EARTHSTONE ENERGY INC - Annual Report: 2015 (Form 10-K)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

For the Fiscal Year Ended December 31, 2015

Or

Commission File No. 001-35049  

EARTHSTONE ENERGY, INC.

(Exact name of registrant as specified in its charter)

1400 Woodloch Forest Drive, Suite 300

The Woodlands, Texas 77380

(Address of principal executive offices)

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

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

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

None

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

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

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

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

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

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

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

The aggregate market value of voting and non-voting common equity held by non-affiliates computed by reference to the price of $19.53 per share at which the common equity was last sold, as of the last business day of the registrant’s most recently completed second fiscal quarter was approximately $83,152,373.

As of March 9, 2016 13,835,128 shares of the registrant’s common stock were outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Registrant’s Definitive Proxy Statement for its 2016 Annual Meeting of Stockholders (the “Proxy Statement”), are incorporated by reference into Part III of this report Annual Report on Form 10-K.

TABLE OF CONTENTS

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CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS

Certain statements contained in this report may contain “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements other than statements of historical facts contained in this report are forward-looking statements. These forward-looking statements can generally be identified by the use of words such as “may,” “will,” “could,” “should,” “project,” “intends,” “plans,” “pursue,” “target,” “continue,” “believes,” “anticipates,” “expects,” “estimates,” “predicts,” or “potential,” the negative of such terms or variations thereon, or other comparable terminology. Statements that describe our future plans, strategies, intentions, expectations, objectives, goals or prospects are also forward-looking statements. Actual results could differ materially from those anticipated in these forward-looking statements. Readers should consider carefully the risks described under the “Risk Factors” section of this report and other sections of this report which describe factors that could cause our actual results to differ from those anticipated in forward-looking statements, including, but not limited to, the following factors:

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All forward-looking statements are expressly qualified in their entirety by the cautionary statements in this section and elsewhere in this report. Other than as required under the securities laws, we do not assume a duty to update these forward-looking statements, whether as a result of new information, subsequent events or circumstances, changes in expectations or otherwise.

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

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GLOSSARY OF CERTAIN OIL AND NATURAL GAS TERMS

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

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

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

Behind-pipe reserves – Those reserves expected to be recovered from completion interval(s) not yet open but still behind casing in existing wells. These reserves, if they meet the criteria for proved reserves, will be included in the PDNP category of our reserves.

BOE – Barrel of oil equivalent, determined using a ratio of six Mcf of natural gas equal to one barrel of oil equivalent.

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

Completion – 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 agency.

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

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

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

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

Exploitation – The act of making an oil and natural gas property more profitable, productive or useful.

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

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

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

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

HBP – Held by production, a mineral lease provision that extends the right to operate a lease as long as the property produces a minimum quantity of oil and 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. Greater horizontal exposure to a hydrocarbon bearing reservoir typically results in increased production rates and greater ultimate recoveries of hydrocarbons than vertical drilling.

Hydraulic fracture (Frac) – A well stimulation method by which fluid (approximately 95-98% water) and proppant (purposely sized particles used to hold open an induced fracture) are injected downhole and into the producing formation at high pressures and rates in order to exceed the rock strength and create a fracture such that the proppant material can be placed into the fracture to enhance the productive capability of the formation.

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

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

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

MMBtu – One million Btu.

Mcf – One thousand cubic feet.

MMcf – One million cubic feet.

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

NGLs – Natural gas liquids measured in barrels.

NYMEX – The New York Mercantile Exchange.

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

PV-10 – The present value of estimated future revenues, discounted at 10% annually, to be generated from the production of proved reserves determined in accordance with 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) depreciation, depletion and amortization.

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

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

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

Proved developed producing reserves or PDP – Reserves that can be expected to be recovered through existing wells 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

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

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

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

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

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

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.

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

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

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

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PART I

Item 1. Business

Overview

Earthstone Energy, Inc. (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 exploration and production company focused on the acquisition, development, exploration and production of onshore, crude oil and natural gas reserves. Our strategy, which is discussed in greater detail below, is to deliver competitive and sustainable rates of return to our stockholders by developing and acquiring oil and natural gas reserves through an active and diversified program that includes the acquisition, drilling and development of undeveloped leases, purchases of reserves and exploration activities that currently involve oil-weighted projects.

Our operations are all in the upstream segment of the oil and natural gas industry and are conducted onshore in the United States.  Our asset portfolio currently includes activities in the Eagle Ford trend of south Texas and in the Williston Basin of North Dakota and Montana. These regions are a focus for us, as well as other areas in Texas. We also own other operated and non-operated properties in east and south Texas and eastern Oklahoma, which may be divested in the future. We have approximately 21,500 net leasehold acres in the Eagle Ford trend of south Texas, including 18,600 net leasehold acres in the crude oil window in Fayette, Gonzales and Karnes Counties, Texas, and 2,900 net leasehold acres located in the natural gas and condensate window in La Salle County. We serve as the operator for substantially all of our Fayette, Gonzales and Karnes County acreage with working interests ranging from 33% to 50% and we are a non-operator with respect to our La Salle County acreage with working interests ranging typically 10% to 15%. We are also non-operator with respect to the majority of our properties in the Williston Basin. We continuously evaluate opportunities to expand our acreage and our producing assets through acquisitions. Our successful acquisition of assets will depend on the opportunities and the financing alternatives available to us at the time we consider such opportunities.

Our corporate headquarters is located in The Woodlands, Texas.  We also have an operating office in Denver, Colorado and two field offices in south Texas. Our common stock is traded on the NYSE MKT under the symbol ESTE.    

Recent Developments

Acquisitions

On December 16, 2015, we entered into an Arrangement Agreement (the “Arrangement Agreement”), among Lynden Energy Corp., a corporation existing under the laws of British Columbia, Canada (“Lynden”), Earthstone and 1058286 B.C. Ltd., a company organized under the laws of British Columbia, Canada and wholly-owned subsidiary of Earthstone (“Merger Sub”), pursuant to which Merger Sub will acquire all of the outstanding shares of common stock of Lynden (the “Lynden Shares”) and as an integral part of such acquisition, Merger Sub and Lynden will amalgamate to continue as one corporate entity with Lynden surviving the amalgamation as part of a plan of arrangement (the “Transaction”).   Under the Arrangement Agreement, the terms of which were unanimously approved by the Boards of Directors of Earthstone, Lynden and Merger Sub, Earthstone will issue approximately 3.7 million shares of its common stock, (“Earthstone Common Stock”), to Lynden stockholders.

Under the Arrangement Agreement, Lynden stockholders will receive 0.02842 shares of Earthstone Common Stock in exchange for each share of Lynden common stock held. Following the Transaction, stockholders of Earthstone and Lynden are expected to own approximately 79% and 21%, respectively, of the combined company on a fully diluted basis. The Transaction is expected to close in the second quarter of 2016.

On December 19, 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 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 oil and natural gas properties located in Fayette and Gonzales Counties, Texas, in exchange for the issuance of approximately 2.957 million shares of our common stock (the “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%.

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For further discussion of the Exchange and the Contribution Agreement, see Note 3 Acquisitions and Divestitures within the Notes to the Consolidated Financial Statements included in Item 8 of this report.

Our Business Strategy

We pursue a value-driven growth strategy focused on projects that we believe will generate strong and predictable rates of return and increases in stockholder value. Although we have significant non-operated properties, we believe that we should be the operator of 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. We also believe that a reasonable level of diversification in our asset base is preferable to that of a single basin focused company as it may provide us the ability to take advantage of regional changes in realized prices, service costs, service availability and numerous other factors that may affect the cost-efficient and economic development of our assets. Management concentrates on building production, reserves and cash flows while seeking to expand our undeveloped acreage and drilling inventory in select targeted areas. Further expansion of our asset base will be achieved through cost efficient development, exploitation and operation of our current assets and acreage and through additional leasing, acquisitions, development drilling and exploration activities, currently directed toward oil-weighted projects. Finally, management intends to pursue corporate and asset acquisition opportunities.

Our business strategy includes the following:

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

Management believes its strategy is appropriate because it:

Our Operations

We are the operator of properties containing approximately 67% of our proved oil and natural gas reserves and 73% of our proved PV-10 as of December 31, 2015. As operator, we are able to directly influence exploration, development and production of operations of our operating properties. Our producing properties have reasonably predictable production profiles and cash flows, subject to commodity price fluctuations.  Our status as an operator has allowed us to pursue the development of undeveloped acreage, further develop existing properties and generate new projects that we believe have the potential to increase stockholder value.

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

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Description of Major Properties

The following is a brief description of our primary oil and natural gas properties and current focus areas. We also own operated and non-operated properties located in east and south Texas, and eastern Oklahoma.  

Fayette County, Texas and Gonzales County, Texas

Operated Eagle Ford

As of December 31, 2015, we accumulated approximately 38,000 gross (18,600 net) leasehold acres in Gonzales, Fayette 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 50% undivided ownership interest in substantially all of the acreage.

As of December 31, 2015, we operated 62 gross Eagle Ford wells and eight gross Austin Chalk wells and had non-operated interests in two gross producing Eagle Ford wells and one gross producing Austin Chalk well.  Twelve gross Eagle Ford wells and one upper Austin Chalk well were in the process of being drilled or were waiting on completion at December 31, 2015. Our plan is to complete four Eagle Ford wells and one upper Austin Chalk well during 2016. We have identified a total of approximately 220 gross Eagle Ford drilling locations in our acreage. The number of Eagle Ford locations could potentially increase subject to future down spacing initiatives. 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 a 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.

We are currently budgeting $4.5  million to $6.0 million per well to drill and complete Eagle Ford wells with completed lateral lengths of approximately 4,500-7,000 feet, and $4.0 million to $4.5 million per well to drill and complete Austin Chalk wells with lateral lengths of approximately 13,000 feet.

Non-Operated Eagle Ford

We have a non-operated position in approximately 25,400 gross 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:

Williston Basin

We have a non-operated position in approximately 10,900 net acres in the Williston Basin of North Dakota and Montana.  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 4.1% in 77 horizontal Bakken/Three Forks producing wells that are primarily operated by Statoil. We have an additional 27 wells waiting on completion in the Banks Field. We have identified approximately 140 potential drilling locations which are in existing producing units throughout the Bakken/Three Forks play.

