10-K

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, 2016

☐ 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  ☒     No¹

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.

Large accelerated filer	☐	Accelerated filer	☐
Non-accelerated filer	☐	Smaller reporting company	☒
Emerging growth company	☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) 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 9,850,413 shares of voting stock held by non-affiliates of the registrant, based upon the closing sale price of the registrant's common stock on September 30, 2017, the last business day of the registrant's most recently completed third fiscal quarter, of $0.14 per share was $1,379,058.

As of November 30, 2017, the Registrant had 14,674,580 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 and has not filed all Exchange Act reports for the preceding 12 months.

Arête Industries, Inc.

Index to Form 10-K

		Page
PART I		5
Item 1.	Business	5
Item 1A.	Risk Factors	10
Item 1B	Unresolved Staff Comments	18
Item 2.	Properties	19
Item 3.	Legal Proceedings	24
Item 4.	Mine Safety Disclosures	24
PART II		24
Item 5.	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	24
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	32
Item 9-A	Controls and Procedures	32
Item 9-B	Other Information	33
PART III		34
Item 10.	Directors, Executive Officers and Corporate Governance	34
Item 11.	Executive Compensation	37
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	38
Item 13.	Certain Relationships and Related Transactions, and Director Independence	38
Item 14.	Principal Accounting Fees and Services	39
PART IV		40
Item 15.	Exhibits, Financial Statement schedules	40

1

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 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.

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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.

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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.

4

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. There has been no activity on this project in 2017 and we do not expect any activity in 2018.

On September 11, 2017, we entered into an Offer to Purchase Letter for a 25% working interest in two of the Company's oil and gas assets located in Clark County, Kansas for total consideration of $150,000. On November 15, 2017, we completed the sale under a purchase and sale agreement, with an effective date of October 1, 2017 (the "VenJohn PSA"), with Marc VenJohn.

5

Business Strategy

Our business strategy is three-fold in approach.

• 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 impacted the oil and gas industry. As of November 30, 2017, the price of crude oil was approximately $58 per barrel. Continuation of these steep declines puts 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.

6

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

Environmental Regulations

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

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

Hazardous Substances and Wastes

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

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

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Water Discharges

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

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

Hydraulic Fracturing

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

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

Air Emissions

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

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

 In 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.

8

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 issued its final Regulation on June 3, 2016 to be effective August 2, 2016, however, on June 12, 2017 the EPA announced a proposed 2 year stay on the fugitive emissions standards "while the agency reconsiders them".  Therefore, the date when and if these standards may become implemented is still not known.

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. During 2017, the President of the United States determined to withdraw the United States from the Paris Accord.

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.

9

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:

• The statements may disclose our future expectations;

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

• 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, if available at all.

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 2016. 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.

10

Declines in oil and gas prices could materially adversely affect the Company's revenues.

The Company's financial condition and results of operations depend in large part upon the prices obtainable for the Company's oil and natural gas production and the costs of finding, acquiring, developing and producing reserves. As seen in recent years, prices for oil and natural gas are subject to extreme fluctuations in response to changes in supply, market uncertainty and a variety of additional factors that are beyond the Company's control. These factors include worldwide political instability (especially in the Middle East and other oil producing regions), the foreign supply of oil and gas, the price of foreign imports, the level of drilling activity, the level of consumer product demand, government regulations and taxes, the price and availability of alternative fuels, speculating activities in the commodities markets, and the overall economic environment. The Company's operations are substantially adversely impacted as oil prices decline. Lower prices dramatically affect the Company's revenues from its operations. Further, drilling of new wells, development of the Company's leases and acquisitions of new properties are also adversely affected and limited. As a result, the Company's potential revenues from operations as well as the Company's proved reserves may substantially decrease from levels achieved during the period when oil prices were much higher. There can be no assurances as to the future prices of oil or gas. A substantial or extended decline in oil or gas prices would have a material adverse effect on the Company's financial position, results of operations, quantities of oil and gas that may be economically produced, and access to capital. Oil and natural gas prices have historically been and are likely to continue to be volatile.

This volatility makes it difficult to estimate with precision the value of producing properties in acquisitions and to budget and project the return on exploration and development projects involving the Company's oil and gas properties. In addition, unusually volatile prices often disrupt the market for oil and gas properties, as buyers and sellers have more difficulty agreeing on the purchase price of properties.

There is risk that 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 him 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.

11

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:

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

• Pressure or irregularities in geological formations;

• Equipment failures or accidents;

• Adverse weather conditions;

• Reductions in oil and natural gas prices;

• Issues associated with property titles; and

• 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:

• Blowouts, fires and explosions;

• Personal injuries and death;

• Uninsured or underinsured losses;

• Unanticipated, abnormally pressured formations;

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

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

Any of these operating hazards could cause damage to properties, 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.

12

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, 2016, 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".

13

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.

14

Use of the Company's Net Operating Loss Carryforwards May Be Limited.

At December 31, 2016, the Company had, subject to the limitations discussed in this risk factor, substantial amounts of net operating loss carryforwards for U.S. federal and state income tax purposes. These loss carryforwards will eventually expire if not utilized. In addition, as to a portion of the U.S. net operating loss carryforwards, the amount of such carryforwards that the Company can use annually is limited under U.S. tax laws. Uncertainties exist as to both the calculation of the appropriate deferred tax assets based upon the existence of these loss carryforwards, as well as the future utilization of the operating loss carryforwards under the criteria set forth under FASB ASC 740, Income Taxes. In addition, limitations exist upon use of these carryforwards in the event that a change in control of the Company occurs. There are risks that the Company may not be able to utilize some or all of the remaining carryforwards, or that deferred tax assets that were previously booked based upon such carryforwards may be written down or reversed based on future economic factors that may be experienced by the Company. The effect of such write downs or reversals, if they occur, may be material and substantially adverse. At December 31, 2016 and 2015, the Company recorded a valuation allowance against the entire deferred tax asset, including the portion related to the remaining net operating loss carryforwards. This allowance was recorded primarily as a result of cumulative book losses experienced the periods ended December 31, 2016 and 2015.

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.

The Company's operations are also subject to numerous and frequently changing laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. The Company owns or leases, and has owned or leased, properties that have been leased for the exploration and production of oil and gas and these properties and the wastes disposed on these properties may be subject to the Comprehensive Environmental Response, Compensation and Liability Act, the Oil Pollution Act of 1990, the Resource Conservation and Recovery Act, the federal Water Pollution Control Act, the federal Endangered Species Act, and similar state laws. Under such laws, the Company could be required to remove or remediate wastes or property contamination.

Laws and regulations protecting the environment have generally become more stringent and, may in some cases, impose "strict liability" for environmental damage. Strict liability means that the Company may be held liable for damage without regard to whether it was negligent or otherwise at fault. Environmental laws and regulations may expose the Company to liability for the conduct of or conditions caused by others or for acts that were in compliance with all applicable laws at the time they were performed. Failure to comply with these laws and regulations may result in the imposition of administrative, civil and criminal penalties.

The Company's ability to conduct continued operations is subject to satisfying applicable regulatory and permitting controls. The Company's current permits and authorizations and ability to get future permits and authorizations may be susceptible, on a going forward basis, to increased scrutiny, greater complexity resulting in increased cost or delays in receiving appropriate authorizations.

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.

15

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 creates 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.

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 and customers. 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.

16

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.

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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 14,674,580 shares of our common stock outstanding as of November 30, 2017. As of that date, members of our management and their affiliates beneficially owned approximately 4,824,167 shares of our common stock, representing 33.7% 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 intend 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

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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, 2016:

	Productive Wells
	During 2016
State	Gross		Net (a)
Wyoming		23.0		14.8
Kansas		14.0		7.8
Colorado		4.0		4.0
Nebraska		1.0		1.0
Montana		2.0		1.4
		44.0		29.0

(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 2016 other than to the SEC.

The table below summarizes our estimated proved reserves at December 31, 2016 based on reports prepared by Pinnacle. In preparing these reports, Pinnacle evaluated 100% of our properties at December 31, 2016. For more information regarding our independent reserve engineers, please see "Independent Reserve Engineers" below.

	Proved Reserves at 2016 Year-End								Productive Wells				2016 Average
	Quantity		Pre and Post-Tax			%			During 2016				Monthly Production
State	(BOE) (a)		PV 10% (b)			Oil (c)			Gross		Net (d)		(BOE)
Wyoming		75,150		$	398,030		73.5	%		23.0		14.8		1,286
Kansas		90,840			484,710		100.0	%		14.0		7.8		901
Colorado		-			-		-	%		4.0		4.0		204
Nebraska		-			-		-	%		1.0		1.0		91
Montana		-			-		-	%		2.0		1.4		49
		165,990		$	882,740		82.2	%		44.0		29.0		2,531

(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, 2016, which resulted in benchmark prices of $42.75 per barrel for crude oil and $2.49 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 -$2.97/bbl to -$10.77/bbl for oil and for natural gas ranged from -74% to +59% of NYMEX.
(c)	Computed based on BOE using the ratio of six Mcf of natural gas to one barrel of oil.
(d)	Net wells are the sum of our fractional working interests owned in gross wells.

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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	$	5,751,250		$	5,751,250
Future production costs		(4,322,870	)		(4,322,870	)
Future development costs		-			-
Future income taxes		-			-
Future net cash flows		1,428,380			1,428,380
10% annual discount		(545,640	)		(545,640	)
Discounted future net cash flows	$	882,740		$	882,740

There was no difference between the standardized measure of $882,740 and PV10 of $882,740 because there are no income taxes included in the standardized measure at December 31, 2016.

Proved Undeveloped Reserves

At December 31, 2016, 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 have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

To establish reasonable certainty with respect to our estimated proved reserves, our independent reserve engineers, Pinnacle Energy Services, LLC ('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 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 License  No. F6204. Within Pinnacle, the technical persons 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.

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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, 2016, 2015 and 2014, the average sales price per unit sold and the average production cost per unit are presented below.

	Years Ended December 31,
	2016			2015			2014
Oil sales	$	889,285		$	777,123		$	1,797,230
Natural gas sales		82,873			143,907			361,053
Royalty revenues		2,325			4,871			3,369
Sale of oil and natural gas properties		-			27,120			391,585
Total revenue		974,483			953,021			2,553,237
Production taxes		(76,715	)		(84,576	)		(179,660	)
Lease operating expense		(1,064,427	)		(754,362	)		(791,142	)
Other operating expenses		-			(160,011	)		(36,250	)
Depreciation, depletion, amortization and accretion ("DD&A")		(533,333	)		(816,481	)		(767,857	)
Impairment Expense		(3,358,000	)		(3,231,000	)		-
Net operating income (loss) from oil and gas producing activities	$	(4,057,992	)	$	(4,093,409	)	$	778,328
Net barrels of oil sold		23,386			18,956			22,825
Net Mcf of gas sold		41,937			62,630			70,195
Net Barrels of Oil Equivalent ("BOE") sold		30,376			29,394			34,524
Average price per barrel of oil sold	$	38.03		$	41.00		$	78.74
Average price for per Mcf of natural gas sold	$	1.98		$	2.30		$	5.14
Lease operating expense per BOE	$	35.04		$	25.66		$	22.92
DD&A per BOE	$	17.56		$	27.78		$	22.24

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Gross and Net Developed and Undeveloped Acres

As of December 31, 2016, 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, 2016, 2015 and 2014 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
2016		0.00		0.00		0.00		0.00		0.00
2015		0.00		0.00		0.00		0.00		0.00
2014		0.00		0.00		0.0169		0.00		0.0169

Present Activities

At November 30, 2017, 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 primarily of oil and natural gas companies.   Our major customers for 2016 and 2015 were as follows. 

Year	Name of Customer	Amount of Year's Gross Reveneus
2016	DNR Oil & Gas, Inc. – Related Party		90.1	%
2016	Yates Petroleum Corporation		4.7	%
2016	Peak Powder River Resources, LLC		3.7	%
2015	DNR Oil & Gas, Inc. – Related Party		81.9	%
2015	Yates Petroleum Corporation		10.1	%
2015	Peak Powder River Resources, LLC		5.5	%

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

22

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.

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Office Facilities

We currently lease no office space.

Item 3. LEGAL PROCEEDINGS

On September 30, 2016 plaintiff Eric Langan et al. filed a complaint in Maricopa County Superior Court for common law fraud under Arizona law against Arête Industries, Inc., Don and Jane Doe Prosser, and Charles and Jane Doe Davis. The action was removed to federal court on November 17, 2016, civil action number 16 – 03994 – PHX – SPL. On September 1, 2017 a judgment was entered in favor of the defendants and against plaintiffs and the case was dismissed in its entirety for lack of personal jurisdiction.

We are unaware of any other dispute which might lead to future litigation.

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, 2016:
First Quarter	$	0.11	$	0.05
Second Quarter		0.13		0.08
Third Quarter		0.14		0.10
Fourth Quarter		0.15		0.09
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

On November 30, 2017, the last reported sales price of our common stock as reported on the OTCQB was approximately $.08 per share.

Holders

As of November 30, 2017 the number of holders of record of shares of our common stock, our only class of trading securities, was approximately 216. 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 approximately 3,900.

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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 on its common stock.

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 constitutes 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

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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 are an independent energy company whose business plan is to acquire, explore and develop oil, natural gas and natural gas liquids ("NGL's") in the United States. Due to the limited capital and low commodity prices, we have not been able to execute on our business plan since 2014. Our long-term strategy is to seek to deliver net asset value per share growth to our investors via attractive investments within the oil and gas industry. In the event we are able to obtain sufficient additional capital we expect to 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, re-completion and re-working projects. In addition, we seek acreage, prospective for oil and natural gas, to purchase in order to obtain cash flow from the re-sale and farm out of such prospects.

We do not operate any of the properties in which we have an interest. As a result, we have limited ability to exercise influence over, and control the risks associated with operations of these properties. The failure of an operator of our wells to adequately perform operations, an operator's breach of the applicable agreements or an operator's failure to act in ways that are in our best interests could reduce our ability to be successful in finding reserves and could create a liability for us for the operator's failure to properly operate the project and adhere to applicable safety and environmental standards.

It is our desire to provide an understanding of the Company's past performance, its financial condition and its prospects for the future. Accordingly, we discuss and provide our analysis of the following:

•Results of operations;

•Liquidity and capital resources;

•Contractual obligations;

•Off balance sheet arrangements;

•Critical accounting policies; and

•New accounting pronouncements.

Oil, Gas, and NGL Prices

Our financial condition and the results of our operations are significantly affected by the prices we receive for our oil, gas, and NGL production, which can fluctuate dramatically. Our oil and gas is sold under our operators' contracts paying us various industry posted prices, adjusted for basis differentials. We are paid the average of the daily settlement price for the respective posted prices for the period in which the product is sold, adjusted for quality, transportation and location differentials.

We expect future prices for oil, gas, and NGLs to continue to be volatile.  In addition to supply and demand fundamentals, as a global commodity, the price of oil is affected by real or perceived geopolitical risks in all regions of the world as well as the relative strength of the dollar compared to other currencies. Oil markets continue to be unstable.

Results of Operations for the Years Ended December 31, 2016 and 2015

Presented below is a discussion of our results of operations for the years ended December 31, 2016 and 2015.

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Net Loss Applicable to Common Stockholders

Net loss applicable to common stockholders for the years ended December 31, 2016 and 2015 was $4,691,006 and $4,747,053, respectively. The net loss in 2016 and 2015 is primarily due to noncash impairment charges of $3.4 million and $3.2 million, respectively, to the carrying value of our proved oil and gas properties. Our oil and natural gas sales, excluding sales of properties, were higher by $48,582 compared to the prior year. Oil and gas producing costs increased $142,193, gas gathering expenses decreased $102,416 (this project was written off in the prior year and is shut-in) and G&A expenses decreased $95,507. The Company declared dividends on its Series 2 Class A Preferred Stock equal to $191,961 during the year ended December 31, 2016, there were no dividends declared in 2015.

The discussion below further discusses our results of operation for the year ended December 31, 2016 and 2015.

Oil and Gas Producing Activities

The results of our producing oil and gas properties are presented below for the year ended December 31, 2016 and 2015:

	Year Ended
	December 31,
	2016			2015			$ Change			% Change
Oil Sales	$	889,285		$	777,123		$	112,162			14.4	%
Natural Gas Sales		82,873			143,907			(61,034	)		(42.4	)%
Royalty sales		2,325			4,871			(2,546	)		(52.3	)%
Sale of oil and gas properties		-			27,120			(27,120	)		(100.0	)%
Total Revenue		974,483			953,021		$	21,462			2.3	%
Lease Operating Expense		1,064,427			754,362		$	310,065			41.1	%
Production Taxes		76,715			84,576			(7,861	)		(9.3	)%
Other operating expense		-			160,011			(160,011	)		(100.0	)%
Depreciation, depletion, amortization ("DD&A")		439,000			746,106			(307,106	)		(41.2	)%
Accretion		94,333			70,375			23,958			34.0	%
Impairment expense		3,358,000			3,231,000			127,000			3.9	%
Total operating expenses		5,032,475			5,046,430			(13,955	)		(0.3	)%
Net operating loss before general and administrative expense		(4,057,992	)		(4,093,409	)		35,417			(0.9	)%
Net barrels of oil sold		23,386			18,956			4,430			23.4	%
Net mcf of gas sold		41,937			62,630			(20,693	)		(33.0	)%
Boe		30,376			29,394			982			3.3	%
Average price for oil	$	38.03		$	41.00		$	(2.97	)		(7.2	)%
Average price for gas	$	1.98		$	2.30		$	(0.32	)		(14.0	)%
Lease operating expense per BOE	$	35.04		$	25.66		$	9.38			36.5	%
DD&A per BOE	$	17.56		$	27.78		$	(10.22	)		(36.8	)%

Years Ended December 31, 2016 and 2015

Our oil sales for the years ended December 31, 2016 and 2015 were $889,285 and $777,123, respectively, an increase of $112,162 or 14.4%. This increase can be attributed to increased sales volumes, which were 23,386 barrels of oil compared to 18,956 barrels of oil, which is an increase of 4,430 barrels or 23.4%. The increase in barrels is primarily related to the acquisition of the Padgett Properties in December 2015, where we produced 5,849 barrels in 2016 and none in 2015. The increased production from the Padgett Properties was offset with lower production from the legacy properties due to the natural decline and wells being temporarily shut-in for workovers performed throughout the year. The effect on our oil sales due to the increased sales volumes was an increase of $168,471, offset by lower average realized oil prices of $38.03 per barrel, which was $2.97 lower compared to $41.00 per barrel in 2015. This decrease of 7.2% in price negatively impacted our oil sales by $56,309.

Our natural gas sales for the years ended December 31, 2016 and 2015, were $82,873 and $143,907, respectively, a decrease of $61,034 or 42.4%. The average realized natural gas prices, including proceeds from sales of natural gas liquids, in 2016 and 2015, were $1.98 and $2.30 per Mcf, respectively, a decrease of $0.32 or 14.0%. The impact on natural gas sales in the current year due to the lower realized prices resulted in decreased natural gas sales of $40,891, which was further impacted by decreased natural gas volumes, 41,937 Mcf compared to 62,630 Mcf in the prior year, which was 20,693 Mcf or 33.0% lower volumes, resulting in a reduction of natural gas sales of $20,143.

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Lease operating expense ("LOE") for the years ended December 31, 2016 and 2015 were $1,064,427 and $754,362, which was an increase of $310,065 or 41.1%. LOE per BOE in 2016 and 2015 were $35.04 and $25.66, respectively, an increase of $9.38 or 36.5% compared to the prior year. This increase in the cost per BOE was due to increased maintenance, pump changes and chemical work performed during the year, and a workover program in 2016 related to the Padgett Properties to enhance the facilities and well equipment. We had approximately $350,000 of expense related to workovers in 2016.

Production taxes were $76,715 and $84,576, for the years ended December 31, 2016 and 2015, respectively, a decrease of $7,861 or 9.3%. We generally expect absolute production tax expense to trend as a percentage with oil, gas, and NGL production revenue within each state we have operations in. Production taxes as a percentage of revenue in 2016 and 2015 were 7.9% and 9.1%. Our production in Kansas and Nebraska has a blended production tax rate of approximately 4.4% and our Wyoming production is approximately 11.0%; therefore, as our sales increase in Kansas and Nebraska the tax rate as a percentage of sales decreases. We had more production in Kansas and Nebraska in 2016 compared to 2015 due to the Wellstar acquisition in December 2015; therefore, the tax rate as a percentage of revenue decreased.

Our DD&A expenses were $439,000 and $746,106, for the years ended December31, 2016 and 2015, respectively, a decrease of $307,706 or 41.2%. This decrease was due to a lower depletable base because of impairments of oil and gas properties at December 31, 2015 and March 31, 2016, as well as an increase in the reserve base related to the acquisition of additional producing wells (Padgett Properties) at December 31, 2015, which reduced the DD&A rate.

We perform assessments of our long-lived assets to be held and used, including oil and gas properties, whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. To the extent such assessments indicate a reduction of the estimated useful life or estimated future cash flows of our oil and gas properties, the carrying value may not be recoverable and therefore an impairment charge would be required to reduce the carrying value of the proved properties to their fair value.

The cash flow model we use to assess proved properties for impairment includes numerous assumptions. The primary factors that may affect estimates of future cash flows are (i) future reserve adjustments, both positive and negative, to proved reserves and appropriate risk-adjusted probable and possible reserves, (ii) results of future drilling activities, (iii) management's price outlook and (iv) increases or decreases in production costs and capital costs associated with those reserves. All inputs to the cash flow model are evaluated at each measurement date.

As a result of our impairment assessments of our oil and gas properties and gas gathering system, a noncash charge to reduce the carrying values, we recorded impairment expense of $3,358,000 against our proved property in 2016 and an aggregate $3,231,000 in2015against our proved properties and unevaluated properties.

General and Administrative

Presented below is a summary of general and administrative expenses for the years ended December 31, 2016 and 2015:

	December 31,
General and administrative expenses:	2016		2015		$ Change			% Change
Director fees		40,000		47,833	$	(7,833	)		(16.4	)%
Investor relations		12,209		28,128		(15,919	)		(56.6	)%
Legal, auditing and professional fees		183,683		116,078		67,605			58.2	%
Consulting fees - Related Parties		66,732		172,217		(105,485	)		(61.3	)%
Other administrative expenses		41,187		74,634		(33,447	)		(44.8	)%
Depreciation		-		428		(428	)		(100.0	)%
Total G&A Expense		343,811		439,318		(95,507	)		(21.7	)%

Years Ended December 31, 2016 and 2015

General and administrative expenses decreased $95,507 or 21.7% for the year ended December 31, 2016, compared to the same period in 2015. This reduction was primarily due to a decrease in investor relations costs, related party consulting fees and other administrative expenses. We changed our service provider for our shareholder communications, which resulted in a significant cost savings in our investor relations costs, additionally, we are no longer paying Charlie Davis a consulting fee to be our Chief Operating Officer and are only incurring costs to DNR as our operator, which are included in LOE in the current period. We entered into a new D&O Insurance policy in 2016, which resulted in a cost savings in our other administrative expenses. These reductions were offset by higher legal costs related to litigation, general corporate and securities filings and higher auditing and accounting fees. The costs per BOE, decreased $3.63 or 24.3% to $11.32 per BOE compared to $14.95 per BOE in the prior year.

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Interest Expense, net

Interest expense, net of interest income, for the years ended December 31, 2016 and 2015 was $98,117 and $111,910, respectively, a decrease of $13,793 or 12.3%, due to a decrease in the amount of debt outstanding compared to the same period the prior year. We recorded $11,177 of interest expense to related parties during the year ended December 31, 2016 and paid $2,652 to one of the related parties. The remaining interest expense was to unrelated parties, of which we made payments of $81,743 during the year ended December 31, 2016.

Liquidity and Capital Resources

We do not generate adequate revenue to satisfy our current operations, we have negative cash flows from operations, and we have incurred significant net operating losses during the year ended December 31, 2016 and 2015, which raise substantial doubt about the Company's ability to continue as a going concern. The ability to continue as a going concern and appropriateness of using the going concern basis is dependent upon, among other things, additional cash infusion. We have historically obtained funds through private placement offerings of equity and debt, as well as, asset sales.

In late 2015, we raised approximately $1.7 million through a private placement of our Series A2 Preferred Stock. We have successfully negotiated extensions with some of our key notes payable holders resulting in extending the due dates of the notes. Since 2011, we have sold various interests in some of our oil and gas properties, which have resulted in aggregate net proceeds from these sales of $6,377,000. Still, our ability to continue as a going concern is dependent upon the ability to successfully accomplish our business plan and continue to secure other sources of financing and attain profitable operations. The Company continues to pursue additional sources of financing but there can be no assurance that such financing will be completed on terms favorable to the Company, if at all.

We had a working capital deficit as of December 31, 2016 and 2015, of $1.4 million and $1.4 million, respectively. The components of our working capital deficit compared to the prior year were a decrease in our current assets by $473,343, primarily due to a decrease in our cash account, which was lower by $350,296. Our current liabilities decreased by $460,611 compared to the prior year. This decrease can be mostly attributed to our current portion of notes payable decreasing due to extensions we entered into with some of our key debtors.

We incurred negative cash flow of $463,750 from our operations during the year ended December 31, 2016 compared to negative operating cash flow of $96,890 during the same period in the prior year, a change of $366,860 or 378.6%. This increase in cash used in operating activities can be attributed to an increase in operating costs of $302,204 and the remaining change is due to the timing of our cash receipts and payments.

Investing activities used net cash of $249 during the year ended December 31, 2016, which was related to the payment of some leasehold costs and capital additions to some existing wells in which we own a very small working interest in. We used $1.1 million of cash during the year ended December 31, 2015, 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.

We had $113,703 of net cash provided by financing activities for the year ended December 31, 2016, and $1.7 million provided by financing activities for the same period in the prior year. During the current year we entered into a short-term note payable with an unrelated party for net proceeds of $25,500 to finance our D&O Insurance liability policy, we entered into a two year note payable with three unrelated party's for net proceeds of $225,000, we made principal payments on our notes payable in the amount of $147,826, we received $105,000 related to the A2 Preferred Stock issued during the prior year, as well as, receiving proceeds of $50,000 for an additional sale of 5 shares of our A2 Preferred Stock and we paid $143,971 in dividends to our A2 Preferred Stock holders. We had approximately $1.7 million of net cash provided by financing activities in 2015, which consisted of borrowings of $67,000 against our line of credit, principal payments made to certain notes payables of $25,568 and proceeds received in the amount of $1,665,000 through our Series A2 Preferred Stock private placement.

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, which was paid on January 19, 2016.

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Contractual Obligations and Commercial Commitments

As of December 31, 2016, we had no operating leases in place.

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 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 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, 2016 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 and impairments of undeveloped properties..

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.

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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 Statements of Operations.

Stock-based Compensation

We did not grant any stock options or warrants during 2016 and 2015 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 2016 and 2015. We have recorded these transactions based on the value of the services or the value of the common stock, whichever is more readily determinable.

New Accounting Pronouncements

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 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 February 2016, FASB issued ASU 2016-02, "Leases." ASU 2016-02 requires the recognition of lease assets and lease liabilities by lessees for those leases currently classified as operating leases and makes certain changes to the way lease expenses are accounted for. This update is effective for fiscal years beginning after December 15, 2018 and for interim periods beginning the following year. This update should be applied using a modified retrospective approach, and early adoption is permitted. The Company is evaluating the new guidance and has not determined the impact this standard may have on its financial statements.

In November 2016, the FASB issued ASU 2016-18, "Statement of Cash Flows: Restricted Cash" to address diversity in practice in the classification and presentation of changes in restricted cash. The accounting update requires that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, amounts generally described as restricted cash or restricted cash equivalents should be included with cash and cash equivalents when reconciling beginning-of-period and end-of-period amounts shown on the statement of cash flows. The guidance is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years, with early adoption permitted. This is an expansive set of revisions to the cash flow presentation standards, but at this time we do not believe that these changes will impact our financial statements.

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Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

The financial statements and supplementary data commence on page F-1.

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

On August 17, 2016, Causey Demgen & Moore P.C. ("CDM") declined to stand for re-election to serve as Arête Industries, Inc.'s (the "Company") independent registered public accounting firm to audit the Company's financial statements as of and for the fiscal year ending December 31, 2016.

The reports of CDM on the financial statements of the Company as of and for the fiscal years ended December 31, 2015 and 2014, did not contain any adverse opinion or disclaimer of opinion, and were not qualified or modified as to uncertainty, audit scope or accounting principles. During the fiscal years ended December 31, 2015 and 2014, and the interim period through August 17, 2016, (i) the Company had no disagreements with CDM on any matter of accounting principles or practices, financial statement disclosure or auditing scope or procedure, which disagreements, if not resolved to CDM's satisfaction, would have caused CDM to make reference to the subject matter of such disagreements in its reports on the financial statements of the Company for such time period and (ii) there were no reportable events of the type described in Item 304(a)(1)(v) of Regulation S-K.

On August 26, 2016, the Company's Board of Directors unanimously appointed Hein & Associates LLP ("Hein") to serve as the Company's new independent registered public accounting firm to audit the Company's financial statements as of and for the fiscal year ended December 31, 2016. The appointment became effective upon the completion of Hein's client acceptance procedures, which occurred on August 26, 2016

During the fiscal years ended December 31, 2015 and 2014, and the interim period through August 26, 2016, the Company did not consult Hein with respect to either (i) the application of accounting principles to a specified transaction, either completed or proposed, or the type of audit opinion that might be rendered on the Company's financial statements, and no written report or oral advice was provided to the Company by Hein that Hein concluded was an important factor considered by the Company in reaching a decision as to the accounting, auditing or financial reporting issue; or (ii) any matter that was either the subject of a disagreement, as that term is described in Item 304(a)(1)(iv) of Regulation S-K and the related instructions to Item 304 of Regulation S-K, or a reportable event, as that term is described in Item 304(a)(1)(v) of Regulation S-K.

On November 30, 2017, HEIN & Associates, LLP ("HEIN") declined to stand for re-election to serve as Arête Industries, Inc.'s (the "Company") independent registered public accounting firm to audit the Company's financial statement as of and for the fiscal year ending December 31, 2017.

The report of HEIN on the financial statement of the Company as of and for the fiscal year ended December 31, 2016, did not contain any adverse opinion or disclaimer of opinion, and were not qualified or modified as to uncertainty, audit scope or accounting principles, except that it contained and explanatory paragraph noting substantial doubt about our ability to continue as a going concern. During the fiscal year ended December 31, 2016, (i) the Company had no disagreements with HEIN on any matter of accounting principles or practices, financial statement disclosure or auditing scope or procedure, which disagreements, if not resolved to HEIN's satisfaction, would have caused HEIN to make reference to the subject matter of such disagreements in its reports on the financial statement of the Company for such time period and (ii) there were no reportable events of the type described in Item 304(a)(1)(v) of Regulation S-K, except HEIN communicated the material weaknesses noted in item 9(a) of this 10-K.

Item 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

As of December 31, 2016, 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.

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Management's Report on Internal Control Over Financial Reporting.

As of December 31, 2016, 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 our disclosure obligations under the Exchange Act and the rules and regulations promulgated thereunder. As discussed in our Annual Report on Form 10-K for the year ended December 31, 2015, the ineffectiveness of our disclosure controls and procedures is due primarily to (i) our Board of Directors does not currently have any independent members that qualify as an audit committee financial expert, (ii) we have not developed and effectively communicated our accounting policies and procedures, (iii) our documentation of transaction in certain circumstances is not timely due to our limited staff and resources, (iv) our controls over financial statement disclosures were determined to be ineffective, including deficiencies in the preparation of the disclosure checklist and (v) 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 (vi) We have not maintained a tax basis property roll-forward and we have not filed tax returns since 2011 and therefore the tax assets disclosed are managements best estimate and this estimate could change as the company completes it tax returns.

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.

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PART III

Item 10. Directors, Officers and Executive matters

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	FirstBecame Officer and/or Director	Position(s)
Nicholas L. Scheidt 7260 Osceola Street Westminster, CO 80030	56	November 2012	Director and Chief Executive Officer
Charles B. Davis 7260 Osceola Street Westminster, CO 80030	59	October 2007	Director and Chief Operating Officer
William W. Stewart 7260 Osceola Street Westminster, CO 80030	56	December 2001	Director and Assistant Secretary
Robert J. McGraw, Jr. 7260 Osceola Street Westminster, CO 80030	62	April 2015	Director
Randall K. Arnold 7260 Osceola Street Westminster, CO 80030	64	June 2015	Director
Tristan R. Farel 7260 Osceola Street Westminster, CO 80030	47	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.

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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 seven times during the year 2016.

Director Independence

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

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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 2016.

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 2016.

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 did not meet during the year 2016.

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.

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ITEM 11. EXECUTIVE COMPENSATION

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 2016 or 2015 in their capacity as officers. During 2016 and 2015, we used independent contractors, consultants, attorneys and accountants as necessary, to complement services for operations and regulatory filings.

We paid $4,000 for Nicholas Scheidt as his compensation as Chief Executive Officer for services through in 2016. 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 $156,000 and $216,000 in 2016 and 2015, 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 $5,300 with 40,000 shares of common stock valued at $5,250 in 2015 for management services.

We issued Tristan R. Farel 316,667 shares of common stock in 2016 with a fair value of $25,333 as his compensation for services performed as CFO and have accrued $35,398 in consulting fees as of December 31, 2016 for CFO services.

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	FeesEarned ($)(1)		StockAwards ($)		OptionAwards ($)		All OtherCompensation ($)		Total ($)
Charles B. Davis	$	8,000	$	—		—		—	$	8,000
William W. Stewart	$	8,000	$	—		—		—	$	8,000
Robert J. McGraw, Jr.	$	8,000	$	—		—		—	$	8,000
Randall K. Arnold	$	8,000	$	—		—		—	$	8,000
Nicholas L. Scheidt	$	8,000	$	—		—		—	$	8,000

(1) Our Directors are entitled to a fee equal to $2,000 at the end of each calendar quarter, which is payable in the Company's common stock once approved by the board of directors. The number of shares is calculated based on the closing price of our common stock as reported by the OTC Market on the date the board approves the issuance of the shares.

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.

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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 April 26, 2015 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 April 16, 2016, were 14,295,413.

Title of Class	Name and Address of Beneficial Owner Directors and Executive Officers	Amount and Nature of Beneficial Ownership		Percentof 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	483,333		3.4	%
Common Stock	Directors and Officers as a Group (6 persons)	Total:	4,507,500		33.7	%

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:

	2016		2015
Officers, directors and affiliates:
Collateralized note payable (1)	$	120,728	$	120,728
Notes payable, interest 7.0%, due January 2019 (2)		30,546		43,803
Total officers, directors and affiliates		151,274		164,531
Less: Current portion of officers, directors, and affiliates		134,839		13,152
Long-term portion of officers, directors, and affiliates	$	16,435	$	151,379

(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 $120,728, with interest accruing at an annual rate of 7.5%, with principal and interest due on 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 asset 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 paid a loan fee to Apex 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 Company obtained a default waiver from Apex related to the new notes entered into through December 31, 2016. The Company has not had operating income or had any lease or well sales in the current fiscal year; therefore, no payments have been made to Apex through December 31, 2016.

(2) In January 2014, we memorialized certain short-term liabilities owed to one of our directors, Charlie Davis, into a formal promissory note. This note accrues interest at an annual rate of 7.0% with monthly payments equal to $1,316 (principal and interest) and will mature on January 1, 2019.

We had related party payables of accrued interest to the officers and directors above of $18,567 at December 31, 2016.

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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. $91,668 (2016) and $53,200 (2015)

2. Audit-Related Fees. $-0- (2016 and 2015)

3. Tax Fees. $-0- (2016 and 2015)

4. All Other Fees. $-0- (2016 and 2015)

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 Hein & Associates, LLP in 2016 and Causey Demgen and Moore, P.C. in 2015 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

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PART IV

Item 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

1. The following documents are filed as part of this Report:

Balance Sheets

Statements of Operations

Statements of Stockholder's Equity (Deficit)

Statement of Cash Flows

Notes to Financial Statements

2. Financial Schedules:

Schedules have been omitted because the information required to be set forth therein is not applicable or is included in the Financial Statements or notes thereto.

3. 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)

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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.

41

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.
November 30, 2017	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	Chairman of the Board, Chief Executive Officer (Principal Executive Officer), Director	November 30, 2017
Nicholas L. Scheidt
/s/ Tristan R. Farel	Chief Financial Officer (Principal Financial and Accounting Officer)	November 30, 2017
Tristan R. Farel
/s/ Robert J. McGraw	Director	November 30, 2017
Robert J. McGraw
/s/ Charles B. Davis	Director and Chief Operating Officer	November 30, 2017
Charles B. Davis
/s/ William W. Stewart	Director and Assistant Secretary	November 30, 2017
William W. Stewart
/s/ Randall K. Arnold	Director	November 30, 2017
Randall K. Arnold

42

ARÊTE INDUSTRIES, INC.

INDEX TO FINANCIAL STATEMENTS

Report of Independent Registered Public Accounting Firm	F-2
Report of Independent Registered Public Accounting Firm	F-3
Balance Sheets – As of December 31, 2016 and 2015	F-4
Statements of Operations – For the years ended December 31, 2016 and 2015	F-6
Statements of Stockholders' Equity (Deficit) – For the years ended December 31, 2016 and 2015	F-7
Statements of Cash Flows – For the years ended December 31, 2016 and 2015	F-8
Notes to Financial Statements	F-9

F-1

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders

Arête Industries, Inc.

We have audited the accompanying balance sheet of Arête Industries, Inc. as of December 31, 2016, and the related statements of operations, stockholders' equity and cash flows for the year 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 audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides 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. as of December 31, 2016, and the results of its operations and its cash flows for the year then ended, in conformity with U.S. generally accepted accounting principles.

The accompanying financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 2 to the financial statements, the Company has suffered recurring losses from operations and its total liabilities exceed its total assets. This raises substantial doubt about the Company's ability to continue as a going concern. Management's plans in regard to these matters also are described in Note 2. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

/s/ Hein & Associates LLP

Denver, Colorado

November 30, 2017

F-2

 

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 the related statements of operations, stockholders' equity and cash flows for the year 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 audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit 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 audit provides 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 the results of its operations and its cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America.

/s/ Causey Demgen & Moore P.C.

Denver, Colorado

May 6, 2016

F-3

ARÊTE INDUSTRIES, INC.
BALANCE SHEETS
As of
	December 31,
ASSETS	2016			2015
Current Assets:
Cash	$	171,370		$	521,666
Accounts receivable - oil and natural gas sales		14,014			2,539
Subscription receivable		-			105,000
Prepaid expenses and other		3,032			32,554
Total Current Assets		188,416			661,759
Property and Equipment:
Oil and gas properties, at cost, successful efforts method:
Proved properties		5,325,381			8,683,273
Unevaluated properties		154,977			154,836
Furniture and equipment		22,522			22,522
Total property and equipment		5,502,880			8,860,631
Less accumulated depreciation, depletion and amortization		(3,684,522	)		(3,245,522	)
Net property and equipment		1,818,358			5,615,109
TOTAL ASSETS	$	2,006,774		$	6,276,868

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

F-4

ARÊTE INDUSTRIES, INC.
BALANCE SHEETS, Continued
	As of December 31,
LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)	2016			2015
Current Liabilities:
Accounts payable:
Trade accounts payable		133,343			64,896
Accounts payable - DNR Oil & Gas, Inc.		453,439			501,281
Accounts payable - directors and affiliates		77,616			-
Dividends payable:
Dividends payable		5,998			-
Dividends payable - directors and affiliates		41,992			-
Accrued interest expense:
Accrued interest expense		23,821			2,532
Accrued interest expense - directors and affiliates		-			9,442
Notes and advances payable - current portion:
Notes and advances payable		240,750			989,853
Notes and advances payable - directors and affiliates		134,839			13,152
Current portion of asset retirement obligations		425,200			409,621
Other accrued costs and expenses		61,745			68,577
Total Current Liabilities		1,598,743			2,059,354
Long-Term Liabilities:
Notes and advances payable, net of current portion:
Notes and advances payable, net of discount		1,032,928			173,519
Notes and advances payable - Directors and affiliates		16,435			151,379
Asset retirement obligations, net of current portion		659,800			585,576
Total Long-Term Liabilities		1,709,163			910,474
Total Liabilities		3,307,906			2,969,828
Commitments and Contingencies (Notes 6, 7, 9 and 10)
Stockholders' Equity (Deficit):
Convertible Class A preferred stock; $10,000 face value per share, authorized 1,000,000 shares:
Series 1; 30,000 shares authorized, none issued and outstanding.		-			-
Series 2; authorized 2,500 shares, 272 and 267 shares issued and outstanding as of December 31, 2016 and 2015, respectively, liquidation preference $2,767,991.		2,720,000			2,670,000
Common stock, no par value; 499,000,000 shares authorized, 14,674,580 and 14,295,413 issued and outstanding as of December 31, 2016 and 2015, respectively.		21,535,469			21,502,635
Accumulated deficit		(25,556,601	)		(20,865,595	)
Total Stockholders' Equity (Deficit)		(1,301,132	)		3,307,040
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)	$	2,006,774		$	6,276,868

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

F-5

ARÊTE INDUSTRIES, INC.
STATEMENTS OF OPERATIONS
	Years ended December 31,
	2016			2015
Revenues:
Oil sales	$	889,285		$	777,123
Natural gas sales		82,873			143,907
Royalty revenues		2,325			4,871
Sale of oil and natural gas properties		-			27,120
Total revenues		974,483			953,021
Operating Expenses:
Oil and natural gas producing activities:
Lease operating expenses		1,064,427			754,362
Production taxes		76,715			84,576
Other operating expense		-			160,011
Depreciation, depletion, amortization and accretion		533,333			816,481
Impairment		3,358,000			3,231,000
Gas gathering:
Operating expenses		-			1,406
Depreciation		-			44,362
Impairment		-			56,648
General and administrative expenses:
Director fees		40,000			47,833
Investor relations		12 ,209			28,128
Legal, auditing and professional fees		183,683			116,078
Consulting fees executive services-related parties		66,732			172,217
Other administrative expenses		41,187			74,634
Depreciation		-			428
Total operating expenses		5,376,286			5,588,164
Operating loss		(4,401,803	)		(4,635,143	)
Other income (expense):
Other income		875			-
Interest expense, net		(98,117	)		(111,910	)
Loss before income taxes		(4,499,045	)		(4,747,053	)
Income tax benefit (expense)		-			-
Net loss attributable to Arête Industries, Inc.	$	(4,499,045	)	$	(4,747,053	)
Net Loss Applicable to Common Stockholders:
Net loss attributable to Arête Industries, Inc.	$	(4,499,045	)	$	(4,747,053	)
Preferred stock dividends declared		(191,961	)		-
Net loss applicable to common stockholders	$	(4,691,006	)	$	(4,747,053	)
Loss Per Share Applicable to Common Stockholders:
Basic	$	(0.32	)	$	(0.37	)
Diluted	$	(0.32	)	$	(0.37	)
Weighted Average Number of Common Shares Outstanding:
Basic		14,528,345			12,882,000
Diluted		14,528,345			12,882,000

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

F-6

ARÊTE INDUSTRIES, INC.

STATEMENTS OF STOCKHOLDERS' EQUITY (DEFICIT)

	Class A2 Preferred Stock				Common Stock				Accumulated
	Shares		Amount		Shares		Amount		Deficit			Total
Balances, January 1, 2015		-	$	-		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 of debt with a related party		90		900,000		-		-		-			900,000
Net loss		-		-		-		-		(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
Issuance of stock for services		-		-		316,667		25,334		-			25,334
Issuance of shares related to notes payable (See Note 6)		-		-		62,500		7,500		-			7,500
Issuance of series A2 preferred stock		5		50,000		-		-		-			50,000
Preferred stock dividends		-		-		-		-		(191,961	)		(191,961	)
Net loss		-		-		-		-		(4,499,045	)		(4,499,045	)
Balances, December 31, 2016		272	$	2,720,000		14,674,580	$	21,535,469	$	(25,556,601	)	$	(1,301,132	)

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

F-7

ARÊTE INDUSTRIES, INC.
STATEMENTS OF CASH FLOWS
	December 31,
	2016			2015
Cash Flows from Operating Activities:
Net loss	$	(4,499,045	)	$	(4,747,053	)
Adjustments to reconcile net loss to net cash used in
operating activities:
Depreciation, depletion and amortization		439,000			790,896
Accretion of discount on asset retirement obligations		94,333			70,375
Amortization of loan servicing fees		1,875			-
Gain on sale of oil and gas properties		-			(27,120	)
Additional acquisition cost realized on settlement with related party		-			141,099
Common stock issued in exchange for services		25,334			85,048
Impairment expense		3,358,000			3,287,648
Changes in operating assets and liabilities:
Accounts receivable		(11,475	)		132,041
Prepaid expenses and other		29,522			1,668
Accounts payable:
Trade accounts payable		68,447			21,531
Accounts payable - DNR Oil & Gas, Inc.		(47,842	)		161,952
Accounts payable - directors and affiliates		77,616			(20,000	)
Settlement of Asset Retirement Obligation		(4,530	)		(28,684	)
Other accrued expenses and accrued interest		5,015			33,709
Net cash used in operating activities		(463,750	)		(96,890	)
Cash Flows from Investing Activities:
Capital expenditures for property and equipment		(249	)		(68,631	)
Capital expenditures for acquisitions of oil and gas properties		-			(1,100,000	)
Proceeds from sale of oil & gas properties		-			50,000
Net cash used in investing activities		(249	)		(1,118,631	)
Cash Flows from Financing Activities:
Proceeds from notes payable		250,500			67,000
Principal payments on notes payable		(147,826	)		(25,568	)
Proceeds received from subscription receivable		105,000			-
Preferred stock dividends paid		(143,971	)		-
Proceeds received from issuance of Series A2 Preferred Stock		50,000			1,665,000
Net cash provided by financing activities		113,703			1,706,432
Net increase (decrease) in cash and equivalents		(350,296	)		490,911
Cash and equivalents, beginning of period		521,666			30,755
Cash and equivalents, end of period	$	171,370		$	521,666
Supplemental Disclosure of Cash Flow Information:
Cash paid for interest	$	84,395		$	83,136
Accrued dividends	$	47,990		$	-
Series A2 preferred stock issued for debt settlement – related party	$	-		$	900,000
Common stock issued for director fees payable	$	-		$	20,900
Common stock issued for loan closing costs	$	7,500		$	-
Common stock issued for asset purchase	$	-		$	100,000

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

F-8

ARÊTE INDUSTRIES, INC.

NOTES TO FINANCIAL STATEMENTS

For the Years Ended December 31, 2016 and 2015

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 focuses on acquiring interests in traditional exploratory and development oil and gas ventures, and seeks 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

Going Concern

The accompanying financial statements have been prepared on a going concern basis of accounting, which contemplates continuity of operations, realization of assets and liabilities and commitments in the normal course of business. The accompanying financial statements do not reflect any adjustments that might result if the Company is unable to continue as a going concern. The Company does not generate adequate revenue to satisfy its current operations, has negative cash flows from operations, and incurred significant net operating losses during the years ended December 31, 2016 and 2015, which raise substantial doubt about the Company's ability to continue as a going concern. The ability of the Company to continue as a going concern and appropriateness of using the going concern basis is dependent upon, among other things, additional cash infusion. The Company has historically obtained funds through private placement offerings of equity and debt, as well as, asset sales. There is no assurance that the Company will be able to continue raising the required capital.

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.

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

F-9

Cash and 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. During the year ending December 31, 2015, the Company wrote this asset off by recording an impairment charge against the gas gathering system of $56,648.  Depreciation of furniture and equipment is computed using the straight-line method over an estimated useful life of five years. As of December 31, 2016 and 2015, furniture and equipment was fully depreciated.  During the year ended December 31, 2016 and 2015, the Company recorded $0 and $428, respectively in depreciation expense.

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.

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 or future plans to develop acreage.

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. The Company recorded impairment charges against its oil and gas properties in the amount of $3,358,000 and $3,231,000 at December 31, 2016 and 2015, respectively.

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.

F-10

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 Statements of Operations. See Note 9 – Asset Retirement Obligations.

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, 2016 and 2015 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, 2016 and 2015, 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, 2016 and 2015 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 2016 and 2015. 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 financial statements in amounts which approximate fair value because of the short-term maturity of these instruments.

F-11

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, 2016, the Company did not have any uninsured cash balances.  The Company received 90% and 82% of its oil and gas production revenue from one purchaser during fiscal years ended December 31, 2016 and 2015, 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, 2016, the convertible preferred stock had an aggregate liquidation preference of $2,767,991 and was convertible to 1,383,995 shares of common stock. These shares were excluded from the earnings per share calculation because they would be anti-dilutive due to the Company's net loss.

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

	Year ended December 31,
	2016			2015
Net loss available to Arête Industries, Inc.	$	(4,499,045	)	$	(4,747,053	)
Less: Preferred stock dividends		(191,961	)		-
Net loss available to common shareholders'	$	(4,691,006	)	$	(4,747,053	)
Weighted average common shares outstanding – Basic		14,528,345			12,882,000
Add: Dilutive effect of stock options		-			-
Add: Dilutive effect of preferred stock		-			-
Weighted average common shares outstanding – Diluted		14,528,345			12,882,000
Net loss per common share:
Basic	$	(0.32	)	$	(0.37	)
Diluted	$	(0.32	)	$	(0.37	)

New Accounting Pronouncements

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 financial statements and disclosures.

F-12

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 February 2016, FASB issued ASU 2016-02, "Leases." ASU 2016-02 requires the recognition of lease assets and lease liabilities by lessees for those leases currently classified as operating leases and makes certain changes to the way lease expenses are accounted for. This update is effective for fiscal years beginning after December 15, 2018 and for interim periods beginning the following year. This update should be applied using a modified retrospective approach, and early adoption is permitted. The Company is evaluating the new guidance and has not determined the impact this standard may have on its financial statements.

In November 2016, the FASB issued ASU 2016-18, "Statement of Cash Flows: Restricted Cash" to address diversity in practice in the classification and presentation of changes in restricted cash. The accounting update requires that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, amounts generally described as restricted cash or restricted cash equivalents should be included with cash and cash equivalents when reconciling beginning-of-period and end-of-period amounts shown on the statement of cash flows. The guidance is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years, with early adoption permitted. This is an expansive set of revisions to the cash flow presentation standards, but at this time we do not believe that these changes will impact our financial statements.

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 7 – 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 Company 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 an alleged amount of $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 6 below.  During the year ended December 31, 2015, 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.

F-13

4. Oil and Gas Properties

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

	December31,
	2016			2015
Proved oil and gas properties at cost, net of impairment	$	5,325,381		$	8,683,273
Unevaluated oil and gas properties at cost, net of impairment		154,977			154,836
Accumulated depreciation, depletion and amortization		(3,662,000	)		(3,223,000	)
Oil and gas properties, net	$	1,818,358		$	5,615,109

During the years ended December 31, 2016 and 2015, the Company recorded depletion expense of $439,000 and $746,104, respectively. The Company recorded impairment expense of $3,358,000 and $3,231,000 against proved and unevaluated oil and gas properties at December 31, 2016 and 2015, respectively.

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 maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available. 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). 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. The lowest level of any input that is significant to the fair value measurement determines the applicable level in the fair value hierarchy. The three levels of the fair value hierarchy 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.

- Level 3 – Unobservable inputs that are supported by little or no market activity, generally requiring a significant amount of judgment by management.

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.

The Company does not have any liabilities that are measured at fair value on a recurring or nonrecurring basis as of December 31, 2016 or 2015.  The Company does not have any assets that are measured at fair value on a recurring basis.  The following table represents the Company's assets that are measured at fair value on a nonrecurring basis in the accompanying balance sheets, and where they are classified within the fair value hierarchy as of December 31, 2016:

	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other  Observable Inputs (Level 2)		Significant  Unobservable Inputs (Level 3)
Proved oil and gas properties at cost, net of impairment		-		-	$	1,377,260

F-14

The following table represents the Company's assets that are measured at fair value on a nonrecurring basis in the accompanying balance sheets, and where they are classified within the fair value hierarchy as of December 31, 2015:

	Level 1		Level 2		Level 3
Proved oil and gas properties at cost, net of impairment		-		-	$	5,460,273
Unevaluated oil and gas properties at cost, net of impairment		-		-	$	-

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, at a risk-adjusted discount rate of 10%.

The carrying amounts of other financial instruments including cash and cash equivalents, accounts receivable, accounts payable, and accrued liabilities approximate fair value because of the short-term nature of these instruments as of December 31, 2016 and December 31, 2015.

6. Stockholders' Equity (Deficit)

Common Stock

On May 11, 2016, the Company issued 316,667 shares of restricted common stock at $0.08 per share to its Chief Financial Officer as compensation for services performed from January 1 through May 31, 2016.

On June 29, 2016, the Company issued 30,000 shares of restricted common stock as a loan closing cost related to one of its notes payable valued at $3,600 (see Note 7 – Notes and advances payable).

On July 1, 2016, the Company issued 20,000 shares of restricted common stock as a loan closing cost related to one of its notes payable valued at $2,400 (see Note 7 – Notes and advances payable).

On July 5, 2016, the Company issued 12,500 shares of restricted common stock as a loan closing cost related to one of its notes payable valued at $1,500 (see Note 7 – Notes and advances payable).

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.

During the year ended December 31, 2015, 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 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, 2016, the Company had $2,720,000 (272 shares) outstanding. In 2016 5 shares ($50,000) were sold for cash. In 2015, 177 shares ($1,770,000) were sold for cash and 90 shares ($900,000) were issued to DNR as part of the consideration for a settlement entered into with DNR during the year ended December 31, 2015.

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.

F-15

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 our common stock but it is junior to our 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 our 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 our assets may be made to or set aside for the holders of any of our junior capital stock and subject to the rights of our 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 our property or business is not deemed to be a liquidation for purposes of the preceding sentence.

Redemption. The Series A2 Preferred Stock is redeemable in whole or in part at our 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 our 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 prior to the mandatory conversion of the Series A2 Preferred Stock.

F-16

7. Notes and advances payable

Notes payable consist of the following as of the date indicated:

	December 31, 2016		December 31, 2015
Officers, directors and affiliates:
Note payable, interest 7.0%, due January 2019 (1)		30,546		43,803
Collateralized note payable (2)		120,728		120,728
Total officers, directors and affiliates		151,274		164,531
Less: Current portion of officers, directors, and affiliates		134,839		13,152
Long-term portion of officers, directors, and affiliates	$	16,435	$	151,379
Unrelated parties:
Notes payable, interest at 7.5%, due March 2018 (3)	$	100,000	$	100,000
Notes payable, interest at 7.0%, due January 2017 (4)		22,737		32,607
Note payable, due March 2018 (5)		150,000		150,000
Note payable, due January 2019 (6)		13,566		19,660
Note payable, interest variable (see below) due June 2018 (7)		523,000		616,105
Note payable, interest at 7.0%, due August 2016 (8)		62,000		62,000
Notes payable, interest at 7.0%, due June 2018 (9)		183,000		183,000
Notes payable, net of discount, interest at 7.0%, due June 2018 (10)		97,300		-
Notes payable, net of discount, interest at 7.0%, due June 2018 (11)		98,200		-
Notes payable, net of discount, interest at 7.0%, due June 2018 (12)		23,875		-
Total unrelated parties		1,273,678		1,163,372
Less: Current portion of unrelated parties		240,750		989,853
Long-term portion of unrelated parties	$	1,032,928	$	173,519

(1) In January 2014, we memorialized certain short-term liabilities owed to one of our directors, Charlie Davis, into a formal promissory note. This note accrues interest at an annual rate of 7.0% with monthly payments equal to $1,316 (principal and interest) and will mature on January 1, 2019.

(2) 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 $120,728, with interest accruing at an annual rate of 7.5%, with principal and interest due on 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 asset 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 paid a loan fee to Apex 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 Company obtained a default waiver from Apex related to the new notes entered into through December 31, 2016. The Company has not had operating income or had any lease or well sales in the current fiscal year; therefore, no payments have been made to Apex through December 31, 2016.

(3) On March 28, 2012, the Company executed a promissory note with Pikerni, LLC ("Pikerni"). This note was extended and amended on April 1, 2015,extending the maturity date of the note to 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. The note accrues interest at an annual rate of 7.5% and is payable quarterly. The Company did not make any of the principal payments and was in default on this note, however, in January 2016 the Company entered into an extension agreement with Pikerni, with an effective date of June 15, 2016. The principal amount of $100,000 was extended to March 30, 2018, with interest continuing to accrue at an annual rate of 7.5% and interest payments continuing to be paid in 90-day intervals.

(4) On January 1, 2014, the Company executed a promissory note with William Stewart, one of the Company's board members, subsequently assigned to Pikerni, LLC, for $49,500. This note accrues interest at a rate of 7.0% per annum with monthly payments equal to $980 (principal and interest) and matures on January 1, 2017. The monthly payments are based on a 60 month amortization schedule, with a balloon payment of $22,737 due on January 1, 2017. The balloon payment was not made at January 1, 2017, and this note is currently in default. The Company has continued making the monthly payments of $980 and is negotiating new terms. The principal balance is classified in current notes payable on the balance sheet at December 31, 2016.

F-17

(5) On March 28, 2012, the Company executed a Promissory Note with Fairfield Management Group, LLC, subsequently assigned to Donald Prosser (former CFO and Director) ("Prosser") during the fiscal year ended December 31, 2015. The note has a principal balance of $150,000, accrues interest at 7.5% payable monthly and had a maturity date of March 31, 2016, which was subsequently extended to March 31, 2017 and extended again on May 3, 2017 to March 30, 2018.

(6) On December 31, 2013, the Company executed a promissory note with Mr. Prosser for $28,500. This note accrues interest at a rate of 7.0% with monthly payments equal to $564 (principal and interest) and matures on January 1, 2019.

(7) On January 28, 2014, we entered into a line of credit loan agreement ("Credit Facility") with Citywide Banks ("Citywide") for $1,500,000 due January 15, 2015, subsequently extended to June 28, 2018. 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 plus an add on index with the current and minimum rate of 6.5%, the note has draw provisions and is collateralized by the 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. At December 31, 2016, the borrowing base was $523,000. 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. At December 31, 2016, the Company was in compliance with all of the covenants. 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. On January 1, 2017, the Company failed to make the principal payment due to Pikerni, LLC, and was in default on that note. The Company received a waiver from Citywide.

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

b. A payment of $31,000, plus accrued and unpaid interest was payable on August 15, 2016

The Company did not make the August 15, 2015, or August 15, 2016, principal payment and is currently in default on this note. The Company is negotiating new terms with the note holder.

(9) In June 2013, in connection with the conversions of Series A-1 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 in writing with the holders of these two existing notes to extend the maturity date of the notes to June 18, 2018.

F-18

(10) On June 29, 2016, the Company entered into a promissory note with an unrelated party and received $100,000 and issued 30,000 shares of the Company's restricted common stock, valued at $3,600, as a loan servicing fee. This note accrues interest at the rate of 7.0% per annum with interest paid quarterly in arrears and all principal and interest due on June 29, 2018. In the event of a default, the loan will become due immediately and a default interest rate of 18.0% per year will be assessed on all amounts outstanding until paid in full. An event of default only occurs if any payment required by this note is not paid. All payments have been made on this note through the filing of this report. The loan servicing fee will be amortized over the life of the loan.

(11) On June 30, 2016, the Company entered into a promissory note with an unrelated party for $100,000 and the issuance of 20,000 shares of the Company's restricted common stock, valued at $2,400, as a loan servicing fee. This note accrues interest at the rate of 7.0% per annum with interest paid quarterly in arrears and all principal and interest due on June 30, 2018. In the event of a default, the loan will become due immediately and a default interest rate of 18.0% per year will be assessed on all amounts outstanding until paid in full. An event of default only occurs if any payment required by this note is not paid. The proceeds for this note were received on July 1, 2016, upon formal closing of the transaction. The loan servicing fee will be amortized over the life of the loan.

(12) On June 30, 2016, the Company entered into a promissory note with an unrelated party for $25,000 and the issuance of 12,500 shares of the Company's restricted common stock, valued at $1,500, as a loan servicing fee. This note accrues interest at the rate of 7.0% per annum with interest paid quarterly in arrears and all principal and interest due on June 29, 2018. In the event of a default, the loan will become due immediately and a default interest rate of 18.0% per year will be assessed on all amounts outstanding until paid in full. An event of default only occurs if any payment required by this note is not paid. The proceeds from this note were received on July 5, 2016, upon formal closing of the transaction. The loan servicing fee will be amortized over the life of the loan.

 8. Income Taxes

At December 31, 2016, the Company has net operating loss ("NOL") carryforwards for Federal income tax purposes of approximately $10,214,000. If not previously utilized, the NOL carryforwards will expire in 2018 through 2036.

For the years ended December 31, 2016 and 2015, 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, 2016 and 2015 differs from the amounts computed using the federal statutory tax rate of 34%, as follows:

	2016			2015
Income tax benefit (expense) at the statutory rate	$	1,530,000		$	1,614,000
Benefit (expense) resulting from:
Increase in Federal valuation allowance		(1,530,000	)		(1,884,000	)
Other permanent differences		-			270,000
Utilization of net operating loss carryforwards		-			-
Income tax benefit (expense)	$	-		$	-

At December 31, 2016 and 2015, the tax effects of temporary differences that give rise to significant deferred tax assets and liabilities are presented below:

	2016			2015
Federal net operating loss carryforwards	$	3,473,000		$	3,030,000
State net operating loss carryforwards		358,000			315,000
Oil and gas properties		1,927,000			917,000
Asset retirement obligations		405,000			371,000
Net deferred tax assets		6,163,000			4,633,000
Less valuation allowance		(6,163,000	)		(4,633,000	)
Net deferred tax assets	$	—		$	—

The Company has not maintained a tax basis property roll-forward and has not filed tax returns since 2011 and therefore, the tax assets disclosed above are management's best estimate and this estimate could change as the company completes it tax returns. 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, 2016 and 2015.

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, 2016 and 2015, 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 2011 through 2016 remain open to examination by these taxing jurisdictions.

F-19

9. 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, 2016 and 2015 is as follows:

	2016			2015
Balance, beginning of year	$	995,197		$	749,013
Liabilities incurred upon acquisition of properties		-			204,493
Liabilities settled		(4,530	)		(28,684	)
Accretion expense		94,333			70,375
Balance, end of year		1,085,000			995,197
Less: current asset retirement obligations		(425,200	)		(409,621	)
Long-term asset retirement obligations	$	659,800		$	585,576

10. 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 2016 and 2015 was $0 and $1,400, which is included in gas gathering operating costs. The Company does not have any operating leases in place as of December 31, 2016.

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. On September 30, 2016 plaintiff Eric Langan et al. filed a complaint in Maricopa County Superior Court for common law fraud under Arizona law against Arête Industries, Inc., Don and Jane Doe Prosser, and Charles and Jane Doe Davis. The action was removed to federal court on November 17, 2016, civil action number 16 – 03994 – PHX – SPL. On September 1, 2017 a judgment was entered in favor of the defendants and against plaintiffs in the case was dismissed in its entirety for lack of personal jurisdiction.

As of December 31, 2016, 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.

11. Subsequent Events

The following are the subsequent events:

On September 11, 2017, we entered into an Offer to Purchase Letter  with Marc VenJohn (the "Offer Letter") for a 25% working interest in two of the Company's oil and gas assets located in Clark County, Kansas for total consideration of $150,000 and an effective date of October 1, 2017. On November 15, 2017, the Company completed the sale under a purchase and sale agreement, with an effective date of October 1, 2017 (the "VenJohn PSA"), with Marc VenJohn.

F-20

12. 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, 2016 and 2015:

	2016		2015
Acquisition costs:
Unproved properties	$	-	$	-
Proved properties		-		1,404,493
Exploration costs		-		-
Development costs		-		115,992
Revisions to asset retirement obligation		-		-
Total costs incurred	$	-	$	1,520,485
Depletion per BOE of production	$	17.56	$	27.78

Supplemental Oil and Gas Reserve Information

The reserve information presented below is based on estimates of net proved reserves as of December 31, 2016 and 2015 that were prepared by Pinnacle Energy Services, L.L.C. the Company's independent petroleum engineering firm, 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 oil and gas reserve quantities for the years ended December 31:

	Oil (Bbl)			Gas (Mcf)			Equivalent (BOE)
Balance, January 1, 2015		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
Sale of oil and gas reserves in place		-			-			-
Acquisition of reserves in place		-			-			-
Revisions in previous estimates (1)		(105,804	)		(196,533	)		(138,562	)
Production		(23,386	)		(41,937	)		(30,376	)
Balance, December 31, 2016		146,030			119,770			165,990
Proved reserves, December 31, 2015:
Proved developed		275,220			358,240			334,928
Proved undeveloped		-			-			-
Proved reserves, December 31, 2016:
Proved developed		146,030			119,770			165,990
Proved undeveloped		-			-			-

(1) The primary reason for the revision in previous estimates is due to the higher lease operating expenses incurred, which made several of the wells uneconomic sooner than the prior year.

F-21

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, 2016, 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 2016, which resulted in benchmark prices of $42.75 per barrel for crude oil, West Texas Intermediate ("WTI") and $2.49 per MMbtu for natural gas, Henry Hub. Prices were further adjusted for transportation, quality and basis differentials, which resulted in a difference from the benchmark prices ranging from -$2.97 per barrel to -$10.77 per barrel, depending on the location of the wells. One well that produces from the Minnelusa formation has an oil differential of -$26.67 per barrel. The calculated natural gas differentials ranged from -74% 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, 2016 and 2015:

	2016			2015
Future cash inflows	$	5,751,250		$	13,002,030
Future production costs		(4,322,870	)		(7,976,560	)
Future development costs		-
Future income taxes		-
Future net cash flows		1,428,380			5,025,470
10% annual discount		(545,640	)		(2,472,800	)
Standardized measure of discounted future net cash flows	$	882,740		$	2,552,670

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.

F-22

A summary of changes in the standardized measure of discounted future net cash flows is as follows for the years ended December 31, 2016 and 2015:

	2016			2015
Standardized measure of discounted future net cash flows, beginning of year	$	2,552,670		$	5,989,127
Sales of oil and gas, net of production costs and taxes		(224,105	)		23,891
Purchases of reserves in place		-			589,190
Sales of reserves in place		-			—
Changes in development costs		-			(699,000	)
Revisions of previous estimates		(802,699	)		(440,871	)
Changes in prices and production costs		(898,393	)		(4,661,912	)
Net changes in income taxes		-			1,153,332
Accretion of discount		255,267			598,913
Standardized measure of discounted future net cash flows, end of year	$	882,740		$	2,552,670

F-23

EX-31.1

Exhibit 31.1

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER

PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Nicholas L. Scheidt, certify that:

1. I have reviewed this annual report on Form 10-K of Arête Industries, Inc.

2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;

3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;

4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the small business issuer and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including any consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

(c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Dated: November 30, 2017	By:	/s/ Nicholas L. Scheidt
	Nicholas L. Scheidt, Principal Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION OF PRINCIPAL ACCOUNTING OFFICER

PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Tristan R. Farel, certify that:

1. I have reviewed this annual report on Form 10-K of Arête Industries, Inc.

2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;

3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;

4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including any consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

(c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Dated: November 30, 2017	By:	/s/ Tristan R. Farel
	Tristan R. Farel, Chief Financial Officer, Principal Financial and Accounting Officer

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Arête Industries, Inc. (the "Company") on Form 10-K for the fiscal year ended December 31, 2016, as filed with the Securities and Exchange Commission on the date hereof (the "Report"), I, Nicholas L. Scheidt, Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Company.

Dated: November 30, 2017	By:	/s/ Nicholas L. Scheidt
	Nicholas L. Scheidt, Principal Executive Officer, Chief Executive Officer

EX-32.2

EXHIBIT 32.2

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Arête Industries, Inc. (the "Company") on Form 10-K for the fiscal year ended December 31, 2016, as filed with the Securities and Exchange Commission on the date hereof (the "Report"), I, Tristan R. Farel, Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Company.

Dated: November 30, 2017	By:	/s/ Tristan R. Farel
	Tristan R. Farel, Chief Financial Officer, Principal Financial Officer

EX-99.1

Exhibit 99.1

Arete Industries, Inc.

Year-End 2016 Reserve Report

SEC Pricing

Prepared by:

Richard J. Morrow, PE

Pinnacle Energy Services, LLC

9420 Cedar Lake Ave

Oklahoma City, Oklahoma 73114

May 15, 2017

Arete Industries, Inc.

1410 High Street

Denver, CO  80218

Attn: Mr. Tristan Farel

Re:  Reserve and Economic Evaluation Arete Industries, Inc. Year-End 2016 SEC Pricing

Executive Summary

Pinnacle Energy Services, LLC ("Pinnacle") has performed a reserve and economic evaluation on certain oil and gas assets of Arete Industries, Inc. ("Arete") as of December 31, 2016.  Well names, owned interests, and other well information are provided on the attached Exhibit A. Information used in the evaluation was provided by Arete and supplemented by data gathered from public sources.  Summary results of this analysis are located below and details are presented in accompanying exhibits.

This evaluation was performed using SEC reserve standards and SEC year-end pricing, and includes fifty-one (51) Proved Developed Producing (PDP) properties and twenty (20) Proved Shut-In (PSI) properties.

As presented in the accompanying summary projections, the net reserves and future net cash flows as of January 1, 2017 are as follows (Volumes in MBBLs and MMcf, Values in M$):

	Number of		Net Reserves						Net		Net		NPV
Reserve Class	Properties		Oil		Gas		NGL		Capital		Cashflow		Disc @ 10%
			MBBL		MMCF		MBBL		M$		M$		M$
PDP		51		146		120		0		$0		$1,428		$883
PSI		20		0		0		0		$0		$0		$0
Total Proved		71		146		120		0		$0		$1,428		$883

Pricing

Per SEC rules as of January 1, 2010, the SEC pricing is calculated by averaging the first-of-the-month oil and gas pricing for the calendar year being evaluated.  For 2016, the average oil and gas prices were $42.75/BBL for oil (WTI) and $2.49/MMBTU for natural gas (Henry Hub).  Both prices were held constant.

Pinnacle Energy Services, LLC

9420 Cedar Lake Ave, Oklahoma City, OK 73114

Ofc: 405-810-9151 Fax: 405-843-4700                www.PinnacleEnergy.com

Based on an evaluation of actual oil prices received by Arete in 2016, differentials to NYMEX prices were applied to each lease. The calculated oil price differentials ranged from -$2.97/bbl to

-$10.77/bbl. One well, the Neil Federal 14, that produces from the Minnelusa has an oil differential of -$26.67/bbl.

Based on an evaluation of actual gas prices received by Arete in 2016, differentials to NYMEX prices were applied to each lease. The calculated gas price differentials ranged from -74% to +59%.

Interests

Interest information was provided by Arete for each property or lease. These interests are shown on the attached Exhibit A.

Taxes

Oil and gas severance tax rates vary by state, and were calculated based on the lease operating statements provided by Arete.

Expenses

Average monthly operating expenses for each property were calculated based on the 2016 expense data provided by Arete.

Property Descriptions and Reserve Estimates

Fifty-one (51) properties were on production as of December 31, 2016. Remaining reserves for these properties were determined by decline curve analysis and analogy. Production plots for each property showing historical production and forecasts are included in the attachments.

Twenty (20) properties had previously produced but are now shut-in.

Reserves

Remaining recoverable reserves are those quantities of petroleum that are anticipated to be commercially recovered from known accumulations from a given date forward.  All reserve estimates involve some degree of uncertainty depending primarily on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data.  The relative degree of uncertainty is conveyed by classifying reserves as Proved (highly certain) or Non-Proved (less certain).  The estimated reserves and revenues shown in this report were determined for Proved Developed Producing (PDP) and Proved Shut-In (PSI) reserve categories. By definition, PDP refers to existing producing properties.

Pinnacle Energy Services, LLC

9420 Cedar Lake Ave, Oklahoma City, OK 73114

Ofc: 405-810-9151 Fax: 405-843-4700                www.PinnacleEnergy.com

Accuracy of production forecasts generally depends on the amount of historical production and pressure data available, and the majority the producing wells reviewed in this evaluation had sufficient historical data to forecast future production with confidence.  Those with limited production or pressure data history were forecasted by reviewing analogy well and test data and applying this knowledge to the available well information.

Future Cashflow

Future cash flow being reported is after deducting state production taxes and ad valorem taxes, but prior to deducting federal income taxes.  The future net cash flow has been discounted at an annual rate of 10 percent to determine its present worth.  The present worth is shown to indicate the effect of time on the value of money and should not be construed as being the fair market value of the properties.

General

The reserves and values included in this report are estimates only and should not be construed as being exact quantities. The reserve estimates were arrived at by using accepted engineering practices and were primarily based on historical rate decline analysis for existing producers.  As additional pressure and production performance data becomes available, reserve estimates may increase or decrease in the future. The revenue from such reserves and the actual costs related may be more or less than the estimated amounts. Because of governmental policies and uncertainties of supply and demand, the prices actually received for the reserves included in this report and the costs incurred in recovering such reserves may vary from the price and cost assumptions referenced. Therefore, in all cases, estimates of reserves may increase or decrease as a result of future operations.

In evaluating the information available for this analysis, items excluded from consideration were all mattersas to which legal or accounting, rather than engineering interpretation, may be controlling. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering data and such conclusions necessarily represent only informed professional judgments.  The titles to the properties have not been examined nor has the actual degree or type of interest owned been independently confirmed.  A field inspection of the properties is not usually considered necessary for the purpose of this report.

Information included in this report includes the graphical decline curves for individual wells, projected production and cash flow economic results, one-line economic result summaries for each well, and miscellaneous individual well information.  Additional information reviewed will be retained and is available for review at any time.  Pinnacle Energy Services, L.L.C. can take no responsibility for the accuracy of the data used in the analysis, whether gathered from public sources or otherwise.

Pinnacle Energy Services, LLC

9420 Cedar Lake Ave, Oklahoma City, OK 73114

Ofc: 405-810-9151 Fax: 405-843-4700                www.PinnacleEnergy.com

Pinnacle Energy Services, LLC

{original signed by Richard J. Morrow}

Richard J. Morrow, P.E.

Petroleum Engineer

Disclaimer:  Pinnacle Energy Services, L.L.C. nor any of its subsidiaries, affiliates, officers, directors, shareholders, employees, consultants, advisors, agents, or representatives make any representation or warranty, express or implied, in connection with any of the information made available herein, including, but not limited to, the past, present or future value of the anticipated reserves, cash flows, income, costs, expense, liabilities and profits, if any, to be derived from the properties described herein.  All statements, estimates, projections and implications as to future operations are based upon best judgments of Pinnacle Energy Services; however, there is no assurance that such statements, estimates, projections or implications will prove to be accurate.  Accordingly, any company, or other party receiving such information will rely solely upon its own independent examination and assessment of said information.  Neither Pinnacle Energy Services nor any of its subsidiaries, affiliates, officers, directors, shareholders, employees, consultants, advisors, agents, or representatives shall have any liability to any party receiving the information herein, nor to any affiliate, partner, member, officer, director, shareholder, employee, consultant, advisor, agent or representative of such party from any use of such information.  The property description and other information attached hereto are for the sole, confidential use of the person to whom this copy has been made available.  It may not be disseminated or reproduced in any matter whatsoever, whether in full or in part, without the prior written consent of Pinnacle Energy Services, L.L.C.  This evaluation and all descriptions and other information attached hereto are for information purposes only and do not constitute an evaluation of or offer to sell or a solicitation of an offer to buy any securities.

EXHIBIT A

Economic Summary

By Reserve Class and

Category

One-Line

Enonomic Report

PDP

Detailed Economic Report &

Decline Curves

XML

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2016	Nov. 30, 2017	Sep. 30, 2017
Document And Entity Information [Abstract]
Entity Registrant Name	ARETE INDUSTRIES INC
Entity Central Index Key	0000820901
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2016
Document Fiscal Year Focus	2016
Document Fiscal Period Focus	FY
Trading Symbol	ARET
Entity Filer Category	Smaller Reporting Company
Entity Common Stock, Shares Outstanding		14,674,580
Entity Public Float			$ 1,379,058

XML

BALANCE SHEETS - USD ($)	Dec. 31, 2016	Dec. 31, 2015
Current Assets:
Cash	$ 171,370	$ 521,666
Accounts receivable - oil and natural gas sales	14,014	2,539
Subscription receivable	0	105,000
Prepaid expenses and other	3,032	32,554
Total Current Assets	188,416	661,759
Oil and gas properties, at cost, successful efforts method:
Proved properties	5,325,381	8,683,273
Unevaluated properties	154,977	154,836
Furniture and equipment	22,522	22,522
Total property and equipment	5,502,880	8,860,631
Less accumulated depreciation, depletion and amortization	(3,684,522)	(3,245,522)
Net Property and Equipment	1,818,358	5,615,109
TOTAL ASSETS	2,006,774	6,276,868
Accounts payable:
Trade accounts payable	133,343	64,896
Accounts payable - DNR Oil & Gas, Inc.	453,439	501,281
Accounts payable - directors and affiliates	77,616	0
Dividends payable:
Dividends payable	5,998	0
Dividends payable - directors and affiliates	41,992	0
Accrued interest expense:
Accrued interest expense	23,821	2,532
Accrued interest expense - directors and affiliates	0	9,442
Notes and advances payable - current portion:
Notes and advances payable	240,750	989,853
Notes and advances payable - directors and affiliates	134,839	13,152
Current portion of asset retirement obligations	425,200	409,621
Other accrued costs and expenses	61,745	68,577
Total Current Liabilities	1,598,743	2,059,354
Notes and advances payable, net of current portion:
Notes and advances payable, net of discount	1,032,928	173,519
Notes and advances payable - Directors and affiliates	16,435	151,379
Asset retirement obligations, net of current portion	659,800	585,576
Total Long-Term Liabilities	1,709,163	910,474
Total Liabilities	3,307,906	2,969,828
Stockholders' Equity (Deficit):
Convertible Class A preferred stock; $10,000 face value per share, authorized 1,000,000 shares: Series 1; 30,000 shares authorized, none issued and outstanding. Series 2; authorized 2,500 shares, 272 and 267 shares issued and outstanding as of December 31, 2016 and 2015, respectively, liquidation preference $2,767,991.	2,720,000	2,670,000
Common stock, no par value; 499,000,000 shares authorized, 14,674,580 and 14,295,413 issued and outstanding as of December 31, 2016 and 2015, respectively.	21,535,469	21,502,635
Accumulated deficit	(25,556,601)	(20,865,595)
Total Stockholders' Equity (Deficit)	(1,301,132)	3,307,040
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)	2,006,774	6,276,868
Series A1 Preferred Stock [Member]
Stockholders' Equity (Deficit):
Convertible Class A preferred stock; $10,000 face value per share, authorized 1,000,000 shares: Series 1; 30,000 shares authorized, none issued and outstanding. Series 2; authorized 2,500 shares, 272 and 267 shares issued and outstanding as of December 31, 2016 and 2015, respectively, liquidation preference $2,767,991.	0	0
Series A2 Preferred Stock [Member]
Stockholders' Equity (Deficit):
Convertible Class A preferred stock; $10,000 face value per share, authorized 1,000,000 shares: Series 1; 30,000 shares authorized, none issued and outstanding. Series 2; authorized 2,500 shares, 272 and 267 shares issued and outstanding as of December 31, 2016 and 2015, respectively, liquidation preference $2,767,991.	$ 2,720,000	$ 2,670,000

XML

BALANCE SHEETS (Parenthetical) - USD ($)	Dec. 31, 2016	Dec. 31, 2015
Convertible preferred stock, face value	$ 10,000	$ 10,000
Convertible preferred stock, shares authorized	1,000,000	1,000,000
Common stock, par value	$ 0	$ 0
Common stock, shares authorized	499,000,000	499,000,000
Common stock, shares issued	14,674,580	14,295,413
Common stock, shares outstanding	14,674,580	14,295,413
Series A1 Preferred Stock [Member]
Convertible preferred stock, shares authorized	30,000	30,000
Convertible preferred stock, shares issued	0	0
Convertible preferred stock, shares outstanding	0	0
Series A2 Preferred Stock [Member]
Convertible preferred stock, shares authorized	2,500	2,500
Convertible preferred stock, shares issued	272	267
Convertible preferred stock, shares outstanding	272	267
Convertible preferred stock, liquidation preference	$ 2,767,991

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STATEMENTS OF OPERATIONS - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Revenues:
Oil sales	$ 889,285	$ 777,123
Natural gas sales	82,873	143,907
Royalty revenues	2,325	4,871
Sale of oil and natural gas properties	0	27,120
Total revenues	974,483	953,021
Oil and gas producing activities:
Lease operating expenses	1,064,427	754,362
Production taxes	76,715	84,576
Other operating expense	0	160,011
Depreciation, depletion, amortization and accretion	533,333	816,481
Impairment	3,358,000	3,231,000
Gas gathering:
Operating expenses	0	1,406
Depreciation	0	44,362
Impairment	0	56,648
General and administrative expenses:
Director fees	40,000	47,833
Investor relations	12,209	28,128
Legal, auditing and professional fees	183,683	116,078
Consulting fees executive services-Related Parties	66,732	172,217
Other administrative expenses	41,187	74,634
Depreciation	0	428
Total operating expenses	5,376,286	5,588,164
Operating loss	(4,401,803)	(4,635,143)
Other income (expense):
Other income	875	0
Interest expense net	(98,117)	(111,910)
Loss before income taxes	(4,499,045)	(4,747,053)
Income tax benefit (expense)	0	0
Net loss attributable to Arête Industries, Inc.	(4,499,045)	(4,747,053)
Net Loss Applicable to Common Stockholders:
Net loss attributable to Arête Industries, Inc.	(4,499,045)	(4,747,053)
Preferred stock dividends declared	(191,961)	0
Net loss applicable to common stockholders	$ (4,691,006)	$ (4,747,053)
Loss Per Share Applicable to Common Stockholders:
Basic	$ (0.32)	$ (0.37)
Diluted	$ (0.32)	$ (0.37)
Weighted Average Number of Common Shares Outstanding:
Basic	14,528,345	12,882,000
Diluted	14,528,345	12,882,000

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STATEMENTS OF STOCKHOLDERS' EQUITY (DEFICIT) - USD ($)	Class A2 Preferred Stock	Common Stock	Accumulated Deficit	Total
Beginning Balance at Dec. 31, 2014		$ 21,294,887	$ (16,118,542)	$ 5,176,345
Beginning Balance, in Shares at Dec. 31, 2014		12,558,459
Common Stock Issued for Services - Related Parties		$ 32,516		32,516
Common Stock Issued for Services - Related Parties, in Shares		206,666
Common Stock Issued for Directors Fees		$ 75,232		75,232
Common Stock Issued for Directors Fees, in Shares		530,288
Issuance of common stock for oil and gas acquisition		$ 100,000		$ 100,000
Issuance of common stock for oil and gas acquisition, in Shares		1,000,000		1,000,000
Issuance of Preferred stock Series A Two	$ 1,770,000			$ 1,770,000
Issuance of Preferred stock Series A Two, in Shares	177
Preferred stock issued for settlement with a related party	$ 900,000			900,000
Preferred stock issued for settlement with a related party, in Shares	90
Net loss			(4,747,053)	(4,747,053)
Ending Balance at Dec. 31, 2015	$ 2,670,000	$ 21,502,635	(20,865,595)	3,307,040
Ending Balance, in Shares at Dec. 31, 2015	267	14,295,413
Common Stock Issued for Services - Related Parties		$ 25,334		25,334
Common Stock Issued for Services - Related Parties, in Shares		316,667
Issuance of shares related to notes payable		$ 7,500		7,500
Issuance of shares related to notes payable, in Shares		62,500
Issuance of Preferred stock Series A Two	$ 50,000			50,000
Issuance of Preferred stock Series A Two, in Shares	5
Preferred stock issued for settlement with a related party				0
Preferred stock dividends			(191,961)	(191,961)
Net loss			(4,499,045)	(4,499,045)
Ending Balance at Dec. 31, 2016	$ 2,720,000	$ 21,535,469	$ (25,556,601)	$ (1,301,132)
Ending Balance, in Shares at Dec. 31, 2016	272	14,674,580

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STATEMENTS OF CASH FLOWS - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Cash Flows from Operating Activities:
Net loss	$ (4,499,045)	$ (4,747,053)
Adjustments to reconcile net loss to net cash used in operating activities:
Depreciation, depletion and amortization	439,000	790,896
Accretion of discount on asset retirement obligations	94,333	70,375
Amortization of loan servicing fees	1,875	0
Gain on sale of oil and gas properties	0	(27,120)
Impairment expense	0	141,099
Additional acquisition expense realized on settlement with a related party	25,334	85,048
Common stock issued in exchange for services	3,358,000	3,287,648
Changes in operating assets and liabilities:
Accounts receivable	(11,475)	132,041
Prepaid expenses and other	29,522	1,668
Accounts payable:
Trade accounts payable	68,447	21,531
Accounts payable - DNR Oil & Gas, Inc.	(47,842)	161,952
Accounts payable - directors and affiliates	77,616	(20,000)
Settlement of Asset Retirement Obligation	(4,530)	(28,684)
Other accrued expenses and accrued interest	5,015	33,709
Net cash provided by operating activities	(463,750)	(96,890)
Cash Flows from Investing Activities:
Capital expenditures for property and equipment	(249)	(68,631)
Capital expenditures for acquisitions of oil and gas properties	0	(1,100,000)
Proceeds from sale of oil & gas properties	0	50,000
Net cash used in investing activities	(249)	(1,118,631)
Cash Flows from Financing Activities:
Proceeds from notes payable	250,500	67,000
Principal payments on notes payable	(147,826)	(25,568)
Proceeds received from subscription receivable	105,000	0
Preferred stock dividends paid	(143,971)	0
Proceeds received from issuance of Series A Two Preferred Stock	50,000	1,665,000
Net cash provided by financing activities	113,703	1,706,432
Net increase (decrease) in cash and equivalents	(350,296)	490,911
Cash and equivalents, beginning of period	521,666	30,755
Cash and equivalents, end of period	171,370	521,666
Supplemental Disclosure of Cash Flow Information:
Cash paid for interest	84,395	83,136
Accrued dividends	47,990	0
Series A preferred stock issued for debt settlement – related party	0	900,000
Common Stock issued for directors fees payable	0	20,900
Common stock issued for loan closing costs	7,500	0
Common stock issued for asset purchase	$ 0	$ 100,000

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Organization and Nature of Operations

12 Months Ended

Dec. 31, 2016

Organization And Nature Of Operations

Organization and Nature of Operations

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 focuses on acquiring interests in traditional exploratory and development oil and gas ventures, and seeks 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.

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Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2016

Summary Of Significant Accounting Policies

Summary of Significant Accounting Policies

 2. Summary of Significant Accounting Policies

Going Concern

The accompanying financial statements have been prepared on a going concern basis of accounting, which contemplates continuity of operations, realization of assets and liabilities and commitments in the normal course of business. The accompanying financial statements do not reflect any adjustments that might result if the Company is unable to continue as a going concern. The Company does not generate adequate revenue to satisfy its current operations, has negative cash flows from operations, and incurred significant net operating losses during the years ended December 31, 2016 and 2015, which raise substantial doubt about the Company's ability to continue as a going concern. The ability of the Company to continue as a going concern and appropriateness of using the going concern basis is dependent upon, among other things, additional cash infusion. The Company has historically obtained funds through private placement offerings of equity and debt, as well as, asset sales. There is no assurance that the Company will be able to continue raising the required capital.

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.

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

Cash and 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. During the year ending December 31, 2015, the Company wrote this asset off by recording an impairment charge against the gas gathering system of $56,648.  Depreciation of furniture and equipment is computed using the straight-line method over an estimated useful life of five years. As of December 31, 2016 and 2015, furniture and equipment was fully depreciated.  During the year ended December 31, 2016 and 2015, the Company recorded $0 and $428, respectively in depreciation expense.

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.

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 or future plans to develop acreage.

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. The Company recorded impairment charges against its oil and gas properties in the amount of $3,358,000 and $3,231,000 at December 31, 2016 and 2015, respectively.

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 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 Statements of Operations. See Note 9 – Asset Retirement Obligations.

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, 2016 and 2015 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, 2016 and 2015, 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, 2016 and 2015 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 2016 and 2015. 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 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, 2016, the Company did not have any uninsured cash balances.  The Company received 90% and 82% of its oil and gas production revenue from one purchaser during fiscal years ended December 31, 2016 and 2015, 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, 2016, the convertible preferred stock had an aggregate liquidation preference of $2,767,991 and was convertible to 1,383,995 shares of common stock. These shares were excluded from the earnings per share calculation because they would be anti-dilutive due to the Company's net loss.

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

	Year ended December 31,
	2016			2015
Net loss available to Arête Industries, Inc.	$	(4,499,045	)	$	(4,747,053	)
Less: Preferred stock dividends		(191,961	)		-
Net loss available to common shareholders'	$	(4,691,006	)	$	(4,747,053	)
Weighted average common shares outstanding – Basic		14,528,345			12,882,000
Add: Dilutive effect of stock options		-			-
Add: Dilutive effect of preferred stock		-			-
Weighted average common shares outstanding – Diluted		14,528,345			12,882,000
Net loss per common share:
Basic	$	(0.32	)	$	(0.37	)
Diluted	$	(0.32	)	$	(0.37	)

New Accounting Pronouncements

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 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 February 2016, FASB issued ASU 2016-02, "Leases." ASU 2016-02 requires the recognition of lease assets and lease liabilities by lessees for those leases currently classified as operating leases and makes certain changes to the way lease expenses are accounted for. This update is effective for fiscal years beginning after December 15, 2018 and for interim periods beginning the following year. This update should be applied using a modified retrospective approach, and early adoption is permitted. The Company is evaluating the new guidance and has not determined the impact this standard may have on its financial statements. 

In November 2016, the FASB issued ASU 2016-18, "Statement of Cash Flows: Restricted Cash" to address diversity in practice in the classification and presentation of changes in restricted cash. The accounting update requires that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, amounts generally described as restricted cash or restricted cash equivalents should be included with cash and cash equivalents when reconciling beginning-of-period and end-of-period amounts shown on the statement of cash flows. The guidance is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years, with early adoption permitted. This is an expansive set of revisions to the cash flow presentation standards, but at this time we do not believe that these changes will impact our financial statements.

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Acquisitions and Dispositions of Oil and Gas Properties

12 Months Ended

Dec. 31, 2016

Business Combinations [Abstract]

Acquisitions and Dispositions of Oil and Gas Properties

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 7 – 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 Company 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 an alleged amount of $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 6 below.  During the year ended December 31, 2015, 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.

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Oil and Gas Properties

12 Months Ended

Dec. 31, 2016

Extractive Industries [Abstract]

Oil and Gas Properties

4. Oil and Gas Properties

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

	December 31,
	2016			2015
Proved oil and gas properties at cost, net of impairment	$	5,325,381		$	8,683,273
Unevaluated oil and gas properties at cost, net of impairment		154,977			154,836
Accumulated depreciation, depletion and amortization		(3,662,000	)		(3,223,000	)
Oil and gas properties, net	$	1,818,358		$	5,615,109

During the years ended December 31, 2016 and 2015, the Company recorded depletion expense of $439,000 and $746,104, respectively. The Company recorded impairment expense of $3,358,000 and $3,231,000 against proved and unevaluated oil and gas properties at December 31, 2016 and 2015, respectively.

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Fair Value Measurements

12 Months Ended

Dec. 31, 2016

Fair Value Disclosures [Abstract]

Fair Value Measurements

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 maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available. 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). 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. The lowest level of any input that is significant to the fair value measurement determines the applicable level in the fair value hierarchy. The three levels of the fair value hierarchy 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.

- Level 3 – Unobservable inputs that are supported by little or no market activity, generally requiring a significant amount of judgment by management.

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.

The Company does not have any liabilities that are measured at fair value on a recurring or nonrecurring basis as of December 31, 2016 or 2015.  The Company does not have any assets that are measured at fair value on a recurring basis.  The following table represents the Company's assets that are measured at fair value on a nonrecurring basis in the accompanying balance sheets, and where they are classified within the fair value hierarchy as of December 31, 2016:

	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other  Observable Inputs (Level 2)		Significant  Unobservable Inputs (Level 3)
Proved oil and gas properties at cost, net of impairment		-		-	$	1,377,260

The following table represents the Company's assets that are measured at fair value on a nonrecurring basis in the accompanying balance sheets, and where they are classified within the fair value hierarchy as of December 31, 2015:

	Level 1		Level 2		Level 3
Proved oil and gas properties at cost, net of impairment		-		-	$	5,460,273
Unevaluated oil and gas properties at cost, net of impairment		-		-	$	-

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, at a risk-adjusted discount rate of 10%.

The carrying amounts of other financial instruments including cash and cash equivalents, accounts receivable, accounts payable, and accrued liabilities approximate fair value because of the short-term nature of these instruments as of December 31, 2016 and December 31, 2015.

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Stockholders' Equity

12 Months Ended

Dec. 31, 2016

Stockholders Equity

Stockholders' Equity

6. Stockholders' Equity (Deficit)

Common Stock

On May 11, 2016, the Company issued 316,667 shares of restricted common stock at $0.08 per share to its Chief Financial Officer as compensation for services performed from January 1 through May 31, 2016.

On June 29, 2016, the Company issued 30,000 shares of restricted common stock as a loan closing cost related to one of its notes payable valued at $3,600 (see Note 7 – Notes and advances payable).

On July 1, 2016, the Company issued 20,000 shares of restricted common stock as a loan closing cost related to one of its notes payable valued at $2,400 (see Note 7 – Notes and advances payable).

On July 5, 2016, the Company issued 12,500 shares of restricted common stock as a loan closing cost related to one of its notes payable valued at $1,500 (see Note 7 – Notes and advances payable).

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.

During the year ended December 31, 2015, 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 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, 2016, the Company had $2,720,000 (272 shares) outstanding. In 2016 5 shares ($50,000) were sold for cash. In 2015, 177 shares ($1,770,000) were sold for cash and 90 shares ($900,000) were issued to DNR as part of the consideration for a settlement entered into with DNR during the year ended December 31, 2015.

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 our common stock but it is junior to our 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 our 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 our assets may be made to or set aside for the holders of any of our junior capital stock and subject to the rights of our 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 our property or business is not deemed to be a liquidation for purposes of the preceding sentence.

Redemption. The Series A2 Preferred Stock is redeemable in whole or in part at our 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 our 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 prior to the mandatory conversion of the Series A2 Preferred Stock.

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Notes and advances payable

12 Months Ended

Dec. 31, 2016

Notes And Advances Payable

Notes and advances payable

7. Notes and advances payable

Notes payable consist of the following as of the date indicated:

	December 31, 2016		December 31, 2015
Officers, directors and affiliates:
Note payable, interest 7.0%, due January 2019 (1)		30,546		43,803
Collateralized note payable (2)		120,728		120,728
Total officers, directors and affiliates		151,274		164,531
Less: Current portion of officers, directors, and affiliates		134,839		13,152
Long-term portion of officers, directors, and affiliates	$	16,435	$	151,379
Unrelated parties:
Notes payable, interest at 7.5%, due March 2018 (3)	$	100,000	$	100,000
Notes payable, interest at 7.0%, due January 2017 (4)		22,737		32,607
Note payable, due March 2018 (5)		150,000		150,000
Note payable, due January 2019 (6)		13,566		19,660
Note payable, interest variable (see below) due June 2018 (7)		523,000		616,105
Note payable, interest at 7.0%, due August 2016 (8)		62,000		62,000
Notes payable, interest at 7.0%, due June 2018 (9)		183,000		183,000
Notes payable, net of discount, interest at 7.0%, due June 2018 (10)		97,300		-
Notes payable, net of discount, interest at 7.0%, due June 2018 (11)		98,200		-
Notes payable, net of discount, interest at 7.0%, due June 2018 (12)		23,875		-
Total unrelated parties		1,273,678		1,163,372
Less: Current portion of unrelated parties		240,750		989,853
Long-term portion of unrelated parties	$	1,032,928	$	173,519

(1)

In January 2014, we memorialized certain short-term liabilities owed to one of our directors, Charlie Davis, into a formal promissory note. This note accrues interest at an annual rate of 7.0% with monthly payments equal to $1,316 (principal and interest) and will mature on January 1, 2019.

(2)

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 $120,728, with interest accruing at an annual rate of 7.5%, with principal and interest due on 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 asset 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 paid a loan fee to Apex 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 Company obtained a default waiver from Apex related to the new notes entered into through December 31, 2016. The Company has not had operating income or had any lease or well sales in the current fiscal year; therefore, no payments have been made to Apex through December 31, 2016.

(3)

On March 28, 2012, the Company executed a promissory note with Pikerni, LLC ("Pikerni"). This note was extended and amended on April 1, 2015,extending the maturity date of the note to 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. The note accrues interest at an annual rate of 7.5% and is payable quarterly. The Company did not make any of the principal payments and was in default on this note, however, in January 2016 the Company entered into an extension agreement with Pikerni, with an effective date of June 15, 2016. The principal amount of $100,000 was extended to March 30, 2018, with interest continuing to accrue at an annual rate of 7.5% and interest payments continuing to be paid in 90-day intervals.

(4)

On January 1, 2014, the Company executed a promissory note with William Stewart, one of the Company's board members, subsequently assigned to Pikerni, LLC, for $49,500. This note accrues interest at a rate of 7.0% per annum with monthly payments equal to $980 (principal and interest) and matures on January 1, 2017. The monthly payments are based on a 60 month amortization schedule, with a balloon payment of $22,737 due on January 1, 2017. The balloon payment was not made at January 1, 2017, and this note is currently in default. The Company has continued making the monthly payments of $980 and is negotiating new terms. The principal balance is classified in current notes payable on the balance sheet at December 31, 2016.

(5) On March 28, 2012, the Company executed a Promissory Note with Fairfield Management Group, LLC, subsequently assigned to Donald Prosser (former CFO and Director) ("Prosser") during the fiscal year ended December 31, 2015. The note has a principal balance of $150,000, accrues interest at 7.5% payable monthly and had a maturity date of March 31, 2016, which was subsequently extended to March 31, 2017 and extended again on May 3, 2017 to March 30, 2018.

(6) On December 31, 2013, the Company executed a promissory note with Mr. Prosser for $28,500. This note accrues interest at a rate of 7.0% with monthly payments equal to $564 (principal and interest) and matures on January 1, 2019.

(7) On January 28, 2014, we entered into a line of credit loan agreement ("Credit Facility") with Citywide Banks ("Citywide") for $1,500,000 due January 15, 2015, subsequently extended to June 28, 2018. 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 plus an add on index with the current and minimum rate of 6.5%, the note has draw provisions and is collateralized by the 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. At December 31, 2016, the borrowing base was $523,000. 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. At December 31, 2016, the Company was in compliance with all of the covenants. 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. On January 1, 2017, the Company failed to make the principal payment due to Pikerni, LLC, and was in default on that note. The Company received a waiver from Citywide.

(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.	A payment of $31,000, plus accrued and unpaid interest was payable on August 15, 2015
		b.	A payment of $31,000, plus accrued and unpaid interest was payable on August 15, 2016

The Company did not make the August 15, 2015, or August 15, 2016, principal payment and is currently in default on this note. The Company is negotiating new terms with the note holder.

(9) In June 2013, in connection with the conversions of Series A-1 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 in writing with the holders of these two existing notes to extend the maturity date of the notes to June 18, 2018.

(10)

On June 29, 2016, the Company entered into a promissory note with an unrelated party and received $100,000 and issued 30,000 shares of the Company's restricted common stock, valued at $3,600, as a loan servicing fee. This note accrues interest at the rate of 7.0% per annum with interest paid quarterly in arrears and all principal and interest due on June 29, 2018. In the event of a default, the loan will become due immediately and a default interest rate of 18.0% per year will be assessed on all amounts outstanding until paid in full. An event of default only occurs if any payment required by this note is not paid. All payments have been made on this note through the filing of this report. The loan servicing fee will be amortized over the life of the loan.

(11)

On June 30, 2016, the Company entered into a promissory note with an unrelated party for $100,000 and the issuance of 20,000 shares of the Company's restricted common stock, valued at $2,400, as a loan servicing fee. This note accrues interest at the rate of 7.0% per annum with interest paid quarterly in arrears and all principal and interest due on June 30, 2018. In the event of a default, the loan will become due immediately and a default interest rate of 18.0% per year will be assessed on all amounts outstanding until paid in full. An event of default only occurs if any payment required by this note is not paid. The proceeds for this note were received on July 1, 2016, upon formal closing of the transaction. The loan servicing fee will be amortized over the life of the loan.

(12) On June 30, 2016, the Company entered into a promissory note with an unrelated party for $25,000 and the issuance of 12,500 shares of the Company's restricted common stock, valued at $1,500, as a loan servicing fee. This note accrues interest at the rate of 7.0% per annum with interest paid quarterly in arrears and all principal and interest due on June 29, 2018. In the event of a default, the loan will become due immediately and a default interest rate of 18.0% per year will be assessed on all amounts outstanding until paid in full. An event of default only occurs if any payment required by this note is not paid. The proceeds from this note were received on July 5, 2016, upon formal closing of the transaction. The loan servicing fee will be amortized over the life of the loan.

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Income Taxes

12 Months Ended

Dec. 31, 2016

Income Taxes

Income Taxes

 8. Income Taxes

At December 31, 2016, the Company has net operating loss ("NOL") carryforwards for Federal income tax purposes of approximately $10,214,000. If not previously utilized, the NOL carryforwards will expire in 2018 through 2036.

For the years ended December 31, 2016 and 2015, 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, 2016 and 2015 differs from the amounts computed using the federal statutory tax rate of 34%, as follows:

	2016			2015
Income tax benefit (expense) at the statutory rate	$	1,530,000		$	1,614,000
Benefit (expense) resulting from:
Increase in Federal valuation allowance		(1,530,000	)		(1,884,000	)
Other permanent differences		-			270,000
Utilization of net operating loss carryforwards		-			-
Income tax benefit (expense)	$	-		$	-

At December 31, 2016 and 2015, the tax effects of temporary differences that give rise to significant deferred tax assets and liabilities are presented below:

	2016			2015
Federal net operating loss carryforwards	$	3,473,000		$	3,030,000
State net operating loss carryforwards		358,000			315,000
Oil and gas properties		1,927,000			917,000
Asset retirement obligations		405,000			371,000
Net deferred tax assets		6,163,000			4,633,000
Less valuation allowance		(6,163,000	)		(4,633,000	)
Net deferred tax assets	$	—		$	—

The Company has not maintained a tax basis property roll-forward and has not filed tax returns since 2011 and therefore, the tax assets disclosed above are management's best estimate and this estimate could change as the company completes it tax returns. 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, 2016 and 2015.

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, 2016 and 2015, 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 2011 through 2016 remain open to examination by these taxing jurisdictions.

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Asset Retirement Obligations

12 Months Ended

Dec. 31, 2016

Asset Retirement Obligations

Asset Retirement Obligations

9. 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, 2016 and 2015 is as follows:

	2016			2015
Balance, beginning of year	$	995,197		$	749,013
Liabilities incurred upon acquisition of properties		-			204,493
Liabilities settled		(4,530	)		(28,684	)
Accretion expense		94,333			70,375
Balance, end of year		1,085,000			995,197
Less: current asset retirement obligations		(425,200	)		(409,621	)
Long-term asset retirement obligations	$	659,800		$	585,576

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2016

Commitments And Contingencies

Commitments and Contingencies

10. 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 2016 and 2015 was $0 and $1,400, which is included in gas gathering operating costs. The Company does not have any operating leases in place at December 31, 2016.

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. On September 30, 2016 plaintiff Eric Langan et al. filed a complaint in Maricopa County Superior Court for common law fraud under Arizona law against Arête Industries, Inc., Don and Jane Doe Prosser, and Charles and Jane Doe Davis. The action was removed to federal court on November 17, 2016, civil action number 16 – 03994 – PHX – SPL. On September 1, 2017 a judgment was entered in favor of the defendants and against plaintiffs in the case was dismissed in its entirety for lack of personal jurisdiction.

As of December 31, 2016, 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.

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Subsequent Events

12 Months Ended

Dec. 31, 2016

Subsequent Events

Subsequent Events

11. Subsequent Events

The following are the subsequent events:

On September 11, 2017, we entered into an Offer to Purchase Letter  with Marc VenJohn (the "Offer Letter") for a 25% working interest in two of the Company's oil and gas assets located in Clark County, Kansas for total consideration of $150,000 and an effective date of October 1, 2017. On November 15, 2017, the Company completed the sale under a purchase and sale agreement, with an effective date of October 1, 2017 (the "VenJohn PSA"), with Marc VenJohn.

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Supplementary Oil and Gas Information (unaudited)

12 Months Ended

Dec. 31, 2016

Supplementary Oil And Gas Information

Supplementary Oil and Gas Information (unaudited)

12. 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, 2016 and 2015:

	2016		2015
Acquisition costs:
Unproved properties	$	-	$	-
Proved properties		-		1,404,493
Exploration costs		-		-
Development costs		-		115,992
Revisions to asset retirement obligation		-		-
Total costs incurred	$	-	$	1,520,485
Depletion per BOE of production	$	17.56	$	27.78

The reserve information presented below is based on estimates of net proved reserves as of December 31, 2016 and 2015 that were prepared by Pinnacle Energy Services, L.L.C. the Company's independent petroleum engineering firm, 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 oil and gas reserve quantities for the years ended December 31:

	Oil (Bbl)			Gas (Mcf)			Equivalent (BOE)
Balance, January 1, 2015		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
Sale of oil and gas reserves in place		-			-			-
Acquisition of reserves in place		-			-			-
Revisions in previous estimates (1)		(105,804	)		(196,533	)		(138,562	)
Production		(23,386	)		(41,937	)		(30,376	)
Balance, December 31, 2016		146,030			119,770			165,990
Proved reserves, December 31, 2015:
Proved developed		275,220			358,240			334,928
Proved undeveloped		-			-			-
Proved reserves, December 31, 2016:
Proved developed		146,030			119,770			165,990
Proved undeveloped		-			-			-

(1) The primary reason for the revision in previous estimates is due to the higher lease operating expenses incurred, which made several of the wells uneconomic sooner than the prior year.

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, 2016, 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 2016, which resulted in benchmark prices of $42.75 per barrel for crude oil, West Texas Intermediate ("WTI") and $2.49 per MMbtu for natural gas, Henry Hub. Prices were further adjusted for transportation, quality and basis differentials, which resulted in a difference from the benchmark prices ranging from -$2.97 per barrel to -$10.77 per barrel, depending on the location of the wells. One well that produces from the Minnelusa formation has an oil differential of -$26.67 per barrel. The calculated natural gas differentials ranged from -74% 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, 2016 and 2015:

	2016			2015
Future cash inflows	$	5,751,250		$	13,002,030
Future production costs		(4,322,870	)		(7,976,560	)
Future development costs		-
Future income taxes		-
Future net cash flows		1,428,380			5,025,470
10% annual discount		(545,640	)		(2,472,800	)
Standardized measure of discounted future net cash flows	$	882,740		$	2,552,670

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, 2016 and 2015:

	2016			2015
Standardized measure of discounted future net cash flows, beginning of year	$	2,552,670		$	5,989,127
Sales of oil and gas, net of production costs and taxes		(224,105	)		23,891
Purchases of reserves in place		-			589,190
Sales of reserves in place		-			—
Changes in development costs		-			(699,000	)
Revisions of previous estimates		(802,699	)		(440,871	)
Changes in prices and production costs		(898,393	)		(4,661,912	)
Net changes in income taxes		-			1,153,332
Accretion of discount		255,267			598,913
Standardized measure of discounted future net cash flows, end of year	$	882,740		$	2,552,670

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Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2016

Summary Of Significant Accounting Policies Policies

Going Concern

Going Concern

The accompanying financial statements have been prepared on a going concern basis of accounting, which contemplates continuity of operations, realization of assets and liabilities and commitments in the normal course of business. The accompanying financial statements do not reflect any adjustments that might result if the Company is unable to continue as a going concern. The Company does not generate adequate revenue to satisfy its current operations, has negative cash flows from operations, and incurred significant net operating losses during the years ended December 31, 2016 and 2015, which raise substantial doubt about the Company's ability to continue as a going concern. The ability of the Company to continue as a going concern and appropriateness of using the going concern basis is dependent upon, among other things, additional cash infusion. The Company has historically obtained funds through private placement offerings of equity and debt, as well as, asset sales. There is no assurance that the Company will be able to continue raising the required capital.

Use of Estimates

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.

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

Cash and Cash Equivalents

Cash Equivalents and 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

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

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. During the year ending December 31, 2015, the Company wrote this asset off by recording an impairment charge against the gas gathering system of $56,648.  Depreciation of furniture and equipment is computed using the straight-line method over an estimated useful life of five years. As of December 31, 2016 and 2015, furniture and equipment was fully depreciated.  During the year ended December 31, 2016 and 2015, the Company recorded $0 and $428, respectively in depreciation expense.

Oil and Gas Producing Activities

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.

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 or future plans to develop acreage.

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. The Company recorded impairment charges against its oil and gas properties in the amount of $3,358,000 and $3,231,000 at December 31, 2016 and 2015, respectively.

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

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 Statements of Operations. See Note 9 – Asset Retirement Obligations.

Revenue Recognition

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, 2016 and 2015 were not material.

Environmental Liabilities

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, 2016 and 2015, 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

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

Stock-Based Compensation

The Company did not grant any stock options or warrants during the years ended December 31, 2016 and 2015 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 2016 and 2015. 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

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

Fair Value of Financial Instruments

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

Concentration of Credit Risk

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, 2016, the Company did not have any uninsured cash balances.  The Company received 90% and 82% of its oil and gas production revenue from one purchaser during fiscal years ended December 31, 2016 and 2015, 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

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, 2016, the convertible preferred stock had an aggregate liquidation preference of $2,767,991 and was convertible to 1,383,995 shares of common stock. These shares were excluded from the earnings per share calculation because they would be anti-dilutive due to the Company's net loss.

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

	Year ended December 31,
	2016			2015
Net loss available to Arête Industries, Inc.	$	(4,499,045	)	$	(4,747,053	)
Less: Preferred stock dividends		(191,961	)		-
Net loss available to common shareholders'	$	(4,691,006	)	$	(4,747,053	)
Weighted average common shares outstanding – Basic		14,528,345			12,882,000
Add: Dilutive effect of stock options		-			-
Add: Dilutive effect of preferred stock		-			-
Weighted average common shares outstanding – Diluted		14,528,345			12,882,000
Net loss per common share:
Basic	$	(0.32	)	$	(0.37	)
Diluted	$	(0.32	)	$	(0.37	)

New Accounting Pronouncements

New Accounting Pronouncements

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 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 February 2016, FASB issued ASU 2016-02, "Leases." ASU 2016-02 requires the recognition of lease assets and lease liabilities by lessees for those leases currently classified as operating leases and makes certain changes to the way lease expenses are accounted for. This update is effective for fiscal years beginning after December 15, 2018 and for interim periods beginning the following year. This update should be applied using a modified retrospective approach, and early adoption is permitted. The Company is evaluating the new guidance and has not determined the impact this standard may have on its financial statements.

In November 2016, the FASB issued ASU 2016-18, "Statement of Cash Flows: Restricted Cash" to address diversity in practice in the classification and presentation of changes in restricted cash. The accounting update requires that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, amounts generally described as restricted cash or restricted cash equivalents should be included with cash and cash equivalents when reconciling beginning-of-period and end-of-period amounts shown on the statement of cash flows. The guidance is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years, with early adoption permitted. This is an expansive set of revisions to the cash flow presentation standards, but at this time we do not believe that these changes will impact our financial statements.

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Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2016

Summary Of Significant Accounting Policies Tables

Schedule of Earning per Share

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

	Year ended December 31,
	2016			2015
Net loss available to Arête Industries, Inc.	$	(4,499,045	)	$	(4,747,053	)
Less: Preferred stock dividends		(191,961	)		-
Net loss available to common shareholders'	$	(4,691,006	)	$	(4,747,053	)
Weighted average common shares outstanding – Basic		14,528,345			12,882,000
Add: Dilutive effect of stock options		-			-
Add: Dilutive effect of preferred stock		-			-
Weighted average common shares outstanding – Diluted		14,528,345			12,882,000
Net loss per common share:
Basic	$	(0.32	)	$	(0.37	)
Diluted	$	(0.32	)	$	(0.37	)

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Oil and Gas Properties (Tables)

12 Months Ended

Dec. 31, 2016

Extractive Industries [Abstract]

Schedule of Oil and Gas Properties

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

	December 31,
	2016			2015
Proved oil and gas properties at cost, net of impairment	$	5,325,381		$	8,683,273
Unevaluated oil and gas properties at cost, net of impairment		154,977			154,836
Accumulated depreciation, depletion and amortization		(3,662,000	)		(3,223,000	)
Oil and gas properties, net	$	1,818,358		$	5,615,109

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Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2016

Fair Value Disclosures [Abstract]

Schedule of Fair Value Measurements on Nonrecurring Basis

The following table represents the Company's assets that are measured at fair value on a nonrecurring basis in the accompanying balance sheets, and where they are classified within the fair value hierarchy as of December 31, 2016:

	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other  Observable Inputs (Level 2)		Significant  Unobservable Inputs (Level 3)
Proved oil and gas properties at cost, net of impairment		-		-	$	1,377,260

The following table represents the Company's assets that are measured at fair value on a nonrecurring basis in the accompanying balance sheets, and where they are classified within the fair value hierarchy as of December 31, 2015:

	Level 1		Level 2		Level 3
Proved oil and gas properties at cost, net of impairment		-		-	$	5,460,273
Unevaluated oil and gas properties at cost, net of impairment		-		-	$	-

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Notes and advances payable (Tables)

12 Months Ended

Dec. 31, 2016

Notes And Advances Payable Tables

Schedule of Notes and Advances Payable

Notes payable consist of the following as of the date indicated:

	December 31, 2016		December 31, 2015
Officers, directors and affiliates:
Note payable, interest 7.0%, due January 2019 (1)		30,546		43,803
Collateralized note payable (2)		120,728		120,728
Total officers, directors and affiliates		151,274		164,531
Less: Current portion of officers, directors, and affiliates		134,839		13,152
Long-term portion of officers, directors, and affiliates	$	16,435	$	151,379
Unrelated parties:
Notes payable, interest at 7.5%, due March 2018 (3)	$	100,000	$	100,000
Notes payable, interest at 7.0%, due January 2017 (4)		22,737		32,607
Note payable, due March 2018 (5)		150,000		150,000
Note payable, due January 2019 (6)		13,566		19,660
Note payable, interest variable (see below) due June 2018 (7)		523,000		616,105
Note payable, interest at 7.0%, due August 2016 (8)		62,000		62,000
Notes payable, interest at 7.0%, due June 2018 (9)		183,000		183,000
Notes payable, net of discount, interest at 7.0%, due June 2018 (10)		97,300		-
Notes payable, net of discount, interest at 7.0%, due June 2018 (11)		98,200		-
Notes payable, net of discount, interest at 7.0%, due June 2018 (12)		23,875		-
Total unrelated parties		1,273,678		1,163,372
Less: Current portion of unrelated parties		240,750		989,853
Long-term portion of unrelated parties	$	1,032,928	$	173,519

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2016

Income Taxes Tables

Schedule of Income Tax Reconciliation

	2016			2015
Income tax benefit (expense) at the statutory rate	$	1,530,000		$	1,614,000
Benefit (expense) resulting from:
Increase in Federal valuation allowance		(1,530,000	)		(1,884,000	)
Other permanent differences		-			270,000
Utilization of net operating loss carryforwards		-			-
Income tax benefit (expense)	$	-		$	-

Schedule of Deferred Tax assets and Liabilities

At December 31, 2016 and 2015, the tax effects of temporary differences that give rise to significant deferred tax assets and liabilities are presented below:

	2016			2015
Federal net operating loss carryforwards	$	3,473,000		$	3,030,000
State net operating loss carryforwards		358,000			315,000
Oil and gas properties		1,927,000			917,000
Asset retirement obligations		405,000			371,000
Net deferred tax assets		6,163,000			4,633,000
Less valuation allowance		(6,163,000	)		(4,633,000	)
Net deferred tax assets	$	—		$	—

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Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2016

Asset Retirement Obligations Tables

Asset Retirement Obligations (ARO)

A reconciliation of the Company's ARO for the years ended December 31, 2016 and 2015 is as follows:

	2016			2015
Balance, beginning of year	$	995,197		$	749,013
Liabilities incurred upon acquisition of properties		-			204,493
Liabilities settled		(4,530	)		(28,684	)
Accretion expense		94,333			70,375
Balance, end of year		1,085,000			995,197
Less: current asset retirement obligations		(425,200	)		(409,621	)
Long-term asset retirement obligations	$	659,800		$	585,576

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Supplementary Oil and Gas Information (unaudited) (Tables)

12 Months Ended

Dec. 31, 2016

Supplementary Oil And Gas Information Tables

Costs Incurred in Oil and Gas Property Acquisition

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, 2016 and 2015:

	2016		2015
Acquisition costs:
Unproved properties	$	-	$	-
Proved properties		-		1,404,493
Exploration costs		-		-
Development costs		-		115,992
Revisions to asset retirement obligation		-		-
Total costs incurred	$	-	$	1,520,485
Depletion per BOE of production	$	17.56	$	27.78

Changes in Proved Reserves

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

	Oil (Bbl)			Gas (Mcf)			Equivalent (BOE)
Balance, January 1, 2015		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
Sale of oil and gas reserves in place		-			-			-
Acquisition of reserves in place		-			-			-
Revisions in previous estimates (1)		(105,804	)		(196,533	)		(138,562	)
Production		(23,386	)		(41,937	)		(30,376	)
Balance, December 31, 2016		146,030			119,770			165,990
Proved reserves, December 31, 2015:
Proved developed		275,220			358,240			334,928
Proved undeveloped		-			-			-
Proved reserves, December 31, 2016:
Proved developed		146,030			119,770			165,990
Proved undeveloped		-			-			-

Standardized Measure of Discounted Future Net Cash Flows Related 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, 2016 and 2015:

	2016			2015
Future cash inflows	$	5,751,250		$	13,002,030
Future production costs		(4,322,870	)		(7,976,560	)
Future development costs		-
Future income taxes		-
Future net cash flows		1,428,380			5,025,470
10% annual discount		(545,640	)		(2,472,800	)
Standardized measure of discounted future net cash flows	$	882,740		$	2,552,670

Changes in Standardized Measure of Discounted Future Net Cash Flows

A summary of changes in the standardized measure of discounted future net cash flows is as follows for the years ended December 31, 2016 and 2015:

	2016			2015
Standardized measure of discounted future net cash flows, beginning of year	$	2,552,670		$	5,989,127
Sales of oil and gas, net of production costs and taxes		(224,105	)		23,891
Purchases of reserves in place		-			589,190
Sales of reserves in place		-			—
Changes in development costs		-			(699,000	)
Revisions of previous estimates		(802,699	)		(440,871	)
Changes in prices and production costs		(898,393	)		(4,661,912	)
Net changes in income taxes		-			1,153,332
Accretion of discount		255,267			598,913
Standardized measure of discounted future net cash flows, end of year	$	882,740		$	2,552,670

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Organization and Nature of Operations - Additional Information (Details Narrative)	12 Months Ended
	Dec. 31, 2016
Organization And Nature Of Operations - Additional Information Details Narrative
Entity Incorporation, Date of Incorporation	Jul. 21, 1987
Entity Incorporation, State Country Name	Colorado

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Summary of Significant Accounting Policies (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Summary Of Significant Accounting Policies Details Narrative
Net loss available to common shareholder's - Basic	$ (4,499,045)	$ (4,747,053)
Plus: Preferred stock dividends	(191,961)	0
Net loss available to common shareholder's - Diluted	$ (4,691,006)	$ (4,747,053)
Weighted average common shares outstanding - Basic	14,528,345	12,882,000
Add: Dilutive effect of stock options	0	0
Add: Dilutive effect of preferred stock	0	0
Weighted average common shares outstanding - Diluted	14,528,345	12,882,000
Net loss per common share:
Basic	$ (0.32)	$ (0.37)
Diluted	$ (0.32)	$ (0.37)

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Summary of Significant Accounting Policies (Details Narrative) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Impairment charge against gas gathering system	$ 0	$ 56,648
Depreciation expense	0	428
Impairment expense of oil and gas properties	3,358,000	$ 3,231,000
Federal Deposit Insurance Corporation insurance limit	$ 250,000
Concentration of Credit Risk	90.00%	82.00%
Series A2 Preferred Stock [Member]
Convertible preferred stock, liquidation preference	$ 2,767,991
Convertible of common stock	1,383,995
Exchange price	$ 2.00

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Acquisitions and Dispositions of Oil and Gas Properties (Detail Narrative) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Acquisitions And Dispositions Of Oil And Gas Properties Detail Narrative
Other operating expense	$ 0	$ 160,011

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Oil and Gas Properties (Details) - USD ($)	Dec. 31, 2016	Dec. 31, 2015
Extractive Industries [Abstract]
Proved oil and gas properties at cost, net of impairment	$ 5,325,381	$ 8,683,273
Unevaluated oil and gas properties at cost, net of impairment	154,977	154,836
Accumulated depreciation, depletion and amortization	(3,662,000)	(3,223,000)
Oil and gas properties, net	$ 1,818,358	$ 5,615,109

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Oil and Gas Properties (Details Narrative) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Extractive Industries [Abstract]
Depletion Expenses	$ 439,000	$ 746,104
Impairment Expenses	$ 3,358,000	$ 3,231,000

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Fair Value Measurements (Details) - USD ($)	Dec. 31, 2016	Dec. 31, 2015
Proved oil and gas properties at cost, net of impairment	$ 5,325,381	$ 8,683,273
Unevaluated oil and gas properties at cost, net of impairment	154,977	154,836
Fair Value, Measurements, Nonrecurring [Member] | Fair Value, Inputs, Level 1 [Member]
Proved oil and gas properties at cost, net of impairment	0	0
Unevaluated oil and gas properties at cost, net of impairment		0
Fair Value, Measurements, Nonrecurring [Member] | Fair Value, Inputs, Level 2 [Member]
Proved oil and gas properties at cost, net of impairment	0	0
Unevaluated oil and gas properties at cost, net of impairment		0
Fair Value, Measurements, Nonrecurring [Member] | Fair Value, Inputs, Level 3 [Member]
Proved oil and gas properties at cost, net of impairment	$ 1,377,260	5,460,273
Unevaluated oil and gas properties at cost, net of impairment		$ 0

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Stockholders' Equity (Details Narrative) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Convertible preferred stock, shares authorized	1,000,000	1,000,000
Common stock, par value	$ 0	$ 0
Common stock, shares authorized	499,000,000	499,000,000
Common stock, shares issued	14,674,580	14,295,413
Common stock, shares outstanding	14,674,580	14,295,413
Issuance of common stock for oil and gas acquisition		$ 100,000
Issuance of common stock for oil and gas acquisition, in Shares		1,000,000
Common stock issued for compensation of services		$ 480,288
Common stock issued for compensation of services, in Shares		736,954
Common stock issued for consulting services		256,666
Issuance of Preferred stock Series A Two	$ 50,000	$ 1,770,000
Preferred stock issued for settlement with a related party	0	900,000
Class A2 Preferred Stock
Issuance of common stock for oil and gas acquisition
Issuance of common stock for oil and gas acquisition, in Shares
Issuance of Preferred stock Series A Two	$ 50,000	$ 1,770,000
Issuance of Preferred stock Series A Two, in Shares	5	177
Preferred stock issued for settlement with a related party		$ 900,000
Preferred stock issued for settlement with a related party, in Shares		90
Series A1 Preferred Stock [Member]
Convertible preferred stock, shares authorized	30,000	30,000
Convertible preferred stock, shares issued	0	0
Convertible preferred stock, shares outstanding	0	0
Series A2 Preferred Stock [Member]
Convertible preferred stock, shares authorized	2,500	2,500
Convertible preferred stock, shares issued	272	267
Convertible preferred stock, shares outstanding	272	267

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Notes and advances payable (Details) - USD ($)	Dec. 31, 2016	Dec. 31, 2015
Officers, directors and affiliates:
Note payable	$ 30,546	$ 43,803
Collateralized note payable	120,728	120,728
Total officers, directors and affiliates	151,274	164,531
Less: Current portion of officers, directors, and affiliates	134,839	13,152
Long-term portion of officers, directors, and affiliates	16,435	151,379
Unrelated parties:
Total unrelated parties	1,273,678	1,163,372
Less: Current portion of unrelated parties	240,750	989,853
Long-term portion of unrelated parties	1,032,928	173,519
Notes Payable [Member]
Unrelated parties:
Total unrelated parties	100,000	100,000
Notes Payable One [Member]
Unrelated parties:
Total unrelated parties	22,737	32,607
Notes Payable Two [Member]
Unrelated parties:
Total unrelated parties	150,000	150,000
Notes Payable Three[Member]
Unrelated parties:
Total unrelated parties	13,566	19,660
Notes Payable Four [Member]
Unrelated parties:
Total unrelated parties	523,000	616,105
Notes Payable Five [Member]
Unrelated parties:
Total unrelated parties	62,000	62,000
Notes Payable Six [Member]
Unrelated parties:
Total unrelated parties	183,000	183,000
Notes Payable Seven [Member]
Unrelated parties:
Total unrelated parties	97,300	0
Notes Payable Eight [Member]
Unrelated parties:
Total unrelated parties	98,200	0
Notes Payable Nine [Member]
Unrelated parties:
Total unrelated parties	$ 23,875	$ 0

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Income Taxes (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Income Taxes Details
Income tax benefit (expense) at the statutory rate	$ 1,530,000	$ 1,614,000
Benefit (expense) resulting from:
Increase in Federal valuation allowance	(1,530,000)	(1,884,000)
Other permanent differences	0	270,000
Utilization of net operating loss carryforwards	0	0
Income tax benefit (expense)	$ 0	$ 0

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Income Taxes (Details 2) - USD ($)	Dec. 31, 2016	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Federal net operating loss carryforwards	$ 3,473,000	$ 3,030,000
State net operating loss carryforwards	358,000	315,000
Oil and gas properties	1,927,000	917,000
Asset retirement obligations	405,000	371,000
Net deferred tax assets	6,163,000	4,633,000
Less valuation allowance	(6,163,000)	(4,633,000)
Net deferred tax assets	$ 0	$ 0

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Income Taxes (Details Narrative) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Operating loss carry forwards, amount	$ (10,214,000)
Federal statutory tax rate	34.00%	34.00%
Minimum [Member]
Operating loss carry forwards, expiration	2018
Maximum [Member]
Operating loss carry forwards, expiration	2036

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Reconciliation of Asset Retirement Obligations (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Reconciliation Of Asset Retirement Obligations Details
Balance, beginning of year	$ 995,197	$ 749,013
Liabilities incurred upon acquisition of properties	0	204,493
Liabilities settled	(4,530)	(28,684)
Accretion expense	94,333	70,375
Balance, end of year	1,085,000	995,197
Less current asset retirement obligations	(425,200)	(409,621)
Long-term asset retirement obligations	$ 659,800	$ 585,576

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Commitments and Contingencies (Details Narrative) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Commitments And Contingencies Details Narrative
Rental expense under operating leases	$ 0	$ 1,400

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Supplementary Oil and Gas Information (unaudited) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Acquisition costs:
Unproved properties	$ 0	$ 0
Proved properties	0	1,404,493
Exploration costs	0	0
Development costs	0	115,992
Revisions to asset retirement obligations	0	0
Total costs incurred	$ 0	$ 1,520,485
Depletion per BOE of production	$ 17.56	$ 27.78

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Supplementary Oil and Gas Information (unaudited) (Details 2)	12 Months Ended
	Dec. 31, 2016 Boe Mcf bbl	Dec. 31, 2015 Boe Mcf bbl
Oil
Balance, beginning of the year | bbl	275,220	237,229
Sale of oil and gas reserves in place | bbl	0	0
Acquisition of reserves in place | bbl	0	71,870
Revisions in previous estimates | bbl	(105,804)	(14,924)
Production | bbl	(23,386)	(18,955)
Balance at end | bbl	146,030	275,220
Proved developed | bbl	146,030	275,220
Proved undeveloped | bbl	0	0
Gas
Balance, beginning of the year | Mcf	358,240	614,940
Sale of oil and gas reserves in place | Mcf	0	0
Acquisition of reserves in place | Mcf	0	0
Revisions in previous estimates | Mcf	(196,533)	(194,070)
Production | Mcf	(41,937)	(62,630)
Balance at end | Mcf	119,770	358,240
Proved developed | Mcf	119,770	358,240
Proved undeveloped | Mcf	0	0
Equivalent
Balance, beginning of the year | Boe	334,928	339,720
Sale of oil and gas reserves in place | Boe	0	0
Acquisition of reserves in place | Boe	0	71,870
Revisions in previous estimates | Boe	(138,562)	(47,269)
Production | Boe	(30,376)	(29,393)
Balance at end | Boe	165,990	334,928
Proved reserve
Proved developed | Boe	165,990	334,928
Proved undeveloped | Boe	0	0

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Supplementary Oil and Gas Information (unaudited) (Details 3) - USD ($)	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Supplementary Oil And Gas Information Details 2
Future cash inflows	$ 5,751,250	$ 13,002,030
Future production costs	(4,322,870)	(7,976,560)
Future development costs	0	0
Future income taxes	0	0
Future net cash flows	1,428,380	5,025,470
10% annual discount	(545,640)	(2,472,800)
Standardized measure of discounted future net cash flows	$ 882,740	$ 2,552,670	$ 5,989,127

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Supplementary Oil and Gas Information (unaudited) (Details 4) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Supplementary Oil And Gas Information Details 3
Standardized measure of discounted future net cash flows, beginning of year	$ 2,552,670	$ 5,989,127
Sales of oil and gas, net of production costs and taxes	(224,105)	23,891
Purchases of reserves in place	0	589,190
Sales of reserves in place	0	0
Changes in development costs	0	(699,000)
Revisions of previous estimates	(802,699)	(440,871)
Changes in prices and production costs	(898,393)	(4,661,912)
Net changes in income taxes	0	1,153,332
Accretion of discount	255,267	598,913
Standardized measure of discounted future net cash flows, end of year	$ 882,740	$ 2,552,670