Breitling Energy 10KT 2013 Annual report (with FYE transition)

Breitling Energy (BECC) Inactive 10-KT2013 FY Annual report (with FYE transition)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

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

For the fiscal year ended

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

For the transition period from March 31, 2013 to December 31, 2013

Commission file number: 000-50541

BREITLING ENERGY CORPORATION

(Exact name of registrant as specified in its charter)

Nevada

88-0507007

State or other jurisdiction of

incorporation or organization

I.R.S. Employer

Identification No.

1910 Pacific Ave, Suite 12000, Dallas, Texas 75201

(Address of principal executive offices) (Zip Code)

Registrant’s telephone number, including area code: (214) 716-2600

Securities registered pursuant to Section 12(b) of this Act: None

Securities registered pursuant to Section 12(g) of the Act: Common Stock, $.001 par value per share

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

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ Nox

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (ss. 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (ss. 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 definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check One).

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

The aggregate market value of the voting common stock held by non-affiliates of the registrant at June 30, 2013 was $2,828,454.

Number of shares of the registrant’s common stock outstanding at March 15, 2014 was 498,883,626.

DOCUMENTS INCORPORATED BY REFERENCE:

Portions of the registrant’s definitive proxy statement for the 2014 annual meeting of stockholders, which will be filed within 120 days after December 31, 2013, are incorporated by reference in Part III of this Form 10-K.

TABLE OF CONTENTS


		Page
PART I

ITEM 1	Business		10
ITEM 1A	Risk Factors		15
ITEM 1B	Unresolved Staff Comments		28
ITEM 2	Properties		28
ITEM 3	Legal Proceedings		33
ITEM 4	Mine Safety Disclosures		33
PART II

ITEM 5	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		34
ITEM 6	Selected Financial Data		34
ITEM 7	Management’s Discussion and Analysis of Financial Condition and Results of Operations		34
ITEM 7A	Quantitative and Qualitative Disclosures About Market Risk		41
ITEM 8	Financial Statements and Supplementary Data		F-1
ITEM 9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		41
ITEM 9A	Controls and Procedures		41
ITEM 9B	Other Information		42
PART III (incorporated by reference to be filed with the Company’s Definitive Proxy Statement)
ITEM 10	Directors, Executive Officers, and Corporate Governance		43
ITEM 11	Executive Compensation		43
ITEM 12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		43
ITEM 13	Certain Relationships and Related Transactions, and Director Independence		43
ITEM 14	Principal Accounting Fees and Services		43
PART IV
ITEM 15	Exhibits and Financial Statement Schedules		43
SIGNATURES			45

Cautionary Notice Regarding Forward-Looking Statements

The information in this report includes “forward-looking statements” within the meaning of the Securities Act of 1933, as amended (the “Securities Act”), and the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical fact included in this report, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this report, the words “could”, “should”, “will”, “play”, “believe”, “anticipate”, “intend”, “estimate”, “expect”, “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on our current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under the heading “Risk Factors” included in this report. These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events.

Forward-looking statements may include statements about:

•

business strategy;

•

reserve quantities and the present value of our reserves;

•

financial strategy, liquidity and capital required for our development program;

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future oil and natural gas prices;

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timing and amount of future production of oil and natural gas;

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hedging strategy and results, if applicable;

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future drilling plans;

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marketing of oil and natural gas;

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leasehold or business acquisitions;

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costs of developing our properties;

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liquidity and access to capital;

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future operating results; and

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plans, objectives, expectations and intentions contained in this report that are not historical.

We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the exploration for and development and production of oil and natural gas. These risks include, but are not limited to, commodity price volatility, low prices for oil and/or natural gas, global economic conditions, inflation, increased operating costs, lack of availability of drilling and production equipment and services, environmental risks, weather risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating oil and natural gas reserves and in projecting future rates of production, reductions in cash flow, access to capital, and the other risks described under “Item 1A. Risk Factors” in this report.

Reserve engineering is a process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reservoir engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of oil and natural gas that are ultimately recovered.

Should one or more of the risks or uncertainties described in this report occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.

All forward-looking statements, expressed or implied, included in this report are expressly qualified in their entirety by these cautionary statements. These cautionary statements should also be considered in connection with any subsequent written or oral forward-looking statements that we may issue.

Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this report.

CERTAIN DEFINITIONS

Unless the context otherwise requires, the terms “we,” “us,” “our,” “ours,” the “Company” or “Breitling” when used in this report refer to Breitling Energy Corporation, together with our consolidated operating subsidiaries. When the context requires, we refer to these entities separately.

We have included below the definitions for certain terms used in 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.

AFE –Authority for expenditure.

After payout – With respect to an oil or natural gas interest in a property, refers to the time period after which the costs to drill and equip a well have been recovered.

AMI–Area of mutual interest.

Bbl – One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to crude oil or other liquid hydrocarbons.

Bbls/d orBOPD – Barrels per day.

Bcf – Billion cubic feet.

Bcfe – Billion cubic feet equivalent, determined using the ratio of six thousand cubic feet (Mcf) of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

Before payout– With respect to an oil and natural gas interest in a property, refers to the time period before which the costs to drill and equip a well have been recovered.

Behind-pipe reserves – Those reserves expected to be recovered from completion interval(s) not yet open but still behind casing in existing wells.

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

Carried interest – A contractual arrangement whereby all or a portion of the working interest cost participation of the project originator is paid for by another party in exchange for earning an interest in such project.

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.

Compression – A force that tends to shorten or squeeze, decreasing volume or increasing pressure.

DD&A– Depreciation, depletion and amortization.

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 installation of facilities and the drilling and completion of wells for production purposes.

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.

EUR– Expected ultimate recovery from a well, reservoir or field.

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

Exploratory well – A well drilled to find and produce oil or natural gas reserves not classified as proved to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir or to extend a known reservoir.

Farm-in orFarmout – An agreement where the owner of a working interest in an oil and natural gas lease assigns the working interest or a portion thereof to another party who desires to drill on the leased acreage. Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage. The assignor usually retains a royalty and/or reversionary interest in the lease. The interest received by the assignee is a “farm-in” while the interest transferred by the assignor is a “farmout.”

FASB – The Financial Accounting Standards Board.

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.

GAAP – Generally accepted accounting principles in the United States of America.

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

Horizontal drilling – A drilling technique that permits the operator to contact and intersect a larger portion of the producing horizon than conventional vertical drilling techniques that may, depending on horizon, result in increased production rates and greater ultimate recoveries of hydrocarbons.

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

Mineral rights – Ownership of minerals under a defined surface along with the legal right of access so the minerals can be extracted. Mineral rights can be separated and transferred from land ownership. Also called subsurface rights.

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.

Mbtu (Mmbtu) – Used as a standard unit of measurement for natural gas and provides a convenient basis for comparing the energy content of various grades of natural gas and other fuels. One cubic foot of natural gas produces approximately 1,000 BTUs, so 1,000 cubic feet of gas is comparable to 1 MBTU. MBTU is often expressed as MMBTU, which is intended to represent a thousand BTUs.

Mcf – One thousand cubic feet.

Mcf/d – One thousand cubic feet per day.

Mcfe – One thousand cubic feet equivalent determined by using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids, which approximates the relative energy content of crude oil, condensate and natural gas liquids as compared to natural gas. Prices have historically been higher or substantially higher for crude oil than natural gas on an energy equivalent basis although there have been periods in which they have been lower or substantially lower.

MMcf – One million cubic feet.

MMcf/d – One million cubic feet per day.

MMcfe – One million cubic feet equivalent.

Net acres or net wells – The product of the fractional working interests owned by gross acres or gross wells.

NGL’s – Natural gas liquids measured in barrels.

NRI orNet Revenue Interests – The share of production after satisfaction of all royalty, oil payments and other non-operating interests.

Normally pressured reservoirs – Reservoirs with a formation-fluid pressure equivalent to 0.465 per square inch per foot of depth from the surface. For example, if the formation pressure is 4,650 per square inch at a depth of 10,000 feet, the pressure is considered to be normal.

Over-riding royalty interest – A royalty interest derived from the working interest, in excess of the royalty provided in the oil and gas lease.

Over-pressured reservoirs – Reservoirs with a formation fluid pressure greater than 0.465 per square inch per foot of depth from the surface.

Plant products – Liquids generated by a plant facility; including propane, iso-butane, normal butane, pentane and ethane.

Plugging and abandonment orP&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 or to the surface. Regulations of many states require plugging of abandoned wells.

PV-10 – The present value of estimated future revenues to be generated from the production of proved reserves calculated in accordance with SEC guidelines, net of estimated lease operating expense, production taxes and future development costs, using prices, as prescribed in the SEC rules, and costs as of the date of estimation without future escalation, without giving effect to non-property related expenses such as general and administrative expenses, debt service, depreciation, depletion and amortization, or Federal income taxes and discounted using and annual discount rate of 10%. PV-10 is considered a non-GAAP financial measure as defined by the SEC.

Possible reserves – Additional reserves that are less certain to be recovered than probable reserves. When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates. Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project. Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves. Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the Company believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir. Where direct observation has defined a highest known oil (“HKO”) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

Primary recovery – The first stage of hydrocarbon production in which natural reservoir drives are used to recover hydrocarbons, although some form of artificial lift may be required to exploit declining reservoir drives.

Probable reserves –Additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates. Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir. Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

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 exceed production expenses and taxes.

Proved developed nonproducing reserves orPDNP – Proved developed nonproducing reserves are proved reserves that are either shut-in or are behind-pipe reserves.

Proved developed producing reservesor PDP – Proved developed reserves that are expected to be recovered from completion intervals currently open in existing wells and able to produce to market.

Proved developed reserves – Proved reserves that are expected to be recovered from existing wells with existing equipment and operating methods.

Proved oil and gas reserves – Proved oil and gas reserves are those quantities of oil and 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. (i) The area of the reservoir considered as proved includes: (A) the area identified by drilling and limited by fluid contacts, if any, and (B) 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. (ii) 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. (iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. (iv) 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: (A) 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 (B) the project has been approved for development by all necessary parties and entities, including governmental entities. (v) 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 location – A site on which a development well can be drilled consistent with spacing rules for purposes of recovering proved undeveloped reserves.

Proved undeveloped reserves orPUD – 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.

Recompletion – The completion for production of an existing wellbore 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.

Reprocessing – Taking older seismic data and performing new mathematical techniques to refine subsurface images or to provide additional ways of interpreting the subsurface environment.

Reservoir – A porous and 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 – The portion of oil, gas, and minerals retained by the lessor on execution of a lease or their cash value paid by the lessee to the lessor or to one who has acquired possession of the royalty rights, based on a percentage of the gross production from the property free and clear of all costs except taxes.

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.

Secondary recovery – The use of water-flooding or gas injection to maintain formation pressure during primary production and to reduce the rate of decline of the original reservoir drive.

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.

Standardized Measure of Discounted Future Net Cash Flows – Present value of proved reserves, as adjusted to give effect to estimated future abandonment costs, net of estimated salvage value of related equipment, and estimated future income taxes.

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 orWI – The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and share of production, subject to all royalties, overriding royalties and other burdens and to share in all costs of exploration, development operations and all risks in connection therewith.

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

PART I

ITEM 1 – BUSINESS

Overview of Our Business

History

Breitling Energy Corporation (formerly, Bering Exploration Inc., formerly, Oncolin Therapeutics, Inc., formerly, Edgeline Holdings, Inc., formerly, Dragon Gold Resources, Inc., formerly Folix Technologies, Inc.) (“we”, “our” or the “Company”) was incorporated in the State of Nevada on December 13, 2000 under the name “Folix Technologies, Inc.” On August 18, 2004, the Company changed its name to Dragon Gold Resources, Inc. On June 22, 2007, the Company changed its name to Edgeline Holdings, Inc. and on March 11, 2008 to Oncolin Therapeutics, Inc. On September 7, 2010, the Company changed its name to Bering Exploration, Inc. and on January 20, 2014 to Breitling Energy Corporation.

On February 12, 2012, the Board of Directors of the Company (the “Board of Directors”) approved a 1-for-10 reverse stock split, which became effective on February 27, 2012. The Company has retroactively applied this reverse stock split to its financial reporting for the years ended March 31, 2012 and 2011. On December 23, 2013, the stockholders of the Company voted to approve a resolution authorizing the Board of Directors to effect a reverse stock split of the Company’s common stock at a ratio of not less than 1-for-2 and not greater than 1-for-100, with the exact ratio to be set within such a range at the discretion of the Board of Directors. The Board of Directors has not yet effected this reverse stock split.

On December 9, 2013, we completed an Asset Purchase Agreement (the “Purchase Agreement”) with Breitling Oil and Gas Corporation, a Texas corporation (“O&G”) and Breitling Royalties Corporation, a Texas corporation (“Royalties,” and collectively with O&G, the “Predecessors”). Pursuant to the Purchase Agreement, the Company issued to the Predecessors 461,863,084 shares of common stock, in exchange for substantially all of the oil and gas assets owned by the Predecessors (the “Transaction”). In connection with the closing of the Transaction (the “Closing”), all of the Company’s outstanding convertible notes were converted into common stock. The shares of common stock issued to the Predecessors represent approximately 92.5% of the shares of common stock outstanding following the Closing. The Closing did not affect the number of shares of common stock held by our existing public stockholders. O&G was founded in October 2004 in Dallas, Texas.

Business Strategy

We are an oil and gas exploration and production company that acquires and develops lower risk onshore oil and gas working interests and royalty interests in proven basins in the United States, such as the Permian Basin in Texas, the Bakken / Three Forks formations located in North Dakota and the Mississippi Lime and Hunton / Woodford / Cleveland formations located in Oklahoma. We operate wells in the Permian Basin in Texas and Mississippi Lime in Kansas and plan to expand our operations in the Permian Basin. As of December 31, 2013, the vast majority of our oil and gas interests were acquired as royalty interests or non-operated working interests. Our asset base is primarily comprised of rights to the revenue interests. We are developing infrastructure and expertise to acquire and develop our own properties after December 31, 2013.

Exploration and Production Activities

Our exploration activities are focused on adding profit generating production to existing core areas and increasing our current operated and non-operation positions.

Our primary goal is to increase stockholder value by increasing the value of acquired properties through a combination of exploitation, drilling and proven engineering extraction practices.

As part of our corporate strategy, we believe in the following fundamental principles:

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Expand our direct operations through the acquisition of operated working interests.

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Maximize the value of our properties by increasing production and reserves while controlling cost.

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Maintain a highly competitive team of experienced and incentivized personnel.

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Acquire properties where we believe additional value can be created through secondary and tertiary recovery operations and a combination of other exploitation, development, exploration and marketing techniques.

Our goal is to build long-term stockholder value by growing reserves and production revenues in a cost-efficient manner. To accomplish our goal, we plan to carry out a balanced program of (1) developing our properties and expanding into other areas, (2) operating as a low-cost producer, (3) pursuing strategic, complementary acquisitions and (4) maintaining financial flexibility. The following are key elements of our strategy:

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Develop our properties. Operations and investment opportunities are focused on exploratory and developmental drilling onshore in the U.S. in major plays such as the Permian Basin, Eagle Ford, Marcellus, Utica, Granite Wash, Cleveland, Hunton, Mississippi Lime, Bakken, Lower Hope Lime and Three Forks unconventional liquids plays.

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Operate our properties as a low-cost producer. We strive to minimize our operating costs by concentrating our assets within geographic areas where we can consolidate operating control and, thus, create operating efficiencies. We continue to develop our operations in Texas, Oklahoma and Kansas.

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Acquire strategic, complementary assets. We target the acquisition of assets in oil and gas fields which display long-lived, high-quality production, heavily weighted in oil and/or liquids rich natural gas production. We evaluate acquisitions based on decline profiles, reserve life and seek to take advantage of any operational in-efficiencies of the target operator. We predominantly value the target’s discounted cash flows from its proved developed producing category.

Oil and Gas Leases and Wells

As of December 31, 2013, our approximately 1,426 oil and gas properties located in seven states and 84 counties consist of approximately 6,000 oil and gas wells, 999 proved locations, 291 probable locations and 136 possible locations, which are primarily held by production. Our asset base is primarily comprised of rights to receive revenue interest.

Operated Acreage

On February 19, 2014, the Company entered into an agreement (the “Farmout Agreement”) with Steller Energy and Investment Corporation (“Steller”). Steller had previously entered into an agreement with Clayton Williams Energy, Inc. for the exploration and development of approximately 3,680 acres located in Sterling County, Texas and the Farmout Agreement provides for the Company to perform the obligations of Steller under that existing agreement. Under the Farmout Agreement, the Company will earn a 100% working interest in each well that the Company drills, along with surrounding acreage. If the Company elects to drill at least eight wells, the Company will retain the interest in the entire acreage. The acreage is located in northwestern Sterling County in an area with multiple pay zones. Wells drilled on or adjacent to this block have produced from the Lower Wolfcamp Lime, the Canyon Sand, the Mississippian Chert and Lime, the Fusselman Lime, the Montoya Lime, and the Ellenburger Dolomite. Using improved exploration and exploitation methods, the farmout offers the opportunity to develop significant oil and gas reserves with low to moderate risk.

Acquisitions of Carried Interests

The Predecessors acquired their oil and gas assets in connection with their business model that differs substantially from that of the Company or an ordinary oil and exploration and production company. The Predecessors acquired either working interests in oil and gas properties or royalty interests in oil and gas properties. Following these acquisitions, the Predecessors offered interests in those properties to accredited investors through a series of private placements. The interests offered in those properties were subject to certain carried interests, and those carried interests constitute the bulk of the oil and gas assets acquired from the Predecessors.

The Predecessors have also entered into turnkey drilling contracts with outside working interest owners to develop leasehold acreage acquired. In these arrangements, the Predecessors acquired a working interest in a prospect pursuant to an oil and gas lease, and then sold a portion of a well’s working interest on the acquired lease to third parties with a turnkey drilling agreement. In each case, the working interest holders are obligated to bear the cost of drilling, testing, completing, equipping and operating the well. The Predecessors typically sold a substantial portion of the working interests, had a third-party operate the projects and were granted a carried interest.

In a turnkey drilling agreement, the Predecessors agreed to pay for all costs of identifying, acquiring mineral rights to, drilling, testing, completing and equipping the well for initial production at a fixed price. If the actual costs of these activities exceed the turnkey price, the Predecessors were obligated to pay the excess cost. If the actual costs were less than the turnkey price, the Predecessors were entitled to retain the excess of the turnkey price over actual costs. Following completion of each producing well, the Predecessors and the third-party working interest owners would bear the cost of operating the well according to each party’s proportionate working interest percentage.

