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EX-32.2 - EX-32.2 - EARTHSTONE ENERGY INCeste-ex322_116.htm
EX-99.1 - EX-99.1 - EARTHSTONE ENERGY INCeste-ex991_532.htm
EX-32.1 - EX-32.1 - EARTHSTONE ENERGY INCeste-ex321_115.htm
EX-31.2 - EX-31.2 - EARTHSTONE ENERGY INCeste-ex312_117.htm
EX-31.1 - EX-31.1 - EARTHSTONE ENERGY INCeste-ex311_118.htm
EX-23.3 - EX-23.3 - EARTHSTONE ENERGY INCeste-ex233_593.htm
EX-23.2 - EX-23.2 - EARTHSTONE ENERGY INCeste-ex232_533.htm
EX-23.1 - EX-23.1 - EARTHSTONE ENERGY INCeste-ex231_465.htm
EX-21.1 - EX-21.1 - EARTHSTONE ENERGY INCeste-ex211_119.htm

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-K

 

(Mark One)

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

For the Fiscal Year Ended December 31, 2016

Or

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

Commission File No. 001-35049  

 

EARTHSTONE ENERGY, INC.

(Exact name of registrant as specified in its charter)

 

 

Delaware

 

84-0592823

(State or other jurisdiction

of incorporation or organization)

 

(I.R.S. Employer

Identification No.)

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:

 

Title of each class

 

Name of each exchange on which registered

Common Stock, $0.001 par value per share

 

NYSE MKT

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

None

 

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

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

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

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

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, 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):

 

Large accelerated filer

 

  

Accelerated filer

 

 

 

 

 

Non-accelerated filer

 

  (Do not check if a smaller reporting company)

  

Smaller reporting company

 

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

The aggregate market value of voting and non-voting common equity held by non-affiliates computed by reference to the price of $10.78 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 $133,417,225.

As of March 9, 2017 22,273,820 shares of the registrant’s common stock were outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

None.

 

 

 

 


 

TABLE OF CONTENTS

 

 

 

 

Page

Glossary of Certain Oil and Natural Gas Terms

 

 

 

 

 

 

PART I

 

 

Item 1.

Business

 

8

Item 1A.

Risk Factors

 

17

Item 1B.

Unresolved Staff Comments

 

28

Item 2.

Properties

 

28

Item 3.

Legal Proceedings

 

35

Item 4.

Mine Safety Disclosures

 

35

PART II

 

 

Item 5.

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

 

38

Item 6.

Selected Financial Data

 

40

Item 7.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

 

40

Item 7A.

Quantitative and Qualitative Disclosures About Market Risk

 

53

Item 8.

Financial Statements and Supplemental Data

 

54

Item 9.

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

 

54

Item 9A.

Controls and Procedures

 

54

Item 9B.

Other Information

 

57

PART III

 

 

Item 10.

Directors, Executive Officers and Corporate Governance

 

58

Item 11.

Executive Compensation

 

64

Item 12.

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

 

71

Item 13.

Certain Relationships and Related Transactions, and Director Independence

 

73

Item 14.

Principal Accountant Fees and Services

 

74

PART IV

 

 

Item 15.

Exhibits, Financial Statements and Schedules

 

75

Signatures

 

79

 

 

 

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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:

 

volatility and weakness in commodity prices for oil, natural gas and natural gas liquids and the effect of prices set or influenced by action of the Organization of Petroleum Exporting Countries (“OPEC”);

 

substantial changes in estimates of our proved reserves;

 

substantial declines in the estimated values of our oil and natural gas reserves;

 

our ability to replace our oil and natural gas reserves;

 

the potential for production decline rates for our wells to be greater than we expect;

 

the timing and extent of our success in discovering, acquiring, developing and producing oil and natural gas reserves; 

 

the ability and willingness of our partners under our joint operating agreements to join in our future exploration, development and production activities;

 

our ability to acquire leases and quality services and supplies on a timely basis and at reasonable prices;

 

the cost and availability of high quality goods and services with fully trained and adequate personnel, such as drilling rigs and completion equipment;

 

risks in connection with potential acquisitions and the integration of significant acquisitions;

 

the possibility that acquisitions and divestitures may involve unexpected costs or delays, and that acquisitions may not achieve intended benefits and will divert management’s time and energy;

 

the possibility that anticipated divestitures may not occur or could be burdened with unforeseen costs;

 

reductions in the borrowing base under our credit facility;

 

risks incidental to the drilling and operation of oil and natural gas wells including mechanical failures;

 

the presence or recoverability of estimated oil and natural gas reserves and the actual future production rates and associated costs;

 

the availability of sufficient pipeline and other transportation facilities to carry our production to market and the impact of these facilities on prices;

 

significant competition for oil and natural gas acreage and acquisitions;

 

the effect of existing and future laws, governmental regulations and the political and economic climates of the United States;

 

our ability to retain key members of senior management and key technical and financial employees;

 

changes in environmental laws and the regulation and enforcement related to those laws;

 

the identification of and severity of environmental events and governmental responses to these or other environmental events;

 

legislative or regulatory changes, including retroactive royalty or production tax regimes, hydraulic-fracturing regulations, derivatives reform, and changes in federal and state income taxes;

 

general economic conditions, whether internationally, nationally or in the regional and local market areas in which we conduct business, may be less favorable than expected, including the possibility that economic conditions in the United States will worsen and that capital markets and debt will be disrupted or unavailable;

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social unrest, political instability or armed conflict in major oil and natural gas producing regions outside the United States, such as Africa, the Middle East, and acts of terrorism or sabotage;

 

the insurance coverage maintained by us may not adequately cover all losses that may be sustained in connection with our business activities;

 

other economic, competitive, governmental, regulatory, legislative, including federal, state and tribal regulations and laws, geopolitical and technological factors that may negatively impact our business, operations or oil and natural gas prices;

 

the effect of our oil and natural gas derivative activities;

 

title to the properties in which we have an interest may be impaired by title defects; and

 

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

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

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

 

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GLOSSARY OF CERTAIN OIL AND NATURAL GAS TERMS

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

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

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

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

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

Completion – The installation of permanent equipment for the production of oil or natural gas or, in the case of a dry hole, the reporting of abandonment to the appropriate agency.

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

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

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

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

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

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

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

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

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

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

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

Hydraulic fracture or Frac – A well stimulation method by which fluid (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.

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

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

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

MMBtu – One million Btu.

Mcf – One thousand cubic feet.

MMcf – One million cubic feet.

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

NGLs – Natural gas liquids measured in barrels.

NYMEX – The New York Mercantile Exchange.

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

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

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

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

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

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

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

Proved reserves – Those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. The area of the reservoir considered as proved includes (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest 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

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structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

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

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

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

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

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

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

Slickwater – A method of hydraulic fracturing that uses water with a minor amount of chemicals in order to stimulate rock and enhance fluid flow.

Swing producer – A supplier or a close oligopolistic group of suppliers of any commodity, controlling its global deposits and possessing large spare production capacity.

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 development and production company.  In addition, the Company is active in corporate mergers and the acquisition of oil and natural gas properties that have production and future development opportunities.  Our operations are all in the upstream segment of the oil and natural gas industry and all our properties are onshore in the United States.

