EARTHSTONE ENERGY INC - Annual Report: 2014 (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, 2014

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. ¨

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 $33.52 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 $41,493,391.

As of March 25, 2015 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 2015 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 paragraph 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.

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.

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.

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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 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

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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 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 and the Rocky Mountain states. We also own other operated and non-operated properties in east and south Texas, eastern Oklahoma and north Louisiana, which are currently contributing to cash flow, but may be divested in the future. We have accumulated approximately 27,000 net leasehold acres in the Eagle Ford trend of south Texas, including 23,900 net leasehold acres in the crude oil window in Fayette County and Gonzales County and 3,100 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 County and Gonzales County acreage with working interests ranging from 38% to 50% and we are a non-operator with respect to our La Salle County acreage with working interests ranging from 10% to 15%. We are also non-operator with respect to 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 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, 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 has been accounted for as a reverse acquisition whereby Oak Valley is considered the acquirer for accounting purposes.  All historical financial information contained in this report is that of OVR and its subsidiaries.  

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%.

For a detailed discussion of these transactions, see “Note 3 – Acquisitions and Divestitures” within the Notes to the Consolidated Financial Statements included in Part II Item 8. Financial Statements and Supplementary Data of this report.

Bank of Texas Credit Facility

In connection with the closing of the OVR and Flatonia transactions described above, on December 19, 2014, we entered into a credit agreement providing for a $500.0 million four-year senior secured revolving credit facility (the “Credit Agreement”) with BOKF, NA dba Bank of Texas (“Bank of Texas”), as agent and lead arranger, and 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”).

The initial borrowing base of the Credit Agreement is $80.0 million and is subject to redetermination on the first business day of May and November of each year. At the option of the borrower, the amounts borrowed under the Credit Agreement bear annual interest

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rates at either (a) the London Interbank Offered Rate (“LIBOR”) plus the applicable utilization margin of 1.50% to 2.50% or (b) the base rate plus the applicable utilization margin of 0.50% to 1.50%. Principal amounts outstanding under the credit facility are due and payable in full at maturity on December 19, 2018. All of the obligations under the Credit Agreement, and the guarantees of those obligations, are secured by substantially all of our assets. Additional payments due under the Credit Agreement include paying a commitment fee to the Lender in respect of the unutilized commitments thereunder. The commitment rate ranges from 0.375% to 0.50% per year, depending upon the unutilized portion of the borrowing base in effect from time to time. We are also required to pay customary letter of credit fees.  For additional details, see “Note 8 – Long-Term Debt” in the Notes to the Consolidated Financial Statements included in Part II Item 8. Financial Statements and Supplementary Data.

Our Business Strategy

We pursues a value-driven growth strategy focused on projects that we believe will generate strong and predictable rates of return and increases in stockholder value. 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 most cost-efficient and economic development of our assets. Management concentrates on building production, reserves and cash flows while continually 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 79% of our proved PV-10 as of December 31, 2014. 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.

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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.

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, eastern Oklahoma and north Louisiana.  

Fayette County, Texas and Gonzales County, Texas

Operated Eagle Ford

As of December 31, 2014, we had accumulated approximately 47,900 gross (23,900 net) leasehold acres in Gonzales and Fayette 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, 2014, we operated 49 gross Eagle Ford wells and five gross Austin Chalk wells and had non-operated interests in two gross producing Eagle Ford wells and two gross producing Austin Chalk wells.  Seventeen gross Eagle Ford wells were in the process of being drilled or were waiting on completion. Our plan is to complete approximately five wells per quarter throughout 2015. We have identified a total of approximately 217 gross Eagle Ford drilling locations. 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 future additional economic locations. The majority of our acreage is covered by a 173 square mile 3-D seismic survey, which is being used to effectively develop the Eagle Ford and identify Austin Chalk locations and other economic opportunities.

We are currently budgeting $7.1 million to $7.5 million per well to drill and complete Eagle Ford wells with lateral lengths of approximately 6,000-7,000 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 26,300 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, North Dakota and Montana.  