We intend to continue the acquisition of working interests and royalty interests in oil and gas properties through our subsidiaries and special purpose entities and retain carried interests relating to such properties. The Company through its subsidiaries and special purpose entities plans to develop and operate private placement funds to various institutions (the “Funds”) pursuant to which investors (who are not the same as the stockholders of the Company) will be offered the opportunity to invest in certain oil and gas interests or royalties interests sourced by the Company. These Funds will generate management fees and other fees payable to subsidiaries of the Company as well as generate the retained carried interests.

Acquisition of Other Assets and Leveraging of Assets Acquired

The Company intends to acquire additional assets of a similar type and nature as the assets it currently has including new and existing hydrocarbon wells and oil and gas leases. In the event the Company is unable to acquire the additional assets it plans to acquire it will take the Company significantly longer to implement profitable revenue producing activities. If the Company should successfully acquire additional assets, the assets may or may not be in the same geographical location as the assets we currently own as the Company reserves the right to acquire assets or operate in any geographic locations management believes, in their sole judgment, to be in the best interest of the Company.

Once the Company acquires the oil and gas assets, the Company may leverage those assets by borrowing from a financial source and using the assets as collateral. While this strategy will increase the available funds for Company use, it will require the Company to pay debt service from its cash flow.

There can be no assurance that the Company will be able to achieve its objectives as its plans are dependent upon a number of factors, including but not limited to, the availability of debt and equity capital, the performance of the economy, the availability of adequate raw materials, skilled employees and managers and the activities of our competition.

Development and Exploration Activities

Economic factors prevailing in the oil and gas industry change from time to time. The uncertain nature and trend of economic conditions and energy policy in the oil and gas business generally make flexibility of operating policies important in achieving desired profitability. We intend to evaluate continuously all conditions affecting our potential activities and to react to those conditions, as we deem appropriate from time to time by engaging in businesses we believe will be the most profitable for us. With the continued increase in oil and gas prices and the disparity of US natural gas prices compared to other places in the world, we believe there will be continued growth for the foreseeable future.

Governmental Regulations

Both state and federal authorities regulate the extraction, production, transportation and sale of oil, gas, and minerals. The executive and legislative branches of government at both the state and federal levels have periodically proposed and considered proposals for establishment of controls on alternative fuels, energy conservation, environmental protection, taxation of crude oil imports, limitation of crude oil imports, as well as various other related programs. If any proposals relating to the above subjects were to be enacted, we cannot predict what effect, if any, implementation of such proposals would have upon our operations. A listing of the more significant current state and federal statutory authority for regulation of our current operations and business are provided below.

Federal Regulatory Controls

Recently a new wave of legislation and regulation at the federal level has been initiated. Our operations are subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Without limiting the generality of the foregoing, these laws and regulations may:

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require the acquisition of a permit before drilling commences;

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restrict the types, quantities and concentration of various substances that can be released into the environment from drilling and production activities;

•

limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas;

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require remedial measures to mitigate pollution from former operations, such as plugging abandoned wells; and

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impose substantial liabilities for pollution resulting from our operations.

Our operations use hydraulic fracturing to drill new oil and gas wells. Hydraulic fracturing is a process that is used to release hydrocarbons from certain geological formations. The process involves the injection of water (typically mixed with significant quantities of sand and small quantities of chemical additives) under pressure into the formation to fracture the surrounding rock and stimulate movement of hydrocarbons through the formation. The process is typically regulated by state oil and gas commissions and has been exempt (except when the fracturing fluids or propping agents contain diesel fuels) since 2005 from United States federal regulation pursuant to the Safe Drinking Water Act.

Legislation has been introduced before Congress to provide for federal regulation of hydraulic fracturing, including, for example, requiring disclosure of chemicals used in the fracturing process or seeking to repeal the exemption from the Safe Drinking Water Act. If adopted, such legislation would add an additional level of regulation and necessary permitting at the federal level and could make it more difficult to complete wells using hydraulic fracturing. Similar laws and regulations with respect to chemical disclosure also exist or are being considered by the United States Department of Interior and in several states that could restrict hydraulic fracturing.

Future United States federal, state or local laws or regulations could significantly restrict, or increase costs associated with hydraulic fracturing and make it more difficult or costly for producers to conduct hydraulic fracturing operations, which could result in a decline of our exploration and production. New laws and regulations, and new enforcement policies by regulatory agencies, could also expressly restrict the quantities, sources and methods of water use and disposal in hydraulic fracturing and otherwise increase our costs and our customers’ cost of compliance, which could minimize water use and disposal needs even if other limits on drilling and completing new wells were not imposed. Any decline in exploration and production or any restrictions on water use and disposal could result in a decline in our drilling and rework activity and have a material adverse effect on our business, financial condition, results of operations and cash flows.

State Regulatory Controls

In each state where we conduct or contemplate oil and gas activities, these activities are subject to various regulations. The regulations relate to the extraction, production, transportation and sale of oil and natural gas, the issuance of drilling permits, the methods of developing new production, the spacing and operation of wells, the conservation of oil and natural gas reservoirs and other similar aspects of oil and gas operations. In particular, the State of Texas (where we plan to conduct a large part of our oil and gas operations to date) regulates the rate of daily production allowable from both oil and gas wells on a market demand or conservation basis. At the present time, no significant portion of our production has been curtailed due to reduced allowable production. We know of no proposed regulation that will significantly impede our operations.

State Environmental Regulations

Our extraction, production and drilling operations are subject to environmental protection regulations established by federal, state, and local agencies. To the best of our knowledge, we believe that we are in compliance with the applicable environmental regulations established by the agencies with jurisdiction over our operations. We are acutely aware that the applicable environmental regulations currently in effect could have a material detrimental effect upon our earnings, capital expenditures, or prospects for profitability.

Our competitors are subject to the same regulations and therefore, the existence of such regulations does not appear to have any material effect upon our position with respect to our competitors. The Texas Legislature has mandated a regulatory program for the management of hazardous wastes generated during crude oil and natural gas exploration and production, gas processing, oil and gas waste reclamation and transportation operations. The disposal of these wastes, as governed by the Railroad Commission of Texas, is becoming an increasing burden on the industry.

As discussed above the likelihood of increased level of regulations at the federal level will also have a corresponding regulatory action at the state level.

Revenues from oil and gas production are subject to taxation by the state in which the production occurred. In Texas, the state receives a severance tax of 4.6% for oil production and 7.5% for gas production. These high percentage state taxes can have a significant impact upon the economic viability of marginal wells that we may produce and require plugging of wells sooner than would be necessary in a less arduous taxing environment.

Marketing and Transportation Regulations

Sales of natural gas are affected by the availability, terms and cost of transportation. The price and terms for access to pipeline transportation are subject to extensive federal and state regulation. From 1985 to the present, several major regulatory changes have been implemented by Congress and the Federal Energy Regulatory Commission (“FERC”) that affect the economics of natural gas production, transportation and sales. In addition, FERC is continually proposing and implementing new rules affecting segments of the natural gas industry, most notably interstate natural gas transmission companies, which remain subject to FERC’s jurisdiction. These initiatives may also affect the intrastate transportation of gas under certain circumstances. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry and these initiatives generally reflect more light-handed regulation.

Our sales of crude oil and condensate are currently not regulated and are made at market prices. In a number of instances, however, the ability to transport and sell such products are dependent on pipelines whose rates, terms and conditions of service are subject to FERC jurisdiction under the Interstate Commerce Act. However, we do not believe that these regulations affect us any differently than other crude oil producers.

Marketing

Our ability to market oil and natural gas often depends on factors beyond our control. The potential effects of governmental regulation and market factors, including alternative domestic and imported energy sources, available pipeline capacity, and general market conditions, are not entirely predictable.

Natural gas is generally sold pursuant to individually negotiated gas purchase contracts, which vary in length from spot market sales of a single day to term agreements that may extend several years. Customers who purchase natural gas include marketing affiliates of the major oil and gas companies, pipeline companies, natural gas marketing companies, and a variety of commercial and public authorities, industrial, and institutional end-users who ultimately consume the gas. Gas purchase contracts define the terms and conditions unique to each of these sales. The price received for natural gas sold on the spot market may vary daily reflecting changing market conditions. The deliverability and price of natural gas are subject to both governmental regulation and supply and demand forces.

We sell natural gas to many customers. All customers are well capitalized and regulated. We do not anticipate any customer becoming unable to perform under their agreement.

Oil produced is sold at the prevailing field price to one or more of a number of unaffiliated purchasers in the area. Generally, purchase contracts for the sale of oil are cancelable on 30 days’ notice. The price paid by these purchasers is an established market or “posted” price that is offered to all producers.

Competition

We compete with major integrated oil and natural gas companies and independent oil and natural gas companies in all areas of our operation. In particular, we compete for property acquisitions and for the equipment and labor required to operate and develop these properties. Many of our competitors have substantially greater financial and other resources than we have. Larger competitors may be able to absorb the burden of any changes in federal, state and local laws and regulations more easily than we can, which could adversely affect our competitive position. Our competitors also may be able to pay more for exploratory prospects and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than we can. Further, our competitors may have technological advantages and may be able to implement new technologies more rapidly than we can. Our ability to explore for oil andnatural gas prospects and to acquire additional properties in the future will depend on our ability to conduct operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. In addition, most of our competitors have operated for a much longer time than we have and have demonstrated the ability to operate through industry cycles.

At various times, we may experience occasional or prolonged shortages or unavailability of drilling rigs, drill pipe and other material used in oil and natural gas drilling. Such unavailability could result in increased costs, delays in timing of anticipated development or cause interests in undeveloped oil and natural gas leases to lapse.

Insurance

In accordance with customary industry practices, we maintain insurance coverage against some, but not all, potential losses in order to protect against the risks we face. We do not carry business interruption insurance. We may elect not to carry insurance if our management believes that the cost of available insurance is excessive relative to the risks presented. In addition, we cannot insure fully against pollution and environmental risks. The occurrence of an event not fully covered by insurance could have a material adverse effect on our financial condition and results of operations.

Employees

We employ ten full-time employees. The employees are assigned to the following departments: administrative, accounting, legal and operations. We retain the services of a significant number of individuals through contract services. These services provide operational and administrative support.

ITEM 1A - RISK FACTORS

Described below are certain risks that we believe are applicable to our business and the oil and gas industry in which we operate. There may be additional risks that are not presently material or known. You should carefully consider each of the following risks and all other information set forth in this annual report.

The risks and uncertainties described below are not the only ones we face. Additional risks and uncertainties, other than those we describe below, that are not presently known to us or that we currently believe are immaterial, may also impair our business operations. If any of the following risks occur, our business, financial condition and results of operations could be harmed.

We have had operating losses and limited revenues to date.

We have operated at a loss in each of the last two years. Net losses applicable to stockholders for the fiscal years ended December 31, 2012 and 2013 were $5.7 million and $2.5 million, respectively. Our revenues for the fiscal years ended December 31, 2012 and 2013 were $13.4 million and $26.6 million, respectively. We may not be able to generate significant revenues in the future. In addition, we expect to incur substantial operating expenses in connection with our natural gas and oil exploration and development activities. As a result, we may continue to experience negative cash flow for at least the foreseeable future and cannot predict if or when we might become profitable.

We do not have a long history of operations.

Until the Company establishes centralized accounting and other administrative systems, it will rely primarily on the separate systems developed by the Predecessors. The success of the Company will depend, in part, on the extent to which it is able to centralize these functions and otherwise integrate the systems developed by the Predecessor and such additional businesses as it may hereafter acquire into a cohesive, efficient enterprise. The Company’s executive officers have only limited experience working together, and no assurance can be given they will be able to manage the Company effectively or successfully execute the Company’s acquisition and operating strategies.

Our exploration appraisal and development activities are subject to many risks which may affect our ability to profitably extract oil reserves or achieve targeted returns. In addition, continued growth requires that we acquire and successfully develop additional oil reserves.

Oil and gas exploration may involve unprofitable efforts, not only from dry wells, but from wells that are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other costs. Completion of a well does not assure a profit on the investment or recovery of drilling, completion and operating costs. In addition, drilling hazards or environmental damage could greatly increase the cost of operations, and various field operating conditions may negatively affect the production from successful wells. These conditions include delays in obtaining governmental approvals or consents, shut-ins of connected wells resulting from extreme weather conditions, insufficient storage or transportation capacity or other geological and mechanical conditions. While diligent well supervision and effective maintenance operations can contribute to maximizing production rates over time, production delays and declines from normal field operating conditions cannot be eliminated and can be expected to negatively affect revenue and cash flow levels to varying degrees.

Our future success depends upon our ability to find, develop and acquire additional oil and gas reserves that are economically recoverable.

The rate of production from oil and natural gas properties declines as reserves are depleted. As a result, we must continually locate and develop or acquire new oil and gas reserves to replace those being depleted by production. We must do this even during periods of low oil and gas prices when it is difficult to raise the capital necessary to finance activities. Without successful exploration or acquisition activities, our reserves and revenues will decline. A future increase in our reserves will depend not only on our ability to explore and develop any properties we may have from time to time, but also on our ability to select and acquire suitable producing properties or prospects. We cannot guaranty that we will be able to continue to locate satisfactory properties for acquisition or participation. Moreover, if such acquisitions or participations are identified, we may determine that current markets, terms of acquisition and participation or pricing conditions make such acquisitions or participations economically disadvantageous. We cannot guaranty that commercial quantities of oil will be discovered or acquired by us.

The marketability of our production depends in part upon the availability, proximity and capacity of pipelines and other factors that are beyond our control.

Our ability to market oil and gas from our wells depends upon numerous factors beyond our control. These factors include, but are not limited to, the following:

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the level of domestic production and imports of oil and gas;

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the proximity of gas production to gas pipelines;

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the availability of pipeline capacity;

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the demand for oil and gas by utilities and other end users;

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the availability of alternate fuel sources;

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the effect of inclement weather;

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state and federal regulation of oil and gas marketing; and

•

federal regulation of gas sold or transported in interstate commerce.

If these factors were to change dramatically, our ability to market oil and gas or obtain favorable prices for our oil and gas could be adversely affected.

The marketability of our production may be dependent upon transportation facilities over which we have no control.

The marketability of our production depends in part upon the availability, proximity and capacity of pipelines, natural gas gathering systems and processing facilities. Any significant change in market factors affecting these infrastructure facilities could harm our business. We deliver oil and natural gas through gathering systems and pipelines that we do not own. These facilities may not be available to us in the future.

The nature of our business may lead to conflicts of interest.

Conflicts of interest exist and may arise in the future as a result of the relationships between the Company and its affiliates. Approximately 92.5% of our common stock is owned by the Predecessors, which in turn are owned by our President, CEO and Chairman, Parker Hallam and Michael Miller. Pursuant to an Administrative Services Agreement entered into between Crude Energy, LLC and Crude Royalties, LLC (collectively, “Crude”), the Company may, from time to time, offer working interests and royalty interests to Crude. Crude is controlled by Parker Hallam and Michael Miller.

In addition, the Company through its subsidiaries and special purpose entities plans to develop and operate private placement funds to various institutions (the “Funds”) pursuant to which investors (who are not the same as the stockholders of the Company) will be offered the opportunity to invest in certain oil and gas interests or royalty interests sourced by the Company. In addition, many of the officers of the Company serve in similar capacities with the Funds, which may lead to additional conflicts of interest. The directors and officers of the Funds have fiduciary duties to manage the Funds in a manner beneficial to its owners. At the same time, our directors and officers have a fiduciary duty to manage the Company in a manner beneficial to us and our stockholders.

Whenever a conflict arises between the Funds, the Predecessors and their affiliates, on the one hand, and the Company or its stockholders on the other hand, our board of directors will resolve that conflict. We cannot assure you that the conflicts will always be resolved in the Company’s favor.

We may be subject to liabilities arising out of the Predecessors’ business.

The Predecessors operated a business of acquiring interests in oil and gas properties, selling those interests and retaining carried interests therein. In connection with that business, the Predecessors conducted private placements of securities. Consequently, if the oil and gas interests sold by the Predecessors do not perform as expected by the investors therein, the Predecessors may be subject to future claims arising out of allegations that those securities were issued in violation of the Securities Act or State Blue Sky Laws. Any such claims, if made, could result in attorneys’ fees and other defense costs, including any settlements or judgments rendered, that may adversely affect the financial condition of the Company.

Counterparty credit risk may negatively impact the conversion of our accounts receivables to cash.

The Company is or may be exposed to third party credit risk through its contractual arrangements with its current or future marketers of its oil and natural gas production and other parties. In the event such entities fail to meet their contractual obligations to the Company, such failures could have a material adverse effect on our cash flow from operations.

Recent economic conditions in the credit markets may adversely affect our financial condition.

The disruption experienced in U.S. and global credit markets since the latter half of 2008 has resulted in instability in demand for oil and natural gas, resulting in volatile energy prices, and has affected the availability and cost of capital. In addition, capital and credit markets have experienced unprecedented volatility and disruption and continue to be unpredictable. Given the current levels of market volatility and disruption, the availability of funds from those markets has diminished substantially. Prolonged negative changes in domestic and global economic conditions or disruptions of the financial or credit markets may have a material adverse effect on our results from operations, financial condition and liquidity. At this time, it is unclear whether and to what extent the actions taken by the U.S. government will mitigate the effects of the financial market turmoil. The impact of the current difficult conditions on our ability to obtain, and the cost and terms of, any financing in the future is equally unclear. Any inability to obtain adequate financing or to fund on acceptable terms could deter or prevent us from meeting our future capital needs to finance our development program and result in a deterioration of our financial condition.

Oil and natural gas prices are volatile. A substantial decrease in oil and natural gas prices could adversely affect our financial results.

Our future financial condition, results of operations and the carrying value of our oil and natural gas properties depend primarily upon the prices we receive for our oil and natural gas production. Oil and natural gas prices historically have been volatile and likely will continue to be volatile in the future, especially given world geopolitical conditions. Our cash flow from operations is highly dependent on the prices that we receive for oil and natural gas. This price volatility also affects the amount of our cash flow available for capital expenditures and our ability to borrow money or raise additional capital. Oil prices are likely to affect us more than natural gas prices because approximately 81% of our proved reserve value, or 63% of our PV-10 based on our reserve report, is oil. The prices for oil and natural gas are subject to a variety of additional factors that are beyond our control. These factors include:

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the level of consumer demand for oil and natural gas;

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the domestic and foreign supply of oil and natural gas;

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the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;

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the price of foreign oil and natural gas;

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domestic governmental regulations and taxes;

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the price and availability of alternative fuel sources;

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weather conditions, including hurricanes and tropical storms in and around the Gulf of Mexico;

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market uncertainty;

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political conditions in oil and natural gas producing regions, including the Middle East; and

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worldwide economic conditions.

These factors and the volatility of the energy markets generally make it extremely difficult to predict future oil and natural gas price movements with any certainty. Also, oil and natural gas prices do not necessarily move in tandem. Declines in oil and natural gas prices would not only reduce revenue, but could reduce the amount of oil and natural gas that we can produce economically and, as a result, could have a material adverse effect upon our financial condition, results of operations, oil and natural gas reserves and the carrying values of our oil and natural gas properties. If the oil and natural gas industry experiences significant price declines, we may, among other things, be unable to meet our financial obligations or make planned expenditures.

Competitive industry conditions may negatively affect our ability to conduct operations.

We encounter competition from other natural gas and oil companies in all areas of our operations, including the acquisition of exploratory prospects and proved properties. There is also competition for contracting for drilling equipment and the hiring of experienced personnel. Factors that affect our ability to compete in the marketplace include:

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our access to the capital necessary to drill wells and acquire properties;

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our ability to acquire and analyze seismic, geological and other information relating to a property;

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our ability to retain and hire the personnel necessary to properly evaluate seismic and other information relating to a property;

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our ability to hire experienced personnel, especially for our accounting, financial reporting, tax and land departments;

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the location of, and our ability to access, platforms, pipelines and other facilities used to produce and transport oil and gas production; and

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the standards we establish for the minimum projected return on an investment of our capital.

Our competitors include major integrated natural gas and oil companies and substantial independent energy companies, many of which possess greater financial, technological, personnel and other resources than we do. Many of our competitors are large, well-established companies that have been engaged in the natural gas and oil business much longer than we have and possess substantially larger operating staffs and greater capital resources than we do. These companies may be able to pay more for exploratory projects and productive natural gas and oil properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may be able to expend greater resources on the existing and changing technologies that we believe are and will be increasingly important to attaining success in the industry. We may not be able to conduct our operations, evaluate and select suitable properties and consummate transactions successfully in this highly competitive environment.

We rely on our senior management team and the loss of a single member could adversely affect our operations.

We depend to a large extent on the services of certain key management personnel, including Chris A. Faulkner, our President and Chief Executive Officer, Jeremy S. Wagers, our Chief Operating Officer and General Counsel, Judson “Rick” F. Hoover, our Chief Financial Officer, and our other executive officers and key employees. The loss of Mr. Faulkner, Mr. Wagers, Mr. Hoover or other key management personnel could have a material adverse effect on our business, financial condition and results of operations. These individuals have experience and expertise in the oil and natural gas industry. We do not maintain key-man life insurance with respect to any of our employees. Our success will be dependent on our ability to continue to employ and retain skilled technical personnel.

The inability to control associated entities could adversely affect our business.

We do not operate all of the properties in which we have working interests. Accordingly, our success depends in part upon operations on certain properties in which we may have an interest along with other business entities. In the event that an operator experiences financial difficulties, this may negatively impact our ability to receive payments for our share of net production to which we are entitled under our contractual arrangements with such operator. While we seek to minimize such risks, there can be no assurances that we can do so in all situations covering our non-operated properties. Because we have no control over such operators and entities, we are able to neither direct their operations, nor ensure that their operations on our behalf will be completed in a timely and efficient manner. Any delay in such business entities’ operations could adversely affect our operations.

There are risks in acquiring producing properties.

We constantly evaluate opportunities to acquire oil and natural gas properties and frequently engage in bidding and negotiating for these acquisitions. If successful in this process, we may alter or increase our capitalization through the issuance of additional debt or equity securities, the sale of production payments or other measures. Any change in capitalization affects our risk profile.

A change in capitalization, however, is not the only way acquisitions affect our risk profile. Acquisitions may alter the nature of our business. This could occur when the character of acquired properties is substantially different from our existing properties in terms of operating or geologic characteristics.

A substantial percentage of our proved reserves consist of undeveloped reserves.

As of the end of our 2013 fiscal year, approximately 57% of our proved reserves, based on PV-10, were classified as proved undeveloped reserves. These reserves may not ultimately be developed or produced. As a result, we may not find commercially viable quantities of oil and natural gas, which in turn may have a material adverse effect on our results of operations.

Operating hazards may adversely affect our ability to conduct business.

Our operations are subject to risks inherent in the oil and gas industry, including but not limited to the following:

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blowouts;

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cratering;

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explosions;

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uncontrollable flows of oil, gas or well fluids;

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fires;

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pollution; and

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other environmental risks.

These risks could result in substantial losses to us from injury and loss of life, damage to and destruction of property and equipment, pollution and other environmental damage and suspension of operations. Governmental regulations may impose liability for pollution damage or result in the interruption or termination of operations.

Losses and liabilities from uninsured or underinsured drilling and operating activities could have a material adverse effect on our financial condition and operations.

Oil and natural gas operations are subject to particular hazards incident to the drilling and production of oil and natural gas, such as blowouts, cratering, explosions, uncontrollable flows of oil, natural gas or well fluids, fires and pollution and other environmental risks. These hazards can cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and suspension of operation. We do not operate all of the properties in which we have an interest. In such non-operated properties, the operator for the prospect maintains insurance of various types to cover our operations with policy limits and retention liability customary in the industry. We believe the coverage and types of insurance are adequate. The occurrence of a significant adverse event that is not fully covered by insurance could result in the loss of our total investment in a particular prospect, which could have a material adverse effect on our financial condition and results of operations.

Compliance with environmental and other government regulations could be costly and could negatively impact production.

Our operations are subject to complex and constantly changing laws and regulations adopted by federal, state and local governmental authorities governing the discharge of materials into the environment or otherwise relating to environmental protection. Without limiting the generality of the foregoing, these laws and regulations may:

•

require the acquisition of a permit before drilling commences;

•

restrict the types, quantities and concentration of various substances that can be released into the environment from drilling and production activities;

•

limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas;

•

require remedial measures to mitigate pollution from former operations, such as plugging abandoned wells; and

•

impose substantial liabilities for pollution resulting from our operations.

The recent trend toward stricter standards in environmental legislation and regulation is likely to continue. The enactment of stricter legislation or the adoption of stricter regulation could have a significant impact on our operating costs, as well as on the oil and gas industry in general. We will continue to be subject to uncertainty associated with new regulatory interpretations and inconsistent interpretations between state and federal agencies. We cannot be sure that existing environmental laws or regulations, as currently interpreted or enforced, or as they may be interpreted, enforced or altered in the future, will not have a material adverse effect on our results of operations and financial condition.

Our operations could result in liability for personal injuries, property damage, oil spills, discharge of hazardous materials, remediation and clean-up costs and other environmental damages. We could also be liable for environmental damages caused by previous property owners. As a result, substantial liabilities to third parties or governmental entities may be incurred which could have a material adverse effect on our financial condition and results of operations. We maintain insurance coverage for our operations, but we do not believe that insurance coverage for environmental damages that occur over time or complete coverage for sudden and accidental environmental damages is available at a reasonable cost. Accordingly, we may be subject to liability or may lose the privilege to continue exploration or production activities upon substantial portions of our properties if certain environmental damages occur.

Cyber-attacks targeting systems and infrastructure used by the oil and gas industry may adversely impact our operations.

Our business has become increasingly dependent on digital technologies to conduct certain exploration, development, production and financial activities. We depend on digital technology to estimate quantities of oil and gas reserves, process and record financial and operating data, analyze seismic and drilling information, and communicate with our employees and third party partners. Unauthorized access to our seismic data, reserves information or other proprietary information could lead to data corruption, communication interruption or other operational disruptions in our exploration or production operations. Also, computers control nearly all of the oil and gas distribution systems in the United States and abroad, which are necessary to transport our production to market. A cyber-attack directed at oil and gas distribution systems could damage critical distribution and storage assets or the environment, delay or prevent delivery of production to markets and make it difficult or impossible to accurately account for production and settle transactions. While we have not experienced cyber-attacks, there is no assurance that we will not suffer such attacks and resulting losses in the future. Further, as cyber-attacks continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber-attacks.

Our operations are subject to United States federal, state and local laws and regulations relating to health, safety, transportation and protection of natural resources and the environment.

Natural gas and oil operations are subject to various federal, state and local government regulations that may change from time to time. Matters subject to regulation include discharge permits for drilling operations, plug and abandonment bonds, reports concerning operations, the spacing of wells, unitization and pooling of properties and taxation. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of natural gas and oil wells below actual production capacity in order to conserve supplies of natural gas and oil. Other federal, state and local laws and regulations relating primarily to the protection of human health and the environment apply to the development, production, handling, storage, transportation and disposal of natural gas and oil, by-products thereof and other substances and materials produced or used in connection with natural gas and oil operations. We also are subject to changing and extensive tax laws, the effects of which cannot be predicted. Compliance with existing, new or modified laws and regulations could have a material adverse effect on our business, financial condition and results of operations.

Certain U.S. federal income tax deductions currently available with respect to oil and natural gas drilling and development may be eliminated as a result of future legislation.

In recent years, the current U.S. government’s budget proposals and other proposed legislation have included the elimination of certain key U.S. federal income tax incentives currently available to oil and gas exploration and production. If enacted into law, these proposals would eliminate certain tax preferences applicable to taxpayers engaged in the exploration or production of natural resources. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain domestic production activities and (iv) increasing the amortization period for certain geological and geophysical expenditures paid or incurred in connection with the exploration for or development of, oil and gas within the United States. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development, and any such change could increase our tax liability and negatively impact our financial condition and results of operations.

The adoption of derivatives legislation by the U.S. Congress could have an adverse effect on the Company’s ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with its business.

The Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd Act”), signed into law in 2010, establishes, among other provisions, federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market. The Dodd Act required the Commodities Futures Trading Commission (“CFTC”) and the SEC to promulgate rules and regulations implementing the new legislation; although the CFTC and the SEC have issued final regulations in certain areas, final rules in other areas and the scope of relevant definitions and/or exemptions still remain to be finalized. In its rulemaking under the Dodd Act, the CFTC has issued a final rule on position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents; the CFTC’s final rule was set aside by the U.S. District Court for the District of Columbia on September 28, 2012 and remanded to the CFTC to resolve ambiguity as to whether statutory requirements for such limits to be determined necessary and appropriate were satisfied. The CFTC appealed this ruling, but subsequently withdrew its appeal. On November 5, 2013, the CFTC approved a Notice of Proposed Rulemaking to implement new position limits regulation which would be published later in a final rule. Certainbona fide hedging transactions or positions are exempt from these position limits. While it is not possible at this time to predict when the CFTC will finalize the position limit rule or other related rules and regulations, depending on our classification, these

rules and regulations may require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with any derivative activities. The Dodd Act may also require the counterparties to derivative instruments to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties. The Dodd Act and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts and reduce the availability of derivatives to protect against risks we encounter. Finally, the Dodd 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. Our revenues could therefore be adversely affected if a consequence of the Dodd Act and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our ability to hedge risks and on our financial position, results of operations or cash flows.

Improvements in or new discoveries of alternative energy technologies could have a material adverse effect on our financial condition and results of operations.

Because our business depends on the level of activity in the oil and natural gas industry, any improvement in or new discoveries of alternative energy technologies (such as wind, solar, geothermal, fuel cells and biofuels) that increase the use of alternative forms of energy and reduce the demand for oil and natural gas could have a material adverse impact on our business, financial condition and results of operations.

Increased regulation of hydraulic fracturing, including regulation of the quantities, sources and methods of water use and disposal, could result in reduction in drilling and completing new oil and natural gas wells or minimize water use or disposal, which could adversely impact our financial condition.

Our success depends, in large part, on our level of exploration and production of oil and gas. We may use hydraulic fracturing to drill new oil and gas wells. Hydraulic fracturing is a process that is used to release hydrocarbons from certain geological formations. The process involves the injection of water (typically mixed with significant quantities of sand and small quantities of chemical additives) under pressure into the formation to fracture the surrounding rock and stimulate movement of hydrocarbons through the formation. The process is typically regulated by state oil and gas commissions and has been exempt (except when the fracturing fluids or propping agents contain diesel fuels) since 2005 from United States federal regulation pursuant to the Safe Drinking Water Act.

The EPA is conducting a comprehensive study of the potential environmental impacts of hydraulic fracturing activities, and a committee of the United States House of Representatives is also conducting an investigation of hydraulic fracturing practices. The results of the EPA study and House investigation could lead to restrictions on hydraulic fracturing. The EPA is currently working on new guidance for application of the Safe Drinking Water Act permits for drilling or completing processes that use fracturing fluids or propping agents containing diesel fuels. In addition, the EPA proposed regulations under the federal Clean Air Act in July 2011 regarding certain criteria and hazardous air pollutant emissions from hydraulic fracturing wells and, in October 2011, announced its intention to propose regulations by 2014 under the federal Clean Water Act to regulate wastewater discharges from hydraulic fracturing and other gas production. Legislation has been introduced before Congress to provide for federal regulation of hydraulic fracturing, including, for example, requiring disclosure of chemicals used in the fracturing process or seeking to repeal the exemption from the Safe Drinking Water Act. If adopted, such legislation would add an additional level of regulation and necessary permitting at the federal level and could make it more difficult to complete wells using hydraulic fracturing. Similar laws and regulations with respect to chemical disclosure also exist or are being considered by the United States Department of Interior and in several states, including certain states in which we operate, that could restrict hydraulic fracturing.

Future United States federal, state or local laws or regulations could significantly restrict, or increase costs associated with hydraulic fracturing and make it more difficult or costly for producers to conduct hydraulic fracturing operations, which could result in a decline of our exploration and production. New laws and regulations, and new enforcement policies by regulatory agencies, could also expressly restrict the quantities, sources and methods of water use and disposal in hydraulic fracturing and otherwise increase our costs and our customers’ cost of compliance, which could minimize water use and disposal needs even if other limits on drilling and completing new wells were not imposed. Any decline in exploration and production or any restrictions on water use and disposal could result in a decline in our drilling and rework activity and have a resulting material adverse effect on our business, financial condition, results of operations and cash flows.

Our business is difficult to evaluate.

Our future financial results depend primarily on (1) our ability to discover commercial quantities of oil and gas; (2) the market price for oil and gas; (3) our ability to continue to generate potential exploration prospects; and (4) our ability to fully implement our exploration and development program. We cannot predict that our future operations will be profitable. In addition, our operating results may vary significantly during any financial period. These variations may be caused by significant periods of time between discovery and development of oil or gas reserves, if any, in commercial quantities.

Exploratory drilling is a high risk activity with many uncertainties that could adversely affect our business, financial condition or results of operations.

Exploratory drilling involves numerous risks, including the risk that we will not find any commercially productive oil or gas reservoirs. The cost of drilling, completing and operating wells is often uncertain, and a number of factors can delay or prevent drilling operations, including:

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unexpected drilling conditions,

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pressure or irregularities in formations,

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equipment failures or accidents,

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adverse weather conditions,

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compliance with governmental requirements,

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shortages or delays in the availability of drilling rigs and the delivery of equipment, and

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shortages of trained oilfield service personnel.

Our future drilling activities may not be successful, nor can we be sure that our overall drilling success rate or our drilling success rate for activities within a particular area will not decline. Unsuccessful drilling activities could have a material adverse effect on our results of operations and financial condition. Also, we may not be able to obtain any options or lease rights in potential drilling locations that we identify. Although we have identified a number of potential exploration projects, we cannot be sure that we will ever drill them or that we will produce oil or gas from them or any other potential exploration projects.

Our exploration and development activities are subject to reservoir and operational risks which may lead to increased costs and decreased production.

Even when oil and gas is found in what is believed to be commercial quantities, reservoir risks, which may be heightened in new discoveries, may lead to increased costs and decreased production. These risks include the inability to sustain deliverability at commercially productive levels as a result of decreased reservoir pressures, large amounts of water, or other factors that might be encountered. As a result of these types of risks, most lenders will not loan funds secured by reserves from newly discovered reservoirs, which would have a negative impact on our future liquidity. Operational risks include hazards such as fires, explosions, craterings, blowouts, uncontrollable flows of oil, gas or well fluids, pollution, releases of toxic gas and encountering formations with abnormal pressures. In addition, we may be liable for environmental damage caused by previous owners of property we own or lease. As a result, we may face substantial liabilities to third parties or governmental entities, which could reduce or eliminate funds available for exploration, development or acquisitions or cause us to incur substantial losses. The occurrence of any one of these significant events, if it is not fully insured against, could have a material adverse effect on our financial condition and results of operations.

Our operations require large amounts of capital and we may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a loss of properties and a decline in our natural gas and oil reserves.

Our current development plans will require us to make large capital expenditures for the exploration and development of our oil and gas projects. Also, we must secure substantial capital to explore and develop our other potential projects. In the near future, we may fund capital expenditures through the issuance of equity or debt. Volatility in the price of our common stock, which may be significantly influenced by our drilling and production activity, may impede our ability to raise money quickly, if at all, through the issuance of equity at acceptable prices. Future cash flows and the availability of financing will be subject to a number of variables, such as:

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our success in locating and producing reserves in other projects;

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the level of production from existing wells; and

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prices of oil and gas.

Any additional capital raised through the sale of equity may dilute the ownership percentage of our stockholders. Raising any such capital could also result in a decrease in the nominal fair market value of our equity securities because our assets would be owned by a larger pool of outstanding equity. The terms of securities we issue in future capital transactions may be more favorable to new investors and may include preferences, superior voting rights and the issuance of other derivative securities, all of which may have a dilutive effect to existing investors.

Our ability to obtain financing, if and when necessary, may be impaired by such factors as the capital markets (both generally and in the oil and gas industry in particular), the location of our oil and gas properties, prices of oil and gas on the commodities markets (which will impact the amount of asset-based financing available to us) and the departure of key employees. Further, if oil or gas prices decline, our revenues will likely decrease and such decreased revenues may increase our requirements for capital. If our revenues were to decrease due to lower oil and gas prices, decreased production or other reasons, and if we could not obtain capital through a credit facility or otherwise, our ability to execute our development plans, obtain and replace reserves, or maintain production levels could be greatly limited.

Oil and gas reserve estimates may not be accurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond our control. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in any exact way, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates made by different engineers often vary from one another. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revisions of such estimates, and such revisions, if significant, would change the schedule of any further production and development drilling. Accordingly, reserve estimates are generally different, and often materially so, from the quantities of oil and natural gas that are ultimately recovered. Furthermore, estimates of quantities of proved reserves and their PV-10 value may be affected by changes in crude oil and gas prices because our quantity estimates are based on prevailing prices at the time of their determination.

Not hedging our production may result in losses.

We currently have no hedging agreements in place. However, we may in the future enter into arrangements to reduce our exposure to fluctuations in the market prices of oil and natural gas. We may enter into oil and gas hedging contracts in order to increase credit availability. Hedging will expose us to risk of financial loss in some circumstances, including if:

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production is less than expected;

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the other party to the contract defaults on its obligations; or

•

there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received.

In addition, hedging may limit the benefit we would otherwise receive from increases in the prices of oil and gas. Further, if we do not engage in hedging, we may be more adversely affected by changes in oil and gas prices than our competitors who engage in hedging.

Accounting rules may require write-downs, which may result in a charge to earnings. We may incur write-downs of the net book values of our oil and natural gas properties that would adversely affect our equity and earnings.

We utilize the full cost method of accounting for costs related to our natural gas and oil properties. Under the full cost method, we are subject to quarterly calculations of a “ceiling” or limitation on the amount of our oil and gas properties that can be capitalized on our

balance sheet. If the net capitalized costs of our oil and gas properties exceed the cost center ceiling, we are subject to a write-down of our net oil and gas properties to the extent of such excess. A capitalized cost ceiling test impairment also reduces earnings and impacts stockholders’ equity in the period of occurrence and results in lower amortization expense in future periods. The discounted present value of our proved reserves is a major component of the ceiling calculation and represents the component that requires the most subjective judgments.

The risk that we will be required to write down the carrying value of oil and natural gas properties increases when natural gas and crude oil prices are depressed or volatile. In addition, a write-down of proved oil and natural gas properties may occur if we experience substantial downward adjustments in our estimated proved reserves, or if purchasers cancel long-term contracts for our natural gas production. An expense recorded in one period may not be reversed in a subsequent period even though higher natural gas and crude oil prices may have increased the applicable ceiling in the subsequent period. This and other factors could cause us to write down our natural gas and oil properties or other assets in the future and incur a non-cash charge against future earnings.

We face risks related to title to the leases we enter into that may result in additional costs and affect our operating results.

It is customary in the oil and gas industry to acquire a leasehold interest in a property based upon a preliminary title investigation. If the title to the leases acquired is defective, we could lose the money already spent on the acquisition, or incur substantial costs to cure the title defect, including any necessary litigation. If a title defect cannot be cured, we will not have the right to participate in the development of or production from the leased properties. In addition, it is possible that the terms of our oil and gas leases may be interpreted differently depending on the state in which the property is located. For instance, royalty calculations can be substantially different from state to state, depending on each state’s interpretation of lease language concerning the costs of production. We cannot guarantee that there will be no litigation concerning the proper interpretation of the terms of our leases. Adverse decisions in any litigation of this kind could result in material costs or the loss of one or more leases.

Our leases primary terms may expire prior to drilling.

Oil and gas leases have a primary term in which drilling or operations must commence; otherwise, the lease will expire. As such, we may have insufficient capital to drill leases or economic conditions may change which make the leases not commercially viable or equipment and man power may not be available to drill during the primary term. If any of this occurs, we will have to write the value of the leases off in the current earnings period in which they expire.

Technological changes could put us at a competitive disadvantage.

The oil and gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As new technologies develop, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement those new technologies at a substantial cost. If other oil and gas exploration and development companies implement new technologies before we do, those companies may be able to provide enhanced capabilities and superior quality compared with what we are able to provide. We may not be able to respond to these competitive pressures and implement new technologies on a timely basis or at an acceptable cost. If we are unable to utilize the most advanced commercially available technologies, our business could be materially and adversely affected.

Our industry is heavily regulated, which increases the costs of our operations.

Federal, state and local authorities extensively regulate the oil and gas industry. Legislation and regulations affecting the industry are under constant review for amendment or expansion, raising the possibility of changes that may affect, among other things, the pricing or marketing of oil and gas production. State and local authorities regulate various aspects of oil and gas drilling and production activities, including the drilling of wells (through permit and bonding requirements), the spacing of wells, the unitization or pooling of oil and gas properties, environmental matters, safety standards, the sharing of markets, production limitations, plugging and abandonment, and drill site restoration. The overall regulatory burden on the industry increases the cost of doing business, which, in turn, decreases profitability.

Our business depends on transportation facilities owned by others.

The marketability of our potential oil and gas production depends in part on the availability, proximity and capacity of pipeline systems owned or operated by third parties. Federal and state regulation of oil and gas production and transportation, tax and energy policies, changes in supply and demand and general economic conditions could adversely affect our ability to produce, gather and transport oil and natural gas.

Attempts to grow our business could have an adverse effect.

Because of our small size, we desire to grow rapidly in order to achieve certain economies of scale. Although there is no assurance that this rapid growth will occur, to the extent that it does occur, it will place a significant strain on our financial, technical, operational and administrative resources. As we increase our services and enlarge the number of projects we are evaluating or in which we are participating, there will be additional demands on our financial, technical and administrative resources. The failure to continue to upgrade our technical, administrative, operating and financial control systems or the occurrence of unexpected expansion difficulties, including the recruitment and retention of geoscientists and engineers, could have a material adverse effect on our business, financial condition and results of operations.

RISKS RELATED TO OUR EQUITY

We do not intend to pay dividends on our common stock and, consequently, your only opportunity to achieve a return on your investment is if the price of our stock appreciates.

We have not historically paid a dividend on our common stock, cash or otherwise, and do not plan to declare dividends on shares of our common stock in the foreseeable future. Consequently, your only opportunity to achieve a return on your investment in us will be if the market price of our common stock appreciates, which may not occur, and you sell your shares at a profit.

Future sales of our common stock in the public market could lower our stock price, and any additional capital raised by us through the sale of equity or convertible securities will dilute your ownership in us.

We may sell shares of common stock in public offerings or otherwise issue additional shares of common stock or convertible securities. The Predecessors currently own 461,863,084 shares (approximately 92.5%) of our common stock. Although they are currently subject to a lock-up with the Company that expires on March 9, 2015, the Company has the ability to release these entities from the restrictions contained in that agreement. We cannot predict the size of future issuances of our common stock or the effect, if any, that future issuances and sales of shares of our common stock will have on the market price of our common stock. Sales of substantial amounts of our common stock (including shares issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices of our common stock. Our intention is to grow the Company which will require us to issue additional common stock should we raise additional capital through both public and private offerings. We may also issue additional common stock in the acquisition of or merger with other companies we may acquire. The effect of both of these activities would result in the significant dilution of the Company’s current stockholders.

Our directors and officers own a significant majority of our common stock and the ability of other stockholders to influence the Company and its affairs is limited.

The Predecessors control approximately 92.5% of our issued and outstanding shares of our voting common stock. The Predecessors are owned by Chris Faulkner, our President, CEO and Chairman, Parker Hallam and Michael Miller. They collectively have the current ability to control the affairs of the Company and to determine the path the Company will take. All other stockholders will not have sufficient voting power to override or otherwise influence any vote taken by the Predecessors in their capacity as stockholders of the Company.

Our stock is a penny stock. Trading of our stock may be restricted by the SEC’s penny stock regulations which may limit a stockholder’s ability to buy and sell our stock.

Our stock is a penny stock. The SEC has adopted Rule 15g-9 which generally defines “penny stock” to be any equity security that has a market price (as defined) of less than $5.00 per share or an exercise price of less than $5.00 per share, subject to certain exceptions. Our securities are covered by the penny stock rules, which impose additional sales practice requirements on broker-dealers who sell to persons other than established customers and “accredited investors.” The penny stock rules require a broker-dealer, prior to a transaction in a penny stock not otherwise exempt from the rules, to deliver a standardized risk disclosure document in a form prepared by the SEC which provides information about penny stocks and the nature and level of risks in the penny stock market. The broker-dealer also must provide the customer with current bid and offer quotations for the penny stock, the compensation of the broker-dealer and its salesperson in the transaction and monthly account statements showing the market value of each penny stock held in the customer’s account. The bid and offer quotations, and the broker-dealer and salesperson compensation information, must be given to the customer orally or in writing

prior to effecting the transaction and must be given to the customer in writing before or with the customer’s confirmation. In addition, the penny stock rules require that prior to a transaction in a penny stock not otherwise exempt from these rules, the broker-dealer must make a special written determination that the penny stock is a suitable investment for the purchaser and receive the purchaser’s written agreement to the transaction. These disclosure requirements may have the effect of reducing the level of trading activity in the secondary market for the stock that is subject to these penny stock rules. Consequently, these penny stock rules may affect the ability of broker-dealers to trade our securities. We believe that the penny stock rules discourage investor interest in and limit the marketability of our common stock.

The Financial Industry Regulatory Authority sales practice requirements may also limit a stockholder’s ability to buy and sell our stock.

In addition to the “penny stock” rules described above, the Financial Industry Regulatory Authority FINRA has adopted rules that require that in recommending an investment to a customer, a broker-dealer must have reasonable grounds for believing that the investment is suitable for that customer. Prior to recommending speculative low-priced securities to their non-institutional customers, broker-dealers must make reasonable efforts to obtain information about the customer’s financial status, tax status, investment objectives and other information. Under interpretations of these rules, FINRA believes that there is a high probability that speculative low-priced securities will not be suitable for at least some customers. FINRA requirements make it more difficult for broker-dealers to recommend that their customers buy our common stock, which may limit your ability to buy and sell our stock and have an adverse effect on the market for shares of our common stock.

Substantial sales of our common stock could adversely affect our stock price.

Sales of a substantial number of shares of our common stock, or the perception that such sales could occur, could adversely affect the market price of our common stock by introducing a large number of sellers to the market. Such sales could cause the market price of our common stock to decline. We cannot predict whether future sales of our common stock, or the availability of our common stock for sale, will adversely affect the market price for our common stock or our ability to raise capital by offering equity securities.

Trading of our common stock may be volatile and sporadic, which could depress the market price of our common stock and make it difficult for our stockholders to resell their shares.

There is currently a limited market for our common stock and the volume of our common stock traded on any day may vary significantly from one period to another. Our common stock is quoted on OTC Market’s OTCQB. Trading in stock quoted on OTC Market’s OTCQB is often thin and characterized by wide fluctuations in trading prices, due to many factors that may have little to do with our operations or business prospects. The availability of buyers and sellers represented by this volatility could lead to a market price for our common stock that is unrelated to operating performance. Moreover, OTC Market’s OTCQB is not a stock exchange, and trading of securities quoted on OTC Market’s OTCQB is often more sporadic than the trading of securities listed on a stock exchange like NASDAQ. There is no assurance that a sufficient market will develop in the stock, in which case it could be difficult for our stockholders to resell their stock.

Our Board of Directors can issue preferred stock with terms that are preferential to our common stock.

Pursuant to our articles of incorporation, as amended, our Board of Directors may issue preferred stock without action by our stockholders, with in such series and classes, and with rights and preferences related thereto, determined by the Board of Directors. Rights or preferences could include, among other things:

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the establishment of dividends which must be paid prior to declaring or paying dividends or other distributions to our common stockholders;

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greater or preferential liquidation rights which could negatively affect the rights of common stockholders; and

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the right to convert the preferred stock at a rate or price which would have a dilutive effect on the outstanding shares of common stock.

We make estimates and assumptions in connection with the preparation of our financial statements, and any changes to those estimates and assumptions could have a material adverse effect on our results of operations.

In connection with the preparation of our financial statements, we use certain estimates and assumptions based on historical experience and other factors. Our most critical accounting estimates are described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in this report. In addition, as discussed in Note 2 to the financial statements, we make certain estimates, including decisions related to provisions for legal proceedings and other contingencies. While we believe that these estimates and assumptions are reasonable under the circumstances, they are subject to significant uncertainties, some of which are beyond our control. Should any of these estimates and assumptions change or prove to have been incorrect, it could have a material adverse effect on our results of operations.

Failure of our internal controls over financial reporting could harm its business and financial results.

Our Management is responsible for establishing and maintaining effective internal controls over financial reporting. Internal controls over financial reporting are processes to provide reasonable assurance regarding the reliability of financial reporting for external purposes in accordance with GAAP. Internal control over financial reporting include maintaining records that in reasonable detail accurately and fairly reflect the Company’s transactions; providing reasonable assurance that transactions are recorded as necessary for preparation of the financial statements; providing reasonable assurance that receipts and expenditures are made in accordance with management authorization; and providing reasonable assurance that unauthorized acquisition, use or disposition of the Company assets that could have a material effect on the financial statements would be prevented or detected on a timely basis. Because of its inherent limitations, internal controls over financial reporting are not intended to provide absolute assurance that a misstatement of the Company’s financial statements would be prevented or detected. Failure to maintain an effective system of internal controls over financial reporting could limit the Company’s ability to report its financial results accurately and timely or to detect and prevent fraud.

ITEM 1B - UNRESOLVED STAFF COMMENTS.

None.

Item 2. Properties

LOGO

Oil and Gas Properties, Wells, Operations, and Acreage

The Company’s approximately 1,426 oil and gas properties, which are primarily held by production in seven states with approximately 6,000 oil and gas wells. The Company’s asset base is comprised of approximately 498 Mbbl of oil and approximately 1,278.51 MMcf of gas. The Predecessors acquired their oil and gas assets in connection with their business model that differs substantially from that of the Company or an ordinary oil and exploration and production company. Through a combination of subsidiaries, the Predecessors acquired either working interests in oil and gas properties or overriding royalty interests in oil and gas properties. Following these acquisitions, the Predecessors offered interests in those properties to accredited investors through a series of private placements. The interests offered in those properties were subject to certain carried interests, and those carried interests constitute the bulk of the oil and gas assets acquired from the Predecessors.

Since the Predecessors’ interests consist primarily of carried interests, the Predecessors have historically not held a sufficient working interest in any well necessary to give the Predecessors operating rights. Consequently, the vast majority of our holdings represent non-operated working or royalty interests. Since the Predecessors were not the operators of these wells, all operating decisions were made by other parties, and the Predecessors were not in charge of drilling or other operations. The well counts listed herein represent our best estimates based on information provided to us as a non-operating working interest or royalty interest owner. Due to the significant number of individual deeds, leases and similar instruments involved in the acquisition and development of properties by us or the Predecessors, our data is subject to change as new information becomes available. In addition, our access to information concerning activity and operations on the properties is limited. Most of our producing properties are subject to old leases and other contracts pursuant to which we are not entitled to well information. Some of our newer leases provide for access to technical data and other information or we may have limited access to public data in some areas through third party subscription services. Consequently, the exact number of wells producing from our drilling on our royalty properties is not determinable.

On a prospective basis, the Company intends to acquire working interests in oil and gas prospects sufficient to give the Company the right to act as operator. Thereafter, the Company will drill and operate those leaseholds which it has the right to operate in the ordinary course of business.

Of the Company’s approximately 606 proved producing wells, approximately 523 are held in Texas in 78 fields, approximately 22 are held in Oklahoma in 20 fields and approximately 17 are held in Louisiana in 9 fields. The remaining approximately 44 wells are held in Mississippi and North Dakota.

Oil and Natural Gas Reserves

Set forth below is a summary of the Company’s oil and gas reserves, as well as the PV-10 for each category of property listed:


	Gross Oil (Mbbl)		Net Oil (Mbbl)		Gross Gas (Mmcf)		Net Gas (Mmcf)		PV-10⁽¹⁾
Proved Producing		163,602		84.58		487,274		373.13	$	4,873.64
Proved Non-Producing		6,567		17.16		31,008		20.41	$	568.67
Proved Undeveloped		13,005		49.01		30,049		132.39	$	2,668.78
Probable Undeveloped		15,457		150.04		253,940		547.32	$	6,930.45
Probable Non-Producing		9,028		11.08		26,292		13.08	$	408.06
Possible Undeveloped		6,638		184.31		101,571		191.95	$	6,599.77
Possible Non-Producing		1,561		1.43		3,293		0.23	$	24.00

Total		215,858		497.61		933,427		1,278.51	$	22,073.37

(1)

The total proved PV-10 value of the estimated future net revenue are not intended to represent the current market value of the estimated oil and natural gas reserves we own. Management believes that the presentation of PV-10, while not a financial measure in accordance with GAAP, provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and natural gas companies. Because many factors that are unique to each individual company impact the amount of future income taxes estimated to be paid, the use of a pre-tax measure is valuable when comparing companies based on reserves. PV-10 is not a measure of financial or operating performance under GAAP. PV-10 should not be considered as an alternative to the standardized measure as defined under GAAP. PV-10 of probable or possible reserves represent the present value of estimated future revenues to be generated from the production of probable or possible reserves, calculated net of estimated lease operating expenses, production taxes and future development costs, using costs as of the date of estimation without future escalation and using 12-month average prices, without giving effect to non-property related expenses such as general and administrative expenses, debt service, and depreciation, depletion, and amortization, or future income taxes and discounted using an annual discount rate of 10%. With respect to pre-tax PV-10 amounts for probable or possible reserves, there do not exist any directly comparable GAAP measures, and such amounts do not purport to present the fair value of our probable and possible reserves.

Probable Reserves

Estimates of probable reserves are inherently imprecise. When producing an estimate of the amount of oil and natural gas that is recoverable from a particular reservoir, an estimated quantity of probable reserves is an estimate of those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. Estimates of probable reserves are also continually subject to revisions based on production history, results of additional exploration and development, price changes and other factors.

When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates. Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir. Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

Possible Reserves

Estimates of possible reserves are also inherently imprecise. When producing an estimate of the amount of oil and natural gas that is recoverable from a particular reservoir, an estimated quantity of possible reserves is an estimate that might be achieved, but only under more favorable circumstances than are likely. Estimates of possible reserves are also continually subject to revisions based on production history, results of additional exploration and development, price changes and other factors.

When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates. Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project. Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

Internal Controls

Management has established, and is responsible for, a number of internal controls designed to provide reasonable assurance that the estimates of proved, probable and possible reserves are computed and reported in accordance with rules and regulations provided by the SEC as well as established industry practices used by independent engineering firms and our peers. These internal controls consist of documented process workflows and qualified professional engineering and geological personnel with specific reservoir experience. We also retain an outside independent engineering firm to prepare estimates of our proved, probable and possible reserves. We work closely with this firm, and management is responsible for providing accurate operating and technical data to it. Senior management reviews and approves our reserves estimate, whether prepared internally or by third parties.

Estimates of oil and natural gas reserves are projections based on a process involving an independent third-party engineering firm’s collection of all required geologic, geophysical, engineering and economic data, and such firm’s complete external preparation of all required estimates and are forward-looking in nature. These reports rely upon various assumptions, including assumptions required by the SEC, such as constant oil and natural gas prices, operating expenses and future capital costs. We also make assumptions relating to availability of funds and timing of capital expenditures for development of our proved undeveloped, probable and possible reserves. These

reports should not be construed as the current market value of our reserves. The process of estimating oil and natural gas reserves is also dependent on geological, engineering and economic data for each reservoir. Because of the uncertainties inherent in the interpretation of this data, we cannot ensure that the reserves will ultimately be realized. Our actual results could differ materially.

Controls Over Reserve Report Preparation

Our long term prospects for continuing to extract oil and gas are directly related to our oil and gas reserves. Estimates of proved reserves at December 31, 2013, were prepared by Mire & Associates, Inc., independent petroleum consultants, a Texas registered petroleum consulting firm. The technical person responsible for preparing the reserve estimates is an independent petroleum engineer and geoscientist that meets the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Specifically, our reserve report was prepared by Mr. Kurt Mire, a reservoir engineer with over 30 years of experience. Mr. Mire has a B.S., in Petroleum Engineering from University of Southwestern Louisiana.

The reserve report was prepared as of December 31, 2013, under SEC pricing requirements. The 2013 reserve report summary is an exhibit to this annual report.

Proved Undeveloped Reserves


Years Ended December 31, 2013

Estimated Proved Oil and Natural Gas Reserves:
Net oil reserves (MBbls):
Proved developed		84,580
Proved undeveloped		66,170

Total		150,750

Net natural gas reserves (MMcf):
Proved developed		373,130
Proved undeveloped		152,800

Total		525,930

Estimated Present Value of Net Proved Reserves:
PV-10 value (in thousands)
Proved developed	$	3,240,460
Proved undeveloped		4,870,640

Total	$	8,111,100


Prices Used in Calculating Reserves:
Natural gas (per Mcf)	$	3.67
Oil (per Bbl)	$	96.91

The following table is a tabular representation of the estimate for our proved developed and undeveloped reserves:


	Crude Oil (Bbl)			Natural Gas (Mcf)
PROVED-DEVELOPED AND UNDEVELOPED RESERVES
December 31, 2011		16,810			232,880

Revisions of previous estimates		12,178			(44,220	)
Extensions and discoveries		12,618			63,801
Acquisitions of reserves		66,230			63,660
Production		(1,206	)		(7,271	)


December 31, 2012		106,630			308,850


Revisions of previous estimates
Extensions and discoveries
Acquisitions of reserves		55,290			272,950
Production		(11,170	)		(55,870	)


December 31, 2013		150,750			525,930


PROVED DEVELOPED RESERVES
December 31, 2013		84,580			373,130

December 31, 2012		66,460			129,310

Production, Price and Production Cost

The Company receives hydrocarbon production in the form of oil, natural gas and condensates which it markets to third party purchasers. The following chart lists our net production, total sales and average price we experienced from our wells in the last two fiscal years:


	Year Ended December 31,
	2013		2012
Gross Production:
Oil (Bbl)		8,960,410		8,113,670
Natural Gas (Mcf)		40,067,530		21,852,740
Barrel of Oil Equivalent (Boe)		15,638,332		11,755,793

Net Production:
Oil (Bbl)		11,170		1,660
Natural Gas (Mcf)		55,870		31,510
Barrel of Oil Equivalent (Boe)		20,482		6,912

Oil and Natural Gas Sales:
Oil (in thousands)	$	934,545	$	153,749
Natural Gas (in thousands)	$	165,375	$	175,826

Total (thousands)	$	1,099,920	$	329,575

Average Sales Price:
Oil ($ per Bbl)	$	96.38	$	92.62
Natural Gas ($ per Mcf)	$	2.96	$	5.58
Barrel of Oil Equivalent ($ per Boe)	$	53.71	$	47.68

Drilling Activity

As of December 31, 2013, the Company has not drilled any productive or dry exploratory or developmental wells in the last three years.

Present Activities

As of December 31, 2013, the Company was not drilling any wells.

Delivery Commitments

As of December 31, 2013, the Company has no commitments to provide a fixed quantity of oil or natural gas.

Title to Properties

In most situations, as is customary in the oil and gas industry, only a preliminary title examination is conducted at the time we acquire oil and gas leases covering properties for possible drilling operations. Prior to the commencement of drilling operations, a more complete title examination of the drill site tract is usually conducted by independent attorneys or landmen. Once production from a given well is established, we prepare a division order title report indicating the proper parties and percentages for payment of production proceeds, including royalties. The level of title examination often differs from property to property. Our properties are subject to customary royalty interests, liens incident to operating agreements, liens for current taxes and other burdens which we believe do not materially interfere with the use of or affect the carrying value of our properties.

Company Offices

The Company currently leases office space at 1910 Pacific Ave, Suite 12000, Dallas, TX 75201. The Company entered into a Lease Agreement on September 9, 2013, for a term of 120 months and expiring on June 30, 2024.

Available Information

We file annual, quarterly and current reports, proxy statements and other information electronically with the SEC. You may read and copy any materials we file with the SEC at the SEC’s Public Reference Room at 100 F. Street, NE, Washington, DC 20549. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC maintains an internet site (www.sec.gov) that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC, including our filings.

Our internet address is www.breitlingenergy.com. We make available free of charge on or through our internet site our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC.

ITEM 3 - LEGAL PROCEEDINGS

The Company is from time to time involved in legal proceedings. Management of the Company believes that any liability to the Company that may arise as a result of these proceedings will not have a material adverse effect on the financial condition of the Company and its subsidiaries taken as a whole.

ITEM 4 - MINE SAFETY DISCLOSURES

Not applicable.

PART II

ITEM 5 - MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Market information

Our common stock is quoted on OTCBB under the symbol “BECC.”

The following table shows the quarterly range of high and low bid information for our common stock over the fiscal quarters for the last two fiscal years as quoted on OTCBB. We obtained the following high and low bid information from OTCBB. These over-the-counter market quotations reflect inter-dealer prices without retail mark-up, mark-down or commission, and may not represent actual transactions. Investors should not rely on historical prices of our common stock as an indication of its future price performance. On March 28, 2014, the closing price of our common stock as reported by OTCBB was $.51 per share.


The Quarter Ended*	HIGH		LOW

March 31, 2012	$	1.05	$	0.05
June 30, 2012		0.75		0.20
September 30, 2012		0.50		0.15
December 31, 2012	$	0.60	$	0.14


The Quarter Ended*	HIGH		LOW

March 31, 2013	$	0.60	$	0.14
June 30, 2013		0.26		0.15
September 30, 2013		0.16		0.05
December 31, 2013	$	0.25	$	0.06

As of March 28, 2014, there were an estimated 4,200 beneficial holders of our common stock.

Dividends

We have not paid any cash dividends to date, and have no intention of paying any cash dividends on our common stock in the foreseeable future. The declaration and payment of dividends is subject to the discretion of our Board of Directors and to certain limitations imposed under Nevada law. The timing, amount and form of dividends, if any, will depend on, among other things, our results of operations, financial condition, cash requirements and other factors deemed relevant by our Board of Directors.

ITEM 6 – SELECTED FINANCIAL DATA

Not Applicable

ITEM 7 – MANAGEMENT DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion should be read in conjunction with our financial statements and notes thereto for the fiscal year ended December 31, 2013, included elsewhere in this annual report.

Our Business

We are an oil and gas exploration and production company. We acquire oil and gas leases from landowners, or interest in oil and gas wells through working interest or royalty interests in geographical locations which we believe have the potential for the success. If the wells are drilled or acquired, we may or may not operate the wells. We may or may not sell interest in those wells through either royalty or working interests. The Predecessors acquired their oil and gas assets in connection with their business model which differs substantially from ours and that of an ordinary oil and exploration and production company. The Predecessors acquired either working interests in oil and gas properties or royalty interests in oil and gas properties.

Following these acquisitions, the Predecessors offered interests in those properties to accredited investors through a series of private placements. The interests offered in those properties were subject to certain carried interests, and those carried interests constitute the bulk of the oil and gas assets acquired from the Predecessors.

The Predecessors also entered into turnkey drilling contracts with outside working interest owners to develop leasehold acreage acquired. In these arrangements, the Predecessors acquired a working interest in a prospect pursuant to an oil and gas lease, and then sold a portion of a well’s working interest on the acquired lease to third parties with a turnkey drilling agreement. In each case, the working interest holders are obligated to bear the cost of drilling, testing, completing, equipping and operating the well. The Predecessors typically sold a substantial portion of the working interests, had a third-party operate the projects and was granted a carried interest.

We intend to continue the acquisition of working interests and royalty interests in oil and gas properties through our subsidiaries and special purpose entities and retaining carried interests relating such properties.

RESULTS OF OPERATIONS

For the year ended December 31, 2013 compared to year ended December 31, 2012:

Revenue. During the year ended December 31, 2013, the Company generated revenues of $26,651,288, an increase of $13,243,167 or 99% as compared to the same period last year. The Company had increased revenues primarily through sales of royalty interests in oil and gas properties.

During the year ended December 31, 2013, we produced an additional 9,510 barrels of oil as compared to 1,660 sold in 2012 or an increase of 573%. During the year ended December 31, 2013, we produced an additional 24,360 Mcfs of gas as compared to 31,510 sold in 2012. Our average price per barrel sold during 2013 increased by $3.76 from $92.62 in 2012. Our average price per Mcf sold during 2013 decreased by $2.62 from $5.58 in 2012. These items increased our revenues from oil in 2013 by $846,251 and $75,826 from gas. Some revenues from commodity sales is reflected in the sale of turnkey contracts and royalties interests.

Total Expenses. During the year ended December 31, 2013, total expenses, which are comprised of depreciation, operating costs and general and administrative expenses, were $28,964,979 compared to $18,920,720 during the same period in 2012. This change represents an increase of $10,044,259 or 53%. The increase is primarily due to increased general and administrative expenses, and professional fees. These increases are due primarily to additional services necessary to support our 106% increase in revenue, the preparation to transition to a public company, and direct expenses relating to the transition to a public company.

For the year ended December 31, 2012 compared to year ended December 31, 2011:

Revenue.During the year ended December 31, 2012, the Company generated revenues of $13,408,121 an increase of $4,028,457 or 43% as compared to the same period in 2011. The Company had increased revenues primarily through sales of turnkey drilling contracts. The Company saw a decrease in sales of oil and natural gas royalty interests of $1,151,766 or 92% as compared to the same period in the prior year as investors pursued turnkey contracts rather than royalty interests during the year ended December 31, 2012.

During the year ended December 31, 2012, we produced 1,660 barrels of oil as compared to negligible amounts in 2011. During the year ended December 31, 2012, we produced approximately 31,510 Mcfs of gas as compared to negligible amounts in 2011. Our average price per barrel sold during 2012 was $92.62. Our average price per Mcf sold during 2012 was $5.58.

Total Expenses.During the year ended December 31, 2012, total expenses, which are comprised of depreciation, operating costs and general and administrative expenses, were $18,920,720 compared to $8,680,967 during the same period in 2011. This change represents an increase of $10,239,753 or 118%. The increase is primarily due to activities relating to deferred revenues in the turnkey drilling area. The Company had recognized the expenses associated with the generation of the revenue, but had defer the revenue recognition until the completion of certain wells.

LIQUIDITY AND CAPITAL RESOURCES

For the year ended December 31, 2013:

We have increased our net working capital deficit as of December 31, 2013 to $9,545,632 an increase of $4,961,670 from December 31, 2012. The increase is primarily due to growth in our revenues.

Net cash used in operating activities of $2,550,466 for year ended December 31, 2013 decreased from cash provided by operations of $947,869 for the same period last year, a decrease of $3,498,335. The decrease is primarily due to the increase in paying current expenses associated with generating future revenues.

Net cash used in investing activities of $1,511,659 was primarily utilized to develop our oil and gas assets during the year 2013. This is a decrease of $1,351,753 from the same period in 2012.

The Company was considered the acquirer for accounting purposes because it obtained effective control of Bering. Breitling did not have a change in control since Breitling’s operations comprise the ongoing operations of the combined entity, its senior management became the senior management of the combined entity, and its former owners own a majority voting interest in the combined entity and are able to elect a majority of the combined entity’s board of directors. Accordingly, the Business Combination does not constitute the acquisition of a business for purposes of Financial Accounting Standards Board’s Accounting Standard Codification 805, “Business Combinations,” or ASC 805. As a result, the assets and liabilities of Breitling are carried at historical cost and the Company has not recorded any step-up in basis or any intangible assets or goodwill as a result of the Business Combination. All direct costs of the Business Combination were offset to additional paid-in capital. The historical financial statements presented herein are that of Breitling.

The Company has incurred losses and negative cash flows from operations in recent years and expects to continue to incur operating losses until revenues from all sources reach a level sufficient to support its on-going operations. The Company’s liquidity will largely be determined by its ability to raise capital from debt, equity, or other forms of financing, by the success of its product offerings, by developing additional product offerings, and by reducing expenses associated with operations. The Company’s management believes that its cash resources at December 31, 2013, will be sufficient to meet current obligations and fund its operating activities through December 31, 2014.

In the absence of a sufficient increase in revenues, the Company will need to do one or more of the following in the next 12 months to meet its planned level of expenditures: (a) raise additional capital; (b) reduce spending on operations; or (c) restructure its operations. A capital raise could take any number of forms including but not limited to: additional debt, additional equity, asset sales, or other forms of financing as dictated by its needs and its view toward its overall capital structure. However, additional financing might not be available on acceptable terms, if at all, and such financing might only be available on terms dilutive or otherwise detrimental to its stockholders or its business. As such, the Company’s Chief Executive Officer, Mr. Chris Faulkner, has personally guaranteed his ability and financial wherewithal to ensure the Company can continue until at least January 1, 2015. This personal guaranty may include reduction of salary, capital or debt contributions and/or other measures, as needed.

Our current working capital should be positive in the first quarter of 2014.

Future Financing

We will require additional financing to fund our planned operations, including further development of our current leases through the drilling of additional wells and the acquiring of additional leases in geographical locations which we believe have potential for successful exploration. We estimate that to develop our current undeveloped properties and to acquire properties to maintain our current revenue level we will need approximately $12 million dollars. We may issue equity, debt or a combination of the foregoing in order to raise the capital that we need. There can be no assurance that we will be able to raise financing sufficient to fund our planned operations on terms acceptable to us.

Off-Balance Sheet Arrangements

From time-to-time, we enter into off-balance sheet arrangements and transactions that can give rise to off-balance sheet obligations. As of December 31, 2013, the off-balance sheet arrangements and transactions that we had entered into included operating lease agreements and gas transportation commitments. The Company does not believe that these arrangements are reasonably likely to materially affect its liquidity or availability of, or requirements for, capital resources currently or in the future.

Application of Critical Accounting Policies

Our financial statements and accompanying notes are prepared in accordance with GAAP. Preparing financial statements requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenue and expenses. These estimates and assumptions are affected by management’s application of accounting policies. We believe that understanding the basis and nature of the estimates and assumptions involved with the following aspects of our financial statements is critical to an understanding of our financials.

We base our assumptions and estimates on historical experience and other sources that we believe to be reasonable at the time. Actual results may vary from our estimates due to changes in circumstances, politics, global economics, general business conditions and other factors.

There are accounting policies that we believe are significant to the presentation of our financial statements.

Revenue Recognition

The Company enters into turnkey drilling contracts with outside working interest owners to develop leasehold acreage the Company has acquired. In these arrangements, the Company acquires a working interest in a prospect pursuant to an oil and gas lease, and then sells a portion of a well’s working interest on the acquired lease to outside working interest owners with a turnkey drilling agreement. Title to the lease property is not conveyed to the outside working interest owners. The outside working interest owner purchases a working interest directly in the well bore. The working interest purchased in the turnkey drilling agreements is an ownership interest in which the working interest holder is responsible to bear the cost of drilling, testing, completing, equipping and operating the well. The Company typically sells a substantial portion of the working interests and has a third-party operate the projects.

In a turnkey drilling agreement, the Company agrees to sell a percentage of the well’s working interest to outside working interest owners and to pay for all costs of identifying, acquiring mineral rights to drilling testing, completing and equipping the well for initial production at a fixed price. If the actual costs of these activities exceed the turnkey price, the Company is obligated to pay the excess cost. If the actual costs are less than the turnkey price, the Company retains the excess of the turnkey price over actual costs. The Company bears 100% of the risk should actual costs exceed estimated costs of a project for both the Company’s working interest and the working interest sold to outside working interest owners in a well. When the well is completed as a commercially productive well, the Company and the outside working interest owners bear the cost of operating the well according to each party’s proportionate working interest percentage.

When the Company sponsors a turnkey drilling project for sale, outsider working interest owners enter into a signed contract with the Company. In this agreement, the outside working interest owner agrees to share in the prospect acquisition costs and drilling costs. The prospect acquisition costs include geophysical and geographical costs, costs to lease the mineral rights, and other costs as required so the drilling of the project can proceed. Drilling costs are those costs incurred to build the drilling location, drill, and log the well, and if the well is successful, to complete and test the well. Once drilling begins, the well is generally completed within 30 to 60 days.

The Company bases the price at which it sells working interests under the turnkey drilling agreement on its estimates of the costs, described above, and is based upon the historical cost to complete those activities.

Since the outside working interest owner’s interest in the prospect is limited to the well, and not the lease, the outside working interest owner does not have a legal right to participate in additional wells drilled within the same lease. However, it is the Company’s policy to offer to outside working interest owners in a successful well the right to participate in subsequent wells at the same percentage level as their working interest investment in the prior successful well with similar turnkey drilling agreement terms.

The turnkey revenue is recorded on a gross basis with the associated turnkey drilling costs, as agreed to in the turnkey contract, being deferred until the associated revenue is recognized. Early recognition of loss is recorded if it is determined that the well cost will exceed the applicable revenue received on the specific well. Total turnkey drilling revenue recognized for the year ended December 31, 2013 and 2012 was approximately $14,914,114 and $13,085,714, respectively. As of December 31, 2013 and 2012, the Company had approximately $4,609,041 and $6,562,000 in deferred turnkey drilling revenue, respectively.

The Company utilizes the accrual method of accounting for natural gas and crude oil revenues, whereby revenues are recognized based on the Company’s net revenue interest in the wells. The Company will also enter into physical contract sale agreements through its normal operations. Revenue from the sale of natural gas and crude oil is recognized when title to the commodities passes.

Gas imbalances are accounted for using the sales method. Under this method, revenues are recognized based on actual volumes of oil and gas sold to purchasers. However, the Company has no history of significant gas imbalances.

Fair Value Measurements

The Company has adopted and follows Accounting Standards Codification (“ASC”) 820,Fair Value Measurements and Disclosures, for measurement and disclosures about fair value of its financial instruments. ASC 820 establishes a framework for measuring fair value in GAAP, and expands disclosures about fair value measurements. To increase consistency and comparability in fair value measurements and related disclosures, ASC 820 establishes a fair value hierarchy which prioritizes the inputs to valuation techniques used to measure fair value into three (3) broad levels. The fair value hierarchy gives the highest priority to quoted prices (unadjusted) in active markets for identical assets or liabilities and the lowest priority to unobservable inputs. The three (3) levels of fair value hierarchy defined by ASC 820 are:

Level 1 — Inputs are unadjusted, quoted prices in active markets for identical assets or liabilities at the measurement date.

Level 2 — Inputs (other than quoted market prices included in Level 1) are either directly or indirectly observable for the asset or liability through correlation with market data at the measurement date and for the duration of the instrument’s anticipated life.

Level 3 — Inputs reflect management’s best estimate of what market participants would use in pricing the asset or liability at the measurement date. Consideration is given to the risk inherent in the valuation technique and the risk inherent in the inputs to the model. Valuation of instruments includes unobservable inputs to the valuation methodology that are significant to the measurement of fair value of assets or liabilities.

As defined by ASC 820, the fair value of a financial instrument is the amount at which the instrument could be exchanged in a current transaction between willing parties, other than in a forced or liquidation sale, which was further clarified as the price that would be received to sell an asset or paid to transfer a liability (“an exit price”) in an orderly transaction between market participants at the measurement date. The carrying amounts of the Company’s financial assets and liabilities, such as cash, receivables, joint interest revenues payable, accounts payable and accrued liabilities, approximate their fair values because of the short maturity of these instruments.

Cash

The Company considers all highly-liquid debt instruments with original maturities of three months or less to be cash equivalents. As of December 31, 2013 and 2012, the Company did not hold any cash equivalents.

The Company maintains its cash balances in financial institutions which are insured by the Federal Deposit Insurance Corporation (“FDIC”). The cash accounts maintain FDIC coverage of up to $250,000 per institution. Non-interest bearing accounts were fully covered subject to the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Act”) for the years ended December 31, 2013 and 2012. This provision of the Act expired on December 31, 2012. As of December 31, 2013 and 2012, the Company had no amounts in excess of FDIC coverage.

Oil and Gas Natural Gas Properties

The Company uses the full-cost method of accounting for its oil and natural gas producing activities as further defined under ASC 932, Extractive Activities -Oil and natural gas. Under these provisions, all costs incurred for both successful and unsuccessful exploration and development activities, including salaries, benefits and other internal costs directly identified with these activities, and oil and natural gas property acquisitions are capitalized. All costs related to production, general corporate overhead or similar activities are expensed as incurred.

The amortization base in the UOP calculation includes the sum of proved property, net of accumulated depreciation, depletion and amortization (“DD&A”), estimated future development costs (future costs to access and develop reserves) and asset retirement costs that are not already included in oil and natural gas property, less related salvage value.

The cost of unproved properties and properties under development are excluded from the amortization calculation until it is determined whether or not proved reserves can be assigned to such properties or until development projects are placed in service. Geological and geophysical costs not associated with specific properties are recorded to proved properties. Unproved properties and properties under development are reviewed for impairment at least quarterly. Exploratory drilling costs associated with dry holes are transferred to proved properties immediately upon determination that a well is dry and amortized accordingly. December 31, 2013, 2012 and 2011, no unproved properties or properties under development were included in the oil and natural gas properties of the accompanying combined financial statements.

Oil and Gas Natural Gas Properties (continued)

Proceeds from the sale or disposition of oil and natural gas properties are accounted for as a reduction to capitalized costs unless a significant portion (greater than 25 percent) of the Company’s reserve quantities are sold, in which case a gain or loss is recognized in income. For the years ended December 31, 2013 and, 2012, the Company recognized gains from the sale or disposition of oil and natural gas properties and royalties due to the proceeds from the sales exceeding 100% of the capitalized costs.

Under the full-cost method of accounting, the net book value of oil and natural gas properties, less related deferred income taxes, may not exceed a calculated “ceiling.” The ceiling limitation is the estimated after-tax future net cash flows from proved oil and natural gas reserves, discounted at 10 percent per annum based on industry standards and adjusted for cash flow hedges. Estimated future net cash flows exclude future cash outflows associated with settling accrued asset retirement obligations. Any excess of the net book value of proved oil and gas properties, less related deferred income taxes, over the ceiling is charged to expense and reflected as additional DD&A in the combined statements of operations. For the years ended December 31, 2013 and, 2012, no impairment charge occurred.

Other Property and Equipment

Other property and equipment, which includes furniture, vehicles, software, and office equipment, is stated at cost less accumulated depreciation and amortization. Depreciation and amortization is computed using the straight-line method over the estimated useful lives of the assets. Furniture and office equipment are generally depreciated over a useful life of ten years, vehicles over a useful life of five years, and software over a useful life of three years.

Impairment of Long-Lived Assets

The Company assesses the impairment of long-lived assets when circumstances indicate that the carrying value may not be recoverable. The Company determines if impairment has occurred through adverse changes. When it is determined that the estimated future net cash flows of an asset will not be sufficient to recover its carrying amount, an impairment loss must be recorded to reduce the carrying amount to its estimated fair value. For the years ended December 31, 2013 and, 2012, no circumstances indicated an unrecoverable carrying value of long-lived assets.

Equity Investment

The Company holds a 50% non-controlling interest in Breitling Royalty Funds (“BRF”). The equity investment in BRF is carried at cost and is adjusted for the Company’s proportionate share of their undistributed earnings or losses.

Joint Interest Revenues Payables

Joint interest revenues payable are comprised of amounts owed to joint interest owners for their proportionate share of revenues. Generally, operators of natural gas and crude oil properties have the right to offset joint interest receivables with joint interest revenues payable. Accordingly, any joint interest owner that has a joint interest receivable and joint interest revenues payable as of December 31, 2013 and, 2012 are shown at net in the accompanying combined balance sheets.

Asset Retirement Obligations

The Company follows the provisions of ASC 410-20,Asset Retirement Obligations. ASC 410-20 requires entities to record the fair value of obligations associated with the retirement of tangible long-lived assets in the period in which it is incurred. When the liability is initially recorded, the entity capitalizes a cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value each period, and the capitalized cost is depleted as part of the oil and natural gas property. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement. The Company’s asset retirement obligations relate to the plugging, dismantlement, removal, site reclamation and similar activities of its oil and natural gas properties.

include, but are not limited to, costs of labor, costs of materials, profits on costs of labor and materials, the effect of inflation on estimated costs, and the discount rate. Accordingly, asset retirement obligations are considered a Level 3 measurement under ASC 820. Additionally, because of the subjectivity of assumptions and the relatively long lives of the Company’s wells, the costs to ultimately retire the Company’s wells may vary significantly from prior estimates.

Lease Operating Expenses

Lease operating expenses represent field personnel salaries, saltwater disposal, ad valorem taxes, repairs and maintenance, severance taxes, expensed workovers and other operating expenses. Lease operating expenses are expensed as incurred.

Sales-Based Taxes

The Company incurs severance tax on the sale of its production which is generated in Texas, North Dakota, and Oklahoma. These taxes are reported on a gross basis and are included in lease operating expense within the accompanying combined statements of operations. Sales-based taxes for the years ended December 31, 2013 and 2012 were approximately $71,000 and $34,000, respectively.

Income Taxes

Income taxes are recorded in accordance with FASB ASC 740, “Income Taxes”. This statement requires the recognition of deferred tax assets and liabilities to reflect the future tax consequences of events that have been recognized in the financial statements or tax returns. Measurement of the deferred items is based on enacted tax laws. In the event the future consequences of differences between financial reporting bases and tax bases of the Company’s assets and liabilities result in a deferred tax asset, ASC 740 requires an evaluation of the probability of being able to realize the future benefits indicated by such assets. A valuation allowance related to a deferred tax asset is recorded when it is more likely than not that some portion or the entire deferred tax asset will not be realized.

The Company has filed all of their tax returns. As of December 31, 2013, there is approximately $7,150,000 in accumulated losses for tax purposes. These losses will give rise to deferred tax assets, a significant portion of which are likely to be net operating loss carry forwards. Due to the transaction of December 9, 2013, these net operating loss deferred tax assets may be subject to limitations. Current tax laws limit the amount of loss available to be offset against future taxable income when a substantial change in ownership occurs. Therefore, the amount available to offset future taxable income may be limited. Because of these potential limitations, the Company has not recognized any deferred tax asset and has placed a full valuation allowance on such assets.

The Company may be subject to potential examination by U.S. federal, U.S. states or foreign jurisdiction authorities in the areas of income taxes. These potential examinations may include questioning the timing and amount of deductions, the nexus of income among various tax jurisdictions and compliance with U.S. federal, U.S. state and foreign tax laws. The Company’s management does not expect that the total amount of unrecognized tax benefits will materially change over the next twelve months.

Net Income (Loss) per Common Share

Basic net income (loss) per common share is computed by dividing the net income (loss) attributable to stockholders by the weighted average number of common shares outstanding during the period. Diluted net income per common share is calculated in the same manner, but also considers the impact to net income (loss) and common shares for the potential dilution from stock options, non-vested share appreciation rights and non-vested restricted shares. For the years ended December 31, 2013 and 2012, there were no potentially dilutive shares.

Use of Estimates

The preparation of combined financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the combined financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates.

The Company’s estimates of oil and natural gas reserves are, by necessity, projections based on geologic and engineering data, and there are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production and the timing of development expenditures. Reserve engineering is a subjective process of estimating underground accumulations of natural gas and oil that are difficult to measure. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. Estimates of economically recoverable natural gas and oil reserves and future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effect of regulations by governmental agencies, and assumptions governing future natural gas and oil prices, future operating costs, severance taxes, development costs and workover costs, all of which may in fact vary considerably from actual results. The future drilling costs associated with reserves assigned to proved undeveloped locations may ultimately increase to the extent that these reserves are later determined to be uneconomic. For these reasons, estimates of the economically recoverable quantities of expected natural gas and oil attributable to any particular group of properties, classifications of such reserves based on risk of recovery, and estimates of the future net cash flows may vary substantially. Any significant variance in the assumptions could materially affect the estimated quantity of the reserves, which could affect the carrying value of the Company’s oil and natural gas properties and/or the rate of depletion related to the oil and natural gas properties.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Not applicable.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The information required by this item is included in Item 15, “Exhibits Financial Statements and Financial Statement Schedules.”

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None. Previously disclosed on form 8-K and filed with the SEC on February 18, 2014.

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of December 31, 2013. Disclosure controls and procedures means controls and other procedures that are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is (a) recorded, processed, summarized and reported, within the time periods specified in the SEC rules and forms and (b) accumulated and communicated to our management, including our principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

Based on the evaluation of our disclosure controls and procedures as of December 31, 2013, our Chief Executive Officer and Chief Financial Officer concluded that, as of such date, our disclosure controls and procedures were ineffective, due to the material weaknesses in our internal control over financial reporting described below.

Management’s Annual Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2013 based on the guidelines established inInternal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

Because of its inherent limitations, internal control over financial reporting cannot provide absolute assurance of achieving financial reporting objectives. Internal control over financial reporting is a process that involves human diligence and compliance and is subject to lapses in judgment and breakdowns resulting from human failures. Internal control over financial reporting also can be circumvented by collision or improper management override. Because of such limitations, there is a risk that material misstatements may not be prevented or detected on a timely basis by internal control over financial reporting. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with established policies or procedures may deteriorate.

A material weakness is a control deficiency, or a combination of control deficiencies, that results in more than a remote likelihood that a material misstatement of the annual or interim financial statements will not be prevented or detected. As a result of our management’s assessment of the effectiveness of internal control over financial reporting, we have identified the following material weaknesses that existed as of December 31, 2013:

1. Inadequate and ineffective controls over the financial statement close process.

In conjunction with the year-end financial close, our procedures and controls to ensure that accurate financial statements in accordance with GAAP could be prepared and reviewed on timely basis were not operating effectively. Such ineffective procedures and controls include (a) ineffective segregation of duties; (b) insufficient documentation of accounting policies and procedures and retention of historical accounting portions. As a result of the above deficiencies, material and less significant post-closing adjustments were identified by our independent registered public accounting firm, Rothstein Kass, and recorded in our financial statements as of and for the year ended December 31, 2013.

2. Inadequate staffing within the accounting organization.

During 2013, there were numerous changes in our accounting personnel, both on staff and third party support. This has led to our not having a sufficient number of experienced personnel in the accounting organization to provide reasonable assurance that transactions are being recorded as necessary to ensure timely preparation of financial statements in accordance with GAAP, including the preparation of this annual report. We consider this weakness to be a material weakness in the operation of entity-level controls and operation level controls. The ineffectiveness of such controls can result in misstatement to assets, liabilities, revenues, and expenses.

Our management concluded that, due to the material weaknesses described above, we did not maintain effective internal control over financial reporting as of December 31, 2013.

3. Remedial actions

In an effort to remediate the identified deficiencies, we have commenced, and are continuing to implement, a number of changes to our internal control over financial reporting. These following changes will be made before the end of 2014:

•

We have retained an independent Board of Directors and implemented our Corporate Policies; and

•

We have retained a full time Chief Financial Officer.

Additionally, in response to the identified deficiencies, we intend to implement additional remedial measures, including but not limited to the following:

•

Hiring additional accounting personnel; and

•

Improving our documentation and training related to policies and procedures for the controls related to our significant accounts and processes.

Changes in Internal Control over Financial Reporting

Except as described above, during its assessment of our internal control over financial reporting our management identified no change in our internal control over financial reporting that occurred during the fourth quarter of 2013 that has materially affected, or is reasonably likely to affect, our internal control over financial reporting.

ITEM 9B – OTHER INFORMATION

None.

PART III

ITEM 10 – DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

See“Executive Officers, Board of Directors, Committees of the Board and Section 16(a) Beneficial Ownership Reporting Compliance” in our Proxy Statement (the “Proxy Statement”) for the Annual Meeting of Stockholders (to be filed with the SEC within 120 days after the end of the Company’s fiscal year ended December 31, 2013) which is incorporated herein by reference.

The Company’s Code of Business Conduct and Ethics and the Code of Ethics for the Chief Executive Officer, Chief Financial Officer (Code of Ethics) can be found on the Company’s internet website located at www.BreitlingEnergy.com.

ITEM 11 – EXECUTIVE COMPENSATION

Information required by this item will be contained in the Proxy Statement under the caption “Executive Compensation,” and is hereby incorporated by reference herein.

ITEM 12 – SECURITIES OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Information required by this item will be contained in the Proxy Statement under the caption “Securities Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters” and is incorporated herein by reference.

ITEM 13 – CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Information required by this item will be contained in the Proxy Statement under the caption “Certain Transactions” and “Corporate Governance” and is hereby incorporated by reference herein.

ITEM 14 – PRINCIPAL ACCOUNTANT FEES AND SERVICES

Information required by this item will be contained in the Proxy Statement under the caption “Auditors’ Fees,” and is hereby incorporated by reference.

PART IV

ITEM 15 – EXHIBITS, FINANCIAL STATEMENT SCHEDULES.

ITEM 15. Exhibits


Exhibit			Description

1			The following is an index to the financial statements and financial statement schedules that are filed in Part II, Item 8 of this report on Form 10-K.

			Report of Independent Registered Public Accounting Firm

			Combined and Consolidated Balance Sheets as of December 31, 2013 and 2012

			Combined and Consolidated Statements of Operations for each of the three years in the period ended December 31, 2013

			Combined and Consolidated Statements of Stockholders’ Equity (Deficit) for each of the three years in the Period Ended December 31, 2013

			Combined and Consolidated Statements of Cash Flows for each of the three years in the period ended December 31, 2013

			Notes to Combined and Consolidated Financial Statements

2			Schedules other than those listed above are omitted because they are not required, not applicable or the required information is included in the financial statements or notes thereto.

3		Exhibits

	3		Articles of Incorporation and Bylaws

		3.1	Amended and Restated Articles of Incorporation of Oncolin Therapeutics, Inc.

		3.2	Certificate of Amendment to Articles of Incorporation changing name from Oncolin Therapeutics, Inc. to Bering Exploration, Inc.



	3.3	Certificate of Amendment to Articles of Incorporation changing the name from Bering Exploration, Inc. to Breitling Energy Corporation.

	3.4	Bylaws of the Company (incorporated by reference from Exhibit 3.1 of the Company’s Current Report on Form 8-K, filed February 5, 2014)

10		Material contracts

	10.1	Asset Purchase Agreement among the Company, Breitling Oil & Gas Corporation and Breitling Royalties Corporation (incorporated by reference from Exhibit 10.1 of the Company’s Current Report on Form 8-K, filed December 9, 2013)

	10.2	Form of Termination Agreement and Release executed by each of the Company’s exiting executive officers (incorporated by reference from Exhibit 10.2 of the Company’s Current Report on Form 8-K, filed December 9, 2013)

	10.3	Form of Non-Transfer Agreement executed by certain of the Company’s existing stockholders (incorporated by reference from Exhibit 10.3 of the Company’s Current Report on Form 8-K, filed December 9, 2013)

	10.4	Form of Release executed by certain of the Company’s existing stockholders (incorporated by reference from Exhibit 10.4 of the Company’s Current Report on Form 8-K, filed December 9, 2013)

	10.5	Form of Release executed by the Company, Kevan Casey and his affiliates. (incorporated by reference from Exhibit 10.5 of the Company’s Current Report on Form 8-K, filed December 9, 2013)

	10.6	Non-Transfer Agreement executed by Breitling Oil & Gas Corporation and Breitling Royalties Corporation (incorporated by reference from Exhibit 10.6 of the Company’s Current Report on Form 8-K, filed December 9, 2013)

	10.7	Administrative Services Agreement between the Company, Crude Energy, LLC and Crude Royalties, LLC (incorporated by reference from Exhibit 10.7 of the Company’s Current Report on Form 8-K, filed December 9, 2013)

14		Code of Ethics

	14.1	Code of Ethics for Financial Officers (incorporated by reference to Exhibit 99.1 of the Company’s Current Report on Form 8-K, filed February 5, 2014)

21		Subsidiaries of the Company

	21.1	Subsidiaries of the Company

31		Rule 13a-14(a) Certifications

	31.1	Certification of Chief Executive Officer pursuant to Rule 13(a)-14(a)

	31.2	Certification of Chief Financial Officer pursuant to Rule 13(a)-14(a)

32		Section 1350 Certifications of Chief Executive and Financial Officers pursuant to Rule 13(a)-14(b)

	32.1	Certification of Chief Executive Officer

	32.2	Certification of Chief Financial Officer

99		Additional Exhibits

	99.1	Reserve Report Summary prepared by Mire & Associates as of December 31, 2013

101		Interactive Data Files

*	Not applicable to this filing

SIGNATURES

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


	Breitling Energy Corporation

Date: March 31, 2014	By:	/s/ Chris Faulkner
	Chief Executive Officer and President (Principal Executive)

Date: March 31, 2014	By:	/s/ Rick Hoover
	Financial Officer (Principal Financial and Accounting Officer)

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

Date: March 31, 2014	By:	/s/ Chris Faulkner
		Chris Faulkner, Chief Executive Officer, President and Chairman of the Board of Directors (Principal Executive and Authorized Officer)

Date: March 31, 2014	By:	/s/ Jeremy S. Wagers
		Jeremy S. Wagers, Chief Operating Officer & General Counsel

Date: March 31, 2014	By:	/s/ Rick Hoover
		Rick Hoover, Chief Financial Officer (Principal Financial and Accounting Officer)

Date: March 31, 2014	By:	/s/ Jonathan S. Huberman
		Jonathan S. Huberman, Independent Director

Date: March 31, 2014	By:	/s/ Richard H. Mourglia
		Richard H. Mourglia, Independent Director

Date: March 31, 2014	By:	/s/ Chris E. Williford
	Chris E. Williford, Independent Director

Item 15.

Exhibits and Financial Statement Schedules

INDEX TO FINANCIAL STATEMENTS


	Page
Report of Independent Registered Public Accounting Firm		F-2
Consolidated and Combined Balance Sheets as of December 31, 2013 and 2012		F-3
Consolidated and Combined Statements of Operations for the Years Ended December 31, 2013 and 2012		F-4
Consolidated and Combined Statements of Stockholders’ Equity (Deficit) for the Years Ended December 31, 2013 and 2012		F-5
Consolidated and Combined Statements of Cash Flows for the Years Ended December 31, 2013 and 2012		F-6
Notes to Consolidated Financial Statements		F-7

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Stockholders of Breitling Energy Corporation:

We have audited the accompanying consolidated and combined balance sheets of Breitling Energy Corporation (the “Company”) as of December 31, 2013 and 2012 and the related consolidated and combined statements of operations, changes in stockholders’ deficit and cash flows for each of the years in the two-year period ended December 31, 2013. These consolidated and combined financial statements are the responsibility of the management of the Company. Our responsibility is to express an opinion on these consolidated and combined financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated and combined financial statements referred to above present fairly, in all material respects, the financial position of Breitling Energy Corporation as of December 31, 2013 and 2012, and the results of their operations and their cash flows for each of the years in the two-year period ended December 31, 2013, in conformity with accounting principles generally accepted in the United States of America.

/s/ Rothstein Kass

Dallas, Texas

March 31, 2014

F-2

BREITLING ENERGY CORPORATION

CONSOLIDATED AND COMBINED BALANCE SHEETS


	December 31,
	2013			2012

ASSETS

Current assets
Cash	$	606,715		$	4,668,839
Other		898			1,850


Total current assets		607,613			4,670,689


Other assets
Equity investment		3,561			12,205
Other property and equipment, net of depreciation		153,621			128,258


Total other assets		157,182			140,463


Total assets	$	764,795		$	4,811,152


LIABILITIES AND STOCKHOLDERS’ DEFICIT

Current liabilities
Accounts payable and accrued liabilities	$	3,119,727		$	2,783,761
Joint interest revenues payable		151,153			51,559
Deferred revenue from turnkey contracts		4,609,041			6,562,426
Current asset retirement obligations		16,495			22,905


Total current liabilities		7,896,416			9,420,651


Long-term liabilities
Asset retirement obligations		20,842			20,842


Stockholders’ deficit
Common stock, $.001 par value; 500,000,000 shares authorized; 498,884,626 and 461,863,084, respectively; shares issued and outstanding		498,884			461,863
Accumulated deficit		(7,651,347	)		(5,092,204	)


Total stockholders’ deficit		(7,152,463	)		(4,630,341	)


Total liabilities and stockholders’ deficit	$	764,795		$	4,811,152

See accompanying notes to the consolidated and combined financial statements.

F-3

BREITLING ENERGY CORPORATION

CONSOLIDATED AND COMBINED STATEMENTS OF OPERATIONS


	Year Ended December 31,
	2013			2012

Revenues
Turnkey drilling	$	14,914,114		$	13,085,714
Gain on sale of oil & natural gas royalties		11,275,402			192,093
Oil, natural gas, and related product sales		461,772			130,314


Total revenues		26,651,288			13,408,121


Expenses
Turnkey drilling and completion		5,437,880			6,009,535
General and administrative		9,629,938			5,630,436
Marketing		7,681,013			5,135,122
Professional fees		6,060,103			2,083,811
Lease operating		130,072			117,459
Depreciation and amortization		143,388			14,817


Total expenses		29,082,394			18,991,180


Operating loss		(2,431,106	)		(5,583,059	)


Income tax expense
State tax provision		91,016			101,838


Net loss	$	(2,522,122	)	$	(5,684,897	)


Net loss per basic and diluted common share	$	(0.01	)	$	(0.01	)


Weighted average basic and diluted common shares outstanding		462,057,484			461,863,084

See accompanying notes to the consolidated and combined financial statements.

F-4

BREITLING ENERGY CORPORATION

CONSOLIDATED AND COMBINED STATEMENTS OF CHANGES IN STOCKHOLDERS’ DEFICIT


For the Years Ended December 31, 2013 and 2012
	Common Stock ($.001 Par Value)(1)				Net Deficit			Total
	Shares		Amount		Net Deficit			Total

Balances, January 1, 2012		461,863,084	$	461,863	$	592,693		$	1,054,556

Net loss						(5,684,897	)		(5,684,897	)


Balances, December 31, 2012		461,863,084		461,863	$	(5,092,204	)	$	(4,630,341	)

Net loss						(2,522,122	)		(2,522,122	)

Recapitalization with Bering Exploration Inc.		37,020,542	$	37,021		(37,021	)		—


Balances, December 31, 2013		498,883,626	$	498,884	$	(7,651,347	)	$	(7,152,463	)

(1)	Balances have been adjusted to reflected to the recapitalization with Bering Exploration Inc.

See accompanying notes to the consolidated and combined financial statements.

F-5

BREITLING ENERGY CORPORATION

CONSOLIDATED AND COMBINED STATEMENTS OF CASH FLOWS


	Year Ended December 31,
	2013			2012

Cash flows from operating activities
Net loss	$	(2,522,122	)	$	(5,684,897	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depreciation and amortization		143,388			14,817
Accretion of asset retirement obligation		2,294			3,058
Net loss from equity investment		40,394			32,164
Increase (decrease) in cash attributable to changes in operating assets and liabilities:
Related party receivable		952			(1,850	)
Accounts payable and other adjustments		335,966			1,810,332
Joint interest revenues payable		99,594			51,559
Deferred revenues		(1,953,385	)		4,722,686


Net cash provided by (used in) operating activities		(3,852,919	)		947,869


Cash flows from investing activities
Acquisition of other property and equipment		(177,455	)		(124,906	)
Investment in equity investment		(31,750	)		(35,000	)


Net cash used by investing activities		(209,205	)		(159,906	)


Net increase (decrease) in cash		(4,062,124	)		787,963

Cash, beginning of period		4,668,839			3,880,876


Cash, end of period	$	606,715		$	4,668,839

See accompanying notes to the consolidated and combined financial statements.

F-6

Breitling Energy Corporation

CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

DECEMBER 31, 2013 and 2012

1. Organization and nature of operations

Breitling Energy Corporation, (formerly, Bering Exploration Inc., formerly, Oncolin Therapeutics, Inc., formerly, Edgeline Holdings, Inc., formerly, Dragon Gold Resources, Inc., formerly Folix Technologies, Inc.) (“we”, “our” or the “Company”) was incorporated in the state of Nevada on December 13, 2000 under the name “Folix Technologies, Inc.” On August 18, 2004, the Company changed its name to Dragon Gold Resources, Inc. On June 22, 2007, the Company changed its name to Edgeline Holdings, Inc. and on March 11, 2008 to Oncolin Therapeutics, Inc. On September 7, 2010, the Company changed its name to Bering Exploration, Inc. and on January 20, 2014, to Breitling Energy Corporation.

On December 9, 2013 (the “Acquisition Date”), the Company entered into an Asset Purchase Agreement (the “Purchase Agreement”) with Breitling Oil and Gas Corporation, a Texas corporation (“O&G”) and Breitling Royalties Corporation, a Texas corporation (“Royalties,” and collectively with O&G, the “Predecessors”). Pursuant to the Purchase Agreement, the Company issued to the Predecessors 461,863,084 shares of Common Stock, in exchange for substantially all of the oil and gas assets owned by the Predecessors (the “Transaction”). In connection with the closing of the Transaction, all of the Company’s outstanding convertible notes were converted into Common Stock. The shares of Common Stock issued to the Predecessors represent approximately 92.5% of the shares of Common Stock outstanding following the closing of the Transaction (the “Closing”). The Transaction results in the owners of the Company (the “accounting acquirer”) having actual or effective operating control of Bering after the transaction, with the shareholders of Bering (the “legal acquirer”) continuing only as passive investors. The closing of the Transaction did not affect the number of shares of Common Stock held by the Company’s existing public stockholders.

The Company was considered the acquirer for accounting purposes because it obtained effective control of Bering. Breitling did not have a change in control since Breitling’s operations comprise the ongoing operations of the combined entity, its senior management became the senior management of the combined entity, and its former owners own a majority voting interest in the combined entity and are able to elect a majority of the combined entity’s board of directors. Accordingly, the Business Combination does not constitute the acquisition of a business for purposes of Financial Accounting Standards Board’s Accounting Standard Codification 805, “Business Combinations,” or ASC 805. As a result, the assets and liabilities of Breitling are carried at historical cost and the Company has not recorded any step-up in basis or any intangible assets or goodwill as a result of the Business Combination. The historical financial statements presented herein are that of Breitling.

2. Liquidity

3. Summary of significant accounting policies

Basis of Presentation

The consolidated and combined financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America (“GAAP”).

These consolidated and combined financial statements were approved by management and available for issuance on March 31, 2013. Subsequent events have been evaluated through this date.

Principles of Consolidation and Combination

The consolidated and combined financial statements reflect the historical combined results of O&G and Royalties prior to the reverse recapitalization completed on December 9, 2013, and the consolidated results of the Company thereafter. All intercompany and interentity transactions have been eliminated in the consolidation and combination.

Fair Value Measurements

The Company has adopted and follows ASC 820,Fair Value Measurements and Disclosures, for measurement and disclosures about fair value of its financial instruments. ASC 820 establishes a framework for measuring fair value in GAAP, and expands disclosures about fair value measurements. To increase consistency and comparability in fair value measurements and related disclosures, ASC 820 establishes a fair value hierarchy which prioritizes the inputs to valuation techniques used to measure fair value into three (3) broad levels. The fair value hierarchy gives the highest priority to quoted prices (unadjusted) in active markets for identical assets or liabilities and the lowest priority to unobservable inputs. The three (3) levels of fair value hierarchy defined by ASC 820 are:

Level 1 — Inputs are unadjusted, quoted prices in active markets for identical assets or liabilities at the measurement date.

Level 2 — Inputs (other than quoted market prices included in Level 1) are either directly or indirectly observable for the asset or liability through correlation with market data at the measurement date and for the duration of the instrument’s anticipated life.

Level 3 — Inputs reflect management’s best estimate of what market participants would use in pricing the asset or liability at the measurement date. Consideration is given to the risk inherent in the valuation technique and the risk inherent in the inputs to the model. Valuation of instruments includes unobservable inputs to the valuation methodology that are significant to the measurement of fair value of assets or liabilities.

As defined by ASC 820, the fair value of a financial instrument is the amount at which the instrument could be exchanged in a current transaction between willing parties, other than in a forced or liquidation sale, which was further clarified as the price that would be received to sell an asset or paid to transfer a liability (“an exit price”) in an orderly transaction between market participants at the measurement date. The carrying amounts of the Company’s financial assets and liabilities, such as cash and cash equivalents, oil and natural gas sales receivable, and accounts payable and accrued liabilities, approximate their fair values because of the short maturity of these instruments.

F-7

Cash

The Company maintains its cash balances in financial institutions which are insured by the Federal Deposit Insurance Corporation (“FDIC”). The interest bearing cash accounts maintain FDIC coverage of up to $250,000 per institution. As of December 31, 2013 and 2012, the Company did not have any amounts in excess of its FDIC coverage.

Oil and Gas Natural Gas Properties

The Company uses the full-cost method of accounting for its oil and natural gas producing activities as further defined under ASC 932,Extractive Activities -Oil and natural gas. Under these provisions, all costs incurred for both successful and unsuccessful exploration and development activities, including salaries, benefits and other internal costs directly identified with these activities, and oil and natural gas property acquisitions are capitalized. All costs related to production, general corporate overhead or similar activities are expensed as incurred.

Proved properties are amortized using the units of production method (“UOP”). The UOP calculation, in its simplest terms, multiplies the percentage of estimated proved reserves produced at year end by the cost of those reserves. The amortization base in the UOP calculation includes the sum of proved property, net of accumulated depreciation, depletion and amortization (“DD&A”), estimated future development costs (future costs to access and develop reserves) and asset retirement costs that are not already included in oil and natural gas property, less related salvage value.

The cost of unproved properties and properties under development are excluded from the amortization calculation until it is determined whether or not proved reserves can be assigned to such properties or until development projects are placed in service. Geological and geophysical costs not associated with specific properties are recorded to proved properties. Unproved properties and properties under development are reviewed for impairment at least quarterly. Where proved reserves exist, exploratory drilling costs associated with dry holes are transferred to proved properties immediately upon determination that a well is dry and amortized accordingly. As of December 31, 2013 and 2012, no unproved properties or properties under development were included in the oil and natural gas properties of the accompanying combined financial statements.

Under the full-cost method of accounting, the net book value of oil and natural gas properties, less related deferred income taxes, may not exceed a calculated “ceiling.” The ceiling limitation is the estimated after-tax future net cash flows from proved oil and natural gas reserves, discounted at 10 percent per annum based on industry standards and adjusted for cash flow hedges. Estimated future net cash flows exclude future cash outflows associated with settling accrued asset retirement obligations. Any excess of the net book value of proved oil and gas properties, less related deferred income taxes, over the ceiling is charged to expense and reflected as additional DD&A in the accompanying combined statements of operations. For the years ended December 31, 2013, and 2012, no impairment charge occurred.

Other Property and Equipment

Impairment of Long-Lived Assets

The Company assesses the impairment of long-lived assets when circumstances indicate that the carrying value may not be recoverable. The Company determines if impairment has occurred through adverse changes. When it is determined that the estimated future net cash flows of an asset will not be sufficient to recover its carrying amount, an impairment loss must be recorded to reduce the carrying amount to its estimated fair value. For the years ended December 31, 2013, and 2012, no circumstances indicated an unrecoverable carrying value of the long-lived assets.

F-8

Asset Retirement Obligations

Asset retirement obligations are estimated at the present value of expected future net cash flows and are discounted using the Company’s credit adjusted risk free rate. The Company uses unobservable inputs in the estimation of asset retirement obligations that include, but are not limited to, costs of labor, costs of materials, profits on costs of labor and materials, the effect of inflation on estimated costs, and the discount rate. Accordingly, asset retirement obligations are considered a Level 3 measurement under ASC 820. Additionally, because of the subjectivity of assumptions and the relatively long lives of the Company’s wells, the costs to ultimately retire the Company’s wells may vary significantly from prior estimates.

Revenue Recognition

BOG enters into turnkey drilling contracts with outside working interest owners to develop leasehold acreage BOG has acquired. In these arrangements, BOG acquires a working interest in a prospect pursuant to an oil and gas lease, and then sells a portion of a well’s working interest on the acquired lease to outside working interest owners with a turnkey drilling agreement. Title to the lease property is not conveyed to the outside working interest owners. The outside working interest owner purchases a working interest directly in the well bore. The working interest purchased in the turnkey drilling agreements is an ownership interest in which the working interest holder is responsible to bear the cost of drilling, testing, completing, equipping and operating the well. BOG typically sells 100% of the working interests and has a third-party operate the projects.

In a turnkey drilling agreement, BOG agrees to sell a percentage of the well’s working interest to outside working interest owners and to pay for all costs of identifying, acquiring mineral rights to, drilling, testing, completing and equipping the well for initial production at a fixed price. If the actual costs of these activities exceed the turnkey price BOG charged to the outside working interest owners, BOG is responsible to pay the excess cost. If the actual costs are less than the turnkey price, BOG retains the excess of the turnkey price over actual costs. BOG bears 100% of the risk should actual cost exceed estimated costs of a project for both BOG’s working interest and the working interest sold to outside working interest owners in a well. When the well is completed as a commercially productive well, BOG and the outside working interest owners bear the cost of operating the well according to each party’s proportionate working interest percentage.

When BOG sponsors a turnkey drilling project for sale, outsider working interest owners enter into a signed contract with BOG. In this agreement, the outside working interest owner agrees to share in the prospect acquisition costs and drilling costs. The prospect acquisition costs include geophysical & geographical costs, costs to lease the mineral rights, and other costs as required so the drilling of the project can proceed. Drilling costs are those costs incurred to build the drilling location, drill, and log the well, and if the well is successful, to complete and test the well. Once drilling begins, the well is generally completed within 30 to 60 days. BOG bases the price at which it sells working interests under the turnkey drilling agreement on its estimates of the costs described above, and is based upon the historical cost to complete those activities. Since the outside working interest owner’s interest in the prospect is limited to the well, and not the lease, the outside working interest owner does not have a legal right to participate in additional wells drilled within the same lease. However it is the Company’s policy to offer to outside working interest owners in a successful well the right to participate in subsequent wells at the same percentage level as their working interest investment in the prior successful well with similar turnkey drilling agreement terms.

The Company recognizes revenues associated with its turnkey contracts when development steps outlined in the contract have been achieved on a well under development. Revenues are earned in accordance with the turnkey contracts when the following development steps are met on the respective oil and natural gas well under development: completion of the drilling/testing of the well and completion of the completion/equipping phase of the well. Any cash collected under the turnkey contracts that have not met one of the development steps is deferred and presented as deferred revenue from turnkey contracts on the combined balance sheets. The turnkey revenue is recorded on a gross basis with the associated turn key drilling costs, as agreed to in the turnkey contract, being deferred until the associated revenue is recognized. Early recognition of loss is recorded if it is determined that the well cost will exceed the applicable revenue received on the specific well. Total turnkey drilling revenues recognized for the for years ended December 31, 2013 and 2013 was approximately $14,910,000 and $13,086,000 respectively. As of December 31, 2013 and 2012, the Company had approximately $4,609,000 and $6,562,000 ,in deferred turnkey drilling revenue, respectively.

Sales-Based Taxes

Lease Operating Expenses

Lease operating expenses represents severance and production taxes, field personnel salaries, saltwater disposal, ad valorem taxes, repairs and maintenance, and other operating expenses. Lease operating expenses are expensed as incurred.

General and Administrative Expense

General and administrative expenses are reported net of recoveries from owners in properties operated by the Company and net of amounts related to lease operating activities or capitalized pursuant to the full-cost method of accounting.

F-9

Income Taxes

Prior to the Acquisition Date, the Company elected to be treated as an “S” corporation under Subchapter S of the Internal Revenue Code. As such, income or loss of the Company, in general, is allocated to the shareholders for inclusion in their income tax return. Accordingly, the Company has not provided for federal, state, or local income taxes prior to this date. Texas does have a “margin tax” that remains with the corporate entity; therefore the Company has reflected any expense associated with the Texas margin tax as income taxes for financial statement purposes.

Subsequent to the Acquisition Date, income taxes are recorded in accordance with FASB ASC 740, “Income Taxes”. This statement requires the recognition of deferred tax assets and liabilities to reflect the future tax consequences of events that have been recognized in the financial statements or tax returns. Measurement of the deferred items is based on enacted tax laws. In the event the future consequences of differences between financial reporting bases and tax bases of the Company’s assets and liabilities result in a deferred tax asset, ASC 740 requires an evaluation of the probability of being able to realize the future benefits indicated by such assets. A valuation allowance related to a deferred tax asset is recorded when it is more likely than not that some portion or the entire deferred tax asset will not be realized.

The Company has filed all of their tax returns. As of December 31, 2013, there is approximately $14 million in accumulated losses for tax purposes. These losses will give rise to deferred tax assets, a significant portion of which are likely to be net operating loss carry forwards. Due to the transaction of December 9, 2013, these net operating loss deferred tax assets may be subject to limitations. Current tax laws limit the amount of loss available to be offset against future taxable income when a substantial change in ownership occurs. Therefore, the amount available to offset future taxable income may be limited. Because of these potential limitations, the Company has not recognized any deferred tax asset and has placed a full valuation allowance on such assets.

In accordance with GAAP, the Company is required to determine whether a tax position of the Company is more likely than not to be sustained upon examination by the applicable taxing authority, including resolution of any related appeals or litigation processes, based on the technical merits of the position. The tax benefit to be recognized is measured as the largest amount of benefit that is greater than fifty percent likely of being realized upon ultimate settlement. De-recognition of a tax benefit previously recognized could result in the Company recording a tax liability that would reduce stockholders equity. Based on its analysis, the Company has accrued a liability relating to uncertain tax positions for amounts totaling approximately $728,000 and $309,000 as of December 31, 2013 and 2012 respectively. This policy also provides guidance on thresholds, measurement, de-recognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition that is intended to provide better financial statement comparability among different entities. Management’s conclusions regarding this policy may be subject to review and adjustment at a later date based on factors including, but not limited to, on-going analyses of and changes to tax laws, regulations and interpretations thereof. Currently, the Company, along with that of Bering’s historical tax returns, are subject to examination for the years ending December 31, 2013, 2012, and 2011.

Net Income (Loss) per Common Share

Basic net income (loss) per common share is computed by dividing the net income (loss) attributable to stockholders by the weighted average number of common shares outstanding during the period. Diluted net income per common share is calculated in the same manner, but also considers the impact to net income (loss) and common shares for the potential dilution from stock options, nonvested share appreciation rights and non-vested restricted shares. For the years ended December 31, 2013 and 2012, there were no potentially dilutive shares.

Use of Estimates

The preparation of combined financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the combined financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

New Accounting Pronouncements

In January 2013, the Financial Accounting Standards Board (“FASB”) issued ASC Update No. 2013-01 (“ASC No. 2013-01”), The objective of ASC No. 2013-01 is to clarify that the scope of Accounting Standards Update No. 2011-11 ,Disclosures about Offsetting Assets and Liabilities (“ASC No. 2011-11”), would apply to derivatives including bifurcated embedded derivatives, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions that are either offset or are subject to a master netting arrangement or similar agreement. ASC No. 2011-11, issued in December 2011, requires that entities disclose both gross and net information about instruments and transactions eligible for offset in the statement of financial position as well as instruments and transactions subject to an agreement similar to a master netting arrangement. In addition, the standard requires disclosure of collateral received and posted in connection with master netting agreements or similar arrangements. The amendments are effective for annual reporting periods beginning on or after January 1, 2013, and interim periods within those annual periods. The disclosures required by the amendments are required to be applied retrospectively for all comparative periods presented. The Company does not believe the adoptions of this update will have a material impact on the Company’s combined financial statements.

F-10

3. Fair Value Measurements

As of December 31, 2013, and 2012, the Company had no assets which were measured at fair value.

The following tables present information about the Company’s liabilities measured at fair value as of December 31, 2013, and 2012


	Level 1 (unaudited)	Level 2 (unaudited)	Level 3 (unaudited)		Balance as of December 31, 2013
Liabilities (at fair value):
Asset retirement obligations	$	$	$	37,337	$	37,337


					Balance as of
	Level 1	Level 2	Level 3		December 31, 2012

Liabilities (at fair value):
Asset retirement obligations	$	$	$	43,747	$	43,747

4. Other property and equipment

The following table presents a summary of the Company’s other property and equipment:


	December 31,
	2013			2012
Other equipment
Furniture	$	194,275		$	112,565
Vehicles		25,708			25,708
Software		21,047			6,017
Office equipment		71,627			5,434
Less: Accumulated depreciation		(159,036	)		(21,466	)

Total other equipment, net of accumulated deprecation	$	153,621		$	128,258

F-11

5. Asset retirement obligations

The Company has recognized the fair value of its asset retirement obligations related to the future costs of plugging, abandonment, and remediation of oil and natural gas producing properties. The present value of the estimated asset retirement obligations has been capitalized as part of the carrying amount of the related oil and natural gas properties. The liability has been accreted to its present value as of the end of each period. At December 31, 2013 and 2012, the Company evaluated 213 and 210 wells, and has determined a range of abandonment dates between December 2012 and December 2051. As of December 31, 2013, and 2012, the Company realized $10,500 in Asset retirement obligations.


	Year Ended December 31,
	2013			2012
Asset retirement obligations, beginning of period	$	43,747		$	40,689
Additions to asset retirement obligation
Liabilities settled during the period
Accretion of discount		2,294			3,058
Revision of estimate		(8,704	)


Asset retirement obligations, end of period	$	37,337		$	43,747

6. Stockholders’ Deficit

On December 9, 2013, the Company entered into the Purchase Agreement with Bering. Pursuant to the Purchase Agreement, Bering issued to the Company 461,863,084 shares of Bering’s common stock, in exchange for substantially all of the oil and gas assets owned by the Company. In connection with the closing of the Transaction, all of the Bering’s outstanding convertible notes were converted into Bering common stock. The shares of Bering common stock issued to the Company represent approximately 92.5% of the shares of Bering common stock on a fully diluted basis following the Closing. The Transaction results in the Company being the accounting acquirer as the Company has actual operating control of Bering after the transaction. Accordingly, the Consolidated and combined statement of changes in stockholder’s deficit reflects the effects of this reverse recapitalization as if it look place effective January 1, 2012.

7. Income taxes

The Company and its subsidiaries file a consolidated federal income tax return.

The Company’s effective income tax rate of 34% for the years ended December 31, 2013 and 2012 respectively differed from the federal statutory rate due to valuation adjustments of 34% for the years ended December 31, 2013 and 2012 respectively.

The tax accruals are reflected as follows:


For the year ended December 31,	2013			2012
Income taxes (benefit)	$	(866,000	)	$	(1,933,000	)
Changes in valuation allowance		866,000			1,933,000

	$	0		$	0

Deferred tax assets and liabilities are as follows as of December 31:


	2013			2012
Deferred tax assets relating to:
Net operating loss carryforward	$	4,764,000		$	3,898,000
Less valuation allowance		(4,764,000	)		(3,898,000	)

Total deferred tax asset		0			0

A valuation allowance for deferred tax assets is required when it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of this deferred tax asset depends on the Company’s ability to generate sufficient taxable income in the future. Management believes it is more likely that not that the net deferred tax asset will not be realized by future operating results. The valuation allowance increased by approximately $866,000, and $1.9 million for the years ended December 31, 2013 and 2012, respectively.

At December 31, 2013, the Company had net operating loss carry-forwards for federal income tax purposes of approximately $4.8 million, these carry-forwards will need to be reviewed further, and may be limited to the rate of application or utilization after consideration of the recapitalization and prior history.

The Company routinely assesses potential uncertain tax positions and, if required, establishes accruals for such amounts. Only tax positions that meet the more-likely-than-not recognition threshold are recorded.

8. Commitment and Contingencies

Legal

From time-to-time, the Company may become subject to proceedings, lawsuits and other claims in the ordinary course of business including working interest rescissions and operator disputes. Such matters are subject to many uncertainties, and outcomes are not predictable with assurance. As of December 31, 2013 and 2012, the Company accrued $166,000 to settle working interest rescissions.

Oil and Natural Gas Regulations

The Company is subject to various possible contingencies that arise primarily from interpretation of federal and state laws and regulations affecting the oil and natural gas industry. Such contingencies include differing interpretations as to the prices at which oil and natural gas sales may be made, the prices at which royalty owners may be paid for production from their leases, environmental issues and other matters. Although management believes that it has complied with the various laws and regulations, administrative rulings and interpretations thereof, adjustments could be required as new interpretations and regulations are issued. In addition, environmental matters are subject to regulation by various federal and state agencies.

Office Lease

The Company leases its primary office space under an operating lease which expires in 2020. Lease expense was approximately $110,000 for the year ended December 31, 2013 and approximately $83,000 for the year ended December 31, 2012.

Aggregate future minimum annual rental payments in the years subsequent to December 31, 2013 are as follows:


Year ending December 31,
2014		136,000
2015		139,000
2016		143,000
2017		147,000
Thereafter		386,000

Total future minimum rental payments	$	951,000

F-12

BREITLING ENERGY CORPORATION

SUPPLEMENTAL INFORMATION

Costs Incurred

The following table summarizes costs incurred in oil and natural gas property acquisition, exploration, and development activities. Property acquisition costs those incurred to purchase lease or otherwise acquire property, including both undeveloped leasehold and the purchase of reserves in place. Exploration costs include costs of identifying areas that may warrant examination and examining specific areas that are considered to have prospects containing oil and natural gas reserves, including costs of drilling exploratory wells, geological and geophysical costs, and carrying costs on undeveloped properties. Development costs are incurred to obtain access to proved reserves, including the cost of drilling development wells, and to provide facilities for extracting, treating, gathering and storing oil and natural gas.

Costs incurred (capitalized and charged to expense) in oil and natural gas activities for the years ended December 31, 2013 and 2012 were as follows:


	Year ended December 31, 2013		Year ended December 31, 2012
Acquisitions	$	3,806,516	$	16,321,566
Exploration
Development		1,631,364		3,447,611

Total costs incurred	$	5,437,880	$	19,769,177

Oil and Natural Gas Operating Results

Results of operations from oil and natural gas producing activities for the years ended December 31, 2012 and 2011, excluding Company overhead and interest costs, were as follows:


	Year ended December 31, 2013			Year ended December 31, 2012
Oil, natural gas and related product sales	$	461,772		$	130,314
Lease operating costs		(121,892	)		(83,446	)
Production taxes		(8,180	)		(34,013	)

Results of operations from oil and natural gas producing activities	$	331,700		$	12,855

Proved Reserves Methodology

The Company’s estimated proved reserves, as of December 31, 2013 and 2012, are made in accordance with the SEC’s final rule,Modernization of Oil and Gas Reporting,which amended Rule 4-10 of Regulation S-X (the “Final Rule”). As defined by the Final Rule, proved reserves are 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 in future years from known reservoirs under existing economic conditions, operating methods, and government regulations. Projects to extract the hydrocarbons must have commenced or an operator must be reasonably certain that it will commence the projects within a reasonable time. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the projects. Further requirements for assignment of estimated proved reserves include the following:

The area of a reservoir considered proved includes (A) that portion delineated by drilling and defined by natural gas, oil, and/or water contacts, if any; and (B) 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 and highest known oil seen in well penetrations unless geoscience, engineering, or performance data and reliable technology establishes a lower or higher contact with reasonable certainty. Reliable technologies are any grouping of one or more technologies (including computational methods) that have been field-tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

Reserves which can be produced economically through applications of improved recovery techniques (including, but not limited to fluid injections) are included in the proved classification when 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, and other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based.

Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The prices used are the average crude oil and natural gas prices during the twelve 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.

Reserves engineering is a subjective process of estimating underground accumulations of crude oil, condensate, natural gas, and natural gas liquids that cannot be measured in an exact manner. The accuracy of any reserves estimate is a function of the quality of available date and of engineering and geological interpretation and judgment. The reserves actually recovered, the timing of production of those reserves, as well as operating costs and the amount and timing of development expenditures may be substantially different from original estimates. Revisions result primarily from new information obtained from development drilling, production history, field tests, and data analysis and from changes in economic factors including expectation and assumptions as to availability of financing for development projects.

Reserve Quantity Information

The following table presents the Company’s estimate of its proved oil and gas reserves all of which are located in the United States. The estimates have been prepared with the assistance of Mire & Associates Inc., an independent petroleum consultant. Oil reserves, which include condensate and natural gas liquids, are stated in barrels and gas reserves are stated in thousands of cubic feet.


	Crude Oil (Bbl)			Natural Gas (Mcf)
PROVED-DEVELOPED AND UNDEVELOPED RESERVES
December 31, 2012		106,630			308,850

Revisions of previous estimates		(18,847	)		4,201
Extensions and discoveries		48,080			158,100
Acquisitions of reserves		20,750			62,050

Sales of reserves
Production		(5,863	)		(7,271	)

December 31, 2013		150,750			525,930

PROVED DEVELOPED RESERVES
December 31, 2013		84,580			373,130

December 31, 2012		66,460			129,310

F-13

Approximately $24,000 was spent during 2013 related to proved undeveloped reserves that were transferred to proved developed reserves. Estimated future development costs relating to the development of proved undeveloped reserves are projected to be approximately $32,500 for 2014. All proved undeveloped drilling locations are scheduled to be drilled prior to the end of 2015. Future cash flows are computed by applying a first-day-of-the-month 12-month average price of natural gas (Henry Hub) and oil (West Texas Intermediate) to year end quantities of proved natural gas and oil reserves. Future operating expenses and development costs are computed primarily by the Company’s petroleum engineers by estimating the expenditures to be incurred in developing and producing the Company’s proved natural gas and oil reserves at the end of the year, based on year end costs and assuming continuation of existing economic conditions. For the year ended December 31, 2013, the oil and natural gas prices were applied at $96.91/Bbl and $3.67/MMBtu, respectively, in the standardized measure. For the year ended December 31, 2012, the oil and natural gas prices were applied at $94.71/Bbl and $2.85/MMBtu, respectively, in the standardized measure.

Standardized Measure of Discounted Future Net Cash Flow and Changes Therein Relating to Proved Oil and Gas Reserves

The following tables, which presents a standardized measure of discounted future cash flows and changes therein relating to proved oil and gas reserves as of December 31, 2013 and 2012, for the years ended December 31, 2013 and 2012, is presented pursuant to ASC 932. In computing this data, assumptions other than those required by the Financial Accounting Standards Board could produce different results. Accordingly, the data should not be construed as being representative of the fair market value of the Company’s proved oil and gas reserves.

A discount factor of 10 percent was used to reflect the timing of future net cash flows. The standardized measure of discounted future net cash flows is not intended to represent the replacement costs or fair value of the Company’s natural gas and oil properties. An estimate of fair value would take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs, and a discount factor more representative of time value of money and the risks inherent in reserve estimates of natural gas and oil producing operations. There have been no estimates for future plugging and abandonment costs.

Standardized Measure of Discounted Future Net Cash Flows as of December 31, 2013


Future cash inflows	$	18,149,790
Less: Future production costs		(2,588,090	)
Future development costs		(32,500	)
Future income tax expense		(5,279,928	)

Future net cash flows		10,249,272
10% discount factor		(5,339,501	)

Standardized measure of discounted future net cash inflows	$	4,909,771

Estimated future development cost anticipated for following two years on existing properties	$	32,500

Changes in Standardized Measure of Discounted Future Net Cash Flows for the Year Ended December 31, 2013


Beginning of year	$	4,485,462
Sales of oil and natural gas, net of production costs		(331,700	)
Net changes in prices and production costs		(86,294	)
Development costs incurred during the year		(24,000	)
Changes in future development costs		0
Extensions, discoveries, and improved recoveries		2,624,270
Revisions of previous quantity estimates		(531,051	)
Accretion of discount		467,842
Net change in income taxes		(3,148,534	)
Purchases and sale of mineral interests		1,104,390
Timing and other		349,386

End of year	$	4,909,771

F-14

Standardized Measure of Discounted Future Net Cash Flow and Changes Therein Relating to Proved Oil and Gas Reserves (continued)

Standardized Measure of Discounted Future Net Cash Flows as of December 31, 2012


Future cash inflows	$	12,053,050
Less: Future production costs		(1,561,000	)
Future development costs		(56,500	)
Future income tax expense		(104,355	)

Future net cash flows		10,331,195
10% discount factor		(5,845,733	)

Standardized measure of discounted future net cash inflows	$	4,485,462

Estimated future development cost anticipated for following two years on existing properties	$	56,500

Changes in Standardized Measure of Discounted Future Net Cash Flows for the Year Ended December 31, 2012


Beginning of year	$	1,535,467
Sales of oil and natural gas, net of production costs		(12,855	)
Net changes in prices and production costs		(216,011	)
Development costs incurred during the year		42,000
Changes in future development costs		(51,118	)
Extensions, discoveries, and improved recoveries
Revisions of previous quantity estimates		182,078
Accretion of discount		271,027
Net change in income taxes		22,584
Purchases and sale of mineral interests		2,954,880
Timing and other		(242,590	)

End of year	$	4,485,462

Significant Changes in Reserves for the Year Ended December 31, 2013

Extensions, discoveries, and improved recoveries: During the year ended December 31, 2013, the Company had extensions and discoveries of 48,080 Bbl of crude oil and 158,100 Mcf of natural gas from primarily newly identified drilling opportunities in the oil and natural gas reservoirs.

Net change in income taxes: During the year ended December 31, 2013, the Company became a taxable entity under the federal government. The future net cash flows were estimated to be taxed at a regulatory rate of 34%.

Purchases and Sale of Mineral Interests: During the year ended December 31, 2013, the Company acquired 20,750 Bbl of crude oil and 62,050 Mcf of natural gas through the purchase of undeveloped properties.

Significant Changes in Reserves for the Year Ended December 31, 2012

Net changes in Prices and Production Costs: For the year ended December 31, 2012, the oil and natural gas prices were applied at $94.68/Bbl and $2.76/MMBtu, respectively, in the standardized measure. At December 31, 2011, the oil and natural gas prices were applied at $95.84/Bbl and $4.15/MMBtu, respectively, in the standardized measure. The decrease in oil and natural gas prices resulted in a significant decrease in future expected cash flows and reserves.

Purchases and Sale of Mineral Interests: During the year ended December 31, 2012, the Company acquired 66,230 Bbl of crude oil and 63,660 Mcf of natural gas through the purchase of undeveloped properties.

F-15

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company