement, classification, interest, penalties and disclosure. The Company’s tax positions related to its pass-through status and state income tax liability, including deductibility of expenses, have been reviewed by the Company’s management and they believe those positions would more likely than not be sustained upon examination. Accordingly, the Company has not recorded an income tax liability for uncertain tax positions at December 31, 2017, 2016 or 2015.

On December 22, 2017, the United States enacted tax reform legislation commonly known as the Tax Cuts and Jobs Act (the “TCJA”), resulting in significant modifications to existing law. Our consolidated financial statements for the year ended December 31, 2017, reflect certain effects of the TCJA, which includes the federal corporate income tax rate reduction to 21%. Consistent with Staff Accounting Bulletin No. 118 issued by the SEC, which provides for a measurement period of one year from the enactment date to finalize the accounting for effects of the TCJA, the Company provisionally recorded income tax expense of $7.8 million related to the TCJA. In accordance with SEC guidance, provisional amounts may be refined as a result of additional guidance from, and interpretations by, U.S. regulatory and standard-setting bodies, and changes in assumptions. In the subsequent period, provisional amounts will be adjusted for the effects, if any, of interpretative guidance issued after December 31, 2017, by the U.S. Department of the Treasury. The effects of the TCJA may be subject to changes for items that were previously reported as provisional amounts, as well as any element of the TCJA for which a provisional estimate could not be made, and such changes could be material.

The Company has made provisional computations of the impact of the TCJA as provided for under SAB 118, including transition tax on the mandatory deemed repatriation of foreign earnings and executive compensation limitations under Internal Revenue Code Section 162(m), among others. The Internal Revenue Service is expected to issue additional guidance clarifying provisions of the Act. As additional guidance is issued one or more of the provisional amounts may change.

Recently Issued Accounting Standards

Accounting for the Tax Cuts and Jobs Act – In December 2017, the SEC Staff issued Staff Accounting Bulletin No. 118, Income Tax Accounting Implications of the TCJA (“SAB 118”), to supplement the accounting requirements of FASB ASC Topic 740, Income Taxes (ASC Topic 740), as it relates to assessing and recognizing the impacts of the TCJA in the period of enactment.  SAB 118 allows an entity to recognize provisional amounts in its financial statements in circumstances in which the entity’s assessment is incomplete, but for which a reasonable estimate can be made.  Provisional amounts recognized are subject to adjustment for up to one year from the enactment date.

In the fourth quarter of 2017, the Company remeasured its deferred taxes at 21%, in accordance with the TCJA and GAAP.

For further details, see Note 16. Income Taxes to the Consolidated Financial Statements.

Revenue Recognition - In May 2014, the FASB issued updated guidance for recognizing revenue from contracts with customers, which seeks to provide a single, comprehensive revenue recognition model for all contracts with customers to improve comparability within industries, across industries and across capital markets. This new revenue standard contains principles that an entity will apply to determine the measurement of revenue and timing of when it is recognized. The underlying principle is that an entity will recognize revenue to depict the transfer of goods or services to customers at an amount that the entity expects to be entitled to in exchange for those goods or services. The two permitted transition methods under the new standard are the full retrospective method, in which case the standard would be applied to each prior reporting period presented, or the modified retrospective method, in which case the cumulative effect of applying the standard would be recognized at the date of initial application. The new standard is now effective prospectively for reporting periods beginning on or after December 15, 2017. The Company has completed its evaluation of the new standard and will adopt the new standard, as required, beginning with the first quarter of 2018, and does not expect the adoption to have a material impact on its Consolidated Financial Statements.  The Company has elected to use the modified retrospective method for adoption and has updated its related internal control documentation, processes and controls to conform to the new standard.

F-12

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EARTHSTONE ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

 

Leases – In February 2016, the FASB issued updated guidance on accounting for leases. The update requires that a lessee recognize in the statement of financial position a liability to make lease payments and a right-of-use asset representing its right to use the underlying asset for the lease term. For leases with a term of 12 months or less, a lessee is permitted to make an accounting policy election by class of underlying asset not to recognize lease assets and lease liabilities. Similar to current guidance, the update continues to differentiate between finance leases and operating leases; however, this distinction now primarily relates to differences in the manner of expense recognition over time and in the classification of lease payments in the statement of cash flows. The standards update is effective for interim and annual periods beginning after December 15, 2018 with early adoption permitted. Entities are required to use a modified retrospective adoption, with certain relief provisions, for leases that exist or are entered into after the beginning of the earliest comparative period in the financial statements when adopted. The Company expects to adopt this standards update, as required, beginning with the first quarter of 2019. The Company is in the process of evaluating the impact, if any, of the adoption of this guidance on its Consolidated Financial Statements.

Statement of Cash Flows – In August 2016, the FASB issued updated guidance that clarifies how certain cash receipts and cash payments are presented in the statement of cash flows. This update provides guidance on eight specific cash flow issues. The standards update is effective for interim and annual periods beginning after December 15, 2017, and should be applied retrospectively to all periods presented. The Company will adopt this update, as required, beginning with the first quarter of 2018, and does not expect the adoption to have a material impact on its Consolidated Statements of Cash Flows.

Business Combinations – In January 2017, the FASB issued updated guidance that clarifies the definition of a business, which amends the guidance used in evaluating whether a set of acquired assets and activities represents a business. The guidance requires an entity to evaluate if substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset or a group of similar identifiable assets; if so, the set of transferred assets and activities is not considered a business. As a result, acquisition fees and expenses will be capitalized to the cost basis of the property acquired, and the tangible and intangible components acquired will be recorded based on their relative fair values as of the acquisition date. The standard is effective for all public business entities for annual periods beginning after December 15, 2017.  The Company will adopt this update, as required, beginning with the first quarter of 2018, and does not expect the adoption to have a material impact on its Consolidated Financial Statements.

Intangibles - Goodwill and Other – In January 2017, the FASB issued updated guidance simplifying the test for goodwill impairment. The update eliminates Step 2 of the goodwill impairment test. Instead, an entity should perform its annual or interim goodwill impairment test by comparing the fair value of a reporting unit with its carrying amount. An entity should recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit’s fair value; however, the loss recognized should not exceed the total amount of goodwill allocated to that reporting unit. An entity still has the option to perform the qualitative assessment for a reporting unit to determine if the quantitative impairment test is necessary. The update is effective for annual and interim periods beginning after December 15, 2019 and early adoption is permitted for interim or annual goodwill impairment tests performed after January 1, 2017. The Company is in the process of evaluating the impact, if any, on its Consolidated Financial Statements.

Compensation – Stock Compensation – In May 2017, the FASB issued updated guidance that provides clarity about which changes to the terms or conditions of a share-based payment award require an entity to apply modification accounting. The update is effective for annual periods beginning after December 15, 2017.  The Company will adopt this update, as required, beginning with the first quarter of 2018, and does not expect the adoption to have a material impact on its Consolidated Financial Statements.

Note 3. Acquisitions and Divestitures

The Company accounts for its acquisitions that qualify as business combinations, under the acquisition method of accounting in accordance with FASB ASC Topic 805, Business Combinations, which, among other things, requires the assets acquired and liabilities assumed to be measured and recorded at their fair values as of the acquisition date. The initial accounting for acquisitions may not be complete and adjustments to provisional amounts, or recognition of additional assets acquired or liabilities assumed, may occur as additional information is obtained about the facts and circumstances that existed as of the acquisition dates.

Bold Transaction

On May 9, 2017, Earthstone completed the Bold Transaction described in Note 1. Organization and Basis of Presentation.