Our reserve portfolio primarily consists of assets in the Midland Basin of west Texas, the Eagle Ford trend of south Texas and in the Williston Basin of North Dakota. We have approximately 5,900 net leasehold acres in the Midland Basin, representing an average 40% working interest, located in Howard, Glasscock, Martin and Midland Counties. We have approximately 21,000 net leasehold acres in the Eagle Ford trend of south Texas, including approximately 18,000 net leasehold acres in the crude oil window in Fayette, Gonzales and Karnes Counties, with working interests ranging from approximately 25% to 50%, and approximately 3,000 net leasehold acres located in the natural gas and condensate window in La Salle County, with working interests averaging approximately 11%. In the Williston Basin of North Dakota, we have approximately 5,900 net leasehold acres, with working interests ranging from approximately 1% to 6%.

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

Recent Developments

Acquisitions

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

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

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

Non-Recent Acquisitions

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

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

Immediately following the Exchange, we acquired an additional 20% undivided ownership interest in certain crude oil and natural gas properties located in Fayette and Gonzales Counties, Texas, in exchange for the issuance of approximately 2.957 million shares of our Common Stock (the “Flatonia Contribution Agreement”) to Flatonia Energy, LLC (“Flatonia”), increasing our ownership in these properties from a 30% undivided ownership to a 50% undivided ownership interest. As a result of the share issuance to Flatonia, OVR’s ownership in us decreased from 84% to 66%.

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

Our Business Strategy

We pursue a value-driven growth strategy focused on projects that we believe will generate strong and predictable rates of return and increases in stockholder value. Although we currently have significant non-operated properties, our intent is to operate the majority of our properties in order to control costs and direct the efficient development of such properties in an effort to optimize investment returns and profitability. Historically, we have operated the majority of our assets and implemented our strategy in multiple basins in order to enable us to benefit from regional changes and differences in realized prices, service costs, service availability and numerous other factors that would enhance the timely, cost-efficient and economic development of our assets, and lead to greater rates of return.  This multi-basin strategy could change in the future and we could focus all or a majority of our capital expenditures in a single basin, as a result of acquisitions, project economics and capital market considerations. Management concentrates on building production, reserves and cash flows while seeking to expand our undeveloped acreage and drilling inventory. 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, to a lesser extent, exploration activities, currently directed toward unconventional oil-weighted projects. Finally, management intends to pursue corporate and asset acquisition opportunities.

Our business strategy includes the following:

 

pursuing value-accretive corporate merger and acquisition opportunities;

 

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

 

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

 

generating additional development projects in our areas of primary interest;

 

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

 

maintaining a strong balance sheet and capital structure; and

 

obtaining additional capital, as needed and available, through the issuance of equity and debt securities or by soliciting industry or financial participants to jointly develop and/or acquire assets

 

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

 

maximizing profit margins;

 

controlling capital expenditures and operating and administrative costs; and

 

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

Management believes its strategy is appropriate because it addresses multiple risks of oil and natural gas operations while providing equity holders with upside potential and results in “staying power,” which management believes is essential to mitigate the adverse impacts of historically volatile commodity prices and financial markets.

9


 

Our Operations

We are currently the operator of properties containing approximately 38% of our proved oil and natural gas reserves and 58% of our proved PV-10 as of December 31, 2016 (see reconciliation of PV-10 to the standardized measure of discounted future net cash flows in Item 2. Properties). As operator, we are able to directly influence development and production of operations of our operated properties. Our producing properties have reasonably predictable production profiles and cash flows, subject to commodity price fluctuations. Our status as an operator has allowed us to pursue the development of undeveloped acreage, further develop existing properties and generate new projects that we believe have the potential to increase stockholder value.

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

Description of Major Properties

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

Midland Basin

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

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

Eagle Ford Basin

Operated Eagle Ford

As of December 31, 2016, we owned approximately 36,000 gross (17,600 net) leasehold acres in Fayette, Gonzales and Karnes Counties, Texas. The acreage is located in the crude oil window of the Eagle Ford shale trend of south Texas and is prospective for the Eagle Ford, Austin Chalk, Upper Eagle Ford, Buda, Wilcox and Edwards formations. We serve as the operator with a range of approximately 25% to 50% undivided ownership interest in substantially all of the acreage.

As of December 31, 2016, we operated 70 gross Eagle Ford wells and 9 gross Austin Chalk wells and had non-operated interests in two gross producing Eagle Ford wells and one gross producing Austin Chalk well. We have identified a total of approximately 140 gross Eagle Ford drilling locations in this acreage. The number of Eagle Ford locations could potentially increase subject to future down spacing initiatives and successful implementation of slickwater enhanced completions. In addition, because our acreage position is prospective for the Austin Chalk, Upper Eagle Ford, Buda, Wilcox and Edwards formations, we may have additional future economic locations. The majority of our acreage is covered by an approximately 173 square mile 3-D seismic survey, which is being used to develop the Eagle Ford and identify Austin Chalk locations and other economic opportunities.

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Non-Operated Eagle Ford

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

 

a)

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

 

b)

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

Williston Basin

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

Competition

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

Seasonality of Business

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

Operational Risks

Oil and natural gas exploitation, development and production involves 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, acquire or produce additional oil and natural gas in commercial quantities. Oil and natural gas operations also involve the risk that well fires, blowouts, equipment failure, human error and other events may cause accidental leakage or spills of toxic or hazardous materials, such as petroleum liquids or drilling fluids into the environment, or cause significant injury to persons or property. In such event, substantial liabilities to third parties or governmental entities may be incurred, the satisfaction of which could substantially reduce our available cash and possibly result in loss of oil and natural gas properties. Such hazards may also cause damage to or destruction of wells, producing formations, production facilities and pipeline or other processing facilities.

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

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Title to Properties

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

 

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

 

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

 

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

 

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

 

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

 

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

To the extent that such burdens and obligations affect our rights to production revenues, they have been taken into account in calculating our net revenue interests and in estimating the size and value of our reserves. We believe that the burdens and obligations affecting our oil and natural gas properties are conventional in our industry with respect to the types of properties 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, development and production activities related to oil and natural gas, including provisions related to permits for the drilling of wells, bonding requirements to drill or operate wells, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, sourcing and disposal of water used in the drilling and completion process, and the plugging and abandonment of wells. Our operations are also subject to various conservation laws and regulations. These laws and regulations govern the size of drilling and spacing units, the density of wells that may be drilled in oil and natural gas properties and the unitization or pooling of oil and natural gas properties. In this regard, some states allow the forced pooling or integration of land and leases to facilitate exploration and/or development 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, local authorities have imposed moratoria or other restrictions on exploration, development and production activities pending investigations and studies addressing potential local impacts of these activities before allowing oil and natural gas exploration, development and production to proceed.

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

Environmental Regulations

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

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Beyond existing requirements, new programs and changes in existing programs, may address various aspects of our business including oil and natural gas exploration, development and production, air emissions, waste management, and underground injection of waste material. Environmental laws and regulations have been subject to frequent changes over the years, and the imposition of more stringent requirements could have a material adverse effect on our business, financial condition or 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, development 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 or subject them to enhanced solid waste regulation. If such proposals were to be enacted, they could have a significant impact on our operating costs and on those of all the industry in general. In the ordinary course of our operations moreover, some wastes generated in connection with our exploration, development and production activities may be regulated as solid waste under RCRA, as hazardous waste under existing RCRA regulations or as hazardous substances under CERCLA. From time to time, releases of materials or wastes have occurred at locations we own or at which we have operations. These properties and the materials or wastes released thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, we have been and may be required to remove or remediate such materials or wastes.