We have a non-operated position in approximately 10,900 net acres in the Williston Basin of North Dakota and Montana. Our most active areas within the basin include the Banks, Indian Hill and Camel Butte Fields in McKenzie County, North Dakota and fields within Dunn County, North Dakota.  In the Banks Field, we have an average working interest of 3.6% in 69 horizontal Bakken/Three Forks wells that are primarily operated by Statoil. In the Indian Hill and Camel Butte Fields, we have an average working interest of 1.6% in five horizontal Bakken/Three Forks wells operated by various parties.  In Dunn County, North Dakota, we have an average working interest of 1.2% in seven horizontal Bakken/Three Forks wells that are operated by Marathon Oil Corporation.  In Divide County, North Dakota and Sheridan County, Montana, we have an interest in undeveloped acreage that is held by a producing vertical wells. The acreage is prospective for the Bakken and/or Three Forks formation.

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

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

Operational Risks

Oil and natural gas 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 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 will 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 include the regulation of the size of drilling and spacing units or proration units, the number of wells which may be drilled in an area, and the unitization or pooling of oil and natural gas properties, as well as regulations that generally prohibit the venting or flaring of natural gas, and impose certain requirements regarding the establishment of maximum allowable rates of production from fields and individual wells. Our operations are also subject to various conservation laws and regulations. These laws and regulations govern the size of drilling and

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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.

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 regulate 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.

New programs and changes in existing programs, however, may address various aspects of our business including natural 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 waste. 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.

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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 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. 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. Additional disclosure requirements could result in increased regulation, operational delays, and increased operating costs that could make it more difficult to perform hydraulic fracturing.

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.

Recently, 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 will impose additional requirements and costs on our operations.

In December 2014, the EPA proposed to lower the existing 75 parts per billion (“ppb”) national ambient air quality standards (“NAAQS”) for ozone under the federal Clean Air Act to a range within 65-70 ppb. The EPA is also taking public comment on whether the ozone NAAQS should be revised to as low as 60 ppb. A lowered ozone NAAQS in a range of 60-70 ppb 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.

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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 begun 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, and the Kyoto Protocol 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 begun 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.

In addition, President Obama released a Strategy to Reduce Methane Emissions in March 2014. Consistent with that strategy, the EPA has announced that it intends to issue a proposed rule in 2015 to set standards for methane and VOC emissions from new and modified oil and natural gas production sources and natural gas processing and transmission sources. The EPA intends to issue a final rule in 2016. As another prong of the President’s strategy, the federal Bureau of Land Management (“BLM”) is expected to propose standards in 2015 to reduce 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, the Clean Water Act and CERCLA. 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.

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.

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Occupational Safety and Health Act

We are subject to the requirements of the federal Occupations 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, 2014, we had 50 full-time and 2 part-time employees, 40 of which are management, technical and administrative personnel, and 12 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.

Office Leases

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

During 2014, aggregate rental payments for our office facilities totaled approximately $0.3 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 Oak Valley Resources, LLC, Mr. Lodzinski was Chairman, President and Chief Executive Officer of GeoResources, Inc. from April 2007 until its merger with Halcón Resources Corporation in August 2012 and from September 2012 until December 2012 he conducted preformation activities for Oak Valley Resources, LLC.  He has over 43 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 since its formation.  The Southern Bay entities were merged into GeoResources in April 2007. He holds a BSBA degree in Accounting and Finance from Wayne State University in Detroit, Michigan.

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Ray Singleton is a petroleum engineer with over 37 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 us in 1988 as a Production Manager/Petroleum Engineer. From 1983 until 1988, he owned and operated a small engineering consulting firm (Singleton & Associates) serving the needs of 40 small oil & 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 C-Level experience and has an intimate knowledge of the Company’s legacy Rocky Mountain 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 28 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 President and Chief Operating Officer of Halcón Resources Corporation. Mr. Anderson was employed by GeoResources, Inc. from April 2007 until its merger with Halcón Resources 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 26 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 December 2014. Prior to employment by Oak Valley Resources, LLC, he served from August 2012 to November 2012 as a consultant to Halcón Resources.  Mr. Collins was employed by GeoResources from April 2007 until its merger with Halcón Resources in August 2012 and directed all field operations, including production, workover, recompletion, and drilling 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.

Chris 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 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 from April 2007 until its merger with Halcón Resources 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 35 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 Resources upon its merger with GeoResources 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.