Competition

The domestic oil and natural gas business is intensely competitive in the exploration for and acquisition of reserves and in the producing and marketing of oil and natural gas production. Our competitors include national oil companies, major oil and natural gas companies, independent oil and natural gas companies, individual producers, natural gas marketers, and major pipeline companies, as well as participants in other industries supplying energy and fuel to consumers.  

Seasonality of Business

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

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Operational Risks

Oil and natural gas exploration and development involves 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 discover or acquire 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 or cash flows. For further discussion of risks see Item 1A. Risk Factors of this report.

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 such properties. Our properties are typically subject, in one degree or another, to one or more of the following:

To the extent that such burdens and obligations affect our rights to production revenues, they have been taken into account in calculating our net revenue interests and in estimating the size and value of our reserves. We believe that the burdens and obligations affecting our properties are conventional in the industry for properties of the kind that we own.

Regulations

All of the jurisdictions in which we own or operate producing oil and natural gas properties have statutory provisions regulating the exploration for and production of 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, some states allow the forced pooling or integration of land and leases to facilitate exploration while other states rely primarily or exclusively on voluntary pooling of land and leases. In areas where pooling is primarily or exclusively voluntary, it may be difficult to form spacing units and therefore difficult to develop a project if the operator owns 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, tribal and local authorities have imposed moratoria or other restrictions on exploration and production activities pending investigations and studies addressing potential local impacts of these activities before allowing oil and natural gas exploration 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.

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Environmental Regulations

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

Hazardous Substances and Wastes

The federal Comprehensive Environmental Response, Compensation, and Liability Act, referred to as CERCLA or the Superfund law, and comparable state laws impose liability, without regard to fault, on certain classes 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 at the site. Under CERCLA, these persons may be subject to 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 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 the federal Solid Waste Disposal Act, as amended by the Resource Conservation and Recovery Act of 1976, referred to as RCRA, most wastes generated by the exploration and production of oil and natural gas are not regulated as hazardous wastes. Periodically, however, there are proposals to lift the existing exemption for oil and natural gas wastes and reclassify them as hazardous wastes. If such proposals were to be enacted, they could have a significant impact on our operating costs, as well as the oil and natural gas industry in general. In the ordinary course of our operations moreover, some wastes generated in connection with our exploration and production activities may be regulated as solid waste under RCRA, as hazardous waste under existing RCRA regulations or as hazardous substances under CERCLA. 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 federal Clean Water Act and analogous state laws. Under the Clean Water Act, the EPA has adopted regulations concerning discharges of storm water runoff. This program requires covered facilities to obtain 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, or be included under, these permits, where necessary, and make minor modifications to existing facilities and operations that would not have a material effect on us. The Clean Water Act and similar 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 for such discharges could result in civil and criminal penalties, orders to cease such 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 with on-site storage of significant quantities of oil.

Our oil and natural gas production also generates salt water, which we dispose of by underground injection.  The federal Safe Drinking Water Act (“SDWA”), the Underground Injection Control (“UIC”) regulations promulgated under the SDWA and related state programs regulate the drilling and operation of salt water disposal wells. The EPA directly administers the UIC program in some states, and in others it is delegated to the state for administering. Permits must be obtained before drilling salt water disposal wells, and casing integrity monitoring must be conducted periodically to ensure the casing is not leaking salt water to groundwater. Contamination of groundwater by oil and natural gas drilling, production, and related operations may result in fines, penalties, and

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remediation costs, among other sanctions and liabilities under the SDWA and state laws. In addition, third party claims may be filed by landowners and other parties claiming damages for alternative water supplies, property damages, and bodily injury.

Hydraulic Fracturing

Our completion operations are subject to regulation, which may increase in the short- or long-term. In particular, the well completion technique known as hydraulic fracturing is used to stimulate production of natural gas and oil has come under increased scrutiny by the environmental community, and local, state and federal jurisdictions. 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 depth to stimulate oil and natural gas production.

Under the direction of Congress, the EPA has undertaken a study of the effect of hydraulic fracturing on drinking water and groundwater. The EPA has also announced its plan to propose pre-treatment standards under the Clean Water Act for wastewater discharges from shale hydraulic fracturing operations. Congress may consider legislation to amend the SDWA to require the disclosure of chemicals used by the oil and natural gas industry in the hydraulic fracturing process. Certain states, including Colorado, Utah and Wyoming, have issued similar disclosure rules. Several environmental groups have also petitioned the EPA to extend toxic release reporting requirements under the Emergency Planning and Community Right-to-Know Act to the oil and natural gas extraction industry.

Air Emissions

The federal Clean Air Act and comparable state laws regulate 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 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, the EPA issued four new regulations for the oil and natural gas industry, including: a new source performance standard for volatile organic compounds (“VOCs”); a new source performance standard for sulfur dioxide; an air toxics standard for oil and natural gas production; and an air toxics standard for natural gas transmission and storage. The final rule includes the first federal air standards for natural gas wells that are hydraulically fractured, or refractured, as well as requirements for several sources, such as storage tanks and other equipment, and limits methane emissions from these sources. Compliance with these regulations has imposed additional requirements and costs on our operations.

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, the new standard could result in a significant expansion of ozone nonattainment areas across 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 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 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 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, at the state level, many states, either individually or through multi-state regional initiatives, have been implementing legal measures to reduce emissions of greenhouse gases, primarily through the 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 and reporting rules, the EPA has issued an “Endangerment Finding” under section 202(a) of the Clean Air Act, concluding greenhouse gas pollution threatens the public health and welfare of current and future generations. The finding served as the first step to issuing regulations that require permits for and reductions in greenhouse gas emissions for certain facilities.

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In addition, President Obama released a Strategy to Reduce Methane Emissions in March 2014. Consistent with that strategy, the EPA issued a proposed rule in 2015 that would set additional standards for methane and VOC emissions from oil and natural gas production sources, including hydraulically fractured oil wells and natural gas processing and transmission sources. The EPA intends to issue a final rule in 2016. In addition, the federal Bureau of Land Management (“BLM”) has proposed standards for reducing venting and flaring on public lands. The EPA and BLM actions are part of a series of steps by the Administration that are intended to result by 2025 in a 40-45% decrease in methane emissions from the oil and natural gas industry as compared to 2012 levels.  In the courts, several decisions have been issued that may increase the risk of claims being filed by governments and private parties against companies that have significant greenhouse gas emissions. Such cases may seek to challenge air emissions permits that greenhouse gas emitters apply for and seek to force emitters to reduce their emissions or seek damages for alleged climate change impacts to the environment, people, and property.

Any laws or regulations that may be adopted to restrict or reduce emissions of greenhouse gases could require us to incur additional operating costs, such as costs to purchase and operate emissions control systems or other compliance costs, and reduce demand for our products.

The National Environmental Policy Act

Oil and natural gas exploration and production activities may be subject to the National Environmental Policy Act, or NEPA. NEPA requires federal agencies, including the Department of the Interior, to evaluate major agency actions that have the potential to significantly impact the environment. In the course 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.

Threatened and endangered species, migratory birds and natural resources

Various state and federal 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, the Migratory Bird Treaty Act and the Clean Water Act.  The United States Fish and Wildlife Service may designate critical habitat areas that it believes are necessary for survival of threatened or endangered species. A critical habitat designation could result in further material restrictions on federal land use or on private land use and could delay or prohibit land access or development. Where takings of or harm to species or damages to wetlands, habitat, or natural resources occur or may occur, government entities or at times private parties may act to prevent or restrict oil and natural gas exploration activities or seek damages for any injury, whether resulting from drilling or construction or releases of oil, wastes, hazardous substances or other regulated materials, and in some cases, criminal penalties may result.

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 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 and the public.

Occupational Safety and Health Act

We are subject to the requirements of the federal Occupational Safety and Health Act and comparable state statues that regulate the protection of the health and safety of workers. In addition, the Occupational Safety and Health Administration’s 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

As of December 31, 2015, we had 50 full-time employees and one part-time employee, 37 of which are management, technical and administrative personnel, and 14 of which are field operations employees.  Contract personnel perform some technical and administrative tasks and operate some of our producing fields under the direct supervision of our employees.  No employees are covered under a collective bargaining agreement nor are any employees represented by a union.  The Company considers all relations with its employees to be good.

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Office Leases

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

During 2015, aggregate rental payments for our office facilities totaled approximately $0.8 million.

Executive Officers of the Company

Frank A. Lodzinski has served as our Chairman, President and Chief Executive Officer since December 2014.  Previously, he served as President and Chief Executive Officer of Oak Valley Resources, LLC from its formation in December 2012 until the closing of its strategic combination with us in December 2014.  Prior to his service with Oak Valley Resources, LLC, Mr. Lodzinski was Chairman, President and Chief Executive Officer of GeoResources, Inc. from April 2007 until its merger with Halcón in August 2012 and from September 2012 until December 2012 he conducted pre-formation activities for Oak Valley Resources, LLC.  He has over 44 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 audit committee of Yuma Energy, Inc. since September 2014. He holds a BSBA degree in Accounting and Finance from Wayne State University in Detroit, Michigan.

Ray Singleton is a petroleum engineer with over 38 years of experience in the oil and gas industry.  He has been one of our directors since July 1989 and was our President and Chief Executive Officer from March 1993 until December 2014. Since December 2014, he has served as our Executive Vice President, Northern Region. Mr. Singleton joined us in 1988 as a Production Manager/Petroleum Engineer. From 1983 until 1988, he owned and operated an engineering consulting firm (Singleton & Associates) serving the needs of 40 small oil and gas clients.  During this period, he was engaged by the Company on various projects in south Texas and the Rocky Mountain region.  Mr. Singleton began his career with Amoco Production Company in 1973 as a production engineer in Texas. He was subsequently employed by the predecessor of Union Pacific Resources as a drilling, completion and production engineer from 1980 to 1983. His professional experience includes acquisition evaluation and economics, reserve engineering and drilling, completion and production engineering in both Texas and the Rocky Mountain region.  In addition, he possesses over 20 years of executive experience and has an intimate knowledge of the Company’s legacy Rocky Mountain and south Texas properties.  Mr. Singleton received a B.S. degree in Petroleum Engineering from Texas A&M University in 1973, and received an MBA from Colorado State University’s Executive MBA Program in 1992.