Water Discharges

Our operations are also subject to the federal Clean Water Act and analogous state laws. Under the Clean Water Act, the EPA has adopted regulations concerning discharges of storm water runoff. This program requires covered facilities to obtain individual permits, or seek coverage under a general permit. Some of our properties may require permits for discharges of storm water runoff. We believe that we will be able to obtain, or be included under, these permits, where necessary, and make minor modifications to existing facilities and operations that would not have a material effect on us. The Clean Water Act and similar state acts regulate other discharges of wastewater, oil, and other pollutants to surface water bodies, such as lakes, rivers, wetlands, and streams. Failure to obtain permits for such discharges could result in civil and criminal penalties, orders to cease such discharges, and costs to remediate and pay natural resources damages. These laws also require the preparation and implementation of Spill Prevention, Control, and Countermeasure Plans in connection with on-site storage of significant quantities of oil. In the event of a discharge of oil into U.S. waters we could be liable under the Oil Pollution Act for clean-up costs, damages and economic losses.

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

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Under the direction of Congress, the EPA completed a study finding that hydraulic fracturing could potentially harm drinking water resources under adverse circumstances such as injection directly into groundwater or into production wells lacking mechanical integrity. The EPA has also finalized pre-treatment standards under the Clean Water Act for wastewater discharges from shale hydraulic fracturing operations to municipal sewage treatment plants. Beyond that, several environmental groups have petitioned 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 and to require disclosure under the Toxic Substances Control Act of chemicals used in fracturing. Congress might likewise consider legislation to amend the federal 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, already have issued similar disclosure rules.

In addition, the Department of the Interior has promulgated regulations concerning the use of hydraulic fracturing on lands under its jurisdiction, which includes lands on which we conduct or plan to conduct operations. States similarly have been imposing new restrictions or bans on hydraulic fracturing. Even local jurisdictions have adopted, or tried to adopt, regulations restricting hydraulic fracturing. Additional hydraulic fracturing requirements at the federal, state or local level may limit our ability to operate or increase our operating costs.

Air Emissions

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

In 2012 and 2016, the EPA issued air regulations for the oil and natural gas industry that address emissions from certain new sources of volatile organic compounds (“VOCs”), sulfur dioxide, air toxics and methane. The rules include the first federal air standards for oil and natural gas wells that are hydraulically fractured, or refractured, as well as requirements for other processes and equipment, including storage tanks. Compliance with these regulations has imposed additional requirements and costs on our operations. The EPA also has started to consider whether to extend such regulations to existing wells.

In October 2015, the EPA announced that it was lowering the primary national ambient air quality standards (“NAAQS”) for ozone from 75 parts per billion to 70 parts per billion. Implementation will take place over several years; however, the new standard could result in a significant expansion of ozone nonattainment areas across the United States, including areas in which we operate. Oil and natural gas operations in ozone nonattainment areas would likely be subject to increased regulatory burdens in the form of more stringent emission controls, emission offset requirements, and increased permitting delays and costs.

Climate Change

Studies over recent years have indicated that emissions of certain gases may be contributing to warming of the Earth’s atmosphere. In response to these studies, governments have been adopting domestic and international climate change regulations that require reporting and reductions of the emission of such greenhouse gases. Methane, a primary component of natural gas, and carbon dioxide, a byproduct of burning oil, natural gas and refined petroleum products, are considered greenhouse gases. Internationally, the United Nations Framework Convention on Climate Change, the Kyoto Protocol and the Paris Agreement address greenhouse gas emissions, and several countries including those comprising the European Union, have established greenhouse gas regulatory systems. In the United States, at the state level, many states, either individually or through multi-state regional initiatives, have been implementing legal measures to reduce emissions of greenhouse gases, primarily through 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, the Obama Administration developed a Strategy to Reduce Methane Emissions that was intended to result by 2025 in a 40-45% decrease in methane emissions from the oil and gas industry as compared to 2012 levels. Consistent with that strategy, the EPA issued its air rules for oil and natural gas production sources, and the federal Bureau of Land Management (“BLM”) promulgated standards for reducing venting and flaring on public lands.

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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, development 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 federal and state statutes prohibit certain actions that adversely affect endangered or threatened species and their habitat, migratory birds, wetlands, and natural resources. These statutes include the Endangered Species Act, the Migratory Bird Treaty Act and the Clean Water Act. The United States Fish and Wildlife Service may designate critical habitat areas that it believes are necessary for survival of threatened or endangered species. A critical habitat designation could result in further material restrictions on federal land use or on private land use and could delay or prohibit land access or development. Where takings of or harm to species or damages to wetlands, habitat, or natural resources occur or may occur, government entities or at times private parties may act to prevent or restrict oil and natural gas exploration activities or seek damages for any injury, whether resulting from drilling or construction or releases of oil, wastes, hazardous substances or other regulated materials, and in some cases, criminal penalties may result. Moreover, as a result of a settlement approved by the U.S. District Court for the District of Columbia in September 2011, the U.S. Fish and Wildlife Service is required to make a determination on listing of more than 250 species as endangered or threatened under the ESA by no later than completion of the agency’s 2017 fiscal year. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. The federal government in the past has issued indictments under the Migratory Bird Treaty Act to several oil and natural gas companies after dead migratory birds were found near reserve pits associated with drilling activities. The identification or designation of previously unprotected species as threatened or endangered in areas where underlying property operations are conducted could cause us to incur increased costs arising from species protection measures or could result in limitations on our development activities that could have an adverse impact on our ability to develop and produce our oil and natural gas reserves. If we were to have a portion of our leases designated as critical or suitable habitat, it could adversely impact the value of our leases.

Hazard communications and community right to know

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

Occupational Safety and Health Act

We are subject to the requirements of the federal Occupational Safety and Health Act and comparable state statutes 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, 2016, we had 48 full-time employees and one part-time employee; 9 are management, 13 are technical personnel, 15 are administrative personnel and 12 are field operations employees. Our employees are not covered under a collective bargaining agreement nor are any employees represented by a union. We consider all relations with our employees to be satisfactory.

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Office Leases

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

 

Location

 

Approximate Size

 

Lease Expiration Date

 

Intended Use

The Woodlands, Texas

 

19,600 sq. ft.

 

December 31, 2019

 

Office

Denver, Colorado

 

7,000 sq. ft.

 

April 30, 2018

 

Office

 

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

Available Information

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

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Item 1A.  Risk Factors

Our business is subject to various risks and uncertainties in the course of our business. The following summarizes significant risks and uncertainties that may adversely affect our business, financial condition or results of operations. When considering an investment in our shares, you should carefully consider the risk factors included below as well as those matters referenced in this report under “Cautionary Statement Concerning Forward-Looking Statements” and other information included and incorporated by reference into this report.