An allocation of the purchase price was prepared using, among other things, a reserve report prepared by qualified reserve engineers and priced as of the acquisition date. The following allocation is still preliminary with respect to final tax amounts and certain accruals and includes the use of estimates based on information that was available to management at the time these Consolidated Financial Statements were prepared.

F-13

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EARTHSTONE ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

 

The following table summarizes the consideration transferred, fair value of assets acquired and liabilities assumed (in thousands, except share and share price amounts):

 

F-14

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EARTHSTONE ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

 

The following unaudited supplemental pro forma condensed results of operations present consolidated information as though the Bold Transaction and the Bakken Sale (discussed below) had been completed as of January 1, 2016. The unaudited supplemental pro forma financial information was derived from the historical consolidated and combined statements of operations for Bold and Earthstone and adjusted to include: (i) depletion expense applied to the adjusted basis of the properties acquired and (ii) to eliminate non-recurring transaction costs directly related to the Bold Transaction that do not have a continuing impact on the Company’s operating results. These unaudited supplemental pro forma results of operations are provided for illustrative purposes only and do not purport to be indicative of the actual results that would have been achieved by the combined company for the periods presented or that may be achieved by the combined company in the future. Future results may vary significantly from the results reflected in this unaudited pro forma financial information (in thousands, except per share amounts):

 

The Company has included in its Consolidated Statements of Operations, revenues of $50.2 million and direct operating expenses of $23.8 million for the period from May 9, 2017 to December 31, 2017 related to the properties acquired in the Bold Transaction.

Divestitures

On December 20, 2017, the Company sold all of its oil and natural gas leases, oil and natural gas wells and associated assets located in the Williston Basin in North Dakota (the “Bakken Sale”) for a net cash consideration of approximately $26.4 million after normal and customary purchase price adjustments of $0.9 million to account for net cash flows from the effective date to the closing date. The sale resulted in a net gain of approximately $3.0 million recorded in Gain on sale of oil and gas properties in the Consolidated Statements of Operations. The effective date of the sale was December 1, 2017.

For the year ended December 31, 2017, the Company sold certain non-core properties for a total cash consideration of approximately $7.5 million, while eliminating approximately $4.0 million of future abandonment obligations. The sales resulted in a net gain of approximately $6.1 million recorded in Gain on sale of oil and gas properties in the Consolidated Statements of Operations.

In April 2015, the Company sold its Louisiana properties located primarily in DeSoto and Caddo Parishes, for cash consideration of approximately $3.4 million.  The sale resulted in a net gain of $1.6 million recorded in Gain on sale of oil and gas properties in the Consolidated Statements of Operations.  The effective date of the transaction was March 1, 2015.

Note 4. Fair Value Measurements

FASB ASC Topic 820, defines fair value as the price that would be received to sell an asset, or paid to transfer a liability, in an orderly transaction between market participants at the measurement date. ASC Topic 820 provides a framework for measuring fair value, establishes a three-level hierarchy for fair value measurements based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date and requires consideration of the counterparty’s creditworthiness when valuing certain assets.

The three-level fair value hierarchy for disclosure of fair value measurements defined by ASC Topic 820 is as follows:

Level 1 – Unadjusted, quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. An active market is defined as a market where transactions for the financial instrument occur with sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2 – Inputs, other than quoted prices within Level 1, that are either directly or indirectly observable for the asset or liability through correlation with market data at the measurement date and for the duration of the instrument’s anticipated life.

Level 3 – Prices or valuations that require unobservable inputs that are both significant to the fair value measurement and unobservable. Valuation under Level 3 generally involves a significant degree of judgment from management.

A financial instrument’s level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement. Where available, fair value is based on observable market prices or parameters or derived from such prices or

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EARTHSTONE ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

 

parameters. Where observable prices or inputs are not available, valuation models are applied. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the price transparency for the instruments or market and the instrument’s complexity. The Company reflects transfers between the three levels at the beginning of the reporting period in which the availability of observable inputs no longer justifies classification in the original level. There were no transfers between fair value hierarchy levels for the year ended December 31, 2017.

Fair Value on a Recurring Basis

Derivative financial instruments are carried at fair value and measured on a recurring basis. The derivative financial instruments consist of swaps for crude oil and natural gas. The Company’s swaps are valued based on a discounted future cash flow model. The primary input for the model is published forward commodity price curves. The swaps are also designated as Level 2 within the valuation hierarchy.

The fair values of commodity derivative instruments in an asset position include a measure of counterparty nonperformance risk, and the fair values of commodity derivative instruments in a liability position include a measure of the Company’s nonperformance risk. These measurements were not material to the Consolidated Financial Statements.

The following table summarizes the fair value of the Company’s financial assets and liabilities, by level within the fair-value hierarchy (in thousands): 

 

Other financial instruments include cash, accounts receivable and payable, and revenue royalties. The carrying amount of these instruments approximates fair value because of their short-term nature. The Company’s long-term debt obligation bears interest at floating market rates, therefore carrying amounts and fair value are approximately equal.

Fair Value on a Nonrecurring Basis

The Company applies the provisions of the fair value measurement standard on a non-recurring basis to its non-financial assets and liabilities, including oil and gas properties and goodwill. These assets and liabilities are not measured at fair value on an ongoing basis but are subject to fair value adjustments only in certain circumstances. 

Proved Oil and Natural Gas Properties

Proved oil and natural gas properties are measured at fair value on a nonrecurring basis in order to review for impairment. The impairment charge reduces the carrying values to their estimated fair values. These fair value measurements are classified as Level 3 measurements and include many unobservable inputs. Fair value is calculated as the estimated discounted future net cash flows attributable to the assets. The Company’s primary assumptions in preparing the estimated discounted future net cash flows to be recovered from oil and natural gas properties are based on (i) proved reserves, (ii) forward commodity prices and assumptions as to costs and expenses, and (iii) the estimated discount rate that would be used by potential purchasers to determine the fair value of the assets. See Note 6. Oil and Natural Gas Properties.

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EARTHSTONE ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

 

Goodwill

Goodwill represents the excess of the purchase price of assets acquired over the fair value of those assets and is tested for impairment annually, or more frequently if events or changes in circumstances dictate that the fair value of goodwill may be less than its carrying amount. Such test includes an assessment of qualitative and quantitative factors. See Note 7. Goodwill.

Business Combinations

The Company records the identifiable assets acquired and liabilities assumed at fair value at the date of acquisition on a nonrecurring basis. Fair value may be estimated using comparable market data, a discounted cash flow method, or a combination of the two. In the discounted cash flow method, estimated future cash flows are based on management’s expectations for the future and include estimates of future oil and natural gas production, commodity prices based on NYMEX commodity futures price strips as of the date of the estimate, operating and development costs, and a risk-adjusted discount rate. The future oil and natural gas pricing used in the valuation is a Level 2 assumption. Significant Level 3 assumptions associated with the calculation of discounted cash flows used in the determination of fair value of the acquisition include the Company’s estimate operating and development costs, anticipated production of proved reserves, appropriate risk-adjusted discount rates and other relevant data. The Company’s acquisitions are discussed in Note 3 Acquisitions and Divestitures.

Asset Retirement Obligations

The asset retirement obligation estimates are derived from historical costs and management’s expectation of future cost environments; and therefore, the Company has designated these liabilities as Level 3. The significant inputs to this fair value measurement include estimates of plugging, abandonment and remediation costs, well life, inflation and credit-adjusted risk-free rate. See Note 13 Asset Retirement Obligations for a reconciliation of the beginning and ending balances of the liability for the Company’s asset retirement obligations.

Note 5. Derivative Financial Instruments

In connection with the closing of the Bold Transaction on May 9, 2017, all oil and natural gas derivative contracts were novated to EEH. The Company’s hedging activities consist of derivative instruments entered into in order to hedge against changes in oil and natural gas prices through the use of fixed price swaps and basis swaps agreements. Swaps exchange floating price risk in the future for a fixed price at the time of the hedge. Consistent with its hedging policy, the Company has entered into a series of derivative instruments to hedge a significant portion of its expected oil and natural gas production through December 31, 2019. Typically, these derivative instruments require payments to (receipts from) counterparties based on specific indices as required by the derivative agreements. Although not risk free, the Company believes these instruments reduce its exposure to oil and natural gas price fluctuations and, thereby, allow the Company to achieve a more predictable cash flow.

The Company’s derivative instruments are cash flow hedge transactions in which it is hedging the variability of cash flow related to a forecasted transaction. The Company does not enter into derivative instruments for trading or other speculative purposes. These transactions are recorded in the Consolidated Financial Statements in accordance with FASB ASC Topic 815. The Company has accounted for these transactions using the mark-to-market accounting method. Generally, the Company incurs accounting losses on derivatives during periods where prices are rising and gains during periods where prices are falling which may cause significant fluctuations in the Consolidated Balance Sheets and Consolidated Statements of Operations.

The Company nets its derivative instrument fair value amounts executed with each counterparty pursuant to an International Swap Dealers Association Master Agreement (“ISDA”), which provides for net settlement over the term of the contract. The ISDA is a standard contract that governs all derivative contracts entered into between the Company and the respective counterparty. The ISDA allows for offsetting of amounts payable or receivable between the Company and the counterparty, at the election of both parties, for transactions that occur on the same date and in the same currency.

The following table sets forth the Company’s outstanding derivative contracts at December 31, 2017.  When aggregating multiple contracts, the weighted average contract price is disclosed.     

 

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EARTHSTONE ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

 

In January 2018, the Company entered into additional fixed price oil and natural gas swap agreements, hedging an additional 365,000 Bbls of 2019 oil production at a price of $58.38/Bbl and 1,552,000 MMBtu of 2018 natural gas production at a price of $2.96/MMBtu.

The following table summarizes the location and fair value amounts of all derivative instruments in the Consolidated Balance Sheets as well as the gross recognized derivative assets, liabilities, and amounts offset in the Consolidated Balance Sheets (in thousands): 

 

 

The follow table summarizes the location and amounts of the Company’s realized and unrealized gains and losses on derivatives instruments in the Company’s Consolidated Statements of Operations (in thousands): 

 

 

Note 6. Oil and Natural Gas Properties

The Company follows the successful efforts method of accounting for its oil and natural gas properties.  Under this method, costs to acquire oil and natural gas properties, drill and equip exploratory wells that find proved reserves, and drill and equip development wells are capitalized.  Exploration costs, including unsuccessful exploratory wells and geological and geophysical costs, are charged to operations as incurred.  Upon sale or retirement of oil and natural gas properties, the costs and related accumulated depreciation, depletion and amortization are eliminated from the accounts and the resulting gain or loss is recognized.

Costs incurred to maintain wells and related equipment, lease and well operating costs, and other exploration costs are charged to expense as incurred. Gains and losses arising from the sale of properties are included in operating income (loss) in the Consolidated Statements of Operations.

The Company’s lease acquisition costs and development costs of proved oil and natural gas properties are amortized using the units-of-production method, at the field level, based on total proved reserves and proved developed reserves, respectively. Depletion expense for oil and natural gas producing property and related equipment was $36.4 million, $25.4 million, and $30.7 million, for the years ended December 31, 2017, 2016, and 2015, respectively.

Proved Properties

Proved oil and natural gas properties are measured at fair value on a nonrecurring basis in order to review for impairment. The impairment charge reduces the carrying values to their estimated fair values. These fair value measurements are classified as Level 3 measurements and include many unobservable inputs. Fair value is calculated as the estimated discounted future net cash flows attributable to the assets. The Company’s primary assumptions in preparing the estimated discounted future net cash flows to be recovered from oil and natural gas properties are based on (i) proved reserves, (ii) forward commodity prices and assumptions as to costs and expenses, and (iii) the estimated discount rate that would be used by potential purchasers to determine the fair value of the assets.

Unproved Properties

Unproved properties consist of costs incurred to acquire undeveloped leases as well as the cost to acquire unproved reserves. Undeveloped lease costs and unproved reserve acquisition costs are capitalized. Unproved oil and natural gas leases are generally for a primary term of three to five years. In most cases, the term of the unproved leases can be extended by paying delay rentals, meeting

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EARTHSTONE ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

 

contractual drilling obligations, or by the presence of producing wells on the leases. Unproved costs related to successful exploratory drilling are reclassified to proved properties and depleted on a units-of-production basis.

The Company reviews its unproved properties periodically for impairment.  In determining whether an unproved property is impaired, the Company considers numerous factors including, but not limited to, current exploration and development plans, favorable or unfavorable exploration activity on the property being evaluated and/or adjacent properties, our geologists' evaluation of the property, and the remaining months in the lease term for the property.

The Company had the following non-cash asset impairment charges to its oil and natural gas properties for the years ended December 31, 2017, 2016 and 2015 (in thousands): 

 

Accumulated impairments to proved and unproved oil and natural gas properties as of December 31, 2017 and 2016, were $148.2 million and $162.7 million, respectively.

 

Note 7. Goodwill

Goodwill represents the excess of the purchase price of assets acquired over the fair value of those assets and is tested for impairment annually, or more frequently if events or changes in circumstances dictate that the carrying value of goodwill may not be recoverable. Such test includes an assessment of qualitative and quantitative factors.

The Company did not have any non-cash impairment charges to its goodwill for the year ended December 31, 2017. The Company had the following non-cash impairment charges to its goodwill for the years ended December 31, 2016 and 2015 (in thousands):

 

Accumulated impairments to Goodwill as of December 31, 2017 and 2016, were $19.1 million.

Note 8. Noncontrolling Interest

As a result of the Bold Transaction, Earthstone became the sole managing member of, and has a controlling interest in, EEH. As the sole managing member of EEH, Earthstone operates and controls all of the business and affairs of EEH and its subsidiaries. Immediately following the Bold Transaction, Earthstone and Lynden US owned a 38.6% membership interest in EEH while Bold Holdings owned the remaining 61.4%.

The Bold Transaction was recorded in accordance with FASB ASC Topic 805, Business Combinations, and is consolidated in these financial statements in accordance with FASB ASC Topic 810, Consolidation, which requires the recording of a noncontrolling interest component of net income (loss), as well as a noncontrolling interest component within equity, including changes to Additional paid-in capital to reflect the noncontrolling interest within equity in the Consolidated Balance Sheet as of December 31, 2017 at the noncontrolling interest’s respective membership interest in EEH. A reconciliation of the equity attributable to the noncontrolling interest as of May 9, 2017 is as follows (in thousands):

 

F-19

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EARTHSTONE ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

 

Earthstone consolidates the financial results of EEH and its subsidiaries, and records a noncontrolling interest for the economic interest in Earthstone held by the members of EEH other than Earthstone and Lynden US. Net loss attributable to noncontrolling interest in the Consolidated Statements of Operations for the year ended December 31, 2017 represents the portion of net income or loss attributable to the economic interest in the Company held by the members of EEH other than Earthstone and Lynden US. Noncontrolling interest in the Consolidated Balance Sheet as of December 31, 2017 represents the portion of net assets of the Company attributable to the members of EEH other than Earthstone and Lynden US.

The following table presents the changes in noncontrolling interest for the year ended December 31, 2017:

 

The following table summarizes the activity for the equity attributable to the noncontrolling interest for the year ended December 31, 2017 (in thousands):

 

 

Note 9. Net Loss Per Common Share

Net loss per common share—basic is calculated by dividing Net loss by the weighted average number of shares of common stock outstanding during the period (Common Stock through May 8, 2017 and Class A Common Stock from May 9, 2017 through December 31, 2017). Net loss per common share—diluted assumes the conversion of all potentially dilutive securities and is calculated by dividing Net loss by the sum of the weighted average number of shares of common stock, as defined above, outstanding plus potentially dilutive securities. Net loss per common share—diluted considers the impact of potentially dilutive securities except in periods in which there is a loss because the inclusion of the potential common shares, as defined above, would have an anti-dilutive effect.

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EARTHSTONE ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

 

A reconciliation of Net loss per common share is as follows:

 

Class B Common Stock has been excluded, as its conversion would eliminate noncontrolling interest and Net loss attributable to noncontrolling interest of $32.2 million would be added back to Net loss attributable to Earthstone Energy, Inc., having no dilutive effect on Net loss per common share attributable to Earthstone Energy, Inc. For the years ended December 31, 2017 and 2016, the Company excluded 105,422 and 52,844 shares, respectively, for the dilutive effect of restricted stock units in calculating diluted earnings per share as the effect was anti-dilutive due to the net loss incurred these periods.  For the year ended December 31, 2015, there were no restricted stock units issued or outstanding under the 2014 Plan.

Note 10. Common Stock

On May 9, 2017, and in connection with the completion of the Bold Transaction, Earthstone recapitalized its Common Stock into two classes, as described in Note 1. Organization and Basis of Presentation, Class A Common Stock and Class B Common Stock. At that time, all of Earthstone’s existing outstanding Common Stock was automatically converted on a one-for-one basis into Class A Common Stock.

Class A Common Stock

At December 31, 2017, there were 27,584,638 shares of Class A Common Stock issued and outstanding. On July 1, 2017, Earthstone retired and returned the 15,357 shares of treasury stock to authorized but unissued shares of Class A Common Stock. During the period January 1, 2017 through May 8, 2017, the Company issued 382,804 shares of Common Stock as a result of the vesting and settlement of restricted stock units under the 2014 Plan. During the period May 9, 2017 through December 31, 2017, the Company issued 320,410 shares of Class A Common Stock as a result of the vesting and settlement of restricted stock units under the 2014 Plan, of which 61,055 shares of Class A Common Stock were withheld by the Company in exchange for payment of income tax withholdings. Additionally, on May 9, 2017, under the Bold Contribution Agreement, Earthstone issued 150,000 shares of Class A Common Stock valued at approximately $2.0 million on that date. For additional information, see Note 3. Acquisitions and Divestitures.

Class A Common Stock Offering

In October 2017, Earthstone completed a public offering of 4,500,000 shares of Class A Common Stock, at an issue price of $9.25 per share.  Earthstone received net proceeds from this offering of $39.4 million, after deducting underwriters’ fees and offering expenses of $2.2 million. The net proceeds from the offering were used to repay outstanding indebtedness under the EEH Credit Agreement, as described in Note 12. Long-Term Debt.

Class B Common Stock

At December 31, 2017, there were 36,052,169 shares of Class B Common Stock issued and outstanding. On May 9, 2017, in connection with Earthstone’s completion of the Bold Transaction, Earthstone issued 36,070,828 shares of Class B Common Stock in exchange for $36 thousand. Each share of Class B Common Stock, together with one EEH Unit, is convertible into one share of Class A Common Stock. Earthstone did not have any Class B Common Stock issued at December 31, 2016. For additional information, see Note 3. Acquisitions and Divestitures. Additionally, subsequent to the completion of the Bold Transaction, 18,659 shares of Class B Common Stock were exchanged, along with 18,659 EEH Units, for 18,659 shares of Class A Common Stock.

F-21

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EARTHSTONE ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

 

Common Stock

During the year ended December 31, 2016, there were the following changes to the Common Stock:

During the year ended December 31, 2015, there were no changes to the Common Stock.

 

Note 11. Stock Based Compensation

The 2014 Plan allows, among other things, for the grant of restricted stock units (“RSUs”). On May 9, 2017, and in connection with the completion of the Bold Contribution Agreement, and upon approval by the stockholders of Earthstone, the 2014 Plan was amended to increase the number of shares of Class A Common Stock authorized to be issued under the 2014 Plan by 4.3 million shares, to a total of 5.8 million shares. Each RSU represents the contingent right to receive one share of Class A Common Stock. The holders of outstanding RSUs do not receive dividends or have voting rights prior to vesting and settlement. Prior to May 9, 2017, the Company determined the fair value of granted RSUs based on the market price of the Common Stock on the date of the grant. Beginning on May 9, 2017, the Company began determining the fair value of granted RSUs based on the market price of the Class A Common Stock on the date of the grant. Compensation expense for granted RSUs is recognized on a straight-line basis over the vesting and is net of forfeitures, as incurred.

The table below summarizes unvested RSU activity for the year ended December 31, 2017:

 

During the year ended December 2017, Earthstone granted 910,000 RSUs to employees and 39,000 RSUs to certain members of the Board with vesting periods varying from 12 months to 36 months. The total grant date fair value of the RSUs granted during the years 2017 and 2016 were $9.8 million and $9.3 million, respectively, with a weighted average grant fair value per share of $9.80 and $12.53, respectively.  There were no RSUs granted during 2015. The total vesting date fair value of the RSUs that vested during 2017 was $8.3 million. There were no RSUs that vested during the years 2016 and 2015. As of December 31, 2017, there was approximately $8.4 million of total unrecognized stock-based compensation expense related to unvested RSUs, which will be amortized over the remaining vesting periods. The weighted average remaining vesting period of the unrecognized compensation expense is 0.91 years.

Stock-based compensation expense for the years ended December 31, 2017 and 2016 was $6.6 million and $3.3 million, respectively. There was no stock-based compensation expense for the year ended December 31, 2015. Stock-based compensation expense is recorded in the Consolidated Statements of Operations with a corresponding increase in Additional paid-in capital within the Consolidated Balance Sheet.

 

Note 12. Long-Term Debt

Credit Agreement

On May 9, 2017, in connection with the closing of the Bold Transaction, the Company exited its credit agreement dated December 19, 2014, by and among Earthstone, OVR Operating, LLC, EF Non-OP, LLC, Sabine River Energy, LLC, Basic Petroleum Services, Inc., BOKF, NA dba Bank of Texas, and the lenders party thereto (as amended, modified or restated from time to time, the “ESTE Credit Agreement”). At that time, all outstanding borrowings of $10.0 million under the ESTE Credit Agreement were repaid and $0.5 million of remaining unamortized deferred financing costs were expensed and included in Write-off of deferred financing costs in the Consolidated Statements of Operations.  

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EARTHSTONE ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

 

On May 9, 2017, EEH (the “Borrower”), Earthstone Operating, LLC, EF Non-Op, LLC, Sabine River Energy, LLC, Earthstone Legacy Properties, LLC, Lynden Op, Bold, Bold Operating, LLC (the “Guarantors”), BOKF, NA dba Bank Of Texas, as Agent and Lead Arranger, Wells Fargo Bank, National Association as Syndication Agent and the lenders party thereto (the “Lenders”), entered into a credit agreement (the “EEH Credit Agreement”).

The borrowing base under the EEH Credit Agreement is currently $185.0 million, and is subject to redetermination on or about November 1st and May 1st of each year. The amounts borrowed under the EEH Credit Agreement bear annual interest rates at either (a) the London Interbank Offered Rate (“LIBOR”) plus 2.25% to 3.25% or (b) the prime lending rate of Bank of Texas plus 1.25% to 2.25%, depending on the amounts borrowed under the EEH Credit Agreement. Principal amounts outstanding under the EEH Credit Agreement are due and payable in full at maturity on May 9, 2022. All of the obligations under the EEH Credit Agreement, and the guarantees of those obligations, are secured by substantially all of EEH’s assets. Additional payments due under the EEH Credit Agreement include paying a commitment fee of 0.50% per year to the Lenders in respect of the unutilized commitments thereunder, as well as certain other customary fees.

The EEH Credit Agreement contains a number of covenants that, among other things, restrict, subject to certain exceptions, EEH’s ability to incur additional indebtedness, create liens on assets, make investments, enter into sale and leaseback transactions, pay dividends and make distributions or repurchase its limited liability interests, engage in mergers or consolidations, sell certain assets, sell or discount any notes receivable or accounts receivable and engage in certain transactions with affiliates.

In addition, the EEH Credit Agreement requires EEH to maintain the following financial covenants: a current ratio of not less than 1.0 to 1.0 and a leverage ratio of not greater than 4.0 to 1.0. Leverage ratio means the ratio of (i) the aggregate debt of EEH and its consolidated subsidiaries as at the last day of the fiscal quarter (excluding any debt from obligations relating to non-cash losses under FASB ASC 815 as a result of changes in the fair market value of derivatives) to (ii) the product of EBITDAX for such fiscal quarter multiplied by four. The term “EBITDAX” means, for any period, the sum of consolidated net income for such period plus (a) the following expenses or charges to the extent deducted from consolidated net income in such period: (i) interest, (ii) taxes, (iii) depreciation, (iv) depletion, (v) amortization, (vi) non-cash losses under FASB ASC 815 as a result of changes in the fair market value of derivatives, (vii) exploration expenses, (viii) impairment expenses, and (ix) non-cash compensation expenses and minus (b) to the extent included in consolidated net income in such period, non-cash gains under FASB ASC 815 as a result of changes in the fair market value of derivatives.

The EEH Credit Agreement contains customary affirmative covenants and defines events of default to include failure to pay principal or interest, breach of covenants, breach of representations and warranties, insolvency, judgment default, and if Frank A. Lodzinski ceases to serve and function as Chief Executive Officer of EEH and the majority of the Lenders do not approve of Mr. Lodzinski’s successor. Upon the occurrence and continuance of an event of default, the Lenders have the right to accelerate repayment of the loans and exercise their remedies with respect to the collateral. As of December 31, 2017, EEH was in compliance with all covenants under the EEH Credit Agreement.       

As of December 31, 2017, the Company had a $185.0 million borrowing base under the EEH Credit Agreement, of which $25.0 million was outstanding, bearing an annual interest rate of 3.7611%, resulting in an additional $160.0 million of borrowing base availability under the EEH Credit Agreement.

Promissory Note

In July 2016, Earthstone issued a $5.1 million unsecured promissory note (the “Note”) to a drilling rig contractor in settlement of rig idle charges and the termination amount of the contract. These expenses which were incurred from late January 2016 through December 31, 2016 and were recorded in Rig idle and termination expense in the Consolidated Statements of Operations for the year ended December 31, 2016. The Note was assigned to EEH in connection with the closing of the Bold Transaction. In December 2017, the remaining balance of the Note was paid in full.

The following table below summarizes long term debt (in thousands):

 

F-23

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EARTHSTONE ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

 

For the year ended December 31, 2017, the Company had borrowings of $85.0 million and $74.3 million in repayments of borrowings. The borrowings included $58.0 million related to the repayments of all outstanding borrowings under Bold’s credit agreement which were assumed by EEH in connection with the closing of the Bold Transaction.  The repayments primarily included $35.0 million of the proceeds received from the Class A Common Stock offering in October 2017 and $25.0 million of the proceeds received from the Bakken Sale in December 2017. As stated above, in December 2017, the remaining balance of the Note was paid in full.

For the years ended December 31, 2017, 2016 and 2015, interest on all outstanding debt averaged 4.26%, 4.03% and 1.68% per annum, respectively, of which excluded commitment fees of $0.3 million for each period ended and amortization of deferred financing costs of $0.3 million for each period ended, respectively.  

The Company capitalized $1.4 million, $0.1 million and $0.1 million, respectively, of costs associated with the credit agreements for the years ended December 31, 2017, 2016 and 2015. These capitalized costs are included in Other noncurrent assets in the Consolidated Balance Sheets. The Company’s policy is to capitalize the financing costs associated with its debt and amortize those costs on a straight-line basis over the term of the associated debt.  

 

Note 13. Asset Retirement Obligations

The Company has asset retirement obligations associated with the future plugging and abandonment of oil and natural gas properties and related facilities. Revisions to the liability typically occur due to changes in the estimated abandonment costs, well economic lives, and the discount rate.

The following table summarizes the Company’s asset retirement obligation transactions recorded during the years ended December 31, 2017 and 2016 (in thousands):

 

 

Note 14. Related Party Transactions

FASB ASC Topic 850, Related Party Disclosures, requires that information about transactions with related parties that would make a difference in decision making shall be disclosed so that users of the financial statements can evaluate their significance.

Flatonia Energy, LLC (“Flatonia”), which owns approximately 10.7% of the outstanding Class A Common Stock as of December 31, 2017, is a party to a joint operating agreement (the “Operating Agreement”) with the Company. The Operating Agreement covers certain jointly owned oil and natural gas properties located in the Eagle Ford Trend of south Texas. In connection with the Operating Agreement, the Company made payments to Flatonia of $26.5 million, $26.6 million and $33.9 million, and received payments from Flatonia of $5.4 million, $21.7 million and $66.7 million, respectively, for the years ended December 31, 2017, 2016 and 2015. At December 31, 2017 and 2016, amounts receivable due from Flatonia in connection with the Operating Agreement were $1.3 million and $1.5 million, respectively. Amounts payable due to Flatonia in connection with the Operating Agreement were $3.1 million at December 31, 2016. There were no payables outstanding and due to Flatonia as of December 31, 2017.        

Our majority shareholder consists of various investment funds managed by a venture capital firm who may manage other investments in entities with which we interact in the normal course of business.

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EARTHSTONE ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

 

Note 15. Commitments and Contingencies

Contractual Commitments

Future minimum contractual commitments as of December 31, 2017 under non-cancelable agreements having remaining terms in excess of one year are as follows: 

 

The Company has a non-cancelable fixed cost agreement of $1.6 million per year through 2021 to reserve pipeline capacity of 10,000 MMBtu per day for gathering and processing related to certain Eagle Ford assets in south Texas through 2021. Additionally, the Company leases corporate office space in The Woodlands, Texas, Midland, Texas and Denver, Colorado. Rent expense was approximately $0.9 million, $0.8 million, and $0.8 million for the years ended December 31, 2017, 2016, and 2015, respectively.  Minimum lease payments under the terms of non-cancelable operating leases as of December 31, 2017 are shown in the table above.   

Environmental

The Company’s operations are subject to risks normally associated with the drilling, completion and production of oil and gas, including blowouts, fires, and environmental risks such as oil spills or gas leaks that could expose the Company to liabilities associated with these risks.

In the Company’s acquisition of existing or previously drilled well bores, the Company may not be aware of prior environmental safeguards, if any, that were taken at the time such wells were drilled or during such time the wells were operated. The Company maintains comprehensive insurance coverage that it believes is adequate to mitigate the risk of any adverse financial effects associated with these risks.

However, should it be determined that a liability exists with respect to any environmental cleanup or restoration, the liability to cure such a violation could still fall upon the Company. No claim has been made, nor is the Company aware of any liability which the Company may have, as it relates to any environmental cleanup, restoration, or the violation of any rules or regulations relating thereto except for the matter discussed above.

Legal

From time to time, Earthstone and its subsidiaries may be involved in various legal proceedings and claims in the ordinary course of business.

In July 2015, EF Non-Op, LLC, a subsidiary of Earthstone, filed suit in the 125^th Judicial District Court of Harris County, Texas against the operator of its properties in LaSalle County, Texas. In the case EF Non-Op, LLC vs. BHP Billiton Petroleum Properties (N.A.), LP (F/K/A Petrohawk Properties, LP), the Company claimed the operator breached the applicable joint operating agreements in numerous ways, including, but not limited to, improper authorization for expenditure requests, improper and imprudent operations, misrepresentation of charges and excessive billings, as well as refusal to provide requested information. The Company also claims damages from negligent representation and fraud. In December 2017, we resolved the dispute with no material impact on the Company.

Olenik v. Lodzinksi et al.: On June 2, 2017, Nicholas Olenik filed a purported shareholder class and derivative action in the Delaware Court of Chancery against Earthstone’s Chief Executive Officer, along with other members of the Board, EnCap, Bold, Bold Holdings and OVR. The complaint alleges that Earthstone’s directors breached their fiduciary duties in connection with the Bold Contribution Agreement. The Plaintiff asserts that the directors negotiated the Bold Transaction to benefit EnCap and its affiliates, failed to obtain adequate consideration for the Earthstone shareholders who were not affiliated with EnCap or Earthstone management, did not follow an adequate process in negotiating and approving the Bold Transaction and made materially misleading or incomplete proxy disclosures in connection with the Bold Transaction. The suit seeks unspecified damages and purports to assert claims derivatively on behalf of Earthstone and as a class action on behalf of all persons who held Common Stock up to March 13, 2017, excluding defendants and their affiliates. Earthstone and each of the other defendants believe the claims are entirely without merit and they intend to mount a vigorous defense. The outcome of this suit is uncertain, and while Earthstone is confident in its position, any potential monetary recovery or loss to Earthstone cannot be estimated at this time.

On August 18, 2017, litigation captioned Trinity Royal Partners, LP v. Bold Energy III LLC, et al. was filed with the 142nd Judicial District of the District Court in Midland County, Texas, asserting breach of contract and indemnity claims for alleged damages from

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EARTHSTONE ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

 

loss of property relating to two oil and natural gas wells in which Bold was the operator. Trinity Royalty Partners, LP (“Trinity”) alleges that Bold is required to indemnify Trinity under the terms of an Assignment and a Participation and Joint Development Agreement between Bold and Trinity. Damages are alleged to include costs incurred in attempting to repair and restore an oil and natural gas well and for the loss of future reserves attributable to both wells. Trinity is seeking approximately $7.2 million in damages and attorneys’ fees. Earthstone and Bold believe the suit is without any merit and Bold intends to mount a vigorous defense. The outcome of this suit is uncertain, and while the Company is confident in its position, any potential monetary recovery or loss to the Company cannot be estimated at this time.

 

Note 16. Income Taxes

The following table shows the components of the Company’s income tax provision for the years ended December 31, 2017, 2016 and 2015 (in thousands):

 

Effective Tax Rate

Following the closing of the Bold Transaction, the Company continues to record an income tax provision consistent with its status as a corporation. The Company’s corporate structure requires the filing of two separate consolidated U.S. Federal income tax returns and one Canadian income tax return resulting from the Lynden Arrangement that includes Lynden US, Earthstone, and Lynden Corp. As such, taxable income of Earthstone cannot be offset by tax attributes, including net operating losses, of Lynden US, nor can taxable income of Lynden US be offset by tax attributes of Earthstone. Following the Bold Transaction, Earthstone and Lynden US record a tax provision, respectively, for their share of the book income or loss of EEH, net of the noncontrolling interest, as well as any standalone income or loss generated by each company. As EEH is treated as a partnership for U.S. Federal income tax purposes, it is not subject to income tax at the federal level and only recognizes the Texas Margin Tax.

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EARTHSTONE ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

 

A reconciliation of the effective tax rate to the statutory rate for the years ended December 31, 2017 and 2016 is as follows (in thousands, except percentages):

During the year ended December 31, 2017, the Company recorded a total income tax benefit of $16.4 million which was primarily driven by the change in valuation allowance associated with the Bold Transaction. For Lynden US, the Company recorded an income tax benefit of $8.6 million, of which $4.8 million related to the reduction of that amount in its deferred tax liability resulting from the federal corporate income tax rate reduction to 21% as described below. Additionally, the Company recorded an income tax benefit for Earthstone of $7.7 million which resulted from a change in assessment of the realization of its net deferred tax assets due to the deferred tax liability that was recorded with respect to its investment in EEH as part of the Bold Transaction as an adjustment to Additional paid-in capital within the Consolidated Balance Sheet. Additionally, Earthstone recorded income tax expense of $12.6 million related to the reduction of that amount in its deferred tax asset resulting from the federal corporate income tax rate reduction to 21% as described below, which was fully offset by the reduction in its valuation allowance for that amount because the future realization of such loss cannot be reasonably assured and is subject to a full valuation allowance.  

On December 22, 2017, the United States enacted tax reform legislation commonly known as the TCJA, resulting in significant modifications to existing law. Our consolidated financial statements for the year ended December 31, 2017, reflect certain effects of the TCJA, which includes the federal corporate income tax rate reduction to 21%. Consistent with Staff Accounting Bulletin No. 118 issued by the SEC, which provides for a measurement period of one year from the enactment date to finalize the accounting for effects of the TCJA, the Company provisionally recorded income tax expense of $7.8 million related to the TCJA. In accordance with SEC guidance, provisional amounts may be refined as a result of additional guidance from, and interpretations by, U.S. regulatory and standard-setting bodies, and changes in assumptions. In the subsequent period, provisional amounts will be adjusted for the effects, if any, of interpretative guidance issued after December 31, 2017, by the U.S. Department of the Treasury. The effects of the TCJA may be subject to changes for items that were previously reported as provisional amounts, as well as any element of the TCJA for which a provisional estimate could not be made, and such changes could be material.

The Company has made provisional computations of the impact of the TCJA as provided for under SAB 118, including transition tax on the mandatory deemed repatriation of foreign earnings and executive compensation limitations under Internal Revenue Code Section 162(m), among others. The Internal Revenue Service is expected to issue additional guidance clarifying provisions of the Act. As additional guidance is issued one or more of the provisional amounts may change.

The Company’s effective tax rate for the year ended December 31, 2016, was approximately (1.0)% which was less than the U.S. Federal statutory tax rate primarily due to both the recording of a $12.2 million valuation allowance as the realizability of the Company’s deferred tax assets is not more likely-than-not, and $6.0 million reduction of income tax benefit resulting from non-deductible impairment of goodwill.

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EARTHSTONE ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

 

A reconciliation of the effective tax rate to the statutory rate for the year ended December 31, 2015 is as follows (in thousands, except percentages):

 

The Company’s effective tax rate for the year ended December 31, 2015, was approximately 18.5% which was less than the U.S. Federal statutory tax rate primarily due to the increase in valuation allowance in 2015. The impairments recorded by the Company during 2015 reduced the book value of its properties below the tax basis; thereby, giving rise to a significant deferred tax asset associated with its oil and natural gas properties and putting the Company in an overall net deferred tax asset position prior to any realization assessment. The realizability of the Company’s deferred tax assets is not more likely-than-not, therefore the Company recorded a valuation allowance to reduce its overall net deferred tax asset portion to zero.

Deferred Tax Assets and Liabilities

The Company's deferred tax position reflects the net tax effects of the temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax reporting.  Significant components of the deferred tax assets and liabilities at December 31, 2017 and 2016 are as follows (in thousands):  

 

As of December 31, 2017, the Company had a valuation allowance recorded against its deferred tax assets of $24.1 million which is in excess of its net deferred noncurrent tax assets of $13.6 million, as presented above. The Company’s corporate organizational structure requires the filing of two separate consolidated U.S. Federal corporate income tax returns, one separate U.S. Federal partnership income tax return and one Canadian income tax return. As a result, tax attributes of one group cannot be offset by the tax attributes of another. At December 31, 2017, the deferred tax assets and liabilities related to the two U.S. Federal corporate income tax returns and one Canadian income tax return are a $20.5 million deferred tax asset, an $8.5 million deferred tax liability and a $3.6 million deferred tax asset, respectively, before considering the valuation allowance of $24.1 million.

As of December 31, 2016, the Company had a valuation allowance recorded against its deferred tax assets of $39.6 million which is in excess of its Net deferred noncurrent tax assets of $23.8 million, as presented above. The Company’s corporate organizational structure requires the filing of two separate consolidated U.S. Federal income tax returns and one Canadian income tax return. As a result, tax attributes of one group cannot be offset by the tax attributes of another. At December 31, 2016, the deferred tax assets and liabilities related to the two U.S. Federal income tax returns and one Canadian income tax return are a $36.0 million deferred tax asset, a $15.8 million deferred tax liability and a $3.6 million deferred tax asset, respectively.

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EARTHSTONE ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

 

As of December 31, 2017, the Company had estimated U.S. net operating loss carryforwards of $49.1 million, the first expiring in 2034 and the last in 2037, and estimated Canadian net operating loss carryforwards of $10.0 million, the first expiring in 2024 and the last in 2036. The ability to utilize net operating losses and other tax attributes could be subject to a significant limitation if the Company were to undergo an ownership change for the purposes of Section 382 (“Sec 382”) of the Internal Revenue Code of 1986, as amended (the “Code”).  The Company has an additional estimated U.S. net operating loss carryforward of $28.0 million limited by Sec 382 resulting from the Lynden Arrangement. The Company continues to evaluate the impact, if any, of potential Sec 382 limitations.

Uncertain Tax Positions

FASB ASC Topic 740, Income Taxes (“ASC 740”) prescribes a recognition threshold and a measurement attribute for the financial statement recognition and measurement of income tax positions taken or expected to be taken in an income tax return. For those benefits to be recognized, an income tax position must be more-likely-than-not to be sustained upon examination by taxing authorities. As of December 31, 2017, the Company had no material uncertain tax positions. The Company’s uncertain tax positions may change in the next twelve months; however, the Company does not expect any possible change to have a significant impact on its results of operations or financial position.

The Company files two federal income tax returns, one Canadian income tax return and various combined and separate filings in several state and local jurisdictions. The Company’s practice is to recognize estimated interest and penalties, if any, related to potential underpayment of income taxes as a component of income tax expense in its Consolidated Statement of Operations. As of December 31, 2017, the Company did not have any accrued interest or penalties associated with any uncertain tax liabilities.

Note 17. Profit Sharing Plan

The Company sponsors a 401(k) defined contribution plan (the “401(k) Plan”) for substantially all of its employees, which was initiated in April 2017. Eligible employees may make contributions to the 401(k) Plan by electing to contribute up to 100% of their annual compensation, not to exceed annual limits established by the federal government. The Company makes matching contributions of up to six percent of the eligible employee’s annual compensation contributed. The Company’s matching contributions vest immediately.  The Company’s contributions to the 401(k) Plan for the year ended December 31, 2017 were $0.3 million.

Note 18. Supplemental Selected Quarterly Financial Data (Unaudited)  

 

Second quarter 2017 loss from operations includes a non-cash impairment charge of $66.6 million related to the Company’s oil and natural gas properties, as discussed in Note 6. Oil and Natural Gas Properties.

Fourth quarter 2016 loss from operations includes a non-cash impairment charge of $6.8 million related to the Company’s oil and natural gas properties, as discussed in Note 6. Oil and Natural Gas Properties and a non-cash impairment charge of $17.5 million related to its goodwill, as discussed in Note 7. Goodwill.  Second quarter 2016 loss from operations includes $5.1 million of expenses related to the termination of a drilling rig, as discussed in Note 12. Long-Term Debt.

 

 

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SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES

(UNAUDITED)

Costs Incurred Related to Oil and Gas Activities

Capitalized costs include the cost of properties, equipment, and facilities for oil and natural gas producing activities. Capitalized costs for proved properties include costs for oil and natural gas leaseholds where proved reserves have been identified, development wells, and related equipment and facilities, including development wells in progress. Capitalized costs for unproved properties include costs for acquiring oil and natural gas leaseholds where no proved reserves have been identified, including costs of exploratory wells that are in the process of drilling or in active completion, and costs of exploratory wells suspended or waiting on completion.

The Company’s oil and natural gas activities for 2017, 2016 and 2015 were entirely within the United States of America. Costs incurred in oil and natural gas producing activities were as follows (in thousands):

 

 

 

During the year ended December 31, 2017, additions to oil and natural gas properties of $0.1 million were recorded for estimated costs of future abandonment related to new wells drilled or acquired.  During the years ended December 31, 2016 and 2015, additions to oil and natural gas properties of $0.2 million were recorded for estimated costs of future abandonment related to new wells drilled or acquired.

For the years ended December 31, 2017, 2016 and 2015, the Company had no capitalized exploratory well costs, nor costs related to share-based compensation, general corporate overhead or similar activities.

Capitalized Costs

Capitalized costs, impairment, and depreciation, depletion and amortization relating to the Company’s oil and natural gas properties producing activities, all of which are conducted within the continental United States as of December 31, 2017 and 2016, are summarized below (in thousands):

 

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Oil and Natural Gas Reserves

Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various reservoirs make these estimates generally less precise than other estimates included in the financial statement disclosures.

Proved reserves represent estimated quantities of oil, natural gas and natural gas liquids that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions in effect when the estimates were made. Proved developed reserves represent estimated quantities expected to be recovered through wells and equipment in place and under operating methods used when the estimates were made.

The proved reserves estimates shown herein for the years ended December 31, 2017, 2016 and 2015 have been prepared by Cawley, Gillespie & Associates, Inc., independent petroleum engineers. Proved reserves were estimated in accordance with guidelines established by the SEC, which require that reserve estimates be prepared under existing economic and operating conditions based upon the 12-month unweighted average of the first-day-of-the-month prices.

The reserve information in these Consolidated Financial Statements represents only estimates. There are a number of uncertainties inherent in estimating quantities of proved reserves, including many factors beyond the Company’s control, such as commodity pricing. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgement. As a result, estimates by different engineers may vary. In addition, results of drilling, testing and production subsequent to the date of an estimate may lead to revising the original estimate. Accordingly, initial reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. The meaningfulness of such estimates depends primarily on the accuracy of the assumptions upon which they were based. Except to the extent the Company acquires additional properties containing proved reserves or conducts successful exploration and development activities or both, the Company’s proved reserves will decline as reserves are produced.

The following table illustrates the Company’s estimated net proved reserves, including changes, and proved developed and proved undeveloped reserves for the periods indicated. The oil prices as of December 31, 2017, 2016, and 2015 are based on the respective 12-month unweighted average of the first of the month prices of the West Texas Intermediate (“WTI”) spot prices which equates to $51.34 per barrel, $42.75 per barrel, and $50.28 per barrel, respectively. The natural gas prices as of December 31, 2017, 2016 and 2015 are based on the respective 12-month unweighted average of the first of month prices of the Henry Hub spot price which equates to $2.98 per MMBtu, $2.48 per MMBtu and $2.59 per MMBtu, respectively. Natural gas liquids are made up of ethane, propane, isobutane, normal butane and natural gasoline, each of which have different uses and different pricing characteristics. The natural gas liquids prices used to value reserves as of December 31, 2017, 2016 and 2015 averaged $22.59 per barrel, $13.21 per barrel and $14.11 per barrel, respectively. All prices are adjusted by lease or field for energy content, transportation fees, and market differentials. All prices are held constant in accordance with SEC guidelines.        

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A summary of the Company’s changes in quantities of proved oil, natural gas and NGLs reserves for the years ended December 31, 2017, 2016 and 2015 are as follows:      

 

Notable changes in proved reserves for the year ended December 31, 2017 included the following:

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Notable changes in proved reserves for the year ended December 31, 2016 included the following:

Notable changes in proved reserves for the year ended December 31, 2015 included the following:

For wells classified as proved developed producing where sufficient production history existed, reserves were based on individual well performance evaluation and production decline curve extrapolation techniques. For undeveloped locations and wells that lack sufficient production history, reserves were based on analogy to producing wells within the same area exhibiting similar geologic and reservoir characteristics. Well spacing was determined from drainage patterns derived from a combination of performance-based recoveries and analogous producing wells for each area or field. PUD locations were limited to areas of uniformly high-quality reservoir properties, between existing commercial producers where the reservoir can, with reasonable certainty, be judged to be continuous with existing producers and contain economically producible oil and natural gas on the basis of available geoscience and engineering data.  

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Changes in PUD reserves for the years ended December 31, 2017, 2016 and 2015 were as follows (in MBOE): 

 

2017 Changes in PUD reserves

Conversions to developed. In the Company’s year-end 2016 plan to develop its PUDs within five years, the Company estimated that $6.9 million of capital would be expended in 2017 and that it would convert 732 MBOE.  Because of the improvement in commodity prices and the change in its development plan for 2017, the Company actually spent $8.5 million to convert 622 MBOE to developed. The Company’s plan changed in that it developed more oil PUDs and elected not to participate in natural gas PUDs which included the above mentioned 443 MBOE associated with the Eagle Ford non-participation. The capital to develop the Company’s oil PUDs was higher on a per unit basis than the natural gas PUDs however the margins are higher for oil PUDs. The oil PUDs further benefited the Company’s longer-term operated development plans. Since the Bold Transaction closed in May 2017, the associated capital plan for the properties acquired in the Bold Transaction during 2017 was not considered in the Company’s year-end 2016 report. The Company did however incur $63.4 million to convert 2,134 MBOE of purchased PUD reserves to Developed. The Company intends to convert its proved undeveloped reserves into proved developed producing reserves in accordance with its estimates as of the date of the Company’s year-end 2017 reserve report.

Extensions and discoveries. Additionally, 27,977 MBOE were added as extensions and discoveries due to successful drilling results on the Company’s acreage positions because of the wells it drilled. The increase was also supported by successful drilling results by other operators directly offsetting and in close proximity to the Company’s acreage.  All of these drilling results increased the confidence of the reservoir continuity and performance of the associated reservoirs which increased the number of PUDs primarily in the Midland Basin.

Sales of minerals in place.  Sales of minerals in place totaled 391 MBOE during 2017 and were primarily related to the disposition of the Bakken properties, as further described in Note 3. Acquisitions and Divestitures in the Notes to Consolidated Financial Statements

Purchases of minerals in place. During 2017, 37,327 MBOE were added to PUD reserves upon the closing of the Bold Transaction.

Revision to previous estimates. Revisions of 4,832 MBOE were primarily due to (1) removal of approximately 2,011 MBOE of reserves due to delayed development plans of other operators in the Midland Basin that management previously expected to be developed within five years, (2) reduction of 2,378 MBOE upon the closing of the Bold Transaction and making adjustments to development plans and PUD reserve assignments, and (3) non-participation in three Eagle Ford natural gas PUDs that were expected to develop 443 MBOE. This non-participation has no impact on the Company’s ability to participate in future wells in this acreage position.  

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2016 Changes in PUD reserves

In early 2016, due primarily to depressed prices of oil and natural gas, the Company placed a lower emphasis on the conversion of its PUDs into proved developed producing reserves. In the Company’s plan to convert these reserves over a five-year period, the Company estimated that $3.1 million of capital expenditure would be incurred in 2016, and the bulk of capital expenditures would occur over the following four years. The Company’s actual 2016 capital expenditures for conversion of proved undeveloped reserves were $3.2 million, in line with its estimates. The Company also had estimated that these capital expenditures would result in 258 MBOE of proved developed producing reserves. The Company’s actual estimated conversions were 169 MBOE. The difference was due primarily to one less location being drilled than the Company had estimated and lower initial reserve estimates for wells in certain units where all wells in the units had not been developed. This resulted in lower reserve estimates until the remaining wells in the units are drilled.

As of December 31, 2016, the Company’s estimated proved undeveloped reserves were significantly lower than as of December 31, 2015, due to lower oil and natural gas prices used in making its 2016 estimates.

Extensions and Discoveries during the year ended December 31, 2016, were from the Company’s operated Eagle Ford and non-operated Bakken properties.

2015 Changes in PUD reserves

All of the Company’s purchases of minerals in place reserves during the year ended December 31, 2015, occurred in its Eagle Ford property in Gonzales County, Texas.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves

The following Standardized Measure of Discounted Future Net Cash Flows (Standardized Measure) has been developed utilizing ASC Topic 932, Extractives Activities – Oil and Gas (“ASC 932”) procedures and based on oil and natural gas reserve and production volumes estimated by the Company’s third-party petroleum engineering firm. It can be used for some comparisons, but should not be the only method used to evaluate the Company or its performance. Further, the information in the following table may not represent realistic assessments of future cash flows, nor should the Standardized Measure be viewed as representative of the current value of the Company.

The Company believes that the following factors should be taken into account when reviewing the following information:

At December 31, 2017, 2016 and 2015, as specified by the SEC, the prices for oil and natural gas used in this calculation were the unweighted 12-month average of the first day of the month prices, except for volumes subject to fixed price contracts. Prices used to estimate reserves are included in Oil and Natural Gas Reserves above. Future production costs include per-well overhead expenses allowed under joint operating agreements, abandonment costs (net of salvage value), and a non-cancelable fixed cost agreement to reserve pipeline capacity of 10,000 MMBtu per day for gathering and processing. Estimates of future income taxes are computed using current statutory income tax rates including consideration for estimated future statutory depletion and tax credits. The resulting net cash flows are reduced to present value amounts by applying a 10% discount factor.

The Standardized Measure is as follows (in thousand):

 

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Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves

The following is a summary of the changes in the Standardized Measure for the Company’s proved oil and natural gas reserves during each of the years in the three-year period ended December 31, 2017 (in thousands):

 

 

 

 

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