Robert J. Anderson is a petroleum engineer with over 29 years of diversified domestic and international oil and gas experience. He has served as our Executive Vice President, Corporate Development and Engineering since December 2014.  Previously, he served in a similar capacity with Oak Valley Resources, LLC from March 2013 until the closing of its strategic combination with the Company in December 2014.  Prior to joining Oak Valley Resources, LLC, he served from August 2012 to February 2013 as Executive Vice

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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.

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

Christopher E. Cottrell has been employed in various aspects of land management and commodity marketing activities since 1983. He has served as our Executive Vice President, Land and Marketing and Corporate Secretary since December 2014.  Previously, he served in a similar capacity with Oak Valley Resources, LLC 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 Resources, LLC, he was employed by GeoResources, Inc. from April 2007 until its merger with Halcón in August 2012, ultimately serving as Vice President of Land and Marketing, responsible for land and operating contract matters including oil and gas marketing, land and lease records, title and division orders. In addition, he was actively involved in due diligence associated with business development matters. He has held previous roles at AROC, Texoil, Williams Exploration, Ashland Exploration, American Exploration, Belco Energy, and Citation Oil & Gas. Mr. Cottrell graduated with a B.B.A. degree in Petroleum Land Management from the University of Texas.

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

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

Neil K. Cohen has over 13 years of professional experience.   He has served as our Vice President, Finance, and Treasurer since December 2014. Previously, he served in a similar capacity with Oak Valley Resources, LLC from its formation in December 2012 until the closing of its strategic combination with the Company in December 2014.  He is primarily responsible for all corporate finance, capital markets, and investor relations activities. Prior to joining Oak Valley Resources, LLC, he served from September 2012 to December 2012 as a consultant to Texoil Energy, Inc. From February 2006 to October 2011, Mr. Cohen was employed by UBS Investment Bank as a member of the Global Energy Group, with exposure to all energy subsectors and a particular focus on mergers and acquisitions and equity and debt financings on behalf of exploration and production companies, and as a member of UBS’ Debt

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Capital Markets Group, with a particular focus on investment grade bond offerings on behalf of energy, utility, and real estate issuers.  He has held previous roles at Merrill Lynch (Debt Capital Markets and Debt Derivatives Finance) and Hess Corporation (Finance).  Mr. Cohen graduated with a B.S. degree in Finance from the University of Maryland.

G. Bret Wonson has over 15 years of professional experience. He has served as our Vice President, Principal Accounting Officer since December 2014.  Previously, he served in a similar capacity with Oak Valley Resources, LLC from February 2013 until the closing of its strategic combination with the Company in December 2014. Prior to Oak Valley Resources, LLC, he served from August 2012 to February 2013 as Assistant Controller at Halcón upon its merger with GeoResources, Inc. in August 2012. From February 2012 to August 2012 and from April 2008 to November 2010, Mr. Wonson was Corporate Controller and Controller of GeoResources, respectively. From December 2010 to January 2012, he was an Assistant Controller at Valerus Compression. He has held previous roles at Arthur Andersen, Grant Thornton, and BP. Mr. Wonson holds a bachelor’s degree in Accounting from Mississippi State University and a master’s degree in Accounting from the University of Alabama. Mr. Wonson is a Certified Public Accountant in the State of Texas.

There are no arrangements or understandings between any of Messrs. Lodzinski, Singleton, Anderson, Collins, Cottrell, Merrifield, Mury, Cohen and Wonson, or any other person pursuant to which such person was selected as an officer. None of Messrs. Lodzinski, Singleton, Anderson, Collins, Cottrell, Merrifield, Mury, Cohen and Wonson 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.

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. The SEC also maintains a website at www.sec.gov that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC, including us.

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Item 1A. Risk Factors  

We are subject to various risks and uncertainties in the course of our business. The following summarizes significant risks and uncertainties that may adversely affect our business, financial condition or results of operations. When considering an investment in our 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 are volatile. The continuing and extended decline in oil, natural gas and natural gas liquids prices since 2014 has adversely affected, and 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 negatively impact our stock price further.

The prices we receive for our oil, natural gas and natural gas liquids production heavily influence our revenue, profitability, access to capital and future rate of growth. Oil, natural gas and natural gas liquids are commodities, and therefore, their prices are 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, and this volatility exhibited a negative trend in the second half of 2014 which has continued through 2015 and into the first quarter of 2016. This market will likely continue to be volatile in the future. The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control. These factors include:

Lower oil, natural gas and natural gas liquids prices have and will continue to reduce our cash flows and borrowing ability. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in our oil, natural gas and natural gas liquids reserves as existing reserves are depleted. A continuing decrease in oil, natural gas and natural gas liquids prices could render uneconomic an even larger portion of our exploration, development and exploitation projects. This has already resulted in us having to make significant downward adjustments to our estimated proved reserves, and we may need to make further downward adjustments in the future. Furthermore, under our credit agreement providing for a senior secured revolving credit facility (the “Credit Agreement”) with BOKF, NA dba Bank of Texas (“Bank of Texas”), as agent and lead arranger, Wells Fargo Bank, National Association (“Wells Fargo”), as syndication agent, and the Lenders signatory thereto (collectively with Bank of Texas and Wells Fargo, the “Lender”), our initial borrowing base is subject to redetermination during May and November of each year, and the Lender has the right to call for an interim determination of the borrowing base under the specified circumstances. We expect that the extended

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decline in oil, natural gas and natural gas liquids prices will adversely impact our borrowing base in future borrowing base redeterminations, which could trigger repayment obligations under our senior secured revolving credit facility to the extent our outstanding loans under it exceed the redetermined borrowing base and 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 price of our common stock.

As a result of the sustained decrease in prices for oil, natural gas and natural gas liquids, we have taken and may be required to take further write-downs of the carrying values of our properties.

Accounting rules require that we periodically review the carrying value of our properties for possible impairment. Based on prevailing commodity prices and specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we have been required to, and may be required to further, write-down the carrying value of our properties. A write-down constitutes a non-cash charge to earnings.

Oil, natural gas and natural gas liquids prices have significantly declined since mid-2014 and have remained low in the first-quarter of 2016. Primarily as a result of these lower prices, our December 31, 2015 estimated proved reserves decreased 9,618 MBOE from our December 31, 2014 reserves. If prices remain at or below current levels and all other factors remain the same, we will likely incur further charges in the future. Such charges could have a material adverse effect on our results of operations for the periods in which they are taken. See Note 5 Asset Impairments to our consolidated financial statements included elsewhere in this report for additional information.

Any significant reduction in our borrowing base under our senior secured revolving credit facility as a result of a periodic borrowing base redetermination or otherwise may negatively impact our liquidity and, consequently, our ability to fund our operations, and we may not have sufficient funds to repay borrowings under this facility or any other obligation if required as a result of a borrowing base redetermination.

Availability under our senior secured revolving credit facility is currently subject to a borrowing base of $80.0 million. The borrowing base is subject to scheduled semiannual (May 1 and November 1) and other elective borrowing base redeterminations. The lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under this facility. Reductions in estimates of our oil, NGLs and natural gas reserves will result in a reduction in our borrowing base (if prices are kept constant). Given the ongoing decline in commodity prices for oil, natural gas and natural gas liquids, it is likely that reductions in our borrowing base could also arise from other factors, including but not limited to:

As of March 9, 2016, we had $11.2 million of borrowings outstanding under our senior secured revolving credit facility. We may make further borrowings under our facility in the future. Any significant reduction in our borrowing base as a result of such borrowing base redeterminations or otherwise will negatively impact our liquidity and our ability to fund our operations and, as a result, would have a material adverse effect on our financial position, results of operation and cash flows. Further, if the outstanding borrowings under the facility were to exceed the borrowing base as a result of any such redetermination, we could be required to repay the excess. We may not have sufficient funds to make such repayments. If we do not have sufficient funds and we are otherwise unable to negotiate renewals of our borrowings or arrange new financing, we may have to sell significant assets. Any such sale could have a material adverse effect on our business and financial results.

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

Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Decline rates are typically greatest early in the productive life of a well, particularly horizontal wells. Estimates of the decline rate of an oil or natural gas well are inherently imprecise, and are less precise with respect to new or emerging oil and natural gas formations with limited production histories than for more developed formations with established production histories. Our production levels and the reserves that we currently expect to recover from our wells will change if production from our

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existing wells declines in a different manner than we have estimated and can change under other circumstances. Thus, our future oil and natural gas reserves and production and, therefore, our cash flows and results of operations are highly dependent upon our success in efficiently developing and exploiting our current properties and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire additional reserves to replace our current and future production at acceptable costs. If we are unable to replace our current and future production, our cash flows and the value of our reserves may decrease, adversely affecting our business, financial condition and results of operations.

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

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

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

Quantities of proved reserves are estimated based on economic conditions in existence during the period of assessment. Changes to oil, natural gas and natural gas liquids prices in the markets for such commodities may have the impact of shortening the economic lives of certain fields because it becomes uneconomic to produce all recoverable reserves on such fields, which reduces proved property reserves estimates. As of December 31, 2015, negative revisions of 9,484 MBOE of previously estimated proved reserve quantities are primarily attributable to 7,013 MBOE of revisions to proved undeveloped reserves. The primary driver of the revision in proved undeveloped reserves was 124 locations that were previously economic at year-end 2014 SEC prices were uneconomic at the year-end 2015 SEC prices.  The remaining negative revision of 2,471 MBOE of proved reserves resulted from the combined effect of SEC prices at year-end 2015, performance and other factors that shortened the economic life of the proved reserves.