Oil, natural gas and natural gas liquids prices have been historically volatile. Their prices since 2014 have adversely affected, and may continue to adversely affect, our business, financial condition and results of operations and may in the future affect our ability to meet our financial commitments as well as negatively impact our stock price.

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

 

worldwide and regional economic and financial conditions impacting global and regional supply and demand;

 

the level of global exploration, development and production;

 

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

 

foreign and domestic supply capabilities;

 

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

 

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

 

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

 

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

 

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

 

current and future regulations regarding well spacing;

 

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

 

localized and global supply and demand fundamentals and transportation availability;

 

weather conditions;

 

technological advances affecting energy consumption;

 

the price and availability of alternative fuels; and

 

domestic, local and foreign governmental regulation and taxes.

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

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business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures. In addition, lower oil, natural gas and natural gas liquids gas prices may cause a further decline in the price of our shares.

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

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

Oil, natural gas and natural gas liquids prices have been significantly lower than they were in mid-2014. If those prices fall below current levels for an extended period of time and all other factors remain equal, we may incur impairment charges in the future. Such charges could have a material adverse effect on our results of operations for the periods in which they are recorded. See Note 6. Oil and Natural Gas Properties to our consolidated financial statements included in this report for additional information.

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

Availability under our Credit Agreement is currently subject to a borrowing base of $80.0 million. The borrowing base is subject to scheduled semiannual redeterminations (May 1 and November 1), as well as other elective borrowing base redeterminations. The lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under our Credit Agreement. Reductions in estimates of our oil, natural gas and natural gas liquids reserves may result in a reduction in our borrowing base under our Credit Agreement (if prices are kept constant). Reductions in our borrowing base under our Credit Agreement could also arise from other factors, including but not limited to:

 

 

lower commodity prices or production;

 

increased leverage ratios;

 

inability to drill or unfavorable drilling results;

 

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

 

increased operating and/or capital costs;

 

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

 

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

 

As of March 1, 2017, we had $10.0 million of borrowings outstanding under our Credit Agreement. We may make further borrowings under our Credit Agreement in the future. Any significant reduction in our borrowing base under our Credit Agreement as a result of borrowing base redeterminations or otherwise will negatively impact our liquidity and our ability to fund our operations and, as a result, could have a material adverse effect on our financial position, results of operation and cash flows. Further, if the outstanding borrowings under our Credit Agreement were to exceed the borrowing base as a result of any such redetermination, we could be required to repay the excess.

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

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

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and future production at acceptable costs. If we are unable to replace our current and future production, our cash flows and the value of our reserves may decrease, adversely affecting our business, financial condition and results of operations.

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

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

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

 

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

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

At December 31, 2016, approximately 22% of our estimated reserves were classified as proved undeveloped. Recovery of estimated proved undeveloped reserves requires significant capital expenditures and successful drilling operations. The estimated reserve data assumes that we will make specified 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 may vary from estimated capital expenditures, development may not occur as scheduled and actual results may not be as estimated.

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

You should not assume that the standardized measure of discounted future net cash flows from our estimated proved reserves is the current market value of our estimated oil and natural gas reserves. In accordance with SEC requirements in effect at December 31, 2016, 2015 and 2014, we based the discounted future net cash flows from our proved reserves on the 12-month first-day-of-the-month oil and natural gas arithmetic average prices without giving effect to derivative transactions. Actual future net cash flows from our oil and natural gas properties will be affected by factors such as:

 

the actual prices we receive for oil and natural gas;

 

the actual cost of development and production expenditures;

 

the amount and timing of actual production; and

 

changes in governmental regulations or taxation.

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

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If commodity prices decrease to a level such that our estimated 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 respective 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 oil and natural gas properties. We may incur impairment charges in the future, which could have a material adverse effect on our results of operations for the periods in which such charges are recorded.

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

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

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

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

Although our management team has  identified  numerous  potential drilling locations as a part of our long-range planning related to future drilling activities on our existing acreage, our ability to drill and develop these locations depends on a number of factors, which are beyond our control , including, the availability and cost of capital, oil, natural gas and natural gas liquids prices, drilling and production costs, the availability of drilling services and equipment, drilling results (including the impact of increased horizontal drilling density and longer laterals), lease expirations, gathering systems, marketing and pipeline transportation constraints, regulatory approvals and other factors.  As such, our actual drilling and completion activities, may materially differ from those presently anticipated. Accordingly, it is not certain that these  potential drilling locations  will be developed or if we will be able to produce significant oil, natural gas and natural gas liquids from these or any other potential drilling locations.  Unless production is established, in accordance with the terms of mineral leases that are associated with these locations, such leases could expire.

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

In an effort to achieve more predictable cash flows and reduce our exposure to adverse fluctuations in the prices of oil and natural gas, we often enter into derivative instrument contracts for a portion of our oil and natural gas production, including swaps, collars, puts and basis swaps. We recognize all derivatives as either assets or liabilities, measured at fair value, and recognizes changes in the fair value of derivatives in current earnings. Accordingly, our earnings may fluctuate significantly as a result of changes in the fair market value of our derivative instruments. As our derivative instrument contracts expire, there is uncertainty that we will be able to comparably replace them.

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

 

 

production is less than the volume covered by the derivative instruments;

 

the counter-party to the derivative instrument defaults on its contractual obligations;

 

there is an increase in the differential between the underlying price stated in the derivative instrument contract and actual prices received; or

 

there are issues with regard to legal enforceability of such instruments.

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

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

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

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

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

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

In assessing potential acquisitions, we 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 businesses or properties to be acquired may not uncover all existing or relevant data, obligations or actual or contingent liabilities that could adversely impact any business or property to be acquired and, hence, could adversely affect us as a result of the acquisition. These issues may be material and could include, among other things, unexpected environmental problems, title defects or other liabilities. If we acquire properties on an “as-is” basis, we may have limited or no remedies against the seller with respect to these types of problems.

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

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.

 

Our previously announced proposed transaction with Bold Energy Holdings, LLC (“Bold”) pursuant to the “Bold Contribution Agreement” is subject to material risks.

 

On November 7, 2016, we entered into the Bold Contribution Agreement. The purpose of that agreement is to provide for the business combination between Earthstone and Bold. Bold owns significant developed and undeveloped oil and natural gas properties in the Midland Basin of west Texas. Although we expect to complete the Bold Contribution Agreement, its completion is not assured and is subject to risks, including the risks that approval of the Bold Contribution Agreement by our stockholders will not be obtained or that certain other closing conditions will not be satisfied. If during the pendency of the Bold Contribution Agreement or if it is not completed, our ongoing business and financial results may be adversely affected, including:

 

 

us having to pay certain significant transaction costs relating to an unsuccessful Transaction;

 

restrictions in our ability to pursue alternatives to the Bold Contribution Agreement, which could discourage a potential acquirer from making an alternative proposal to us;

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the potential payment of a termination fee of $5.5 million in certain instances if we accept a proposal from another party we believe to be superior to the Bold Contribution Agreement or if we breach our non-solicitation or other representations, warranties or covenants;

 

the fact that we are subject to certain restrictions in the conduct of our business prior to closing or termination of the Transaction which may prevent us from making certain acquisitions or dispositions or pursuing certain business opportunities;

 

the potential decline in the share price of our Common Stock to the extent that the market prices reflect an assumption by the market that the Bold Contribution Agreement will not be completed or if, in fact, it is not completed at all; and

 

we may be subject to litigation related to any failure on our part to complete the Bold Contribution Agreement, or litigation resulting from minority stockholder actions.

