Annual Report (10-k)

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company

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 December 31, 2015

☐	Transition Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934.

For the transition period from to

Commission File Number 33-16820-D

ARÊTE INDUSTRIES, INC.

(Exact name of registrant as specified in its charter)


Colorado		84-1508638
(State or Other Jurisdiction of Incorporation or Organization)		(I.R.S. Employer Identification No.)


7260 Osceola Street, Westminster, Colorado		80030
(Address of Principal Executive Offices)		(Zip Code)

(303) 427-8688

(Registrant’s Telephone Number, Including Area Code)

Securities registered under Section 12(b) of the Exchange Act: None

Securities registered under Section 12(g) of the Exchange Act: None

Name of Exchange on which registered: None

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

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

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 ☒ No ¹

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

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in the 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.

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

The aggregate market value of the 9,787,913 shares of voting stock held by non-affiliates of the registrant, based upon the closing sale price of the registrant’s common stock on June 30, 2015, the last business day of the registrant’s most recently completed second fiscal quarter, of $0.141 per share was $1,380,096.

As of April 29, 2016, the Registrant had 14,295,413 shares of common stock issued and outstanding.

Documents Incorporated By Reference - None

¹	Explanatory Note: The Company is a voluntary filer with the Securities and Exchange Commission.

Arête Industries, Inc.

Index to Form 10-K


		Page
PART I		5

Item 1.	Business	5
Item 1A.	Risk Factors	11
Item 1B	Unresolved Staff Comments	19
Item 2.	Properties	19
Item 3.	Legal Proceedings	24
Item 4.	Mine Safety Disclosures	24

PART II		25

Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	25
Item 6.	Selected Financial Data	26
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	26
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk
Item 8.	Financial Statements and Supplementary Data.	32
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	54
Item 9-A	Controls and Procedures	54
Item 9-B	Other Information	54

PART III		55

Item 10.	Directors, Executive Officers and Corporate Governance	55
Item 11.	Executive Compensation	57
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	59
Item 13.	Certain Relationships and Related Transactions, and Director Independence	59
Item 14.	Principal Accounting Fees and Services	61

PART IV		62

Item 15.	Exhibits, Financial Statement schedules	62

Cautionary Statement Regarding Forward-Looking Statements

Certain statements contained in this Annual Report on Form 10-K (and other documents to which it refers) are not statements of historical fact and constitute forward-looking statements within the meaning of the various provisions of the Securities Act of 1933, as amended, which we refer to as the Securities Act, and the Securities Exchange Act of 1934, as amended, which we refer to as the Exchange Act, including, without limitation, the statements specifically identified as forward-looking statements within this Annual Report on Form 10-K. Many of these statements contain risk factors as well. In addition, certain statements in our future filings with the SEC, in press releases, and in oral and written statements made by or with our approval, which are not statements of historical fact, constitute forward-looking statements within the meaning of the Securities Act and the Exchange Act. Examples of forward-looking statements, include, but are not limited to: (i) projections of capital availability, terms, expenditures, revenues, income or loss, earnings or loss per share, the payment or non-payment of dividends on our common stock and on our convertible preferred stock, capital structure, and other financial items, (ii) statements of our plans and objectives or our management or board of directors including those relating to possible development of our oil and gas properties, (iii) statements of future economic performance and (iv) statements of assumptions underlying such statements. Words such as “believes”, “anticipates”, “expects”, “intends”, “targeted”, “may”, “will” and similar expressions are intended to identify forward-looking statements but are not the exclusive means of identifying such statements. Important factors that could cause actual results to differ materially from the forward looking statements include, but are not limited to:

•

our ability to alleviate our significant working capital deficit and continue business as a going concern

•

changes in production volumes, worldwide demand and commodity prices for oil and natural gas;

•

changes in estimates of proved reserves;

•

declines in the values of our oil and natural gas properties resulting in impairments;

•

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

•

our ability to acquire leases, drilling rigs, supplies and services at reasonable prices;

•

risks incident to the drilling and operation of oil and natural gas wells;

•

future production and development costs;

•

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

•

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

•

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

•

the identification of and severity of environmental events and governmental responses to the events;

•

the effect of oil and natural gas derivatives activities; and

•

conditions in the capital markets.

Such forward-looking statements speak only as of the date on which such statements are made, and we undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made to reflect the occurrence of unanticipated events.

CERTAIN DEFINITIONS

Unless the context in this Annual Report on Form 10-K otherwise requires, the terms the “Company”, “we”, “us”, “our” or “ours” when used herein refers to Arête Industries, Inc., together with its consolidated subsidiary. When the context requires, we refer to these entities separately. We have included below the definitions for certain terms used in this Annual Report on Form 10-K:

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 or BOPD – barrels per day or barrels of oil per day.

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, usually in a drilling project, 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, amortization and accretion.

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

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

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

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

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

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

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

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.

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.

Mmcf – One million cubic feet.

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

NGL’s – Natural gas liquids measured in barrels.

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

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

PV10 – 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 and costs, as prescribed in the SEC rules, 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, amortization and accretion, or Federal income taxes and discounted using an annual discount rate of 10%. PV10 is considered a Non-GAAP financial measure as defined by the SEC.

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

Proved developed nonproducing reserves or PDNP – Proved reserves that meet the definition of proved developed reserves (defined below) but are either shut-in or are behind-pipe reserves.

Proved developed producing reserves or PDP – Proved reserves that meet the definition of proved developed reserves (defined below) that are currently able to produce to market.

Proved developed reserves – Proved developed oil and gas reserves are reserves of any category that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the costs of the required equipment is relatively minor compared to the costs of a new well.

Proved 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 estimates. 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.

Proved undeveloped reserves or PUDs – Proved undeveloped oil and gas reserves are 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. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time

Reasonable certainty – If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least 90 percent probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical or geochemical) engineering, and economic data are made to estimated ultimate recovery with time, reasonably certain estimated ultimate recovery is much more likely to increase or remain constant than to decrease.

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

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

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

SEC – The U.S. Securities and Exchange Commission.

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 reserves were estimated but were not producing due to market conditions, mechanical difficulties or because production equipment or pipelines were not yet installed. These reserves are included in the PDNP category on the reserve report.

Standardized Measure of Discounted Future Net Cash Flows – A measure of the present value of the estimated future cash flows to be derived from the production and sale of proved oil and gas reserves. Estimated production taxes, estimated operating expenses, estimated future investment costs, and estimated future income taxes are deducted from estimated future cash inflows and discounted at PV 10 to arrive at the standardized measure of discounted future net cash flows. We calculate this measure in accordance with FASB ASC Topic (932) Extractive Activities – Oil and Gas .

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

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

Workover – Major remedial operations on a completed well to restore, maintain or improve the well’s production.

PART 1

Item 1.

BUSINESS

Overview

Arête Industries, Inc., a Colorado corporation, is an independent oil and gas company engaged in the acquisition and development of oil and natural gas reserves through a program which includes purchases of reserves, re-engineering, development and exploration activities primarily focused in Wyoming, Kansas, Colorado and Montana.

In 2011, we entered into a purchase and sale agreement (“DNR and Tindall PSA”) and other related agreements and documents with Tucker Family Investments, LLLP, which we refer to as “Tucker”; DNR Oil & Gas, Inc. which we refer to as “DNR”; and Tindall Operating Company, which we refer to as “Tindall”, and collectively we refer to these parties as the “Sellers”, for the purchase of certain oil and gas operating properties in Colorado, Kansas, Wyoming, and Montana. DNR is owned primarily by an officer and director of the Company, Charles B. Davis, and he is affiliated with Tucker and Tindall. The consideration for the purchase was determined by bargaining between management of the Company and Mr. Davis, and the Company used reports of independent engineering firms to analyze the purchase price. The base purchase price was paid in full on September 29, 2011. On January 19, 2016, but effective December 31, 2015, we entered into a settlement agreement with the Sellers. In consideration of the amounts indicated below, the parties (i) terminated Exhibits C and C-2 to the DNR and Tindall PSA for all purposes; (ii) extinguished all liabilities of the Company under Exhibit C of the DNR and Tindall PSA including $250,000 related to the increase in oil prices after the acquisition; (iii) agreed that the promissory note owed by us to DNR in the amount of $792,151 and accrued interest thereon was paid in full; and (iv) released each other against any and all claims which have been raised or could have been raised among them. Specifically, Exhibits C and C-2 to the DNR and Tindall PSA related to potential payments that would have been needed to be made by us in the event oil prices increased to certain levels and related to certain payments that would have been needed to be made by us in the event we sold certain properties purchased under the Purchase and Sale Agreement. Exhibits C and C-2 were terminated and extinguished (including any amounts owed thereunder including $250,000 under Exhibit C to the Purchase and Sale Agreement) in exchange for 25 fully paid, nonassessable restricted shares of our 7% Series A2 Convertible Preferred Stock. Consideration to pay the above promissory note in full consisted of us issuing to DNR 65 fully paid, nonassessable restricted shares of our 7% Series A2 Convertible Preferred Stock, and paying DNR $303,329 in cash.

On December 30, 2015, we completed the asset acquisition as provided under a purchase and sale agreement executed on November 25, 2015, but effective December 1, 2015 (the "Wellstar Purchase and Sale Agreement ") with Wellstar Corporation (the "Seller"), an unaffiliated corporation. The assets acquired are producing oil and gas leases located in Sumner County, Kansas and Kimball County, Nebraska (collectively, the " Properties" and individually, the " Padgett Properties" and the "Nebraska Properties"). We acquired 51% of Seller's interest (ranging from 47% to 100% of the working interests) in the Padgett Properties and acquired 100% of the Seller's interest (100% of the working interests) in the Nebraska Properties for aggregate consideration of $1,100,000 and the issuance of 1,000,000 shares of our restricted common stock valued at $0.10 per share at the date of closing, or $100,000.

We also own a gas gathering system (pipeline and compressor station related assets) in Campbell County, Wyoming that has been written down to $0. This system was constructed in late 2001 and began operations early in 2002. The system consists of 4.5 miles of 8-inch coated steel pipeline. This system has a current throughput capacity of approximately 4 million cubic feet of gas per day, although the system is currently idle since the related wells are shut-in. We do not expect any activity on this property in 2016.

Business Strategy

Our business strategy is three-fold in approach.

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We plan to and have acquired oil and natural gas properties that will provide for the operations of the Company;

•

We expect to seek to acquire leases that have development possibility either for us to drill or with other companies on a joint venture or farm-out basis. Part of this plan would include the possibility of selling leases and retaining an overriding royalty in the property and a right to buy back into future development; and

•

We are looking for acquisitions of producing properties with future development.

Competitive Business Conditions

The oil and natural gas industry is intensely competitive, and we compete with numerous other companies engaged in the exploration and production of oil and gas. Many of these companies have substantially greater resources than we have. Not only do they explore for and produce oil and natural gas, but also many carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. The operations of other companies are in many instances able to pay more for exploratory prospects and productive oil and natural gas properties. Many of our competitors also have more resources to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or technical resources permit.

Our larger competitors have the resources to be better able to absorb the burden of current and future federal, state, and local laws and regulations more easily than we can, which adversely affects our competitive position. Our ability to locate reserves and acquire interests in properties in the future will be dependent upon our ability and resources to evaluate and select suitable properties and consummate transactions in this highly competitive environment. In addition, we may be at a disadvantage in acquiring producing oil and natural gas properties and bidding for exploratory prospects because we have fewer financial and technical resources than other companies in our industry.

Members of the Organization of Petroleum Exporting Countries establish prices and production quotas for petroleum products from time to time with the intent of affecting the current global supply of crude oil and maintaining, lowering or increasing certain price levels. A drastic reduction in crude oil prices and related products from nearly $100 per barrel at mid-year 2014 to as low as $29 per barrel in early 2016 has impact the oil and gas industry. As of April 28, 2016, the price of crude oil was approximately $45 per barrel. Continuation of these steep declines put us at a disadvantage compared to many of our competitors due to their greater financial resources and ability to withstand such significant price declines

Marketing and Customers

The market for oil and natural gas that we produce depends on factors beyond our control, including the extent of domestic production and imports of oil and natural gas, the proximity and capacity of natural gas pipelines and other transportation facilities, demand for oil and natural gas, the marketing of competitive fuels and the effects of state and federal regulation. The oil and gas industry also competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers.

Our oil production is expected to be sold at prices tied to the spot oil markets, as adjusted for transportation and quality. Our natural gas production is expected to be sold under short-term contracts and priced based on first of the month index prices or on daily spot market prices. We currently rely on our related party operator to market and sell our production.

Seasonality—Gathering and Processing

Generally, but not always, the demand and price levels for natural gas increase during the colder winter months and decrease during the warmer summer months. More recently, historical natural gas prices have been at ten year lows. In addition, pipelines, utilities, local distribution companies and industrial users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer, which can lessen seasonal demand fluctuations. Seasonal anomalies such as mild winters and summers sometimes lessen these fluctuations.

Foreign Operations and Export Sales

We do not have any interests, production facilities, or operations in foreign countries.

Regulations

All of the jurisdictions in which we own or operate producing oil and natural gas properties have statutory provisions regulating the exploration for and production of oil and natural gas, including provisions related to permits for the drilling of wells, bonding requirements to drill or operate wells, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, sourcing and disposal of water used in the drilling and completion process, and the plugging and abandonment of wells. Our operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units, the number of wells which may be drilled in an area, and the unitization or pooling of oil and natural gas properties, as well as regulations that generally prohibit the venting or flaring of natural gas, and impose certain requirements regarding the establishment of maximum allowable rates of production from fields and individual wells. Our operations are also subject to various conservation laws and regulations. These laws and regulations govern the size of drilling and spacing units, the density of wells that may be drilled in oil and natural gas properties and the unitization or pooling of oil and natural gas properties. In this regard, some states allow the forced pooling or integration of land and leases to facilitate exploration while other states rely primarily or exclusively on voluntary pooling of land and leases. In areas where pooling is primarily or exclusively voluntary, it may be difficult to form spacing units and therefore difficult to develop a project if the operator owns less than 100% of the leasehold. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas, and impose specified requirements regarding the ratability of production. On some occasions, tribal and local authorities have imposed moratoria or other restrictions on exploration and production activities pending investigations and studies addressing potential local impacts of these activities before allowing oil and natural gas exploration and production to proceed.

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

Environmental Regulations

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

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

Hazardous Substances and Wastes

The federal Comprehensive Environmental Response, Compensation and Liability Act, referred to as CERCLA or the Superfund law, and comparable state laws impose liability, without regard to fault, on certain classes of persons that are considered to be responsible for the release of a hazardous substance into the environment. These persons may include the current or former owner or operator of the disposal site or sites where the release occurred and companies that disposed or arranged for the disposal of hazardous substances that have been released at the site. Under CERCLA, these persons may be subject to joint and several liability for the costs of investigating and cleaning up hazardous substances that have been released into the environment, for damages to natural resources and for the costs of some health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment.

Under the federal Solid Waste Disposal Act, as amended by the Resource Conservation and Recovery Act of 1976, referred to as RCRA, most wastes generated by the exploration and production of oil and natural gas are not regulated as hazardous waste. Periodically, however, there are proposals to lift the existing exemption for oil and natural gas wastes and reclassify them as hazardous wastes. If such proposals were to be enacted, they could have a significant impact on our operating costs, as well as the oil and natural gas industry in general. In the ordinary course of our operations moreover, some wastes generated in connection with our exploration and production activities may be regulated as solid waste under RCRA, as hazardous waste under existing RCRA regulations or as hazardous substances under CERCLA. From time to time, releases of materials or wastes have occurred at locations we own or at which we have operations. These properties and the materials or wastes released thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, we have been and may be required to remove or remediate such materials or wastes.

Water Discharges

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

Our oil and natural gas production also generates salt water, which we dispose of by underground injection. The federal Safe Drinking Water Act (“SDWA”), the Underground Injection Control (“UIC”) regulations promulgated under the SDWA and related state programs regulate the drilling and operation of salt water disposal wells. The EPA directly administers the UIC program in some states, and in others it is delegated to the state for administering. Permits must be obtained before drilling salt water disposal wells, and casing integrity monitoring must be conducted periodically to ensure the casing is not leaking salt water to groundwater. Contamination of groundwater by oil and natural gas drilling, production, and related operations may result in fines, penalties, and remediation costs, among other sanctions and liabilities under the SDWA and state laws. In addition, third party claims may be filed by landowners and other parties claiming damages for alternative water supplies, property damages, and bodily injury.

Hydraulic Fracturing

Our completion operations are subject to regulation, which may increase in the short- or long-term. The well completion technique known as hydraulic fracturing is used to stimulate production of natural gas and oil has come under increased scrutiny by the environmental community, and local, state and federal jurisdictions. Hydraulic fracturing involves the injection of water, sand and additives under pressure, usually down casing that is cemented in the wellbore, into prospective rock formations at depth to stimulate oil and natural gas production.

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

Air Emissions

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

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

In October 2015, the EPA issued a final rule under the Clean Air Act, lowering the National Ambient Air Quality Standard (“NAAQS”) for ground-level ozone from 75 parts per billion to 70 parts per billion under both the primary and secondary standards to provide requisite protection of public health and welfare, respectively. The final rule became effective in December 2015. Certain areas of the country in compliance with the ground-level ozone NAAQS standard may be reclassified as non-attainment and such reclassification may make it more difficult to construct new or modified sources of air pollution in newly designated non-attainment areas. Moreover, states are expected to implement more stringent regulations, which could apply to our operations. Compliance with this final rule could, among other things, require installation or new emission controls on some of our equipment, result in longer permitting timelines, and significantly increase our capital expenditures and operating costs.

Climate Change

Studies over recent years have indicated that emissions of certain gases may be contributing to warming of the Earth’s atmosphere. In response to these studies, governments have begun adopting domestic and international climate change regulations that require reporting and reductions of the emission of such greenhouse gases. Methane, a primary component of natural gas, and carbon dioxide, a byproduct of burning oil, natural gas and refined petroleum products, are considered greenhouse gases. Internationally, the United Nations Framework Convention on Climate Change, and the Kyoto Protocol address greenhouse gas emissions, and several countries including those comprising the European Union have established greenhouse gas regulatory systems. In the United States, at the state level, many states, either individually or through multi-state regional initiatives, have begun implementing legal measures to reduce emissions of greenhouse gases, primarily through the emission inventories, emissions targets, greenhouse gas cap and trade programs or incentives for renewable energy generation, while others have considered adopting such greenhouse gas programs.

At the federal level, the EPA has issued regulations requiring us and other companies to annually report certain greenhouse gas emissions from our oil and natural gas facilities. Beyond its measuring and reporting rules, the EPA has issued an “Endangerment Finding” under section 202(a) of the Clean Air Act, concluding greenhouse gas pollution threatens the public health and welfare of current and future generations. The finding served as the first step to issuing regulations that require permits for and reductions in greenhouse gas emissions for certain facilities.

In August 2015, the EPA proposed rules that will establish emission standards for methane from certain new and modified oil and natural gas production and natural gas processing and transmission facilities as part of the Obama Administration’s efforts to reduce methane emissions from the oil and natural gas sector by up to 45 percent from 2012 levels by 2025. The EPA’s proposed rule package includes standards to address emissions of methane from equipment and processes across the source category, including hydraulically-fractured oil and natural gas well completions, fugitive emissions from well sites and compressors, and equipment leaks at natural gas processing plants and pneumatic pumps. The EPA is expected to finalize these rules in 2016.

The U.S. Congress and the EPA, in addition to some state and regional efforts, have in recent years considered legislation or regulations to reduce emissions of greenhouse gases (“GHGs”). These efforts have included consideration of cap-and-trade programs, carbon taxes, and GHG reporting and tracking programs. In the absence of federal GHG-limiting legislations, the EPA has determined that GHG emissions present a danger to public health and the environment and has adopted regulations that, among other things, restrict emissions of GHGs under existing provisions of the Clean Air Act and may require the installation of “best available control technology” to limit emissions of GHGs from any new or significantly modified facilities that we may seek to construct in the future if they would otherwise emit large volumes of GHGs together with other criteria pollutants. Also, certain of our operations are subject to EPA rules requiring the monitoring and annual reporting of GHG emissions from specified onshore and offshore production sources. On an international level, the United States is one of almost 200 nations that, in December 2015, agreed to an international climate change agreement in Paris, France that calls for countries to set their own GHG emissions targets and be transparent about the measures each country will use to achieve its GHG emissions targets.

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

The National Environmental Policy Act

Oil and natural gas exploration and production activities may be subject to the National Environmental Policy Act, or NEPA. NEPA requires federal agencies, including the Department of the Interior, to evaluate major agency actions that have the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. Although the Company has a few future projects that could potentially involve federal lands, federal lands require governmental permits that are subject to the requirements of NEPA. This process has the potential to delay the development of future oil and natural gas projects.

Threatened and endangered species, migratory birds and natural resources

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

Hazard communications and community right to know

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

Occupational Safety and Health Act

We are subject to the requirements of the federal Occupational Safety and Health Act and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the Occupational Safety and Health Administration’s hazard communication standard requires that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees.

Employees

We currently have no full time or part time employees. Our officers serve us in a consulting capacity. We anticipate adding employees and are currently using independent contractors, consultants, attorneys and accountants as necessary, to complement services for operations and regulatory filings.

Intellectual Property

We do not currently have any patents, trademarks or licenses.

Item 1A.

RISK FACTORS

An investment in our common stock involves a high degree of risk. Readers of this report should consider carefully the following risks, along with all of the other information included in this report. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial may also impair our business operations. If we are unable to prevent events that have a negative effect from occurring, then our business may suffer. Some of the information in this Annual Report on Form 10-K contains forward-looking statements that involve substantial risks and uncertainties. These statements can be identified by forward-looking words such as “may,” “will,” “expect,” “anticipate,” “believe,” “intend,” “estimate,” and “continue” or other similar words. Statements that contain these words should be carefully read for the following reasons:

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The statements may disclose our future expectations;

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The statements may contain projections of our future earnings or our future financial condition; and

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The statements may state other “forward-looking” information.

Risks Related to Our Business and Industry

We will require significant additional capital in seeking to execute our business plan, which may not be available or may only be available on unfavorable terms.

Our future capital requirements depend on many factors, including development and acquisition opportunities, the availability of debt financing and the cash flow from our operations. To the extent that the funds available are insufficient to meet future capital requirements, we will likely need to reduce our development activity as we did in 2015. Any equity or debt financing, if available at all, may be on terms that are not favorable to us. If we cannot obtain adequate capital on favorable terms or at all, our business, operating results and financial condition will likely be adversely affected.

Volatile oil and natural gas prices could adversely affect our financial condition and results of operations.

Our most significant market risk is the price of crude oil and natural gas. Management expects energy prices to remain volatile and unpredictable. Moreover, oil and natural gas prices result from numerous factors that are outside of our control, including:

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Economic and energy infrastructure disruptions caused by geopolitical factors including but not limited to embargoes and sanctions on major producing countries and actual or threatened acts of war, or terrorist activities particularly with respect to oil producers in the Middle East, Nigeria and Venezuela;

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Weather conditions, such as hurricanes, including energy infrastructure disruptions resulting from those conditions;

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Changes in the global oil supply, demand and inventories;

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Changes in domestic natural gas supply, demand and inventories;

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The price and quantity of foreign imports of oil;

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Political conditions in or affecting other oil-producing countries;

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General economic conditions in the United Stated and worldwide;

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The level of worldwide oil and natural gas exploration and production activity;

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Technological advances affecting energy consumption; and

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The price and availability of alternative fuels.

Lower oil and natural gas prices not only decrease revenues on a per unit of production basis, but also may reduce the amount of oil and natural gas that we can economically produce negatively impacting estimates of our economically recoverable proved reserves. Substantial or extended declines in oil or natural gas prices may materially and adversely affect our financial condition, results of operations, liquidity and ability to finance operations and planned capital expenditures.

A drastic reduction in crude oil prices and related products from nearly $100 per barrel at mid-year 2014 to as low as $29 per barrel in early 2016 has impacted the oil and gas industry. As of April 28, 2016, the price of crude oil was approximately $45 per barrel. Should the recent prevailing oil prices remain in effect for an extended period of time, we may be required to curtail capital expenditures unless we are able to raise additional equity or debt funding. Continuation of the steep decline in oil prices, and any declines that may occur in the future, can be expected to significantly reduce our revenues, profitability and cash flow as well as the value of our reserves and may also adversely affect the economics of future operations resulting in deferral or cancellation of planned drilling and related activities until such time, if ever, as economic conditions improve sufficiently to support such operations.

If oil and natural gas prices decrease, we may be required to further write down the carrying value of our assets, negatively impacting the trading value of our securities.

Accounting rules require that we review periodically the carrying value of our oil and natural gas properties for possible impairment. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we have and may be required to further write down the carrying value of our oil and natural gas properties. A write-down would constitute a non-cash charge to earnings. It is likely the cumulative effect of a write-down could also negatively impact the trading price of our securities.

We do not have any employees and we depend on our chief executive officer for a significant majority of our management decisions, operations and industry contacts.

Due to our limited operations, we do not have any employees, and our executive officers are retained as independent contractors on a part-time basis. We are heavily dependent upon the efforts of our Chief Executive Officer, Nicholas L. Scheidt, who essentially operates our company. We do not have an employment agreement with either officer nor do we have any key man insurance on their life. As we currently do not have a successor to Mr. Scheidt, the loss of his services would likely have a material adverse impact on our business.

Oil and gas prices must remain at sufficient levels in order for us to operate profitably.

In the event we are able to raise substantial additional capital, we expect to focus on acquiring oil and gas properties that we believe offer profit potential from overlooked and by-passed reserves of oil and natural gas, which will include shut-in wells, in-field development, stripper wells, re-completion and re-working projects. Because production is generally on a decline on these mature properties while operating expenses can be high, declines in oil and gas prices will likely have a greater negative impact on our operations compared to oil and gas companies that focus on newer developed properties.

We may expend substantial funds in acquiring and redeveloping properties which are later determined to not be economically viable.

The search for new oil and gas reserves, development wells or secondary recovery frequently result in unprofitable efforts, not only from dry holes, but also from wells which, though productive, will not produce oil or gas in sufficient quantities to return a profit on the costs incurred. There is no assurance that any production will be obtained from any of the acreage to be acquired by us, nor are there any assurances that if such production is obtained, it will be profitable. We may expend substantial funds in acquiring and redeveloping properties which are later determined not to be economically viable. All funds so expended may be a total loss to us and which could result in possibly significant impairments in our oil and gas asset base. In such event, our profitability and operations may be materially adversely affected.

Drilling for and producing oil and natural gas are high-risk activities with many uncertainties that could adversely affect our financial condition and results of operations.

Our success depends on the results of our exploitation, exploration, development and production activities. Oil and natural gas exploration and production activities are subject to numerous significant risks some of which are beyond our control; including the risk that drilling will not result in commercially viable oil or natural gas production. Decisions to purchase, explore, develop or otherwise exploit prospects or properties will depend in large part on our proper evaluation and assessment of data obtained through geophysical and geological analyses, production data, and engineering studies. Our evaluations and assessments could ultimately prove to be incorrect. Significant aspects of costs of drilling, completing and operating wells are often uncertain before drilling commences. Overruns in budgeted expenditures are common risks that can render a particular project uneconomical. Further, many factors may curtail, delay or cancel drilling, including:

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Shortages of or delays in obtaining equipment and qualified personnel such as we are currently experiencing;

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Pressure or irregularities in geological formations;

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Equipment failures or accidents;

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Adverse weather conditions;

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Reductions in oil and natural gas prices;

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Issues associated with property titles; and

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Delays imposed by or resulting from compliance with regulatory requirements.

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

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

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Blowouts, fires and explosions;

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Personal injuries and death;

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Uninsured or underinsured losses;

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Unanticipated, abnormally pressured formations;

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Mechanical difficulties, such as stuck oil field drilling and service tools and casing collapses; and

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

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

Seeking to grow our business by purchase of production, expanding existing production, and exploration subjects us to development and other risks.

The search for commercial quantities of oil and natural gas as a business is highly risky. We cannot provide investors with any assurance that any properties in which we obtain a mineral interest will contain commercially exploitable quantities of oil and/or gas. The exploration expenditures to be made by us may not result in the discovery of commercial quantities of oil and/or gas. Problems such as unusual or unexpected formations or pressures, premature declines of reservoirs, invasion of water into producing formations and other conditions involved in oil and gas exploration often result in unsuccessful exploration efforts. If we are unable to find commercially exploitable quantities of oil and gas, and/or we are unable to commercially extract such quantities, we may be forced to abandon or curtail our business plan, and as a result, any investment in us may become worthless.

Future oil and gas price declines or unsuccessful exploration efforts may result in further write-downs of our exploration and production asset carrying values.

We follow the successful efforts method of accounting for our oil and gas properties. All property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending the determination of whether proved reserves have been discovered. If proved reserves are not discovered with an exploratory well, the costs of drilling the well are expensed. The capitalized costs of our oil and gas properties, on a field basis, cannot exceed the estimated future net cash flows of that field. If net capitalized costs exceed future net revenues, we must write down the costs of each such field to our estimate of fair market value. Unproved properties are evaluated at the lower of cost or fair market value. Accordingly, a significant decline in oil or gas prices or unsuccessful exploration efforts could cause a future write-down of capitalized costs.

We review the carrying value of our proved oil and gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. The impairment analysis is based on then current oil and gas prices in effect. Once incurred, a write-down of oil and gas properties cannot be reversed at a later date even if oil or gas prices increase.

Future oil and gas price declines may affect our ability to raise capital.

If oil and gas prices decrease there will be a corresponding negative impact on the value of our reserves. This could negatively affect our ability to borrow funds or raise equity capital.

Competition in our industry is intense, and many of our competitors have greater financial and technical resources than we do.

We face intense competition from major oil companies, independent oil and gas exploration and production companies, financial buyers and institutional and individual investors who are actively seeking oil and gas properties, along with the equipment, expertise, labor and materials required to operate oil and gas properties. Most of our competitors have financial and technical resources vastly exceeding those available to us, and many oil and gas properties are sold in a competitive bidding process in which our competitors may be able to pay more for development prospects and productive properties or in which our competitors have technological information or expertise to evaluate and successfully bid for the properties that is not available to us.

If we fail to develop or maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud.

Our internal controls and operations are subject to extensive regulation and reporting obligations and as of December 31, 2015, we concluded that our disclosure controls and procedures were not effective. See Item 9A, “Controls and Procedures”. A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Because of its inherent limitations, effective internal control over financial reporting may not prevent or detect misstatements. We cannot be certain that our efforts to develop and maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to comply with our obligations under Section 404 of the Sarbanes-Oxley Act. Any failure to develop or maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet certain reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which could have a negative effect on the trading price of our shares of common stock.

If we learn of any title defects on the properties we own or acquire, it could have a material adverse effect on our operations and profitability.

We may not be the record owner of interest in our properties and may rely instead on contracts with the owner or operator of the property or assignment of leases, pursuant to which, among other things, we have the right to have our interest placed of record. As is customary in the oil and gas industry, a preliminary title examination will be conducted at the time properties or interests are acquired by us. Prior to commencement of operations on such acreage and prior to the acquisition of properties, a title examination will usually be conducted and significant defects remedied before proceeding with operations or the acquisition of proved properties, as appropriate.

Our producing properties are subject to royalty, overriding royalty and other interests customary in the industry, liens incident to agreements, current taxes and other burdens, minor encumbrances, easements and restrictions. Although we are not aware of any material title defects or disputes with respect to our current and prospective acreage acquisitions, to the extent such defects or disputes exist, we could suffer title failures.

Our officers and directors are engaged in other business activities and conflicts of interest have arisen in their daily activities which may not be resolved in our favor.

Certain conflicts of interest exist between us and our officers and directors. Officers or directors may bring energy prospects to us in which they have an interest. They have other business interests to which they devote their attention, and will be expected to continue to do so. They will also devote management time to our business. As a result, conflicts of interest or potential conflicts of interest may arise from time to time that can be resolved only through the officers and directors exercising such judgment as is consistent with fiduciary duties to their other business interests and to us. See Item 13, “ Certain Relationships and Related Transactions, and Director Independence ”.

Insurance may not fully recover potential losses.

Although we believe that we are reasonably insured against losses to wells and associated equipment, potential operational related losses could result in a loss of our reserves and properties and materially reduce our ability to self-fund exploration and development activities and property acquisitions. The insurance market, in general, and the energy insurance market in particular, have experienced substantial cost increases over recent years, resulting from significant losses associated with commercial losses. The potential for loss, however, cannot be accurately or reasonably predicted. If we incur substantial damages or liabilities that are not fully covered by insurance or are in excess of policy limits, then our business, results of operations, and financial condition could be materially affected. Also, as is customary in the oil and gas business, we do not carry business interruption insurance. In the future, it is also possible that we will further modify insurance coverage or determine not to purchase some insurance because of high insurance premiums.

Our failure to successfully identify, complete and integrate future acquisitions of properties or businesses could reduce any earnings we may achieve.

There is intense competition for acquisition opportunities in our industry for attractive oil and gas properties and other exploration and production. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. Our ability to complete acquisitions is dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. Completed acquisitions could require us to invest further in operational, financial and management information systems and to attract, retain, motivate and manage effectively additional employees. The inability to effectively manage the integration of acquisitions could reduce our focus on subsequent acquisitions and current operations, which, in turn, could negatively impact our earnings and growth. Our financial position and results of operations may fluctuate significantly from period to period, based on whether or not significant acquisitions are completed in particular periods.

Negative or downward revisions of oil and gas reserve estimates could adversely affect the trading price of our common stock. Oil and gas reserves and the standardized measure of cash flows represent estimates, which may vary materially over time due to many factors.

The market price of our common stock may be subject to significant decreases due to decreases in our estimated reserves, our estimated cash flows and other factors. Estimated reserves may be subject to downward revision based upon future prices for oil and natural gas, production, results of future development, prevailing operating and development costs, SEC rules related to proved undeveloped reserves and other factors. There are numerous uncertainties and uncontrollable factors inherent in estimating quantities of oil and gas reserves, projecting future rates of production, and timing of development expenditures.

The estimates of future net cash flows from proved reserves and the standardized measure of proved reserves are based upon various assumptions about prices and costs and future production levels that may prove to be incorrect over time. Any significant variance from the assumptions could result in material differences in the actual quantity of reserves and amount of estimated future net cash flows from estimated oil and gas reserves.

In addition, SEC rules generally require that proved undeveloped reserves that have not been drilled within five years be reclassified out of estimates of proved reserves; although such technically and economically recoverable reserves may be still owned or controlled by us. Accordingly, given current low oil and natural gas prices we may not drill certain proved undeveloped locations within the established five year time frame and therefore we may be required to reclassify such reserves out of our estimated proved undeveloped reserves. The effect of reclassifying such reserves would result in decreases in estimated proved reserve quantities and therefore could result in decreases in net income and earnings per share, resulting from increased depletion expense and possible impairments. These effects could have an adverse effect on our stock price.

Our properties are subject to influence by other parties that do not allow us to proceed with exploration and expenditures as we may desire.

We do not operate any of our properties. Joint ownership is customary in the oil and gas industry and is generally conducted under the terms of a joint operating agreement (“JOA”), where a single working interest owner is designated as the “operator” of the property. Most of our producing oil and gas properties are operated by DNR, an affiliate of Charles Davis, one of our officers and directors. Thus, drilling and operating decisions are not within our sole control. If we disagree with the decision of this operator, we may be required, among other things, to postpone the proposed activity or decline to participate. If we decline to participate, we might be forced to relinquish our interest through “in-or-out” elections or may be subject to certain non-consent penalties, as provided in a JOA. In-or-out elections may require a joint owner to participate, or forever relinquish its position. Non-consent penalties typically allow participating working interest owners to recover from the proceeds of production, if any, and an amount equal to 200% to 500% of the non-participating working interest owner’s share of the cost of such operations.

Certain federal income tax deductions currently available with respect to oil and gas exploration and development may be eliminated or curtailed as a result of future legislation.

Among the changes contained in the recent budget proposals, released by the Office of Management and Budget, is the elimination or deferral of certain U.S. federal income tax deductions and credits currently available to domestic oil and gas exploration companies. Such changes include, but are not limited to, (i) the elimination of current deductions for intangible drilling and development costs; (ii) the elimination of the deduction for certain U.S. production activities for oil and gas properties; (iii) an extension of the amortization period for certain geological and geophysical expenditures and (iv) the repeal of the enhanced oil recovery credit. Some of these same proposals to repeal or limit oil and gas tax deductions and credits have been included in legislation that has recently been considered by Congress. It is unclear whether any such changes will be enacted or how soon such changes could be effective. The passage of any legislation as a result of the budget proposal, or the passage of bills containing similar changes in U.S. federal income tax law could eliminate or defer certain tax deductions and credits that are currently available with respect to oil and gas exploration and development and could negatively affect our financial results.

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

Our operations involving the exploration, production, storage, treatment, and transportation of liquid hydrocarbons, including crude oil, are subject to stringent federal, state, and local laws and regulations governing the discharge of materials into the environment. Our operations are also subject to laws and regulations relating to protection of the environment, operational safety, and related employee health and safety matters. Compliance with all of these laws and regulations may represent a significant cost of doing business. Failure to comply with these laws and regulations may result in the assessment of administrative, civil, and criminal penalties; the imposition of investigatory and remedial liabilities; and the issuance of injunctions that may restrict, inhibit or prohibit our operations; or claims of damages to property or persons.

Compliance with environmental laws and regulations may require us to spend significant resources.

Environmental laws and regulations may: (1) require the acquisition of a permit before well drilling commences; (2) restrict or prohibit the types, quantities and concentration of substances that can be released into the environment in connection with drilling and production activities; (3) prohibit or limit drilling activities on certain lands lying within wetlands or other protected areas; and (4) impose substantial liabilities for pollution resulting from past or present drilling and production operations. Moreover, changes in Federal and state environmental laws and regulations, as well as how such laws and regulations are administered, could occur and may result in more stringent and costly requirements which could have a significant impact on our operating costs. In general, under various applicable environmental regulations, we may be subject to enforcement action in the form of injunctions, cease and desist orders and administrative, civil and criminal penalties for violations of environmental laws. We may also be subject to liability from third parties for civil claims by affected neighbors arising out of a pollution event. Laws and regulations protecting the environment may, in certain circumstances, impose strict liability rendering a person liable for environmental damage without regard to negligence or fault on the part of such person. Such laws and regulations may expose us to liability for the conduct of or conditions caused by others, or for our acts which were in compliance with all applicable laws at the time such acts were performed. We believe we are in compliance with applicable environmental and other governmental laws and regulations. In recent years, increased concerns have been raised over the protection of the environment. Legislation to regulate the emissions of greenhouse gases has been introduced in Congress, and there has been a wide-ranging policy debate, both nationally and internationally, regarding the impact of these gases and possible means for their regulation. In addition, efforts have been made and continue to be made in the international community toward the adoption of international treaties or protocols that would address global climate change issues. Also, the EPA has recently undertaken significant efforts to collect information regarding greenhouse gas emissions and their effects.

Climate change legislation or regulations restricting emissions of “greenhouse gasses” could result in increased operating costs and reduced demand for crude oil and natural gas that we produce.

In December 2009, the U.S. Environmental Protection Agency, (“EPA”) determined that emissions of carbon dioxide, methane, and other greenhouse gases (“GHGs”), present an endangerment to public health and the environment because emissions of such gasses are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climate changes. Based on these findings the EPA has begun adopting and implementing regulations to restrict emissions of GHGs under existing provisions of the federal Clean Air Act. The EPA has adopted two sets of rules regulating greenhouse gas emissions under the Clean Air Act, one set of rules limit emissions of GHGs from motor vehicles and the other set of rules require certain Prevention of Significant Deterioration (“PSD”) and Title V permit requirements for GHG emissions from certain large stationary sources. The EPA rules have tailored the PSD and Title V permitting programs to apply to certain stationary sources of GHG emissions in a multi-step process, with the largest sources first subject to permitting. These EPA rulemakings could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified facilities. The EPA has also adopted rules requiring the monitoring and reporting of GHG emissions from specified sources in the United States, including, among others, certain oil and natural gas production facilities, which may include certain of our operations, on an annual basis.

In addition, the U.S. Congress has from time to time considered legislation to reduce emissions of GHGs, and almost one-half of the states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. The adoption of any legislation or regulations that requires reporting of GHGs or otherwise limits emissions of GHGs from our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations or could adversely affect demand for the oil and natural gas that we produce.

Federal, state, and local legislative and regulatory initiatives relating to hydraulic fracturing, as well as government reviews of such activities, could result in increased costs, additional operating restrictions or delays, and adversely affect our production and/or ability to book future reserves.

Hydraulic fracturing involves the injection of water, sand, and chemical additives under pressure into a targeted subsurface formation. The water and pressure create fractures in the rock formations, which are held open by the grains of sand, enabling the oil or natural gas to flow to the wellbore. The process is typically regulated by state oil and natural gas commissions; however, the EPA, recently asserted federal regulatory authority over certain hydraulic-fracturing activities involving diesel under the Safe Drinking Water Act and has begun the process of drafting guidance documents related to this newly asserted regulatory authority. In November 2011, the EPA announced its intent to develop and issue regulations under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing. In February 2012, the U.S. Department of the Interior (the “DOI”) released draft regulations governing hydraulic fracturing on federal and Indian oil and gas leases to require disclosure of information regarding the chemicals used in hydraulic fracturing, advance approval for well-stimulation activities, mechanical integrity testing of casing, and monitoring of well-stimulation operations. In addition, the U.S. Congress, from time to time, has considered adopting legislation intended to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic-fracturing process. In the event that a new, federal level of legal restrictions relating to the hydraulic-fracturing process are adopted in areas where we currently or in the future plan to operate, we may incur additional costs to comply with such federal requirements that may be significant in nature, and also could become subject to additional permitting requirements and cause us to experience added delays or curtailment in the pursuit of exploration, development, or production activities.

There are also certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic-fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic-fracturing practices, and a committee of the U.S. House of Representatives has conducted an investigation of hydraulic-fracturing practices. The EPA released in June, 2015, a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater.

In addition, some states have adopted, and other states are considering adopting, regulations that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing operations. For example, Colorado, Montana, Pennsylvania, Louisiana, Texas, and Wyoming, have adopted, and other states are considering adopting, regulations that could impose new or more stringent permitting, disclosure, and additional well-construction requirements on hydraulic-fracturing operations. For example, Texas adopted a law in June 2011 requiring disclosure to the Railroad Commission of Texas and the public of certain information regarding the components used in the hydraulic-fracturing process. In addition to state laws, local land use restrictions, such as city ordinances, may restrict or prohibit drilling in general and/or hydraulic fracturing in particular. These regulations will affect our operations, increase our costs of exploration and production and limit the quantity of natural gas and oil that we can economically produce to the extent that we use hydraulic fracturing. A major risk inherent in our drilling plans is the need to obtain drilling permits from state and local authorities on a timely basis following leasing. Delays in obtaining regulatory approvals, drilling permits, the failure to obtain a drilling permit for a well or the receipt of a permit with unreasonable conditions or costs could have a material adverse effect on our ability to explore on or develop our properties. Additionally, the natural gas and oil regulatory environment could change in ways that might substantially increase our financial and managerial costs to comply with the requirements of these laws and regulations and, consequently, adversely affect our profitability. Furthermore, these additional costs may put us at a competitive disadvantage compared to larger companies in the industry which can spread such additional costs over a greater number of wells and larger operating staff.

We are exposed to trade credit risk in the ordinary course of our business activities.

We are exposed to risks of loss in the event of nonperformance by our vendors, customers and by counterparties to our hedging arrangements. Some of our vendors, customers and counterparties may be highly leveraged and subject to their own operating and regulatory risks. Many of our vendors, customers and counterparties finance their activities through cash flow from operations, the use of debt or the issuance of equity. Even if our credit reviews are satisfactory, we may experience financial losses in our dealings with other parties. Any increase in the nonpayment or nonperformance by our vendors, customers and/or counterparties could adversely affect our financial condition and results of operation.

Risks Related to Our Common Stock

Investors may be diluted in future common stock offerings.

The holders of our common stock have no preemptive rights, and the issuance of additional shares of common stock by us may result in a commensurate reduction in an individual shareholder’s percentage ownership in us. The value of an investor’s investment in our convertible preferred stock may decrease to the extent that such dilution reduces the fair value of the shares of common stock.

Our common stock is thinly traded and our share price has fluctuated in the past and may continue to fluctuate in the future.

Our common stock has historically been thinly traded and the market price of our common shares in the over-the-counter market has experienced significant volatility and may continue to fluctuate significantly. The market price of our common shares may be significantly affected by factors such as the announcements of agreements and technological innovations by us or our competitors. In addition, while we cannot assure you that any securities analysts will initiate or maintain research coverage of our company and our shares, any statements or changes in estimates by analysts initiating or covering our shares or relating to the oil and gas industry could result in an immediate and adverse effect on the market price of our shares. Further, we cannot predict the effect, if any, that market sales of shares or the availability of shares for sale will have on the market price of the shares prevailing from time to time. Issuance and sale of a substantial number of shares or the perception that such sales could occur, could have a material adverse effect on the market price of our shares.

Trading in shares of companies, such as ours, have been subject to extreme price and volume fluctuations that have been unrelated or disproportionate to operating or other performance.

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

Our common stock is quoted on the OTC Market. Trading in stock quoted on the OTC Bulletin Board 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. This volatility could depress the market price of our common stock for reasons unrelated to operating performance. Moreover, the OTC Market is not a stock exchange, and trading of securities on the OTC Market is often more sporadic than the trading of securities listed on other stock exchanges such as the NASDAQ Stock Market, New York Stock Exchange or American Stock Exchange. Accordingly, our shareholders may have difficulty reselling any of their shares.

Our common stock is a penny stock. Trading of our stock may be restricted by the SEC’s penny stock regulations and the FINRA’s sales practice requirements, which may limit a shareholders ability to buy and sell our stock.

Our common 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) 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 term accredited investor refers generally to institutions with assets in excess of $5,000,000 or individuals with a net worth in excess of $1,000,000 or annual income exceeding $200,000 or $300,000 jointly with their spouse. 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 must also 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 or willingness of broker-dealers to trade our securities. We believe that the penny stock rules discourage broker-dealer and investor interest in, and limit the marketability of, our common stock.

FINRA sales practice requirements may also limit a shareholders ability to buy and sell our stock.

In addition to the penny stock rules promulgated by the SEC, which are discussed in the immediately preceding risk factor, FINRA rules 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 the ability to buy and sell our stock and have an adverse effect on the market value for our shares.

There are a substantial number of shares of our common stock eligible for future sale in the public market. The sale of a large number of these shares could cause the market price of our common stock to fall.

There were 14,295,413 shares of our common stock outstanding as of April 29, 2016. As of that date, members of our management and their affiliates beneficially owned approximately 4,507,500 shares of our common stock, representing 31.5% of our outstanding common stock. Sale of a substantial number of these shares would likely have a significant negative effect on the market price of our common stock, particularly if the sales are made over a short period of time.

If our shareholders, particularly management and their affiliates, sell a large number of shares of our common stock, the market price of shares of our common stock could decline significantly. Moreover, the perception in the public market that our management and affiliates might sell shares of our common stock could depress the market price of those shares.

Because we have no plans to pay dividends on our common stock, investors must look solely to stock appreciation for a return on their investment in us.

We have never declared or paid cash dividends on our common stock. We currently intent to retain all future earnings and other cash resources, if any, for the operations and development of our business and do not anticipate paying cash dividends in the foreseeable future. Payment of any future dividends will be at the discretion of our board of directors after taking into account many factors, including our financial condition, operating results, current and anticipated cash needs and plans for expansions. In addition, we may not pay cash dividends on our common stock for so long as any shares of our convertible preferred stock are outstanding. Any future dividends may also be restricted by any loan agreements which we may enter into from time to time and from the issuance of preferred stock should we decide to do so in the future.

Access to Information

Our website address is www.areteindustries.com We make available, free of charge, on the “Filings” section of our website, our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and all amendments to those reports, as soon as reasonably practicable after these reports are electronically filed with or furnished to the Securities and Exchange Commission (“SEC”). We also make available through our website other reports electronically filed with the SEC under the Securities Exchange Act of 1934, including our proxy statements. We do not intend for information contained in our website to be part of this Annual Report on Form 10-K.

Item 1B.

UNRESOLVED STAFF COMMENTS

None

Item 2.

PROPERTIES

Oil and Natural Gas Properties

The following table lists our oil and natural gas wells by state and field as of December 31, 2015:

	Productive Wells
	During 2015
State	Gross		Net (a)
Wyoming		32.0		22.4
Kansas		5.0		3.4
Colorado		5.0		4.9
Nebraska		-		-
Montana		1.0		1.0
		43.0		31.7

(a)	Net wells are the sum of our fractional working interests owned in gross wells.

Oil and Natural Gas Reserves

All of our oil and natural gas reserves are located in the United States. Unaudited information concerning the estimated net quantities of all of our proved reserves and the standardized measure of future net cash flows from the reserves is presented in Note 13 – Supplementary Information on Oil and Gas Information (Unaudited) in the Notes to the financial statements in in this report. The reserve estimates have been prepared by Pinnacle Energy Services, L.L.C. (“Pinnacle”), an independent petroleum engineering firm. We have no long-term supply or similar agreements with foreign governments or authorities. We did not provide any reserve information to any federal agencies in 2015 other than to the SEC.

The table below summarizes our estimated proved reserves at December 31, 2015 based on reports prepared by Pinnacle. In preparing these reports, Pinnacle evaluated 100% of our properties at December 31, 2015. For more information regarding our independent reserve engineers, please see “Independent Reserve Engineers” below.


	Proved Reserves at 2015 Year-End								2015 Average
	Quantity		Pre and Post-Tax			%			Monthly Production
State	(BOE) (a)		PV 10% (b)			Oil (c)			(BOE)
Wyoming		201,438		$	885,720		67.8	%		1,376
Kansas		113,920			1,623,570		100.0	%		568
Colorado		3,667			8,830		11.7	%		444
Nebraska		1,610			9,690		100.0	%		-
Montana		14,293			24,860		0.0	%		61
		334,928		$	2,552,670		82.2	%		2,449

(a)	BOE is defined as one barrel of oil equivalent determined using the ratio of six Mcf of natural gas to one barrel of oil.
(b)	The prices used in this report were computed by applying the SEC-mandated 12 month arithmetic average of the first of month price for January through December 31, 2015, which resulted in benchmark prices of $50.28 per barrel for crude oil and $2.587 per MMbtu for natural gas. Benchmark prices were further adjusted on a well by well basis for transportation, quality and basis differentials to arrive at the prices used for this report. The differential ranged by well from -$3.40/bbl to -$10.77/bbl for oil and for natural gas ranged from minus 81% to plus 59% of NYMEX.
(c)	Computed based on BOE using the ratio of six Mcf of natural gas to one barrel of oil.

Reconciliation of Standardized Measure to PV10

PV10 is the estimated present value of the future net revenues from our proved oil and natural gas reserves before income taxes discounted using a 10% discount rate. PV10 is considered a non-GAAP financial measure because it does not include the effects of future income taxes, as is required in computing the standardized measure of discounted future net cash flows. We believe that PV10 is an important measure that can be used to evaluate the relative significance of our oil and natural gas properties and that PV10 is widely used by securities analysts and investors when evaluating oil and natural gas companies. Because many factors that are unique to each individual company impact the amount of future income taxes to be paid, we believe the use of a pre-tax measure provides greater comparability of assets when evaluating companies. We believe that many other companies in the oil and natural gas industry calculate PV10 on the same basis. PV10 is computed on the same basis as the standardized measure of discounted future net cash flows but without deducting income taxes. The table below provides a reconciliation of our standardized measure of discounted future net cash flows to our PV10 value:

	Standardized
	Measure			PV 10
Future cash inflows	$	13,002,030		$	6,604,328
Future production costs		( 7,976,560	)		(4,051,658	)
Future development cos		-			-
Future income taxes		-			-

Future net cash flows		5,025,470			2,552,670
10% annual discount		( 2,472,800	)		-

Discounted future net cash flows	$	2,552,670		$	2,552,670

There was no difference between the standardized measure of $2,552,670 and PV10 of $2,552,670 because there are no income taxes included in the standardized measure at December 31, 2015.

Proved Undeveloped Reserves

At December 31, 2015, we had no estimated proved undeveloped (“PUD”) reserves.

Technology Used to Establish Reserves

Under SEC rules, proved reserves are those quantities of oil and natural gas that 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, under existing economic conditions, operating methods and government regulations. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and natural gas actually recovered will equal or exceed the estimate. Reasonable certainty can be established using techniques that have been proven effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

To establish reasonable certainty with respect to our estimated proved reserves, Pinnacle employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our reserves include, but are not limited to, electrical logs, radioactivity logs, core analyses, geologic maps and available downhole and production data, seismic data and well test data. Reserves attributable to producing wells with sufficient production history were estimated using appropriate decline curves or other performance relationships. Reserves attributable to producing wells with limited production history and for undeveloped locations were estimated using both volumetric estimates and performance from analogous wells in the surrounding area. These wells were considered to be analogous based on production performance from the same formation and completion using similar techniques.

Independent Reserve Engineers

We engaged Pinnacle Energy Services, LLC (‘Pinnacle’) to prepare our annual reserve estimates and have relied on Pinnacle’s expertise to ensure that our reserve estimates are prepared in compliance with SEC guidelines. Pinnacle was founded in 1998 and performs consulting petroleum engineering services under Texas Firm License No. F6204. Within Pinnacle, the technical person primarily responsible for preparing the estimates set forth in the Pinnacle reserves report incorporated herein is Mr. Richard Morrow. Mr. Morrow has been practicing consulting petroleum engineering at Pinnacle since 2012. Mr. Morrow is a Registered Professional Engineer in the States of Oklahoma (No. 13684) and Wyoming (No. 5932), and has over 39 years of practical experience in petroleum engineering, with over 25 years of experience in the estimation and evaluation of reserves. He graduated from the University of Kansas in 1976 with a Bachelor of Science degree in Petroleum Engineering. He meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; he is proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.

We do not retain any employee or consultant primarily responsible for overseeing the preparation of our reserve estimates or for overseeing the independent petroleum engineering firm during the preparation of our reserve report.

Internal Control over Preparation of Reserve Estimates

We do not maintain adequate and effective internal controls over our reserve estimation process as well as the underlying data upon which reserve estimates are based. The primary inputs to the reserve estimation process are technical information, financial data, ownership interest, and production data. The relevant field and reservoir technical information, which is updated annually, is assessed for validity when our independent petroleum engineering firm has technical meetings with our officers. Current revenue and expense information is obtained from our accounting records, which are subject to external quarterly reviews and annual audits. All current financial data such as commodity prices, lease operating expenses, production taxes and field-level commodity price differentials are updated in the reserve database and then analyzed to ensure that they have been entered accurately and that all updates are complete. Our current ownership in mineral interests and well production data are also subject to our internal controls over financial reporting, and they are incorporated in our reserve database as well and may be verified internally by us to ensure their accuracy and completeness. Once the reserve database has been updated with current information, and the relevant technical support material has been assembled, our independent engineering firm meets with our management to review field performance and future development plans in order to further verify the validity of estimates. Following these reviews the reserve database is furnished to Pinnacle so that it can prepare its independent reserve estimates and final report. In the event that additional data supports a reserve estimation adjustment, Pinnacle will analyze the additional data, and may make changes it deems necessary. Additional data is usually comprised of updated production information on new wells. Once the review is completed and all material differences are reconciled, the reserve report is finalized and our reserve database is updated with the final estimates provided by Pinnacle. Access to our reserve database is restricted to our executive officers.

Production, Average Price and Average Production Cost

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

	Years Ended December 31,
	2015			2014			2013
Oil sales	$	777,123		$	1,797,230		$	1,791,451
Natural gas sales		143,907			361,053			434,230
Royalty revenues		4,871			3,369			533
Sale of oil and natural gas properties		27,120			391,585			347,888
Total revenue		953,021			2,553,237			2,574,102
Production taxes		(84,576	)		(179,660	)		(187,594	)
Lease operating expense		(754,362	)		(791,142	)		(679,172	)
Other operating expenses		(160,011	)		(36,250	)		-
Depreciation, depletion, amortization and accretion (“DD&A”)		(816,481	)		(767,857	)		(665,123	)
Impariement expense		(3,231,000	)		-			-
Net	$	(4,093,409	)	$	778,328		$	1,042,213
Net barrels of oil sold		18,956			22,825			21,304
Net Mcf of gas sold		62,630			70,195			82,207
Net Barrels of Oil Equivalent (“BOE”) sold		29,394			34,524			35,005
Average price per barrel of oil sold	$	41.00		$	78.74		$	84.09
Average price for per Mcf of natural gas sold	$	2.30		$	5.14		$	5.28
Lease operating expense per BOE	$	25.66		$	22.92		$	19.40
DD&A per BOE	$	27.78		$	22.24		$	19.01

Gross and Net Developed and Undeveloped Acres

As of December 31, 2015, we had total gross and net developed and undeveloped leasehold acres as set forth below. The developed acreage is stated on the basis of spacing units designated or permitted by state regulatory authorities. Gross acres are those acres in which a working interest is owned. The number of net acres represents the sum of fractional working interests we own in gross acres.

	Undeveloped				Developed
State	Gross		Net		Gross		Net
Wyoming		-		-		8,551		7,865
Kansas		-		-		1,510		743
Nebraska		4,400		1,528		160		120
Total		4,400		1,528		10,221		8,728

Exploratory Wells and Development Wells

Set forth below for the years ended December 31, 2015, 2014 and 2013 is information concerning our drilling activity during the years indicated.

	Net Exploratory Wells Drilled				Net Development Wells Drilled				Total Net Productive and Dry Wells
Year	Productive		Dry		Productive		Dry		Drilled
2015		0.00		0.00		0.00		0.00		0.00
2014		0.00		0.00		0.0169		0.00		0.0169
2013		0.00		0.00		0.0285		0.00		0.0285

Present Activities

At March 29, 2016, we had 0 gross (0 net) wells in the process of drilling or completing.

Supply Contracts or Agreements

Crude oil and condensate are sold through month-to-month evergreen contracts. The price is tied to an index or a weighted monthly average of posted prices with certain adjustments for gravity, Basic Sediment and Water (“BS&W”) and transportation.

Competition

The oil and natural gas industry is highly competitive and we compete with a substantial number of other companies that have greater financial and other resources than us. Many of these companies explore for, produce and market oil and natural gas, as well as carry on refining operations and market the resultant products on a worldwide basis. The primary areas in which we encounter substantial competition are in locating and acquiring desirable leasehold acreage and locating and acquiring attractive producing oil and natural gas properties. There is also competition among oil and natural gas producers and other industries producing energy and fuel. Furthermore, competitive conditions may be substantially affected by various forms of energy legislation and/or regulation considered from time to time by the U.S. government and the states in which our properties are located. It is not possible to predict the nature of any such legislation or regulation which may ultimately be adopted or its effects upon our future operations.

Other Business Matters

Major Customers

The purchasers of our oil, natural gas and natural gas liquids production consist of oil and natural gas companies. Our major customers for 2015 and 2014 were as follows. All are unaffiliated with the Company.

Year	Name of Customer	Amount of Year’s Gross Revenues
2014	Plains Marketing		68	%
2014	DCP Midstream		16	%

2015	Plains Marketing		67	%
2015	DCP Midstream		15	%

We believe there are adequate alternate purchasers of our production such that the loss of one or more of the purchasers would not have a material adverse effect on our results of operations or cash flows.

Seasonality of Business

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

Operational Risks

Oil and natural gas exploration and development involves a high degree of risk, which even a combination of experience, knowledge and careful evaluation may not be able to overcome. There is no assurance that we will discover or acquire additional oil and natural gas in commercial quantities. Oil and natural gas operations also involve the risk that well fires, blowouts, equipment failure, human error and other events may cause accidental leakage or spills of toxic or hazardous materials, such as petroleum liquids or drilling fluids into the environment, or cause significant injury to persons or property. In such event, substantial liabilities to third parties or governmental entities may be incurred, the satisfaction of which could substantially reduce available cash and possibly result in loss of oil and natural gas properties. Such hazards may also cause damage to or destruction of wells, producing formations, production facilities and pipeline or other processing facilities.

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

Title to Properties

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

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

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

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

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

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

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

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

Gas Gathering System

In September 2006, the Company acquired a gas gathering system (pipeline and compressor station related assets) located in Campbell County, Wyoming. This system was constructed in late 2001 and began operations early in 2002. The system consists of 4.5 miles of 8-inch coated steel pipeline. This pipeline has been shut-in since June 2011 and is not generating revenue. The system has been shut in due to the low price of natural gas and at December 31, 2015, we wrote off the remaining book value of this asset recording $56,648 of impairment expense..

This system has a current throughput capacity of approximately 4 million cubic feet (“MMcf”) of gas per day. Since July 2011, the Company has owned a 100% working interest in all of the coal-bed methane properties that are connected to the Company’s gathering system.

Office Facilities

We currently lease no office space.

Item 3.

LEGAL PROCEEDINGS

None

Item 4.

MINE SAFETY DISCLOSURES

Not Applicable.

PART II

Item 5.

MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Our common stock has been quoted on the OTCQB tier of the OTC Markets. Our trading symbol is “ARET.OTCQB”

The following table sets forth the range of high and low trading price information for our common stock for each fiscal quarter for the past two fiscal years as reported by the OTC Markets Inc. and obtained from Yahoo Finance. High and low trading information represents prices between dealers without adjustment for retail mark-ups, markdowns or commissions.

	HIGH		LOW
Year Ended December 31, 2015:
First Quarter	$	0.17	$	0.08
Second Quarter		0.22		0.11
Third Quarter		0.16		0.11
Fourth Quarter		0.20		0.07
Year Ended December 31, 2014:
First Quarter	$	0.89	$	0.22
Second Quarter		0.45		0.26
Third Quarter		0.43		0.20
Fourth Quarter		0.27		0.08

On April 12, 2016, the last reported sales price of our common stock as reported on the OTCQB was approximately $.08 per share.

Holders

As of April 14, 2016, the number of holders of record of shares of our common stock, our only class of trading securities, was approximately 2,940. The number of record holders of our common stock was determined from the records of our transfer agent and does not include numerous beneficial owners of our common stock whose shares are held in street name by various security brokers, dealers, and registered clearing agencies. The number of beneficial shareholders is unknown to us.

Dividends

The Company has not paid any cash dividends with respect to its common stock and it is not anticipated that the Company will pay cash dividends in the foreseeable future. Under its line of credit agreement with its bank, the Company must obtain permission from the bank to pay a cash dividend.

The Securities Enforcement and Penny Stock Reform Act of 1990

The SEC has adopted rules that regulate broker-dealer practices in connection with transactions in penny stocks. Penny stocks are generally equity securities with a price of less than $5.00 (other than securities registered on certain national securities exchanges or quoted on the Nasdaq system, provided that current price and volume information with respect to transactions in such securities is provided by the exchange or system). Our common shares are currently subject to the penny stock rules.

A purchaser purchasing a penny stock has limitations on the ability to sell the stock. The Company’s no par value common stock constitute a penny stock under the Exchange Act. The classification of a penny stock makes it more difficult for a broker-dealer to sell the stock into a secondary market, which makes it more difficult for a purchaser to liquidate his/her investment. Any broker-dealer engaged by the purchaser for the purpose of selling his or her shares in us will be subject to Rules 15g-1 through 15g-10 of the Exchange Act. Rather than creating a need to comply with those rules, some broker-dealers will refuse to attempt to sell penny stock.

The penny stock rules require a broker-dealer, prior to a transaction in a penny stock not otherwise exempt from those rules, to deliver a standardized risk disclosure document prepared by the SEC, which:

•

contains a description of the nature and level of risk in the market for penny stocks in both public offerings and secondary trading;

•

contains a description of the broker’s or dealer’s duties to the customer and of the rights and remedies available to the customer with respect to a violation to such duties or other requirements of the Exchange Act, as amended;

•

contains a brief, clear, narrative description of a dealer market, including “bid” and “ask” prices for penny stocks and the significance of the spread between the bid and ask price;

•

contains a toll-free telephone number for inquiries on disciplinary actions;

•

defines significant terms in the disclosure document or in the conduct of trading penny stocks; and

•

contains such other information and is in such form (including language, type, size and format) as the SEC shall require by rule or regulation.

The broker-dealer also must provide, prior to effecting any transaction in a penny stock, to the customer:

•

the bid and offer quotations for the penny stock;

•

the compensation of the broker-dealer and its salesperson in the transaction;

•

the number of shares to which such bid and ask prices apply, or other comparable information relating to the depth and liquidity of the market for such stock; and

•

monthly account statements showing the market value of each penny stock held in the customer’s account.

In addition, the penny stock rules require that prior to a transaction in a penny stock not otherwise exempt from those 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 acknowledgment of the receipt of a risk disclosure statement, a written agreement to transactions involving penny stocks, and a signed and dated copy of a written suitability statement. These disclosure requirements have the effect of reducing the trading activity in the secondary market for our stock. Thus, shareholders may have difficulty selling their securities.

Our Transfer Agent

ComputerShare Investor Services is the transfer agent for our Common Stock. ComputerShare can be contacted at 250 Royal Street, Canton, MA 02021.

Securities Authorized for Issuance Under Equity Compensation Plans

We do not have any equity compensation plans in effect.

Repurchases of Equity Securities of the Issuer

None

Item 6.

SELECTED FINANCIAL DATA

As a smaller reporting issuer, the Company is not required to report selected financial data specified in Item 301 of Regulation S-K.

Item 7.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

General Overview

We discuss and provide below our analysis of the following:

•

Critical accounting policies;

•

Results of operations;

•

Liquidity and capital resources;

•

Contractual obligations and commercial commitments;

•

Off-balance sheet arrangements;

•

New accounting pronouncements; and

•

Controls and procedures.

As of December 31, 2015, the Company had a working capital deficit of $1,384,443 and a balance of cash and equivalents of $521,666. For the past few years we have obtained loans, primarily from related parties, and incurred significant operating payables.

In the third quarter of 2011, we completed an acquisition of oil and natural gas properties in Montana, Wyoming, Colorado and Kansas. These properties include proved undeveloped and probable drilling opportunities. However, due to our working capital deficit discussed above, our primary challenge is to obtain additional financing to primarily address the significant working capital deficit and secondarily to seek to exploit existing drilling opportunities and possibly to acquire additional properties. We have sold some of these properties while retaining overriding royalty interests for future upside upon further development of the properties. In addition, from time to time we review opportunities for the purchase of production and underdeveloped oil and gas leases for future development. In order to purchase properties or begin substantive drilling activities we must obtain additional financing, which cannot be assured. We rely heavily on the skills of our board members in the areas of business development, capital acquisition, corporate visibility, oil and gas development, geology and operations.

There are no assurances that we can resolve our pressing capital needs, and although we have revenue from operations, our ability to execute our plans will still be dependent on our ability to raise additional capital. Our operating cash flow is dependent on the prices for crude oil. We also have a line of credit for $1,500,000 of which we have drawn $616,105.

While we seek to reduce the amount of our variable costs on an ongoing basis, it is difficult to reduce or offset our fixed expenses related to being a public company, such as legal, accounting, transfer agent fees, reporting, corporate governance, and shareholder communications. We also incur cash costs for the due diligence, reserve studies, audits, and legal cost for any proposed acquisitions of oil and gas properties.

Our future expectation is that monthly operating expenses will remain as low as possible until we can raise additional capital to address our working capital deficit.

Critical Accounting Policies

The Company has identified the accounting policies described below as critical to its business operations and the understanding of the Company’s results of operations. The impact and any associated risks related to these policies on the Company’s business operations is discussed throughout this section where such policies affect the Company’s reported and expected financial results. The preparation of our consolidated financial statements requires the Company to make estimates and assumptions that affect the reported amount of assets and liabilities of the Company, revenues and expenses of the Company during the reporting period, and contingent assets and liabilities as of the date of the Company’s consolidated financial statements. There can be no assurance that the actual results will not differ from those estimates.

Revenue Recognition

We record revenue from the sale of natural gas, NGL’s and crude oil when delivery to the purchaser has occurred and title has transferred. We use the sales method to account for gas imbalances. Under this method, revenue is recorded on the basis of gas actually sold by us. In addition, we record revenue for our share of gas sold by other owners that cannot be volumetrically balanced in the future due to insufficient remaining reserves. Our remaining over- and under-produced gas balancing positions are considered in our proved oil and gas reserves. Gas imbalances at December 31, 2014 and 2015 were not material.

Use of Estimates

Preparation of our financial statements in accordance with GAAP requires management to make various assumptions, judgments and estimates that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Changes in these assumptions, judgments and estimates will occur as a result of the passage of time and the occurrence of future events and, accordingly, actual results could differ from amounts initially established.

The most significant areas requiring the use of assumptions, judgments and estimates relate to the volumes of natural gas and oil reserves used in calculating depreciation, depletion and amortization, which we refer to as DD&A, the amount of expected future cash flows used in determining possible impairments of oil and gas properties and the amount of future capital costs used in these calculations. Assumptions, judgments and estimates also are required in determining future asset retirement obligations, impairments of undeveloped properties, and in valuing stock-based payment awards.

Oil and Gas Producing Activities

In January 2010, the Financial Accounting Standards Board, which we refer to as the FASB, issued authoritative oil and gas reserve estimation and disclosure guidance that was effective for the Company beginning in 2010. This guidance was issued to align the accounting oil and gas reserve estimation and disclosure requirements with the requirements in the SEC final rule, “Modernization of Oil and Gas Reporting”, which was also effective in 2010.

Our oil and gas exploration and production activities are accounted for using the successful efforts method. Under this method, all property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending determination of whether the well has found proved reserves. If an exploratory well does not find proved reserves, the costs of drilling the well are charged to expense and included within cash flows from investing activities in the Statements of Cash Flows. The costs of development wells are capitalized whether productive or nonproductive. Oil and gas lease acquisition costs are also capitalized.

Other exploration costs, including certain geological and geophysical expenses and delay rentals for oil and gas leases, are charged to expense as incurred. The sale of a partial interest in a proved property is accounted for as a cost recovery and no gain or loss is recognized as long as this treatment does not significantly affect the unit-of-production DD&A rate. A gain or loss is recognized for all other sales of proved properties and is classified in other operating revenues. Maintenance and repairs are charged to expense, and renewals and betterments are capitalized to the appropriate property and equipment accounts.

Unevaluated oil and gas property costs are transferred to proved oil and gas properties if the properties are subsequently determined to be productive. Proceeds from sales of partial interests in unproved leases are accounted for as a recovery of cost without recognizing any gain until all costs are recovered. Unevaluated oil and gas properties are assessed periodically for impairment on a property-by-property basis based on remaining lease terms, drilling results, reservoir performance, commodity price outlooks and future plans to develop acreage.

We review our proved oil and gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. We estimate the expected undiscounted future cash flows of our oil and gas properties and compare such undiscounted future cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we will adjust the carrying amount of the oil and gas properties to fair value. The factors used to determine fair value include, but are not limited to, recent sales prices of comparable properties, the present value of estimated future cash flows, net of estimated operating and development costs using estimates of reserves, future commodity pricing, future production estimates, anticipated capital expenditures and various discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flows projected.

The provision for DD&A of oil and gas properties is calculated on a field-by-field basis using the unit-of-production method. Natural gas is converted to barrel equivalents, BOE, at the rate of six Mcf to one barrel of oil. Estimated future dismantlement, restoration and abandonment costs, which are net of estimated salvage values, are taken into consideration.

Asset Retirement Obligations

The estimated fair value of the future costs associated with dismantlement, abandonment and restoration of oil and gas properties is recorded generally upon acquisition or completion of a well. The net estimated costs are discounted to present values using a credit-adjusted, risk-free rate over the estimated economic life of the oil and gas properties. Such costs are capitalized as part of the related asset. The asset is depleted on the units-of-production method on a field-by-field basis. The associated liability is classified in current and long-term liabilities in the Balance Sheets. The liability is periodically adjusted to reflect (1) new liabilities incurred, (2) liabilities settled during the period, (3) accretion expense and (4) revisions to estimated future cash flow requirements. The accretion expense is recorded as a component of depreciation, depletion and amortization expense in the Consolidated Statements of Operations.

Stock-based Compensation

We did not grant any stock options or warrants during 2015 and 2014 and no options or warrants were outstanding at any time during these years. We have issued shares of common stock for services performed by officers, directors and unrelated parties during 2015 and 2014. We have recorded these transactions based on the value of the services or the value of the common stock, whichever is more readily determinable.

Results of Operations for the Years Ended December 31, 2015 and 2014

Presented below is a discussion of our results of operations for the years ended December 31, 2015 and 2014.

Oil and Gas Producing Activities

In 2011, we entered into a purchase and sale agreement which resulted in our acquisition of producing oil and gas properties in Wyoming, Colorado, Kansas and Montana. Presented below is a summary of our oil and gas operations for the years ended December 31, 2015 and 2014:


	2015			2014
Oil sales	$	777,123		$	1,797,230
Natural gas sales		143,907			361,053
Royalty revenue		4,871			3,369
Sale of oil and natural gas properties		27,120			391,585

Total revenue		953,021			2,553,237
Production taxes		(84,576	)		(179,660	)
Lease operating expense		(754,362	)		(791,142	)
Other operating expenses		(160,011	)		(36,250	)
Depreciation, depletion, amortization and accretion (“DD&A”)		(816,481	)		(767,857	)
Impairment expense		(3,231,000	)		-

Net	$	(4,093,409	)	$	778,328

Net barrels of oil sold		18,956			22,825
Net Mcf of gas sold		62,630			70,195
Net Barrels of Oil Equivalent (“BOE”) sold		29,394			34,524
Average price per barrel of oil sold	$	41.00		$	78.74

Average price for per Mcf of natural gas sold	$	2.30		$	5.14

Lease operating expense per BOE	$	25.66		$	22.92

DD&A per BOE	$	27.78		$	22.24

Our oil sales are primarily attributable to our properties in Kansas and Wyoming. The average realized oil price for 2015 and 2014 were $41.00 and $78.74 per barrel, respectively, a decrease of 47.9% or $37.74 per barrel and our oil sales volumes decreased 3,869 barrels or 17.0%, resulting in barrels sold of 18,956 compared to 22,825 in the prior year. These decreases in oil price and volumes negatively impacted our oil sales revenues by $1,020,107 compared to the prior year. The impact of the lower prices reduced our revenue by $861,476 and the lower volumes impacted revenue by $158,631. This decrease in our oil sales volumes is attributed to the natural decline of production in our wells and to the inclement weather in March, April and May of 2015, which made it difficult to get back to the tank batteries and pick up the oil to transport it to the market. The wells automatically shut-in once the tank batteries become full.

The average realized natural gas prices, including proceeds from sales of natural gas liquids, was $2.30 and $5.14 per Mcf for the years ended December 31, 2015 and 2014, respectively, and our natural gas sales volumes decreased from 70,195 mcf in 2014 to 62,630 mcf in 2015, resulting in a decrease of 7,565 mcf or 10.8%. The impact due to lower prices resulted in a decrease of natural gas revenues of $199,764, while the impact of lower sales volumes decreased revenue by $17,382.

Production taxes on a per BOE basis for the years ended December 31, 2015 and 2014, decreased 52.9% compared to the prior year. We generally expect production tax expense to trend with oil, gas, and NGL production revenue. Product mix, the location of production, and incentives to encourage oil and gas development can all impact or change the amount of production tax we recognize. Production taxes as a percentage of revenue was 8.3% and 9.1% during 2015 and 2014, respectively.

Gas Gathering

We have owned and operated a natural gas gathering system (pipeline and compressor station) for coal bed methane properties in the Powder River Basin of Wyoming since 2006. We have had no revenues relating to this system since June 2011 due to low natural gas prices which resulted in all wells in the field being shut-in. While this field is shut-in we do continue to perform routine maintenance to ensure it is in a safe condition. Operating expenses for 2015 and 2014 were $1,406 and $8,926, respectively. At December 31, 2015, we wrote off the remaining book value of this asset by recording $56,648 of impairment expense.

General and Administrative

Presented below is a summary of general and administrative expenses for the years ended December 31, 2015 and 2014:


	2015		2014		Change
Director fees	$	47,833	$	20,450	$	27,383
Investor relations		28,128		65,833		(37,705	)
Legal, auditing and professional services		116,078		146,581		(30,503	)
Consulting and executive services:
Related parties		172,217		220,800		(48,583	)
Unrelated parties		—		—		—
Other administrative expenses		74,634		72,807		1,827
Depreciation		428		570		(142	)

Total general and administrative expenses	$	439,318	$	527,041	$	(87,723	)

General and administrative expenses decreased by $87,723 for 2015 compared to 2014, primarily due to decreases in investor relations, legal, auditing and professional fees and related party consulting services. Director fees increased by $27,383 and other administrative expenses increased slightly by 1,827. The increase in directors fees is related to shares issued to two board members for five years of service on the board and the addition of a new board member increasing the board from 5 seats to 6 seats.

We have an operating agreement with DNR, whereby executive level expertise for our existing and prospective oil and gas properties is provided for a monthly fee of $18,000. This monthly charge is allocated $10,000 to consulting and executive services and $8,000 is allocated to lease operating expense. DNR is an affiliate of Charles B. Davis, an executive officer and director of the Company.

We had a net loss for 2015 of $4,747,053 compared to net income of $62,369 for 2014. This decrease was primarily due to decreased revenues from lower oil and natural gas prices and volumes and a one-time non-cash charge of approximately $3.3 million recorded as impairment expense related to our oil and gas properties and gas gathering system. Depreciation, depletion & amortization increased approximately $48,000 due to a lower reserve base. These costs were offset slightly by lower lease operating costs, which decreased approximately $37,000 and lower production taxes, which are directly related to revenue, which decreased approximately $95,000.

Interest expense decreased from $135,773 for 2014 to $111,910 for 2015. The decrease of $23,863 was due primarily to the pay down of principal on certain notes payable.

Liquidity and Capital Resources

In order to execute our drilling plans and to be in a position to seek to acquire additional interests in oil and gas properties that meet our objectives, we need to obtain significant additional financing. Historically, we have used a line of credit, preferred stock offerings and sales of oil and gas properties in order to fund our operations. In late 2015, we raised approximately $1.7 million through a private placement of our Series A2 Preferred Stock to accredited investors only. Also, since 2011, we have sold various interests in some of our oil and gas properties, which have resulted in aggregate net proceeds from three sales of $6,377,000. We intend to continue to sell properties, but only those properties that can be liquidated at attractive prices. There can be no assurance that we will continue to generate any proceeds from the sale of our properties or that we will successfully raise additional capital from sales of our equity.

We had a working capital deficit as of December 31, 2015 of approximately $1.4 million, compared to a working capital deficit of approximately $1.3 million at December 31, 2014. The increase in our deficit was primarily due to the payable due to DNR related to a settlement agreement of approximately $300,000 that was accrued as part of operator fees and other in current liabilities, an increase in our current obligation for our asset retirement obligations and certain notes payable that are due within 12 months. This was offset with higher current assets, primarily due to sales of preferred stock.

We used $96,890 in operating cash flow during the year ended 2015 compared to $658,919 generated through operating cash flow during the year ended 2014. This is primarily related to lower oil and natural gas prices and lower sales volumes, which resulted in lower revenues of approximately $1.6 million.

During 2015 investing activities used net cash of approximately $1.1 million, which was attributed to an acquisition of oil and gas properties that we closed on December 30, 2015. We also had capital additions of $68,631, which was offset with proceeds received of $50,000 for the sale of one of our wells. During 2014, we generated net proceeds of approximately $313,000 from a participation agreement in an oil and gas property, which was offset with capital additions of $640,000, resulting in net cash used in investing activities of $326,470.

We had approximately $1.7 million of net cash provided by financing activities in 2015, compared to net cash used in financing activities of $778,000 in 2014. We borrowed $67,000 against our line of credit during the year, we made principal payments to certain notes payables of $25,568 and we raised $1,665,000 through our Series A2 Preferred Stock private placement. The 2014 financing activities included borrowings of approximately $623,000. These funds were needed to fund our operations, a redemption of Series A1 Preferred Stock of $15,500, repurchase of 1,200,000 shares of common stock for $228,000, and repayment of notes payable of $1,157,000.

Contractual Obligations and Commercial Commitments

As of December 31, 2015, we had no operating leases in place.

Off-Balance Sheet Arrangements

In connection with the related party acquisition of oil and gas properties in the third quarter of 2011, we acquired interests in certain geologic zones of the properties. This agreement contained several arrangements that would require us to pay certain amounts depending on certain thresholds met. However, on January 19, 2016, but effective December 31, 2015, we entered into a settlement agreement with the Sellers of these properties, whereby in consideration of the amounts indicated below, the parties (i) terminated Exhibits C and C-2 to the DNR and Tindall PSA for all purposes; (ii) extinguished all liabilities of the Company under Exhibit C of the DNR and Tindall PSA including $250,000, related to the increase in oil prices after the acquisition; (iii) agreed that the promissory note owed by us to DNR in the amount of $792,151 and accrued interest thereon was paid in full; and (iv) released each other against any and all claims which have been raised or could have been raised among them. Specifically, Exhibits C and C-2 to the DNR and Tindall PSA related to potential payments that would have been needed to be made by us in the event oil prices increased to certain levels and related to certain payments that would have been needed to be made by us in the event we sold certain properties purchased under the Purchase and Sale Agreement. Exhibits C and C-2 were terminated and extinguished (including any amounts owed thereunder including $250,000 under Exhibit C to the Purchase and Sale Agreement) in exchange for 25 fully paid, nonassessable restricted shares of our 7% Series A2 Convertible Preferred Stock. Consideration to pay the above promissory note in full consisted of us issuing to DNR 65 fully paid, nonassessable restricted shares of our 7% Series A2 Convertible Preferred Stock, and paying DNR $303,329 in cash.

New Accounting Pronouncements

In June 2014, the FASB issued ASU No. 2014-12, Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could Be Achieved after the Requisite Service Period (“ASU 2014-12”). The amendments in ASU 2014-12 require that a performance target that affects vesting and that could be achieved after the requisite service period be treated as a performance condition. A reporting entity should apply existing guidance in Accounting Standards Codification Topic No. 718, “Compensation – Stock Compensation” (“ASC 718”), as it relates to awards with performance conditions that affect vesting to account for such awards. The amendments in ASU 2014-12 are effective for annual periods and interim periods within those annual periods beginning after December 15, 2015. Early adoption is permitted. Entities may apply the amendments in ASU 2014-12 either: (a) prospectively to all awards granted or modified after the effective date; or (b) retrospectively to all awards with performance targets that are outstanding as of the beginning of the earliest annual period presented in the financial statements and to all new or modified awards thereafter. The adoption of ASU 2014-12 is not expected to have a material effect on the Company’s consolidated financial statements or disclosures.

In April 2014, the FASB issued ASU 2014-08, “Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity.” ASU 2014-08 changes the criteria for reporting a discontinued operation. Under the new pronouncement, a disposal of a part of an organization that has a major effect on its operations and financial results is a discontinued operation. The Company is required to adopt ASU 2014-08 prospectively for all disposals or components of its business classified as held for sale during fiscal periods beginning after December 15, 2014. The adoption of ASU 2014-08 did not have a material effect on the Company’s consolidated financial statements or disclosures.

In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers” (“ASU 2014-09”), which provides guidance for revenue recognition. ASU 2014-09 affects any entity that either enters into contracts with customers to transfer goods or services or enters into contracts for the transfer of nonfinancial assets and supersedes the revenue recognition requirements in Topic 605, “Revenue Recognition,” and most industry-specific guidance. This ASU also supersedes some cost guidance included in Subtopic 605-35, “Revenue Recognition- Construction-Type and Production-Type Contracts.” ASU 2014-09’s core principle is that a company will recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which a company expects to be entitled in exchange for those goods or services. In doing so, companies will need to use more judgment and make more estimates than under today’s guidance, including identifying performance obligations in the contract, estimating the amount of variable consideration to include in the transaction price and allocating the transaction price to each separate performance obligation. ASU 2014-09 is effective for the Company beginning January 1, 2017 and, at that time, the Company may adopt the new standard under the full retrospective approach or the modified retrospective approach. Early adoption is not permitted. The Company is currently evaluating the method and impact the adoption of ASU 2014-09 will have on the Company’s consolidated financial statements and disclosures.

In August 2014, the FASB issued ASU No. 2014-15, Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern (“ASU 2014-15”). ASU 2014-15 will explicitly require management to assess an entity’s ability to continue as a going concern, and to provide related footnote disclosure in certain circumstances. The new standard will be effective for all entities in the first annual period ending after December 15, 2016. Earlier adoption is permitted. We are currently evaluating the impact of the adoption of ASU 2014-15.

In April 2015, the Financial Accounting Standards Board (“FASB”) issued new authoritative accounting guidance requiring debt issuance costs to be presented on the balance sheet as a direct deduction from the carrying value of the related debt liability. This guidance is to be applied using a retrospective method and is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2015. Early application is permitted. The Company is currently evaluating the provisions of this guidance and assessing its impact on the Company's financial statements and disclosures.

In November 2015, the FASB issued ASU 2015-17 Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes. This guidance eliminates the current requirement for organizations to present deferred tax liabilities and assets as current and noncurrent in a classified balance sheet. Instead, organizations will be required to classify all deferred tax assets and liabilities as noncurrent. This guidance is effective for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods. The amendments may be applied prospectively to all deferred tax liabilities and assets or retrospectively to all periods presented. The Company does not expect this to impact its operating results or cash flows.

In September 2015, the FASB issued Accounting Standards Update No. 2015-16 (ASU 2015-16): Business Combinations (Topic 805), effective for annual reporting periods beginning after December 15, 2015, including interim periods within that reporting period, to simplify the accounting for measurement-period adjustments for an acquirer in a business combination. ASU 2015-16 requires an acquirer to recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. The acquirer is required to adjust its financial statements for the effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the change to the provisional amounts calculated as if the accounting had been completed at the acquisition date. We are currently evaluating the provisions of ASU 2015-16 and assessing the impact, if any, it may have on our financial position and results of operations.

Other accounting standards that have been issued or proposed by the FASB, or other standards-setting bodies, that do not require adoption until a future date are not expected to have a material impact on the Company’s financial statements upon adoption.

Item 8.

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

ARÊTE INDUSTRIES, INC. AND SUBSIDIARIES

INDEX TO FINANCIAL STATEMENTS



Report of Independent Registered Public Accounting Firm		33

Consolidated Balance Sheets – December 31, 2015 and 2014		34

Consolidated Statements of Operations – For the years ended December 31, 2015 and 2014		35

Consolidated Statements of Stockholders’ Equity – For the years ended December 31, 2015 and 2014		36

Consolidated Statements of Cash Flows – For the years ended December 31, 2015 and 2014		37

Notes to Consolidated Financial Statements		38

CAUSEY DEMGEN & MOORE P.C.

1125 Seventeenth Street, Suite 1450

Denver, Colorado 80202

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders

of Arête Industries, Inc.

We have audited the accompanying balance sheet of Arête Industries, Inc. as of December 31, 2015 and 2014, and the related statements of operations, stockholders’ equity and cash flows for the years then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these 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. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Arête Industries, Inc. at December 31, 2015 and 2014, and the results of its operations and its cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America.


Denver, Colorado May 6, 2016		/s/ CAUSEY DEMGEN & MOORE P.C.

ARÊTE INDUSTRIES, INC.

BALANCE SHEETS

December 31,


ASSETS	2015			2014

Current Assets:
Cash and equivalents	$	521,666		$	30,755
Receivable from DNR Oil & Gas, Inc.:
Oil and gas sales, net of production costs		-			103,668
Other		-			78,273
Accounts receivable - oil and gas sales		2,539			-
Subscription receivable		105,000			-
Prepaid expenses and other		32,554			34,222

Total Current Assets		661,759			246,918

Property and Equipment:
Oil and gas properties, at cost, successful efforts method:
Proved properties		8,683,273			10,222,668
Unevaluated properties		154,836			348,836
Natural gas gathering system		-			442,195
Furniture and equipment		22,522			22,522
Total property and equipment		8,860,631			11,036,221
Less accumulated depreciation, depletion and amortization		(3,245,522	)		(2,840,173	)

Net Property and Equipment		5,615,109			8,196,048

TOTAL ASSETS	$	6,276,868		$	8,442,966


LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable:
Payable to DNR Oil & Gas, Inc.:
Operator fees and other		501,281			36,000
Unrelated parties		64,896			43,365
Notes and advances payable - current portion:
Directors and affiliates		18,900			288,258
Unrelated parties		970,953			872,239
Accrued interest expense		11,974			3,279
Accrued consulting - related party		-			21,800
Director fees payable in common stock		-			20,900
Current portion of asset retirement obligations		409,621			191,843
Other accrued costs and expenses		68,577			63,642
Total Current Liabilities		2,046,202			1,541,326
Long-Term Liabilities:
Contingent acquisition costs payable to DNR Oil & Gas, Inc.		-			250,000
Notes and advances payable, net of current portion:
DNR Oil & Gas, Inc.		-			792,151
Directors and affiliates		315,292			62,440
Unrelated parties		22,758			63,534
Asset retirement obligations, net of current portion		585,576			557,170
Total Long-Term Liabilities		923,626			1,725,295
Total Liabilities		2,969,828			3,266,621
Commitments and Contingencies
Stockholders' Equity:
Convertible Class A preferred stock; $10,000 face value per share, authorized 1,000,000 shares:
Series 1; authorized 30,000 shares, issued and outstanding no shares in 2014 and no shares in 2015, liquidation preference of $0 in 2014 and 2015		-			-
Series 2; authorized 2,500 shares, 267 shares issued and outstanding in 2015, liquidation preference of $2,670,000 at December 31, 2015		2,670,000			-
Common stock, no par value; authorized 499,000,000 shares, 14,295,413 and 12,558,459 issued and outstanding in 2015 and 2014, respectively		21,502,635			21,294,887
Accumulated deficit		(20,865,595	)		(16,118,542	)
Total Stockholders' Equity		3,307,040			5,176,345
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	6,276,868		$	8,442,966

The Accompanying Notes are an Integral Part of These Financial Statements.

ARÊTE INDUSTRIES, INC.

STATEMENTS OF OPERATIONS

Years Ended December 31,


	2015			2014
Revenues:
Oil and natural gas sales	$	921,030		$	2,158,283
Sale of oil and natural gas properties		27,120			391,585
Royalty revenues		4,871			3,369
Total revenues		953,021			2,553,237
Operating Expenses:
Oil and gas producing activities:
Lease operating expenses		754,362			791,142
Production taxes		84,576			179,660
Other operating expense		160,011			36,250
Depreciation, depletion, amortization and accretion		816,481			767,857
Impairment		3,231,000			-
Gas gathering:
Operating expenses		1,406			8,926
Depreciation		44,362			44,219
Impairment		56,648			-
General and administrative expenses:
Director fees		47,833			20,450
Investor relations		28,128			65,833
Legal, auditing and professional fees		116,078			146,581
Consulting fees executive services-related parties		172,217			220,800
Other adminstrative expenses		74,634			72,807
Depreciation		428			570
Total operating expenses		5,588,164			2,355,095
Operating income (loss)		(4,635,143	)		198,142

Other income (expense)
Interest income (expense), net		(111,910	)		(135,773	)
Total other expense		(111,910	)		(135,773	)
Income (loss) before income taxes		(4,747,053	)		62,369
Income tax benefit (expense)		-			-
Net income (loss) attributable to Arete Industries, Inc.	$	(4,747,053	)	$	62,369
Net Income (Loss) Applicable to Common Stockholders:
Net income (loss)	$	(4,747,053	)	$	62,369
Redemption of preferred stock		-			17,951
Accrued preferred stock dividends		-			(9,375	)
Net income (loss) applicable to common stockholders	$	(4,747,053	)	$	70,945
Earnings (Loss) Per Share Applicable to Common Stockholders:
Basic	$	(0.37	)	$	0.01

Diluted	$	(0.37	)	$	0.01
Weighted Average Number of Common Shares Outstanding:
Basic		12,882,000			12,450,000

Diluted		12,882,000			12,450,000

The Accompanying Notes are an Integral Part of These Financial Statements.

ARÊTE INDUSTRIES, INC.

STATEMENTS OF STOCKHOLDERS' EQUITY

For the Years Ended December 31, 2014 and 2015


	Class A Preferred Stock						Common Stock						Accumulated
	Shares			Amount			Shares			Amount			Deficit			Total
Balances, December 31, 2013		10		$	95,451			13,608,459		$	21,488,387		$	(16,198,862	)	$	5,384,976
Issuance of common stock for oil and gas acquisition from related parties, shares valued at $0.23 per share		-			-			150,000			34,500			-			34,500
Redemption of common stock		-			-			(1,200,000	)		(228,000	)		-			(228,000	)
Redemption of preferred stock		(10	)		(95,451	)		-			-			17,951			(77,500	)
Net income		-			-									62,369			62,369
Balances, December 31, 2014		-			-			12,558,459			21,294,887			(16,118,542	)		5,176,345

Common Stock Issued for Services - Related Parties		-			-			206,666			32,516			-			32,516
Common Stock Issued for Directors Fees		-			-			530,288			75,232			-			75,232
Issuance of common stock for oil and gas acquisition		-			-			1,000,000			100,000			-			100,000
Issuance of series A2 preferred stock		177			1,770,000			-			-			-			1,770,000
Preferred stock issued for settlement with a related party		90			900,000			-			-			-			900,000
Net income		-			-			-			-			(4,747,053	)		(4,747,053	)
Balances, December 31, 2015		267		$	2,670,000			14,295,413		$	21,502,635		$	(20,865,595	)	$	3,307,040

The Accompanying Notes are an Integral Part of These Financial Statements.

ARÊTE INDUSTRIES, INC.

STATEMENTS OF CASH FLOWS

For the Years Ended December 31,


	2015			2014
Cash Flows from Operating Activities:
Net income (loss)	$	(4,747,053	)	$	62,369
Adjustments to reconcile net income (loss) to net cash provided by
(used in) operating activities:
Depreciation, depletion and amortization		790,896			745,836
Accretion of discount on asset retirement obligations		70,375			66,810
Gain on sale of oil and gas properties		(27,120	)		(391,585	)
Additional cost for settlement of asset retirement obligations		(28,684	)		-
Impairment expense		3,287,648			-
Additional acquisition expense realized on settlement with a related party		141,099			-
Common stock issued in exchange for services		85,048			-
Changes in operating assets and liabilities:
Accounts receivable		132,041			101,740
Prepaid expenses and other		1,668			3,955
Accounts payable		21,531			25,559
Directors and officers services payable		141,952			-
Accrued costs and expenses		33,709			44,235
Net cash provided by (used in) operating activities		(96,890	)		658,919
Cash Flows from Investing Activities:
Capital expenditures for property and equipment		(68,631	)		(639,259	)
Capital expenditures for acquisition of oil & gas properties		(1,100,000	)		-
Proceeds from sale of oil and gas properties		50,000			312,789
Net cash provided by (used in) investing activities		(1,118,631	)		(326,470	)
Cash Flows from Financing Activities:
Proceeds from notes and advance payable		67,000			622,638
Principal payments on notes payable		(25,568	)		(1,157,155	)
Net proceeds received from issuance of Series A2 Preferred Stock		1,665,000			-
Redemption of preferred stock		-			(15,500	)
Redemption of common stock		-			(228,000	)
Net cash provided by (used in) financing activities		1,706,432			(778,017	)
Net increase (decrease) in cash and equivalents		490,911			(445,568	)
Cash and equivalents, beginning of period		30,755			476,323

Cash and equivalents, end of period	$	521,666		$	30,755

Supplemental Disclosure of Cash Flow Information:
Cash paid for interest	$	83,136		$	123,669
Cash paid for income taxes	$	-		$	-

Supplemental Disclosure of Non-cash Investing and Financing Activities:
Issuance of common stock for asset purchase	$	100,000		$	34,500
Conversion of series A1 preferred stock to note payable	$	-		$	62,000
Series A2 preferred stock issued for debt settlement - related party	$	900,000		$	-
Common Stock Issued for services	$	3,950		$	-
Common Stock issued for directors fees payable	$	20,900		$	-

The Accompanying Notes are an Integral Part of These Financial Statements.

ARÊTE INDUSTRIES, INC.

NOTES TO FINANCIAL STATEMENTS

For the Years Ended December 31, 2015 and 2014

1.	Organization and Nature of Operations

Arête Industries, Inc. (“Arête” or the “Company”), is a Colorado corporation that was incorporated on July 21, 1987. The Company is in the business of exploration for and production of oil and natural gas. The Company’s primary area of oil exploration and production is in Colorado, Montana, Kansas, and Wyoming.

The Company seeks to focus on acquiring interests in traditional exploratory and development oil and gas ventures, and seek properties that offer profit potential from overlooked and by-passed reserves of oil and natural gas, which may include shut-in wells, in-field development, stripper wells, enhanced recovery, re-completion and re-working projects. In addition, the Company’s strategy includes the purchase and sale of acreage prospective for oil and natural gas and seeking to obtain cash flow from the sale and farm out of such prospects.

2.	Summary of Significant Accounting Policies

Use of Estimates

Preparation of the Company’s financial statements in accordance with accounting principles generally accepted in the United States of America (“GAAP”) requires management to make various assumptions, judgments and estimates that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Changes in these assumptions, judgments and estimates will occur as a result of the passage of time and the occurrence of future events and, accordingly, actual results could differ from amounts initially established.

The most significant areas requiring the use of assumptions, judgments and estimates relate to the volumes of natural gas and oil reserves used in calculating depreciation, depletion and amortization (“DD&A”), the amount of expected future cash flows used in determining possible impairments of oil and gas properties and the amount of future capital costs used in these calculations. Assumptions, judgments and estimates also are required in determining future asset retirement obligations, impairments of undeveloped properties, and in valuing stock-based payment awards.

The only component of comprehensive income that is applicable to the Company is net income (loss). Accordingly, a separate statement of comprehensive income (loss) is not included in these financial statements.

Cash Equivalents

For purposes of the statement of cash flows, the Company considers cash and all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents.

Accounts Receivable

The Company’s receivables consist mainly of trade account receivables from working interests in oil and gas production from partners with interests in common properties. Collectability is dependent upon the financial wherewithal of each entity and is influenced by the general economic conditions of the oil and gas industry. The Company records an allowance for doubtful accounts on a case by case basis once there is evidence that collection is not probable.

Gas Gathering System, Furniture and Equipment

The Company’s gas gathering system and its furniture and equipment are stated at cost. Material expenditures that increase the life of an asset are capitalized and depreciated over the estimated remaining useful life of the asset. The cost of normal maintenance and repairs is charged to operating expenses as incurred. Upon disposal of an asset, the cost of the asset and the related accumulated depreciation are removed from the accounts, and any gains or losses will be reflected in current operations. For the gas gathering system, depreciation is computed using the straight line method over an estimated useful life of ten years. Depreciation of furniture and equipment is computed using the straight-line method over an estimated useful life of five years. At December 31, 2015, the Company wrote this asset off by recording an impairment charge against the gas gathering system of $56,648. Furniture and equipment was fully depreciated at December 31, 2015.

Oil and Gas Producing Activities

The Company’s oil and gas exploration and production activities are accounted for using the successful efforts method. Under this method, all property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending determination of whether the well has proved reserves. If an exploratory well does not result in proved reserves, the costs of drilling the well are charged to expense and included within cash flows from investing activities in the Statements of Cash Flows. The costs of development wells are capitalized whether productive or nonproductive. Oil and gas lease acquisition costs are also capitalized.

The Company reviews its proved oil and gas properties for impairment annually or whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. The Company estimates the expected undiscounted future cash flows of its oil and gas properties and compares such undiscounted future cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will adjust the carrying amount of the oil and gas properties to fair value. The factors used to determine fair value include, but are not limited to, recent sales prices of comparable properties, the present value of estimated future cash flows, net of estimated operating and development costs using estimates of reserves, future commodity pricing, future production estimates, anticipated capital expenditures and various discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flows projected. Once incurred, a write-down may not be reversed in a later period. At December 31, 2015, the Company recorded impairment against its oil and gas properties in the amount of $3,231,000 due to the sustained decline in oil prices in 2015 and forecasts for future prices. There was no impairment at December 31, 2014.

The provision for DD&A of oil and gas properties is calculated based on proved reserves on a field-by-field basis using the unit-of-production method. Natural gas is converted to barrel equivalents, BOE, at the rate of six Mcf of natural gas to one barrel of oil. Estimated future dismantlement, restoration and abandonment costs, which are net of estimated salvage values, are taken into consideration.

Asset Retirement Obligations

The estimated fair value of the future costs associated with dismantlement, abandonment and restoration of oil and gas properties is recorded generally upon acquisition or completion of a well. The net estimated costs are discounted to present values using a credit-adjusted, risk-free rate over the estimated economic life of the oil and gas properties. Such costs are capitalized as part of the related asset. The asset is depleted on the units-of-production method on a field-by-field basis. The associated liability is classified in current and long-term liabilities in the Consolidated Balance Sheets. The liability is periodically adjusted to reflect (1) new liabilities incurred, (2) liabilities settled during the period, (3) accretion expense and (4) revisions to estimated future cash flow requirements. The accretion expense is recorded as a component of depreciation, depletion and amortization expense in the Consolidated Statements of Operations. See Note 8 – Asset Retirement Obligation.

Revenue Recognition

The Company records revenues from the sale of crude oil, natural gas and natural gas liquids (“NGL”) when delivery to the purchaser has occurred and title has transferred. The Company uses the sales method to account for gas imbalances. Under this method, revenue is recorded on the basis of gas actually sold by the Company. In addition, the Company will record revenue for its share of gas sold by other owners that cannot be volumetrically balanced in the future due to insufficient remaining reserves. The Company also reduces revenue for other owners’ gas sold by the Company that cannot be volumetrically balanced in the future due to insufficient remaining reserves. The Company’s remaining over and under produced gas balancing positions are considered in the Company’s proved oil and gas reserves. Gas imbalances at December 31, 2015 and 2014 were not material.

Environmental Liabilities

Environmental expenditures that relate to an existing condition caused by past operations and that do not contribute to current or future revenue generation are expensed. Liabilities are accrued when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated. As of December 31, 2015 and 2014, the Company had not accrued for nor been fined or cited for any environmental violations that would have a material adverse effect upon capital expenditures, operating results or the competitive position of the Company.

Industry Segment and Geographic Information

The Company operates in one industry segment, which is the exploration, development and production of natural gas and crude oil, and all of the Company’s operations are conducted in the continental United States. Consequently, the Company currently reports as a single industry segment.

Stock-Based Compensation

The Company did not grant any stock options or warrants during the years ended December 31, 2015 and 2014 and no options or warrants were outstanding at any time during these years. The Company has issued shares of common stock for services performed by officers, directors and unrelated parties during 2015 and 2014. The Company has recorded these transactions based on the value of the services or the value of the common stock, whichever is more readily determinable.

Income Taxes

Income taxes are reported in accordance with GAAP, which requires the establishment of deferred tax accounts for all temporary differences between the financial reporting and tax bases of assets and liabilities, using currently enacted federal and state income tax rates. In addition, deferred tax accounts must be adjusted to reflect new rates if enacted.

Realization of deferred tax assets is contingent on the generation of future taxable income. As a result, management considers whether it is more likely than not that all or a portion of such assets will be realized during periods when they are available, and if not, management provides a valuation allowance for amounts not likely to be recognized.

Management periodically evaluates tax reporting methods to determine if any uncertain tax positions exist that would require the establishment of a loss contingency. A loss contingency would be recognized if it were probable that a liability has been incurred as of the date of the financial statements and the amount of the loss can be reasonably estimated.

Fair Value of Financial Instruments

Cash and cash equivalents, accounts receivable, accounts payable, accrued liabilities and notes payable are carried in the Consolidated Financial Statements in amounts which approximate fair value because of the short-term maturity of these instruments.

Concentration of Credit Risk

Financial instruments that potentially subject the Company to concentrations of credit risk consist primarily of cash equivalents and revenue receivables. The Company periodically maintains cash balances at a commercial bank in excess of the Federal Deposit Insurance Corporation insurance limit of $250,000. At December 31, 2015, the Company’s uninsured cash balance was $271,666. The Company received 82% and 84% of its oil and gas production revenue from two purchasers during fiscal years ended December 31, 2015 and 2014, respectively.

The concentration of credit risk in the oil and gas industry affects the overall exposure to credit risk because customers may be similarly affected by changes in economic or other conditions. The creditworthiness of customers and other counterparties is subject to continuing review.

Earnings Per Share

Basic net income (loss) per share of common stock is calculated by dividing net income (loss) attributable to common stockholders by the weighted average number of common shares outstanding during each period. Diluted net income (loss) attributable to common stockholders is calculated by dividing net income (loss) attributable to common stockholders by the weighted average number of common shares outstanding and other dilutive securities. The only potentially dilutive securities for the diluted earnings per share calculations consist of Series A2 preferred stock that is convertible into common stock at an exchange price of $2.00 per common share. As of December 31, 2015, the convertible preferred stock had an aggregate liquidation preference of $2,670,000 and was convertible to 1,335,000 shares of common stock. These shares were excluded from the earnings per share calculation because they would be anti-dilutive. All of the Series A1 preferred stock was redeemed during the year ended December 31, 2014, therefore, there was no outstanding preferred stock at December 31, 2014.

The following table sets forth the calculation of basic and diluted earnings per share:

	Year ended December 31,
	2015			2014
Net income (loss) available to common shareholder’s – Basic	$	(4,747,053	)	$	70,945
Plus: Preferred stock dividends		-			-
Net income (loss) available to common shareholder’s – Diluted	$	(4,747,053	)	$	70,945
Weighted average common shares outstanding – Basic		12,882,000			12,450,000
Add: Dilutive effect of stock options		-			-
Add: Dilutive effect of preferred stock		-			-
Weighted average common shares outstanding – Diluted		12,882,000			12,450,000

Net income (loss) per common share:
Basic	$	(0.37	)	$	0.01
Diluted	$	(0.37	)	$	0.01

New Accounting Pronouncements

3.	Acquisitions and Dispositions of Oil and Gas Properties

Acquisitions

In 2011, the Company entered into a purchase and sale agreement (“DNR and Tindall PSA”) and other related agreements and documents with Tucker Family Investments, LLLP, which we refer to as “Tucker”; DNR Oil & Gas, Inc. which we refer to as “DNR”; and Tindall Operating Company, which we refer to as “Tindall”, and collectively we refer to these parties as the “Sellers”, for the purchase of certain oil and gas operating properties in Colorado, Kansas, Wyoming, and Montana. DNR is owned primarily by an officer and director of the Company, Charles B. Davis, and he is an affiliate of Tucker and Tindall. The consideration for the purchase was determined by bargaining between management of the Company and Mr. Davis, and the Company used reports of independent engineering firms to analyze the purchase price. The base purchase price was paid in full on September 29, 2011.

On January 19, 2016, but effective December 31, 2015, (the "Effective Date") we entered into a Settlement Agreement with Tucker, DNR and Tindall regarding the DNR and Tindall PSA and other related matters. In consideration of the amounts indicated below, the parties (i) terminated Exhibits C and C-2 to the DNR and Tindall PSA for all purposes; (ii) extinguished all liabilities of the Company under Exhibit C of the DNR and Tindall PSA including $250,000 related to the increase in oil prices after the acquisition; (iii) agreed that the promissory note of $792,151 due to DNR (See Note 5 – Notes and Advances Payable) and accrued interest thereon was paid in full; and (iv) released each other against any and all claims which have been raised or could have been raised among them. Specifically, Exhibits C and C-2 to the DNR and Tindall PSA related to potential payments that would have needed to have been made by the us in the event oil prices increased to certain levels and related to certain payments to have been made by us in the event we sold certain properties purchased under the DNR and Tindall PSA. Exhibits C and C-2 were terminated and extinguished (including any amounts owed thereunder including $250,000 under Exhibit C to the DNR and Tindall PSA) in exchange for 25 fully paid nonassessable restricted shares of our 7% Series A2 Convertible Preferred Stock. Consideration to pay the above promissory note in full consisted of the issuance to DNR of 65 fully paid, nonassessable restricted shares of its 7% Series A2 Convertible Preferred Stock, and paying DNR $303,329 in cash. A description of the terms of the 7% Series A2 Convertible Preferred Stock, including its terms of conversion into shares of the Company's common stock is set forth in Note 4 below. The Company recorded an expense of $141,099 included in other operating expense in the statement of operations as a result of this transaction.

On December 30, 2015, the Company completed an asset acquisition pursuant to a purchase and sale agreement executed on November 25, 2015, but effective December 1, 2015 (the "Wellstar Purchase and Sale Agreement ") with Wellstar Corporation (the "Seller"), an unaffiliated corporation. The assets acquired were producing oil and gas leases in Sumner County, Kansas and Kimball County, Nebraska (collectively, the "Properties" and individually, the "Padgett Properties" and the "Nebraska Properties"). The Company acquired 51% of Seller's interest (ranging from 47% to 100% of the working interests) in the Padgett Properties and acquired 100% of the Seller's interest (100% of the working interests) in the Nebraska Properties for aggregate consideration of $1,100,000 and the issuance of 1,000,000 shares of the Company's restricted common stock valued at $0.10 per share at the date of closing, or $100,000.

The table below presents the purchase price allocation for the Wellstar Purchase and Sale Agreement:

Purchase Price allocation:	Amount

Cash	$	1,100,000
Common Stock		100,000
Total Consideration	$	1,200,000

Oil and gas properties	$	1,404,493
Asset retirement obligation assumed		(204,493	)
Total Purchase price allocation	$	1,200,000

Pro-Forma information acquisition (unaudited)

The table below reflects unaudited pro forma results as if the acquisition of oil and gas properties had taken place as of January 1, 2014:

	December31,
	2015			2014
Total revenue	$	1,294,069		$	3,384,674
Net income (loss)		(4,773,679	)		455,736
Net income (loss) applicable to common shareholders		(4,773,679	)		464,312

Earnings per share	$	(0.34	)	$	0.03
Basic
Diluted	$	(0.34	)	$	0.03

The unaudited pro forma data gives effect to the actual operating results of the acquired properties prior to the acquisition, adjusted to include the pro forma effect of depreciation, depletion, amortization and accretion based on the purchase price of the properties.

4.	Oil and Gas Properties

The following table sets forth information concerning the Company’s oil and gas properties:

	December31,
	2015			2014
Proved oil and gas properties at cost, net of impairment	$	8,683,273		$	10,222,668
Unevaluated oil and gas properties at cost, net of impairment		154,836			348,836
Accumulated depreciation, depletion and amortization		(3,223,000	)		(2,476,898	)
Oil and gas properties, net	$	5,615,109		$	8,094,606

During the years ended December 31, 2015 and 2014, the Company recorded depletion expense of $746,104 and $701,042, respectively. The Company recorded impairment expense of $3,037,000 and $194,000 against proved and unevaluated oil and gas properties, respectively at December 31, 2015. There was no impairment expense during fiscal year ended December 31, 2014.

5.	Fair Value Measurements

FASB ASC 820, “Fair Value Measurements and Disclosures”, establishes a framework for measuring fair value. That framework provides a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets and liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). The three levels of the fair value hierarchy under FASB ASC 820 are described as follows:

Level 1 – Observable inputs, such as unadjusted quoted prices in active markets, for substantially identical assets and liabilities.

Level 2 – Observable inputs other than quoted prices within Level 1 for similar assets and liabilities. These include quoted prices for similar assets and liabilities in active markets, quoted prices for identical assets and liabilities in markets that are not active, or other inputs that are observable or can be corroborated by observable market data. If the asset or liability has a specified or contractual term, the input must be observable for substantially the full term of the asset or liability.

Level 3 – Unobservable inputs that are supported by little or no market activity, generally requiring a significant amount of judgment by management. The assets or liabilities fair value measurement level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement. Valuation techniques used need to maximize the use of observable inputs and minimize the use of unobservable inputs.

The methods described above may produce a fair value calculation that may not be indicative of net realizable value or reflective of future fair values. Further, although the Company believes its valuation methods are appropriate and consistent with other market participants, the use of different methodologies or assumptions to determine the fair value of certain financial instruments could result in a different fair value measurement at the reporting date.

Upon completion of wells, the Company records an asset retirement obligation at fair value using Level 3 assumptions.

Nonfinancial assets and liabilities are measured at fair value on a nonrecurring basis upon impairment. The following table sets forth by level, within the fair value hierarchy, the Company’s assets and liabilities at fair value on a recurring basis as of December 31, 2015:

	Level 1		Level 2		Level 3		Net Book Value		Total Pre-tax (Non-cash) Impairment Loss
Proved oil and gas properties at cost, net of impairment		-		-	$	315,138	$	3,386,585	$	3,071,447
Unevaluated oil and gas properties at cost, net of impairment		-		-	$	154,783	$	314,336	$	159,553
Gas gathering system (1)		-		-		-		56,648	$	56,648

(1) The gas gathering system was written off entirely at December 31, 2015.

The fair values of the properties were determined using discounted cash flow models. The discounted cash flows were based on management’s expectations for the future. The inputs included estimates of future crude oil and natural gas production, commodity prices based on sales contracted terms or commodity price curves as of the date of the estimate, estimated operating and development costs, as a risk-adjusted discount rate of 10%.

The carrying amounts of other financial instruments including cash and cash equivalents, accounts receivable, account payables, accrued liabilities and long term debt in our balance sheet approximates fair value as of December 31, 2015 and December 31, 2014.

Stockholders’ Equity

Common Stock

During the year ended December 31, 2014, the Company purchased an option to acquire rights in minerals owned by William W. Stewart (related party) for 150,000 shares of common stock valued at $34,500.

On January 30, 2014, the Company entered into a Direct Stock Purchase Agreement with Burlingame Equity Investors II L.P. and Burlingame Equity Investors Master Fund, L.P., whereby the Company purchased an aggregate 1,200,000 shares of its common stock from these entities at a price of $0.19 per share for total consideration of $228,000.

During the year ended December 31, 2015, the Company issued 736,954 shares of common stock as compensation for services; 480,288 shares of common stock were issued for board services ranging in value from $0.10 to $0.20 per share and 256,666 shares of common stock were issued for consulting services provided by three related parties ranging in value from $0.10 to $0.16 per share.

The Company issued 1,000,000 shares of common stock valued at $0.10 per share or $100,000 related to the Wellstar Purchase and Sale Agreement that was executed on December 30, 2015. See Note 3 – Acquisitions, for additional information regarding this transaction.

Preferred Stock

On September 29, 2011, the Company completed a private placement of its Series A1 Preferred Stock which resulted in the issuance of 522.5 shares for gross proceeds of $5,225,000.

Effective June 28, 2013, several holders of the Company’s Series A1 Convertible Preferred Stock elected to convert shares of such stock into the Company’s common stock at a redemption price of $0.75 per common share. In connection with those redemptions all such holders agreed to waive all dividend rights on their shares of Series A1 Preferred Stock subsequent to March 30, 2013. Information regarding the conversions is set forth below.


Name of Holder		Number of Shares of Series A1 Preferred Stock Converted	Number of Common Shares Issued
Burlingame Equity Investors II, LP		16		100,800
Burlingame Equity Investors Master Fund, LP		184		1,159,200
Charles B. Davis*		100		1,333,333
Tucker Family Investments LLLP		25		333,333
Mark Venjohn		10		133,333
Pete Haman		35		466,667
Nicholas L. Scheidt*		100		1,333,333
Michael J. Finney		5		66,667
William and Sara Kroske		2.5		33,333
Michael A. Geller		10		133,333
John H. Rosasco		10		133,333
Lyon Oil & Gas Company		10		133,333
T P Furlong		5		66,667
*	Executive Officer and Director of the Company

In connection with the conversions of Series A1 Preferred Stock by Burlingame Equity Investors II, LP and Burlingame Equity Investors Master Fund, LP, the Company entered into transactions with these entities in exchange for cash consideration, promissory notes and cancellation of certain Series A1 Preferred Shares.


Name of Holder	Cash Consideration			Promissory Note–Principal			Series A1 Preferred Shares Cancelled
Burlingame Equity Investors II, LP		$	4,000		$	48,000		16
Burlingame Equity Investors Master Fund, LP		$	46,000		$	552,000		184

On August 15, 2014, the Company redeemed the remaining 10 shares of Series A-1 Convertible Preferred Stock for consideration of $77,500, of which $15,500 was paid in cash and the remaining amount as a promissory note for $62,000. See additional discussion of the note below in Note 5 – Notes and Advances Payable.

On December 11, 2015, the Company began a private placement of its Series A2 7% Preferred Convertible Stock with a maximum amount of 600 shares at $10,000 per share or $6,000,000. At December 31, 2015, the Company had sold subscriptions equal to $1,750,000 (175 shares) and issued to DNR 90 shares fully paid ($900,000), nonassessable restricted shares of its 7% Series A2 Convertible Preferred Stock as part of the consideration for a settlement agreement entered into with DNR (See Note 5 – Advances and Notes Payable for details of the settlement).

The following are the terms of the Preferred Stock Series A2:

Authorized Shares, Stated Value and Liquidation Preference . Six hundred shares are designated as the Series A2 7% Convertible Preferred Stock, which has a stated value and liquidation preference of $10,000 per share plus accrued and unpaid dividends.

Ranking . The Series A2 Preferred Stock will rank senior to future classes or series of preferred stock established after the issue date of the Series A2 Preferred Stock, unless the Company’s Board of Directors expressly provides otherwise when establishing a future class or series. The Series A2 Preferred Stock ranks senior to the Company’s common stock but it is junior to the Company’s outstanding debt and accounts payable.

Dividends . Holders of Series A2 Preferred Stock are entitled to receive dividends at an annual rate of 7.0% of the $10,000 per share liquidation preference, payable quarterly on each of March 31, June 30, September 30 and December 31. Dividends are payable in cash or in shares of common stock (at its then fair market value), at the Company’s election.

Voting Rights . Holders of the Series A2 Preferred Stock will vote together with the holders of the Company’s common stock as a single class on all matters upon which the holders of common stock are entitled to vote. Each share of Series A Preferred Stock will be entitled to such number of votes as the number of shares of common stock into which such share of Preferred Stock is convertible; however, solely for the purpose of determining such number of votes, the conversion price per share will be deemed to be $2.00, subject to customary anti-dilution adjustment. In addition, the holders of the Series A2 Preferred Stock will vote as a separate class with respect to certain matters, including amendments to the Company’s Articles of Incorporation that alter the voting powers, preferences and special rights of the Series A2 Preferred Stock.

Liquidation . In the event we voluntarily or involuntarily liquidate, dissolve or wind up, the holders of the Series A2 Preferred Stock will be entitled, before any distribution or payment out of the Company’s assets may be made to or set aside for the holders of any of the Company’s junior capital stock and subject to the rights of the Company’s creditors, to receive a liquidation distribution in an amount equal to $10,000 per share, plus any unpaid dividends. A merger, consolidation or sale of all or substantially all of the Company’s property or business is not deemed to be a liquidation for purposes of the preceding sentence.

Redemption by the Company . The Series A2 Preferred Stock is redeemable in whole or in part at the Company’s option at any time for cash. The redemption price is equal to $10,000 per share, plus any unpaid dividends.

Optional Redemption by Holder. Unless prohibited by Colorado law governing distributions to shareholders, the Company, upon 90 days' prior written request from any holders of outstanding shares of Series A2 Preferred Stock, in its sole discretion, may redeem at a redemption price equal to the sum of (i) $10,000 per share and (ii) the accrued and unpaid dividends thereon, to the redemption date, up to one-third of each holder's outstanding shares of Series A2 Preferred Stock on: (i) the first anniversary of the Original Issue Date (the " First Redemption Date "), (ii) the second anniversary of the Original Issue Date (the " Second Redemption Date ") and (iii) the third anniversary of the Original Issue Date (the " Third Redemption Date ", along with the First Redemption Date and the Second Redemption Date, collectively, each a " Redemption Date "). If on any Redemption Date, Colorado law governing distributions to shareholders prevents the Company from redeeming all shares of Series A2 Preferred Stock to be redeemed, the Company may ratably redeem the maximum number of shares that it may redeem consistent with such law, and may also redeem the remaining shares as soon as it may lawfully do so under such law.

Preemptive Rights . Holders of the Series A2 Preferred Stock do not have preemptive rights.

Mandatory Conversion . Each share of Series A2 Preferred Stock remaining outstanding will automatically be converted into shares of the Company’s common stock upon the earlier of (i) any closing of underwritten public offering by us of shares of common stock pursuant to an effective registration statement under the Securities Act of 1933, in which the aggregate cash proceeds to be received by us and selling stockholders (if any) from such offering (without deducting underwriting discounts, expenses and commissions) are at least $7,000,000, and per share sales price is at least $3.00 (such price to be adjusted for any stock dividends, combinations or splits or (ii) the date agreed to by written consent of the holders of a majority of the outstanding Series A2 Preferred Stock.

Optional Conversion by Investors . At any time, each holder of Series A2 Preferred Stock has the right, at the holder’s option, to convert all or any portion of such holder’s Series A2 Preferred Stock into shares of our common stock at a conversion price of $2.00 per share prior to the mandatory conversion of the Series A2 Preferred Stock.

7.	Notes and advances payable

Notes payable consist of the following as of December 31:


	2015		2014
Officers, directors and affiliates:
Note payable, interest at 7.5%, due March 2016 (6)	$	150,000	$	150,000
Notes payable, interest 7.0%, due January 2019 (3)		63,464		79,970
Notes payable, interest varies (4)		-		792,151
Collateralized note payable (1)		120,728		120,728

Total officers, directors and affiliates		334,192		1,142,849
Less: Current portion of officers, directors, and affiliates		18,900		288,258

Long-term portion of officers, directors, and affiliates	$	315,292	$	854,591

Unrelated parties:
Notes payable, interest at 7.5%, due March 2016 (7)	$	100,000	$	100,000
Note payable, interest variable (see below) due January 2016, Extended to May 2016 (2)		616,105		549,105
Note payable, interest at 7.0%, due August 2016 (8)		62,000		62,000
Notes payable, interest at 7.0%, due January 2017		32,606		41,668
Notes payable, interest at 7.0%, due January 2016, Extended to May 2016 (5)(8)		183,000		183,000

Total unrelated parties		993,711		935,773
Less: Current portion of unrelated parties		970,953		872,239

Long-term portion of unrelated parties	$	22,758	$	63,534

(1)

On April 29, 2013, the Company executed a promissory note under which the Company agreed to pay Apex Financial Services Corp, a Colorado corporation, (“Apex”) the principal sum of $1,000,000, with interest accruing at an annual rate of 7.5%, with principal and interest due on May 31, 2014, and subsequently extended to March 31, 2017. The Company also agreed to assign 75% of its operating income from its oil and gas operations and any lease or well sale or any other assets sales to Apex to secure the debt. Apex is 100% owned by the CEO, director, and shareholder of the Company, Nicholas L. Scheidt. The Company borrowed the full amount of principal on the note, and also paid a loan fee of $10,000. In the event of default on the note and failure to cure the default in ten days, Apex may accelerate payment and the annual interest rate on the note will accrue at 18%. Default includes failure to pay the note when due or if the Company borrows any other monies or offers security in the Company or in the collateral securing the note prior to the note being paid in full. The outstanding principal balance as of December 31, 2015, was $120,728.

(2)

On January 28, 2014, we entered into a line of credit loan agreement for $1,500,000 due January 15, 2015 extended to January 28, 2016, and further extended after December 31, 2015 to May 28, 2016. The terms of the note are as follows: 1) the accrued interest is payable monthly starting February 28, 2014, 2) the interest rate is variable based on an index calculated based on a prime rate as published by the Wall Street Journal index (currently 3.5%) plus an add on index with the current and minimum rate of 6.5%, the note has draw provisions and is secured by seven wells and leases owned by the Company, a certificate of deposit for $500,000 at CityWide Banks pledged by a related party, and 5) the personal guarantee of Nicholas Scheidt, Chief Executive Officer. The amount eligible for borrowing on the Credit Facility is limited to the lesser of (i) 65% of the Company’s PV10 value of its carbon reserves based upon the most current engineering reserve report or (ii) 48 month cumulative cash flow based upon the most current engineering reserve report. In addition to the borrowing base limitation, the Company is required to maintain and meet certain affirmative and negative covenants and conditions in order to draw advances on the Credit Facility. The Credit Facility contains certain representations, warranties, and affirmative and negative covenants applicable to the Company, which are customarily applicable to senior secured loan facilities. Key covenants include limitations on indebtedness, restricted payments, creation of liens on oil and gas properties, hedging transactions, mergers and consolidations, sales of assets, use of loan proceeds, change in business, and change in control. The above-referenced promissory note contains customary default and acceleration provisions and provides for a default interest rate of 21% per annum. In addition, the Credit Facility contains customary events of default, including: (a) failure to pay any obligations when due; (b) failure to comply with certain restrictive covenants; (c) false or misleading representations or warranties; (d) defaults of other indebtedness; (e) specified events of bankruptcy, insolvency or similar proceedings; (f) one or more final, non-appealable judgments in excess of $50,000 that is not covered by insurance; (g) change in control (25% threshold); (h) negative events affecting the Guarantor; and (i) lender in good faith believes itself insecure. In an event of default arising from the specified events, the Credit Facility provides that the commitments thereunder will terminate and the Lender may take such other actions as permitted including, declaring any principal and accrued interest owed on the line of credit to become immediately due and payable. The Credit Facility is secured by a security interest in substantially all of the assets of the Company, pursuant to a Security Agreement, Deed of Trust and Assignment of As-Extracted Collateral entered into between the Company and Citywide Banks. The outstanding principal balance as of December 31, 2015 was $616,105.

(3)

On January 1, 2014, we memorialized certain short-term liabilities into formal promissory notes. Information concerning these promissory notes is set forth in the table below.


Name of Holder	Position	Principal Amount			Annual Interest Rate			Monthly P&I Payment Amount			Number of Monthly Payments
Donald W. Prosser	Former CFO & Director		$	28,500		7.00	%		$	564		60

Charles B. Davis	COO & Director		$	66,500		7.00	%		$	1,317		60

The above-referenced promissory notes contain customary default and acceleration provisions and provide for a default interest rate of 18% per annum. The aggregate outstanding principal balance on the notes as of December 31, 2015 was $63,464.

(4)

We issued an unsecured promissory note in the amount of $792,151 on January 1, 2014 to DNR. The note accrues interest at the rate of 2.50% for the calendar years 2014 and 2015, 4.00% for the calendar year 2016, 6.00% for the calendar year 2017 and 8.00% for the remainder of the term of the DNR note. The DNR note matures on January 1, 2019.

On January 19, 2016, but effective December 31, 2015, (the "Effective Date") we entered into a Settlement Agreement with DNR and Tindall Operating Company discussed above under which the DNR Note was deemed paid in full.

(5)

In June 2013, in connection with the conversions of Series A1 Preferred Stock by Burlingame Equity Investors II, LP and Burlingame Equity Investors Master Fund, LP, the Company issued unsecured promissory notes in the original principal amounts of $48,000 and $552,000, respectively, with interest at 7% per annum payable quarterly and all unpaid interest and principal due on July 23, 2014. We have agreed with the holders of these two existing notes to extend the maturity date of the notes to May 25, 2016. Information concerning the principal pay down is set forth in the following table.

Name of Holder	Principal Balance before Pay down		Principal Pay down		Remaining Principal Balance
Burlingame Equity Investors II, LP	$	44,000	$	26,251	$	17,749
Burlingame Equity Investors Master Fund, LP	$	506,000	$	340,749	$	165,251

(6)

On March 28, 2012, the Company executed a Promissory Note with Fairfield Management Group, LLC (“Fairfield”), a related party. The note accrues interest at 7.5%, payable monthly and has a maturity date of March 31, 2016. During the fiscal year ended December 31, 2015, Fairfield assigned this note to Donald Prosser (former CFO and Director). Subsequent to the year ended December 31, 2015, the Company and Mr. Prosser extended the due date to March 31, 2017.

(7)

On March 28, 2012, the Company executed a promissory note with Pikerni, LLC (“Pikerni”). This note was extended and amended on April 1, 2015. The note accrues interest at 7.5% and is payable quarterly. The maturity date of the note is April 1, 2016, with principal payments of $5,000 due on June 30, 2015, September 30, 2015, December 31, 2015, and March 31, 2016, and the remaining principal balance of $80,000 due on April 1, 2016. At December 31, 2015, the Company was in default on this note. The Company is currently negotiating an amendment with Pikerni to cure the default.

(8)

On August 15, 2014, the Company redeemed the remaining 10 shares of Series A-1 Convertible Preferred Stock outstanding for consideration of $77,500, of which $15,500 was paid in cash and the remaining amount as a promissory note for $62,000. The note accrues interest at 7% per annum, payable in two installments as follows;

A payment of $31,000, plus accrued and unpaid interest was payable on August 15, 2015

A payment of $31,000, plus accrued and unpaid interest shall be payable on August 15, 2016

The Company did not make the August 15, 2015, principal payment and is currently in default on this note. The Company is negotiating new terms with the note holder.

8.	General and Administrative Expenses

In connection with the property acquisition agreement entered into in the third quarter of 2011, the Company executed an operating agreement whereby DNR provides services to operate all of the properties acquired by the Company for a monthly fee of $23,000. The operating agreement expired on March 31, 2012 and renews on a month to month basis.

Based on operator costs for the properties prior to the Company’s acquisition, approximately $8,000 per month was classified as lease operating expenses and $15,000 per month was classified as related party consulting fees. Effective July 1, 2012, the monthly operator fee was reduced to $18,000 per month, of which $8,000 per month is included in lease operating expense and the remaining $10,000 per month is included in related party consulting fees in the consolidated statements of operations.

Presented below is a summary of general and administrative expenses for the years ended December 31, 2015 and 2014:


	2015		2014		Change
Director fees	$	47,833	$	20,450	$	27,383
Investor relations		28,128		65,833		(37,705	)
Legal, auditing and professional services		116,078		146,581		(30,503	)
Consulting and executive services:
Related parties		172,217		220,800		(48,583	)
Unrelated parties		—		—		—
Other administrative expenses		74,634		72,807		1,827
Depreciation		428		570		(142	)

Total general and administrative expenses	$	439,318	$	527,041	$	(87,723	)

9.	Income Taxes

At December 31, 2015, the Company has net operating loss (“NOL”) carryforwards for Federal income tax purposes of approximately $8,336,000. If not previously utilized, the NOL carryforwards will expire in 2018 through 2035.

For the years ended December 31, 2015 and 2014, the Company did not recognize any current or deferred income tax benefit or expense. Actual income tax benefit (expense) for the years ended December 31, 2015 and 2014 differs from the amounts computed using the federal statutory tax rate of 34%, as follows:


	2015			2014
Income tax benefit (expense) at the statutory rate	$	1,614,000		$	(21,000	)
Benefit (expense) resulting from:
Increase in Federal valuation allowance		(1,884,000	)		—
Other permanent differences		270,000			—
Utilization of net operating loss carryforwards		—			21,000

Income tax benefit (expense)	$	—		$	—

At December 31, 2015 and 2014, the tax effects of temporary differences that give rise to significant deferred tax assets and liabilities are presented below:


	2015			2014
Federal net operating loss carryforwards	$	3,030,000		$	2,465,000
State net operating loss carryforwards		315,000			264,000
Oil and gas properties		917,000			(222,000	)
Asset retirement obligations		371,000			241,000

Net deferred tax assets		4,632,000			2,748,000
Less valuation allowance		(4,632,000	)		(2,748,000	)

Net deferred tax assets	$	—		$	—

A valuation allowance has been recorded for all deferred tax assets since the “more likely than not” realization criterion was not met as of December 31, 2015 and 2014.

A tax benefit from an uncertain tax position may be recognized if it is “more likely than not” that the position is sustainable based solely on its technical merits. For the years ended December 31, 2015 and 2014, the Company had no unrecognized tax benefits and management is not aware of any issues that would cause a significant increase to the amount of unrecognized tax benefits within the next year. The Company’s policy is to recognize any interest or penalties as a component of income tax expense. The Company’s material taxing jurisdictions are comprised of the U.S. federal jurisdiction and the states of Colorado, Wyoming and Kansas. The tax years 2010 through 2015 remain open to examination by these taxing jurisdictions.

10.	Asset Retirement Obligations

The Company follows accounting for asset retirement obligations (“ARO”) in accordance with ASC 410, Asset Retirement and Environmental Obligations , which requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it was incurred if a reasonable estimate of fair value can be made. The Company’s ARO primarily represents the estimated present value of the amounts expected to be incurred to plug, abandon and remediate producing and shut-in wells at the end of their productive lives in accordance with applicable state and federal laws. The Company determines the estimated fair value of its ARO by calculating the present value of estimated cash flows related to plugging and abandonment liabilities. The significant inputs used to calculate such liabilities include estimates of costs to be incurred; the Company’s credit adjusted discount rates, inflation rates and estimated dates of abandonment. The ARO is accreted to its present value each period and the capitalized asset retirement costs are amortized using the unit of production method.

A reconciliation of the Company’s ARO for the years ended December 31, 2015 and 2014 is as follows:


	2015			2014
Balance, beginning of year	$	749,013		$	682,203
Liabilities incurred upon acquisition of properties		204,493			—
Liabilities settled		(28,684	)		—
Accretion expense		70,375			66,810
Revisions of prior estimates		—			—

Balance, end of year		995,197			749,013
Less current asset retirement obligations		(409,621	)		(191,843	)

Long-term asset retirement obligations	$	585,576		$	557,170

11.	Commitments and Contingencies

Lease commitments. The Company entered into a lease for property access rights and compressor space in Wyoming related to the Company’s natural gas gathering system. The expense in 2015 and 2014 was approximately $1,400 and $9,000, which is included in gas gathering operating costs. The Company used office space and conference room space provided by a director for an annual charge of $3,000 for the year ended December 31, 2014. The Company does not have any operating leases in place at December 31, 2015.

Legal Proceedings. The Company is subject to the risk of litigation, claims and assessments that may arise in the ordinary course of its business activities, including contractual matters and regulatory proceedings. As of December 31, 2015, the Company was not subject to any pending litigation and management is not currently aware of any asserted or unasserted claims and assessments that may impact the Company’s future results of operations.

12.	Subsequent Events

The following are the subsequent events:

The Company extended the following notes subsequent to the year ended December 31, 2015;

Donald W. Prosser (formerly Fairfield) - $100,000 principal – extended to March 31, 2017

Apex Financial Services Corp.- $120,728 principal– extended to March 31, 2017

CityWide Banks - $616, 105 principal– extended to May 28, 2016

Burlingame Equity Investors II, LP – extended to May 25, 2016

Burlingame Equity Investors Master Fund, LP – extended to May 25, 2016

(See Note 7.)

13.	Supplementary Oil and Gas Information (unaudited)

Costs Incurred in Oil and Gas Producing Activities

Costs incurred in oil and gas property acquisition, exploration and development activities and related depletion, depreciation, amortization and accretion (“DD&A”) per equivalent unit-of-production were as follows for the years ended December 31, 2015 and 2014:


	2015		2014
Acquisition costs:
Unproved properties	$	—	$	34,500
Proved properties		1,404,493		—
Exploration costs		—		—
Development costs		115,992		594,359
Revisions to asset retirement obligation		—		—

Total costs incurred	$	1,520,485	$	628,859

Depletion per BOE of production	$	27.78	$	22.24

Supplemental Oil and Gas Reserve Information

The reserve information presented below is based on estimates of net proved reserves as of December 31, 2015 and 2014 that were prepared by Pinnacle Energy Services, L.L.C. and Ryder Scott Company, respectively, the Company’s independent petroleum engineering firms, in accordance with guidelines established by the SEC.

Proved oil and gas reserves are the estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions (i.e., prices and costs as of the date the estimate is made). Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

Changes in Proved Reserves

The following table sets forth information regarding the Company’s estimated total proved and oil and gas reserve quantities for the years ended December 31:


	Oil (Bbl)			Gas (Mcf)			Equivalent (BOE)
Balance, January 1, 2014		246,994			676,788			359,792
Sale of oil and gas reserves in place		—			—			—
Revisions in previous estimates		13,060			8,347			14,452
Production		(22,825	)		(70,195	)		(34,524	)

Balance, December 31, 2014		237,229			614,940			339,720
Sale of oil and gas reserves in place		—			—			—
Acquisition of reserves in place		71,870			—			71,870
Revisions in previous estimates		(14,924	)		(194,070	)		(47,269	)
Production		(18,955	)		(62,630	)		(29,393	)

Balance, December 31, 2015		275,220			358,240			334,928


Proved reserves, December 31, 2014:
Proved developed		230,530			614,940			333,020

Proved undeveloped		6,699			—			6,699

Proved reserves, December 31, 2015:
Proved developed		275,220			358,240			334,928

Proved undeveloped		—			—			—

Standardized Measure

Certain information concerning the assumptions used in computing the valuation of proved reserves and their inherent limitations are discussed below. The Company believes such information is essential for a proper understanding and assessment of the data presented.

As of December 31, 2014, future cash inflows were computed by applying the SEC-mandated 12 month arithmetic average of the first of month price for January through December of 2014, which resulted in benchmark prices of $94.99 per barrel for crude oil and $4.35 per MMbtu for natural gas. Prices were further adjusted for transportation, quality and basis differentials, which resulted in an average price used as of December 31, 2014, of $84.09 per barrel of oil and $6.09 per Mcf for natural gas.

As of December 31, 2015, future cash inflows were computed by applying the SEC-mandated 12 month arithmetic average of the first of month price for January through December of 2015, which resulted in benchmark prices of $50.28 per barrel for crude oil and $2.587 per MMbtu for natural gas. Prices were further adjusted for transportation, quality and basis differentials, which resulted in a difference from the benchmark prices ranging from -$3.40 per barrel to -$10.77 per barrel, depending on the location of the wells. The calculated natural gas differentials ranged from -81% to +59% as a percentage of the benchmark prices depending on where the well was located.

The assumptions used to compute estimated future cash inflows do not necessarily reflect the Company’s expectations of actual revenues or costs, nor their present worth. In addition, variations from the expected production rate also could result directly or indirectly from factors outside of the Company’s control, such as unexpected delays in development, changes in prices or regulatory or environmental policies. The reserve valuation further assumes that all reserves will be disposed of by production. However, if reserves are sold in place, additional economic considerations could also affect the amount of cash eventually realized.

Future development and production costs are computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions.

Future income tax expenses are computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pre-tax net cash flows relating to the Company’s proved oil and gas reserves. Net operating losses incurred in oil and gas producing activities are utilized to reduce taxable income. Permanent differences in oil and gas related tax credits and allowances are recognized, if reasonably estimable.

A 10% annual discount rate was used to reflect the timing of the future net cash flows relating to proved oil and gas reserves. The following table presents the standardized measure of discounted future net cash flows related to proved oil and gas reserves as of December 31, 2013 and 2014:


	2015			2014
Future cash inflows	$	13,002,030		$	23,132,987
Future production costs		(7,976,560	)		(9,732,541	)
Future development costs		—			(781,442	)
Future income taxes		—			(1,905,627	)

Future net cash flows		5,025,470			10,713,377
10% annual discount		(2,472,800	)		(4,724,250	)

Standardized measure of discounted future net cash flows	$	2,552,670		$	5,989,127

The present value (at a 10% annual discount) of future net cash flows from the Company’s proved reserves is not necessarily the same as the current market value of its estimated oil and gas reserves. The Company bases the estimated discounted future net cash flows from its proved reserves on average prices realized in the preceding year and on costs in effect at the end of the year. However, actual future net cash flows from the Company’s oil and gas properties will also be affected by factors such as actual prices the Company receives for oil and gas, the amount and timing of actual production, supply of and demand for oil and gas and changes in governmental regulations or taxation.

The timing of both the Company’s production and incurrence of expenses in connection with the development and production of oil and gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% annual discount factor the Company uses when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with the Company or the oil and gas industry in general.

A summary of changes in the standardized measure of discounted future net cash flows is as follows for the years ended December 31, 2013 and 2014:


	2015			2014
Standardized measure of discounted future net cash flows, beginning of year	$	5,989,127		$	6,154,647
Sales of oil and gas, net of production costs and taxes		23,891			(1,190,850	)
Purchases of reserves in place		589,190			—
Sales of reserves in place		—			—
Changes in development costs		(699,000	)		98,054
Revisions of previous estimates		(440,871	)		213,112
Changes in prices and production costs		(4,661,912	)		(341,335	)
Net changes in income taxes		1,153,332			440,034
Accretion of discount		598,913			615,465

Standardized measure of discounted future net cash flows, end of year	$	2,552,670		$	5,989,127

Item 9.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

Not Applicable.

Item 9A.

CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

As of December 31, 2015, our Chief Executive Officer and Chief Financial Officer (the “Certifying Officers”) conducted evaluations of our disclosure controls and procedures. As defined under Sections 13a-15(e) and 15d-15(e) of the Exchange Act, the term “disclosure controls and procedures” means controls and other procedures of an issuer that are designed to ensure that information required to be disclosed by the issuer in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Exchange Act is accumulated and communicated to the issuer’s management, including the Certifying Officers, to allow timely decisions regarding required disclosure. Based on this evaluation, the Certifying Officers have concluded that our disclosure controls and procedures were not effective to ensure that material information is recorded, processed, summarized and reported by our management on a timely basis in order to comply with the disclosure requirements under the Exchange Act and the rules and regulations promulgated thereunder.

Management’s Report on Internal Control Over Financial Reporting.

Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) under the Securities Exchange Act, as amended. Our management assessed the effectiveness of our internal control over financial reporting as of December 31, 2015. In making this assessment, our management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) in Internal Control-Integrated Framework. A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the company’s annual or interim financial statements will not be prevented or detected on a timely basis. We have identified the following material weaknesses.

•

We have not developed and effectively communicated our accounting policies and procedures, and

•

Our controls over financial statement disclosures were determined to be ineffective.

Changes in Internal Control Over Financial Reporting.

The annual report does not include an attestation report of the Company’s registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by the Company’s registered public accounting firm pursuant to rules of the Securities and Exchange Commission that permit smaller reporting companies to provide only management’s report in this annual report

There have been no changes in our internal control over financial reporting during the latest fiscal quarter that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Item 9B.

OTHER INFORMATION

Not Applicable.

PART III

Item 10.

Directors, Executive Officers and Corporate Governance

The directors named below were elected for one-year terms. Officers hold their positions at the discretion of the Board of Directors absent any employment agreements, none of which currently exist or are contemplated. The names, addresses and ages of each of our directors and executive officers and the positions and offices held by them are:


Name and Address	Age	First Became Officer and/or Director	Position(s)
Nicholas L. Scheidt 7260 Osceola Street Westminster, CO 80030	55	November 2012	Director and Chief Executive Officer

Charles B. Davis 7260 Osceola Street Westminster, CO 80030	58	October 2007	Director and Chief Operating Officer

William W. Stewart 7260 Osceola Street Westminster, CO 80030	55	December 2001	Director and Assistant Secretary

Robert J. McGraw, Jr. 7260 Osceola Street Westminster, CO 80030	61	April 2015	Director

Randall K. Arnold 7260 Osceola Street Westminster, CO 80030	63	June 2015	Director

Tristan R. Farel 7260 Osceola Street Westminster, CO 80030	46	June 2015	Chief Financial Officer and Secretary

Nicholas L. Scheidt

Mr. Scheidt joined the Company’s Board of Directors in November of 2012, and became the Chief Executive Officer in May 2013, and is a member of the Company’s Audit, Nomination and Compensation Committees. Mr. Scheidt has served as President and Chairman of Apex Financial Services Corp (aka Apex Realty Investments Inc.) since 1983; he has served on the Board of Directors of Truck Wash Inc. since 1989; he has served on the Board of Directors of Out Reach Housing Corporation since 1992 and he has served as Chief Financial Officer of Truck Wash Inc. since 1995.

Charles B. Davis

Mr. Davis joined Arête’s Board of Directors in 2006, and serves as a member of the Company’s Nominating and Compensation Committees. From January 1981 to June 1983, Mr. Davis was Operations Manager for Keba Oil and Gas Co. where he was responsible for drilling, completion and producing operations. From July 1983 to April 1986, Mr. Davis was Vice-President of operations for Private Oil Industries. From April 1986 until August 1988, Mr. Davis did consulting work related to well site operations. Since August 1988 Mr. Davis has worked for DNR Oil & Gas Inc., as president, overseeing the day to day operations for 150 to 200 wells, and involved in exploration activities. Mr. Davis graduated from the University of Wyoming with a Bachelor of Science Degree in Engineering.

William W. Stewart

From December, 2001 until August, 2002, Mr. Stewart ran the operations and directed the business plan of Eagle Capital Funding Corp. (Eagle Capital) to pursue capital funding projects. In addition to serving as an outside director, he serves as a member of the Company’s Nominating and Compensation Committees. Mr. Stewart worked in the brokerage industry as an NASD licensed registered representative from 1986 to 1994. Mr. Stewart started his career with Boettcher and Company of Denver, Colorado and left the Principal Financial Group of Denver, Colorado in 1994 to open his own small-cap investment firm, S.W. Gordon Capital, Inc., where he has been its president since 1994 to the present. Mr. Stewart formerly served as CEO and is an owner of Larimer County Sports, LLC, a Colorado limited liability company, which owns the Colorado Eagles Hockey Club a minor league professional hockey franchise in northern Colorado. He has been President of Wenatche Sports Partners, LLC, owner of a minor league hockey team, since 2008. Mr. Stewart attended the University of Denver on a full athletic scholarship where he played hockey from 1979 to 1983 as right wing and served as assistant captain during his senior year. Mr. Stewart graduated with a BS, Business Administration from the University of Denver in 1983, with honors as a Student Athlete.

Robert J. McGraw, Jr.

Mr. McGraw is the President of McGraw & McGraw CPA and a 1977 graduate from Western State Colorado University. A practicing Colorado-licensed Certified Public Accountant since 1982, he specializes in accounting for small businesses, personal and corporate tax planning and preparation as well as small business consulting. Mr. McGraw is also a member of the American Institute of Certified Public Accountants and the Colorado Society of Certified Public Accountants. He has served on the board of directors for multiple publicly traded companies as Audit Committee Chairman and is currently serving on the boards of two non-profit organizations.

Randall K. Arnold

Mr. Arnold brings over 38 years of experience drilling, completing and producing oil and natural gas wells throughout the major basins in the United States. Mr. Arnold graduated from the University of Oklahoma in 1977 with a Bachelor of Science degree in Mechanical Engineering. Mr. Arnold began his oilfield experience in 1976 while completing his degree with Cameron Iron Works.

After graduating Mr. Arnold accepted a position with Phillips Petroleum as a drilling engineer working in Oklahoma and the North Sea. In 1980, he joined Petro Lewis Corporation ("Petro Lewis") as an operations engineer and over a five year career at Petro Lewis held the positions of District Engineer, Production Superintendent, Operations Manager for the SW Region located in Lubbock, TX and Operations Manager for the Central Region located in Denver, CO encompassing an area from North Dakota to West Texas.

From 1985 to 1995 Mr. Arnold worked for three small independent exploration companies, Liedtke Operating Corp, Emerald Corp, and Wilbanks Exploration. He then started his own company in 1995, Buffalo Operating Corporation. In 2002 Mr. Arnold accepted a position with Delta Petroleum ("Delta") as Operations Manager and was eventually promoted to Senior Vice President of Operations. In 2006 after leaving Delta, he again ran Buffalo Operating Corporation and in 2008 became a member of North Plains Energy ("NPE") and in 2012 was retained by NPE as a consultant until NPE was sold to Kodiak Oil and Gas in 2012.

Tristan R. Farel

Mr. Farel is an executive with five years of experience as a chief financial officer and 15 years of accounting and public company reporting experience. Mr. Farel currently is the President of Pivot Accounting, LLC, a company he founded which provides a full suite of solutions to both public and private companies operating in the oil and gas industry offering outsourced chief financial officer and controller functions, as well as accounting and bookkeeping services. Since February 2010, Mr. Farel has also served as the Chief Financial Officer of New Frontier Energy, Inc., a non-reporting, publicly-held domestic energy company engaged in the exploration for, and development of, oil and natural gas reserves in the continental United States. Mr. Farel has also served as a financial consultant to various entities since December 2009. From June 2007 to December 2009, Mr. Farel served as a financial reporting manager for Resolute Energy Corporation, an oil and gas exploration and development company. From January 2002 to June 2007, Mr. Farel was an auditor for Hein & Associates, a public accounting firm. Mr. Farel has a Bachelor of Science in Business Administration with an emphasis in Accounting from the University of Colorado.

Board Committees

Our Board of Directors oversees the business affairs of the Company and monitors the performance of our management. The Board of Directors met five times during the year 2015.

Director Independence

Our common stock is listed on the OTC Markets under the QB tier, which does not have director independence requirements.

Audit, Compensation and Nominating Committees

As noted above, our common stock is listed on the OTC Markets, which does not require companies to maintain audit, compensation or nominating committees consisting solely of independent directors. Nonetheless, we maintain an audit, compensation and nominating committee, although the membership on these committees does not solely consist of independent directors.

Audit Committee

The Audit Committee’s primary responsibilities are to monitor our financial reporting process and internal control system, to monitor the audit processes of our independent auditors, and internal financial management; and to provide an open avenue of communication among our independent auditors, financial and senior management and the Board. The Audit Committee reviews its charter annually and updates it as appropriate. The Committee met four times during the year 2015.

Audit Committee Financial Expert

The Board has determined that Mr. McGraw is the audit committee financial expert for the Audit Committee.

Nominating Committee

The Nominating Committee was also established in 2003. It identifies candidates for future Board membership and proposes criteria for Board candidates and candidates to fill Board vacancies, as well as a slate of directors for election by the shareholders at each annual meeting. The Committee reviews and makes recommendations to the Board concerning the composition, size and structure of the Board and its committees; and annually reviews and reports to the Board on director compensation and benefits matters. The Nominating Committee met one time during the year 2015.

Compensation Committee.

While the Company established a Compensation Committee in 2003, our full Board currently administers compensation matters. As we expand our operations and compensation policies, we intend to appoint members to the committee. Upon reinstatement of the Committee, it will administer our incentive plans, sets policies that govern executives’ annual compensation and long-term incentives, and reviews management performance, compensation, development and succession. The Compensation Committee met one time during the year 2015.

Compliance with Section 16(a) of the Exchange Act.

The Company voluntarily files reports under Section l5 (d) of the Exchange Act; accordingly, directors, executive officers and 10% shareholders are not required to make filings under Section 16 of the Exchange Act.

Shareholder Communications.

We do not have a formal shareholder communications process. Shareholders are welcome to communicate with the Company by forwarding correspondence to Arête Industries, Inc., Board of Directors, 7260 Osceola Street, Westminster, Colorado 80030, Attention: Nicholas Scheidt, CEO and Director.

CODE OF BUSINESS CONDUCT AND ETHICS

Our corporate philosophy is that good ethics and good business conduct go hand in hand. Our business standards provide a general framework of values and obligations that should be adhered to at all times. Corporate standards guide our professional conduct in regard to actions, words, sense of fairness, honesty and integrity. The Company is required to comply with laws in all jurisdictions, and our Code of Business Conduct and Ethics, which we refer to as the Code, supports and reflects our statutory compliance with such laws. The Code applies to our principal executive officer, principal financial officer, principal accounting officer or controller, and persons performing similar functions.

ITEM 11.

EXECUTIVE COMPENSATION

We do not currently have any full time or part time employees, except as set forth below. Our three executive officers, who are also directors, did not receive any salary or other compensatory benefits during 2015 or 2014 in their capacity as officers. During 2015 and 2014, we used independent contractors, consultants, attorneys and accountants as necessary, to complement services for operations and regulatory filings.

We paid $20,000 for Nicholas Scheidt as his compensation as Chief Executive Officer for services through June 2014. We paid no compensation to Mr. Scheidt in 2015. Donald W. Prosser was our Chief Financial Officer and Director through May 2015. We paid no cash compensation during 2015 to Mr. Prosser. We paid a company that is controlled by Charles Davis $216,000 and $216,000 in 2015 and 2014, respectively, for providing us with management services relating to our oil and gas properties. See also “Certain Relationships and Related Transactions” for further information regarding certain transactions with our officers. We paid William W. Stewart $15,000 in cash and 40,000 shares of common stock valued at $5,250 in 2015 for management services.

We issued Tristan R. Farel 166,666 shares of common stock with a fair value of $26,666 as his compensation for services performed as CFO for the year ended December 31, 2015.

Equity Awards

We do not maintain any equity award plans. Accordingly, there were no stock grants, options or other equity awards to our two executive officers in their capacity as officers.

Compensation of Directors.

The following table discloses the cash, equity awards and other compensation earned, paid or awarded, as the case may be, to each of our non-employee Directors during the fiscal year ended December 31, 2015.


Name	Fees Earned Or Paid in Cash ($)		Stock Awards ($) (1)		Option Awards ($)		All Other Compensation ($)		Total ($)
Charles B. Davis		—	$	12,180		—		—	$	132,180
William W. Stewart		—	$	21,280		—		15,000	$	36,280
Robert J. McGraw, Jr.		—	$	6,000		—		—	$	6,000
Randall K. Arnold		—	$	4,666		—		—	$	4,666

(1)	Our Directors are entitled to common shares of the Company’s common stock for each meeting attended. The fee was payable at the end of each calendar quarter and was calculated based on the closing price of our common stock as reported by the OTC Market as of the last day of each quarter.

Cash Compensation Paid to Directors

We currently do not pay any cash fees to our Directors for services provided in their capacity as Directors.

Equity Based Compensation Paid to Directors

Since we currently do not have any formal equity incentive plans, the stock issued to directors is allocated from our authorized shares. The offer and sale of shares issued in connection with the Directors’ fees are not registered with the SEC and are therefore “restricted securities” as that term is defined in Rule 144 of the SEC, and as such are subject to holding period requirements and other restrictions set forth in Rule 144.

Other

All Directors are reimbursed for their reasonable expenses incurred in connection with attending meetings.

Item 12.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Security Ownership of Certain Beneficial Owners and Management

The following table sets forth certain information regarding the beneficial ownership of the Company’s common stock as of May 5, 2016 by (i) each person known by the Company to beneficially own more than five percent of the outstanding shares of common stock, (ii) each current director and named executive officer of the Company and (iii) all executive officers and directors as a group. Except as indicated, the persons named in the table have sole voting and investment power with respect to all shares beneficially owned. Outstanding shares at May 5, 2016, were 14,295,413.


Title of Class	Name and Address of Beneficial Owner Directors and Executive Officers	Amount and Nature of Beneficial Ownership		Percent of Class
Common Stock	Nicholas L. Scheidt, Director/CEO 7260 Osceola Street Westminster, Colorado 80030,	Direct	1,721,703		12.0	%
Common Stock	Charles B. Davis, Director/COO 7260 Osceola Street Westminster, Colorado 80030,	Direct	2,152,167		15.1	%
Common Stock	William W. Stewart, Director 7260 Osceola Street Westminster, Colorado 80030,	Direct	382,982		2.7	%
Common Stock	Robert J. McGraw, Jr., Director 7260 Osceola Street Westminster, Colorado 80030,	Direct	47,315		0.3	%
Common Stock	Randall K. Arnold, Director 7260 Osceola Street Westminster, Colorado 80030,	Direct	36,667		0.3	%
Common Stock	Tristan R. Farel, CFO 7260 Osceola Street Westminster, Colorado 80030,	Direct	166,666		1.2	%

Common Stock	Directors and Officers as a Group (6 persons)	Total:	4,507,500		31.5	%

Item 13.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Our officers and directors have advanced funds to pay for necessary expenses and costs of the Company. The following are the advances from the officers and directors as of December 31, 2015 and 2014 are unsecured and due on demand:

	2015		2014
Officers, directors and affiliates:
Note payable, interest at 7.5%, due March 2016 (4)	$	150,000	$	150,000
Notes payable, interest 7.0%, due January 2019 (2)		63,464		79,970
Notes payable, interest varies (3)		-		792,151
Collateralized note payable (1)		120,728		120,728

Total officers, directors and affiliates		334,192		1,142,849
Less: Current portion of officers, directors, and affiliates		18,900		288,258

Long-term portion of officers, directors, and affiliates	$	315,292	$	854,591

(1)

(2)

On January 1, 2014, we memorialized certain short-term liabilities into formal promissory notes. These certain outstanding advances and other notes payable are now included in single promissory notes, all have been reported previously in our financial statements. Information concerning these promissory notes is set forth in the table below.


Name of Holder	Position	Principal Amount			Interest Rate			Monthly P&I Payment Amount			Number of Monthly Payments
Donald W. Prosser	Former CFO and Director		$	28,500		7.00	%		$	564.33		60

Charles B. Davis	COO & Director		$	66,500		7.00	%		$	1,316.78		60

The above-referenced promissory notes contain customary default and acceleration provisions and provide for a default interest rate of 18% per annum. The outstanding principal balances as of December 31, 2015 were $63,464.

(3)

(4)

On March 28, 2012, the Company executed a Promissory Note with Fairfield Management Group, LLC (“Fairfield”), a related party. The note accrues interest at 7.5%, payable monthly and had a maturity date of March 31, 2016. During 2015 Fairfield assigned this note to Donald W. Prosser (former CFO and Director). Subsequent to December 31, 2015, the parties extended the due date to March 31, 2017.

We had related party payables of accrued interest to the officers and directors above of $10,825 at December 31, 2015.

Due to the need of additional assistance with respect to corporate matters and operational needs, in October, 2014, we entered into a Consulting Agreement with William W. Stewart, a Director of the Company, to assist and advise us with respect to the following matters:

(a)

Assist the Company with resolving outstanding business issues; advise and assist with respect to proposed transactions and the Company’s business plan.

(b)

Assist with operations, including reviewing and advising on correspondence and documents received by the Company.

(c)

Review the Company’s insurance needs, obtain quotes and consult with the Company’s officers and Board remembers regarding the same.

(d)

Review the Company’s website and advise regarding updating and revising the website.

(e)

Review the Company’s organizational documents and related corporate governance documents and advise the Board regarding corporate governance matters and recommend revisions and updates to the organizational documents.

The agreement was for a term of eight months. For his consulting services, we paid Mr. Stewart a monthly cash retainer of $3,000 per month. In addition, the Company agreed to issue Mr. Stewart 40,000 restricted shares (the “Restricted Shares”) of the Company’s common stock, which are subject to vesting in increments of 5,000 per month. He was paid a total of $15,000 and was issued a total of 40,000 shares of common stock under this agreement in 2015.

Item 14.

PRINCIPAL ACCOUNTANT FEES AND SERVICES

The following relate to aggregate fees billed for the last two fiscal years by the Company’s principal accountants concerning the Company’s: (1) audit; (2) for assurance and services reasonably related to the audit; (3) for tax compliance, advice, and planning; and (4) for other fees provided by the principal accountant for the following:

1. Audit Fees. $53,200 (2015) and $48,600 (2014)

2. Audit-Related Fees. $-0- (2015 and 2014)

3. Tax Fees. $-0- (2015 and 2014)

4. All Other Fees. $-0- (2015 and 2014)

5. (i) The Company’s Audit Committee’s pre-approval policies and procedures (described in paragraph (c)(7)(i) of Rule 2-01 of Regulation S-X), are:

Audit Committee Pre-Approval Policies and Procedures

As set forth in its charter, our Audit Committee has the sole authority to pre-approve all audit and non-audit services provided by our independent auditor. All services performed by Causey Demgen and Moore, P.C. in 2015 and 2014 were pre-approved by our Audit Committee. Having considered whether the provision of the auditors’ services other than for the annual audit and quarterly reviews is compatible with its independence, the Audit Committee has concluded that it is.

The Audit Committee on an annual basis reviews audit and non-audit services performed by the independent auditors. All audit and non-audit services are pre-approved by the Audit Committee, which considers, among other things, the possible effect of the performance of such services on the auditors’ independence. All requests for services to be provided by the independent auditor, which must include a description of the services to be rendered and the amount of corresponding fees, are submitted to the Chief Executive or Financial Officer. The Chief Executive or Financial Officer authorizes services that have been pre-approved by the Audit Committee. If there is any question as to whether a proposed service fits within a pre-approved service, the Audit Committee chair is consulted for a determination. The Chief Executive or Financial Officer submits requests or applications to provide services that have not been pre-approved by the Audit Committee, which must include an affirmation by the Chief Executive or Financial Officer and the independent auditor that the request or application is consistent with the SEC’s rules on auditor independence, to the Audit Committee (or its chair or any of its other members pursuant to delegated authority) for approval.

(ii) 100 per cent of the fees billed by the principal accountant were approved by the Audit Committee (described in paragraph (c)(7)(i)(C) of Rule 2-01 of Regulation S-X).

6. The percentage (if over 50%) of hours expended on the principal accountant’s engagement to audit the Company’s financial statements for the most recent fiscal year done by persons other than the principal accountant’s full-time, permanent employees, was: Not applicable.

PART IV

Item 15.

EXHIBITS

The following exhibits are filed with, or incorporated by reference in, this registration statement:


Exhibit Number		Description

3.1		Restated Articles of Incorporation with Amendment adopted by shareholders on September 1, 1998 (filed as Exhibit 3.1 to Form 10-KSB for the year ended December 31, 1998 (filed with the SEC on April 16, 1999), and incorporated herein by reference).

3.2		Articles of Amendment to the Articles of Incorporation of Arête Industries, Inc. – Preferences, Limitations and Relative Rights of 15% Series A1 convertible preferred stock (filed as Exhibit 3.1 to Form 8-K dated September 30, 2011, and incorporated herein by reference.)

3.2(a)		Articles of Amendment to Articles of Incorporation dated May 29, 2012 – Preferences, Limitations and Relative Rights of 15% Series A1 Convertible Preferred Stock (filed as Exhibit 3.2(a) to Registration Statement on Form S-1 filed on May 29, 2012, and incorporated herein by reference.)

3.2(b)		Articles of Amendment to Articles of Incorporation dated December 30, 2015 – Preferences, Limitations and Relative Rights of 7% Series A2 Convertible Preferred Stock (filed as Exhibit 3.1 to Form 8-K dated February 23, 2016, and incorporated herein by reference.)

3.3		Bylaws (filed as Exhibit 3.3 to Form 10-K for the year ended December 31, 2010 and filed with the SEC on March 30, 2011.)

10.1		Purchase and Sale Agreement among Tucker Family Investment LLLP, DNR Oil & Gas, Inc., Tindall Operating Company and Arête Industries, Inc., dated May 25, 2011 (filed as Exhibit 10.4 to Form 8-K dated May 25, 2011, and incorporated herein by reference.)

10.2		Security Agreement among Tucker Family Investment LLLP, DNR Oil & Gas, Inc., Tindall Operating Company and Arête Industries, Inc., dated May 25, 2011 (filed as part of Exhibit 10.4 to Form 8-K dated May 25, 2011, and incorporated herein by reference.)

10.4		Amended and Restated Purchase and Sale Agreement among Tucker Family Investment LLLP, DNR Oil & Gas, Inc., Tindall Operating Company and Arête Industries, Inc., dated July 29, 2011 (filed as Exhibit 10.5 to Amendment No. 1 to Form 8-K dated May 25, 2011 (filed with the SEC on August 5, 2011), and incorporated herein by reference.)

10.5		First Amendment to the Amended and Restated Purchase and Sale Agreement among Tucker Family Investment LLLP, DNR Oil & Gas, Inc., Tindall Operating Company and Arête Industries, Inc., dated August 12, 2011 (filed as Exhibit 10.8 to Amendment No. 1 to Form 8-K/A dated August 12, 2011 (filed with the SEC on August 18, 2011), and incorporated herein by reference.)

10.6		Second Amendment to the Amended and Restated Purchase and Sale Agreement among Tucker Family Investment LLLP, DNR Oil & Gas, Inc., Tindall Operating Company and Arête Industries, Inc., dated September 16, 2011 (filed as Exhibit 10.9 to Form 8-K dated September 16, 2011, and incorporated herein by reference.)

10.7		Promissory Note due to Pikerni, LLC ($250,000) (filed as Exhibit 10.7 to Registration Statement on Form S-1 filed on May 29, 2012, and incorporated herein by reference)

10.8		Promissory Note due to Fairfield Management Group, LLC ($150,000) (filed as Exhibit 10.8 to Registration Statement on Form S-1 filed on May 29, 2012, and incorporated herein by reference)

10.9		Amended and Restated Contract Operator Agreement between DNR Oil & Gas, Inc. and Arête Industries, Inc. (filed as Exhibit 10.9 to Registration Statement on Form S-1 filed on May 29, 2012, and incorporated herein by reference)

10.10		Agreement regarding Increase in Payments in respect of Amended and Restated Purchase and Sale Agreement (Exhibit C) (filed as Exhibit 10.10 to Registration Statement on Form S-1 filed on May 29, 2012, and incorporated herein by reference)

10.11		Promissory Note due to Apex Financial Services Corp. ($455,000) and Assignment of Proceeds (filed as Exhibit 10.11 to Amended Registration Statement on Form S-1 filed on October 26, 2012, and incorporated herein by reference)

10.12		Promissory Note due to Apex Financial Services Corp. dated April 2, 2013 (filed as Exhibit 10.12 to Form 8-K dated May 3, 2013, and incorporated herein by reference.)

10.13		Notice of Conversion by Burlingame Equity Investors II, LP, dated June 28, 2013 (filed as Exhibit 10.13 to Form 8-K dated July 5, 2013, and incorporated herein by reference.)

10.14		Notice of Conversion by Burlingame Equity Investors Master Fund, LP, dated June 28, 2013 (filed as Exhibit 10.14 to Form 8-K dated July 5, 2013, and incorporated herein by reference.)

10.15		Promissory Note - Burlingame Equity Investors II, LP, dated June 28, 2013 (filed as Exhibit 10.15 to Form 8-K dated July 5, 2013, and incorporated herein by reference.)

10.16		Promissory Note - Burlingame Equity Investors Master Fund, LP, dated June 28, 2013 (filed as Exhibit 10.16 to Form 8-K dated July 5, 2013, and incorporated herein by reference.)

10.17		Form of Notice of Conversion for holders of Series A1 Preferred Stock other than Burlingame Equity Investors II, LP and Burlingame Equity Investors Master Fund, LP (filed as Exhibit 10.17 to Form 8-K dated July 5, 2013, and incorporated herein by reference.)

10.18		Promissory Note, Dated January 28, 2014 City Wide Bank (filed as Exhibit 10.18 to Form 8-K dated February 3, 2014, and incorporated herein by reference.)

10.19		Promissory Note, Dated January 28, 2014 Donald W Prosser (filed as Exhibit 10.19 to Form 8-K dated February 3, 2014, and incorporated herein by reference.)

10.20		Promissory Note, Dated January 28, 2014 Charles B Davis (filed as Exhibit 10.20 to Form 8-K dated February 3, 2014, and incorporated herein by reference.)

10.21		Promissory Note, Dated January 28, 2014 William Stewart (filed as Exhibit 10.21 to Form 8-K dated February 3, 2014, and incorporated herein by reference.)

10.22		Promissory Note, Dated January 28, 2014 DNR Oil & Gas, Inc. (filed as Exhibit 10.22 to Form 8-K dated February 3, 2014, and incorporated herein by reference.)

10.23		Extension of Burlingame Equity Investors II, LP Promissory Note, Dated January 28, 2014 (filed as Exhibit 10.23 to Form 8-K dated February 3, 2014, and incorporated herein by reference.)

10.24		Extension of Burlingame Equity Investors Master Fund, LP Promissory Note, Dated January 28, 2014 (filed as Exhibit 10.24 to Form 8-K dated February 3, 2014, and incorporated herein by reference.)

10.25		Direct stock purchase agreement between Arête Industries, Inc. and Burlingame Equity Investors Master Fund LP dated January 30, 2014 (filed as Exhibit 10.25 to Form 8-K dated February 21, 2014, and incorporated herein by reference.)

10.25		Account Services Agreement between Arête Industries, Inc. and Tristan R. Farel and Pivot Accounting, LLC dated May 26, 2015 (filed as Exhibit 10.1 to Form 8-K dated June 1, 2016, and incorporated herein by reference.)

10.26		Settlement Agreement between Arête Industries, Inc. and Tucker Family Investments, LLLP, DNR Oil & Gas, Inc., Tindall Operating Company, and Tucker Energy, LLC (filed as Exhibit 10.1 to Form 8-K dated February 23, 2016, and incorporated herein by reference.)

10.27		Lease Purchase Agreement between Arête Industries, Inc. and Wellstar Corporation, dated November 24, 2015 (filed as Exhibit 10.2 to Form 8-K dated February 23, 2016, and incorporated herein by reference.)

14		Code of Business Conduct and Ethics (filed as Exhibit 14 to Registration Statement on Form S-1 filed on May 29, 2012, and incorporated herein by reference)

21		List of Subsidiaries (filed as Exhibit 21 to Registration Statement on Form S-1 filed on May 29, 2012, and incorporated herein by reference)

31.1		Certification of the Principal Executive Officer pursuant to §302 of the Sarbanes-Oxley Act of 2002. *

31.2		Certification of the Principal Financial Officer pursuant to §302 of the Sarbanes-Oxley Act of 2002. *

32.1		Certification of the Principal Executive Officer pursuant to 18 U.S.C. Section 1350. *

32.2		Certification of the Principal Financial Officer pursuant to 18 U.S.C. Section 1350. *

99.1		Report of Pinnacle Energy Services, L.L.C.*

101		The following materials are filed herewith: (i) XBRL Instance, (ii) XBRL Taxonomy Extension Schema, (iii) XBRL Taxonomy Extension Calculation, (iv) XBRL Taxonomy Extension Definition, (v) XBRL Taxonomy Extension Labels, and (vi) XBRL Taxonomy Extension Presentation.

*	Filed herewith.

SIGNATURES

In accordance with Section 13 or 15(d) of the Exchange Act, the registrant caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


	Arête Industries, Inc.

May 6, 2016	By:	/s/ Nicholas L. Scheidt
		Nicholas L. Scheidt,
		Chief Executive Officer

In accordance with the Exchange Act, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

/s/ Nicholas L. Scheidt
Nicholas L. Scheidt	Chairman of the Board, Chief Executive Officer (Principal Executive Officer), Director	May 6, 2016
/s/ Tristan R. Farel
Tristan R. Farel	Chief Financial Officer (Principal Financial and Accounting Officer)	May 6, 2016
/s/ Robert J. McGraw
Robert J. McGraw	Director	May 6, 2016
/s/ Charles B. Davis
Charles B. Davis	Director and Chief Operating Officer	May 6, 2016
/s/ William W. Stewart
William W. Stewart	Director and Assistant Secretary	May 6, 2016
/s/ Randall K. Arnold
Randall K. Arnold	Director	May 6, 2016