Negative revisions in the estimated quantities of proved reserves have the effect of increasing the rates of depletion on the affected properties, which decrease earnings or result in losses through higher depletion expense. These revisions, as well as revisions in the assumptions of future cash flows of these reserves, may also trigger impairment losses on certain properties, which would result in a non-cash charge to earnings. See Note 5 Asset Impairments, to our consolidated financial statements included elsewhere in this report.

At December 31, 2015, approximately 32% of our estimated reserves were classified as proved undeveloped. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. The reserve data assumes that we will make significant capital expenditures to develop our reserves. The estimates of these oil and natural gas reserves and the costs associated with development of these reserves have been prepared in accordance with SEC regulations; however, actual capital expenditures will likely vary from estimated capital expenditures, development may not occur as scheduled and actual results may not be as estimated.

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

You should not assume that the standardized measure of discounted future net cash flows from our proved reserves is the current market value of our estimated oil and natural gas reserves. In accordance with SEC requirements in effect at December 31, 2015, 2014 and 2013, we based the discounted future net cash flows from our proved reserves on the 12-month first-day-of-the-month oil and natural gas average prices without giving effect to derivative transactions. Actual future net cash flows from our oil and natural gas properties will be affected by factors such as:

The timing of both our production and our incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing and amount of actual future net revenues from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating standardized measure may not be the most appropriate

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discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general.  As a corporation, we are treated as a taxable entity for federal income tax purposes and our future income taxes will be dependent on our future taxable income. Actual future prices and costs may differ materially from those used in the present value estimates included in this report which would could have a material effect on the value of our reserves.

If commodity prices decrease to a level such that our future undiscounted cash flows from our properties are less than their carrying value for a significant period of time, then we will be required to incur write-downs of the carrying values of our properties in addition to the significant write-down we incurred in 2015.

Accounting rules require that we periodically review the carrying value of our properties for possible impairment. Based on 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 may be required to write down the carrying value of our properties.  A write-down constitutes a non-cash charge to earnings. We may incur impairment charges in the future, which could have a material adverse effect on our results of operations for the periods in which such charges are taken.

A write-down of the capitalized cost of individual oil and natural gas properties 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. A write-down could adversely affect the trading price of our common stock.

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 will 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.

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 we experience increases in the price of oil and/or natural gas or increases in the quantity of our estimated proved reserves.

The potential drilling locations for our future wells that we have tentatively internally identified will be drilled, if at all, over many years. This makes them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling, which in certain instances could prevent production prior to the expiration date of leases for such locations.

Although our management team has established certain potential drilling locations as a part of our long-range planning related to future drilling activities on our existing acreage, our ability to drill and develop these locations depends on a number of uncertainties, including oil, natural gas and natural gas liquids prices, the availability and cost of capital, drilling and production costs, the availability of drilling services and equipment, drilling results (including the impact of increased horizontal drilling and longer laterals), lease expirations, gathering systems, marketing and pipeline transportation constraints, regulatory approvals and other factors. Because of these uncertain factors, we cannot be certain if the numerous potential drilling locations we have currently identified will ever be drilled to a substantial degree or if we will be able to produce oil, natural gas and natural gas liquids from these or any other potential drilling locations. In addition, unless production is established within the spacing units covering the undeveloped acres on which some of the potential locations are obtained, the leases for such acreage will expire. As such, our actual drilling activities, especially in the long term, may materially differ from those presently anticipated.

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

To achieve more predictable cash flows and reduce our exposure to adverse fluctuations in the prices of oil and natural gas, we enter into derivative instrument contracts for a portion of our oil and natural gas production, including swaps, collars, puts and basis swaps. In accordance with applicable accounting principles, we are required to record our derivatives at fair market value, and they are included on our consolidated balance sheet as assets or liabilities and in our consolidated statements of operations as gain (loss) on derivatives. Gain (loss) on derivatives are included in our cash flows from operating activities. Accordingly, our earnings may fluctuate significantly as a result of changes in the fair market value of our derivative instruments. Although our current hedges provide us with a benefit as they are priced above the current depressed prices for oil and natural gas, as these hedges expire, there is significant uncertainty that we will be able to put new hedges in place that will provide us with similar benefit.

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Derivative instruments also expose us to the risk of financial loss in some circumstances, including when:

For additional information regarding our hedging activities, please see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.

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

The oil and gas industry is highly competitive. We compete with major integrated and larger independent oil and gas companies for the acquisition of desirable oil and gas properties and leases, for the equipment and services required to develop and operate properties, and in the marketing of oil and gas to end-users. Many competitors have financial and other resources that are substantially greater than ours, which will make any acquisition of acreage or producing properties at economic prices difficult. In addition, many larger competitors may be better able to respond to factors that affect the demand for oil and natural gas production, such as changes in worldwide oil and natural gas prices and levels of production, the cost and availability of alternative fuels and the application of government regulations. Significant competition also exists in attracting and retaining technical personnel, including geologists, geophysicists, engineers, landmen and other specialists, as well as financial and administrative personnel and we may be at a competitive disadvantage to companies with larger financial resources than ours.

A failure to complete additional acquisitions would limit our potential growth.

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

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

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

The success of any acquisition that we complete will depend on a variety of factors, including our ability to accurately assess the reserves associated with the acquired properties, future oil and natural gas prices and operating costs, potential environmental and other liabilities and other factors. These assessments are often inexact and subjective. As a result, we may not recover the purchase price of a property from the sale of production from the property or recognize an acceptable return from such sales. In addition, we may face greater risks to the extent we acquire properties in areas outside of areas in which we currently operate because we may be less familiar with operating, regulatory and other issues specific to those areas.

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

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

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

Any of these operating hazards could cause damage to properties, reduced cash flows, serious injuries, fatalities, oil spills, discharge of hazardous materials, remediation and clean-up costs and other environmental damages, which could expose us to liabilities. Although we believe we are adequately insured for replacement costs of our wells and associated equipment, the payment of any of these liabilities could reduce the funds available for exploration, development, and acquisition, or could result in a loss of our properties.

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

Our operations involving the exploration and production of hydrocarbons are subject to stringent federal, state, and local laws and regulations governing the discharge of materials into the environment. Our operations are also subject to laws and regulations relating to protection of the environment, operational safety, and related employee health and safety matters. Laws and regulations applicable to us include those relating to the following:

Compliance with all of these laws and regulations are a significant cost of doing business. Failure to comply with applicable laws and regulations may result in the assessment of administrative, civil, and criminal penalties; the imposition of investigatory and remedial

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liabilities; the issuance of injunctions that may restrict, inhibit or prohibit our operations; and claims of damages to property or persons.

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

Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing, natural gas venting and transportation restrictions based on crude oil volatility, could result in increased costs and additional operating restrictions or delays in our production of oil and natural gas and lower returns on our capital investments.

Hydraulic fracturing is a practice that is used to stimulate production of oil and/or natural gas from tight formations. The process involves the injection of water, proppants and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. The majority of our proved non-producing and proved undeveloped reserves associated with future drilling projects require hydraulic fracturing. If we are unable to apply hydraulic fracturing to our wells or the process is prohibited or significantly regulated or restricted, we would lose the ability to (i) drill and complete the projects for such proved reserves and (ii) maintain the associated acreage, which would have a material adverse effect on our future business, financial condition, operating results and prospects.

The federal Safe Drinking Water Act (“SDWA”) regulates the underground injection of substances through the Underground Injection Control (“UIC”) Program. However, hydraulic fracturing is generally exempt from regulation under the UIC Program, and thus the process is typically regulated by state oil and gas commissions. Nevertheless, the EPA has asserted federal regulatory authority over hydraulic fracturing involving diesel additives under the UIC Program. Under this assertion of authority, the EPA requires facilities to obtain permits to use diesel fuel in hydraulic fracturing operations. The U.S. Energy Policy Act of 2005, which exempts hydraulic fracturing from regulation under the SDWA, prohibits the use of diesel fuel in the fracturing process without a UIC permit. On February 12, 2014, the EPA published a revised UIC Program guidance for oil, NGL and natural gas hydraulic fracturing activities using diesel fuel. The guidance document describes how regulations of Class II wells, which are those wells injecting fluids associated with oil, NGL and natural gas production activities, may be tailored to address the purported unique risks of diesel fuel injection during the hydraulic fracturing process. Although the EPA is not the permitting authority for UIC Class II programs in Texas, where we maintain acreage, the EPA is encouraging state programs to review and consider use of the above-mentioned guidance. Furthermore, legislation has been proposed in recent sessions of Congress to repeal the hydraulic fracturing exemption from the SDWA, provide for federal regulation of hydraulic fracturing, and require public disclosure of the chemicals used in the fracturing process.

On May 9, 2014, the EPA issued an Advanced Notice of Proposed Rulemaking seeking public comment on its intent to develop and issue regulations under the Toxic Substances Control Act regarding the disclosure of information related to the chemicals used in hydraulic fracturing. The public comment period ended on September 18, 2014. The EPA plans to develop a Notice of Proposed Rulemaking by December 2016, which would describe a proposed mechanism, regulatory, voluntary, or a combination of both, to collect data on hydraulic fracturing chemical substances and mixtures.

Also, on March 26, 2015, the Bureau of Land Management (the "BLM") published a final rule governing hydraulic fracturing on federal and Indian lands. The rule requires public disclosure of chemicals used in hydraulic fracturing, implementation of a casing and cementing program, management of recovered fluids, and submission to the BLM of detailed information about the proposed operation, including wellbore geology, the location of faults and fractures, and the depths of all usable water. The rule took effect on June 24, 2015, although it is the subject of several pending lawsuits filed by industry groups and at least four states, alleging that federal law does not give the BLM authority to regulate hydraulic fracturing. On September 30, 2015, the United States District Court for Wyoming issued a preliminary injunction preventing the BLM from implementing the rule nationwide. This order has been appealed to the Tenth Circuit Court of Appeals.