 

Completion of the Bold Contribution Agreement may also give rise to additional business risks, including:

 

 

the fact that our sole material asset will be our equity interest in EEH, which will be the holding company for all our assets and Bold’s assets and accordingly we will be dependent on distributions from EEH to pay taxes and cover our corporate and other overhead expenses;

 

we may experience difficulties in integrating our business with Bold’s business, which could cause the combined company to fail to realize many of the anticipated potential benefits of the Bold Contribution Agreement; and

 

most of our current stockholders will have a reduced ownership and voting interest after the Bold Contribution Agreement.

 

These and other considerations and risks associated with the Bold Contribution Agreement will be fully discussed in a proxy statement to be delivered to our stockholders when available.

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

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

 

 

unanticipated, abnormally pressured formations;

 

significant mechanical difficulties, such as stuck drilling and service tools and casing collapses;

 

blowouts, fires and explosions;

 

personal injuries and death;

 

uninsured or underinsured losses; and

 

environmental hazards, such as uncontrollable flows of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater contamination.

Any of these operating hazards could cause damage to properties, reduced cash flows, serious injuries, fatalities, oil spills, discharge of hazardous materials, remediation and clean-up costs and other environmental damages, which could expose us to significant liabilities. 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 exposes us to significant compliance costs and liabilities.

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

 

 

land use restrictions;

 

delivery of our oil and natural gas to market;

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drilling bonds and other financial responsibility requirements;

 

spacing of wells;

 

air emissions;

 

property unitization and pooling;

 

habitat and endangered species protection, reclamation and remediation;

 

containment and disposal of hazardous substances, oil field waste and other waste materials;

 

drilling permits;

 

use of saltwater injection wells, which affects the disposal of saltwater from our wells;

 

safety precautions;

 

prevention of oil spills;

 

operational reporting; and

 

taxation and royalties.

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

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

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

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

From time to time, for example, legislation has been proposed in Congress to amend the federal Safe Drinking Water Act (“SDWA”) to require federal permitting of hydraulic fracturing and the disclosure of chemicals used in the hydraulic fracturing process. Further, the EPA completed a study finding that hydraulic fracturing could potentially harm drinking water resources under adverse circumstances such as injection directly into groundwater or into production wells lacking mechanical integrity. Other governmental reviews have also been recently conducted or are under way that focus on environmental aspects of hydraulic fracturing. For example, a federal Bureau of Land Management (the “BLM”) rulemaking for hydraulic fracturing practices on federal and Indian lands resulted in a 2015 final rule that requires public disclosure of chemicals used in hydraulic fracturing, confirmation that the wells used in fracturing operations meet proper construction standards and development of plans for managing related flowback water. These activities could result in additional regulatory scrutiny that could make it difficult to perform hydraulic fracturing and increase our costs of compliance and doing business.

Certain states, including North Dakota where we conduct operations, and have interests in numerous non-operated wells and have adopted, and other states are considering or have adopted more stringent requirements for various aspects of hydraulic fracturing operations, such as permitting, disclosure, air emissions, well construction, seismic monitoring, waste disposal and water use. In

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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 extended to bans on hydraulic fracturing.

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

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

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

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

At the federal level, the Obama Administration pledged for the Paris Agreement to meet an economy-wide target in 2025 of reducing greenhouse gas emissions by 26-28% below the 2005 level. To help achieve these reductions, federal agencies have been addressing climate change through a variety of administrative actions. The U.S. Environmental Protection Agency (the “EPA”) thus issued greenhouse gas monitoring and reporting regulations that cover oil and natural gas facilities, among other industries. Beyond measuring and reporting, the EPA issued an “Endangerment Finding” under Section 202(a) of the federal Clean Air Act, concluding certain greenhouse gas pollution threatens the public health and welfare of current and future generations. The finding served as the first step to issuing regulations that require permits for and reductions in greenhouse gas emissions for certain facilities. In March 2014, moreover, then President Obama released a Strategy to Reduce Methane Emissions that included consideration of both voluntary programs and targeted regulations for the oil and natural gas sector. Consistent with that strategy, the EPA issued final rules in 2016 for new and modified oil and natural gas production sources (including hydraulically fractured oil wells, natural gas well sites, natural gas processing plants, natural gas gathering and boosting stations and natural gas transmission sources) to reduce emissions of methane as well as volatile organic compound and toxic pollutants. In addition, the BLM has promulgated standards for reducing venting and flaring on public lands. The EPA and BLM actions are part of a series of steps by the Obama Administration that were 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.

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

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

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

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

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

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

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

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

In past years, legislation has been proposed that would, if enacted into law, make significant changes to U.S. tax laws, including to certain key U.S. federal income tax provisions currently available to oil and natural gas exploration, development and production companies. Such legislative changes have included, but not limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain domestic production activities, and (iv) an extension of the amortization period for certain geological and geophysical expenditures. Congress could consider, and could include, some or all of these proposals as part of tax reform legislation, to accompany lower federal income tax rates. Moreover, other more general features of tax reform legislation, including changes to cost recovery rules and to the deductibility of interest expense, may be developed that also would change the taxation of oil and natural gas companies. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could take effect. The passage of any legislation as a result of these proposals or any similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that currently are available with respect to oil and natural gas development, or increase costs, and any such changes could have an adverse effect on our financial position, results of operations and cash flows.

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

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

Crude oil from the Bakken / Three Forks formations may pose unique hazards that may have an adverse effect on our operations.

The United States Department of Transportation (“USDOT”) has concluded that crude oil from the Bakken / Three Forks formations has a higher volatility than most other crude oil from the United States and thus is more ignitable and flammable. Based on that

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information, and several fires involving rail transportation of crude oil, USDOT imposed additional requirements for shipping crude oil by rail. Beyond that, the rail industry has adopted increased precautions for crude shipments. Any restrictions that significantly affect transportation of crude oil production could materially and adversely affect our financial condition, results of operations and cash flows.

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

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

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

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

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

Use of debt financing may adversely affect our strategy.

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

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

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

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

Our ability to exercise influence over operations and costs for the properties we do not operate is limited. Our dependence on the operator and other working interest owners for these projects and our limited ability to influence operations and associated costs could prevent the realization of our targeted returns on capital with respect to 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 but not limited to:

 

 

the timing and amount of capital expenditures;

 

the operator’s expertise and financial resources;

 

the approval of other participants in drilling wells; and

 

the selection of technology.

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

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

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

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

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

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

Risks Related to the Ownership of our Common Stock

OVR holds a significant number of shares of our common stock.

OVR holds a significant number of shares of our outstanding 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 significantly influence the election of the members of our board of directors and thereby significantly influence our management and Company affairs. In addition, OVR has the ability to significantly influence 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 the Company that could deprive our stockholders of an opportunity to receive a premium for their common stock as part of a sale of the Company. The existence of a significant stockholder may adversely affect matters that could be in the best interests of minority stockholders. For example, the existence of a significant stockholder could have the effect of deterring hostile takeovers or other bona-fide purchase proposals, 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 the Company. However, approval of the

27


 

Bold Contribution Agreement requires the approval of both a majority of shareholders and a majority of minority stockholders, which excludes the shares held by OVR.