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Francis M. Mury has over 40 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 from April 2007 until its merger with Halcón Resources 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.

G. Bret Wonson has over 13 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 Resources Corporation 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.

Neil K. Cohen has over 11 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 emphasis on exploration and production companies, and as a member of UBS’ Debt Capital Markets Group, with a particular emphasis on investment grade energy and utility 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.

There are no arrangements or understandings between any of Messrs. Lodzinski, Singleton, Anderson and Wonson, or any other person pursuant to which such person was selected as an officer. None of Messrs. Lodzinski, Singleton, Anderson 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 securities, you should carefully consider the risk factors included below as well as those matters referenced in the foregoing pages under “Cautionary Statement Concerning Forward-Looking Statements” and other information included and incorporated by reference into this report.

Oil and natural gas prices are volatile. A substantial or extended decline in commodity prices may adversely affect our business, financial condition and results of operations and our ability to meet our capital expenditure obligations and financial commitments.

Our revenues, profitability and future growth and the carrying value of our properties depend substantially on prevailing oil and natural gas prices. These prices also affect the amount of cash flow available for our capital expenditures and our ability to borrow and raise additional capital. The amount we will be able to borrow under our credit agreement will be subject to periodic redetermination based in part on current oil and natural gas prices and on changing expectations of future prices. Lower prices may also reduce the amount of oil and natural gas that we can economically produce, resulting in an adverse effect on the quantities and the value of our reserves.

Historically, the markets for oil and natural gas have been volatile, and they are likely to continue to be volatile in the future. Among the factors that can cause volatility are:

These external factors and the volatile nature of the energy markets make it difficult to estimate future prices of oil and natural gas.

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 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 flow 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 flow and the value of our reserves may decrease, adversely affecting our business, financial condition and results of operations.

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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.

At December 31, 2014, approximately 56% 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, 2014, 2013 and 2012, 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 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.

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

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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 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 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.

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.

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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 these laws and regulations may result in the assessment of administrative, civil, and criminal penalties; the imposition of investigatory and remedial liabilities; the issuance of injunctions that may restrict, inhibit or prohibit our operations; and claims of damages to property or persons.

Some environmental laws and regulations impose strict liability. 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

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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.

Bills have been introduced in the U.S. Congress and in various state legislatures to regulate hydraulic fracturing operations and related injection of fracturing fluids and propping agents used in fracturing fluids by the oil and natural gas industry under the federal Safe Drinking Water Act (“SDWA”) and to require the disclosure of chemicals used in the hydraulic fracturing process under the SDWA, Emergency Planning and Community Right-to-Know Act (“EPCRA”) or other authority. Hydraulic fracturing is an important and commonly used process in the completion of unconventional oil and natural gas wells in shale and tight sand formations. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into rock formations to stimulate oil and natural gas production. We engage third parties to provide hydraulic fracturing or other well stimulation services to us for many of the wells that we drill and operate. Sponsors of such bills have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies, surface waters, and other natural resources, and threaten health and safety. In addition, The EPA has commenced a study of the potential adverse effects that hydraulic fracturing may have on water quality and public health, with a draft of the study anticipated to be available by March 2015, and legislation has been proposed before Congress to provide for federal regulation of hydraulic fracturing and to require the disclosure of chemicals used by the oil and natural gas industry in the hydraulic fracturing process, which legislation could be reintroduced in the current session of Congress. Further, certain members of the Congress have called upon the U.S. Government Accountability Office to investigate how hydraulic fracturing might adversely affect water resources, the SEC to investigate the natural gas industry and any possible misleading of investors or the public regarding the economic feasibility of pursuing natural gas deposits in shales by means of hydraulic fracturing, and the U.S. Energy Information Administration to provide a better understanding of that agency's estimates regarding natural gas reserves, including reserves from shale formations, as well as uncertainties associated with those estimates. Certain states and localities have also considered or imposed reporting and other operational obligations relating to the use of hydraulic fracturing techniques.

Certain states, including Texas, where we conduct operations, have adopted, and other states are considering the adoption of, regulations that impose new or more stringent permitting, disclosure and well construction requirements on hydraulic fracturing operations. In addition to state laws, local land use restrictions, such as city ordinances, may restrict or prohibit drilling in general or hydraulic fracturing in particular. Such efforts have resulted in the imposition of bans on hydraulic fracturing. Some local jurisdictions, including Dallas, Texas, have adopted regulations restricting hydraulic fracturing. The proliferation of regulations may limit our ability to conduct hydraulic fracturing, which is an essential component of our current operations in the Eagle Ford trend of south Texas and in the Williston Basin of North Dakota and Montana.

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 Texas and other 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 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 several recent 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

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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.

Regulation related to global warming and climate change could have an adverse effect on our operations and demand for oil and natural gas.

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 and the Kyoto Protocol address greenhouse gas emissions, and international negotiations over climate change and greenhouse gases are continuing. Meanwhile, several countries, including those comprising the European Union, have established greenhouse gas regulatory regimens.

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

At the federal level, the Obama Administration is attempting to address climate change through a variety of administrative actions. The EPA has issued greenhouse gas monitoring and reporting regulations that cover oil and natural gas facilities, among other industries. On July 19, 2011, the EPA amended the oil and natural gas facility greenhouse gas reporting rule to require reporting beginning in September 2012. Beyond measuring and reporting, the EPA issued an “Endangerment Finding” under section 202(a) of the Clean Air Act, concluding certain greenhouse gas pollution threatens the public health and welfare of current and future generations. The finding served as the first step to issuing regulations that require permits for and reductions in greenhouse gas emissions for certain facilities. In March 2014, moreover, the President released a Strategy to Reduce Methane Emissions that included consideration of both voluntary programs and targeted regulations for the oil and gas sector. Towards that end, the EPA has released five draft white papers on methane and volatile organic compound emissions and mitigation measures for natural gas compressors, hydraulically fractured oil wells, pneumatic devices, well liquids unloading facilities and natural gas production and transmission facilities. Building on its white papers and public input on those documents, the EPA has announced that it intends to issue a proposed rule in the summer of 2015 to set standards for methane and VOC emissions from new and modified oil and gas production sources and natural gas transmissions sources. Also as part of the President’s strategy, the BLM is expected to propose 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 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 controls or other compliance costs, and reduce demand for our products.

The ongoing implementation of federal legislation enacted in 2010 could have an adverse impact on our ability to use derivative instruments to reduce the effects of commodity prices, interest rates and other risks associated with our business.

Historically, we have entered into a number of commodity derivative contracts in order to hedge a portion of our oil and natural gas production and, periodically, interest expense. On July 21, 2010, President Obama signed into law the Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Act, which requires the SEC and the Commodity Futures Trading Commission (or CFTC), along with other federal agencies, to promulgate regulations implementing the new legislation. The CFTC, in coordination with the SEC and various U.S. federal banking regulators, has issued regulations to implement the so-called “Volcker Rule” under which banking entities are generally prohibited from proprietary trading of derivatives. Although conditional exemptions from this general prohibition are available, the Volcker Rule may limit the trading activities of banking entities that have been counterparties to our derivatives trades in the past. Also, a provision of the Dodd-Frank Act known as the “swaps push-out rule” may require some of the banking counterparties to our commodity derivative contracts to “push out” some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty.

The CFTC also has finalized other regulations implementing the Dodd-Frank Act’s provisions regarding trade reporting, margin and position limits; however, some regulations remain to be finalized and it is not possible at this time to predict when the CFTC will adopt final rules. For example, the Dodd-Frank Act and the CFTC regulations may require compliance with margin requirements and

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with certain clearing and trade-execution requirements in connection with certain of our derivative activities. Also, the CFTC has re-proposed regulations setting position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. Certain bona fide hedging transactions are expected to be made exempt from these limits. It is possible that the CFTC, in conjunction with the U.S. federal banking regulators, may mandate that financial counterparties entering into swap transactions with end-users must do so with credit support agreements in place, which could result in negotiated credit thresholds above which we would be required to post collateral.

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

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.

Hedging transactions may limit our potential gains and increase our potential losses.

In order to manage our exposure to price risks in the marketing of our oil, natural gas, and natural gas liquids production, we have entered into hedging arrangements with respect to a portion of our anticipated production and we may enter into additional hedging transactions in the future. While intended to reduce the effects of volatile oil and natural gas prices, these transactions may limit our potential gains and increase our potential losses if oil and natural gas prices, were to rise substantially over the price established by the hedges. In addition, these transactions may expose us to the risk of loss in certain circumstances, including instances in which:

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.

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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.

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 64% 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.

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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.

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.

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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 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.

2014 Increases in proved reserves

From January 1, 2014 to December 31, 2014, our proved reserves increased as follows:

These significant increases were attributable to a combination of (i) drilling and development and (ii) the strategic combination with OVR and the Flatonia acquisition, which occurred in 2014 and are more fully described elsewhere in this report.  

Proved Reserves as of December 31, 2014

The below table sets forth a summary of our estimated crude oil, natural gas and natural gas liquids reserves as of December 31, 2014 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 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

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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 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 increased 4,667 MBOE or 60%, for the year ended December 31, 2014 compared to the year ended December 31, 2013.  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 2014 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, 2014 (in MBOE):

Conversions.  In 2014, approximately 63% of the reserve conversions occurred in our operated Eagle Ford / Austin Chalk properties in Fayette and Gonzales Counties, Texas, with the remaining occurring in our non-operated Eagle Ford project in La Salle County, Texas.  

Extensions and discoveries.  During 2014, we added 850 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.

Purchases.  In December 2014, we acquired additional interests in our operated Eagle Ford properties in Fayette and Gonzales Counties, Texas and acquired properties in the Williston Basin of North Dakota and Montana as part of our Oak Valley and Flatonia acquisitions as disclosed elsewhere in this report.   

Revisions.  In 2014, the upward revisions of 672 MBOE to PUD reserves occurred primarily as a result of increased natural gas prices, which increased 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 30 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

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

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,” 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 (“NGLs”) produced and sold by us for the years ended December 31, 2014, 2013, and 2012, the average sales price per unit sold and the average production cost per unit are presented below.

As of December 31, 2014, three fields accounted for 65% of our total estimated proved reserves. Two of those fields, Southern Bay Eagle Ford and Eagleville, which were acquired during the year ended December 31, 2013, accounted for 37% and 16%, respectively, of our total estimated proved reserves. The third field, Hawkville, was 12% 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, 2014, 2013 or 2012. The net

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quantities of oil, natural gas and NGLs produced and sold by us from these significant fields for each of the years ended December 31, 2014, 2013 and 2012, the average sales price per unit sold and the average production cost per unit are presented below.

Southern Bay Eagle Ford Field

Eagleville Field

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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 NGLs production consist primarily of independent marketers, major oil and natural gas companies and pipeline companies. In 2014 and 2013, one purchaser, United Energy Trading, LLC (“United”), accounted for 60% and 21%, of our oil, natural gas and NGLs revenues, respectively. 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 NGLs revenues during 2014. , 2013 and 2012.

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 NGLs to the purchaser, and collects and distributes the revenue to us. In 2014, one operator account for 20% of our total oil, natural gas and NGLs revenues. In 2013, two operators distributed 47% and 11% of our oil, natural gas and NGL revenues. In 2012, two operators distributed 65% and 18% of our oil, natural gas and NGLs revenues. No other operator accounted for 10% or more of our oil, natural gas and NGLs revenues during the years ended December 31, 2014, 2013 and 2012.

Gross and Net Productive Wells

As of December 31, 2014, our total gross and net productive wells were as follows:

Gross and Net Developed and Undeveloped Acres

As of December 31, 2014, 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.

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Exploratory Wells and Development Wells

Set forth below for the three years ended December 31, 2014 is information concerning the number of wells the Company drilled during the years indicated.

Present Activities

As of December 31, 2014, we had 17 gross (7.8 net) operated wells in the process of drilling or completing and 51 gross (2.2 net) non-operated well in the process of drilling or completing.  

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, 2014, and through the filing date of this report, we are not aware of any such proceedings against us or contemplated to be brought against us.  

Item 4.  Mine Safety Disclosures

Not applicable.

PART II

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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 23, 2015, there were approximately 2,000 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.

Unregistered Sale of Securities

On December 19, 2014, we closed (i) the transactions contemplated by the Exchange Agreement dated May 15, 2014 and as amended September 26, 2014 (the “Exchange Agreement”) with OVR and (ii) the previously announced Contribution Agreement dated October 16, 2014 (the “Contribution Agreement”), by and among us, OVR, Sabine, OVO, Parallel Resources Partners, LLC, a Delaware limited liability company (“Parallel”), and Flatonia.  

Pursuant to the Exchange Agreement, OVR, contributed to us membership interest in its three subsidiaries, OVO, Sabine and EF Non-Op, LLC, a Texas limited liability company, inclusive of producing assets, undeveloped acreage and approximately $130.0 million of cash , in exchange for the issuance of 9,124,452 shares (the “Exchange Shares”) of Common Stock, to OVR (the “Exchange”). The issuance of the Exchange Shares was exempt from registration as a private placement under Section 4(a)(2) of the Securities Act, and Rule 506 promulgated thereunder, among other exemptions.

Pursuant to the Contribution Agreement, Sabine, acquired a 20% undivided ownership interest in certain oil and gas properties located in Fayette and Gonzales Counties, Texas, in exchange for the issuance of 2,957,288 shares (the “Contribution Shares”) of Common Stock to Flatonia (the “Contribution”). The issuance of Contribution Shares was exempt from registration as a private placement under Section 4(a)(2) of the Securities Act, and Rule 506 promulgated thereunder, among other exemptions.    

Equity Compensation Plan Information

In December 2014, our stockholders approved and adopted the 2014 Long-Term Incentive Plan (the “2014 Plan”), which was effective upon the December 19, 2014 closing of the Exchange Agreement and the 2014 Plan remain in effect until December 18, 2024.  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.

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The 2014 Plan currently provides that a maximum of 750,000 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.

The following table sets forth information concerning our only compensation plan available to non-employee directors, officers, employees and consultants at December 31, 2014:

Repurchase of Equity Securities

We did not repurchase any of our shares of common stock during the quarter ended December 31, 2014.

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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 generally accepted accounting practices in the United States (“GAAP”) the financial information and financial statements included herein are those of OVR and its subsidiaries. Prior to the reverse acquisition 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 should be read together with the 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.

Overview

We are an independent oil and gas company engaged in the acquisition, development, exploration and production of onshore, oil and natural gas reserves. 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. 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 Texas and in the Williston Basin of North Dakota and Montana. 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. Following is a brief outline of our current plans:

While the impact and success of our corporate plans cannot be predicted with accuracy, our goal is to replace production and further increase our reserve base at an acquisition or finding cost that will yield attractive rates of return.

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, 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 has been accounted for as a reverse acquisition in which Oak Valley is considered the acquirer for accounting purposes.  All historical financial information contained in this report is that of OVR and its subsidiaries.  

Immediately following the Exchange, we acquired an additional 20% undivided ownership interest in certain oil and natural gas properties located in Fayette and Gonzales Counties, Texas, (the “2014 Eagle Ford Acquisition Properties”) 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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As of December 31, 2014, we had an estimated 22,192 MBOE of proved reserves, consisting of 13,803 MBbls of oil, 38,579 MMcf of natural gas, and 1,959 MBbls of natural gas liquids. Approximately 44% of our proved reserves were classified as proved developed. Production for the year ended December 31, 2014, totaled 882 MBOE, or 2,416 BOE per day, of which 46% was oil.

Results of Operations

Year ended December 31, 2014, compared to the year ended December 31, 2013

Sales and Other Operating Revenues

The quantities of oil, natural gas, and natural gas liquids produced and sold for the years ended December 31, 2014 and 2013, and the average sales price per unit sold are presented below:

Our revenues for the years ended December 31, 2014 and 2013, are summarized in the table below:

Sale of Oil

For the year ended December 31, 2014, oil revenues increased by $18.7 million or 117% relative to the comparable period in 2013. Of the increase, $23.5 million was attributable to increased volume, which was offset by $4.8 million attributable to a decrease in our realized price. Oil sales volumes increased by 240 MBbls primarily due to an increase of 223 MBbls produced from our operated Eagle Ford property. The interest in these properties that we acquired during 2013 provided for 212 MBbls of the increase while the additional interest we acquired during mid-December 2014, the 2014 Eagle Ford Acquisition Properties, provided for an additional 10 MBbls. Also contributing to the increase in oil sales volumes was 6 MBbls from the legacy Earthstone assets and 12 MBbls from our Grayson County wells that were drilled in late 2013. Average realized price per Bbl decreased from $98.32 for the year ended December 31, 2013 to $86.29 for the year ended December 31, 2014.

Sale of Natural Gas

For the year ended December 31, 2014, natural gas revenues decreased by $0.3 million or 4% relative to the comparable period in 2013. Of the decrease, $1.8 million was attributable to decreased volume, which was offset by $1.5 million attributable to an increase in our realized price. Natural gas sales volumes decreased by 503 MMcf primarily due to a decline in production of 406 MMcf from our non-operated Eagle Ford properties in La Salle County, Texas, a decline in production of 143 MMcf from our non-operated east Texas properties, as well as approximately 61 MMcf due to natural production declines in our other properties. The decreases in

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production volumes were offset by a production increase of 97 MMcf from our operated Eagle Ford property. The interest in these properties that we acquired during 2013 provided for 93 MMcf of the increase while the additional interest we acquired during mid-December 2014, the 2014 Eagle Ford Acquisition Properties, provided for an additional 4 MMcf. Also offsetting the decreases above was 10 MMcf from the legacy Earthstone properties. Our average realized price per Mcf increased from $3.69 for the year ended December 31, 2013 to $4.39 for the year ended December 31, 2014.

Sale of Natural Gas Liquids

For the year ended December 31, 2014, natural gas liquids revenues decreased by $0.4 million or 10% relative to the comparable period in 2013. Of the decrease, $0.3 million was attributable to decreased volume and $0.1 million was attributable to realized price. Natural gas liquids sales volumes decreased by 10 MBbls primarily due to a decline in production of 39 MBbls from our non-operated Eagle Ford properties in La Salle County, Texas, which was offset by increases in production of 26 MBbls from our operated Eagle Ford property. The interest in these properties that was acquired during 2013 accounted for substantially all of this increase.  Average realized price per Bbl decreased from $28.88 for the year ended December 31, 2013 to $28.29 for the year ended December 31, 2014.

Production Costs

Our production costs for the years ended December 31, 2014 and 2013 are summarized in the table below:

Lease Operating Expenses

Lease operating expenses (“LOE”) includes all costs incurred to operate wells and related facilities for both operated and non-operated properties. In addition to direct operating costs such as labor, repairs and maintenance, equipment rentals, materials and supplies, fuel and chemicals, LOE includes product marketing and transportation fees, insurance, ad valorem taxes, accretion expense related to asset retirement obligations, and overhead charges provided for in operating agreements. Ad valorem taxes included in LOE were $0.5 million in both the years ended December 31, 2014 and 2013.

LOE increased by $1.7 million or 20% for the year ended December 31, 2014 relative to the comparable period in 2013. The increase in LOE was primarily due to our operated Eagle Ford properties. On a unit-of-production basis, LOE, excluding ad valorem taxes and accretion expense, has remained relatively consistent, increasing by only $0.12 per BOE from $10.59 in 2014 to $10.47 in 2013. The additional interests that we acquired in our operated Eagle Ford property during December 2014 accounted for $50,000 of the total increase while the legacy Earthstone assets accounted for $53,000 of the increase.

Severance Taxes

Severance taxes increased by $0.8 million or 63% for the year ended December 31, 2014 relative to the comparable period in 2013. The increase in severance taxes was primarily due to increased production from our operated Eagle Ford property. The interest in this property that we acquired during 2013 accounted for $0.9 million of the total increase while the additional interest we acquired in December-2014 added $30,000. The legacy Earthstone assets added an additional $35,000. These increases were offset by decreases on our non-operated Eagle Ford property. As a percentage of revenues from oil, natural gas, and natural gas liquids, severance taxes increased from 4.13% to 4.20%.