Furthermore, there are certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. For example, the EPA has commenced a study of the potential adverse effects that hydraulic fracturing may have on water quality and public health. In June 2015, the EPA released its draft assessment report for peer review and public comment, finding that, while there are certain mechanisms by which hydraulic fracturing activities could potentially impact drinking water resources, there is no evidence available showing that those mechanisms have led to widespread, systemic impacts. Also, on February 6, 2015, the EPA released a report with findings and recommendations related to public concern about induced seismic

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activity from disposal wells. The report recommends strategies for managing and minimizing the potential for significant injection-induced seismic events. Other governmental agencies, including the U.S. Department of Energy, the U.S. Geological Survey, and the U.S. Government Accountability Office, have evaluated or are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory mechanisms.

On August 16, 2012, the EPA published final rules that subject oil, natural gas and natural gas liquids production, processing, transmission, and storage operations to regulation under the New Source Performance Standards ("NSPS") and National Emission Standards for Hazardous Air Pollutants ("NESHAP") programs. The rule includes NSPS Standards for completions of hydraulically fractured gas wells and establishes specific new requirements for emissions from compressors, controllers, dehydrators, storage vessels, natural gas processing plants and certain other equipment. The final rule seeks to achieve a 95% reduction in volatile organic compounds ("VOC") emitted by requiring the use of reduced emission completions or "green completions" on all hydraulically-fractured wells constructed or refractured after January 1, 2015. The EPA received numerous requests for reconsideration of these rules from both industry and the environmental community, and court challenges to the rules were also filed. In response, the EPA has issued, and will likely continue to issue, revised rules responsive to some of these requests for reconsideration. For example, in September 2013 and December 2014, the EPA amended its rules to extend compliance deadlines and to clarify the NSPS. Further, on July 31, 2015, the EPA finalized two updates to the NSPS to address the definition of low-pressure wells and references to tanks that are connected to one another (referred to as connected in parallel). In addition, on September 18, 2015, the EPA published a suite of proposed rules to reduce methane and VOC emissions from oil and gas industry, including new "downstream" requirements covering equipment in the natural gas transmission segment of the industry that was not regulated by the 2012 rules. The public comment period closed on December 4, 2015.

Also, on January 22, 2016, the BLM announced a proposed rule to reduce the flaring, venting and leaking of methane from oil and gas operations on federal and Indian lands. The proposed rule would require operators to use currently available technologies and equipment to reduce flaring, periodically inspect their operations for leaks, and replace outdated equipment that vents large quantities of gas into the air. The rule would also clarify when operators owe the government royalties for flared gas.

These standards, as well as any future laws and their implementing regulations, may require us to obtain pre-approval for the expansion or modification of existing facilities or the construction of new facilities expected to produce air emissions, impose stringent air permit requirements, or utilize specific equipment or technologies to control emissions. Any failure by us to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations and, potentially, criminal enforcement actions.

Some states have adopted, and other states are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances or otherwise require the public disclosure of chemicals used in the hydraulic fracturing process. For example, pursuant to legislation adopted by the State of Texas in June 2011, the chemical components used in the hydraulic fracturing process, as well as the volume of water used, must be disclosed to the RRC and the public beginning February 1, 2012. Furthermore, on May 23, 2013, the RRC issued the "well integrity rule," which updates the RRC's Rule 13 requirements for drilling, putting pipe down and cementing wells. The rule also includes new testing and reporting requirements, such as (i) the requirement to submit to the RRC cementing reports after well completion or after cessation of drilling, whichever is later, and (ii) the imposition of additional testing on wells less than 1,000 feet below usable groundwater. The "well integrity rule" took effect in January 2014. Additionally, on October 28, 2014, the RRC adopted disposal well rule amendments designed, among other things, to require applicants for new disposal wells that will receive non-hazardous produced water and hydraulic fracturing flowback fluid to conduct seismic activity searches utilizing the U.S. Geological Survey. The searches are intended to determine the potential for earthquakes within a circular area of 100 square miles around a proposed, new disposal well. The disposal well rule amendments, which became effective on November 17, 2014, also clarify the RRC's authority to modify, suspend or terminate a disposal well permit if scientific data indicate a disposal well is likely to contribute to seismic activity. The RRC has used this authority to deny permits for waste disposal wells. In addition to state law, local land use restrictions, such as city ordinances, may restrict or prohibit the performance of well drilling in general and/or hydraulic fracturing in particular.

If these or any other new laws or regulations that significantly restrict hydraulic fracturing are adopted or laws or regulations are adopted to restrict water disposal wells, such laws could make it more difficult or costly for us to drill and produce from conventional or tight formations as well as make it easier for third parties opposing the oil, natural gas and natural gas liquids industry to initiate legal proceedings. In addition, if these matters are regulated at the federal level, fracturing and disposal activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. These developments, as well as new laws or regulations, could cause us to incur substantial compliance costs, and compliance or the consequences of failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the potential impact on our business that may arise if federal or state legislation governing hydraulic fracturing or water disposal wells are enacted into law.

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Additional legislation or regulation could make it easier for parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process adversely affect groundwater. There has also been increasing public controversy regarding hydraulic fracturing with regard to use of fracturing fluids, impacts on drinking water supplies, use of water and the potential for adverse impacts to surface water, groundwater and the environment generally. A number of lawsuits and enforcement actions have been initiated in states implicating hydraulic fracturing practices.

Legislation, regulation, litigation and enforcement actions at the federal, state or local level that restrict hydraulic fracturing services could limit the availability and raise the cost of such services, delay completion of new wells and production of our oil, NGLs and natural gas, lower our return on capital expenditures and have a material adverse impact on our business, financial condition, results of operations and cash flows and quantities of oil and natural gas reserves that may be economically produced.

Certain states, including North Dakota where we conduct operations, and have interest in numerous non-operated wells, and intend to expand our presence in the future have adopted, and other states are considering the adoption of, regulations that impose new or more stringent permitting, disclosure and threshold requirements on the intentional or inadvertent venting of natural gas. Such efforts have resulted in the delay of certain drilling and/or completion operations until additional natural gas pipelines are built or sufficient transportation capacity is available.  The proliferation of these regulations in North Dakota and in other states may limit or delay our ability to conduct operations in a timely manner.

The state of North Dakota has issued new conditioning standards requiring certain crude oils produced in North Dakota to be conditioned to remove lighter, volatile hydrocarbons, and thereby make the oil safer to transport by railroad. The new standards seek to address safety concerns stemming from train derailments in U.S. and Canada.  The new standard establishes a goal of achieving a vapor pressure of no greater than 13.7 pounds per square inch (psi) rather than the current national standard of 14.7 psi or less.  The adoption of these regulations and/or their proliferation to other states may require the installation of new and more costly control equipment, increase the cost of production operations, increase the costs incurred by oil transporters and thereby decrease the price we receive for crude oil sold in North Dakota.

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

Congress has from time to time considered legislation to reduce emissions of greenhouse gasses, “GHGs”, and almost one-half of the states have already taken legal measures to reduce emissions of GHGs, through the planned development of GHG emission inventories and/or regional GHG cap and trade programs or other mechanisms. Most cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances corresponding with their annual emissions of GHGs. The number of allowances available for purchase is reduced each year until the overall GHG emission reduction goal is achieved. As the number of GHG emission allowances declines each year, the cost or value of allowances is expected to escalate significantly. Some states have enacted renewable portfolio standards, which require utilities to purchase a certain percentage of their energy from renewable fuel sources.

In addition, in December 2009, the EPA determined that emissions of carbon dioxide, methane and other GHGs present an endangerment to human health and the environment, because emissions of such gases are, according to the EPA, contributing to warming of the earth's atmosphere and other climatic changes. These findings by the EPA allow the agency to proceed with the adoption and implementation of regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act. In response to its endangerment finding, the EPA recently adopted two sets of rules regarding possible future regulation of GHG emissions under the Clean Air Act. The motor vehicle rule, which became effective in July 2010, purports to limit emissions of GHGs from motor vehicles. The EPA adopted the stationary source rule (or the "tailoring rule") in May 2010, and it became effective in January 2011. The tailoring rule established new GHG emissions thresholds that determine when stationary sources must obtain permits under the Prevention of Significant Deterioration ("PSD") and Title V programs of the Clean Air Act. On June 23, 2014, in Utility Air Regulatory Group v. EPA ("UARG v. EPA"), the Supreme Court held that stationary sources could not become subject to PSD or Title V permitting solely by reason of their GHG emissions. The Court ruled, however, that the EPA may require installation of best available control technology for GHG emissions at sources otherwise subject to the PSD and Title V programs. On December 19, 2014, the EPA issued two memoranda providing initial guidance on GHG permitting requirements in response to the Court's decision in UARG v. EPA. In its preliminary guidance, the EPA indicated it would promulgate a rule to rescind any PSD permits issued under the portions of the tailoring rule that were vacated by the Court. In the interim, the EPA issued a narrowly crafted "no action assurance" indicating it will exercise its enforcement discretion not to pursue enforcement of the terms and conditions relating to GHGs in an EPA-issued PSD permit, and for related terms and conditions in a Title V permit. On April 30, 2015, the EPA issued a final rule allowing permitting authorities to rescind PSD permits issued under the invalid regulations.

In September 2009, the EPA issued a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the U.S., including natural gas liquids fractionators and local natural gas/distribution companies, beginning in 2011 for emissions occurring in 2010. In November 2010, the EPA published a final rule expanding the GHG reporting rule to include onshore oil, NGL and natural gas production, processing, transmission, storage and distribution facilities. This rule requires reporting of GHG emissions

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from such facilities on an annual basis, with reporting beginning in 2012 for emissions occurring in 2011. In October 2015, the EPA amended the GHG reporting rule to add the reporting of GHG emissions from gathering and boosting systems, completions and workovers of oil wells using hydraulic fracturing, and blowdowns of natural gas transmission pipelines.

The EPA has continued to adopt GHG regulations applicable to other industries, such as its August 2015 adoption of three separate, but related, actions to address carbon dioxide pollution from power plants, including final Carbon Pollution Standards for new, modified and reconstructed power plants, a final Clean Power Plan to cut carbon dioxide pollution from existing power plants, and a proposed federal plan to implement the Clean Power Plan emission guidelines. Upon publication of the Clean Power Plan on October 23, 2015, more than two dozen states as well as industry and labor groups challenged the Clean Power Plan in the D.C. Circuit Court of Appeals. On February 9, 2016, the U.S. Supreme Court stayed the Clean Power Plan pending disposition of the legal challenges. Nevertheless, as a result of the continued regulatory focus, future GHG regulations of the oil and gas industry remain a possibility.

In December 2015, the United States joined the international community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France. The resulting Paris Agreement calls for the parties to undertake "ambitious efforts" to limit the average global temperature, and to conserve and enhance sinks and reservoirs of GHGs. The Paris Agreement, if ratified, establishes a framework for the parties to cooperate and report actions to reduce GHG emissions.

Restrictions on GHG emissions that may be imposed could adversely affect the oil and natural gas industry. The adoption of legislation or regulatory programs to reduce GHG emissions could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory requirements. Any GHG emissions legislation or regulatory programs applicable to power plants or refineries could also increase the cost of consuming, and thereby reduce demand for, the oil, natural gas and natural gas liquids we produce. Consequently, legislation and regulatory programs to reduce GHG emissions could have an adverse effect on our business, financial condition and results of operations.

In addition, claims have been made against certain energy companies alleging that GHG emissions from oil, NGL and natural gas operations constitute a public nuisance under federal and/or state common law. As a result, private individuals may seek to enforce environmental laws and regulations against us and could allege personal injury or property damages. While we are currently not a party to such litigation, we could be named in actions making similar allegations. An unfavorable ruling in any such case could significantly impact our operations and could have an adverse impact on our financial condition.

Moreover, there has been public discussion that climate change may be associated with extreme weather conditions such as more intense hurricanes, thunderstorms, tornadoes and snow or ice storms, as well as rising sea levels. Another discussed possible consequence of climate change is increased volatility in seasonal temperatures. Some studies indicate that climate change could cause some areas to experience temperatures substantially colder than their historical averages. Extreme weather conditions can interfere with our production and increase our costs and damage resulting from extreme weather may not be fully insured. However, at this time, we are unable to determine the extent to which climate change may lead to increased storm or weather hazards affecting our operations.

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

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

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

The July 2010 Dodd-Frank Wall Street Reform and Consumer Protection Act (the "Dodd-Frank Act") provides for federal oversight of the over-the-counter derivatives market and entities that participate in that market and mandates that the Commodity Futures Trading Commission (the "CFTC"), the SEC, and federal regulators of financial institutions (the "Prudential Regulators") adopt rules or regulations implementing the Dodd-Frank Act and providing definitions of terms used in the Dodd-Frank Act. The Dodd-Frank Act establishes margin requirements and requires clearing and trade execution practices for certain market participants and may result in certain market participants needing to curtail or cease their derivatives activities.

Although some of the rules necessary to implement the Dodd-Frank Act remain to be adopted, the CFTC, the SEC and the Prudential Regulators have issued many rules to implement the Dodd-Frank Act, including a rule, which we refer to as the "Mandatory Clearing

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Rule," requiring clearing of hedges, or swaps, that are subject to it (currently, only certain interest rate and credit default swaps, which we do not presently have), a rule, which we refer to as the "End User Exception," establishing an "end user" exception to the Mandatory Clearing Rule, a rule, which we refer to as the "Margin Rule," setting forth collateral requirements in connection with swaps that are not cleared and also an exception to the Margin Rule for end users that are not financial end users, which exception we refer to as the "Non-Financial End User Exception," and a rule, subsequently vacated by the United States District Court for the District of Columbia and remanded to the CFTC for further proceedings, imposing position limits. The CFTC proposed a new version of this rule, which we refer to as the "Re-Proposed Position Limit Rule," with respect to which the comment period has closed but a final rule has not been issued.

We qualify for the End User Exception and will utilize it if the Mandatory Clearing Rule is expanded to cover swaps in which we participate, we qualify for the Non-Financial End User Exception and will not be required to post margin in connection with uncleared swaps under the Margin Rule, and the quantities under the swaps in which we participate are well within applicable limits under the Re-Proposed Position Limit Rule, so we do not expect to be directly affected by any of such rules. However, most if not all of our hedge counterparties will be subject to mandatory clearing in connection with their hedging activities with parties who do not qualify for the End User Exception and will be required to post margin in connection with their hedging activities with other swap dealers, major swap participants, financial end users and other persons that do not qualify for the Non-Financial End User Exception. In addition, the European Union and other non-U.S. jurisdictions have enacted laws and regulations, which we refer to collectively as "Foreign Regulations" which may apply to our transactions with counterparties subject to such Foreign Regulations. The Dodd-Frank Act, the rules which have been adopted and not vacated, and, to the extent that the Re-Proposed Position Limit Rule is effected, such proposed rule could significantly increase the cost of our derivative contracts, materially alter the terms of our derivative contracts, reduce the availability of derivatives to us that we have historically used to protect against risks that we encounter in our business, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. The Foreign Regulations could have similar effects. If we reduce our use of derivatives as a result of the Dodd-Frank Act and regulations and Foreign Regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity contracts related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on us, our financial condition, and our results of operations.

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

Legislation has been proposed that would, if enacted, eliminate certain key U.S. federal income tax preferences currently available to oil and natural gas exploration and production companies. These changes include, but are not limited to (i) the repeal of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain U.S. production activities and (iv) an extension of the amortization period for certain geological and geophysical expenditures. In addition, President Obama recently proposed adding a $10.25 per Bbl tax on crude oil produced in the United States. It is unclear whether any of the foregoing changes will actually be enacted or how soon any such changes could become effective. Any such change or similar other change could materially adversely affect our financial condition and results of operations by increasing the costs we incur which would in turn make it uneconomic to drill some locations if commodity prices are not sufficiently high, resulting in lower revenues and decreases in production and reserves.

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

Water is an essential component of both the drilling and hydraulic fracturing processes. Historically, we have been able to purchase water from local land owners and other sources for use in our operations. During the past several years, Texas has experienced the lowest inflows of water in recent history. As a result of these conditions, some local water districts may begin restricting the use of water subject to their jurisdiction for drilling and hydraulic fracturing in order to protect the local water supply. If we are unable to obtain water to use in our operations from local sources, we may be unable to economically produce oil, natural gas and natural gas liquids, which could have an adverse effect on our results of operations, cash flows and financial condition.

Additionally, our drilling procedures produce large volumes of water that we must properly dispose. The Clean Water Act of 1977, as amended, the Safe Drinking Water Act of 1974, as amended, the Oil Pollution Act of 1990, as amended, and comparable state laws impose restrictions and strict controls regarding the discharge of pollutants, including produced waters and other natural gas wastes, into federal and state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the U.S. Environmental Protection Agency (the "EPA") or the state. Furthermore, many states maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. The underground injection of fluids is subject to permitting and other requirements under state laws and regulation. Obtaining permits has the potential

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to delay the development of oil, NGL and natural gas projects. These same regulatory programs also limit the total volume of water that can be discharged, hence limiting the rate of development, and require us to incur compliance costs. In October 2014, the RRC adopted new regulations effective as of November 17, 2014 that require additional supporting documentation, including records from the U.S. Geological Survey regarding previous seismic events in the area, as part of applications for new disposal wells. The new regulations also clarify the RRC's ability to modify, suspend or terminate a disposal well permit if scientific data indicates it is likely to contribute to seismic activity. The RRC has used this authority to deny permits for waste disposal sites.

Moreover, the EPA is examining regulatory requirements for "indirect dischargers" of wastewater - i.e., those that send their discharges to private or publicly owned treatment facilities, which treat the wastewater before discharging it to regulated waters. On April 7, 2015, the EPA published a proposed rule establishing federal pre-treatment standards for wastewater discharged from onshore unconventional oil and gas extraction facilities to publicly owned treatment works (“POTWs”). The EPA asserts that wastewater from such facilities can be generated in large quantities and can contain constituents that may disrupt POTW operations and/or be discharged, untreated, from the POTW to receiving waters. If adopted, the new pre-treatment rule would require unconventional oil and gas facilities to pre-treat wastewater before transferring it to POTWs. The public comment period ended on July 17, 2015, and the EPA is expected to publish a final rule in 2016. The EPA is also conducting a study of private wastewater treatment facilities (also known as centralized waste treatment, or CWT, facilities) accepting oil and gas extraction wastewater. The EPA is collecting data and information related to the extent to which CWT facilities accept such wastewater, available treatment technologies (and their associated costs), discharge characteristics, financial characteristics of CWT facilities, and the environmental impacts of discharges from CWT facilities.

Because of the necessity to safely dispose of water produced during drilling and production activities, these regulations, or others like them, could have a material adverse effect on our future business, financial condition, operating results and prospects. See Item 1. Business—Regulations, for a further description of the laws and regulations that affect us.

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

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

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

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

The marketability of our oil and natural gas production is dependent upon the availability, proximity and capacity of pipelines, natural gas gathering systems, transportation and processing facilities owned by third parties. In general, we will not control these facilities, and our access to them may be limited or denied due to circumstances beyond our control. A significant disruption in the availability of these facilities could adversely impact our ability to deliver to market the oil and natural gas we produce and thereby cause a significant interruption in our operations. In some cases, our ability to deliver to market our oil and natural gas is dependent upon coordination among third parties that own transportation and processing facilities we use, and any inability or unwillingness of those parties to coordinate efficiently could also interrupt our operations. These are risks for which we generally will not maintain insurance.

Use of debt financing may adversely affect our strategy.

We intend to use debt to fund a portion of our future acquisition and operating activities. Any temporary or sustained inability to service or repay debt will materially adversely affect our ability to access the financing market and to pursue our operating strategies, as well as impair our ability to respond to adverse economic changes in oil and natural gas markets and the economy in general.

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

While we intend to operate the majority of our properties, we are not currently the operator of many of our existing properties and, therefore, may not be able to influence production operations or further development activities. At present, we operate wells comprising approximately 67% of our total proved reserves. Joint ownership is customary in the oil and gas industry and is generally conducted under the terms of a Joint Operating Agreement (“JOA”), where one of the working interest owners is designated as the “operator” of the property. For non-operated properties, subject to the specific terms and conditions of the applicable JOA, if we disagree with the decision of a majority of working interest owners, we may be required, among other things, to postpone the proposed activity or decline to participate. If we decline to participate, we might be forced to relinquish our interest through “in-or-out” elections or may be subject to certain non-consent penalties, as provided in a JOA. In-or-out elections may require a joint owner to participate or forever relinquish its position, typically only in specific wells or drilling units, although such relinquished positions could be of a larger scope. Non-consent penalties typically allow participating working interest owners to recover from the proceeds of production, if any, an amount equal to 200% to 500% of the non-participating working interest owner’s share of the cost of such operations. Further, even for properties operated by us, there may be instances where decisions related to drilling, completion and operating cannot be made in our sole discretion. In such instances, we could be limited in our development operations and subject to penalties as specified above if we choose not to participate in operations proposed by a majority of working interest owners.

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

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

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

Because we cannot control the timing and accuracy of financial information regarding the results of operations on properties we do not operate, our ability to timely and accurately report our results of operations and financial position may be adversely affected.

For properties we do not operate, we are dependent on the operators of such properties for financial information regarding the results of operations. Any delay in receipt of such information or inaccuracies in calculating and reporting such information by the operator would adversely affect our ability to timely and accurately report our results of operations and financial condition.

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

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

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

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

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

Risks Related to the Ownership of our Common Stock

We are a “controlled company” within the meaning of the NYSE MKT rules and, as a result, qualify for, and rely on, exemptions from certain corporate governance requirements. As a result, our stockholders do not have the same protections afforded to stockholders of companies that are subject to such requirements.

OVR beneficially owns a majority of our common stock. As a result, we are a “controlled company” within the meaning of the NYSE MKT corporate governance standards. Under the NYSE MKT rules, a company of which more than 50% of the voting power is held by another person or group of persons acting together is a controlled company and may elect not to comply with certain NYSE MKT corporate governance requirements, including the requirements that:

We are currently utilizing, and intend to continue to utilize, the exemption relating to a majority of our board of directors not being independent, the compensation committee, the nominating committee, and we may utilize this exemption for so long as we are a controlled company. Accordingly, our stockholders do not have the same protections afforded to stockholders of companies that are subject to all of the corporate governance requirements of the NYSE MKT.

OVR holds a substantial majority of our common stock.

OVR holds the majority of the outstanding shares of our common stock. OVR is entitled to act separately in its own interest with respect to its shares of our common stock, and it has the voting power to elect all of the members of our board of directors and thereby control our management and affairs. In addition, OVR has the ability to determine the outcome of all matters requiring stockholder approval, including mergers and other material transactions, and to cause or prevent a change in the composition of our board of directors or a change in control of our company that could deprive our stockholders of an opportunity to receive a premium for their common stock as part of a sale of our company. The existence of a significant stockholder may also have the effect of deterring hostile takeovers, delaying or preventing changes in control or changes in management, or limiting the ability of our other stockholders to approve transactions that they may deem to be in the best interests of our company.

So long as OVR continues to control a significant amount of our common stock, OVR will continue to be able to strongly influence all matters requiring stockholder approval, regardless of whether or not other stockholders believe that a potential transaction is in their own best interests. In any of these matters, the interests of OVR may differ or conflict with the interests of our other stockholders. Moreover, this concentration of stock ownership may also adversely affect the trading price of our common stock to the extent investors perceive a disadvantage in owning stock of a company with a controlling stockholder.

Our common stock price has been and is likely to continue to be highly volatile.

The trading price of our common stock is subject to wide fluctuations in response to a variety of factors, including quarterly variations in operating results, announcements of drilling and rig activity, economic conditions in the natural gas and oil industry, general economic conditions or other events or factors that are beyond our control.

In addition, the stock market in general and the market for oil and natural gas exploration companies, in particular, have experienced large price and volume fluctuations that have often been unrelated or disproportionate to the operating results or asset values of those companies. These broad market and industry factors may seriously impact the market price and trading volume of our common stock regardless of our actual operating performance. In the past, following periods of volatility in the overall market and in the market price of a company’s securities, securities class action litigation has been instituted against certain oil and natural gas exploration

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companies. If this type of litigation were instituted against us following a period of volatility in our common stock trading price, it could result in substantial costs and a diversion of our management’s attention and resources, which could have a material adverse effect on our financial condition, future cash flows and the results of operations.

Item 1B. Unresolved Staff Comments

None.

Item 2.  Properties

Oil and Natural Gas Reserves

All of our oil and natural gas reserves are located in the United States. Our reserve estimates have been prepared by Cawley, Gillespie & Associates, Inc. (“CG&A”), an independent petroleum engineering firm. The scope and results of CG&A’s procedures are summarized in a letter which is included as an exhibit to this report. For further information on reserves, including information on future net cash flows and the standardized measure of discounted future net cash flows, please refer to the “Supplemental Data on Oil and Gas Exploration and Producing Activities (Unaudited)” within Part II, Item 8 of the Notes To Consolidated Financial Statements of this report.

2015 Decreases in proved reserves

From January 1, 2015 to December 31, 2015, our proved reserves decreased as follows:

These significant decreases were due to production of 1,437 MBOE, the divestiture of non-core assets and an economic loss of reserves due to significantly reduced commodity prices.  The majority of 2015 drilling activities were focused on proved locations and therefore very minimal reserves were moved into the proved undeveloped category.

Proved Reserves as of December 31, 2015

The below table sets forth a summary of our estimated crude oil, natural gas and natural gas liquids reserves as of December 31, 2015 based on the reserve report prepared by CG&A. Proved reserves are estimated based on the unweighted average beginning-of-month-prices during the 12-month period for the year.  All prices and costs associated with operating wells were held constant in accordance with the SEC guidelines.   

Present Value Discounted at 10% (“PV-10”) is a non-GAAP measure that differs from the generally accepted accounting practices in the United States (“GAAP”) measure “standardized measure of discounted future net cash flows” in that PV-10 is calculated without including future income taxes. Management believes that the presentation of PV-10 value is relevant and useful to investors because it presents the estimated discounted future net cash flows attributable to our estimated proved reserves independent of our income tax attributes, thereby isolating the intrinsic value of the estimated future cash flows attributable to our reserves. We believe the use of a pre-tax measure provides greater comparability of assets when evaluating companies because the timing and quantification of future income taxes is dependent on company-specific factors, many of which are difficult to discern presently. For these reasons, management uses and believes that the industry generally uses the PV-10 measure in evaluating and comparing acquisition candidates and assessing the potential rate of return on investments in oil and natural gas properties. PV-10 does not necessarily represent the fair market value of oil and natural gas properties. PV-10 is not a measure of financial or operational performance under GAAP, nor

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should it be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows as defined under GAAP.  

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

Proved Undeveloped Reserves (“PUDs”)

Proved undeveloped reserves decreased 8,431 MBOE or 68%, for the year ended December 31, 2015 compared to the year ended December 31, 2014.  Revisions of prior estimates reflect our operational results, drilling activities, and on-going evaluation of our asset portfolio. Certain previously booked PUDs were reclassified as proved developed reserves due to successful drilling efforts. Revisions of prior estimates also include certain PUDs that were reclassified to unproved categories due to development plan changes and the impact of changes in commodity prices.  In accordance with our 2015 year-end independent engineering reserve report, we plan to drill all of our individual PUD drilling locations within the next five years.  

The following table details the changes in our proved undeveloped reserves for year ended December 31, 2015 (in MBOE):

Conversions.  In 2015, approximately 62% of the reserve conversions occurred in our operated Eagle Ford / Austin Chalk properties in Fayette, Gonzales and Karnes Counties, Texas, with the remaining occurring in our non-operated Bakken/Three Forks program in North Dakota.

Extensions and discoveries.  During 2015, we added 685 MBOE of PUDs through extensions and discoveries, primarily as a result of successful drilling in our operated Eagle Ford properties in Fayette and Gonzales Counties, Texas and our non-operated Bakken/Three Forks program in North Dakota.

Purchases.  During 2015, we acquired additional interests in our operated Eagle Ford properties in Karnes and Gonzales Counties, Texas.

Revisions.  In 2015, the downward revisions of 9,340 MBOE to PUD reserves occurred primarily as a result of decreased oil natural gas prices, which decreased the number of economic PUD locations.

Preparation of Reserve Estimates

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

The technical person primarily responsible for the preparation of the reserve report is Mr. Robert D. Ravnaas, President of CG&A. He earned a Bachelor of Science degree with special honors in Chemical Engineering from the University of Colorado at Boulder in 1979 and a Master of Science degree in Petroleum Engineering from the University of Texas at Austin in 1981. Mr. Ravnaas is a Registered Professional Engineer in Texas and has more than 31 years of experience in the estimation and evaluation of oil and natural gas reserves. He is also a member of the Society of Petroleum Geologists and the Society of Professional Well Log Analysts.

Mr. Anderson, our Executive Vice President responsible for reservoir engineering, is a qualified reserve estimator and auditor and is primarily responsible for overseeing CG&A during the preparation of our reserve report. His professional qualifications meet or exceed the qualifications of reserve estimators and auditors set forth in the “Standards Pertaining to Estimation and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers. His qualifications include a Bachelor of Science degree in Petroleum Engineering from the University of Wyoming in 1986; a Master of Business Administration degree from the University of Denver in 1988; member of the Society of Petroleum Engineers since 1985; and more than 29 years of practical

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experience in estimating and evaluating reserve information with more than five of those years being in charge of estimating and evaluating reserves.

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

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

The net quantities of oil and natural gas and natural gas liquids produced and sold by us for the years ended December 31, 2015, 2014, and 2013, the average sales price per unit sold and the average production cost per unit are presented below.

As of December 31, 2015, four fields accounted for approximately 89% of our total estimated proved reserves. Southern Bay Eagle Ford and Eagleville fields accounted for 30% and 33%, respectively, of our total estimated proved reserves. The Banks field, which was acquired as part of the closing of our transaction with OVR in December 2014, was 20% of our total estimated proved reserves. The Hawkville field accounted for 6% of our total estimated proved reserves.  No other single field accounted for 15% or more of our total estimated proved reserves for the years ended December 31, 2015, 2014 or 2013. The net quantities of oil, natural gas and natural gas liquids produced and sold by us from these significant fields for each of the years ended December 31, 2015, 2014 and 2013, the average sales price per unit sold and the average production cost per unit are presented below.

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Southern Bay Eagle Ford Field

Eagleville Field

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Banks Field

Hawkville Field

Our oil production is sold to large purchasers. Due to the quality and location of our oil production, we may receive a discount or premium from index prices or “posted” prices in the area. Our natural gas production is sold primarily to pipeline companies and/or gas marketers under short-term contracts at prices which are tied to the “spot” market for natural gas sold in the area.

The purchasers of our oil, natural gas and natural gas liquids production consist primarily of independent marketers, major oil and natural gas companies and pipeline companies. In 2015, 2014 and 2013, one purchaser, United Energy Trading, LLC (“United”), accounted for 62%, 60% and 21%, respectively, of our oil, natural gas and natural gas liquids revenues. United is expected to be a significant purchaser in the future as well. No other purchaser accounted for 10% or more of our oil, natural gas and natural gas liquids revenues during 2015, 2014 and 2013.

We hold working interests in oil and natural gas properties for which third parties serve as operator. The operator sells the oil, natural gas and natural gas liquids to the purchaser, and collects and distributes the revenue to us. In 2015, one operator accounted for 12% and in 2014, a different operator account for 20% of our total oil, natural gas and natural gas liquids revenues. In 2013, two operators

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distributed 47% and 11% of our oil, natural gas and natural gas liquids revenues. No other operator accounted for 10% or more of our oil, natural gas and natural gas liquids revenues during the years ended December 31, 2015, 2014 and 2013.

Gross and Net Productive Wells

As of December 31, 2015, our total gross and net productive wells were as follows:

Gross and Net Developed and Undeveloped Acres

As of December 31, 2015, we had estimated total gross and net developed and undeveloped leasehold acres as set forth below. The developed acreage is stated on the basis of spacing units designated or permitted by state regulatory authorities.

Gross acres are those acres in which working interest is owned. The number of net acres represents the sum of fractional working interests we own in gross acres.

Out of a total of 87,200 gross (34,700 net) undeveloped acres as of December 31, 2015, the portion of our net undeveloped acreage that is subject to expiration over the next three years, if not successfully developed or renewed, is approximately 14% in 2016, 65% in 2017 and 21% in 2018 and beyond.  The portion of our net undeveloped acres related to the Eagle Ford acreage that is subject to expiration over the next three years, if not successfully developed or renewed, is approximately 9% in 2016, 7% in 2017 and 6% in 2018 and beyond.  We anticipate that within our Eagle Ford acreage, our current and future drilling plans, along with the selected lease extensions, will address the majority of the leases expiring in 2016 and beyond.

Exploratory Wells and Development Wells

Set forth below for the three years ended December 31, 2015 is information concerning the number of wells we drilled during the years indicated.

Present Activities

As of March 9, 2016, we have 12 gross (4.1 net) operated wells in the process of drilling or completing and 33 gross (1.4 net) non-operated well in the process of drilling or completing.  

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Item 3.  Legal Proceedings

In the normal course of business, we may be involved in litigation and claims arising out of our operations.  As of December 31, 2015, and through the filing date of this report, we do not believe the ultimate resolution of any such actions or potential actions of which we are currently aware will have a material effect on our consolidated financial position or results of operations.

A description of our legal proceedings is included in Note 12 Commitments and Contingencies included in Item 8 of this report.

Item 4.  Mine Safety Disclosures

Not applicable.

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PART II

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

Market Information for Common Stock

Shares of our common stock are traded on the NYSE MKT under the symbol “ESTE.” The following table sets forth the reported high and low sales prices of our common stock for the period indicated:

Holders

As of March 4, 2016, there were approximately 1,800 holders of record of our common stock.  

Dividend Policy

We have never paid dividends on our common stock and do not intend to pay a dividend in the foreseeable future. Furthermore, our credit agreement with our bank restricts the payment of cash dividends. The payment of future cash dividends on common stock, if any, will be reviewed periodically by our Board of Directors and will depend upon, but not limited to, our financial condition, funds available for operations, the amount of anticipated capital and other expenditures, our future business prospects and any restrictions imposed by our present or future bank credit arrangements.

Equity Compensation Plan Information

In December 2014, our stockholders approved and adopted the 2014 Long-Term Incentive Plan (the “2014 Plan”), which was effective on December 19, 2014 and the 2014 Plan remains in effect until December 18, 2024.  In October 2015, the 2014 Plan was amended to increase the number of shares of our common stock authorized to be issued.    Under the 2014 Plan, we may grant stock options, restricted stock awards, restricted stock units, stock appreciation rights, performance units, performance bonuses, stock awards and other incentive awards to our employees or those of our subsidiaries or affiliates as well as persons rendering consulting or advisory services and non-employee directors, subject to the conditions set forth in the 2014 Plan.  Generally, all classes of our employees are eligible to participate in the 2014 Plan.

The 2014 Plan currently provides that a maximum of 1,500,000 shares of our common stock may be issued in conjunction with awards granted under the 2014 Plan.  Awards that are forfeited under the 2014 Plan will again be eligible for issuance as though the forfeited awards had never been issued.  Similarly, awards settled in cash will not be counted against the shares authorized for issuance upon exercise of awards under the 2014 Plan.

The 2014 Plan limits the aggregate number of shares of common stock that may be covered by stock options and/or stock appreciation rights granted to any eligible employee in any calendar year to 250,000 shares.  The 2014 Plan also limits the aggregate number of shares of common stock that may be issued in conjunction with awards (other than stock options or stock appreciation rights) granted to any eligible employee in any calendar year to 150,000 shares.  The 2014 Plan also limits the maximum aggregate amount that may be paid in cash pursuant to awards (other than stock options or stock appreciation rights) made to any eligible employee in any calendar year to $2,000,000.

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The following table sets forth information concerning our only compensation plan available to non-employee directors, officers, employees and consultants at December 31, 2015:

Repurchase of Equity Securities

We did not repurchase any of our shares of common stock during the year ended December 31, 2015.

Performance Graph

The following graph reflects a comparison of the cumulative total stockholder return of our common stock beginning December 31, 2010 through December 31, 2015, relative to the cumulative total returns of the S&P 500 Index and the S&P Oil & Gas Exploration & Production Select Industry Index.  The graph assumes the investment of $100 on December 31, 2010 in our common stock and each index and the reinvestment of all dividends, if any.  The identity of the companies included in the S&P Oil & Gas Exploration & Production Select Industry Index will be provided upon request.

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Item 6.  Selected Financial Data

The following selected financial data should be read in conjunction with Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations”, and our consolidated financial statements and the accompanying notes thereto included elsewhere in this report.  In accordance with GAAP the financial information and financial statements included herein are those of OVR and its subsidiaries. Prior to the strategic combination OVR, and its subsidiaries were pass through entities for income tax purposes and therefore no tax expense was recorded for the historical periods prior to the year ended December 31, 2014. OVR was a newly created entity formed in December 2012 that was initially capitalized through the contribution of producing properties, acreage and working capital as well as cash commitments from investors. Upon initial capitalization, the contributed properties, acreage and working capital resulted in one owner retaining a controlling interest in OVR, and despite a change in management, GAAP required OVR to the record the contributed properties at their historical cost basis even though such cost basis was in excess of the valuation agreed upon by members at the time of capitalization.  The GAAP requirement resulted in reporting higher DD&A provisions and significant impairments, both in 2013 and 2012, than would have been reported otherwise had the properties been recorded at the agreed upon valuation which approximated fair value.    

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

The following discussion of our financial condition, results of operations, liquidity and capital resources should be read together with our consolidated financial statements and the notes to consolidated financial statements, which are included in the report in Item 8, and the information set forth in Risk Factors under Item 1A.  Unless the context otherwise requires, the terms “the Company”, “our”, “we”, “us”, and “Earthstone” refer to Earthstone Energy, Inc. and its consolidated subsidiaries.

The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expected performance. We caution that assumptions, expectations, projections, intentions or beliefs about future events may, and often do, vary from actual results and the differences can be material. Some of the key factors that could cause actual results to vary from our expectations include changes in oil and natural gas prices, the timing of planned capital expenditures, availability of acquisitions, joint ventures and dispositions, uncertainties in estimating proved reserves and forecasting production results, potential failure to achieve production from development projects, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital and financial markets generally, as well as our ability to access them, and uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, as well as those factors discussed below and elsewhere in this report, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. See “Cautionary Statement Regarding Forward-Looking Statements” and Item 1A. Risk Factors.

Executive Overview

Strategy and 2016 Outlook

We are a growth-oriented independent oil and gas company engaged in the development and acquisition of oil and gas reserves through an active and diversified program that includes the acquisition, drilling and development of undeveloped leases, asset and corporate acquisitions, and exploration activities, with its current primary assets located in the Eagle Ford trend of south Texas and in the Williston Basin of North Dakota.   As further discussed in this report, future growth in assets, earnings, cash flows and share values will be dependent upon our ability to acquire, discover and develop commercial quantities of oil and natural gas reserves that can be produced at a profit, and assemble an oil and natural gas reserve base with a market value exceeding its acquisition, development and production costs.   Our strategy includes a combination of acquisition, development and exploration activities, typically in more than one basin. Historically, we have shifted our emphasis among these basic activities to take advantage of changing market conditions and to facilitate profitable growth. The majority of our efforts are currently focused on developing our acreage positions in the Eagle Ford trend of South Texas and in the Williston Basin of North Dakota. In addition, it is essential that, over time, our personnel expand our current projects and/or generate additional projects so that we have the potential to economically replace our production and increase our proved reserves.

The significant declines in oil and natural gas prices since September 2014 have adversely impacted our business and the industry as a whole.  In spite of the severe price declines we achieved certain goals in 2015 which included: