our dependency on the skill, ability and decisions of third party operators of oil and natural gas properties in which we have non-operated working ~~interests.~~

interests; and

possible adverse results from litigation and the use of financial resources to defend ourselves.

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.

G~~LOSSARY~~

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~~

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~~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~~ well – A well found to be incapable of producing hydrocarbons economically.

Exploitation– ~~The act of making an oil and natural gas property more profitable, productive~~A development or ~~useful.~~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-inor orFarm-out ~~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 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~~ Frac – A well stimulation method by which fluid, ~~(approximately 95-98% water)~~comprised largely of water and proppant (purposely sized particles used to hold open an induced fracture) ~~are~~is 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 Operating Agreementor orJOA ~~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.

~~MBOE~~

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

MMBoe –One million 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 abandonmentor orP&A ~~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) ~~estimated future abandonment costs, net of the estimated salvage value of related equipment, (ii)~~ non-property related expenses such as general and administrative expenses, debt service and future income tax expense, or ~~(iii)~~(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 reservesor orPDNP ~~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 reservesor orPDP ~~PDP~~– Reserves that can be expected to be recovered ~~through~~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.

Proved undeveloped reservesor orPUD ~~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 scheduleto be drilled within five yearsunless 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~~

Standardized Measure – ~~A method~~The present value of ~~hydraulic fracturing that uses water~~estimated future net revenue to be generated from the production of proved reserves, determined in accordance with ~~a minor amount~~the rules and regulations of ~~chemicals~~the SEC (using prices and costs in ~~order~~effect as of the date of estimation), less future development, production and income tax expenses, and discounted at 10% per annum to ~~stimulate rock and enhance fluid flow.~~

~~Swing producer –~~ ~~A supplier or a close oligopolistic group~~reflect the timing of ~~suppliers of any commodity, controlling its global deposits and possessing large spare production capacity.~~future net revenue.

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 orWI– 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.

PART I

P~~ART I~~

Item 1. Business

Overview

Earthstone Energy, Inc. ~~(together~~, a Delaware corporation (“Earthstone” and together with our consolidated subsidiaries, the “Company,” “our,” “we,” “us,” ~~“Earthstone”~~ or similar terms), ~~a Delaware corporation formed in 1969,~~ is a growth-oriented independent oil and ~~natural~~ gas ~~development and production company. In addition, the Company is active~~company engaged in ~~corporate mergers and~~ the acquisition and development of oil and ~~natural~~ gas ~~properties~~reserves through activities that ~~have production~~include the acquisition, drilling and ~~future~~ development ~~opportunities.~~of undeveloped leases, asset and corporate acquisitions and mergers. 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.

~~Our reserve portfolio primarily consists of~~ At present, our assets are located in the Midland Basin of west Texas and the Eagle Ford ~~trend~~Trend of south ~~Texas and in the Williston Basin of North Dakota. We have approximately 5,900 net leasehold acres~~Texas.

Our primary focus is concentrated in the Midland Basin ~~representing~~of west Texas, a high oil and liquids rich resource basin which provides us with multiple horizontal targets with proven production results, long-lived reserves and historically high drilling success rates. Utilizing one rig for the entirety of 2019 and two rigs for portions of the second and third quarters, we successfully drilled 17 gross / 12.7 net operated wells in the Midland Basin in 2019. Additionally, we spud and drilled vertical sections of eight gross / 7.5 net operated wells late in 2019. We completed and brought online 17 gross / 12.6 net operated wells and had 3.4 net non-operated wells brought online in the Midland Basin in 2019. Additionally, in late December, the operator of a 15-well non-operated project completed approximately five gross / one net well, which had previously been anticipated to occur in early 2020. Completions on this 15 gross / 3.1 net well project are continuing and all 15 wells are anticipated to be brought online during the first quarter of 2020.

With 445 potential gross horizontal drilling locations in the Midland Basin, we are focused on developmental drilling and completion operations in the area. During 2019, we began increasing the spacing between our wells in order to reduce well to well interference which in turn increases capital efficiency and productivity. In certain areas, our acreage may support different spacing designs and we will drill accordingly in seeking to maximize economics and recovery. We continue to pursue acreage trades or bolt-on acreage acquisitions in the Midland Basin with the intent of increasing our operated acreage and drilling inventory, drilling and completing longer laterals and realizing greater operating efficiencies.

We have approximately 29,100 net acres in the core of the Midland Basin that are highly contiguous on a project by project basis which allow us to drill multi-well pads. Of this acreage, 79% is operated and 21% is non-operated. We hold an ~~average~~approximate 94% working interest in our operated acreage and an approximate 40% 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, Midland and Reagan counties. In total, we have an interest in 212 gross producing wells in the Midland ~~Counties.~~Basin. We have approximately ~~21,000~~14,500 net leasehold acres in the Eagle Ford ~~trend~~Trend, which primarily consists of ~~south Texas, including~~ approximately ~~18,000~~14,100 operated net leasehold acres in the crude oil window in Fayette, Gonzales and Karnes ~~Counties,~~counties, with working interests ranging from approximately ~~25%~~12% to ~~50%,~~67%. We have an interest in 116 gross operated producing wells and ~~approximately 3,000 net leasehold acres located~~six gross non-operated producing wells in the natural gas and condensate window in La Salle County, with working interests averaging approximately 11%. In the Williston Basin of North Dakota, we have approximately 5,900 net leasehold acres, with working interests ranging from approximately 1% to 6%Eagle Ford Trend.

.At

Our corporate headquarters are located in The Woodlands, Texas. We also have an operating office in Denver, Colorado and two field offices in south Texas. Our common stock, $0.001 par value per share (the “Common Stock”) is traded on the NYSE MKT under the symbol ESTE.

~~Recent Developments~~

~~Acquisitions~~

On November 7, 2016, we entered into a contribution agreement (the “Bold Contribution Agreement”), by and among the Company, Earthstone Energy Holdings, LLC, a newly formed Delaware limited liability company (“EEH”), Lynden USA, Inc., a Utah corporation (“Lynden USA”), an existing subsidiary of Earthstone, Lynden USA Operating, LLC, a newly formed Texas limited liability company (all wholly-owned subsidiaries of the Company), Bold Energy Holdings, LLC, a Texas limited liability company (“Bold Holdings”), and Bold Energy III LLC, a Texas limited liability company (“Bold”).

Under the Bold Contribution Agreement, the terms of which were unanimously approved by a special committee of disinterested members of the Company’s Board of Directors and the full Board (i) the Company will recapitalize the Common Stock into two classes, consisting of Class A and Class B, and all of its existing Common Stock will be converted into Class A common stock. Bold Holdings will purchase approximately 36.1 million shares of the Company’s Class B common stock for nominal consideration, with the Class B common stock having no economic rights in the Company other than voting rights on a pari passu basis with the Class A common stock. In addition, EEH will issue approximately 22.3 million of its membership units to the Company and Lynden USA, in the aggregate, and approximately 36.1 million membership units to Bold Holdings in exchange for each of the Company, Lynden USA and Bold Holdings transferring all of their assets to EEH; and (iii) each Bold Holdings’ membership unit in EEH, together with one share of Bold Holdings Class B common stock, will be convertible into Class A common stock on a one-for-one basis. Therefore, upon the closing of Bold Contribution Agreement, stockholders of the Company and unitholders of Bold Holdings are expected to own approximately 39% and 61%, respectively of the combined company’s then outstanding Class A and Class B common stock on a fully diluted basis. After closing, the Company expects conduct its activities through EEH and will be its sole managing member. The Bold Contribution Agreement is expected to close in the second quarter of 2017 and is subject to approval of the Company’s stockholders and other customary closing conditions.

In May 2016, we acquired Lynden Energy Corp. (“Lynden”) in an all-stock transaction. The acquisition was made through an arrangement (the “Lynden Arrangement”) instead of a merger because Lynden is incorporated in British Columbia, Canada. The Company acquired all the outstanding shares of common stock of Lynden through a newly formed Company subsidiary, with Lynden surviving in the Lynden Arrangement as a wholly-owned subsidiary of the Company. The Company issued 3,700,279 shares of its common stock to the holders of Lynden common stock in the Lynden Arrangement.

~~Non-Recent Acquisitions~~

In December 2014, we acquired three operating subsidiaries of Oak Valley Resources, LLC, a privately-held Delaware limited liability company (“OVR”), in exchange for shares of our Common Stock (the “Exchange”), which resulted in a change of control. Pursuant to the Exchange Agreement, OVR contributed to us the membership interests of its three subsidiaries, Earthstone Operating,

LLC (formerly Oak Valley Operating, LLC) (“OVO”), EF Non-Op, LLC (“EF Non-Op”) and Sabine River Energy, LLC (“Sabine”), each a Texas limited liability company (collectively “Oak Valley”), in exchange for approximately 9.124 million shares, representing 84% of our Common Stock. The Exchange was accounted for as a reverse acquisition whereby Oak Valley was considered the acquirer for accounting purposes. All historical financial information contained in this report is that of Oak Valley. Upon the closing of the Exchange, we changed our fiscal year from March 31 to December 31, ~~in order for~~2019, our ~~fiscal year end to correspond with the fiscal year end of OVR and its subsidiaries.~~

~~Immediately following the Exchange, we acquired an additional 20% undivided ownership interest in certain crude~~estimated proved oil and natural gas ~~properties located~~reserves were approximately 94,336 MBOE based on the reserve report prepared by Cawley, Gillespie & Associates, Inc. (“CG&A”), our independent petroleum engineers. Based on this report, at December 31, 2019, our proved reserve quantities were approximately 56% oil, 19% natural gas, 25% NGLs with 33% of those reserves classified as proved developed. The calculated percentages include proved developed non-producing reserves. Of these interests, approximately 51,426 MBOE are attributable to noncontrolling interests. See Note 9.Noncontrolling Interest in ~~Fayette and Gonzales Counties, Texas, in exchange for~~ the issuance of approximately 2.957 million shares of our Common Stock (the “Flatonia Contribution Agreement”) to Flatonia Energy, LLC (“Flatonia”), increasing our ownership in these properties from a 30% undivided ownership to a 50% undivided ownership interest. As a result of the share issuance to Flatonia, OVR’s ownership in us decreased from 84% to 66%.

~~For further discussion of the above closed acquisitions, see~~ ~~Note 3. Acquisitions and Divestitures~~ ~~within the~~ Notes to Consolidated Financial ~~Statements~~ Statements.~~included in Item 8 of this report.~~

Our Business Strategy

~~We pursue a value-driven growth~~

Our current business strategy ~~focused on projects that we believe will generate strong and predictable rates of return and increases in stockholder value. Although we currently have significant non-operated properties, our intent~~ is to ~~operate~~focus on the majority of our properties in order to control costs and direct the efficient development of such properties in an effort to optimize investment returns and profitability. Historically, we have operated the majority of our assets and implemented our strategy in multiple basins in order to enable us to benefit from regional changes and differences in realized prices, service costs, service availability and numerous other factors that would enhance the timely, cost-efficient and economic development of our ~~assets,~~existing acreage, increase our acreage and ~~lead to greater rates of return. This multi-basin strategy could change~~horizontal well locations in the ~~future~~Midland Basin and ~~we could focus all or a majority of~~increase stockholder value through the following:

developing our ~~capital expenditures in a single basin, as a result of acquisitions, project economics~~acreage and ~~capital market considerations. Management concentrates on building~~profitably growing our production ~~reserves and cash flows~~ while seeking to ~~expand~~achieve Free Cash Flow (defined in “Non-GAAP Measures” below);

operating our ~~undeveloped acreage~~properties efficiently and continuing to improve our operating margins;

deploying capital efficiently by drilling ~~inventory. Further expansion~~multi-well pads, reducing drilling times and increasing completions per day;

operating our assets in a safe and environmentally sensitive manner;

continuing to hedge commodity prices as opportunities arise;

pursuing value-accretive acquisition and corporate merger opportunities, which could increase the scale of our ~~asset base will be achieved through cost efficient development, exploitation~~operations;

maximizing operating margins and ~~operation of our current assets~~corporate level cash flows by minimizing operating and acreage and through additional leasing, acquisitions, development, drilling and, to a lesser extent, exploration activities, currently directed toward unconventional oil-weighted projects. Finally, management intends to pursue corporate and asset acquisition opportunities.

~~Our business strategy includes the following:~~

~~pursuing value-accretive corporate merger and acquisition opportunities;~~

overhead costs;

expanding our ~~operated~~ acreage positions and drilling inventory in our primary areas of ~~primary~~ interest through acquisitions and farm-in ~~opportunities;~~

opportunities, with an emphasis on operated positions;

~~continuing the cost-effective development and exploitation of our existing~~blocking up acreage ~~positions;~~

to allow for longer horizontal lateral drilling locations which provide higher economic returns; and

~~generating additional development projects in our areas of primary interest;~~

~~divesting non-core assets in order to streamline operations and utilize capital and human resources most effectively;~~

maintaining a strong balance sheet and ~~capital structure;~~financial flexibility.

Our Strengths

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

extensive horizontal development potential in one of the most oil rich basins of the United States;

experienced management team with substantial technical and

operational expertise;

ability to attract technical personnel with experience in our core area of operations;

~~obtaining additional capital, as needed~~history of successful acquisition and ~~available, through~~merger transactions;

operating control over the ~~issuance~~majority of ~~equity and debt securities or by soliciting industry or financial participants to jointly develop and/or acquire assets~~

~~Our fundamental operating and technical strategy is complemented by~~ our ~~focus on increasing stockholder value by our efforts in:~~

~~maximizing profit margins;~~

~~controlling capital expenditures and operating and administrative costs; and~~

~~promoting industry or institutional participants into projects to manage risk, enhance rates of return and lower net finding~~production and development ~~costs.~~

activities;

conservative balance sheet; and

~~Management believes~~

commitment to cost efficient operations.

2019 Highlights

In addition to our drilling program described above, the following are additional highlights of our 2019 activities compared to activity in 2018:

Full year 2019 average daily sales volumes of 13,429 Boepd exceeded our production goals and increased 35%

Increased drilling efficiencies by drilling multi-well pads and longer lateral length wells averaging 10,700 feet in the Midland Basin

Improved frac efficiency from 8 to 12 stages per day

Reduced total drilling and completion costs by approximately 16%

Increased Proved Developed reserves by 33%

Increased Adjusted EBITDAX by 51% (reconciled in “Non-GAAP Measures” below)

Improved our operating margins by 10%

Realized $15.9 million from our hedge positions thereby mitigating commodity price volatility

Strong balance sheet and liquidity position with $155 million of undrawn capacity on a $325 million senior secured revolving credit facility and a cash balance of $13.8 million as of December 31, 2019

Recent Developments

Sharp Decline in Oil Prices

Subsequent to December 31, 2019, oil prices have declined sharply in response to drastic price cutting and increased production by Saudi Arabia coupled with reduced demand caused by the global coronavirus outbreak. Prior to the recent decline in oil prices, we announced our 2020 capital budget of $160-170 million which assumed a one-rig operated program in the Midland Basin as well as non-operated activity currently in progress, which was expected to result in bringing 19 gross / 16.2 net operated wells and 3.1 net non-operated wells online in 2020. Due to the recent oil price volatility, we are currently evaluating our 2020 capital program.

New Credit Agreement

On November 21, 2019, we entered into a new credit agreement with respect to our senior secured revolving credit facility (the “Credit Agreement”). The Credit Agreement has a maturity date of November 21, 2024 with a maximum credit amount of $1.5

billion and an initial borrowing base of $325 million. The Credit Agreement replaced the prior credit agreement, which was terminated on November 21, 2019.

Officer Appointments

On January 30, 2020, we announced that our current Chairman and Chief Executive Officer, Mr. Frank A. Lodzinski, will be appointed Executive Chairman and our current President, Mr. Robert J. Anderson, will be appointed Chief Executive Officer and President, effective on April 1, 2020.

Organizational Structure

Earthstone is the sole managing member of EEH, with a controlling interest in EEH. Earthstone, together with its ~~strategy is appropriate because it~~ ~~addresses multiple risks~~wholly-owned subsidiary, Lynden Energy Corp., a corporation organized under the laws of ~~oil~~British Columbia (“Lynden Corp”), and ~~natural gas operations while providing equity holders with upside potential~~Lynden Corp’s wholly-owned consolidated subsidiary, Lynden USA, Inc. (“Lynden US”) and also a member of EEH, consolidates the financial results of EEH and records a noncontrolling interest in ~~“staying power,” which management believes is essential to mitigate~~ the ~~adverse impacts~~Consolidated Financial Statements representing the economic interests of ~~historically volatile commodity prices~~EEH’s members other than Earthstone and ~~financial markets.~~

Lynden US.

Our Operations

We are currently the operator of properties containing approximately 38% 92% of our proved oil and natural gas reserves and ~~58%~~89% of our proved PV-10 as of December 31, ~~2016~~2019 (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 drilling and completion 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 and cost fluctuations. Our status as an operator has allowed us to pursue the development of undeveloped acreage, further develop existing properties and generate new ~~projects that we believe have the potential to increase stockholder value.~~

projects.

As is common in our industry, we selectively participate in drilling and developmental activities in non-operated ~~properties on a selective basis.~~properties. 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.

~~Description of Major Properties~~

~~The following is a brief description of our primary oil and natural gas properties:~~

~~Midland Basin~~

We have a non-operated position of approximately 5,900 net acres in the Midland Basin of west Texas. At present, our most active area within the basin is the horizontal Wolfcamp play occurring in Howard, Glasscock, Martin and Midland Counties, Texas. We have approximately 112 gross vertical and 5 gross horizontal producing wells with an average working interest of approximately 40% that are primarily operated by Crownquest Operating, LLC. We have identified approximately 180 gross horizontal locations in various benches of the Wolfcamp and Lower Spraberry as well as approximately 118 gross vertical wells that have potential in the Clearfork, Spraberry, Wolfcamp, Strawn and Fusselman formations.

Upon the closing of the Bold Contribution Agreement, we expect to have an operated position in approximately 20,900 net acres in the core of the Midland Basin across Reagan, Upton, Midland, Glasscock, Howard and Martin counties. The acreage is approximately 99% operated with an average working interest of approximately 85%. Current internal estimates indicate approximately 500 gross, largely de-risked operated drilling locations, the vast majority of which are in certain benches of the Wolfcamp A and B formation in the Lower Spraberry formation. Based on industry drilling and production operations additional locations may be proven to be economic, primarily in Reagan and Upton counties, in added benches in the Wolfcamp A, B and C and other formations.

~~Eagle Ford Basin~~

~~Operated Eagle Ford~~

As of December 31, 2016, we owned approximately 36,000 gross (17,600 net) 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, Upper Eagle Ford, Buda, Wilcox and Edwards formations. We serve as the operator with a range of approximately 25% to 50% undivided ownership interest in substantially all of the acreage.

As of December 31, 2016, we operated 70 gross Eagle Ford wells and 9 gross Austin Chalk wells and had non-operated interests in two gross producing Eagle Ford wells and one gross producing Austin Chalk well. We have identified a total of approximately 140 gross Eagle Ford drilling locations in this acreage. The number of Eagle Ford locations could potentially increase subject to future down spacing initiatives and successful implementation of slickwater enhanced completions. In addition, because our acreage position is prospective for the Austin Chalk, Upper Eagle Ford, Buda, Wilcox and Edwards 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, which is being used to develop the Eagle Ford and identify Austin Chalk locations and other economic opportunities.

~~Non-Operated Eagle Ford~~

We have a non-operated position in approximately 25,500 gross (2,900 net) acres in two areas within the Hawkville Field in La Salle County, Texas. The acreage is operated by BHP Billiton and Lewis Petro Properties, Inc. and is prone to natural gas and condensate produced from the Eagle Ford formation. The two areas are summarized below:

White Kitchen – We have an average working interest of approximately 12% in approximately 7,100 gross acres, all of which is held by production. As of December 31, 2016, 30 gross wells were producing, and we have identified approximately 40 additional drilling locations.

Martin Ranch – We have a 10% working interest in approximately 18,000 gross acres. As of December 31, 2016, 31 gross wells were producing, and we have identified approximately 140 potential drilling locations in the acreage.

~~Williston Basin~~

We have a non-operated position in approximately 9, 300 net acres in the Williston Basin of North Dakota. At present, our most active area within the basin is the Banks Field in McKenzie County, North Dakota. In the Banks Field, we have an average working interest of approximately 3.9% in 99 gross horizontal Bakken/Three Forks producing wells that are primarily non-operated. We have an additional 13 gross wells waiting on completion in the Banks Field with an average working interest of approximately 5%. We have identified approximately 210 gross potential drilling locations which are in existing producing units throughout the Bakken/Three Forks play.

~~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.

~~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.

Operational Risks

Oil and natural gas exploitation, development and production ~~involves~~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 ~~acquire~~ 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.

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, 2019, three purchasers accounted for 30%, 14% and 12%, respectively, of our revenue during the period. For the year ended December 31, 2018, three purchasers accounted for 27%, 11% and 10%, respectively, of our revenue during the period. No other customer accounted for more than 10% of our revenue during these periods. If a major customer stopped 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 prospective and productive units and acreage, we consider required flow-lines, gathering and delivery infrastructure. Our oil is transported from the wellhead to our tank batteries or delivery points through our flow-lines or gathering systems. Purchasers of our oil take delivery at (i) our tank batteries and transport the oil by truck, or (ii) at a pipeline delivery point. Our natural gas is transported from the wellhead to the purchaser’s meter and pipeline interconnection point through our gathering systems. We have implemented a Leak Detection and Repair program, or LDAR, to locate and repair leaking components including valves, pumps and connectors in order to minimize the emission of fugitive volatile organic compounds and hazardous air pollutants. In addition, we have started installing vapor recovery units in our newer tank batteries.

In October 2019, we entered into a buy/sell arrangement for a certain portion of our oil production that effects a change in location with required repurchase of oil at a delivery point. This activity is recorded on a net basis and the residual transportation fee is included in Lease operating expenses in the Consolidated Statements of Operations. Arrangements such as this not only reduce our transportation costs by eliminating truck transportation but also provide additional flexibility in delivery points for our product. The decrease in transportation by truck also translates into reduced truck emissions.

Our produced salt water is generally moved by pipeline connected to our operated salt water disposal wells or by pipeline to commercial disposal facilities.

Commodity Hedging

Consistent with our disciplined approach to financial management, we have an active commodity hedging program through which we seek to hedge a meaningful portion of our expected oil and gas production, reducing our exposure to downside commodity prices and enabling us to protect cash flows and maintain liquidity to fund our capital program.

Competition

The domestic oil and natural gas industry is intensely competitive in the acquisition of acreage, production and oil and gas reserves and in producing, transporting and marketing activities. 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, and our ability to fund the acquisition of such properties, 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, development and production. 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, completion and production 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.

Markets for Sale of Production

Our ability to market oil and natural gas found and produced, depends 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 we 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, including constrained pipeline capacity. Specifically, increased domestic and foreign production and increased efficiencies in horizontal drilling and completion, combined with increased development of 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:

royalties and other burdens and obligations, express or implied, under oil and natural gas leases;

overriding royalties and other burdens created by us or our predecessors in title;

a variety of contractual obligations (including, in some cases, development obligations) arising under operating agreements, farmout agreements, participation agreements, production sales contracts and other agreements that may affect the properties or their titles;

back-ins and reversionary interests existing under ~~purchase~~various agreements and leasehold assignments;

liens that arise in the normal course of operations, such as those for unpaid taxes, statutory liens securing obligations to unpaid suppliers and contractors and contractual liens under operating agreements; ~~as well as~~

pooling, unitization and ~~communitization~~other agreements, declarations and orders; and

easements, restrictions, rights-of-way and other matters that commonly affect property.

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 ~~size~~quantity and value of our reserves. We believe that the burdens and obligations affecting our oil and natural gas properties are ~~conventional~~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 ~~regulating the exploration, development~~affecting drilling, completion, and production activities, ~~related~~including, but not limited to, ~~oil and natural gas, 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 ~~exploration and/or~~ development, ~~while~~ other states including Texas, where we operate, rely primarily

or exclusively on voluntary pooling of land and leases. ~~In areas where pooling is primarily or exclusively voluntary,~~Accordingly, it may be difficult for us to form spacing units and therefore difficult to develop a project if ~~the operator owns~~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 FERC or state policies and regulations or laws may adversely affect the availability and reliability of firm and/or interruptible transportation service on interstate pipelines, and we cannot predict what future action that FERC or state regulatory bodies 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 ~~commonly referred to as the EPA,~~(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 ofor 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 ~~address various aspects of~~affect our business including oil and natural gas exploration ~~development~~ 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 ~~business,~~ financial condition orand 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.

Hazardous Substances and Wastes

The federal Comprehensive Environmental Response, Compensation, and Liability Act ~~referred to~~of 1980 (“CERCLA”), also known as ~~CERCLA or~~ the Superfund law, and comparable state laws impose liability, without regard to fault or the legality of the original conduct on certain ~~classes~~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 ~~disposal~~ site or sites where the release occurred and companies that disposed or arranged for the disposal of hazardous substances ~~that have been released~~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 ~~some~~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.

~~Under~~ We are able to control directly the ~~federal Solid Waste Disposal Act,~~operation of only those wells with respect to which we act as ~~amended~~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 ~~referred to as~~(“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 ~~generated by~~associated with the exploration, development and production of oil and natural gas are ~~not~~currently regulated ~~as hazardous waste. Periodically, however, there are proposals~~under RCRA’s solid (non-hazardous) waste provisions. However, legislation has been proposed from time to ~~lift~~time and various environmental groups have filed lawsuits that, if successful, could result in the ~~existing exemption for~~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 ~~reclassify them~~clean-up requirements. A loss of the RCRA exclusion for drilling fluids, produced waters and related wastes could result in an increase in our, as ~~hazardous~~well as the oil and natural gas E&P industry’s, costs to manage and dispose of generated wastes, ~~or subject them to enhanced solid waste regulation. If such proposals were to be enacted, they~~which could have a ~~significant impact~~material adverse effect on the industry as well as on our operating costs and on those of all the industry in general. In the ordinary course of our operations moreover, some wastes generated in connection with our exploration, development and production activities may be regulated as solid waste under RCRA, as hazardous waste under existing RCRA regulations or as hazardous substances under CERCLA. 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

~~Our operations are also subject to the~~

The federal Clean Water Act and analogous state ~~laws. Under~~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, the EPA and U.S. Army Corps of Engineers (the “Corps”) rule defining the scope of federal jurisdiction over Waters of the United States (the “WOTUS rule”) became effective. Following the change in U.S. Presidential Administrations, there have been several attempts to modify or eliminate this rule. For example, on January 23, 2020, the EPA and the Corps finalized the Navigable Waters Protection Rule, which narrows the definition of “waters of the United States” relative to the prior 2015 rulemaking. However, legal challenges to the new rule are expected, and multiple challenges to the EPA’s prior rulemakings remain pending. As a result of these developments, the scope of jurisdiction under the Clean Water Act is uncertain at this time.

The process for obtaining permits has the ~~EPA has adopted regulations concerning discharges~~potential to delay our operations. Spill prevention, control and countermeasure requirements of ~~storm water runoff. This program requires covered facilities~~federal laws require appropriate containment berms and similar structures to ~~obtain~~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 ~~seek~~ coverage under a general ~~permit. Some of our properties may require~~ permits for discharges of storm water ~~runoff. We believe that we will be able to obtain,~~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 ~~be included under, these permits, where necessary,~~other requirements of the Clean Water Act and ~~make minor modifications to existing facilities~~analogous state laws and ~~operations that would not have a material effect on us.~~regulations. The Clean Water Act and ~~similar~~analogous state ~~acts regulate other discharges of wastewater, oil, and other pollutants to surface water bodies, such as lakes, rivers, wetlands, and streams. Failure to obtain permits~~laws provide for ~~such discharges could result in~~administrative, civil and criminal penalties ~~orders to cease such~~for unauthorized discharges and, ~~costs to remediate and pay natural resources damages. These laws also require the preparation and implementation of Spill Prevention, Control, and Countermeasure Plans in connection~~together with ~~on-site storage of significant quantities of oil. In the event of a discharge of oil into U.S. waters we could be liable under~~ the Oil Pollution Act of 1990 (“OPA”), impose rigorous requirements for ~~clean-up~~spill prevention and response planning, as well as substantial potential liability for the costs of removal, remediation, and damages ~~and economic losses.~~

in connection with any unauthorized discharges.

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”) ~~regulations promulgated under the SDWA~~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. In Texas, the Texas Railroad Commission (“RRC”) regulates the disposal of produced water by injection well. 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 response to recent seismic events near underground injection wells used for the disposal of oil and natural gas-related waste waters, federal and some state agencies have begun investigating whether such wells have caused increased seismic activity, and some states have shut down or placed volumetric injection limits on existing wells or imposed moratoria on the use of such injection wells. In response to concerns related to induced seismicity, regulators in some states have already adopted or are considering additional requirements related to seismic safety. For example, the RRC has adopted rules for injection wells to address these seismic activity concerns in Texas. Among other things, the rules require companies seeking permits for disposal wells to provide seismic activity data in permit applications, provide for more frequent monitoring and reporting for certain wells and allow the RRC to modify, suspend, or terminate permits on grounds that a disposal well is likely to be, or determined to be, causing seismic activity. More stringent regulation of injection wells could lead to reduced construction or the capacity of such wells, which could in turn impact the availability of injection wells for disposal of wastewater from our operations. Increased costs associated with the transportation and disposal of produced water, including the cost of complying with regulations concerning produced water disposal, may reduce our profitability. The costs associated with the disposal of proposed water are commonly incurred by all oil and natural gas producers, however, and we do not believe that these costs will have a material adverse effect on our operations. 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 ~~and oil~~ 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.

~~Under~~

The SDWA regulates the ~~direction~~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 ~~completed a study finding~~has taken the position 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. The EPA has also finalized pre-treatment standardswith fluids containing diesel fuel is subject to regulation under the ~~Clean Water Act for wastewater discharges from shale hydraulic fracturing operations to municipal sewage treatment plants. Beyond that, several environmental groups have petitioned~~UIC program, specifically as “Class II” UIC wells.

In addition, on June 28, 2016, the EPA ~~to extend toxic release reporting requirements under~~published a final rule prohibiting the ~~Emergency Planning and Community Right-to-Know Act to the~~discharge of wastewater from onshore unconventional oil and natural gas extraction ~~industry~~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 ~~require disclosure~~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.

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 ~~Toxic Substances Control Act~~use of ~~chemicals used~~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. ~~Congress might likewise consider legislation~~These ongoing or proposed studies could spur initiatives to ~~amend the federal SDWA~~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.

Several states, including Texas, 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. For example, Texas law requires that the well operator disclose the list of chemical ingredients subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) for disclosure on a website and also file the list of chemicals with the RRC with the well completion report. The total volume of water used byto hydraulically fracture a well must also be disclosed to the ~~oil~~public and ~~natural gas industry in~~filed with the RRC. If new or more stringent state or local legal restrictions relating to the hydraulic fracturing ~~process. Certain states, including Colorado, Utah~~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 ~~Wyoming, already have issued similar disclosure rules.~~

~~In addition, the Department of the Interior~~perhaps even be precluded from drilling wells.

There has ~~promulgated regulations concerning~~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 ~~on lands under its jurisdiction, which includes lands on which we conduct~~practices. If new laws or ~~plan to conduct operations. States similarly have been imposing new restrictions or bans on hydraulic fracturing. Even local jurisdictions have adopted, or tried to adopt,~~ regulations ~~restricting hydraulic fracturing. Additional~~that significantly restrict hydraulic fracturing ~~requirements~~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, ~~may limit~~ our ~~ability~~fracturing activities could become subject to ~~operate~~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 ~~increase~~the consequences of any failure to comply by us could have a material adverse effect on our ~~operating costs.~~

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.

From time to time, legislation has been introduced, but not enacted, in the U.S. Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process. In addition, certain candidates running for the office of President of the United States in 2020 have pledged to ban hydraulic fracturing and, on January 28, 2020, one of those candidates introduced Senate Bill 3247 that, if enacted as proposed, would ban hydraulic fracturing nationwide by 2025.

Air Emissions

The federal Clean Air Act (“CAA”) and comparable state laws ~~regulate~~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 ~~federal Clean Air Act~~CAA 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 ~~air regulations for the oil and natural gas industry that address~~New Source Performance Standards to regulate emissions ~~from certain new~~of sources of volatile organic compounds (“VOCs”), sulfur dioxide, air toxics and ~~methane. The rules include the first federal air standards for~~methane from various oil and natural gas ~~wells~~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 rule making 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. Following the change in U.S. Presidential Administrations, there have been attempts to modify these regulations. Most recently, in August 2019, the EPA proposed amendments to the 2016 standards that, among other things, would remove sources in the transmission and storage segment from the oil and natural gas source category and rescind the methane-specific requirements applicable to sources in the production and processing segments of the industry. As an alternative, the EPA also proposed to rescind the methane-specific requirements that apply to all sources in the oil and natural gas industry, without removing the transmission and storage sources from the current source category. Under either alternative, the EPA plans to retain emissions limits for VOCs for covered oil and natural gas facilities and equipment. Legal challenges to any final rulemaking that rescinds the 2016 standards are ~~hydraulically fractured, or refractured,~~expected. 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, ~~for other processes and~~or mandate the use of specific equipment ~~including storage tanks. Compliance~~or technologies to control emissions. We cannot predict the final regulatory requirements or the cost to comply with ~~these regulations has imposed additional~~such requirements ~~and costs on our operations. The EPA also has started to consider whether to extend such regulations to existing wells.~~

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. ~~Implementation will take place over several years; however,~~Since that time, the ~~new standard~~EPA has issued area designations with respect to ground-level ozone. Reclassification of areas of state implementation of the revised NAAQS could result in ~~a significant expansion~~stricter permitting requirements, delay or prohibit our ability to obtain such permits, and result in increased expenditures for pollution control equipment, the costs of ~~ozone nonattainment~~which could be significant.

Climate Change

In response to findings that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) endanger public health and the environment, the EPA has adopted regulations under existing provisions of the CAA that, among other things, establish construction and operating permit reviews for GHG emissions certain large stationary sources, require the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the United States, implement New Source Performance Standards directing the reduction of methane from certain new, modified, or reconstructed facilities in the oil and natural gas sector, and together with the Department of Transportation (the “DOT”), implement GHG emissions limits on vehicles manufactured for operation in the United States. Additionally, various states and groups of states have adopted or are considering adopting legislation, regulations or other regulatory initiatives that are focused on such areas ~~across~~as GHG cap and trade programs, carbon taxes, reporting and tracking programs, and restriction of emissions. At the international level, there is an agreement, the United Nations-sponsored “Paris Agreement,” for nations to limit their GHG emissions through non-binding, individually-determined reduction goals every five years after 2020, although the United States has announced its withdrawal from such agreement, effective November 4, 2020.

Governmental, scientific, and public concern over the threat of climate change arising from GHG emissions has resulted in increasing political risks in the United States, including ~~areas in which we operate. Oil and natural gas operations in ozone nonattainment areas would likely be subject to increased regulatory burdens in~~climate change related pledges made by certain candidates seeking the ~~form of more stringent emission controls, emission offset requirements, and increased permitting delays and costs.~~

~~Climate Change~~

~~Studies over recent years have indicated that emissions of certain gases may be contributing to warming~~office of the ~~Earth’s atmosphere. In response to these studies, governments have been adopting domestic and international climate change regulations that require reporting and reductions~~President 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 several countries including those comprising the European Union, have established greenhouse gas regulatory systems. In the United States atin 2020. Two critical declarations made by one or more candidates running for the ~~state level, many states, either individually or through multi-state regional initiatives, have been implementing legal measures~~Democratic nomination for President include threats to ~~reduce emissions~~take actions banning hydraulic fracturing of greenhouse gases, primarily through emission inventories, emissions 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 EPA has issued regulations requiring us and other companies to annually report certain greenhouse gas emissions from our~~ oil and natural gas ~~facilities. Beyond its measuring~~wells and ~~reporting rules,~~banning new leases for production of minerals on federal properties, including onshore lands and offshore waters. Other actions that could be pursued by presidential candidates may include the ~~EPA has issued an “Endangerment Finding” under Section 202(a)~~imposition of more restrictive requirements for the establishment of pipeline infrastructure or the permitting of liquefied natural gas (“LNG”) export facilities, as well as the reversal of the ~~Clean Air Act, concluding greenhouse~~United States’ withdrawal from the Paris Agreement in November 2020. Litigation risks are also increasing, as a number of cities and other local governments have sought to bring suit against the largest oil and natural gas ~~pollution threatens~~exploration and production companies in state or federal court, alleging, among other things, that such companies created public nuisances by producing fuels that contributed to global warming effects, such as rising sea levels, and therefore are responsible for roadway and infrastructure damages, or alleging that the companies have been aware of the adverse effects of climate change for some time but defrauded their investors by failing to adequately disclose those impacts.

There are also increasing financial risks for fossil fuel producers as shareholders currently invested in fossil-fuel energy companies concerned about the potential effects of climate change may elect in the future to shift some or all of their investments into non-energy related sectors. Institutional lenders who provide financing to fossil-fuel energy companies also have become more attentive to sustainable lending practices and some of them may elect not to provide funding for fossil fuel energy companies. Additionally, the lending practices of institutional lenders have been the subject of intensive lobbying efforts in recent years, oftentimes public ~~health~~in nature, by environmental activists, proponents of the international Paris Agreement, and ~~welfare~~foreign citizenry concerned about climate change not to provide funding for fossil fuel producers. Limitation of ~~current~~investments in and ~~future generations.~~ financings for fossil fuel energy companies could result in the restriction, delay or cancellation of drilling programs or development or production activities.

The ~~finding served as the first step to issuing~~adoption and implementation of new or more stringent international, federal or state legislation, regulations or other regulatory initiatives that ~~require permits~~impose more stringent standards for ~~and reductions in greenhouse gas emissions for certain facilities.~~

~~In addition, the Obama Administration developed a Strategy to Reduce Methane Emissions that was intended to result by 2025 in a 40-45% decrease in methane~~GHG emissions from the oil and natural gas ~~industry as compared to 2012 levels. Consistent with that strategy,~~sector or otherwise restrict the ~~EPA issued its air rules~~areas in which this sector may produce oil and natural gas or generate GHG emissions could result in increased costs of compliance or costs of consuming, and thereby reduce demand for, oil and natural ~~gas production sources,~~gas. Additionally, political, litigation and ~~the federal Bureau of Land Management (“BLM”) promulgated standards for reducing venting and flaring on public lands.~~

~~Any laws~~financial risks may result in us restricting 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 control systems or other compliance costs, and reduce demand for our products.

~~The National Environmental Policy Act~~

~~Oil and natural gas exploration, development and~~cancelling production activities, ~~may be subject~~incurring liability for infrastructure damages as a result of climatic changes, or having an impaired ability to ~~the National Environmental Policy Act,~~continue to operate in an economic manner. One or ~~NEPA. NEPA requires federal agencies, including the Department~~more of ~~the Interior, to evaluate major agency actions that~~these developments could have ~~the potential to significantly impact the environment. In the course~~a material adverse effect on our business, financial condition and results of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. This process has the potential to delay the development of future oil and natural gas projects.

operation.

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 (“MBTA”) and the Clean Water Act. The ~~United States~~U.S. Fish and Wildlife Service (“FWS”) may designate critical habitat areas that it believes are necessary for survival of threatened or endangered species. As a result of a 2011 settlement agreement, the FWS was required to determine whether to identify more than 250 species as endangered or threatened under the FSA by no later than completion of the agency’s 2017 fiscal year. The FWS missed the deadline but reportedly continues to review new species for protected status under the ESA pursuant to the settlement agreement. 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. Moreover, as a result of a settlement approved by the U.S. District Court for the District of Columbia in September 2011, the U.S. Fish and Wildlife Service is required to make a determination on listing of more than 250 species as endangered or threatened under the ESA by no later than completion of the agency’s 2017 fiscal year. Similar protections are offered to migratory birds under the ~~Migratory Bird Treaty Act.~~MBTA. Recently, there have been renewed calls to review protections currently in place for the dunes sagebrush lizard, whose habitat includes portions of the Permian Basin, and to reconsider listing the species under the ESA. 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 MBTA, 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~~MBTA to several oil and natural gas companies after dead migratory birds were found near reserve pits associated with drilling activities. However, in January 2020, the Department of Interior proposed new regulations clarifying that only the intentional taking of protected migratory birds is subject to prosecution under the MTBA. 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 ~~including, but not limited to, the federal Emergency Planning and Community Right-to-Know Act~~ and may require that information be provided to state and local government authorities, as well as the public.

Occupational Safety and Health Act

We are subject to ~~the requirements~~a number of ~~the~~ federal ~~Occupational Safety~~ and ~~Health Act~~state laws and regulations, including OSHA, and comparable state statutes that regulate the protection of the health and safety of workers. In 2016, there were substantial revisions to the regulations under OSHA that may have an impact to our operations. These changes include among other items; record keeping and reporting, revised crystalline silica standard (which requires the oil and gas industry to implement engineering controls and work practices to limit exposures below the new limits by June 23, 2021), naming oil and gas as a high hazard industry and requirements for a safety and health management system. In addition, ~~the Occupational Safety and Health Administration’s~~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.~~

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 2019, nor do we anticipate that such expenditures will be material in 2020.

Employees

As of December 31, ~~2016,~~2019, we had 4869 full-time employees, ~~and one part-time employee; 9~~of which 11 are management, 1322 are technical personnel, 1517 are administrative personnel and 1219 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

As of

~~We lease~~December 31, 2019, we leased office space as set forth in the following table:

~~Location~~

Location	Approximate Size	Lease Expiration Date	Intended Use
The Woodlands, Texas	19,600 sq. ft.	~~December~~March 31, ~~2019~~ 2025	Office
~~Denver, Colorado~~ Midland, Texas	~~7,000~~9,200 sq. ft.	~~April~~June 30, ~~2018~~ 2022	Office

During ~~2016,~~2019, aggregate rental payments for our office facilities totaled approximately $0.8 million.

Information about our Executive Officers

The following table sets forth, as of March 1, 2020, certain information regarding the executive officers of Earthstone:



Name	Age	Position
Frank A. Lodzinski	70	Chairman of the Board and Chief Executive Officer
Robert J. Anderson	58	President
Tony Oviedo	66	Executive Vice President, Accounting and Administration
Mark Lumpkin, Jr.	46	Executive Vice President and Chief Financial Officer
Steven C. Collins	55	Executive Vice President, Completions and Operations
Timothy D. Merrifield	64	Executive Vice President, Geological and Geophysical

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

Frank A. Lodzinski has served as our Chairman and Chief Executive Officer since December 2014. He also served as our President from December 2014 through April 2018. Previously, he served as President and Chief Executive Officer of Oak Valley Resources, LLC (“Oak Valley”) from its formation in December 2012 until the closing of its strategic combination with Earthstone in December 2014. Prior to his service with Oak Valley, 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 Oak Valley. 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 nominating and governance committee, audit committee and compensation committee of Yuma Energy, Inc. since April 2019 and previously served on its audit committee from September 2014 to October 2016 and its compensation committee from October 2016 to April 2019. 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 President since April 2018. From December 2014 through April 2018, he served as our Executive Vice President, Corporate Development and Engineering. Previously, he served in a similar capacity with Oak Valley from March 2013 until the closing of its strategic combination with the Company in December 2014. Prior to joining Oak Valley, 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 the Company, 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.

Mark Lumpkin, Jr. has over 22 years of experience including over 15 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 30 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 Oak Valley from its formation in December 2012 until the closing of its strategic combination with the Company in December 2014. 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 39 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 Oak Valley from its formation in December 2012 until the closing of its strategic combination with the Company in December 2014. Prior to employment by Oak Valley, 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.

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 Securities and Exchange Commission (“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).SEC. 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.

I~~tem~~

Item 1A. Risk Factors

Our business is subject to various risks and uncertainties in the ordinary 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, $0.001 par value per share (“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.

Oil, natural gas and natural gas liquids prices ~~have been historically~~are volatile. Their prices at times since 2014 have adversely affected, and in the future may ~~continue to~~ adversely affect, our business, financial condition and results of operations and ~~may in the future affect~~ our ability to meet our capital expenditure obligations and financial ~~commitments as well as~~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, ~~2016,~~2019, the ~~WTI futures~~West Texas Intermediate (“WTI”) spot price for oil declined from a high of ~~$107.26~~$107.95 per Bbl onin June ~~20,~~ 2014 to ~~$26.21~~$26.19 per Bbl onin February ~~11, 2016, and the~~2016. The Henry Hub ~~futures~~spot price for natural gas has declined from a high of ~~$6.15~~$8.15 per MMBtu onin February ~~19,~~ 2014 to a low of ~~$1.64~~$1.49 per MMBtu onin March 3, 2016. During 2019, WTI spot prices ranged from $46.31 to $65.96 per Bbl and the Henry Hub spot price of natural gas ranged from $1.75 to $4.25 per MMBtu. 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 ~~suffered~~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~~:

including:

worldwide, regional and ~~regional~~local economic and financial conditions impacting ~~global and regional~~ supply and demand;

the level of global exploration, development and production;

the level of global supplies, in particular due to supply growth from the United States;

~~foreign and domestic supply capabilities;~~

the price and quantity of ~~U.S.~~oil, natural gas and NGLs imports to and exports ~~including liquefied natural gas;~~

from the U.S.;

political conditions in or affecting other oil, natural gas and natural gas liquids producing countries and regions, including the current conflicts in the Middle East, ~~as well as conditions in South America, Africa, Ukraine~~Asia and ~~Russia;~~

Eastern Europe;

actions of the OPEC and state-controlled oil companies relating to production and price controls;

the extent to which U.S. shale producers become ~~Swing Producers~~swing producers adding or subtracting to the world supply totals;

future regulations prohibiting or restricting our ability to apply hydraulic fracturing to our wells;

current and future regulations regarding well spacing;

prevailing prices and pricing differentials on local oil, natural gas and natural gas liquids price indices in the areas in which we operate;

localized and global supply and demand fundamentals and transportation, gathering and processing availability;

weather conditions;

technological advances affecting fuel economy, energy supply and energy consumption;

the effect of energy conservation measures, alternative fuel requirements and increasing demand for alternatives to oil and natural gas;

global or national health concerns, including health epidemics such as the coronavirus outbreak at the beginning of 2020;

the price and availability of alternative fuels; and

domestic, local and foreign governmental regulation and taxes.

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 ~~our agreement providing for a senior secured revolving credit facility (the “Credit Agreement”),~~the Credit Agreement, our borrowing base is subject to semi-annual redeterminations ~~(May~~(on or about May 1 and November 1) and ~~the~~our lenders have the right to call for an interim determination of the borrowing base under certain ~~specified~~ 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 Credit Agreement to the extent our outstanding borrowings exceed the redetermined borrowing base and ~~cold~~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 ~~further~~ decline in the market price of our ~~shares~~.

shares.

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

Accounting rules require that we periodically review the carrying value of our proved and unproved 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 ~~further,~~significantly write-down the financial carrying value of our oil and natural gas properties, which constitutes a non-cash charge to earnings.

~~Oil,~~ 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 have been significantly lower than they were in mid-2014. If those~~ 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 6.7. Oil and Natural Gas Properties to ~~our consolidated financial statements~~the Notes to Consolidated Financial Statements included in this report for additional information.

Any significant reduction in our borrowing base under ~~our~~the 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 ~~our~~the Credit Agreement or any other obligation if required as a result of a borrowing base ~~redetermination~~.

redetermination.

Availability under ~~our~~the Credit Agreement is currently subject to a borrowing base of ~~$80.0~~$325.0 million. The borrowing base is subject to scheduled semiannual redeterminations ~~(May~~(on or about May 1 and November 1), as well as other ~~elective~~lender-elective borrowing base redeterminations. The lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under ~~our~~the 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 ~~our~~the Credit Agreement (if prices are kept constant). Reductions in our borrowing base under ~~our~~the Credit Agreement could also arise from other factors, including but not limited to:

lower commodity prices or production;

increased leverage ratios;

inability to drill or unfavorable drilling results;

changes in oil, natural gas and natural gas liquids reserve engineering techniques;

increased operating and/or capital costs;

the ~~lenders'~~lenders’ inability to agree to an adequate borrowing base; or

adverse changes in the ~~lenders'~~lenders’ practices (including required regulatory changes) regarding estimation of reserves.

The Board, in reviewing and assessing the contributions of Mr. Thielemann to the Board, determined that his extensive experience in the oil and gas industry, including serving on the boards of private oil and gas exploration and production companies provide significant contributions to the Board. As a managing director at EnCap, Mr. Thielemann is uniquely positioned to provide the Board with insight and advice on a full range of strategic, financial and governance matters.

~~Zachary G. Urban~~ has served as a director since December 2014. Since January 2014, Mr. Urban has served as CEO at Vlasic Group, which is a private investment company with holdings in a wide variety of asset classes. Prior to being named CEO, Mr. Urban held the position of Managing Director of Investments at Vlasic Group from 2011 through 2013. At Vlasic Group, Mr. Urban has responsibility for a full spectrum of investment disciplines, including asset allocation, investment strategy, direct investments, manager selection, due diligence, and performance measurement. From 2001 to 2011, Mr. Urban worked at Donnelly Penman & Partners (“DP&P”), a regional investment bank. At DP&P, Mr. Urban specialized in merger and acquisition transactions, business valuations, financial advisory, due diligence services, and capital raising for middle market public and private clients. Prior to his time at DP&P, Mr. Urban also worked in the Corporate Value Consulting practice of PricewaterhouseCoopers LLP, where he focused on business valuation services, strategic consulting, and corporate finance consulting for public and private companies, including multinational and Fortune 500 clients. Mr. Urban holds the Chartered Financial Analyst (CFA) designation and graduated from the Honors College of Michigan State University with a B.A. degree in Finance with High Honor.

The Board, in reviewing and assessing the contributions of Mr. Urban to the Board, determined that his extensive investment experience across diverse industries as CEO of the Vlasic Group provide significant contributions to the Board. In addition, his prior experience as an investment banker will enable Mr. Urban to provide the Board with insight and advice on a full range of general business and financial matters.

~~Robert L. Zorich~~ has served as a director since December 2014. Mr. Zorich is a Managing Partner and co-founder of EnCap Investments L.P. He serves on the firm’s up-stream investment and management committees and has been actively involved in all aspects of the firm’s management and growth since its inception in 1988. EnCap is a leading private equity firm focused on the up-stream and midstream sectors of the oil and gas industry in North America, having raised 19 institutional oil and gas investment funds, totaling in excess of $27 billion of capital. Over its history, the firm has created over 220 oil and gas companies and currently manages capital on behalf of more than 250 U.S. and international investors, including public and private pension funds, insurance companies, sovereign wealth funds, university endowments and foundations. Prior to the formation of EnCap, Mr. Zorich was a Senior Vice President in charge of the Houston office of Trust Company of the West, then a large, privately-held pension manager. Previously, Mr. Zorich co-founded MAZE Exploration, Inc., a private oil and gas company headquartered in Denver. For the first seven years of his career, Mr. Zorich was employed by Republic Bank as a Vice President and Division Manager in the energy group. Mr. Zorich serves on the boards of several EnCap portfolio companies. He is also a member of the Board of Directors of Eclipse Resources Corporation and previously served on the board of Oasis Petroleum Inc. and its predecessor entities from March 2007 until March 2012. In addition, he serves on the investment committee of EnCap Flatrock Midstream. Mr. Zorich’s community involvement includes serving as a member of the Leadership Cabinet of Texas Children’s Hospital, as well as serving on the boards of the Workfaith Connection and the Memorial Assistance Ministries Endowment. He is a member of the Independent Petroleum Association of America, the Houston Producers’ Forum and Texas Independent Producers and Royalty Owners Association. Mr. Zorich holds a B.A. in Economics from the University of California at Santa Barbara and a Master’s Degree in International Management (with distinction) from the American Graduate School of International Management in Phoenix, Arizona.

The Board, in reviewing and assessing the contributions of Mr. Zorich to the Board, determined that his significant experience with financing, forming, and guiding numerous oil and gas companies while serving as a co-founder and managing partner of EnCap provide significant contributions to the Board. His insights and relationships should prove valuable towards guiding corporate strategies and pursuing growth opportunities.

There are no arrangements or understandings between any of Messrs. Lodzinski, Singleton, Joliat, Kramer, Swanson, Thielemann, Urban and Zorich, or any other person pursuant to which such person was selected as a director. None of Messrs. Lodzinski, Singleton, Joliat, Kramer, Swanson, Thielemann, Urban and Zorich has any family relationship with any director or other executive officer of the Company or any person nominated or chosen by the Company to become a director or executive officer.

~~Section 16(a) Beneficial Ownership Reporting Compliance~~

Section 16(a) of the Exchange Act requires the Company’s directors and certain executive officers, and persons who beneficially own more than ten percent of our common stock, to file initial reports of ownership and reports of changes in ownership of our common stock and our other equity securities with the SEC. As a practical matter, the Company assists its directors and officers by monitoring transactions and completing and filing Section 16 reports on their behalf. Based solely on a review of the copies of such forms in our

possession and on written representations from reporting persons, we believe that during 2016 all of our named executive officers, directors and greater than ten percent holders filed the required reports on a timely basis under Section 16(a) of the Exchange Act.

~~Code of Business Conduct and Ethics~~

Our Board adopted a Code of Business Conduct and Ethics (“Code of Ethics”), which provides general statements of our expectations regarding ethical standards that we expect our directors, officers and employees to adhere to while acting on our behalf. Among other things, the Code of Ethics provides that:

~~we will comply with all laws, rules and regulations;~~

~~our directors, officers, and employees are to avoid conflicts of interest and are prohibited from competing with the Company or personally exploiting our corporate opportunities;~~

~~our directors, officers, and employees are to protect our assets and maintain our confidentiality;~~

~~we are committed to promoting values of integrity and fair dealing; and~~

~~we are committed to accurately maintaining our accounting records under generally accepted accounting principles and timely filing our SEC periodic reports and our tax returns.~~

~~Our Code of Ethics also contains procedures for employees to report, anonymously or otherwise, violations of the Code of Ethics.~~

~~Board of Directors and Committees~~

~~General~~

On December 19, 2014, following the closing of the Exchange Agreement, and as required by the Exchange Agreement, the Company expanded the size of its Board from four to seven members. At closing of the Exchange Agreement, our directors, other than Ray Singleton, resigned from our Board and Frank A. Lodzinski, Jay F. Joliat, Douglas E. Swanson, Jr., Brad A. Thielemann, Zachary G. Urban, and Robert L. Zorich were appointed as directors to serve on the Board until their successors are duly elected and qualified. Also, our former officers resigned from their positions as of the closing of the Exchange Agreement. In October 2016, our Board expanded the size of the Board to eight members and appointed Phil D. Kramer as a Class III director.

Our Amended and Restated Certificate of Incorporation provides for the classification of the Board into three classes with staggered three-year terms. Messrs. Singleton and Lodzinski serve as Class I directors. Messrs. Swanson, Thielemann and Urban serve as Class II directors, and Messrs. Joliat, Kramer and Zorich serve as Class III directors.

We are committed to high quality corporate governance, which helps us compete more effectively, sustain our success and build long-term stockholder value. The Board reviews the Company’s policies and business strategies, and advises and counsels the executive officers who manage the Company.

~~The full text of the charter of our Audit Committee and our Code of Ethics can be found at www.earthstoneenergy.com. Copies of these documents also may be obtained from our Corporate Secretary.~~

Governance is a continuing focus at the Company, starting with the Board and extending to management and all employees. The Company is governed by a Board of Directors and committees of the Board that meet throughout the year. Directors discharge their responsibilities at Board and committee meetings and also through telephone contact and other communications with management.

~~Director Attendance~~

During 2016, our Board held three meetings and all of our directors at the time attended all of the meetings either in person or telephonically. In addition, the Board acts from time to time by unanimous written consent in lieu of holding a meeting. During 2016, the Board effected 18 actions by unanimous written consent.

We do not have a formal policy regarding our Board members’ attendance at the annual meeting of stockholders. In 2016, Mr. Lodzinski and members of management attended our annual meeting of stockholders along with certain members of our Board that dialed in telephonically.

~~Formerly a Controlled Company~~

In 2015, our Board determined that we were a “controlled company” as defined under the corporate governance rules of the NYSE MKT since more than 50% of our issued and outstanding common stock was then held by OVR. As a “controlled company,” we were exempt from certain rules otherwise applicable to companies whose securities are listed on the NYSE MKT, including: (a) the requirement that the Company have a majority of independent directors; (b) the requirement that nominations to the Board be either selected or recommended by a nominating committee consisting solely of independent directors; and (c) the requirement that the Company’s officers’ compensation be either determined or recommended by a compensation committee consisting solely of independent directors. As a result of our equity offering in June 2016, our Board determined that we ceased to be a “controlled company” as defined under the corporate governance rules of the NYSE MKT. Accordingly, the Company will need to have a majority of the members of its Board be “independent” as defined under the corporate governance rules of the NYSE MKT within one year of no longer being a “controlled company.”

~~Board Leadership~~

Our Board is responsible for the control and direction of the Company. The Board represents the Company’s stockholders and its primary purpose is to build long-term stockholder value. Mr. Lodzinski serves as Chairman of the Board, President and Chief Executive Officer of the Company. The Board believes that Mr. Lodzinski is best situated to serve as Chairman because he is the director most familiar with the Company’s business and industry and is also the person most capable of effectively identifying strategic priorities and leading the discussion and execution of corporate strategy. In this combined role, Mr. Lodzinski is able to foster clear accountability and effective decision making. The Board believes that the combined role of Chairman and Chief Executive Officer strengthens the communication between the Board and management and provides a clear roadmap for stockholder communications. Further, as the individual with primary responsibility for managing day-to-day operations, Mr. Lodzinski is best positioned to chair regular Board meetings and ensure that key business issues and risks are brought to the attention of our Board and the Audit Committee. We therefore believe that the creation of a lead independent director position is not necessary at this time.

~~Stockholder-Recommended Director Candidates~~

The Board is responsible for identifying individuals qualified to become Board members and nominees for directorship are selected by the Board. The Board takes into account many factors, including general understanding of marketing, finance and other disciplines relevant to the success of a publicly traded company in today’s business environment; understanding of the Company’s business on a technical level; and educational and professional background. The Board evaluates each individual in the context of the Board as a whole, with the objective of recommending a group that can best support the success of the business and, based on its diversity of experience, represent stockholder interests through the exercise of sound judgment.

Although the Board is willing to consider candidates recommended by our stockholders, it has not adopted a formal policy with regard to the consideration of any director candidates recommended by our stockholders. The Board believes that a formal policy is not necessary or appropriate because the current Board already has a diversity of business background and industry experience. Additionally, the Board does not have a formal diversity policy in place for the director nomination process, but instead considers diversity of a candidate’s viewpoints, professional experience, education and skill set as a factor in the consideration and assessment of a candidate as set forth above.

In accordance with our Bylaws, stockholders wishing to recommend a director candidate to serve on the Board may do so by providing advance written notice to the Board, which identifies the candidate and includes the information described below. The notice should be sent to the following address: Earthstone Energy, Inc., Attention: Corporate Secretary, 1400 Woodloch Forest Drive, Suite 300, The Woodlands, Texas 77380. The mailing envelope should contain a clear notation indicating that the enclosed letter is a “Director Nomination Recommendation.”

~~The notice must contain the following information as to each proposed nominee:~~

~~name, age, business address and residence address of the nominee;~~

~~principal occupation or employment of the nominee;~~

~~class or series and number of shares of our capital stock that are owned beneficially or of record by the nominee; and~~

any other information relating to the nominee that would require disclosure in a proxy statement or other filings required to be made in connection with solicitations of proxies for election of directors pursuant to Section 14 of the Exchange Act.

~~The notice must also contain the following information as to the stockholder giving the notice:~~

~~name and record address of such stockholder;~~

~~class or series and number of shares of our capital stock that are owned beneficially or of record by such stockholder;~~

all other ownership interests of such stockholder relating to us, including derivatives, hedged positions, synthetic and temporary ownership techniques, swaps, securities, loans, timed purchases and other economic and voting interests;

a description of all arrangements or understandings between such stockholder and each proposed nominee and any other person or persons (including their names) pursuant to which the nomination(s) are to be made by such stockholder;

~~a representation that such stockholder intends to appear in person or by proxy at the meeting to nominate the persons named in such stockholder’s notice; and~~

any other information relating to such stockholder that would require disclosure in a proxy statement or other filings required to be made in connection with solicitations of proxies for election of directors pursuant to Section 14 of the Exchange Act.

In addition to the foregoing requirements, such notice must be accompanied by a written consent of each proposed nominee to being named as a nominee and to serve as a director if elected. Each proposed nominee will be required to complete a questionnaire, in a form to be provided by us, to be submitted with the stockholder’s notice. We may also require any proposed nominee to furnish such other information as we may reasonably require in order to determine the eligibility of such proposed nominee to serve as an independent director or that could be material to a reasonable stockholder’s understanding of the independence, or lack thereof, of such nominee.

~~Board Committees~~

To assist it in carrying out its duties, the Board has delegated certain authority to an Audit Committee as its functions are described below. Each member of the Audit Committee has been determined by the Board to be “independent” for purposes of the listing standards of NYSE MKT and the rules of the SEC, including the heightened “independence” standard required for members of the Audit Committee.

~~Audit Committee~~

The Audit Committee provides oversight of the Company’s accounting policies, internal controls, financial reporting practices and legal and regulatory compliance. Among other things, the Audit Committee appoints our independent auditor and evaluates its independence and performance; maintains a line of communication between the Board, our management and the independent auditor; and oversees compliance with the Company’s policies for conducting business, including ethical business standards.

The members of our Audit Committee during 2016 were Jay F. Joliat (Chairperson) and Zachary G. Urban. On January 6, 2016, Mr. Thielemann was appointed to the Audit Committee. On October 12, 2016, Mr. Kramer was appointed to the Audit Committee and Mr. Thielemann resigned from the Audit Committee. During 2016, the Audit Committee held four meetings. The Board has determined that Mr. Joliat is an “audit committee financial expert” as that term is defined in the listing standards of NYSE MKT and the applicable rules of the SEC.

~~Compensation Committee~~

Our Board does not have a separate compensation committee. After the Company ceased being a “controlled company” in June 2016, all material compensation decisions related to the named executive officers of the Company will be made by the independent directors serving on the Board.

~~Nominating Committee~~

Our Board does not have a separate nominating committee. After the Company ceased being a “controlled company” in June 2016, all decisions relating to the nomination of directors to the Board will be made by the independent directors serving on the Board.

~~Compensation Committee Interlocks and Insider Participation~~

Our Board does not have a separate compensation committee. None of our executive officers serve or have served on the compensation committee of any entity that has one or more of its executive officers serving as a member of our Board. Our President and Chief Executive Officer, Frank A. Lodzinski has participated in discussions with our Board regarding the compensation of our executive officers; however, he is not present during discussions regarding his compensation.

Item 11. Executive Compensation

~~Overview~~

The ~~following Compensation Discussion and Analysis, or CD&A, provides~~ information about the compensation program for our principal executive officer, principal accounting officer and our other three most highly-compensated executive officers (collectively, the “named executive officers” or “NEOs”), andrequired by this item is intended to place in perspective the information contained in the executive compensation tables that follow this discussion. This CD&A provides a general description of the material elements of our compensation program and specific information about its various components. As of June 2016, our independent directors will determine any material changesincorporated herein by reference to the ~~compensation of our named executive officers. See “Board of Directors and Committees” above.~~

Although this CD&A focuses on the information in the tables below and related footnotes, as well as the supplemental narratives relating to the fiscal year ended December 31, 2016, we also describe compensation actions taken after the last completed fiscal year to the extent it enhances the understanding of our named executive officer compensation disclosure.

~~Compensation Philosophy and Objectives~~

~~We operate in a highly competitive and challenging environment and must retain, attract and motivate talented individuals~~2019 Proxy Statement, which will be filed with the ~~requisite technical and managerial skills to pursue our business strategy. The objectives of our compensation program are to:~~

~~Encourage growth in our oil and natural gas reserves and production;~~

~~Encourage growth in cash flow and profitability;~~

~~Mitigate risks in our business related to compensation by balancing fixed compensation with short-term and potentially long-term incentive compensation; and~~

~~Enhance total stockholder returns through a compensation program that attracts and retains highly qualified executive officers.~~

~~Elements of Our Compensation Program~~

~~Element~~	~~Characteristics~~	~~Primary Objective~~
~~Base Salary~~	~~Cash~~	~~Retain and attract highly talented individuals~~
~~Short-Term Incentives~~	~~Cash bonus~~	~~Reward for individual and corporate performance~~
~~Long-Term Incentives~~	~~Equity awards vesting over a period of time or based on performance metrics~~	Align the interests of our employees and shareholders by providing employees with incentive to perform technically and financially in a manner that promotes share price appreciation. The Board is currently evaluating the use of long-term incentives.
~~Other Benefits~~	~~401(k) matching plans and employee health benefit plans~~	~~Provide benefits that promote employee health and support employees in attaining financial security~~

~~Base Salary.~~ Base salary is the principal fixed component of our compensation program, and has historically been reviewed in the first quarter of each year. It is intended to provide our named executive officers with a regular source of income to compensate them for their day-to-day efforts in managing the Company. Base salary is primarily used to retain and attract highly talented individuals. Base salary varies depending on the named executive officer’s experience, responsibilities, education, professional standing in the industry, changes in the competitive marketplace and the importance of the position to the Company.

Due to low commodity prices prevailing in the oil and gas industry, no salary increases were granted to named executive officers or other staff in 2015 or 2016. In January 2016, the Board and our Chief Executive Officer further considered the continued low commodity prices and, with the approval of our Board, implemented certain company-wide staffing and salary reductions, effective

February 1, 2016. These salary reductions applied to most officers and employees, except where an officer or employee assumed significant added responsibility. The following table shows the base salaries for our named executive officers in 2016 and 2017.

2016

2017

Name

Base Salary ($)

Base Salary ($)

Frank A. Lodzinski

229,500

229,500

Robert J. Anderson

235,000

235,000

Timothy D. Merrifield

211,500

211,500

Ray Singleton

207,900

207,900

G. Bret Wonson⁽¹⁾

167,000

—

Tony Oviedo ⁽²⁾

—

220,000

~~(1)~~

~~Resigned effective February 9, 2017.~~

~~(2)~~

~~Appointed Executive Vice President – Accounting and Administration effective February 9, 2017.~~

~~Elements of Our Compensation Program~~

~~Short-Term Incentives.~~ Short-term incentive compensation is the short-term variable portion of our compensation program and is based on the principle of pay-for-performance. Short-term incentives have historically been reviewed in the first quarter of each year or at the end of the fourth quarter. The objective of short-term incentives is to reward our named executive officers based on the performance of the Company as a whole and the contributions of the individual named executive officer in relation to our success. The Company hasSEC not paid any material short-term incentives, for the years ended December 31, 2015 or 2016, although the named executive officers did participate in bonuses totaling 5% of base salary paid to all employees in December of 2016.

~~Long-Term Incentives.~~ Long-term incentives may be awarded to our named executive officers under the Earthstone Energy, Inc. 2014 Long-Term Incentive Plan (the “2014 Plan”), which was originally approved by our stockholders in December 2014. Under our 2014 Plan, the Board has the flexibility to choose among a number of forms of long-term incentive compensation, including stock options, stock appreciation rights, restricted stock awards, restricted stock units, performance units, performance shares, or other incentive awards. In the past, the Company has granted restricted stock awards to employees and non-employee directors under prior Company equity plans.

On June 1, 2016, the Board approved awards of restricted stock units (“RSUs”) to our named executive officers after considering that the base salary levels of our named executive officers are well below industry peers and further considering that no short-term incentives were paid for 2015. The following table shows the restricted stock unit awards granted to our named executive officers on June 1, 2016:

Name

Number of RSUs Vesting on
January 1, 2017

Aggregate Number of
RSUs Vesting on a
Monthly Basis
Beginning on
January 31, 2017

Total

Frank A. Lodzinski

50,000

100,000

150,000

Robert J. Anderson

25,000

50,000

75,000

Timothy D. Merrifield

23,500

46,500

70,000

Ray Singleton

21,500

43,500

65,000

G. Bret Wonson^*

8,334

16,666

25,000

The restricted stock unit award for Mr. Wonson would have vested as to one-third on April 1, 2017 and the remaining two-thirds would have vested in 24 equal monthly installments beginning on April 30, 2017. However, Mr. Wonson resigned from all positions with the Company in February 2017, forfeiting all RSU’s.

~~Other Benefits~~. All employees may participate in our 401(k) Retirement Savings Plan (“401(k) Plan”). Each employee may make before-tax contributions in accordance with the limits established by the Internal Revenue Service. We provide our 401(k) Plan to help our employees attain financial security by providing them with a program to save a portion of their cash compensation for retirement in a tax efficient manner. Our matching contribution is an amount equal to 100% of the employee’s elective deferral contribution not to exceed 6% of the employee’s compensation. Due to low commodity prices, effective April 1, 2016, matching contributions were suspended.

All full time employees, including our named executive officers, may participate in our health and welfare benefit programs, including medical, dental and vision care coverage, disability insurance and life insurance.

~~Roles of our CEO and the Board~~

Our Board has overall responsibility for the compensation of our named executive officers. The Board monitors our director and named executive officer compensation and benefit plans, policies and programs to insure that they are consistent with our compensation philosophy and objectives, along with our corporate governance guidelines. Our Chief Executive Officer, Mr. Lodzinski, makes recommendations to the Board regarding the base salary, short-term and long-term incentive compensation with respect to the named executive officers (otherlater than himself) based on his analysis and assessment of their performance. Such officers are not present at the time of these deliberations. The Board, in its discretion, may accept, modify or reject any or all such recommendations. The Board independently determines the salary, short-term and long-term incentive compensation for our Chief Executive Officer with limited input from him.

~~Factors Considered in Setting Executive Compensation~~

To achieve the objectives of our compensation program, the Board believes that the compensation of each of our named executive officers should reflect the performance of the Company as a whole and the contributions of the individual named executive officer in relation to our success. In other words, our compensation program is based on the idea of pay for performance. The following is a summary of the factors considered in setting compensation for our named executive officers in addition to the factors discussed above under each element of our compensation program.

~~Compensation Risks.~~ The Board reviewed the policies and practices of our compensation program, including, among other things, the types and level of our compensation in relation to the Company as a whole and on a per division basis and the fixed and variable aspects of our compensation. The Board does not believe that our compensation program encourages our named executive officers to take unreasonable risks related to our business. Based upon the Board’s review, the Board concluded that there are no compensation related risks that are reasonably likely to have a material adverse effect on the Company.

~~Lean Management Team.~~ ~~The Board takes into consideration that the Company operates with a lean management team requiring each named executive officer to have significant responsibilities.~~

~~Other Compensation Practices~~

~~Accounting and Tax Considerations.~~ Our Board reviews and takes into account current tax, accounting and securities regulations as they relate to the design of our compensation programs and related decisions. Section 162(m) of the Internal Revenue Code imposes a limit, with certain exceptions, on the amount that a publicly held corporation may deduct in any tax year for individual compensation to certain executives of such corporation exceeding $1,000,000 in any taxable year, unless the compensation is performance-based. We have no individuals with non-performance based compensation paid in excess of the Internal Revenue Code Section 162(m) tax deduction limit.

~~Stock Ownership Guidelines and Pledging Limitations.~~ We do not currently have ownership requirements or a stock retention policy for our named executive officers or non-management directors. The Board has adopted a policy requiring our named executive officers and members of the Board to obtain Board approval prior to pledging, or using as collateral, our common stock in order to secure personal loans or other obligations, which includes holding shares of our common stock in a margin account.

~~We will continue to review periodically best practices in this area and re-evaluate our position with respect to stock ownership guidelines and pledging limitations.~~

~~Clawback Provisions~~. Although we do not presently have any formal policies or practices that provide for the recovery of prior incentive compensation awards that were based on financial information later restated as a result of the Company’s material non-compliance with financial reporting requirements, in such event we reserve the right to seek all recoveries currently available under law. The Board has included a provision in our equity grant agreements whereby the equity grants to named executive officers are subject to any clawback policies the Company may adopt which may result in the reduction, cancellation, forfeiture or recoupment of such grants if certain specified events occur, including, but not limited to, any accounting restatement due to any material noncompliance with financial reporting regulations by the Company.

~~No Employment Agreements.~~ We have no employment contracts in place with any of our named executive officers, each of whom serve at the will of our Board. The company may consider employment contracts for named executive officers in the future.

~~Summary Compensation Table~~

~~The following table presents, for the years ended December 31, 2016 and 2015, for the nine month period from April 1, 2014~~120 days subsequent to December 31, 2014 (the “Stub Period”), and for the year ended March 31, 2014, the compensation of Mr. Lodzinski, our principal executive officer; Mr. Wonson, our principal financial officer during the years ended December 31, 2016 and 2015; and Messrs. Anderson, Merrifield and Singleton, our three most highly-compensated executive officers (other than the principal executive officer and principal financial officer) during the years ended December 31, 2016 and 2015 (collectively, the “named executive officers” or “NEOs”). There has been no compensation awarded to, earned by or paid to any employees required to be reported in any table or column in the fiscal years covered by any table, other than what is set forth in the following table:

Name and Principal Position

Year

Salary
($)

Bonus
($)

Stock
Awards⁽²)
($)

Non-equity
incentive plan
compensation⁽³)
($)

All Other
Compensation
($)

Total
($)

Frank A. Lodzinski

2016

$
231,625

$
11,475

$
1,833,000

$
—

$
3,810

$
2,079,910

President, Chairman and Principal Executive Officer

2015

$
255,000

$
—

$
—

$
—

$
3,185

⁽⁷⁾

$
258,185

Stub Period ⁽⁴⁾

$
8,543

$
100,000

⁽¹⁾

$
—

$
—

$
—

$
108,543

Robert J. Anderson

2016

$
235,000

$
11,750

$
916,500

$
—

$
3,525

$
1,166,775

Executive Vice President, Corporate Development and Engineering

2015

$
235,000

$
—

$
—

$
—

$
15,900

⁽⁸⁾

$
250,900

Stub Period ⁽⁴⁾

$
7,814

$
100,000

⁽¹⁾

$
—

$
—

$
545

⁽⁸⁾

$
108,359

Timothy D. Merrifield

2016

$
213,458

$
10,575

$
855,400

$
—

$
3,349

$
1,082,782

Executive Vice President, Geological and Geophysical

2015

$
235,000

$
—

$
—

$
—

$
15,900

⁽⁸⁾

$
250,900

Stub Period ⁽⁴⁾

$
7,844

$
95,000

⁽¹⁾

$
—

$
—

$
476

⁽⁸⁾

$
103,320

Ray Singleton ⁽⁵⁾

2016

$
209,825

$
10,395

$
794,300

$
—

$
3,234

$
1,017,754

Executive Vice President, Northern Region

2015

$
231,000

$
—

$
—

$
—

$
13,283

⁽⁸⁾

$
244,283

Stub Period

$
173,250

$
9,625

$
23,111

$
188,923

$
6,512

⁽⁶⁾

$
401,421

2014

$
231,000

$
—

$
22,044

$
188,923

$
9,495

⁽⁶⁾

$
451,462

G. Bret Wonson

2016

$
167,833

$
8,850

$
332,500

^$(9)
$
—

$
2,555

$
511,738

Chief Accounting Officer and Principal Financial Officer

2015

$
177,000

$
—

$
—

$
—

$
13,508

⁽⁸⁾

$
190,508

⁽¹⁾

~~Bonus amounts were earned prior to the closing of the Exchange Agreement; however, the Company paid the bonuses in January 2015.~~

2019.

⁽²⁾

Amount shown represents the grant date fair value of the shares of restricted stock granted during 2016, 2015 and 2014. These amounts were calculated based on the closing market price for our shares on the NYSE MKT on the date of grant.

⁽³⁾

Includes $188,923 earned for the fiscal year ended March 31, 2014, and $188,923 during the Stub Period under our performance bonus plan, which was paid in July 2014 but was related to performance for the year ended March 31, 2014.

⁽⁴⁾

~~Information for Mr. Lodzinski, Mr. Anderson and Mr. Merrifield represents the period from December 19, 2014, the date upon which they became employees of the Company, through December 31, 2014.~~

⁽⁵⁾

~~Mr. Singleton was the Company’s President and Chief Executive Officer during 2014 and for the Stub Period through the closing of the Exchange Agreement on December 19, 2014.~~

⁽⁶⁾

Amounts include (i) matching funds contributed by the Company to Mr. Singleton’s 401(k) plan account of $5,323 for the Stub Period, and $8,019 for the fiscal year ended March 31, 2014, and (ii) $1,189 for the Stub Period, and $1,476 for premiums paid by the Company on a life insurance policy for Mr. Singleton during fiscal year ended March 31, 2014, which provides for payment of a death benefit to Mr. Singleton’s designated beneficiary.

⁽⁷⁾

~~Amount shown represents premiums paid by the Company related to a life insurance policy for Mr. Lodzinski.~~

⁽⁸⁾

~~Amounts shown represent matching funds contributed by the Company to the officer’s 401(k) plan accounts.~~

⁽⁹⁾

~~Mr. Wonson resigned from all positions with the Company in February 2017. All of his outstanding RSUs were unvested and forfeited in connection with his resignation.~~

~~Outstanding Equity Awards at Year End~~

~~The following table provides information concerning unvested restricted stock awards and equity incentive plan awards for our named executive officers as of December 31, 2016.~~

Stock Awards

Name

Number of shares or units of
stock that have not vested (#) ⁽¹⁾

Market value of shares or units
of stock that have not vested
($) ⁽²⁾⁾

Frank A. Lodzinski

150,000

2,061,000

Robert J. Anderson

75,000

1,030,500

Timothy D. Merrifield

70,000

961,800

Ray Singleton

65,000

893,100

G. Bret Wonson

25,000

343,500

~~(1)~~

~~Represents restricted stock units granted in 2016 which vest monthly throughout 2017, with the exception of Mr. Wonson’s which were forfeited in February 2017 upon his resignation.~~

~~(2)~~

~~Amount shown represents the fair value of the shares of restricted stock based on the closing market price of our shares on the NYSE MKT on December 30, 2016, which was $13.74.~~

~~The table below shows the vesting dates for the respective unvested restricted stock units listed in the above Outstanding Equity Awards at Year End table:~~

Vesting date

Lodzinski

Anderson

Merrifield

Singleton

Wonson

January 1, 2017

50,000

25,000

23,500

21,500

—

12 equal monthly installments on the last day of the month, beginning January 31, 2017

8,333

4,167

3,875

3,625

—

April 1, 2017

—

—

—

—

8,334

24 equal monthly installments on the last day of the month, beginning April 30, 2017

—

—

—

—

694

~~Grants of Plan-Based Awards~~

The following table provides information about time-based restricted stock unit awards granted under the 2014 Plan to our named executive officers during the year ended December 31, 2016. For named executive officers other than Mr. Wonson, the restricted stock unit awards vest as to one-third of the award on January 1, 2017 and thereafter in 12 equal monthly installments beginning on January 31, 2017. Each restricted stock unit represents a continent right to one share of our common stock. Restricted stock units are generally settled and common shares issued on a quarterly basis shortly after the end of each calendar quarter.

Mr. Wonson resigned from all positions with the Company in February 2017. All of his outstanding RSUs were unvested and forfeited in connection with his resignation. One-third of the RSU award for Mr. Wonson was to vest on April 1, 2017 and the remaining two-thirds were to vest in 24 equal monthly installments beginning on April 30, 2017.

~~Employment Contracts and Termination of Employment~~

We do not have any employment agreements with our named executive officers. The restricted stock unit agreements under which we have granted restricted stock unit awards under the 2014 Plan contain provisions providing for accelerated vesting upon the death or

~~disability of the executive officer and upon termination of employment by the Company without cause or termination of employment by the executive officer for “good reason.”~~

For purposes of the restricted stock unit agreements, the term “good reason” means without the executive officer’s written consent (A) a material reduction in the executive officer’s authority, duties or responsibilities compared to the executive officer’s authority, duties and responsibilities as of the grant date; (B) the executive officer’s principal work location being moved more than 35 miles, from the Company’s current location in The Woodlands, Texas; (C) the Company or any of its subsidiaries materially reduces the executive officer’s base salary (unless the base salaries of substantially all other senior executives of the Company are similarly reduced); or (D) if the executive officer is a party to an employment agreement with the Company, any material breach of such employment agreement by the Company. Termination for good reason by the executive requires prior written to the Company and the opportunity for the Company to cure. For purposes of the restricted stock unit agreements, the term “~~Cause~~” means (A) the executive officer’s failure to perform (other than due to disability or death) the duties of the executive officer’s position (as they may exist from time to time) to the reasonable satisfaction of the Company or any of its subsidiaries after receipt of a written warning and at least fifteen (15) days’ opportunity for the executive officer to cure the failure, (B) any act of fraud or dishonesty committed by the executive officer against or with respect to the Company or any of its subsidiaries or customers as shall be reasonably determined to have occurred by the Board, (C) the executive officer’s conviction or plea of no contest to a crime that negatively reflects on the executive officer’s fitness to perform the executive officer’s duties or harms the Company’s or any of its subsidiaries’ reputation or business, (D) the executive officer’s willful misconduct that is injurious to the Company or any of its subsidiaries, or (E) the executive officer’s willful violation of a material Company or any of its subsidiaries policy.

~~Potential Payments Triggered Upon a Change in Control~~

We do not have any change in control or severance agreements with any named executive officer or director. The restricted stock unit agreements under which we have granted restricted stock unit awards under our 2014 Plan contain provisions providing for accelerated vesting upon a change in control. The amounts shown in the following table reflect the potential value to our named executive officers as of December 30, 2016, of unvested restricted stock unit awards where the vesting may accelerate upon a change in control of the Company. Consistent with SEC requirements, these estimated amounts have been calculated as if the change in control had occurred as of December 30, 2016, the last business day of 2016, and using the closing market price of our common stock on December 30, 2016 ($13.74 per share). The amounts below are estimates of the incremental amounts that would be received upon a change in control; the actual amount could be determined only at the time of any actual change in control.

~~Estimated Potential Payments Upon a Change in Control~~

Restricted Stock Units

Name

Unvested Restricted
Stock Units at 12/31/16
(#)

Total Value of Unvested
Restricted Stock Units that
May Accelerate Upon Change
in Control ($) ⁽¹⁾

Frank A. Lodzinski

150,000

2,061,000

Robert J. Anderson

75,000

1,030,500

Timothy D. Merrifield

70,000

961,800

Ray Singleton

65,000

893,100

G. Bret Wonson⁽²⁾

25,000

343,500

~~(1)~~

~~Amount shown represents the fair value of the shares of restricted stock based on the closing market price for our shares on the NYSE MKT on December 30, 2016, which was $13.74.~~

~~(2)~~

~~Mr. Wonson resigned from all positions with the Company in February 2017. All of his outstanding RSUs were unvested and forfeited in connection with his resignation.~~

~~Director Compensation~~

Directors who are employees of the Company receive no additional compensation for serving on the Board. On July 27, 2016, the Board adopted effective as of April 1, 2016, the following compensation program for two of the non-employee members of the Board, Jay F. Joliat and Zachary G. Urban: (i) an annual cash retainer of approximately $40,000, and (ii) an initial equity grant of 9,000 shares and annual equity grants, thereafter, with a fair market value of approximately $50,000 at the time of grant. In addition, the audit committee chair will be entitled to receive an additional $8,000 cash payment annually. On June 1, 2016, the Board granted Messrs. Joliat and Urban restricted stock unit awards under the 2014 Plan. In October 2016, the Board approved the above

compensation program for Mr. Kramer and granted a restricted stock award to him. Restricted stock units are generally settled and common shares issued on a quarterly basis shortly after the end of each calendar quarter.

~~Director Compensation in 2016~~

~~The following table sets forth the aggregate compensation paid to our non-employee directors during year ended December 31, 2016:~~

Name

Fees Earned or Paid in
Cash ($)

Stock Awards ⁽¹⁾ ($)

Total ($)

Jay F. Joliat

36,000

109,980

145,980

Phil D. Kramer

—

90,180

90,180

Douglas E. Swanson, Jr.

—

—

—

Brad A. Thielemann

—

—

—

Zachary G. Urban

30,000

109,980

139,980

Robert L. Zorich

—

—

—

~~(1)~~

~~Reflects the full grant date fair value of restricted stock unit awards granted in 2016 calculated in accordance with FASB ASC Topic 718. For a discussion of valuation assumptions, see~~ ~~Note 10. Stock Based Compensation~~, in the Notes to Consolidated Financial Statements included in this report. Messrs. Joliat, Kramer and Urban were granted 9,000 restricted stock units that vest as to 3,000 units on January 1, 2017 and the remaining 6,000 units in 12 equal monthly installments beginning on January 31, 2017. Each restricted stock unit represents the contingent right to receive one share of our common stock.

~~The following table presents the number of outstanding restricted stock units held by certain of our non-employee directors as of December 31, 2016:~~

~~Name~~	~~Number of Shares Subject to Restricted Stock Units~~ ~~Outstanding As of December 31, 2016~~
~~Jay F. Joliat~~		~~9,000~~
~~Phil D. Kramer~~		~~9,000~~
~~Douglas E. Swanson, Jr.~~		—
~~Brad A. Thielemann~~		—
~~Zachary G. Urban~~		~~9,000~~
~~Robert L. Zorich~~		—

I~~tem~~

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

The following table includes all holdings of our common stock as of March 1, 2017, of our directors and our named executive officers, our directors and named executive officers as a group, and all those knowninformation required by ~~us to be beneficial owners of more than five percent of our common stock. Unless otherwise noted, the mailing address of each person or entity named below~~this item is ~~1400 Woodloch Forest Drive, Suite 300, The Woodlands, Texas 77380.~~

Name

Common Stock ⁽¹⁾

Percent ⁽²⁾

Named Executive Officers:

Frank A. Lodzinski ⁽³⁾

107,834

^(3)(4)(5)
*

⁽³⁾
Robert J. Anderson ⁽³⁾

41,666

⁽³⁾⁽⁵⁾
*

⁽³⁾
Timothy D. Merrifield ⁽³⁾

39,000

⁽³⁾⁽⁵⁾
*

Ray Singleton ⁽⁶⁾

498,669

⁽⁵⁾

2.2
%

Tony Oviedo

—

—

Non-Management Directors:

Jay F. Joliat⁽³⁾

15,000

⁽⁵⁾
*

Phil D. Kramer

5,000

⁽⁵⁾
*

Douglas E. Swanson, Jr ⁽³⁾⁽⁷⁾

9,162,452

41.1
%

Brad A. Thielemann

—

—

Zachary G. Urban ⁽³⁾

5,000

⁽⁵⁾
*

Robert L. Zorich ⁽³⁾⁽⁷⁾

9,162,452

41.1
%

Officers and Directors as a Group (eleven persons):

9,874,621

44.3
%

Beneficial Owners of More than Five Percent:

Oak Valley Resources, LLC⁽³⁾⁽⁷⁾

9,162,452

41.1
%

Flatonia Energy, LLC ⁽⁸⁾

2,957,288

13.3
%

~~Less than one percent.~~

⁽¹⁾

This column lists beneficial ownership of voting securities as calculated under SEC rules. Otherwise, except to the extent noted below, each director, named executive officer or entity has sole voting and investment power over the shares reported. None of the shares are pledged as security by the named person.

⁽²⁾

~~The percentage is based upon 22,289,177 shares of common stock issued as of March 1, 2017~~.

⁽³⁾

These officers and directors own non-controlling membership interests in OVR. OVR directly owns 9,162,452 shares or 41.1% of our outstanding voting equity securities. Messrs. Lodzinski and Anderson are two of the five members of the board of managers of OVR. Entities affiliated with Messrs. Joliat and Urban are non-controlling members of OVR. Messrs. Anderson and Merrifield, and an entity controlled by Mr. Lodzinski are members of Oak Valley Management, LLC, which is a non-controlling member of OVR. Messrs. Lodzinski, Anderson, Merrifield, Joliat and Urban, and the entities affiliated with them, do not have the sole or shared power to vote or dispose of the shares of common stock held by OVR. Mr. Lodzinski is also a director of the Company. Additionally, Messrs. Swanson and Zorich serve as directors of the Company and as managers of OVR and do not have the sole or shared power to vote or dispose of the common stock held by OVR. Messrs. Swanson and Zorich are each a managing partner of EnCap Partners and may be deemed to beneficially own the reported securities held by OVR. Each of Messrs. Swanson and Zorich disclaim beneficial ownership of such securities, except to the extent of their respective pecuniary interest therein.

⁽⁴⁾

Includes 24,500 shares of common stock held in the name of Azure Energy, LLC (“Azure”). Mr. Lodzinski disclaims beneficial ownership of the shares held by Azure, except to the extent of his pecuniary interests therein.

⁽⁵⁾

Represents the following number of restricted stock units that have vested or will vest within 60 days of the date of this table with each restricted stock unit representing the contingent right to receive one share of our common stock: Mr. Lodzinski – 16,667; Mr. Anderson – 8,333; Mr. Merrifield – 7,750; Mr. Singleton – 7,250; Mr. Joliat – 1,000; Mr. Kramer – 1,000; Mr. Urban – 1,000; and all directors and named executive officers as a group – 43,584.

⁽⁶⁾

~~Mr. Singleton’s address is c/o Earthstone Energy, Inc., 633 Seventeenth Street, Suite 2320, Denver, Colorado 80202.~~

⁽⁷⁾

Five affiliated investment funds (the “EnCap Oak Valley Funds”), specifically EnCap Energy Capital Fund VII, L.P. (“EnCap Fund VII”), EnCap Energy Capital Fund VI, L.P. (“EnCap Fund VI”), EnCap VI-B Acquisitions, L.P. (“EnCap Fund VI‑B”), EnCap Energy Capital Fund V, L.P. (“EnCap Fund V”), and EnCap V-B Acquisitions, L.P. (“EnCap Fund V‑B”), each a Texas limited partnership, collectively own a majority of the membership interests of OVR and have the contractual right to nominate a majority of the members of the board of managers of OVR. Therefore, the EnCap Oak Valley Funds may be deemed to beneficially own all of the reported securities held by OVR. The EnCap Oak Valley Funds collectively own 57.3% of the membership interests of OVR. Accordingly, the EnCap Oak Valley Funds may be deemed to beneficially own the reported securities. EnCap Partners, LLC (“EnCap Partners”) is the managing member of EnCap Investments Holdings, LLC (“EnCap Holdings”), which is the sole member of EnCap Investments GP, L.L.C. (“EnCap Investments GP”), which is the general partner of EnCap, which is the general partner of EnCap Equity Fund VII GP, L.P. (“EnCap Fund VII GP”), EnCap Equity Fund VI GP, L.P. (“EnCap Fund VI GP”), and EnCap Equity Fund V GP, L.P. (“EnCap Fund V GP”). EnCap Fund VII GP is the general partner of EnCap Fund VII. EnCap Fund VI GP is the general partner of EnCap Fund VI. EnCap Fund VI GP is also the general partner of EnCap Energy Capital Fund VI-B, L.P. (“EnCap Capital Fund VI-B”), which is the sole member of EnCap VI-B Acquisitions GP, LLC (“EnCap VI-B Acquisitions GP”), which is the general partner of EnCap Fund VI-B. EnCap Fund V GP is the general partner of EnCap Fund V. EnCap Fund V GP is also the general partner of EnCap Energy Capital Fund V-B, L.P. (“EnCap Capital Fund V-B”), which is the sole member of EnCap V-B Acquisitions GP, LLC (“EnCap V-B Acquisitions GP”), which is the general partner of EnCap Fund V-B. Therefore, EnCap Partners, EnCap Holdings, EnCap Investments GP, EnCap, EnCap Fund VII GP, EnCap Fund VI GP, EnCap Fund V GP, EnCap Capital Fund V-B, EnCap Capital Fund VI-B, EnCap VI-B Acquisitions GP and EnCap V-B Acquisitions GP may be deemed to beneficially own the listed securities. Messrs. Swanson and Zorich do not have the sole or shared power to vote or dispose of our common stock held by the EnCap Oak Valley Funds. Messrs. Swanson and Zorich are each a managing partner of EnCap Partners and may be deemed to beneficially own the reported securities held by the EnCap Oak Valley Funds. Each of Messrs. Swanson and Zorich disclaim beneficial ownership of such securities except to the extent of their respective pecuniary interest therein. The address for the EnCap entities listed above is 1100 Louisiana Street, Suite 4900, Houston, Texas 77002.

⁽⁸⁾

Flatonia Holdings, LLC (“Flatonia Holdings”) is the direct and indirect owner of 100% of the membership interests of Flatonia Energy, LLC (“Flatonia”). Three affiliated entities, specifically Energy Recapitalization and Restructuring Fund, L.P. (“ERR”), ERR FI Flatonia Holdings, LLC (“ERR FI Flatonia Holdings”), and ERR FI II Flatonia Intermediate, L.P. (“ERR FI II Flatonia Intermediate”) collectively own 59.6% of the membership interests of Flatonia Holdings. ERR FI Flatonia Holdings is an indirect wholly owned subsidiary of Energy Recapitalization and Restructuring FI Fund, L.P. (“ERR FI”). ERR FI II Flatonia Intermediate is an indirect wholly owned subsidiary of Energy Recapitalization and Restructuring FI II Fund, L.P. (“ERR FI II” and, together with ERR and ERR FI, collectively, the “ERR Funds”). Parallel Resource Partners, LLC (“Parallel”) serves as the general partner of, and has the power to direct the affairs of, each of the ERR Funds. Parallel also serves as the manager of Flatonia Holdings and owns, directly or indirectly, 1.5% of the membership interests of Flatonia Holdings. The board of managers of Parallel consists of Clint D. Carlson, C. John Wilder, Jr., Ron Hulme, John K. Howie, and Jonathan Siegler. Together, Carlson Energy Partners I, LLC (“CEP I”) and Bluescape Energy Partners LLC (“BEP”) have the power to direct the affairs of Parallel. Additionally, CEP I and BEP each own 50% of the outstanding membership interests of Parallel. Together, Carlson Energy Corp. (“Carlson Corp”), Ron Hulme and John K. Howie have the power to direct the affairs of CEP I. Mr. Clint D. Carlson has the power to direct the affairs of Carlson Corp. Bluescape Resources Company LLC (“Bluescape Resources”) has the power to direct the affairs of BEP. Mr. C. John Wilder, Jr. has the power to direct the affairs of Bluescape Resources. The address of Flatonia is c/o Parallel Resource Partners, LLC, 919 Milam Street, Suite 550, Houston, Texas 77002.

~~Equity Compensation Plan Information~~

~~Long-Term Incentive Plan~~

In December 2014, the Company’s stockholders approved and adopted, effective on December 19, 2014, the 2014 Long-Term Incentive Plan (the “2014 Plan”), which remains in effect until December 18, 2024. In October 2015, the 2014 Plan was amended to increase the number of shares of the Company’s common stock authorized to be issued to 1,500,000. Under the 2014 Plan, the board of directors is authorized to grant stock options, restricted stock awards, restricted stock units, stock appreciation rights, performance units, performance bonuses, stock awards and other incentive awardsincorporated herein by reference to the ~~Company’s employees or those of its subsidiaries or affiliates as well as persons rendering consulting or advisory services and non-employee directors, subject~~2019 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to ~~the conditions set forth in the amended 2014 Plan.~~

~~The following table sets forth information with respect to the equity compensation plan available to non-employee directors, officers, employees and consultants at~~ December 31, ~~2016:~~

2019.

(a)

(b)

(c)

Plan Category

Number of
securities to
be issued upon
exercise of
outstanding
options,
warrants and
rights

Weighted
average
exercise
price of
outstanding
options,
warrants and
rights

Number of securities
remaining available
for future issuance
under equity
compensation plans
(excluding securities
reflected in column (a))

Equity compensation plans approved by security holders

781,500

$
12.53

718,500

Equity compensation plans not approved by security holders

—

$
—

—

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

~~Flatonia Energy, LLC~~

~~Flatonia Energy, LLC (“Flatonia”), a subsidiary of Parallel Resources, LLC (“PRP”), which owns approximately 13.3% of our common stock,~~

The information required by this item is a party to an industry standard joint operating agreement (the “Operating Agreement”) with Earthstone Operating, LLC (“OVO”) one of our wholly owned subsidiaries. This agreement was entered into priorincorporated herein by reference to the ~~closing of~~2019 Proxy Statement, which will be filed with the Flatonia Contribution Agreement on December 19, 2014 under which PRP acquired shares of our common stock. The Operating Agreement covers certain jointly owned oil and gas properties located in the Eagle Ford trend in Texas. During the year endedSEC not later than 120 days subsequent to December 31, 2016, Flatonia paid us $21.7 million as its share of joint operating costs associated with these properties which reflects charges by OVO for its direct costs and operating expenses under the joint Operating Agreement. During 2016, OVO paid $26.6 million to Flatonia for its share of net revenues associates with these properties.

~~Oak Valley Resources, LLC~~

Various members of our Board of Directors and management hold investments in entities that own membership interests in OVR. For instance, Mr. Lodzinski owns an approximate 28.4% interest in an entity that owns a 2.6% membership interest in OVR. Messrs. Swanson and Zorich are associated with EnCap Investments L.P., which advises the EnCap Funds, the majority investors in OVR. Messrs. Joliat and Urban own membership interests in OVR.

~~Policies and Procedures for Approval of Related Party Transactions~~

Our officers and directors are required to obtain Audit Committee approval for any proposed related party transactions. In addition, our Code of Ethics requires that each director, officer and employee must do everything he or she reasonably can to avoid conflicts of interest or the appearance of conflicts of interest. Our Code of Ethics states that a conflict of interest exists when an individual’s private interest interferes in any way or even appears to interfere with our interests and sets forth examples of the types of transactions that must be reported to our Board. Under our Code of Ethics, we reserve the right to determine when an actual or potential conflict of interest exists and then to take any action we deem appropriate to prevent the conflict of interest from occurring.

~~Director Independence~~

2019.

OVR, listed under the “Security Ownership of Certain Beneficial Owners and Management” section, holds stock representing a significant amount of our outstanding shares of common stock. From December 2014 to June 2016, we were a “controlled company” for purposes of the NYSE MKT rules and were not required to have a majority of independent directors on the Board or to comply with the requirements for compensation and nominating/governance committees. However, under the NYSE MKT transition rules, because we are no longer a controlled company, our Board must be comprised of a majority of independent directors within one year of June 21, 2016, the date on which we no longer qualified as a controlled company.

The current Board consists of eight directors, two of whom are currently employed by the Company (Messrs. Lodzinski and Singleton). In March 2017, the Board conducted an annual review and affirmatively determined that certain non-employee directors (Messrs. Joliat, Kramer, Thielemann and Urban) are “independent” as that term is defined in the listing standards of the NYSE MKT. The Board made a subjective determination as to each independent director that no relationship exists, which, in the opinion of the Board, would interfere with the exercise of independent judgment in carrying out the responsibilities of a director. In making these determinations, the Board reviewed and discussed information provided with regard to each director’s business and personal activities

as they may relate to the Company and its management. Further, the Board determined that Mr. Lodzinski is not independent because he is the President and Chief Executive Officer of the Company and Mr. Singleton is not independent because he is the Executive Vice President Northern Region. Further, the Board determined that Messrs. Swanson and Zorich are not independent because they are affiliates of OVR, which beneficially owns approximately 41.1% of our common stock. See “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.”

Item 14. Principal ~~Accountant~~Accounting Fees and Services

The ~~Audit Committee of~~information required by this item is incorporated herein by reference to the ~~Board of Directors has retained Grant Thornton LLP (“GT”) as our independent public accounting firm (our independent auditor). GT audited our consolidated financial statements for~~2019 Proxy Statement, which will be filed with the ~~year ended~~SEC not later than 120 days subsequent to December 31, ~~2016.~~

The audit report of GT on our consolidated financial statements as of and for the year ended December 31, 2016 did not contain an adverse opinion or disclaimer of opinion, and was not qualified or modified as to uncertainty, audit scope or accounting principles. Weaver did issue an adverse opinion on our internal control over financial reporting due to a material weakness related to segregation of duties.

Weaver and Tidwell, L.L.P. (“Weaver”) served as the independent registered public accounting firm for the Company for the year ended December 31, 2015 and 2014, and for the subsequent interim period through June 30, 2016. On July 13, 2016, the Company dismissed Weaver and engaged GT to serve as the Company’s independent registered public accounting firm. The decision to change accountants was recommended by the Audit Committee and approved by the Board of Directors.

~~Audit Committee Pre-Approval Policies and Procedures~~

To help assure independence of the independent auditor, the Audit Committee has established a policy whereby all audit, review, attest and non-audit engagements of the principal auditor or other firms must be approved in advance by the Audit Committee; provided, however, that de minimis non-audit services may instead be approved in accordance with applicable SEC rules. This policy is set forth in our Audit Committee Charter. Of the fees shown above in the table, which were paid to our independent auditor, 100% were approved by the Audit Committee.

2019.

PART IV

~~Fees Paid to GT and Weaver~~

~~The following is a summary and description of fees for services provided by GT for the year ended December 31, 2016, and by Weaver for the years ended December 31, 2016 and 2015:~~

Year Ended December 31, 2016

Year Ended
December 31, 2015

Services

Fees Paid to GT

Fees Paid to Weaver

Fees Paid to Weaver

Audit Fees ⁽¹⁾

$
532,556

$
25,000

$
447,000

Audit-Related Fees ⁽²⁾

21,200

30,000

—

Tax Fees

—

—

—

All Other Fees

—

—

—

Total

$
553,756

$
55,000

$
447,000

⁽¹⁾

Audit Fees include professional services for the audit of our annual financial statements, reviews of the financial statements included in our Form 10-Q filings, and services that are normally provided in connection with statutory and regulatory filings or engagements.

⁽²⁾

~~Audit-Related Fees comprise fees for professional services that are reasonably related to the performance of the audit or review of the Company’s financial statements.~~

PA~~RT IV~~

Item 15. Exhibits, Financial ~~Statements and~~Statement Schedules

Incorporated by Reference

Exhibit
No.

Description

Form

SEC File No.

Exhibit

Filing Date

Filed
Herewith

Furnished
Herewith
2.1

Arrangement Agreement, dated December 16, 2015, among Earthstone Energy, Inc., 1058286 B.C. Ltd. and Lynden Energy Corp.

8-K

001-35049

2.1

December 17, 2015

2.1(a)

First Amendment to Arrangement Agreement dated March 29, 2016, among Earthstone Energy, Inc., 1058286 B.C. Ltd. And Lynden Energy Corp.

8-K

001-35049

2.1

March 29, 2016

2.2

Contribution Agreement dated November 7, 2016, by and among Earthstone Energy, Inc., Earthstone Energy Holdings, LLC, Lynden USA Inc., Lynden USA Operating, LLC, Bold Energy Holdings, LLC and Bold Energy III LLC.

8-K

001-35049

2.1

November 8, 2016

3.1

Amended and Restated Certificate of Incorporation of Earthstone Energy, Inc. dated February 26, 2010.

8-K

001-35049

3(i)

March 3, 2010

3.1(a)

Certificate of Amendment to Certificate of Incorporation of Earthstone Energy, Inc. dated December 20, 2010.

8-K

001-35049

3(i)

January 4, 2011

3.1(b)

Certificate of Amendment of Certificate of Incorporation of Earthstone Energy, Inc. dated December 19, 2014.

8-K

001-35049

3.1

December 29, 2014

3.1(c)

Certificate of Amendment of the Amended and Restated Certificate of Incorporation of Earthstone Energy, Inc. dated October 22, 2015.

8-K

001-35049

3.1

October 26, 2015

3.2

Amended and Restated Bylaws of Earthstone Energy, Inc. dated February 26, 2010.

8-K

001-35049

3(ii)

March 10, 2010

3.2(a)

First Amendment to the Amended and Restated Bylaws of Earthstone Energy, Inc. dated November 22, 2011.

8-K

001-35049

3(ii)c

November 23, 2011

3.2(b)

Second Amendment to the Amended and Restated Bylaws of Earthstone Energy, Inc. dated October 22, 2015.

8-K

001-35049

3.2

October 26, 2015

4.1

Rights Agreement dated February 4, 2009 between Earthstone Energy, Inc. and Corporate Stock Transfer, Inc.

8-K

001-35049

4.1

February 5, 2009

4.1(a)

First Amendment to the Rights Agreement dated May 15, 2014, by and among Earthstone Energy, Inc., Corporate Stock Transfer, Inc., and Direct Transfer LLC.

8-A/A

001-35049

4.1

May 16, 2014

4.1(b)

Second Amendment to the Rights Agreement dated May 15, 2014 between Earthstone Energy, Inc. and Direct Transfer LLC.

8-A/A

001-35049

4.2

May 16, 2014

4.1(c)

Third Amendment to the Rights Agreement dated October 16, 2014 between Earthstone Energy, Inc. and Direct Transfer LLC.

8-A/A

001-35049

4.1

October 20, 2014

4.2

Specimen Common Stock Certificate of Earthstone Energy, Inc.

10-K

001-35049

4.2

June 16, 2011

10.1

Credit Agreement dated December 19, 2014, by and among Earthstone Energy, Inc., Oak Valley 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.

8-K

001-35049

10.4

December 29, 2014

10.1(a)

First Amendment to the Credit Agreement dated December 19, 2014, by and among Earthstone Energy, Inc., Oak Valley 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.

8-K

001-35049

10.1

December 4, 2015

10.1(b)

Second Amendment to the Credit Agreement dated May 18, 2016, by and among Earthstone Energy, Inc., Earthstone Operating, LLC, EF Non-OP, LLC, Sabine River Energy, LLC, Basic Petroleum Services, Inc., Lynden Energy Corp., Lynden USA, Inc., BOKF, NA dba Bank of Texas, and the Lenders party thereto.

8-K

001-35049

10.1

May 18, 2016

10.1( c)

Third Amendment and Limited Waiver to the Credit Agreement dated July 27, 2016, by and among Earthstone Energy, Inc., Earthstone Operating, LLC, EF Non-OP, LLC, Sabine River Energy, LLC, Basic Petroleum Services, Inc., Lynden Energy Corp., Lynden USA, Inc., BOKF, NA dba Bank of Texas, and the Lenders party thereto.

8-K

001-35049

10.1

July 27, 2016

10.2

Exchange Agreement dated May 15, 2014 between Earthstone Energy, Inc. and Oak Valley Resources, LLC.

8-K

001-35049

10.1

May 16, 2014

10.2(a)

Amendment to the Exchange Agreement dated September 26, 2014 between Earthstone Energy, Inc. and Oak Valley Resources, LLC.

8-K

001-35049

10.1

October 2, 2014

10.3

Contribution Agreement dated October 16, 2014, among Earthstone Energy, Inc., Oak Valley Resources, LLC, Sabine River Energy, LLC, Oak Valley Operating, LLC, Parallel Resource Partners, LLC, and Flatonia Energy, LLC.

8-K

001-35049

10.1

October 20, 2014

10.3(a)

First Amendment to Contribution Agreement dated June 4, 2015, by and among Earthstone Energy, Inc., Oak Valley Resources, LLC, Sabine River Energy, LLC, Earthstone Operating, LLC, Parallel Resources Partners, LLC, and Flatonia Energy, LLC.

8-K

001-35049

10.1

June 10, 2015

10.4

Registration Rights Agreement dated December 19, 2014 between Earthstone Energy, Inc. and Oak Valley Resources, LLC.

8-K

001-35049

10.1

December 29, 2014

10.5

Registration Rights Agreement dated December 19, 2014, by and among Earthstone Energy, Inc., Parallel Resource Partners, LLC, Flatonia Energy, LLC, and Oak Valley Resources, LLC.

8-K

001-35049

10.2

December 29, 2014

10.6†

Earthstone Energy, Inc. Employee Severance Compensation Plan.

8-K

001-35049

10.2

May 16, 2014

10.7†

Earthstone Energy, Inc. 2014 Long-Term Incentive Plan.

8-K

001-35049

10.3

December 29, 2014

10.7(a)†

First Amendment to the Earthstone Energy, Inc. 2014 Long-Term Incentive Plan dated October 22, 2015.

8-K

001-35049

10.1

October 26, 2015

10.8

Form of Indemnification Agreement.

8-K

001-35049

10.5

December 29, 2014

10.9†

Earthstone Energy, Inc. 2011 Equity Incentive Compensation Plan.

Def. Proxy Statement

001-35049

Appendix A

July 29, 2011

10.10†

Earthstone Energy, Inc. Performance Bonus Plan.

10-K/A

001-35049

10.3

October 9, 2009

10.11

Form of Voting Support Agreement

8-K

001-35049

10.1

December 17, 2015

10.12†

Form of Restricted Stock Unit Agreement (Executive Management)

8-K

001-35049

10.1

June 1, 2016

10.13†

Form of Restricted Stock Unit Agreement (Employee)

8-K

001-35049

10.2

June 1, 2016

10.14†

Form of Restricted Stock Unit Agreement (Non-Employee Director)

8-K

001-35049

10.3

June 1, 2016

10.15

Voting and Support Agreement

8-K

001-35049

10.1

November 8, 2016

14

Code of Business Conduct and Ethics.

10-KSB/A

001-35049

14.1

May 11, 2005

21.1

List of Subsidiaries.

10-K

001-35049

21.1

March 15, 2017

23.1

Consent of Cawley, Gillespie & Associates, Inc.

10-K/A

001-35049

23.1

July 31, 2017

23.2

Consent of Grant Thornton LLP

10-K

001-35049

23.2

March 15, 2017

23.3

Consent of Weaver and Tidwell, L.L.P.

10-K

001-35049

23.3

March 15, 2017

31.1

Certification of the Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act.

X

31.2

Certification of the Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act.

X

32.1

Certification of the Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act.

X
32.2

Certification of the Chief Accounting Officer pursuant to Section 906 of the Sarbanes-Oxley Act.

X

Incorporated by Reference

Exhibit

No.

Description

Form

SEC File No.

Exhibit

Filing Date

Filed

Herewith

Furnished

Herewith

2.1

Contribution Agreement dated November 7, 2016, by and among Earthstone Energy, Inc., Earthstone Energy Holdings, LLC, Lynden USA Inc., Lynden USA Operating, LLC, Bold Energy Holdings, LLC and Bold Energy III LLC.

8-K

001-35049

2.1

November 8, 2016

2.2(a)

First Amendment to the Contribution Agreement dated March 21, 2017, by and among Earthstone Energy, Inc., Earthstone Energy Holdings, LLC, Lynden USA Inc., Lynden USA Operating, LLC, Bold Energy Holdings, LLC and Bold Energy III LLC.

8-K

001-35049

2.1

March 23, 2017

2.3

Contribution Agreement dated October 17, 2018 by and among Sabalo Holdings, LLC, Earthstone Energy Holdings, LLC and Earthstone Energy, Inc.

8-K

001-35049

2.1

October 17, 2018

3.1

Third Amended and Restated Certificate of Incorporation of Earthstone Energy, Inc. dated May 9, 2017.

8-A

001-35049

3.1

May 9, 2017

3.2

Amended and Restated Bylaws of Earthstone Energy, Inc. dated February 26, 2010.

8-K

001-35049

3(ii)

March 3, 2010

3.2(a)

First Amendment to the Amended and Restated Bylaws of Earthstone Energy, Inc. dated November 22, 2011.

8-K

001-35049

3(ii)c

November 23, 2011

3.2(b)

Second Amendment to the Amended and Restated Bylaws of Earthstone Energy, Inc. dated October 22, 2015.

8-K

001-35049

3.2

October 26, 2015

4.1

Specimen Class A Common Stock Certificate of Earthstone Energy, Inc.

8-K

001-35049

4.1

May 15, 2017

4.2

Description of Earthstone Energy, Inc.’s Class A Common Stock.

10.1†

Earthstone Energy, Inc. 2014 Long-Term Incentive Plan.

8-K

001-35049

10.3

December 29, 2014

10.1(a)†

First Amendment to the Earthstone Energy, Inc. 2014 Long-Term Incentive Plan dated October 22, 2015.

8-K

001-35049

10.1

October 26, 2015

10.1(b)†

Second Amendment to the Earthstone Energy, Inc. 2014 Long-Term Incentive Plan dated May 9, 2017.

8-K

001-35049

10.6

May 15, 2017

10.2

Form of Indemnification Agreement.

8-K

001-35049

10.5

December 29, 2014

10.3†

Form of Restricted Stock Unit Agreement (Executive Management).

8-K

001-35049

10.1

June 2, 2016

10.4†

Form of Restricted Stock Unit Agreement (Employee).

8-K

001-35049

10.2

June 2, 2016

10.5

First Amended and Restated Limited Liability Company Agreement of Earthstone Energy Holdings, LLC dated May 9, 2017.

8-K

001-35049

10.1

May 15, 2017

99.1

Report of Cawley, Gillespie & Associates, Inc.

10-K/A

001-35049

99.1

July 31, 2017

101.INS*

XBRL Instance Document.

X

101.SCH*

XBRL Schema Document.

X

101.CAL*

XBRL Calculation Linkbase Document.

X

101.DEF*

XBRL Definition Linkbase Document.

X

101.LAB*

XBRL Label Linkbase Document.

X

101.PRE*

XBRL Presentation Linkbase Document.

X

10.6

Registration Rights Agreement dated May 9, 2017 between Earthstone Energy, Inc. and Bold Energy Holdings, LLC.

8-K

001-35049

10.3

May 15, 2017

10.7

Voting Agreement dated May 9, 2017 by and among Earthstone Energy, Inc., EnCap Investments L.P., Oak Valley Resources, LLC and Bold Energy Holdings, LLC.

8-K

001-35049

10.4

May 15, 2017

10.8†

Performance Unit Award Agreement (Executive Management).

8-K

001-35049

10.2

March 2, 2018

10.9†

Amended and Restated 2014 Long Term Incentive Plan dated June 6, 2018.

8-K

001-35049

10.1

June 6, 2018

10.10†

Form of Performance Unit Agreement (Executive Management).

8-K

001-35049

10.2

February 1, 2019

10.11†

Earthstone Energy, Inc. Change in Control and Severance Benefit Plan.

8-K

001-35049

10.1

April 12, 2019

10.12

Credit Agreement dated November 21, 2019, by and among Earthstone Energy Holdings, LLC, as Borrower, Earthstone Energy, Inc., as Parent, Wells Fargo Bank, National Association as Administrative Agent and Issuing Bank, BOKF, NA dba Bank of Texas, as Issuing Bank with respect to Existing Letters of Credit, Royal Bank of Canada, as Syndication Agent, SunTrust Bank, as Documentation Agent, and the Lenders party thereto.

8-K

001-35049

10.1

November 22, 2019

10.13†

Form of Performance Unit Agreement (Executive Management).

8-K

001-35049

10.1

January 31, 2020

10.14†

Form of Restricted Stock Unit Agreement (Executive Management).

8-K

001-35049

10.2

January 31, 2020

10.15†

Form of Restricted Stock Unit Agreement (Director).

8-K

001-35049

10.3

January 31, 2020

14.1

Code of Business Conduct and Ethics.

21.1

List of Subsidiaries.

23.1

Consent of Cawley, Gillespie & Associates, Inc.

23.2

Consent of Moss Adams, LLP.

31.1

Certification of the Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act.

31.2

Certification of the Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act.

32.1

Certification of the Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act.

32.2

Certification of the Executive Vice President - Accounting and Administration pursuant to Section 906 of the Sarbanes-Oxley Act.

99.1

Report of Cawley, Gillespie & Associates, Inc.

101.INS

XBRL Instance Document.

101.SCH

XBRL Schema Document.

101.CAL

XBRL Calculation Linkbase Document.

101.DEF

XBRL Definition Linkbase Document.

101.LAB

XBRL Label Linkbase Document.

†

101.PRE

XBRL Presentation Linkbase Document.

†

Indicates management contract or compensatory plan or arrangement.

Item 16. Form 10-K Summary

None.

~~SIGNATURES~~

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.



		EARTHSTONE ENERGY, INC.


		By:	/s/ Frank A. Lodzinski
		Name:	Frank A. Lodzinski
Date: ~~September 1, 2017~~	March 11, 2020	Title:	~~President~~Chief Executive Officer
			(Principal Executive Officer)

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.



Signature	Title	Date

/s/ Frank A. Lodzinski	Chairman of the Board, Director and Chief Executive Officer ~~(Principal~~ (Principal Executive Officer)	March 11, 2020
Frank A. Lodzinski

/s/ Tony Oviedo	Executive Vice President, Accounting and Administration (Principal Financial Officer and Principal Accounting Officer)	March 11, 2020
Tony Oviedo

/s/ Jay F. Joliat	Director	March 11, 2020
Jay F. Joliat	Director

/s/ Phil D. Kramer	Director	March 11, 2020
Phil D. Kramer

/s/ Ray Singleton	Director	March 11, 2020
Ray Singleton	Director

/s/ Wynne M. Snoots, Jr.	Director	March 11, 2020
Wynne M. Snoots, Jr.

/s/ Douglas E. Swanson, Jr.	Director	March 11, 2020
Douglas E. Swanson, Jr.	Director

/s/ Brad A. Thielemann	Director	March 11, 2020
Brad A. Thielemann	Director

/s/ Zachary G. Urban	Director	March 11, 2020
Zachary G. Urban	Director

/s/ Robert L. Zorich	Director	March 11, 2020
Robert L. Zorich	Director

EARTHSTONE ENERGY, INC.

Index to Consolidated Financial Statements and Supplementary Information

			~~Page~~

	Page
Audited Financial Statements:
Report of Independent Registered Public Accounting Firm		~~F-2~~ 2
Consolidated Balance Sheets as of December 31, ~~2016~~2019 and ~~2015~~2018		~~F-4~~ 3
Consolidated Statements of Operations for the Years Ended December 31, ~~2016, 2015~~2019 and ~~2014~~2018		~~F-5~~ 5
Consolidated Statements of Equity for the Years Ended December 31, ~~2016, 2015~~2019 and ~~2014~~2018		~~F-6~~ 6
Consolidated Statements of Cash Flows for the Years Ended December 31, ~~2016, 2015~~2019 and ~~2014~~2018		~~F-7~~ 7
Notes to Consolidated Financial Statements		~~F-8~~ 8
Unaudited Information:
Supplemental Information on Oil and Gas Exploration and Production Activities		~~S-1~~ 27

~~F-1~~

R~~EPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM~~

Report of Independent Registered Public Accounting Firm

To the Shareholders and the Board of Directors ~~and Shareholders~~

Earthstone Energy, Inc.

Opinion on the Financial Statements

We have audited the accompanying consolidated balance ~~sheet~~sheets of Earthstone Energy, Inc. ~~(a Delaware corporation~~ and subsidiaries (the “Company”) as of December 31, ~~2016,~~2019 and 2018, the related consolidated statements of operations, equity and cash flows for years then ended, and the ~~year~~related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the consolidated financial position of the Company as of December 31, 2019 and 2018, and the consolidated results of its operations and its cash flows for the years then ~~ended.~~ ended, 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, 2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 11, 2020 expressed an unqualified opinion on the Company’s internal control over financial reporting.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on ~~these 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 financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall 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 financial position of Earthstone Energy, Inc. and subsidiaries as of December 31, 2016, and the results of their operations and their cash flows for the year then ended 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),~~ the Company’s ~~internal control over financial reporting as of December 31, 2016, 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, 2017 expressed an unqualified opinion.~~

~~/s/ GRANT THORNTON LLP~~

~~Houston, Texas~~

~~March 15, 2017~~

~~F-2~~

~~REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM~~

~~Board of Directors and Stockholders~~

~~Earthstone Energy, Inc.~~

We have audited the accompanying consolidated balance sheet of Earthstone Energy, Inc. and subsidiaries (the Company) (formerly Oak Valley Resources, LLC) as of December 31, 2015 and the related consolidated statements of operations, equity, and cash flows for each of the years in the two-year period 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 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 ~~Public Company Accounting Oversight Board (United States).~~PCAOB. 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~~misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures to respond to those risks. Such procedures included examining, on a test basis, evidence ~~supporting~~regarding the amounts and disclosures in the consolidated financial statements. ~~An audit~~Our audits also ~~includes assessing~~included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial ~~statement presentation.~~statements. We believe that our audits provide a reasonable basis for our opinion.

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

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

Moss Adams, LLP

Houston, Texas

March 11, ~~2016~~

~~F-3~~

2020

We have served as the Company’s auditor since 2018.

EARTHSTONE ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(In thousands, except share and per share amounts)

December 31,

ASSETS

2016

2015

Current assets:

Cash

$
10,200

$
23,264

Accounts receivable:

Oil, natural gas, and natural gas liquids revenues

13,998

13,529

Joint interest billings and other, net of allowance of $163 and $170 at December 31, 2016 and 2015, respectively

2,698

4,924

Derivative asset

—

3,694

Prepaid expenses and other current assets

446

498

Total current assets

27,342

45,909

Oil and gas properties, successful efforts method:

Proved properties

363,072

283,644

Unproved properties

51,723

34,609

Total oil and gas properties

414,795

318,253

Accumulated depreciation, depletion and amortization

(145,393
)

(119,920
)
Net oil and gas properties

269,402

198,333

Other noncurrent assets:

Goodwill

17,620

17,532

Office and other equipment, net of accumulated depreciation of $1,600 and $1,028 at December 31, 2016 and 2015, respectively

1,479

1,934

Other noncurrent assets

669

1,236

TOTAL ASSETS

$
316,512

$
264,944

LIABILITIES AND EQUITY

Current liabilities:

Accounts payable

$
11,927

$
11,580

Revenues and royalties payable

10,769

8,576

Accrued expenses

5,392

12,975

Derivative liability

4,595

—

Advances

4,542

15,447

Current portion of long-term debt

1,604

—

Total current liabilities

38,829

48,578

Noncurrent liabilities:

Long-term debt

12,693

11,191

Asset retirement obligation

6,013

5,075

Derivative liability

1,575

—

Deferred tax liability

15,776

—

Other noncurrent liabilities

169

227

Total noncurrent liabilities

36,226

16,493

Commitments and Contingencies (Note 14)

Equity:

Preferred stock, $0.001 par value, 20,000,000 shares authorized; none issued or outstanding

—

—

Common stock, $0.001 par value, 100,000,000 shares authorized; 22,289,177 issued and 22,273,820 outstanding at December 31, 2016 and 13,835,128 issued and 13,819,771 outstanding at December 31, 2015

23

14

Additional paid-in capital

454,202

358,086

Accumulated deficit

(212,308
)

(157,767
)
Treasury stock, 15,357 shares at December 31, 2016 and 2015, respectively

(460
)

(460
)
Total equity

241,457

199,873

TOTAL LIABILITIES AND EQUITY

$
316,512

$
264,944



	December 31,
ASSETS	2019			2018
Current assets:
Cash	$	13,822		$	376
Accounts receivable:
Oil, natural gas, and natural gas liquids revenues	29,047			13,683
Joint interest billings and other, net of allowance of $83 and $134 at December 31, 2019 and 2018, respectively	6,672			4,166
Derivative asset	8,860			43,888
Prepaid expenses and other current assets	1,867			1,443
Total current assets	60,268			63,556

Oil and gas properties, successful efforts method:
Proved properties	970,808			755,443
Unproved properties	260,271			266,140
Land	5,382			5,382
Total oil and gas properties	1,236,461			1,026,965
Accumulated depreciation, depletion and amortization	(195,567		)	(127,256		)
Net oil and gas properties	1,040,894			899,709

Other noncurrent assets:
Goodwill	17,620			17,620
Office and other equipment, net of accumulated depreciation of $3,180 and $2,490 at December 31, 2019 and 2018, respectively	1,311			662
Derivative asset	770			21,121
Operating lease right-of-use assets	3,108			—
Other noncurrent assets	1,572			1,640
TOTAL ASSETS	$	1,125,543		$	1,004,308
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	25,284		$	26,452
Revenues and royalties payable	35,815			28,748
Accrued expenses	19,538			22,406
Asset retirement obligation	308			557
Derivative liability	6,889			528
Advances	11,505			3,174
Operating lease liability	570			—
Finance lease liability	206			—
Other current liability	43			—
Total current liabilities	100,158			81,865

Noncurrent liabilities:
Long-term debt	170,000			78,828
Asset retirement obligation	1,856			1,672
Derivative liability	—			1,891
Deferred tax liability	15,154			13,489
Operating lease liability	2,539			—
Finance lease liability	85			—
Other noncurrent liabilities	—			71
Total noncurrent liabilities	189,634			95,951

Commitments and Contingencies (Note 16)

Equity:
Preferred stock, $0.001 par value, 20,000,000 shares authorized; none issued or outstanding	—			—
Class A Common Stock, $0.001 par value, 200,000,000 shares authorized; 29,421,131 and 28,696,321 issued and outstanding at December 31, 2019 and 2018, respectively	29			29



Class B Common Stock, $0.001 par value, 50,000,000 shares authorized; 35,260,680 and 35,452,178 issued and outstanding at December 31, 2019 and 2018, respectively	35			35
Additional paid-in capital	527,246			517,073
Accumulated deficit	(181,711		)	(182,497		)
Total Earthstone Energy, Inc. equity	345,599			334,640
Noncontrolling interest	490,152			491,852
Total equity	835,751			826,492

TOTAL LIABILITIES AND EQUITY	$	1,125,543		$	1,004,308

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

~~F-4~~

EARTHSTONE ENERGY, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except share and per share amounts)

Years Ended December 31,

2016

2015

2014

REVENUES

Oil

$
34,358

$
39,849

$
34,734

Natural gas

5,046

5,457

9,367

Natural gas liquids

2,865

2,158

3,510

Total revenues

42,269

47,464

47,611

OPERATING COSTS AND EXPENSES

Lease operating expense

13,415

14,550

9,422

Severance taxes

2,198

2,582

2,002

Rig idle and contract termination expense

5,059

—

—

Re-engineering and workovers

1,652

872

708

Impairment expense

24,283

138,086

19,359

Depreciation, depletion and amortization

25,937

31,228

18,414

General and administrative expense

9,414

9,711

6,830

Stock-based compensation

3,301

—

—

Transaction costs

2,483

589

1,034

Accretion of asset retirement obligation

551

550

317

Exploration expense

5

142

111

Total operating costs and expenses

88,298

198,310

58,197

Gain on sale of oil and gas properties

8

1,617

—

Loss from operations

(46,021
)

(149,229
)

(10,586
)

OTHER INCOME (EXPENSE)

Interest expense, net

(1,282
)

(722
)

(597
)
(Loss) gain on derivative contracts, net

(6,638
)

6,431

4,392

Other (expense) income, net

(72
)

423

62

Total other income (expense)

(7,992
)

6,132

3,857

Loss before income taxes

(54,013
)

(143,097
)

(6,729
)
Income tax expense (benefit)

528

(26,442
)

22,105

Net loss

$
(54,541
)

$
(116,655
)

$
(28,834
)

Net loss per common share:

Basic

$
(2.92
)

$
(8.43
)

$
(3.11
)
Diluted

$
(2.92
)

$
(8.43
)

$
(3.11
)

Weighted average common shares outstanding:

Basic

18,651,582

13,835,128

9,279,324

Diluted

18,651,582

13,835,128

9,279,324



	Years Ended December 31,
	2019			2018
REVENUES
Oil	$	171,925		$	140,775
Natural gas	3,913			7,396
Natural gas liquids	15,424			17,185
Total revenues	191,262			165,356
OPERATING COSTS AND EXPENSES
Lease operating expense	28,683			18,746
Production and ad valorem taxes	11,871			9,836
Impairment expense	—			4,581
Depreciation, depletion and amortization	69,243			47,568
General and administrative expense	27,611			27,346
Transaction costs	1,077			14,337
Accretion of asset retirement obligation	214			169
Exploration expense	653			630
Total operating costs and expenses	139,352			123,213
Gain on sale of oil and gas properties, net	3,222			1,919
Income from operations	55,132			44,062
OTHER INCOME (EXPENSE)
Interest expense, net	(6,566		)	(2,898		)
Write-off of deferred financing costs	(1,242		)	—
(Loss) gain on derivative contracts, net	(43,983		)	60,947
Litigation settlement	—			(4,675		)
Other income (expense), net	(96		)	247
Total other income (expense)	(51,887		)	53,621
Income before income taxes	3,245			97,683
Income tax expense	(1,665		)	(2,470		)
Net income	1,580			95,213
Less: Net income attributable to noncontrolling interest	861			52,888
Net income attributable to Earthstone Energy, Inc.	$	719		$	42,325
Net income per common share attributable to Earthstone Energy, Inc.:
Basic	$	0.02		$	1.50
Diluted	$	0.02		$	1.50
Weighted average common shares outstanding:
Basic	28,983,354			28,153,885
Diluted	29,360,885			28,217,774

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

~~F-5~~

EARTHSTONE ENERGY, INC.

CONSOLIDATED STATEMENTS OF EQUITY

(In thousands, except share amounts)

Additional

Members'

Common Stock

Paid-in

Accumulated

Treasury Stock

Total

Equity

Shares

Amount

Capital

Deficit

Shares

Amount

Equity

At December 31, 2013

$
148,922

—

$
—

—

$
—

—

$
—

$
148,922

Contributions from Oak Valley Resources, LLC members

107,020

—

—

—

—

—

—

107,020

Contribution of Oak Valley Subsidiaries in exchange for shares

(268,220
)

9,124,452

9

268,211

—

—

—

—

Reverse acquisition with Oak Valley

—

1,753,388

2

33,453

(15,357
)

(460
)

32,995

Shares issued in 2014 Eagle Ford Acquisition

—

2,957,288

3

56,422

—

—

—

56,425

Net loss

12,278

—

—

—

(41,112
)

—

—

(28,834
)
At December 31, 2014

—

13,835,128

14

358,086

(41,112
)

(15,357
)

(460
)

316,528

Net loss

—

—

—

—

(116,655
)

—

—

(116,655
)
At December 31, 2015

—

13,835,128

14

358,086

(157,767
)

(15,357
)

(460
)

199,873

Common stock issued, net of offering costs of $2.7 million

—

4,753,770

5

47,120

—

—

—

47,125

Stock-based compensation expense

—

—

—

3,301

—

—

—

3,301

Shares issued in Lynden Arrangement

—

3,700,279

4

45,695

—

—

—

45,699

Net loss

—

—

—

—

(54,541
)

—

—

(54,541
)
At December 31, 2016

$
—

22,289,177

$
23

$
454,202

$
(212,308
)

(15,357
)

$
(460
)

$
241,457



	Issued Shares
	Class A Common Stock		Class B Common Stock		Class A Common Stock		Class B Common Stock			Additional Paid-in Capital			Accumulated Deficit			Total Earthstone Energy, Inc. Stockholders’ Equity			Noncontrolling Interest			Total Equity
At January 1, 2018	27,584,638		36,052,169		$	28	$	36		$	503,932		$	(224,822	)	$	279,174		$	446,558		$	725,732
Stock-based compensation expense	—		—		—		—			7,071			—			7,071			—			7,071
Vesting of restricted stock units, net of taxes paid	511,692		—		—		—			—			—			—			—			—
Class A Common Stock retained by the Company in exchange for payment of recipient mandatory tax withholdings	169,893		—		—		—			(1,524		)	—			(1,524		)	—			(1,524		)
Cancellation of treasury shares	(169,893	)	—		—		—			—			—			—			—			—
Class B Common Stock converted to Class A Common Stock	599,991		(599,991	)	1		(1		)	7,594			—			7,594			(7,594		)	—
Net income	—		—		—		—			—			42,325			42,325			52,888			95,213
At December 31, 2018	28,696,321		35,452,178		$	29	$	35		$	517,073		$	(182,497	)	$	334,640		$	491,852		$	826,492
ASC 842 implementation	—		—		—		—			—			67			67			99			166
Stock-based compensation expense	—		—		—		—			8,648			—			8,648			—			8,648
Vesting of restricted stock units, net of taxes paid	533,312		—		—		—			—			—			—			—			—
Vested restricted stock units retained by the Company in exchange for payment of recipient mandatory tax withholdings	203,394		—		—		—			(1,135		)	—			(1,135		)	—			(1,135		)
Cancellation of treasury shares	(203,394	)	—		—		—			—			—			—			—			—
Class B Common Stock converted to Class A Common Stock	191,498		(191,498	)	—		—			2,660			—			2,660			(2,660		)	—
Net income	—		—		—		—			—			719			719			861			1,580
At December 31, 2019	29,421,131		35,260,680		$	29	$	35		$	527,246		$	(181,711	)	$	345,599		$	490,152		$	835,751

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

~~F-6~~

EARTHSTONE ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

Years Ended December 31,

2016

2015

2014

Cash flows from operating activities:

Net loss

$
(54,541
)

$
(116,655
)

$
(28,834
)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:

Depreciation, depletion and amortization

25,937

31,228

18,414

Impairment of goodwill

17,532

1,547

—

Impairment of proved and unproved oil and gas properties

6,751

136,539

19,359

Total loss (gain) on derivative contracts, net

6,638

(6,431
)

(4,392
)
Operating portion of net cash received in settlement of derivative contracts

3,225

6,306

778

Rig idle and termination expense

5,059

—

—

Stock-based compensation

3,301

—

—

Accretion of asset retirement obligations

551

550

317

Deferred income taxes

528

(26,533
)

22,105

Amortization of deferred financing costs

298

264

164

Settlement of asset retirement obligations

(15
)

(108
)

(56
)
Gain on sale of oil and gas properties

(8
)

(1,617
)

—

Changes in assets and liabilities:

Decrease (increase) in accounts receivable

3,807

9,246

(5,305
)
Decrease (increase) in prepaid expenses and other current assets

511

779

(194
)
(Decrease) increase in accounts payable and accrued expenses

(9,151
)

(30,887
)

28,408

Increase (decrease) in revenues and royalties payable

2,194

(8,739
)

7,099

(Decrease) increase in advances

(10,905
)

(5,929
)

17,925

Net cash provided by (used in) operating activities

1,712

(10,440
)

75,788

Cash flows from investing activities:

Lynden Arrangement, net of cash acquired

(31,334
)

—

—

Reverse acquisition with Oak Valley, net of cash acquired

—

—

(4,239
)
Acquisition of oil and gas properties

—

(8,706
)

(18,772
)
Additions to oil and gas properties

(28,417
)

(61,060
)

(83,041
)
Additions to office and other equipment

(117
)

(378
)

(1,385
)
Proceeds from sale of oil and gas properties

—

3,441

—

Proceeds from sale of land

—

101

—

Net cash used in investing activities

(59,868
)

(66,602
)

(107,437
)
Cash flows from financing activities:

Proceeds from borrowings

36,597

—

11,191

Repayments of borrowings

(38,549
)

—

(10,825
)
Deferred financing costs

(81
)

(141
)

(613
)
Contributions, net of issuance costs

—

—

106,920

Issuance of common stock, net of offering costs of $2.7 million

47,125

��

—

—

Net cash provided by (used in) financing activities

45,092

(141
)

106,673

Net (decrease) increase in cash and cash equivalents

(13,064
)

(77,183
)

75,024

Cash at beginning of period

23,264

100,447

25,423

Cash at end of period

$
10,200

$
23,264

$
100,447

Supplemental disclosure of cash flow information

Cash paid for:

Interest

$
961

$
415

$
493

Non-cash investing and financing activities:

Asset retirement obligations

$
152

$
150

$
237

Accruals of property, plant and equipment

$
2,374

$
7,665

$
18,219

Acquisition of oil and gas properties

$
—

$
1,991

$
—

Promissory Note

$
5,059

$
—

$
—

Common stock issued in Lynden Arrangement

$
45,699

$
—

$
—

Common stock issued in 2014 Eagle Ford Acquisition

$
—

$
—

$
56,425



	Years Ended December 31,
	2019			2018
Cash flows from operating activities:
Net income	$	1,580		$	95,213
Adjustments to reconcile net income to net cash provided by operating activities:
Impairment of proved and unproved oil and gas properties	—			4,581
Depreciation, depletion and amortization	69,243			47,568
Accretion of asset retirement obligations	214			169
Gain on sale of oil and gas properties, net	(3,222		)	(1,919		)
Settlement of asset retirement obligations	(374		)	(79		)
Total loss (gain) on derivative contracts, net	43,983			(60,947		)
Operating portion of net cash received (paid) in settlement of derivative contracts	15,866			(15,090		)
Stock-based compensation	8,648			7,071
Deferred income taxes	1,665			2,470
Write-off of deferred financing costs	1,242			—
Amortization of deferred financing costs	412			325
Changes in assets and liabilities:
(Increase) decrease in accounts receivable	(18,035		)	(8,195		)
(Increase) decrease in prepaid expenses and other current assets	66			(376		)
Increase (decrease) in accounts payable and accrued expenses	(10,438		)	1,132
Increase (decrease) in revenues and royalties payable	7,067			31,869
Increase (decrease) in advances	8,331			(1,413		)
Net cash provided by operating activities	126,248			102,379
Cash flows from investing activities:
Acquisition of oil and gas properties	—			(32,551		)
Additions to oil and gas properties	(204,268		)	(149,999		)
Additions to office and other equipment	(527		)	(170		)
Proceeds from sale of oil and gas properties	4,184			5,965
Net cash used in investing activities	(200,611		)	(176,755		)
Cash flows from financing activities:
Proceeds from borrowings	234,680			156,830
Repayments of borrowings	(143,508		)	(103,002		)
Cash paid related to the exchange and cancellation of Class A Common Stock	(1,135		)	(1,524		)
Cash paid for finance leases	(392		)	—
Deferred financing costs	(1,836		)	(507		)
Net cash provided by financing activities	87,809			51,797
Net increase (decrease) in cash	13,446			(22,579		)
Cash at beginning of period	376			22,955
Cash at end of period	$	13,822		$	376
Supplemental disclosure of cash flow information
Cash paid for:
Interest	$	6,405		$	2,290
Non-cash investing and financing activities:
Accrued capital expenditures	$	28,356		$	22,801
Lease asset additions - ASC 842	$	3,722		$	—
Asset retirement obligations	$	105		$	252

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

~~F-7~~

EARTHSTONE ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1. – Organization and Basis of Presentation

Earthstone Energy, Inc. ~~(together~~, a Delaware corporation (“Earthstone” and together with ~~our~~its consolidated subsidiaries, the ~~“Company,” “our,” “we,” “us,” “Earthstone” or similar terms)~~“Company”), ~~a Delaware corporation,~~ 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. ~~Our~~The Company’s operations are all in the up-stream segment of the oil and natural gas industry and all ~~our~~its properties are onshore in the United States.

~~Oak Valley Resources,~~

Earthstone is the sole managing member of Earthstone Energy Holdings, LLC, ~~(“OVR”) is~~ a Delaware limited liability company ~~formed on December 14, 2012. On December 19, 2014,~~(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 ~~Company acquired three operating subsidiaries~~laws of ~~OVR, in exchange for shares~~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 ~~Earthstone common stock (the “Exchange”). Prior to~~EEH, consolidates the ~~Exchange, OVR was an independent energy company engaged~~financial results of EEH and records a noncontrolling interest in the ~~acquisition, exploration, development,~~Consolidated Financial Statements representing the economic interests of EEH’s members other than Earthstone and production of crude oil, natural gas and natural gas liquids (“NGLs”), with properties in Texas, Oklahoma, and Louisiana. OVR was formed through a series of transactions that conveyed properties and committed cash contributions from various investors including EnCap Investments L.P. (“EnCap”), Wells Fargo Central Pacific Holdings, Inc. (“Wells Fargo”), VILLCo Capital II, LLC (“VILLCo”) and an affiliate of OVR, Oak Valley Management, LLC (“OVM”).

Lynden US.

Certain ~~prior-period~~prior period amounts have been reclassified to conform to ~~current-period~~current period presentation ~~as follows:~~

within the Consolidated ~~Statement of Operations – Accretion of asset retirement obligation has been reclassified out of~~Financial Statements. Prior period ad valorem taxes previously included in Lease operating ~~expense and included in its own line item in~~expenses within the Operating Costs and ~~Expenses. Transaction costs~~Expenses section of the Consolidated Statements of Operations have been reclassified ~~out of~~from Lease operating expenses, combined with the previously presented Severance taxes line-item and the combined total presented as Production and ad valorem taxes, also within Operating Costs and Expenses, to conform to current period presentation. Additionally, prior period legal expenses related to a previously completed transaction and previously included in General and administrative expense and included in its own line item in Operating Costs and Expenses. Gain on sale of oil and gas properties has be reclassified from within Revenues to its own line item to arrive at Loss from operations. Gathering income has be reclassified from within Revenues to inclusion in Lease operating expense within Operating Costs and ~~Expenses.~~Expenses have been reclassified to Transaction costs, also within Operating Costs and Expenses, to conform to current period presentation. These reclassifications had no effect on ~~Loss~~Income from operations ~~Loss before income taxes,~~ or ~~Net loss for each~~any other subtotal in the Consolidated Statements of ~~the three years ended December 31, 2016, 2015 and 2014.~~

Operations.

Consolidated Statement of Cash Flows – Non-cash changes in fair value of the Company’s commodity swaps have been reclassified from the Unrealized (gain) loss on derivative contracts and bifurcated into Total loss (gain) on derivative contracts, net, and Operating portion of net cash received in settlement of derivative contracts. The reclassification had no effect on Net cash provided by operating activities for each of the three years ended December 31, 2016, 2015 and 2014.

Note 2. – Summary of Significant Accounting Policies

Principles of Consolidation

The ~~consolidated financial statements~~Consolidated Financial Statements include the accounts and balances of the Company ~~and its wholly owned subsidiaries~~ 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~~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~~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~~the Company’s estimates. All reserve data ~~included~~used in ~~these~~the preparation of the Consolidated Financial Statements, as well as included in Note 20. Supplemental Information On Oil And Gas Exploration And Production Activities (Unaudited), 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.

~~F-8~~

~~EARTHSTONE ENERGY, INC.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)~~

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, valuation of derivative instruments and valuation of ~~derivative instruments.~~certain performance-based restricted stock unit awards. 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 Note 20.Supplemental Information on Oil and Gas Exploration and Production Activities (Unaudited).

Although management believes these estimates are reasonable, actual results may differ from estimates and assumptions of future events and these revisions could be material. Future production may vary materially from estimated oil and natural gas proved reserves. Actual future prices may vary significantly from price assumptions used for determining proved reserves and for financial reporting.

EARTHSTONE ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

Accounts Receivable

Accounts receivable include estimated 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.

For receivables from joint interest owners, the Company typically has the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings.

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 ~~$0.2~~$0.1 million and $0.1 million at December 31, ~~2016~~2019 and ~~2015.~~

2018, respectively.

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 ~~marked-to-market~~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. ~~We use~~The Company uses the successful efforts method of accounting for oil and natural gas ~~properties as proscribed by the SEC.~~properties. For more information see Note 6.7. 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~~indicate that the carrying value of goodwill may not be recoverable. Such test includes an assessment of qualitative and quantitative factors. ~~During the years ended December 31, 2016 and 2015, impairments to Goodwill of $17.5 million and $1.5 million, respectively, were recorded.~~ There were no impairments to Goodwill recorded in the ~~year~~years ended December 31, ~~2014.~~2019 and 2018, respectfully. For further discussion, see Note 7.8. 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, 2019 and 2018, as well as an adjustment to Net income in the Consolidated Statement of Operations for the years ended December 31, 2019 and 2018. As of December 31, 2019, Earthstone and Lynden US owned a 45.5% membership interest in EEH while Bold Energy Holdings, LLC (“Bold Holdings”), the noncontrolling third party, owned the remaining 54.5%. See further discussion in Note 9. Noncontrolling Interest.

Segment Reporting

~~The~~

Operating segments are 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 the Company’s ~~operations are conducted through two locations~~organization and management, it has only one reportable operating segment, which ~~have been deemed operating segments under ASC 280, Segment Reporting.~~ is oil and natural gas exploration and production.

Comprehensive Income

The Company ~~aggregated them into one reporting segment because these operating segments sell the same products, under the same production processes, with the same type~~has no elements of ~~customers, under the same method of distribution, and in the same type of regulatory environment.~~

comprehensive income other than net income.

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

~~F-9~~

~~EARTHSTONE ENERGY, INC.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)~~

depreciated over the useful life of the asset. Asset retirement obligations are recorded at estimated fair value, measured by

EARTHSTONE ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

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 ~~12.~~14. Asset Retirement Obligations.

Business Combinations

The Company accounts for ~~the acquisition~~its acquisitions of oil and gas properties not commonly controlled ~~based on the requirements of FASB ASC~~in accordance with Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 805, Business Combinations, which, among other things, requires the Company to determine if an ~~acquiring entity to recognize~~asset or a business has been acquired. If the Company determines an asset(s) has been acquired, the asset(s) acquired, as well as any liabilities assumed, are measured and recorded at the acquisition date cost. If the Company determines a business has been acquired, the assets acquired and liabilities assumed are measured and recorded at their fair ~~value under~~values as of the acquisition ~~method~~date, recording goodwill for amounts paid in excess of ~~accounting, provided such assets~~fair value.

Revenue Recognition

The Company’s revenues are comprised solely of revenues from customers and ~~liabilities qualify for acquisition accounting under~~include the ~~standard. The Company accounts for property acquisitions~~sale of ~~proved developed~~ oil, ~~and gas properties as business combinations.~~

~~Revenue Recognition~~

~~Oil,~~ natural gas and natural gas ~~liquids revenues represent income~~liquids. The Company believes that the disaggregation of revenue into these three major product types, as presented in the Consolidated Statements of Operations, appropriately depicts how the nature, amount, timing and uncertainty of revenue and cash flows are affected by economic factors based on its single geographic region. Revenues are recognized when the recognition criteria of ASC 606 “Revenue from Contracts with Customers,” (“ASC 606”) are met, which generally occurs at a point in time when production is sold to a purchaser at a determinable price, delivery has occurred, control has transferred and collection of the ~~production and~~revenue is probable. The Company fulfills its performance obligations under its customer contracts through delivery of oil, natural gas and natural gas liquids and revenues are recorded on a monthly basis and the Company receives payment from one to three months after delivery. Generally, each unit of product represents a separate performance obligation. The prices received for oil, natural gas and natural gas liquids sales under the Company’s contracts are generally derived from stated market prices which are then adjusted to reflect deductions including transportation, fractionation and processing. As a result, revenues from the sale of oil, natural gas and natural gas liquids will decrease if market prices decline. The sales of oil, natural gas and natural gas liquids, as presented on the Consolidated Statements of Operations, represent the Company’s share of revenues net of ~~royalties. Revenues~~royalties and excluding revenue interests owned by others. When selling oil, natural gas and natural gas liquids on behalf of royalty or working interest owners, the Company is acting as an agent and thus reports the revenue on a net basis. To the extent actual volumes and prices of oil and natural gas sales are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and prices for those properties are estimated and recorded. Variances between the Company’s estimated revenue and actual payment are recorded in the month the payment is received. Historically, however, differences have been insignificant.

At the end of each month when the performance obligation is satisfied, the variable consideration can be reasonably estimated and amounts due from customers are recorded in “Accounts receivable: oil, natural gas, and natural gas liquids revenues” in the Consolidated Balance Sheets. As of December 31, 2019 and 2018, receivables from contracts with customers were $29.0 million and $13.7 million, respectively. Taxes assessed by governmental authorities on oil, natural gas and NGL sales are presented separately from such revenues in the Consolidated Statements of Operations.

Oil Sales

Oil production is transported from the wellhead to tank batteries or delivery points through flow-lines or gathering systems. Purchasers of the oil take delivery at (i) the tank batteries and transport the oil by truck, or (ii) at a pipeline delivery point and the Company collects a market price, net of pricing differentials. Revenue is recognized when control transfers to the purchaser at the net price received by the Company. Starting in October 2019, certain of the Company’s oil sales activity involves buy/sell arrangements that effect a change in location with required repurchase of oil at a delivery point. Because the Company acts as the agent in these transactions, the buy/sell activity is recorded on a net basis and the residual transportation fee is included in Lease operating expenses in the Consolidated Statements of Operations.

Natural Gas and NGL Sales

Under the Company’s natural gas sales arrangements, the purchaser takes control of wet gas at a delivery point near the wellhead or at the inlet of the purchaser’s processing facility. The purchaser gathers and processes the wet gas and remits proceeds to the Company for the resulting natural gas and NGL sales. Based on the nature of these arrangements, the Company is the agent and the purchaser is the Company’s customer, thus, the Company recognizes natural gas and NGL sales based on the net amount of proceeds received from the purchaser.

Imbalances

EARTHSTONE ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

The Company recognizes revenue for all oil, natural gas and NGL sold to purchasers regardless of whether the sales are proportionate to the Company’s ownership interest in the property. Production imbalances are recognized ~~when production~~as a liability to the extent an imbalance on a specific property exceeds the Company’s share of remaining proved oil, NGL and natural gas reserves. The Company is ~~sold~~also subject to ~~a purchaser~~natural gas pipeline imbalances, which are recorded as accounts receivable or payable at ~~a fixed or determinable price, delivery has occurred, title has been transferred, and collectability~~values consistent with contractual arrangements with the owner of the ~~revenue is probable. The Company follows the sales method of accounting for gas imbalances.~~pipeline. The Company had no ~~significant gas~~ imbalances as of December 31, ~~2016, 2015,~~2019 or ~~2014.~~

2018.

Contract Balances

Under the Company’s product sales contracts, the Company invoices customers once performance obligations have been satisfied, at which point payment is unconditional. Accordingly, the Company’s product sales contracts do not give rise to contract assets or liabilities under ASC 606.

Transaction Price Allocated to Remaining Performance Obligations

Substantially all of the Company’s product sales are short-term in nature, with a contract term of one year or less. For these contracts, the Company has utilized the practical expedient in ASC 606 which exempts the Company from the requirements to disclose the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less.

For the Company’s product sales that have a contract term greater than one year, the Company has utilized the practical expedient in ASC 606 which states the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these contracts, each unit of product generally represents a separate performance obligation; therefore, future volumes are wholly unsatisfied, and disclosure of the transaction price allocated to remaining performance obligations is not required.

Prior-Period Performance Obligations

The Company records revenue in the month that product is delivered to the purchaser. Settlement statements for certain natural gas and NGLs sales, however, may not be received for 30 to 90 days after the date the product is delivered, and as a result the Company is required to estimate the amount of product delivered to the purchaser and the price that will be received for the sale of the product. In these situations, the Company records the differences between its estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. Any identified differences between the Company’s revenue estimates and actual revenue received have historically been insignificant. For the years ended December 31, 2019 and 2018, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.

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 ~~2016, two~~2019, three purchasers accounted for ~~41%~~30%, 14% and ~~19%~~12%, respectively, of the Company’s oil, natural gas, and natural gas liquids revenues. In ~~2015 and 2014, one purchaser~~2018, three purchasers accounted for ~~62%~~27%, 11% and ~~60%~~10%, respectively, 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 ~~2016, 2015,~~2019 and ~~2014.~~2018. Additionally, at December 31, ~~2016, two~~2019, three purchasers accounted for ~~28%~~46%, 14% and ~~12%~~10%, respectively, of the Company’s oil, natural gas and natural gas liquids receivables. At December 31, ~~2015, one~~2018, five purchasers accounted for ~~25%~~22%, 17%, 13%, 11% and 11% 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, ~~2016~~2019 and ~~2015.~~

2018.

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. ~~The Company recognizes the cash received as revenue.~~ In ~~2016~~2019 and ~~2015, one~~2018, no operator distributed 19% and 12%, respectively, of the Company’s oil, natural gas and natural gas liquids revenues. In 2014, a different operator distributed 20% 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 2016, 2015, and 2014.~~

revenues.

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, ~~2016,~~2019, the Company had noa net derivative ~~contracts in~~ asset ~~positions.~~position of $2.7 million. At December 31, ~~2015, two counterparties accounted for 69% and 31%, respectively,~~2018, the Company had $62.6 million of ~~the Company’s Current~~ derivative contracts that were in a material asset ~~in the Consolidated Balance Sheet.~~

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.

~~F-10~~

Stock-Based Compensation

EARTHSTONE ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

The Company recognized stock-based compensation expense associated with restricted stock units, which include both time- and performance-based awards. The Company accounts for forfeitures of equity-based incentive awards as they occur. Stock-based compensation expense related to time-based restricted stock units is based on the price of the Class A common stock, $0.001 par value per share of Earthstone (“Class A Common Stock”), on the grant date and recognized over the vesting period using the straight-line method. Stock-based compensation expense related to performance-based restricted stock units, which cliff vest, is based on a grant date Monte Carlo Simulation pricing model, which calculates multiple potential outcomes for an award and establishes fair value based on the most likely outcome, and is recognized over the vesting period using the straight-line method. See Note 12. Stock-Based Compensation for further details.

Income Taxes

~~We are~~

The Company is a U.S. company operating in ~~multiple states,~~Texas, as of December 31, 2019, as well as one foreign legal entity, Lynden ~~Energy Corp.,~~Corp, which is a Canadian ~~company discussed in~~ ~~Note 3. Acquisitions and Divestitures~~.company. Consequently, ~~our~~the Company’s tax provision is based upon the tax laws and rates in effect in the applicable jurisdiction in which ~~our~~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, we are~~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. ~~Our~~The Company’s effective tax rate for financial statement purposes will continue to fluctuate from year to year as ~~our~~its operations are conducted in different taxing jurisdictions.

~~Our~~

The Company records 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. 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.

The Company’s deferred tax expense or benefit represents the change in the balance of deferred tax assets or liabilities reported in ~~our~~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, ~~2016~~2019 and ~~2015,~~2018, the Company has recorded a valuation allowance for its deferred tax assets in the Consolidated Balance Sheets. The historical financials prior to December 19, 2014 are those of OVR. OVR was not subject to taxation and therefore tax provisions were not recorded on the historical consolidated financial statements. As a result of the Exchange Agreement, OVR is now a taxable entity and a charge to earnings to record a tax provision was included in the purchase accounting adjustments.

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.~~Consolidated Financial Statements. It requires that the Company recognize in the ~~consolidated financial statements~~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, ~~2016, 2015~~2019 or ~~2014.~~

2018.

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. The Company’s 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 SEC Staff Accounting Bulletin (“SAB”) No. 118, 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 2017. 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. As of December 31, 2018, the Company has finalized the accounting for the enactment of the TCJA.

Recently Issued Accounting Standards

~~Standards adopted in 2016~~Leases

~~Debt Issuance Costs~~ –- In ~~April 2015,~~February 2016, the ~~Financial~~FASB issued Accounting Standards ~~Board~~Update (“~~FASB”~~ASU”) No. 2016-02, Leases (Topic 842): Amendments to the FASB Accounting Standards Codification (“ASU 2016-02”). In January 2018, the FASB issued ~~updated guidance which changes~~ASU No. 2018-01, Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842 (“ASU 2018-01”). In July 2018, the ~~presentation~~FASB issued

EARTHSTONE ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

ASU No. 2018-11, Leases (Topic 842): Targeted Improvements (“ASU 2018-11”). Together these related amendments to GAAP represent ASC Topic 842, Leases (“ASC Topic 842”).

ASU 2016-02 requires lessees to recognize lease assets and liabilities (with terms in excess of ~~debt issuance costs in the financial statements. Under this updated guidance, debt issuance costs are presented~~12 months) on the balance sheet and disclose key quantitative and qualitative information about leasing arrangements. The Company completed a comprehensive assessment of existing contracts, as ~~a direct deduction from~~well as future potential contracts, to determine the ~~related debt liability rather than as an asset. Amortization~~impact of the ~~costs is reported~~new accounting guidance on its Consolidated Financial Statements and related disclosures. The evaluation process included review of contracts for drilling rigs, office facilities, compression services, field vehicles and equipment, general corporate leased equipment, and other existing arrangements to support its operations that may contain a lease component. The Company’s evaluation process did not include review of its mineral leases as ~~interest expense. In August 2015,~~they are outside the ~~FASB subsequently issued a clarification as to the handling~~scope of debt issuance costs related to line-of-credit arrangements that allows the presentation of these costs as an asset. The standards update was effective for interim and annual periods beginning after December 15, 2015. ASC Topic 842.

The Company adopted this ~~standards update, as required, effective~~guidance on January 1, ~~2016.~~ 2019, the transition date, using the simplified transition method described in ASU 2018-11 which allows entities to continue to apply historical accounting guidance in the comparative periods presented in the year of adoption. Accordingly, prior period amounts in the Company’s financial statements are not adjusted and continue to be reported in accordance with historical accounting guidance.

The Company elected the package of practical expedients within ASU 2016-02 that allows an entity to not reassess, prior to the effective date, (i) whether any expired or existing contracts are or contain leases, (ii) the lease classification for any expired or existing leases or (iii) initial direct costs for any existing leases. Additionally, the Company elected the practical expedient under ASU 2018-01 to not evaluate existing or expired land easements not previously accounted for as leases prior to the effective date.

The Company made an accounting policy election not to apply the lease recognition requirements to short-term leases.

The adoption of ~~this standards update did not affect the Company’s method of amortizing debt issuance costs and~~ASC Topic 842 did not have a material impact on ~~its~~the Consolidated Financial ~~Statements.~~Statements, resulted in increases of less than 1% to each of its total assets and total liabilities on the balance sheet, and resulted in an immaterial decrease to accumulated deficit as of the beginning of 2019. See

~~Measurement-Period Adjustments~~Note 19. Leases for further information.

Intangibles – Goodwill and Other – In ~~September 2015,~~January 2017, the FASB issued updated guidance ~~that~~simplifying the test for goodwill impairment. The update eliminates the requirement to ~~restate prior periods to reflect adjustments made to provisional amounts recognized~~determine the implied value of goodwill in ~~a business combination. The updated guidance requires that~~measuring an ~~acquirer recognize adjustments to provisional amounts that are identified during~~impairment loss. Upon adoption, the measurement ~~period in~~of a goodwill impairment will represent the excess of the reporting ~~period in which~~unit’s carrying value over its fair value and will be limited to the ~~adjustment amounts are determined.~~carrying value of goodwill. 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 ~~standards~~ update ~~was~~is effective ~~prospectively~~ for ~~interim~~annual and ~~annual~~interim periods beginning after December 15, ~~2015, with~~2019 and early adoption is permitted for interim or annual goodwill impairment tests performed after January 1, 2017. The Company adopted the update effective January 1, 2020 and the impact was not material to the Consolidated Financial Statements.

Fair Value Measurements – In August 2018, the FASB issued an update which modifies the disclosure requirements on fair value measurements in Topic 820. The ASU is effective for fiscal years beginning after December 15, 2019 and early adoption is permitted. The Company adopted ~~this standard~~the update ~~as required,~~ effective January 1, ~~2016, which did~~2020 and the impact was not ~~have a~~ material to the Consolidated Financial Statements.

Income Taxes - In December 2019, the FASB issued an update that simplifies the accounting for income taxes by removing certain exceptions to the general principles in Topic 740. The amendments also improve consistent application of and simplify GAAP for other areas of Topic 740 by clarifying and amending existing guidance. The amendments in this update are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2020 and early adoption is permitted. The Company is in the process of evaluating the impact of this update, if any, on its Consolidated Financial Statements.

~~Stock Compensation~~

Credit Losses - In ~~March~~June 2016, the FASB issued ~~updated~~an update that requires changes to the recognition of credit losses on financial instruments not accounted for at fair value through net income, including loans, debt securities, trade receivables, net investments in leases and available-for-sale debt securities. The amended standard broadens the information that an entity must consider in developing its estimate of expected credit losses, requiring an entity to estimate credit losses over the life of an exposure based on historical information, current information and reasonable and supportable forecasts. The guidance on share-based payment accounting. The standards update is intended to simplify several areas of accounting for share-based compensation arrangements, including the income tax impact, classification on the statement of cash flows and forfeitures. The standards update is effective for interim and annual periods beginning after December 15, ~~2016 with early adoption permitted.~~2019. The Company ~~elected to early-adopt this standards~~adopted the update ~~as of April~~effective January 1, ~~2016 in connection with its initial grant of awards under the Company’s 2014 Long Term Incentive Plan. The Company has elected to record~~2020 and the impact ~~of forfeitures on compensation cost as they occur. The Company is also permitted~~was not material to ~~withhold income taxes upon settlement of equity-classified awards at up to~~ the ~~maximum statutory tax rates. There was no retrospective adjustment as the Company did not have any outstanding equity awards prior to adoption. See~~ ~~Note 10. Stock-Based Compensation~~.

~~F-11~~

~~EARTHSTONE ENERGY, INC.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)~~

~~Standards not yet adopted~~

~~Revenue Recognition~~ - In May 2014, the FASB issued updated guidance for recognizing revenue from contracts with customers. This update amends the existing accounting standards for revenue recognition and is based on the principle that revenue should be recognized to depict the transfer of good and services to a customer at an amount that reflects the consideration a company expects to receive in exchange for those good or services. The Company will adopt this standards update, as required, beginning with the first quarter of 2018. The Company does not expect the adoption of this guidance to have a material impact on its Consolidated Financial Statements.

~~Leases~~ ~~– In February 2016, the FASB issued updated guidance on accounting for leases.~~ This update requires lessees to recognize a right of use asset and lease liability on the balance sheet for all leases, with the exception of short-term leases. 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 will adopt this standards update, as required, beginning with the first quarter of 2019. ~~The Company is currently evaluating the effect of the update on our consolidated financial statements and related disclosures.~~

~~Statement of Cash Flows –~~ In August 2016, the FASB issued updated guidance that These amendments clarify how entities should classify certain cash receipts and cash payments on the statement of cash flows related to the following transactions: (1) debt prepayment or extinguishment costs; (2) settlement of zero-coupon debt instruments or other debt instruments with coupon rates that are insignificant in relation to the effective interest rate of the borrowing; (3) contingent consideration payments made after a business combination; (4) proceeds from the settlement of insurance claims; (5) proceeds from the settlement of corporate-owned life insurance; (6) distributions received from equity method investees; and (7) beneficial interests in securitization transactions. Additionally, the update clarifies how the predominance principle should be applied when cash receipts and cash payments have aspects of more than one class of cash flows. These amendments are effective for fiscal years, and interim periods within those years, beginning after December 15, 2017, with early adoption permitted. The Company expects to adopt this standards update, as required, beginning with the first quarter of 2018. The Company is currently evaluating the effect of the amendments on our consolidated financial statements and related disclosures.

Note 3. Acquisitions and Divestitures

~~Lynden Arrangement~~

The initial accounting for acquisitions and divestitures 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.

Exchange Involving Monetary Consideration

EARTHSTONE ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

On ~~May 18, 2016,~~October 5, 2018, the Company ~~acquired Lynden Energy Corp. (“Lynden”)~~closed a transaction in ~~an all-stock transaction through an arrangement~~the Midland Basin that included producing properties and undeveloped acreage (the ~~“Lynden Arrangement”~~“Exchange”) instead of a merger because Lynden is incorporated in British Columbia, Canada. The Company acquired all outstanding shares of Lynden’s common stock, through a newly formed subsidiary, with Lynden surviving as a wholly-owned subsidiary of. GAAP required the assets received by the Company ~~issuing 3,700,279 shares of its common stock, $0.001 par value per share (the “Common Stock”),~~ to ~~the holders of the common stock of Lynden. The Lynden Arrangement was accounted for~~be treated as a business combination, ~~in accordance with FASB~~under ASC ~~Topic~~ 805, ~~Business Combinations, which, among other things, requires~~and the assets ~~acquired and liabilities assumed~~conveyed to the other party to be ~~measured and recorded at their fair values~~treated as a disposition of ~~the acquisition date.~~

assets (discussed in Divestitures below).

An allocation of the purchase price was prepared using, among other things, ~~an independent fair market valuation. The following is still preliminary with respect to final tax amounts~~a reserve report prepared by qualified reserve engineers and includes the use of estimates based on information that was available to management at the time these consolidated financial statements were prepared. We expect the purchase price allocation to be finalized in the first quarter of 2017. Based on our ongoing review of preliminary tax amounts, we adjusted the deferred tax liability recordedpriced as ~~a result~~ of the acquisition date. The market assumptions as to the future commodity prices, projections of estimated quantities of oil and ~~a corresponding change to goodwill in~~natural gas reserves, expectations for timing and amount of the ~~fourth quarter of 2016.~~

~~F-12~~

~~EARTHSTONE ENERGY, INC.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)~~

~~The following table summarizes the consideration transferred, fair value of assets acquired~~future development and ~~liabilities assumed and resulting goodwill (in thousands, except share and share price amount~~):

Consideration:

Shares of Earthstone common stock issued in the Arrangement

3,700,279

Closing price of Earthstone common stock as of May 18, 2016

$
12.35

Total consideration to Lynden shareholders

$
45,698

Fair Value of Liabilities Assumed:

Credit facility ⁽⁴⁾

$
36,597

Current liabilities

1,915

Deferred tax liability⁽¹⁾

15,157

Asset retirement obligations

250

Total consideration plus liabilities assumed

$
99,617

Fair Value of Assets Acquired:

Cash and cash equivalents ⁽⁴⁾

$
5,263

Current assets

2,018

Proved oil and gas properties ⁽²⁾⁽³⁾

48,116

Unproved oil and gas properties

26,600

Amount attributable to assets acquired

$
81,997

Goodwill ⁽⁵⁾

$
17,620

~~(1)~~

This amount represents the difference between the recorded book value and the tax basis of the oil and natural gas properties as of the date of the closing of the Lynden Arrangement, tax-effected using a tax rate of approximately 34.5%.

~~(2)~~

The weighted average commodity prices utilized in the determination of the fair value of oil and natural gas properties was $64.73 per barrel of oil, $3.68 per Mcf of natural gas and $19.34 per barrel of oil equivalent for natural gas liquids, after adjustments for transportation fees and regional price differentials.

~~(3)~~

~~The market assumptions as to the future commodity prices,~~operating costs, projections ~~of estimated quantities of oil and natural gas reserves, expectations for timing and amount of the future development and operating costs, projecting~~ of future rates of production, expected recovery rate and risk adjusted discount rates used by the Company to estimate the fair value ~~of the oil and natural gas properties represent Level 3 inputs; see~~ ~~Note 4. Fair Value Measurements,~~ ~~below.~~

~~(4)~~

Concurrent with closing the Lynden Arrangement, the Company paid off the outstanding balance of $36.6 million on the Lynden credit facility. The settlement of the debt and the cash acquired is equal to the $31.3 million net cash outflow associated with the Lynden Arrangement.

~~(5)~~

Goodwill was determined to be the excess consideration exchanged over the fair value of the net assets of Lynden on May 18, 2016. The goodwill resulted from the expected synergies of the management team and balance sheet of the Company combined with the key assets acquired in the Midland Basin area. The goodwill recognized will not be deductible for tax purposes.

~~F-13~~

~~EARTHSTONE ENERGY, INC.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)~~

The following unaudited supplemental pro forma results of operations present consolidated information assuming the Lynden Arrangement had been completed as of January 1, 2014. The unaudited supplemental pro forma financial information was derived from the historical consolidated and combined statements of operations for the Company and Lynden and adjusted to include: (i) depletion expense applied to the adjusted basis of the properties acquired, (ii) accretion expense associated with the asset retirement obligations recorded using the Company’s assumptions about the future liabilities and (iii) interest expense based on the combined debt of the Company post-acquisition. 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~~).

Years ended December 31,

2016

2015

2014

(Unaudited)

Revenue

$
47,679

$
62,817

$
112,370

(Loss) income before taxes

$
(53,510
)

$
(148,609
)

$
32,912

Net (loss) income available to Earthstone common stockholders

$
(54,744
)

$
(122,598
)

$
19,518

Pro Forma net (loss) income per common share:

Basic

$
(2.73
)

$
(6.99
)

$
1.11

Diluted

$
(2.73
)

$
(6.99
)

$
1.11

~~Earthstone Energy Reverse Acquisition~~

On December 19, 2014, the Company acquired three operating subsidiaries of OVR, which included producing assets, undeveloped acreage and cash, in exchange for shares of Common Stock (the “Exchange”), which resulted in a change of control of the Company. Pursuant to the Exchange Agreement, OVR contributed to Earthstone the membership interests of its three subsidiaries, Earthstone Operating, LLC (formerly Oak Valley Operating, LLC (“OVO”)), EF Non-Op, LLC (“EF Non-Op”) and Sabine River Energy, LLC (“Sabine”), each a Texas limited liability company (collectively “Oak Valley”). OVR received approximately 9.124 million shares of the Common Stock of the Company. The Exchange resulted in a change of control of the Company. The Exchange was recorded in accordance with FASB ASC Topic 805 as a reverse acquisition whereby Oak Valley was considered the acquirer for accounting purposes although Earthstone was the acquirer for legal purposes. ASC 805 also requires that, among other things, assets acquired and liabilities assumed be measured at their acquisition date fair values. The results of operations from Earthstone’s legacy assets are reflected in the Company’s Consolidated Statement of Operations beginning December 19, 2014.

An allocation of the purchase price was prepared using, among other things, the December 31, 2014 reserve report prepared by Cawley, Gillespie and Associates, Inc. (“CG&A”), adjusted by the Company’s reserve engineering staff back to the December 19, 2014 acquisition date.

~~F-14~~

~~EARTHSTONE ENERGY, INC.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)~~

~~The following table summarizes the consideration paid to acquire the legacy Earthstone net assets and the estimated values of those net assets (in thousands, except share and share price amounts~~):

Shares of Common Stock issued as consideration

1,753,388

Closing price of Common Stock as of December 19, 2014

$
19.08

Total purchase price

$
33,455

Estimated Fair Value of Liabilities Assumed:

Current liabilities

$
7,631

Long-term debt

7,000

Deferred tax liability ⁽¹⁾

2,880

Asset retirement obligation

1,035

Amount attributable to liabilities assumed

18,546

Total purchase price plus liabilities assumed

$
52,001

Estimated Fair Value of Assets Acquired:

Cash ⁽²⁾

$
2,920

Other current assets

3,466

Proved oil and natural gas properties ^{(3) (4)}

21,813

Unproved oil and natural gas properties

5,524

Other non-current assets

746

Amount attributable to assets acquired

$
34,469

Goodwill ⁽⁵⁾

$
17,532

~~(1)~~

This amount represents the difference between the recorded book value and the tax basis of the oil and natural gas properties as of the date of the closing of the Exchange, tax-effected using a tax rate of approximately 35%.

~~(2)~~

~~Net cash flow related to the Exchange was an outflow of $4.2 million which consisted of the $7.1 million repayment of long-term debt (plus accrued interest) less the cash acquired of $2.9 million.~~

~~(3)~~

The weighted average commodity prices utilized in the determination of the fair value of oil and natural gas properties was $51.62 per barrel of oil and $4.58 per Mcf of natural gas after adjustments for transportation fees and regional price differentials.

~~(4)~~

The market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates used by the Company to estimate the fair value of the oil and natural gas properties represent Level 3 inputs. For additional information on Level 3 inputs, see ~~Note 4. Fair Value Measurements~~.

~~(5)~~

~~Goodwill was determined to be the excess consideration exchanged over the fair value of the Company’s net assets on December 19, 2014. In 2016,~~ ~~due to the commodity price environment, the Company determined that the amount recorded was no longer recoverable and recognized a full impairment~~ ~~charge to Goodwill of $17.5 million in the Consolidated Statement of Operations. See~~ ~~Note 7.Goodwill~~.

~~2014 Eagle Ford Acquisition Properties~~

On December 19, 2014, immediately following the Exchange, Flatonia Energy, LLC (“Flatonia”), Parallel Resource Partners, LLC (“Parallel”), and Sabine, closed a contribution agreement (the “Flatonia Contribution Agreement”) by and among the Company, OVR, Sabine, OVO, Parallel, and Flatonia, whereby Parallel contributed 28.57% of the oil and natural gas ~~property interests held by Flatonia,~~properties represent Level 3 inputs; see Note 5. Fair Value Measurements, below.

As a ~~wholly owned subsidiary of Parallel,~~result, the Company, in exchange for ~~approximately 2.957~~cash of $25.9 million ~~shares~~and value for the assets conveyed of Common Stock. The assets subject to the Flatonia Contribution Agreement were oil and natural gas property interests in producing wells and acreage in the Eagle Ford trend of Texas (the “2014 Eagle Ford Acquisition Properties~~”). One of the subsidiaries included in the Exchange is the operator of the 2014 Eagle Ford Acquisition Properties. The only relationship that Flatonia or Parallel had with this subsidiary or~~$37.1 million, the Company ~~prior to the transaction was that the subsidiary is the operator of the 2014 Eagle Ford Acquisition Properties. The Flatonia Contribution Agreement was accounted for~~recorded $65.8 million in Oil and gas properties, as ~~a business combination~~well as $2.8 million in ~~accordance ASC 805 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~~.

~~F-15~~

~~EARTHSTONE ENERGY, INC.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)~~

~~An allocation of the purchase price was prepared using, the December 31, 2014 reserve report prepared by CG&A that was adjusted by the Company’s reserve engineering staff back to December 19, 2014.~~

~~The following table summarizes the consideration paid to acquire the 2014 Eagle Ford Acquisition Properties and the estimated values of those net assets (in thousands, except share and share price amounts~~):

Shares of Common Stock issued as consideration in the Contribution

2,957,288

Closing price of Common Stock as of December 19, 2014

$
19.08

Total purchase price

$
56,425

Estimated Fair Value of Liabilities Assumed:

Deferred tax liability ⁽¹⁾

$
1,547

Asset retirement obligation

173

Amount attributable to liabilities assumed

1,720

Total purchase price plus liabilities assumed

$
58,145

Estimated Fair Value of Assets Acquired:

Proved oil and natural gas properties ^{(2) (3)}

$
34,745

Unproved oil and natural gas properties

21,853

Amount attributable to assets acquired

$
56,598

Goodwill ⁽⁴⁾

$
1,547

~~(1)~~

This amount represents the difference between the recorded book value and the tax basis of the oil and natural gas properties as of the date of the closing of the Flatonia Contribution Agreement, tax-effected using a tax rate of approximately 34%.

~~(2)~~

The weighted average commodity prices utilized in the determination of the fair value of oil and natural gas properties was $56.36 per barrel of oil and $3.36 per Mcf of natural gas after adjustments for transportation fees and regional price differentials.

~~(3)~~

~~(4)~~

Goodwill was determined as the excess consideration exchanged over the fair value of the 2014 Eagle Ford Acquisition Properties on December 19, 2014. In 2015, due to the commodity price environment, the Company determined that the goodwill balance was not recoverable and therefore fully impaired it, recording a goodwill impairment charge ~~of $1.5 million. See~~ ~~Note 7.Goodwill~~.

~~Other Acquisitions~~

In June 2015, the Company acquired a 50% operated working interests in approximately 1,000 gross acres in southern Gonzales County, Texas. The acreage, acquired for future Eagle Ford development, is 100% held-by-production by two gross Austin Chalk wells with gross production of 44 barrels of oil equivalent per day as of the time of acquisition.

Also during June 2015, the Company acquired 400 gross acres in northern Karnes County, Texas, which is adjacent to the 1,000 gross acres in southern Gonzales County, Texas. Subsequent trades in Karnes County reduced the gross acreage from 400 to 350 gross acres (117 net acres).

~~F-16~~

~~EARTHSTONE ENERGY, INC.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)~~

~~The following table summarizes the consideration paid to acquire the properties and the estimated fair values of the assets acquired and liabilities assumed~~ ~~(in thousands)~~:

Purchase price

$
4,066

Estimated fair value of assets acquired:

Proved oil and natural gas properties

$
588

Unproved oil and natural gas properties

3,496

Total assets acquired

$
4,084

Estimated fair value of liabilities assumed:

Asset retirement obligations

$
13

Other liabilities

5

Total liabilities assumed

$
18

Consideration paid

$
4,066

Additionally, in June 2015, the Company acquired additional acreage and working interest in wells located within existing Bakken spacing units primarily located in the Banks Field of McKenzie County, North Dakota, for $1.4 million plusaccounts payable related known purchase price adjustments, in its Consolidated Balance Sheet as of $2.0 million for the revenues, net of production taxes and operating expenses and capital costs incurred for the existing wells. The acquisition included 164 net acres which allowed the Company to increase its working interest in approximately 41 producing wells and 21 wells that were in the drilling and completion phase.

~~In August 2015, the Company acquired a 33% working interest in approximately 1,650 gross acres, in southern Gonzales County, Texas for $3.3 million.~~

~~Divestitures~~

In April 2015, the Company sold its Louisiana properties located primarily in DeSoto and Caddo Parishes, Louisiana, for cash consideration of $3.4 million. The Company recorded a gain of $1.6 million on the sale.December 31, 2018. The effective date of the Exchange was September 1, 2018.

Divestitures

During the year ended December 31, 2019, the Company sold certain of its non-operated oil and gas properties located in the Midland Basin for approximately $4.2 million in cash, resulting in a gain of approximately $3.6 million recorded in Gain on sale of oil and gas properties, net in the Consolidated Statements of Operations.

During the year ended December 31, 2018, the Company sold certain non-core properties for approximately $6.0 million in cash, while eliminating approximately $0.8 million of future abandonment obligations. The sales resulted in net gains of approximately $4.7 million recorded in Gain on sale of oil and gas properties, net in the Consolidated Statements of Operations.

In association with the Exchange, the Company received value of $37.1 million for Net oil and gas properties conveyed of $39.9 million and recognized a $2.8 million loss on sale of oil and gas properties recorded in Gain on sale of oil and gas properties, net for the year ended December 31, 2018.

Note 4. Transaction Costs

During the year ended December 31, 2019, the Company recorded transaction ~~was March 1, 2015.~~

costs totaling approximately $1.1 million primarily due to legal fees related to the business combination (the “Bold Transaction”) pursuant to the Bold Contribution Agreement (as defined below) which closed on May 9, 2017, as described in under the “Legal” section of Note 16. Commitments and Contingencies.

On October 17, 2018, Earthstone, EEH and Sabalo Holdings, LLC (“Sabalo Holdings”) entered into a contribution agreement (the “Contribution Agreement”) which provided for the contribution by Sabalo Holdings of all its interests in Sabalo Energy, LLC (“Sabalo Energy”) and Sabalo Energy, Inc. to EEH (the “Sabalo Acquisition”). On December 21, 2018, Earthstone, EEH and Sabalo Holdings entered into a termination agreement (the “Termination Agreement”), pursuant to which the parties terminated the Contribution Agreement.

In connection with the Termination Agreement, Earthstone, EEH and Sabalo Holdings also agreed to release each other from certain claims and liabilities arising out of or related to the Contribution Agreement and the transactions contemplated thereby. All other related agreements were also terminated in conjunction with the termination of the Contribution Agreement.

During the year ended December 31, 2018, the Company recorded transaction costs totaling approximately $14.3 million including $13.4 million associated with the terminated Sabalo Acquisition, and $0.8 million of legal fees related to the Bold Transaction which closed on May 9, 2017.

Note 4.5. 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~~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.

EARTHSTONE ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

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 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, ~~2016.~~

~~F-17~~

~~EARTHSTONE ENERGY, INC.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)~~

2019.

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.~~

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):

December 31, 2016

Level 1

Level 2

Level 3

Total

Financial liabilities

Derivative liability

$
—

$
4,595

$
—

$
4,595

Derivative liability

—

1,575

—

1,575

Total financial liabilities

$
—

$
6,170

$
—

$
6,170

December 31, 2015

Financial assets

Derivative asset

$
—

$
3,694

$
—

$
3,694

Total financial assets

$
—

$
3,694

$
—

$
3,694



December 31, 2019	Level 1		Level 2		Level 3		Total
Financial assets
Derivative asset- current	$	—	$	8,860	$	—	$	8,860
Derivative asset- noncurrent	—		770		—		770
Total financial assets	$	—	$	9,630	$	—	$	9,630
Financial liabilities
Derivative liability - current	$	—	$	6,889	$	—	$	6,889
Derivative liability - noncurrent	—		—		—		—
Total financial liabilities	$	—	$	6,889	$	—	$	6,889
December 31, 2018
Financial assets
Derivative asset- current	$	—	$	43,888	$	—	$	43,888
Derivative asset- noncurrent	—		21,121		—		21,121
Total financial assets	$	—	$	65,009	$	—	$	65,009
Financial liabilities
Derivative liability - current	$	—	$	528	$	—	$	528
Derivative liability - noncurrent	—		1,891		—		1,891
Total financial liabilities	$	—	$	2,419	$	—	$	2,419

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.

~~Property Impairments~~

Proved Oil and Natural Gas Properties

Proved oil and natural gas properties are ~~measured at fair value~~reviewed for impairment on a nonrecurring basis. The impairment charge reduces the carrying values ~~of oil and gas properties’~~ to their estimated fair values. These fair value measurements are classified as Level 3 measurements and include

EARTHSTONE ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

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 6.7. Oil and Natural Gas ~~Properties~~Properties..

Goodwill

~~F-18~~

~~EARTHSTONE ENERGY, INC.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)~~

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 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~~risk-free rate. See Note 12 14.Asset Retirement Obligations for a reconciliation of the beginning and ending balances of the liability for the Company’s asset retirement obligations.

Note 5.6. Derivative Financial Instruments

The ~~Company is exposed~~Company’s hedging activities consist of derivative instruments entered into in order to ~~certain risks relating to its ongoing business operations, such as commodity price risk. Derivative contracts are utilized to economically~~ hedge ~~the Company’s exposure to price fluctuations and reduce the variability~~against changes in ~~the Company’s cash flows associated with anticipated sales of future~~ oil and natural gas ~~production.~~ 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, 2020. 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 follows FASB ASC Topic 815,~~ ~~Derivatives and Hedging,~~Company’s derivative instruments are cash flow hedge transactions in which it is hedging the variability of cash flow related to ~~account for its derivative financial instruments.~~a forecasted transaction. The Company does not enter into derivative ~~contracts~~instruments for trading or other speculative ~~trading~~ purposes. ~~It is~~These transactions are recorded in the ~~Company’s policy to enter into derivative contracts only~~Consolidated Financial Statements in accordance with ~~counterparties that are creditworthy financial institutions deemed by management as competent and competitive. The Company did not post collateral under any of these contracts.~~

The Company’s crude oil and natural gas derivative positions consist of swaps. Swaps are designed so that the Company receives or makes payments based on a differential between fixed and variable prices for crude oil and natural gas.FASB ASC Topic 815. The Company has ~~elected to not designate any of its derivative contracts~~accounted for ~~hedge~~these transactions using the mark-to-market accounting ~~purposes. Accordingly,~~method. Generally, the Company ~~records the net change in the mark-to-market valuation of these derivative contracts, as well as all payments~~incurs accounting losses on derivatives during periods where prices are rising and ~~receipts on settled derivative contracts, in~~ ~~(Loss) gain on derivative contracts, net~~ ~~on the Consolidated Statements of Operations. All derivative contracts~~gains during periods where prices are ~~recorded at fair market value~~falling which may cause significant fluctuations in the Consolidated Balance Sheets ~~as assets or liabilities.~~

~~With an individual derivative counterparty, the Company may have multiple hedge positions that expire at various points in the future~~ and ~~result in fair value asset and liability positions. At the end~~Consolidated Statements of each reporting period, those positions are offset to a single fair value asset or liability for each commodity by counterparty, and the netted balance is reflected in the Consolidated Balance Sheets as an asset or a liability.

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 Company had the following open crude oil and natural gas derivative contracts as of December 31, 2016:~~

currency.

Price Swaps

Period

Commodity

Volume
(Bbls / MMBtu)

Weighted Average Price
($/Bbl / $/MMBtu)

Q1 - Q4 2017

Crude Oil

600,000

$
50.38

Q1 - Q4 2018

Crude Oil

270,000

$
50.70

Q1 - Q4 2017

Natural Gas

1,740,000

$
2.997

Q1 - Q4 2018

Natural Gas

600,000

$
2.907

~~F-19~~

EARTHSTONE ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

The following table sets forth the Company’s outstanding derivative contracts at December 31, 2019. When aggregating multiple contracts, the weighted average contract price is disclosed.



Period	Commodity	Volume (Bbls / MMBtu)	Price ($/Bbl / $/MMBtu)
2020	Crude Oil Swap	2,928,000	$60.31
2020	Crude Oil Basis Swap (1)	366,000	$2.55
2020	Crude Oil Basis Swap (2)	2,562,000	$(1.40)
2020	Natural Gas Swap	2,562,000	$2.85
2020	Natural Gas Basis Swap (3)	2,562,000	$(1.07)
2021	Crude Oil Swap	1,095,000	$55.00
2021	Crude Oil Basis Swap (2)	1,095,000	$0.89


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


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


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

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):

December 31, 2016

December 31, 2015

Derivatives not
designated as hedging
contracts under ASC
Topic 815

Balance Sheet Location

Gross
Recognized
Assets /
Liabilities

Gross
Amounts
Offset

Net
Recognized
Assets /
Liabilities

Gross
Recognized
Assets /
Liabilities

Gross
Amounts
Offset

Net
Recognized
Assets /
Liabilities

Commodity contracts

Derivative asset

$
—

$
—

$
—

$
3,694

$
—

$
3,694

Commodity contracts

Derivative liability

$
4,595

$
—

$
4,595

$
—

$
—

$
—

Commodity contracts

Derivative liability

$
1,575

$
—

$
1,575

$
—

$
—

$
—



		December 31, 2019							December 31, 2018
Derivatives not designated as hedging contracts under ASC Topic 815	Balance Sheet Location	Gross Recognized Assets / Liabilities		Gross Amounts Offset			Net Recognized Assets / Liabilities		Gross Recognized Assets / Liabilities		Gross Amounts Offset			Net Recognized Assets / Liabilities
Commodity contracts	Derivative asset - current	$	13,321	$	(4,461	)	$	8,860	$	48,662	$	(4,774	)	$	43,888
Commodity contracts	Derivative liability - current	$	11,350	$	(4,461	)	$	6,889	$	5,302	$	(4,774	)	$	528
Commodity contracts	Derivative asset - noncurrent	$	1,031	$	(261	)	$	770	$	23,605	$	(2,484	)	$	21,121
Commodity contracts	Derivative liability - noncurrent	$	261	$	(261	)	$	—	$	4,375	$	(2,484	)	$	1,891

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 and Consolidated Statements of Cash Flows (in thousands):

Years Ended December 31,

2016

2015

2014

Derivatives not designated as hedging contracts under ASC Topic 815

Statement of Operations Location

Total (loss) gain on commodity contracts

(Loss) gain on derivative contracts, net

$
(9,863
)

$
125

$
3,614

Cash settlements on commodity contracts

(Loss) gain on derivative contracts, net

3,225

6,306

778

(Loss) gain on commodity contracts, net

$
(6,638
)

$
6,431

$
4,392



Derivatives not designated as hedging contracts under ASC Topic 815			Years Ended December 31,
	Statement of Cash Flows Location	Statement of Operations Location	2019			2018
Unrealized (loss) gain	Not presented separately	Not presented separately	$	(59,849	)	$	76,037
Realized gain (loss)	Operating portion of net cash paid in settlement of derivative contracts	Not presented separately	15,866			(15,090		)
	Total loss (gain) on derivative contracts, net	(Loss) gain on derivative contracts, net	$	(43,983	)	$	60,947

Note 6.7. 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

EARTHSTONE ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

expense for oil and natural gas producing property and related equipment was ~~$25.4 million, $30.7~~$68.5 million and ~~$18.1~~$47.1 million for the years ended December 31, ~~2016, 2015,~~2019 and ~~2014,~~2018, respectively.

Proved Oil and Natural Gas Properties

~~The Company reviews its proved~~

Proved oil and natural gas properties are reviewed for impairment ~~when~~ ~~events and circumstances indicate~~on a ~~decline in the recoverability of~~nonrecurring basis. The impairment charge reduces the carrying values ~~of such properties, such~~to their estimated fair values. These fair value measurements are classified as ~~a negative revision of reserves estimates or sustained decrease in commodity prices. We estimate~~Level 3 measurements and include many unobservable inputs. Fair value is calculated as the estimated discounted future net cash flows ~~expected~~attributable to the assets. The Company’s primary assumptions in ~~connection with~~preparing the ~~properties and compare such~~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 ~~carrying amount~~estimated discount rate that would be used by potential purchasers to determine the fair value of the ~~properties to determine if the carrying amount is recoverable.~~ ~~If, upon review, the sum of the undiscounted pretax cash flows is less than the carrying amount, then the carrying amount is written down to its estimated fair value.~~

assets.

Unproved Oil and Natural Gas 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

~~F-20~~

~~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'~~the Company’s geologists’ evaluation of the property, and the remaining months in the lease term for the ~~property~~

property.

The Company ~~had the following~~recorded no non-cash asset impairment charges for the year ended December 31, 2019. During the year ended December 31, 2018, the Company recorded non-cash asset impairments of $4.6 million to its unproved oil and natural gas properties ~~for the years ended December 31, 2016, 2015 and 2014 (in thousands~~):

resulting from certain acreage expirations related to its Eagle Ford Trend properties.

Years Ended December 31,

2016

2015

2014

Proved property

$
2,873

$
93,984

$
16,903

Unproved property

3,878

42,555

2,456

Total

$
6,751

$
136,539

$
19,359

Accumulated impairments to proved and unproved oil and natural gas properties as of December 31, ~~2016~~2019 and ~~2015,~~2018 were ~~$162.7 million and $155.9 million, respectively.~~

$121.1 million.

The Company did not have any non-cash impairment charges to its goodwill for the ~~year~~years ended December 31, ~~2014.~~

~~Delaware~~		~~84-0592823~~

Delaware	84-0592823
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)



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



Large accelerated filer	☐	Accelerated filer	☑

Non-accelerated filer	☐ ~~(Do not check if a smaller reporting company)~~	Smaller reporting company	☐ ☑
Emerging growth Company	☐

				~~Page~~

		Page
Glossary of Certain Oil and Natural Gas Terms			5

PART I
Item 1.	Business		8
Item 1A.	Risk Factors		17 21
Item 1B.	Unresolved Staff Comments		28 37
Item 2.	Properties		28 37
Item 3.	Legal Proceedings		35 46
Item 4.	Mine Safety Disclosures		35 46
PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	��	38 47
Item 6.	Selected Financial Data		40 47
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		40 47
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		53 58
Item 8.	Financial Statements and Supplemental Data		54 58
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		54 58
Item 9A.	Controls and Procedures		54 58
Item 9B.	Other Information		57 60
PART III
Item 10.	Directors, Executive Officers and Corporate Governance		58 60
Item 11.	Executive Compensation		64 60
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		71 60
Item 13.	Certain Relationships and Related Transactions, and Director Independence		73 60
Item 14.	Principal ~~Accountant~~Accounting Fees and Services		74 60
PART IV
Item 15.	Exhibits, Financial Statements ~~and~~ Schedules		75 61
Item 16.	Form 10-K Summary	63
Signatures			79 64

	Oil (MBbl)		Natural Gas (MMcf)		NGL (MBbl)		Total (MBOE) ⁽¹⁾		Present Value Discounted at 10% ($ in thousands)
Proved developed		6,052		13,545		1,051		9,361	$	83,242
Proved undeveloped		1,059		6,856		488		2,690		2,641
Total proved		7,111		20,401		1,539		12,051	$	85,883

☑

☑	ANNUAL REPORT ~~UNDER~~PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

☐

☐	TRANSITION REPORT ~~UNDER~~PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934



	Oil (MBbl)	Natural Gas (MMcf)	NGLs (MBbl)	Total (MBOE)⁽²⁾	% of Total Proved		Undiscounted Future Net Cash Flows ($ in thousands)		PV-10 ($ in thousands)		Standardized Measure of Discounted Future Net Cash Flows ($ in thousands)		Future Capital Expenditures ($ in thousands)
PDP	17,732	34,584	7,371	30,867	33	%	$	679,847	$	434,881	$	418,751	$	—
PDNP	488	536	76	654	1	%	18,217		13,652		13,146		586
PUD	34,430	72,870	16,241	62,815	66	%	896,648		371,459		357,680		628,106
Total proved ⁽¹⁾	52,650	107,990	23,688	94,336	100	%	$	1,594,712	$	819,992	$	789,577	$	628,692


(1)	Includes 28.7 MMBbl of oil, 58.9 Bcf of natural gas and 12.9 MMBbl of NGLs reserves attributable to noncontrolling interests. Additionally, $447.0 million of PV-10 and $430.4 million of standardized measure of discounted future net cash flows were attributable to noncontrolling interests.


(2)	Barrels of oil equivalent have been calculated on the basis of six thousand cubic feet (Mcf) of natural gas equal to one barrel of oil equivalent (BOE). ~~Natural gas liquids have been converted to MBbls.~~

Present value of estimated future net revenues (PV-10)	$	85,883
Future income taxes, discounted at 10%		—
Standardized measure of discounted future net revenues	$	85,883


(1)	Includes $447.0 million attributable to noncontrolling interests.


(2)	Includes $430.4 million attributable to noncontrolling interests.



	Years Ended
	December 31,
	2019		2018
Net income	1,580		95,213
Accretion of asset retirement obligations	214		169
Impairment expense	—		4,581
Depletion, depreciation and amortization	69,243		47,568
Interest expense, net	6,566		2,898
Transaction costs	1,077		14,337
(Gain) on sale of oil and gas properties, net	(3,222	)	(1,919	)
Exploration expense	653		630
Unrealized loss (gain) on derivative contracts	59,849		(76,037	)
Stock based compensation (non-cash)⁽¹⁾	8,648		7,071
Income tax expense	1,665		2,470
Adjusted EBITDAX	146,273		96,981


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



	Oil (MBbl)		Natural Gas (MMcf)		NGLs (MBbl)		Total (MBOE)
Balance - December 31, 2017	47,327		91,088		17,468		79,976
Extensions and discoveries	10,148		17,673		3,116		16,209
Sales of minerals in place	(2,651	)	(14,300	)	(1,562	)	(6,596	)
Purchases of minerals in place	3,532		9,890		1,629		6,810
Production	(2,370	)	(3,610	)	(655	)	(3,627	)
Revision to previous estimates	3,048		12,476		947		6,075
Balance - December 31, 2018	59,034		113,217		20,943		98,847
Extensions and discoveries	3,598		4,476		721		5,065
Sales of minerals in place	(31	)	(4	)	(1	)	(32	)
Production	(3,086	)	(4,760	)	(1,022	)	(4,902	)
Revision to previous estimates	(6,865	)	(4,939	)	3,047		(4,642	)
Balance - December 31, 2019	52,650		107,990		23,688		94,336
Proved developed reserves:
December 31, 2017	11,949		23,336		4,123		19,961
December 31, 2018	14,325		26,110		4,969		23,646
December 31, 2019	18,220		35,120		7,447		31,521
Proved undeveloped reserves:
December 31, 2017	35,378		67,752		13,345		60,015
December 31, 2018	44,709		87,107		15,974		75,201
December 31, 2019	34,430		72,870		16,241		62,815



Years Ended December 31, ⁽¹⁾	Future Production (MBOE) ⁽²⁾	Future Cash Inflows ⁽³⁾		Future Production Costs		Future Development Costs		Future Net Cash Flows
2020	1,541	$	66,705	$	8,048	$	111,077	$	(52,420	)
2021	3,954	160,948		22,784		193,341		(55,177		)
2022	6,164	240,946		37,450		191,197		12,299
2023	7,983	300,405		46,810		112,631		140,964
2024	5,949	208,057		37,115		19,860		151,082
Thereafter	37,224	1,145,081		445,181		—		699,900
Total	62,815	$	2,122,142	$	597,388	$	628,106	$	896,648

	Years Ended December 31,
	2016		2015		2014
Sales Volumes:
Oil (MBbl)		878		904		403
Natural gas (MMcf)		2,171		2,143		2,132
Natural gas liquids (MBbl)		225		176		124
Barrels of oil equivalent (MBOE)*		1,465		1,437		882

Average prices realized:**
Oil (per Bbl)	$	39.13	$	44.09	$	86.29
Natural gas (per Mcf)	$	2.32	$	2.55	$	4.39
Natural gas liquids (per Bbl)	$	12.74	$	12.29	$	28.29
Barrels of oil equivalent (per BOE)	$	28.86	$	33.04	$	53.99

Production cost per BOE***	$	10.06	$	10.72	$	11.39



As of December 31, 2019	Oil (MBbl)	Natural Gas (MMcf)	NGLs (MBbl)	Total (MBOE)
Proved developed	9,933	19,146	4,060	17,183
Proved undeveloped	18,769	39,724	8,853	34,243
Total proved	28,702	58,870	12,913	51,426

As of December 31, 2018	Oil (MBbl)	Natural Gas (MMcf)	NGLs (MBbl)	Total (MBOE)
Proved developed	7,917	14,430	2,746	13,068
Proved undeveloped	24,709	48,140	8,828	41,560
Total proved	32,626	62,570	11,574	54,628



Proved undeveloped reserves at December 31, ~~2015~~ 2017(1)	60,015		~~3,961~~
Conversions to developed	(4,419		~~(169~~	)
Extensions and discoveries	13,734		~~293~~
~~Purchases~~ Sales of minerals in place	(4,702		~~873~~	)
~~Revisions~~ Purchases of minerals in place	4,735		~~(2,268~~	)
Revision to previous estimates	5,838

Proved undeveloped reserves at December 31, ~~2016~~ 2018 (2)	75,201		~~2,690~~
Conversions to developed	(10,254	)
Extensions and discoveries	1,230
Revision to previous estimates	(3,362	)
Proved undeveloped reserves at December 31, 2019 (3)	62,815


(1)	Includes 34,029 MBOE attributable to noncontrolling interests.


(2)	Includes 41,560 MBOE attributable to noncontrolling interests.


(3)	Includes 34,243 MBOE attributable to noncontrolling interests.


(3)	Computation is based on SEC pricing of (i) $52.60 per Bbl (WTI-Cushing oil spot prices, adjusted for differentials), (ii) $0.91 per Mcf (Henry Hub spot natural gas price), as adjusted for location and quality by property and (iii) $16.17 per Bbl for natural gas liquids.


**	Amounts exclude the impact of cash paid/received on settled derivative contracts as we did not elect to apply hedge accounting.


***	~~Transportation costs remain included in these amounts, but exclude ad valorem taxes.~~

	Year Ended December 31,
	2016
Sales Volumes:
Oil (MBbl)		139
Natural gas (MMcf)		352
Natural gas liquids (MBbl)		68
Barrels of oil equivalent (MBOE)*		266

Average prices realized:**
Oil (per Bbl)	$	45.07
Natural gas (per Mcf)	$	2.43
Natural gas liquids (per Bbl)	$	15.73
Barrels of oil equivalent (per BOE)	$	30.83

Production cost per BOE***	$	9.92

Oil ⁽¹⁾				Natural Gas ⁽¹⁾				Total ⁽¹⁾
Gross Wells		Net Wells		Gross Wells		Net Wells		Gross Wells		Net Wells
	462		135		164		50		626		185



	Oil		Natural Gas		Total
	Gross	Net	Gross	Net	Gross	Net
Midland Basin	210	116	2	1	212	117
Eagle Ford Trend	122	52	—	—	122	52

	Developed				Undeveloped				Total
State	Gross		Net		Gross		Net		Gross		Net
Texas		75,400		27,700		135,900		67,000		211,300		94,700
Oklahoma		16,200		13,900		—		—		16,200		13,900
Montana		6,200		2,200		4,700		1,100		10,900		3,300
North Dakota		21,600		2,500		6,800		3,400		28,400		5,900
Wyoming		600		300		1,400		600		2,000		900
Nebraska		—		—		18,400		8,300		18,400		8,300
All Others		3,500		2,500		16,300		600		19,800		3,100
Total		123,500		49,100		183,500		81,000		307,000		130,100



	Expiring Acreage
	2020		2021		2022		Total
	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Midland Basin	1,365	1,109	40	10	518	495	1,923	1,614
Eagle Ford Trend	882	188	793	453	2,546	1,737	4,221	2,378
Total	2,247	1,297	833	463	3,064	2,232	6,144	3,992

	Net Exploratory Wells Drilled				Net Development Wells Drilled				Total Net Productive and Dry Wells
Year	Productive		Dry		Productive		Dry		Drilled
2016		—		—		7.7		—		7.7
2015		—		—		7.2		—		7.2
2014		—		—		7.3		—		7.3


(1)	The dry hole category includes one gross (0.2 net) non-operated well that was unsuccessful due to mechanical issues.

~~Name~~	~~Age~~	~~Position~~
~~Frank A Lodzinski~~	67	~~President and Chief Executive Officer~~
~~Tony Oviedo~~	63	~~Executive Vice President, Accounting and Administration (Principal Accounting Officer)~~
~~Ray Singleton~~	65	~~Executive Vice President, Northern Region~~
~~Robert J. Anderson~~	55	~~Executive Vice President, Corporate Development and Engineering~~
~~Steve C. Collins~~	52	~~Executive Vice President, Completions and Operations~~
~~Christopher E. Cottrell~~	56	~~Executive Vice President, Land and Marketing and Corporate Secretary~~
~~Timothy D. Merrifield~~	61	~~Executive Vice President, Geological and Geophysical~~
~~Francis M. Mury~~	65	~~Executive Vice President, Drilling and Development~~

	Common Stock Price
Period	High		Low
2016
First Quarter	$	14.19	$	10.75
Second Quarter	$	15.93	$	10.12
Third Quarter	$	11.66	$	7.67
Fourth Quarter	$	15.71	$	8.02

2015
First Quarter	$	31.00	$	19.40
Second Quarter	$	28.90	$	17.65
Third Quarter	$	20.15	$	12.11
Fourth Quarter	$	18.50	$	12.99



	Total Number of Shares Purchased ⁽¹⁾	Average Price Paid Per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plan or Programs
October 2019	—	—		—	—
November 2019	—	—		—	—
December 2019	51,678	$	5.94	—	—


(1)	All of the shares were surrendered by employees (via net settlement) in satisfaction of tax obligations upon the vesting of restricted stock unit awards. The acquisition of the surrendered shares was not part of a publicly announced program to repurchase shares of our Class A Common Stock.

	12/31/2011		12/31/2012		12/31/2013		12/31/2014		12/31/2015		12/31/2016
Earthstone Energy, Inc.	$	100.00	$	100.32	$	119.82	$	152.20	$	86.20	$	88.99
S&P 500 Index - Total Return	$	100.00	$	116.00	$	153.57	$	174.60	$	177.01	$	198.18
S&P 500 Oil & Gas Exploration & Production Index - Total Return	$	100.00	$	103.65	$	132.14	$	118.15	$	77.80	$	103.36