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. As of March 1, 2017, OVR controls 9,162,452 shares of our common stock, or 41.1% of the outstanding shares.

Our common stock price has been and may 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 upstream oil and natural gas 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 upstream 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 estimated reserves, including information on estimated future net cash flows and the standardized measure of discounted future net cash flows, please refer to the Supplemental Information on Oil and Gas Exploration and Production Activities (Unaudited) within Part II, Item 8 of the Notes to Consolidated Financial Statements of this report.

28


 

2016 Increases / Decreases in Proved Reserves

From January 1, 2016 to December 31, 2016, our total estimated proved reserves decreased 4% from 12,574 MBOE to 12,051 MBOE. Of that, estimated proved developed reserves increased 9% from 8,613 MBOE to 9,361 MBOE and estimated proved undeveloped reserves decreased 32% from 3,961 MBOE to 2, 690 MBOE

Proved Reserves as of December 31, 2016

The below table sets forth a summary of our estimated crude oil, natural gas and natural gas liquids reserves as of December 31, 2016 based on the annual reserve estimate prepared by CG&A. In preparing this reserve report, CG&A evaluated 100% of our properties at December 31, 2016.  Proved reserves are estimated based on the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period for the year. All prices and costs associated with operating wells were held constant in accordance with the SEC guidelines.  

 

 

 

Oil

(MBbl)

 

 

Natural Gas

(MMcf)

 

 

NGL

(MBbl)

 

 

Total

(MBOE) (1)

 

 

Present Value

Discounted at 10%

($ in thousands)

 

Proved developed

 

 

6,052

 

 

 

13,545

 

 

 

1,051

 

 

 

9,361

 

 

$

83,242

 

Proved undeveloped

 

 

1,059

 

 

 

6,856

 

 

 

488

 

 

 

2,690

 

 

 

2,641

 

Total proved

 

 

7,111

 

 

 

20,401

 

 

 

1,539

 

 

 

12,051

 

 

$

85,883

 

 

 

(1)

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

PV-10 is a non-GAAP measure that differs from a measure under accounting principles generally accepted in the United States (“GAAP”) known as “standardized measure of discounted future net cash flows” in that PV-10 is calculated without including future income taxes. Management believes that the presentation of the PV-10 value of its oil and natural gas properties is relevant and useful to investors because it presents the estimated discounted future net cash flows attributable to our estimated proved reserves independent of our income tax attributes, thereby isolating the intrinsic value of the estimated future cash flows attributable to our reserves. We believe the use of a pre-tax measure provides greater comparability of assets when evaluating companies because the timing and quantification of future income taxes is dependent on company-specific factors, many of which are difficult to 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):

 

Present value of estimated future net revenues (PV-10)

 

$

85,883

 

Future income taxes, discounted at 10%

 

 

 

Standardized measure of discounted future net revenues

 

$

85,883

 

 

Proved Undeveloped Reserves

Proved undeveloped reserves decreased 1,271 MBOE or 32%, for the year ended December 31, 2016 compared to the year ended December 31, 2015. Revisions of prior estimates reflect the reduction in commodity prices from 2015 to 2016. 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. In accordance with our 2016 year-end independent engineering reserve report, we plan to drill all of our individual PUD drilling locations within the next five years.

29


 

The following table details the changes in our estimated proved undeveloped reserves for year ended December 31, 2016 (in MBOE):

 

Proved undeveloped reserves at December 31, 2015

 

 

3,961

 

Conversions to developed

 

 

(169

)

Extensions and discoveries

 

 

293

 

Purchases

 

 

873

 

Revisions

 

 

(2,268

)

Proved undeveloped reserves at December 31, 2016

 

 

2,690

 

 

 

 

 

 

 

Conversions. In 2016, all 169 MBOE of the reserve conversions occurred in our non-operated Bakken/Three Forks program in North Dakota.

Extensions and discoveries. During 2016, we added 293 MBOE of PUDs through extensions and discoveries, primarily as a result of successful drilling in our operated Eagle Ford properties in Fayette and Gonzales Counties, Texas and our non-operated Bakken/Three Forks program in North Dakota.

Purchases. During 2016, all of our purchases of PUD reserves were as a result of our acquisition of Lynden Energy Corp, which included interests in non-operated Midland Basin properties in Glasscock, Howard, Martin and Midland Counties, Texas.

Revisions. In 2016, the downward revisions of 2,268 MBOE to PUD reserves occurred primarily as a result of decreased oil and natural gas prices, which decreased the number of economic PUD locations and the corresponding reserves.

Preparation of Reserve Estimates

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

The technical person primarily responsible for the preparation of the reserve report is Mr. W. Todd Brooker, Senior Vice President of CG&A. He graduated with honors from the University of Texas at Austin in 1989 with a Bachelor of Science degree in Petroleum engineering. Mr. Brooker is a Registered Professional Engineer in Texas and has more than 25 years of experience in the estimation and evaluation of oil and natural gas reserves. He is also a member of the Society of Petroleum Engineers.

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 annual reserve estimates. His professional qualifications meet or exceed the qualifications of reserve estimators and auditors set forth in the “Standards Pertaining to Estimation and Auditing of  Oil and Natural Gas Reserves Information” promulgated by the Society of Petroleum Engineers. His qualifications include a Bachelor of Science degree in Petroleum Engineering from the University of Wyoming in 1986; a Master of Business Administration degree from the University of Denver in 1988; member of the Society of Petroleum Engineers since 1985; and more than 30 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, at least, annually, is assessed for validity when CG&A has technical meetings with our engineers, geologists, operations and land personnel. Current revenue and expense information is obtained from our accounting records, which are subject to external quarterly reviews, annual audits and our own set of internal controls over financial reporting. Internal controls over financial reporting are assessed for effectiveness annually using criteria set forth in Internal Control – Integrated Framework, (2013 Version) issued by the Committee of Sponsoring Organizations of the Treadway Commission. All current financial data such as commodity prices, lease operating expenses, production taxes and field level commodity price differentials are updated in the reserve database and then analyzed to ensure that they have been entered accurately and that all updates are complete. Our current ownership in mineral interests and well production data are also subject to our internal controls over financial reporting, and they are incorporated in our reserve database as well and verified internally by our personnel to ensure their accuracy and completeness. Once the reserve database has been updated with current information, and the relevant technical support material has been assembled, CG&A meets with our technical personnel to review field performance and future development plans in order to further verify the validity of estimates. Following these reviews, the reserve database is furnished to CG&A so that it can prepare its independent reserve estimates and final report. The reserve estimates prepared by CG&A are reviewed and compared to our internal estimates by our Executive Vice President responsible for reservoir engineering. Material reserve estimation differences are reviewed between CG&A and us, and additional data is provided to address the differences. If the supporting documentation will not justify additional changes, the CG&A reserves are accepted. In the

30


 

event that additional data supports a reserve estimation adjustment, CG&A will analyze the additional data, and may make changes it solely deems necessary. Additional data is usually comprised of updated production information on new wells. Once the review is completed and all material differences are reconciled, the reserve report is finalized and our reserve database is updated with the final estimates provided by CG&A.

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

The net quantities of oil, natural gas and natural gas liquids produced and sold by us for the years ended December 31, 2016, 2015, and 2014, the average sales price per unit sold and the average production cost per unit are presented below.

 

 

 

Years Ended December 31,

 

 

 

2016

 

 

2015

 

 

2014

 

Sales Volumes:

 

 

 

 

 

 

 

 

 

 

 

 

Oil (MBbl)

 

 

878

 

 

 

904

 

 

 

403

 

Natural gas (MMcf)

 

 

2,171

 

 

 

2,143

 

 

 

2,132

 

Natural gas liquids (MBbl)

 

 

225

 

 

 

176

 

 

 

124

 

Barrels of oil equivalent (MBOE)*

 

 

1,465

 

 

 

1,437

 

 

 

882

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average prices realized:**

 

 

 

 

 

 

 

 

 

 

 

 

Oil (per Bbl)

 

$

39.13

 

 

$

44.09

 

 

$

86.29

 

Natural gas (per Mcf)

 

$

2.32

 

 

$

2.55

 

 

$

4.39

 

Natural gas liquids (per Bbl)

 

$

12.74

 

 

$

12.29

 

 

$

28.29

 

Barrels of oil equivalent (per BOE)

 

$

28.86

 

 

$

33.04

 

 

$

53.99

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Production cost per BOE***

 

$

10.06

 

 

$

10.72

 

 

$

11.39

 

 

 

*

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

 

**

Amounts exclude the impact of cash paid/received on settled derivative contracts as we did not elect to apply hedge accounting. Our derivatives for 2016, 2015 and 2014 have been marked-to-market in our Consolidated Statements of Operations as other income/expense; which means that all our realized gains/losses on these derivatives are reported in other income/expense.

 

***

Transportation costs remain included in these amounts, but exclude ad valorem taxes, which are included in lease operating expenses in our Consolidated Statements of Operations. Ad valorem taxes were $0.5 million, $0.3 million and $0.5 million in 2016, 2015 and 2014, respectively.

As of December 31, 2016, five fields accounted for approximately 90% of our total estimated proved reserves. Spraberry Trend field, which was acquired in May 2016 as part of our Lynden acquisition, accounted for 26% of our total estimated proved reserves. The Banks field, which was acquired as part of our transaction with OVR in December 2014, was 13% of our total estimated proved reserves. Southern Bay Eagle Ford and Eagleville fields accounted for 19% and 13%, respectively, of our total estimated proved reserves, and the Hawkville field accounted for 19% of our total estimated proved reserves. No other single field accounted for 15% or more of our total estimated proved reserves as of December 31, 2016, 2015 or 2014. The net quantities of oil, natural gas and natural gas liquids produced and sold by us from these significant fields for each of the years ended December 31, 2016, 2015 and 2014, the average sales price per unit sold and the average production cost per unit are presented below.

31


 

Southern Bay Eagle Ford Field (Fayette County, Texas)

 

 

 

Years Ended December 31,

 

 

 

2016

 

 

2015

 

 

2014

 

Sales Volumes:

 

 

 

 

 

 

 

 

 

 

 

 

Oil (MBbl)

 

 

254

 

 

 

653

 

 

 

210

 

Natural gas (MMcf)

 

 

120

 

 

 

229

 

 

 

85

 

Natural gas liquids (MBbl)

 

 

36

 

 

 

68

 

 

 

23

 

Barrels of oil equivalent (MBOE)*

 

 

310

 

 

 

759

 

 

 

247

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average prices realized:**

 

 

 

 

 

 

 

 

 

 

 

 

Oil (per Bbl)

 

$

38.95

 

 

$

45.68

 

 

$

87.75

 

Natural gas (per Mcf)

 

$

2.33

 

 

$

2.58

 

 

$

4.25

 

Natural gas liquids (per Bbl)

 

$

13.58

 

 

$

13.01

 

 

$

28.98

 

Barrels of oil equivalent (per BOE)

 

$

34.38

 

 

$

41.25

 

 

$

78.80

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Production cost per BOE***

 

$

8.32

 

 

$

6.89

 

 

$

6.96

 

 

 

*

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

 

**

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

 

***

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

Eagleville Field (Eagle Ford – Karnes County, Texas)

 

 

 

Years Ended December 31,

 

 

 

2016

 

 

2015

 

 

2014

 

Sales Volumes:

 

 

 

 

 

 

 

 

 

 

 

 

Oil (MBbl)

 

 

216

 

 

 

175

 

 

 

70

 

Natural gas (MMcf)

 

 

60

 

 

 

49

 

 

 

25

 

Natural gas liquids (MBbl)

 

 

16

 

 

 

15

 

 

 

7

 

Barrels of oil equivalent (MBOE)*

 

 

242

 

 

 

198

 

 

 

81

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average prices realized:**

 

 

 

 

 

 

 

 

 

 

 

 

Oil (per Bbl)

 

$

40.54

 

 

$

44.75

 

 

$

84.58

 

Natural gas (per Mcf)

 

$

2.37

 

 

$

2.58

 

 

$

4.36

 

Natural gas liquids (per Bbl)

 

$

13.07

 

 

$

13.14

 

 

$

30.24

 

Barrels of oil equivalent (per BOE)

 

$

37.59

 

 

$

41.13

 

 

$

77.57

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Production cost per BOE***

 

$

5.25

 

 

$

5.96

 

 

$

9.16

 

 

 

*

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

 

**

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

 

***

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

32


 

Banks Field (Bakken – McKenzie County, North Dakota)

No results have been included for 2014 as the field was acquired as part of a December 2014 Exchange.

 

 

 

Years Ended December 31,

 

 

 

2016

 

 

2015

 

Sales Volumes:

 

 

 

 

 

 

 

 

Oil (MBbl)

 

 

109

 

 

 

126

 

Natural gas (MMcf)

 

 

194

 

 

 

230

 

Natural gas liquids (MBbl)

 

 

27

 

 

 

32

 

Barrels of oil equivalent (MBOE)*

 

 

168

 

 

 

196

 

 

 

 

 

 

 

 

 

 

Average prices realized:**

 

 

 

 

 

 

 

 

Oil (per Bbl)

 

$

30.60

 

 

$

40.29

 

Natural gas (per Mcf)

 

$

2.19

 

 

$

2.69

 

Natural gas liquids (per Bbl)

 

$

5.47

 

 

$

7.98

 

Barrels of oil equivalent (per BOE)

 

$

23.19

 

 

$

30.28

 

 

 

 

 

 

 

 

 

 

Production cost per BOE***

 

$

6.54

 

 

$

8.31

 

 

 

*

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

 

**

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

 

***

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

Hawkville Field (Eagle Ford – La Salle County)

 

 

 

Years Ended December 31,

 

 

 

2016

 

 

2015

 

 

2014

 

Sales Volumes:

 

 

 

 

 

 

 

 

 

 

 

 

Oil (MBbl)

 

 

13

 

 

 

18

 

 

 

34

 

Natural gas (MMcf)

 

 

736

 

 

 

943

 

 

 

947

 

Natural gas liquids (MBbl)

 

 

57

 

 

 

76

 

 

 

85

 

Barrels of oil equivalent (MBOE)*

 

 

193

 

 

 

251

 

 

 

280

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average prices realized:**

 

 

 

 

 

 

 

 

 

 

 

 

Oil (per Bbl)

 

$

27.26

 

 

$

31.69

 

 

$

82.34

 

Natural gas (per Mcf)

 

$

2.40

 

 

$

2.61

 

 

$

4.45

 

Natural gas liquids (per Bbl)

 

$

12.26

 

 

$

13.46

 

 

$

27.72

 

Barrels of oil equivalent (per BOE)

 

$

14.61

 

 

$

16.18

 

 

$

33.62

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Production cost per BOE***

 

$

8.53

 

 

$

11.66

 

 

$

11.08

 

 

 

*

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

 

**

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

 

***

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

 

33


 

Spraberry Trend (Midland Basin Properties)

No results for 2015 or 2014 have been included as the field was acquired as part of the Lynden Arrangement in 2016.

 

 

 

Year Ended December 31,

 

 

 

2016

 

Sales Volumes:

 

 

 

 

Oil (MBbl)

 

 

139

 

Natural gas (MMcf)

 

 

352

 

Natural gas liquids (MBbl)

 

 

68

 

Barrels of oil equivalent (MBOE)*

 

 

266

 

 

 

 

 

 

Average prices realized:**

 

 

 

 

Oil (per Bbl)

 

$

45.07

 

Natural gas (per Mcf)

 

$

2.43

 

Natural gas liquids (per Bbl)

 

$

15.73

 

Barrels of oil equivalent (per BOE)

 

$

30.83

 

 

 

 

 

 

Production cost per BOE***

 

$

9.92

 

 

 

*

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

 

**

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

 

***

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

 

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

The purchasers of our oil, natural gas and natural gas liquids production consist primarily of independent marketers, major oil and natural gas companies and pipeline companies. In 2016, two purchasers accounted for 41% and 19%, respectively, of our oil, natural gas and natural gas liquids revenues. In 2015 and 2014, one purchaser, accounted for 62% and 60%, respectively, of our oil, natural gas and natural gas liquids revenues. These purchasers are expected to be a significant purchasers in the future as well. No other purchaser accounted for 10% or more of our oil, natural gas and natural gas liquids revenues during 2016, 2015 and 2014.

We hold working interests in oil and natural gas properties for which third parties serve as operator. The operator sells the oil, natural gas and natural gas liquids to the purchaser, and collects and distributes the revenue to us. In 2016 and 2015, one operator accounted for 19% and 12%, respectively of our total oil, natural gas and natural gas liquids revenues.  In 2014, a different operator accounted for 20% of our total oil, natural gas and natural gas liquids revenues. No other operator accounted for 10% or more of our oil, natural gas and natural gas liquids revenues during the years ended December 31, 2016, 2015 and 2014.

Gross and Net Productive Wells

As of December 31, 2016, our total gross and net productive wells were as follows:

 

Oil (1)

 

 

Natural Gas (1)

 

 

Total (1)

 

Gross Wells

 

 

Net Wells

 

 

Gross Wells

 

 

Net Wells

 

 

Gross Wells

 

 

Net Wells

 

 

462

 

 

 

135

 

 

 

164

 

 

 

50

 

 

 

626

 

 

 

185

 

 

 

(1)

A gross well is a well in which a working interest is owned. The number of net wells represents the sum of fractions of working interests we own in gross wells. Productive wells are producing wells plus shut-in wells we deem capable of production. Horizontal re-entries of existing wells do not increase a well total above one gross well.

Gross and Net Developed and Undeveloped Acres

As of December 31, 2016, 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.

34


 

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.

 

 

 

Developed

 

 

Undeveloped

 

 

Total

 

State

 

Gross

 

 

Net

 

 

Gross

 

 

Net

 

 

Gross

 

 

Net

 

Texas

 

 

75,400

 

 

 

27,700

 

 

 

135,900

 

 

 

67,000

 

 

 

211,300

 

 

 

94,700

 

Oklahoma

 

 

16,200

 

 

 

13,900

 

 

 

 

 

 

 

 

 

16,200

 

 

 

13,900

 

Montana

 

 

6,200

 

 

 

2,200

 

 

 

4,700

 

 

 

1,100

 

 

 

10,900

 

 

 

3,300

 

North Dakota

 

 

21,600

 

 

 

2,500

 

 

 

6,800

 

 

 

3,400

 

 

 

28,400

 

 

 

5,900

 

Wyoming

 

 

600

 

 

 

300

 

 

 

1,400

 

 

 

600

 

 

 

2,000

 

 

 

900

 

Nebraska

 

 

 

 

 

 

 

 

18,400

 

 

 

8,300

 

 

 

18,400

 

 

 

8,300

 

All Others

 

 

3,500

 

 

 

2,500

 

 

 

16,300

 

 

 

600

 

 

 

19,800

 

 

 

3,100

 

Total

 

 

123,500

 

 

 

49,100

 

 

 

183,500

 

 

 

81,000

 

 

 

307,000

 

 

 

130,100

 

 

Out of a total of 183,500 gross (81,000 net) undeveloped acres as of December 31, 2016, the portion of our net undeveloped acreage that is subject to expiration over the next three years, if not successfully developed or renewed, is approximately 77% in 2017, 19% in 2018 and 4% in 2019 and beyond. The portion of our net undeveloped acres related to the Eagle Ford acreage that is subject to expiration over the next three years, if not successfully developed or renewed, is approximately 7% in 2017, 9% in 2018 and 4% in 2019 and beyond. We anticipate that within our Eagle Ford acreage, our current and future drilling plans, along with the selected lease extensions, will address the majority of the leases expiring in 2017 and beyond.

Exploratory Wells and Development Wells

Set forth below for the three years ended December 31, 2016 is information concerning the number of wells we drilled during the years indicated.

 

 

 

Net Exploratory Wells

Drilled

 

 

Net Development Wells

Drilled

 

 

Total Net

Productive and

Dry Wells

 

Year

 

Productive

 

 

Dry

 

 

Productive

 

 

Dry

 

 

Drilled

 

2016

 

 

 

 

 

 

 

 

7.7

 

 

 

 

 

 

7.7

 

2015

 

 

 

 

 

 

 

 

7.2

 

 

 

 

 

 

7.2

 

2014

 

 

 

 

 

 

 

 

7.3

 

 

 

 

 

 

7.3

 

 

Present Activities

As of March 1, 2017, we have 16 gross (2.1 net) non-operated wells in the process of drilling or completing.

Item 3.  Legal Proceedings

In the ordinary course of business, we may be involved in litigation and claims arising out of our operations. As of December 31, 2016, and through the filing date of this report, we do not believe the ultimate resolution of any such actions or potential actions of which we are currently aware will have a material effect on our consolidated financial position or results of operations.

A description of our legal proceedings is included in Note. 14. Commitments and Contingencies included in Item 8 of this report.

Item 4.  Mine Safety Disclosures

Not applicable.

 

 

35


 

Executive Officers of the Company

The following table sets forth, as of March 1, 2017, certain information regarding the executive officers of Earthstone:

 

 

Name

 

Age

 

Position

Frank A Lodzinski

 

67