Re-engineering and Workovers

Re-engineering and workover expenses include the costs to restore or enhance production in current producing zones as well as costs of significant non-recurring operations. These costs increased $0.4 million or 107% for the year ended December 31, 2014 relative to the comparable period in 2013.  During 2014, we began completing several projects associated with integrating the interests we acquired during 2013 in our operated Eagle Ford property into our operations and reducing the rate at which those wells decline.

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General and Administrative Expenses

General and administrative expenses (“G&A”), primarily consist of overhead expenses, employee remuneration, and professional and consulting fees.

G&A expenses increased by $0.1 million from $7.8 million to $7.9 million for the year ended December 31, 2014 relative to the comparable period in 2013. The increase was due to increased headcount and strategic combination related costs but was largely offset by increased overhead cost re-imbursements provided for in our joint operating agreements on the properties we operate.      

Depreciation, Depletion and Amortization and Impairment Expense

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization (“DD&A”) increased in 2014 by $1.3 million, or 8% compared to 2013, due to property additions related primarily to drilling and completion expenditures and increased production during the year ended December 31, 2014, as compared to the same period in 2013.   However, on a unit-of-production basis, DD&A decreased to $20.88 per BOE during 2014 from $23.22 per BOE during 2013. Despite an increase in capitalized property costs, DD&A on a per BOE basis decreased. Reserves in our operated Eagle Ford properties increased significantly, which helped to bring the per BOE rate down, due to successful drilling in the area which resulted in additional proved reserves. We were also able to decrease the rate per BOE due to improved drilling and completion efficiencies and resultant improvement on finding and development costs on a per BOE basis.  The additional interest we acquired in our operated Eagle Ford properties during December 2014 and the legacy Earthstone assets increased DD&A by $0.1 million and $0.1 million, respectively.

Impairment

During the year ended December 31, 2014, we incurred impairment charges of $19.4 million, which consisted of $2.5 million on unproved properties and $16.9 million on proved properties. The impaired unproved properties consisted of acreage throughout Milam County, Texas. The impairment on proved properties primarily resulted from capitalized costs in excess of the fair market value for Oak Valley’s non-operated Eagle Ford property and its Grayson County property.

During the year ended December 31, 2013, we incurred impairment charges of $12.3 million which consisted of $2.5 million on unproved properties and $9.8 million on proved properties. The impaired unproved properties primarily consisted of acreage throughout Oklahoma and in Milam County, Texas. The impairment on proved properties resulted from capitalized costs in excess of the fair market value of our non-operated Eagle Ford property, our Milam County property and one of our east Texas properties.

Interest Expense

Interest expense includes commitment fees, amortization of deferred financing costs, and interest on outstanding indebtedness. Debt outstanding as of December 31, 2014 and December 31, 2013 was $11.2 million and $10.8 million, respectively. Interest expense increased from $0.5 million for the year ended December 31, 2013 to $0.6 million for the year ended December 31, 2014. The $0.1 million increase in interest expense was due to higher amortization of deferred financing costs and increased fees due to a larger credit facility and the accompanying larger unused commitment fees incurred during 2014 versus 2013.

Income Tax Expense

As a result of the Exchange, all historical financial information contained in this report is that of OVR and its subsidiaries.  OVR, is a partnership for federal income tax purposes and is not subject to federal income taxes or state or local income taxes that follow the federal treatment, and therefore OVR does not pay or accrue for such taxes. Pursuant to the Exchange, Oak Valley has become a subsidiary of Earthstone, a taxable entity; as such we recorded tax expense during the year ended December 31, 2014.

Net Gain on Derivative Contracts

During the year ended December 31, 2014, the Company recorded a net gain on derivative contracts of $4.4 million, consisting of net realized gains on settlements of $0.8 million and unrealized mark-to-market gains of $3.6 million. During the year ended December

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31, 2013, the Company recorded a net gain on derivative contracts of $0.3 million, consisting of net realized gains on settlements of $0.3 million and unrealized mark-to-market losses of $45,000.

Year ended December 31, 2013 compared to the year ended December 31, 2012

Sales and Other Operating Revenues

The quantities of oil, natural gas, and natural gas liquids produced and sold for the years ended December 31, 2013 and 2012, and the average sales price per unit sold are presented below:

Our revenues for the years ended December 31, 2013 and 2012 are summarized in the table below: