Our future success depends on our ability to replace reserves that our operators produce.

Because the rate of production from oil and natural gas properties generally declines as reserves are depleted, our future success depends upon our ability to economically find or acquire and produce additional oil and natural gas reserves. Except to the extent that we acquire additional properties containing proved reserves, conduct successful exploration and development activities or, through engineering studies, identify additional behind-pipe zones or secondary recovery reserves, our proved reserves will decline as our reserves are produced. Future oil and natural gas production, therefore, is highly dependent upon our level of success in acquiring or finding additional reserves that are economically recoverable. We cannot assure you that we will be able to find or acquire and develop additional reserves at an acceptable cost.

We may acquire significant amounts of unproved property to further our development efforts. Development and exploratory drilling and production activities are subject to many risks, including the risk that no commercially productive reservoirs will be discovered. We acquire both proved and producing properties as well as undeveloped acreage that we believe will enhance growth potential and increase our earnings over time. However, we cannot assure you that all of these properties will contain economically viable reserves or that we will not abandon our initial investments. Additionally, we cannot assure you that unproved reserves or undeveloped acreage that we acquire will be profitably developed, that new wells drilled on our properties will be productive or that we will recover all or any portion of our investments in our properties and reserves.

As a non-operator, our development of successful operations relies extensively on third-parties who, if not successful, could have a material adverse effect on our results of operation.

We have only participated in wells operated by third-parties. Our current ability to develop successful business operations depends on the success of our consultants and drilling partners. As a result, we do not control the timing or success of the development, exploitation, production and exploration activities relating to our leasehold interests. If our consultants and drilling partners are not successful in such activities relating to our leasehold interests, or are unable or unwilling to perform, our financial condition and results of operations would be materially adversely affected.

Our operators will make decisions in connection with their operations (subject to their contractual and legal obligations to other owners of working interests), which may not be in our best interests.

Additionally, we may have virtually no ability to exercise influence over the operational decisions of our operators, including the setting of capital expenditure budgets and drilling locations and schedules. Dependence on our operators could prevent us from realizing our target returns for those locations. The success and timing of development activities by our operators will depend on a number of factors that will largely be outside of our control, including:

We could experience periodseffected a reverse stock split on February of higher costs2020 which may adversely impact the market price of our common stock.

On February 18, 2020, the Company filed a Certificate of Amendment to its Articles of Incorporation (the “Amended Articles”) with the Secretary of State of Nevada to effect the Company’s previously announced 300-for-one reverse stock split (the “Reverse Stock Split”) of the Company’s common stock. The Reverse Stock Split, effective as activity levelsof February 21, 2020, converted every 300 shares of the Company’s issued and outstanding common stock into one share of common stock. The effect of the Reverse Stock Split upon the market price of our common stock cannot be predicted with certainty and there is no assurance that our common stock will trade at a price consistent with such Reverse Stock Split. Accordingly, it is possible that the market price of our common stock following the Reverse Stock Split will decline, possibly more than would occur in the Williston Basin fluctuateabsence of a Reverse Stock Split.

The Reverse Stock Split may decrease the liquidity of the shares of our common stock and the resulting market price of our common stock may not attract or if commodity prices rise. These increases could reduce our profitability, cash flow, and ability to complete development activities as planned.satisfy the investing requirements of new investors, including institutional investors.

The recent decline in commodity prices has resulted in significantlyliquidity of the shares of our common stock may be affected adversely by the Reverse Stock Split given the reduced activity levelsnumber of shares outstanding following the Reverse Stock Split. Additionally, the Reverse Stock Split may increase the number of shareholders who own odd lots (less than 100 shares) of our common stock, creating the potential for such shareholders to experience an increase in the Williston Basin. However, ifcost of selling their shares and when activity ingreater difficulty affecting such sales. Moreover, there can be no assurance that the Williston Basin increases, competition for equipment, labor and supplies is also expected to increase. Likewise, higher oil, natural gas and NGL prices generally increase the demand for equipment, labor and supplies, and can lead to shortages of, and increasing costs for, drilling equipment, services and personnel. The lower oil prices may alsoReverse Stock Split will result in some suppliers of equipment, labora share price that will attract new investors, including institutional investors, and supplies ceasing operations inthere can be no assurance that the Williston Basin. Shortages of, or increasing costs for, experienced drilling crews and equipment and services could restrict our operating partners’ ability to drill the wells and conduct the operations that we currently expect.

In addition, capital and operating costs in the oil and natural gas industry have generally risen during periods of increasing commodity prices as producers seek to increase production in order to capitalize on higher commodity prices. In situations where cost inflation exceeds commoditymarket price inflation, our profitability and cash flow, and our operators’ ability to complete development activities as scheduled and on budget, may be negatively impacted. While recent oil price declines may result in lower drilling costs, to the extent our third party operators have contracted on a long-term or fixed cost basis and are unable to immediately recognize the lower drilling costs, our profitability may suffer and our capital expenditures may exceed amounts we would otherwise anticipate. Any delay in the drilling of new wells or significant increase in drilling costs or delay in recognizing reductions in drilling costs could reduce our revenues and cash available to make payments on our debt obligations.

Our lack of diversification will increase the risk of an investment in our company, and our financial condition and results of operations may deteriorate if we fail to diversify.

Our business focus is on the crude oil and natural gas industry in a limited number of properties, primarily in North Dakota and Montana. Larger companies have the ability to manage their risk by diversification. We lack diversification in terms of both the nature and geographic scope of our business. As a result, wecommon stock will likely be impacted more acutely by factors affectingsatisfy the investing requirements of these investors. Consequently, the trading liquidity of our industry or the regions in which we operate than we would if our business were more diversified, increasing our risk profile. If we docommon stock may not diversify our operations, our financial condition and results of operations could deteriorate. Asnecessarily improve as a result of the narrow focus of our business, we may be disproportionately exposed to the effects of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, market limitations, weather events or interruption of the processing or transportation of oil or natural gas. Additionally, we may be exposed to further risks, such as changes in field-wide rules and regulations that could cause us to permanently or temporarily shut-in all of our wells within the Williston Basin.Reverse Stock Split.

Our derivative activitiesThe effective increase in the number of shares of our common stock available for issuance as a result of our Reverse Stock Split could result in financial losses or could reducefurther dilution to our cash flow.existing stockholders.

We enter into swap collars or other derivative arrangements from time-to-time to hedge our expected production depending on projected production levels and expected market conditions, and are required to hedge under our Credit Agreements. While intended to mitigate the effects of volatile crude oil and natural gas prices, such transactions may limit our potential gains and increase our potential losses if crude oil and natural gas prices were to rise substantially over the price established by the hedge.

Our actual future production may be significantly higher or lower than we project at the time we enter into derivative contracts for a given period. If actual production is higher than we project, we will have greater commodity price exposure than we intended. If actual production is lower than the notional amount that is subject to our derivative financial instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow from our sale of the underlying physical commodity, resulting in a substantial decrease in our liquidity. As a result of these factors, our hedging activities may not be as effective as we intend in reducing the volatility of our cash flows, and in certain circumstances may actually increase the volatility of our cash flows. In addition, such transactions may expose us to the risk of loss in certain circumstances, including instances in which:

Our derivative activities expose us to potential regulatory risks.

The Federal Trade Commission (“FTC”), Federal Regulatory Commission (“FERC”) and the Commodities Futures Trading Commission (“CFTC”) have statutory authority to monitor certain segments of the physical and futures energy commodities markets. These agencies have imposed broad regulations prohibiting fraud and manipulation of such markets. With regard to derivative activities that we undertake with respect to oil, natural gas, NGLs, or other energy commodities, we are required to observe the market-related regulations enforced by these agencies. Failure to comply with such regulations, as interpreted and enforced, could have a material adverseReverse Stock Split alone had no effect on our business, resultsauthorized capital stock, and the total number of operationsauthorized shares remains the same as before the Reverse Stock Split. The Reverse Stock Split of our issued and financial condition.outstanding shares was effected, increasing the number of shares of our common stock (or securities convertible or exchangeable for our common stock) available for issuance. The additional available shares are available for issuance from time to time at the discretion of the Company’s board of directors when opportunities arise, without further stockholder action or the related delays and expenses, except as may be required for a particular transaction by law, the rules of any exchange on which our securities may then be listed, or other agreements or restrictions (including rights of first refusal, pursuant to the terms of certain of our outstanding secured convertible notes). Any issuance of additional shares of our common stock would increase the number of outstanding shares of our common stock and (unless such issuance was pro-rata among existing stockholders) the percentage ownership of existing stockholders would be diluted accordingly. In addition, any such issuance of additional shares of our common stock could have the effect of diluting the earnings per share and book value per share of outstanding shares of our common stock.

Our net operating loss carryforwards may be limited under Section 382 of the Internal Revenue Code by certain changes in the ownership of our company.

We have net operating loss (“NOL”) carryforwards that we may use to offset against taxable income for U.S. federal income tax purposes. At December 31, 2015,2019, we had an estimated NOL carryforward of approximately $23.8$27 million for United States federal tax return purposes. However, Section 382 of the Internal Revenue Code of 1986, as amended, may limit the NOLs that we may use in any year for U.S. federal income tax purposes in the event of certain changes in ownership of our company. Any limitation on our ability to use NOLs could, depending on the extent of such limitation, result in higher U.S. federal income taxes being paid (and therefore a reduction in cash) than if such NOLs were available as an offset against such income for U.S. federal income tax reporting purposes. In addition, if the limitation under Section 382 is triggered, it could result in a significant charge to earnings in the period in which it is triggered.

The present value of future net cash flows from our proved reserves is not necessarily the same as the current market value of our estimated proved reserves.

We base the estimated discounted future net cash flows from our proved reserves using a 12-month average price and costs in effect on the day of the estimate. However, actual future net cash flows from our oil and natural gas properties will be affected by factors such as:

The timing of both our production and our incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use 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 us or the oil and natural gas industry in general. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves, which could adversely affect our business, results of operations and financial condition.

Our business depends on oil and natural gas transportation and processing facilities and other assets that are owned by third parties.

The marketability of our oil and natural gas depends in part on the availability, proximity and capacity of pipeline systems, processing facilities, oil trucking fleets and rail transportation assets owned by third parties. The lack of available capacity on these systems and facilities, whether as a result of proration, physical damage, scheduled maintenance or other reasons, could result in the shut-in of producing wells or the delay or discontinuance of development plans for our properties. The curtailments arising from these and similar circumstances may last from a few days to several months. In many cases, operators are provided only with limited, if any, notice as to when these circumstances will arise and their duration. In addition, many of our wells are drilled in locations in the Williston Basin that are serviced only to a limited extent, if at all, by gathering and transportation pipelines, which may or may not have sufficient capacity to transport production from all of the wells in the area. As a result, we rely on third party oil trucking to transport a significant portion of our production to third party transportation pipelines, rail loading facilities and other market access points. Any significant curtailment in gathering system or pipeline capacity, or the unavailability of sufficient third party trucking or rail capacity, could adversely affect our business, results of operations and financial condition.

Certain of our undeveloped leasehold acreage is subject to leases that will expire over the next several years unless production is established or operations are commenced on units containing the acreage or the leases are extended.

A portion of our acreage is not currently held by production or held by operations. Unless production in paying quantities is established or operations are commenced on units containing these leases during their terms, the leases will expire. If our leases expire and we are unable to renew the leases, we will lose our right to participate in the development of the related properties. Drilling plans for these areas are generally in the discretion of third party operators and are subject to change based on various factors that are beyond our control, such as: the availability and cost of capital, equipment, services and personnel; seasonal conditions; regulatory and third party approvals; oil, NGL and natural gas prices; results of title work; gathering system and other transportation constraints; drilling costs and results; and production costs. As of December 31, 2015, we estimate that we had leases that were not developed that represented 1,114 net acres potentially expiring in 2016, 433 net acres potentially expiring in 2017, 355 net acres potentially expiring in 2018 and -0- net acres potentially expiring in 2019 and beyond.

Seasonal weather conditions adversely affect operators’ ability to conduct drilling activities in the areas where our properties are located.

Seasonal weather conditions can limit drilling and producing activities and other operations in our operating areas and as a result, a majority of the drilling on our properties is generally performed during the summer and fall months. These seasonal constraints can pose challenges for meeting well drilling objectives and increase competition for equipment, supplies and personnel during the summer and fall months, which could lead to shortages and increase costs or delay operations. Additionally, many municipalities impose weight restrictions on the paved roads that lead to jobsites due to the muddy conditions caused by spring thaws. This could limit access to jobsites and operators’ ability to service wells in these areas.

Significant capital expenditures are required to develop our properties and replace our reserves.

Our exploration, development and acquisition activities require substantial capital expenditures. Historically, we have funded our capital expenditures through a combination of cash flow from operations, our credit facility, debt issuances, and equity issuances. We have also engaged in asset sales from time to time. If our access to capital were limited due to numerous factors, which could include a decrease in operating cash flow due to lower oil and natural gas prices or decreased production or deterioration of the credit and capital markets, we would have a reduced ability to replace our reserves. We may not be able to incur additional bank debt, issue debt or equity, engage in asset sales or access other methods of financing on acceptable terms to develop our properties and/or meet our reserve replacement requirements.

The amount available for borrowing under our credit facility is subject to a borrowing base which is determined by our lenders, at their discretion, taking into account our estimated proved reserves and is subject to periodic redeterminations based on pricing models determined by the lenders at such time. The decline in oil and natural gas prices in the latter half of 2014 and through 2015 adversely impacted the value of our estimated proved reserves and, in turn, the market values used by our lenders to determine our borrowing base. Oil and natural gas prices have fallen significantly since their early third quarter 2014 levels. For example, oil prices declined 65% from over $105 per Bbl in the latter part of July 2014 to near $37 per Bbl on December 31, 2015, and natural gas prices have declined 39% from over $3.85 per Mcf to below $2.34 per Mcf over the same period. In addition, the actual and forecasted prices for 2016 have also declined since year-end. If commodity prices (particularly oil prices) remain at these levels, it will have an adverse effect on our reserves and borrowing base and reduce our ability to replace our reserves.

The development of our proved undeveloped reserves in the Williston Basin and other areas of operation may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our undeveloped reserves may not be ultimately developed or produced.

Approximately 2% of our estimated net barrel of oil equivalents of proved reserves were classified as proved undeveloped as of December 31, 2015. Development of these reserves may take longer and require higher levels of capital expenditures than we currently anticipate. Delays in the development of our reserves or increases in costs to drill and develop such reserves will reduce the PV-10 value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could cause us to have to reclassify our proved reserves as unproved reserves.

Our acquisition strategy will subject us to certain risks associated with the inherent uncertainty in evaluating properties for which we have limited information.

We have expanded our operations in part through acquisitions. Our decision to acquire a property will depend in part on the evaluation of data obtained from production reports and engineering studies, geophysical and geological analyses and seismic and other information, the results of which are often inconclusive and subject to various interpretations. Also, our reviews of acquired properties are inherently incomplete because it generally is not feasible to perform an in-depth review of the individual properties involved in each acquisition. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit us to become sufficiently familiar with the properties to assess fully their deficiencies and potential. Inspections may not always be performed on every well, and environmental problems, such as ground water contamination, are not necessarily observable even when an inspection is undertaken.

Any acquisition involves other potential risks, including, among other things:

We are highly dependent on Kenneth DeCubellis, our chief executive officer and interim chief financial officer, and our other executive officers and employees. The loss of one or more of them, upon whose knowledge, leadership and technical expertise we rely, would harm our ability to execute our business plan.

Our success depends heavily upon (1) the continued contributions of Kenneth DeCubellis, our chief executive officer and interim chief financial officer, whose knowledge, leadership and technical expertise would be difficult to replace, with the support of James Moe, our chief financial officer, and Michael Eisele, our chief operating officer, and (2) on our ability to retain and attract experienced engineers, geoscientists and other technical and professional consultants.officer. If we were to lose their services, our ability to execute our business plan would be harmed and we may be forced to cease operations until such time as we are able to suitably replace them. Any of our executive officers may terminate their employment with our company at any time.

Deficiencies of title to our leased interests could significantly affect our financial condition.

We typically do not incur the expense of a title examination prior to acquiring oil and natural gas leases or undivided interests in oil and natural gas leases or other developed rights. If an examination of the title history of a property reveals that an oil or natural gas lease or other developed rights have been purchased in error from a person who is not the owner of the mineral interest desired, our interest would substantially decline in value or be eliminated. In such cases, the amount paid for such oil or natural gas lease or leases or other developed rights may be lost. It is generally our practice not to incur the expense of retaining lawyers to examine the title to the mineral interest to be acquired. Rather, we typically rely upon the judgment of oil and natural gas lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental or county clerk's office before attempting to acquire a lease or other developed rights in a specific mineral interest.

Prior to drilling an oil or natural gas well, however, it is the normal practice in the oil and natural gas industry for the person or company acting as the operator of the well to obtain a preliminary title review of the spacing unit within which the proposed oil or natural gas well is to be drilled to ensure there are no obvious deficiencies in title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct deficiencies in the marketability of the title, such as obtaining affidavits of heirship or causing an estate to be administered. Such curative work entails expense, and the operator may elect to proceed with a well despite defects to the title identified in the preliminary title opinion. Furthermore, title issues may arise at a later date that were not initially detected in any title review or examination. Any one or more of the foregoing could require us to reverse revenues previously recognized and potentially negatively affect our cash flows and results of operations. Our failure to obtain perfect title to our leaseholds may adversely affect our current production and reserves and our ability in the future to increase production and reserves.

Competition in obtaining rights to explore and develop crude oil and natural gas reserves and to market our production may impair our business.

The crude oil and natural gas industry is highly competitive. Other crude oil and natural gas companies may seek to acquire crude oil and natural gas leases and other properties and services in the same areas in which we desire to invest. This competition is increasingly intense as commodity prices of crude oil have continued to remain at levels that make oil and gas production in our area of operation viable. Additionally, other companies engaged in our line of business may compete with us from time to time in obtaining capital from investors. Competitors include larger companies which, in particular, may have access to greater resources, may be more successful in the recruitment and retention of qualified employees and may conduct their own refining and petroleum marketing operations, which may give them a competitive advantage. In addition, actual or potential competitors may be strengthened through the acquisition of additional assets and interests. If we are unable to compete effectively or respond adequately to competitive pressures, our results of operation and financial condition may be materially adversely affected.

Insufficient transportation or refining capacity in the Williston Basin could cause significant fluctuations in our realized oil and natural gas prices.

The Williston Basin crude oil business environment has historically been characterized by periods when oil production has surpassed local transportation and refining capacity, resulting in substantial discounts in the price received for crude oil versus prices quoted for WTI crude oil. Although additional Williston Basin transportation takeaway capacity has been added over the last several years, production also increased substantially during the same period. The increased production coupled with delays in rail car arrivals and commissioning of rail loading facilities has caused price differentials to significantly increase at times.

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

The U.S. Department of Transportation (“USDOT”) recently concluded that crude oil from the Bakken/Three Forks formations has a higher volatility than most other U.S. crude oil and thus is more ignitable and flammable. Based on that information, and several fires involving rail transportation of crude oil, USDOT has started a rulemaking process to develop new requirements for shipping crude oil by rail. In addition, the rail industry has adopted increased precautions for crude shipments. Any new restrictions that significantly affect transportation of crude oil production could materially and adversely affect our financial condition, results of operations and cash flows.

Regulation of crude oil transportation by rail.

A portion of our crude oil production is transported to market centers by rail. Recent derailments in North America of trains transporting crude oil have caused various regulatory agencies and industry organizations, as well as federal, state and municipal governments, to focus attention on transportation by rail of flammable materials. Transportation safety regulators in the United States and Canada are concerned that crude oil from the Bakken shale may be more flammable than crude oil from other producing regions and are investigating that issue and are also considering changes to existing regulations to address those possible risks. In May 2015, the Pipeline and Hazardous Materials Safety Administration ("PHMSA") adopted a final rule that, among other things, imposes a new and enhanced tank car design standard for certain tank cars carrying crude oil and ethanol, a phase out by as early as January 2018 for older DOT-111 tank cars that are not retrofitted, and a classification and testing program for unrefined petroleum based products, including crude oil. The rule also includes new operational requirements such as routing analyses, speed restrictions and enhanced braking controls. Transport Canada has also issued legal requirements that align with the rule adopted by PHMSA, including standards relating to train speed restrictions, route risk analyses and a phase out of non-compliant DOT-111 tank cars.

Any changes to existing laws and regulations, or promulgation of new laws and regulations, including any voluntary measures by the rail industry, that result in new requirements for the design, construction or operation of tank cars used to transport crude oil could increase our costs of doing business and limit our ability to transport and sell our crude oil at favorable prices at market centers throughout the United States, the consequences of which could have a material adverse effect on our financial condition, results of operations and cash flows.

To the extent that new regulations require design changes or other modifications of tank cars, we may incur significant constraints on transportation capacity during the period while tank cars are being retrofitted or newly constructed to comply with the new regulations. In addition, any derailment of crude oil from the Bakken shale involving crude oil that we have sold or are shipping may result in claims being brought against us that may involve significant liabilities. Although we believe that we are adequately insured against such events, we cannot assure you that our insurance policies will cover the entirety of any damages that may arise from such an event.

Market conditions or operational impediments may hinder our access to oil and natural gas markets or delay our production.

Market conditions or the unavailability of satisfactory oil and natural gas transportation arrangements may hinder our access to oil and natural gas markets or delay our production. The availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for and supply of oil and natural gas and the proximity of reserves to pipelines and terminal facilities. Our ability to market our production depends, in substantial part, on the availability and capacity of gathering systems, pipelines and processing facilities owned and operated by third-parties. Our failure to obtain such services on acceptable terms could materially harm our business. We may be required to shut in wells due to lack of a market or inadequacy or unavailability of crude oil or natural gas pipelines or gathering system capacity. If our production becomes shut-in for any of these or other reasons, we would be unable to realize revenue from those wells until other arrangements were made to deliver the products to market.

Legislative and regulatory developments could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.

In July of 2010, the United States Congress enacted the Dodd-Frank Wall Street Reform and Consumer Protection Act (“Dodd-Frank Act”), which contains measures aimed at increasing the transparency and stability of the over-the-counter (“OTC”) derivatives market and preventing excessive speculation. In November 2013, the CFTC re-proposed implementing regulations imposing position limits for certain physical commodity contracts in the major energy markets and economically equivalent futures, options and swaps, with exemptions for certain bona fide hedging positions. The CFTC’s initial position limit rules were vacated by a federal court in 2012. It is not clear when the newly-proposed rules on position limits would become effective. CFTC rules under the Dodd-Frank Act also may impose clearing and trade execution requirements in connection with our derivative activities; although currently those requirements do not extend to derivatives based on physical commodities in the energy markets and some or all of our derivatives activities may be exempt from such requirements based on our non-financial end-user status.

The legislation and regulations could significantly increase the cost of derivative contracts (including from swap recordkeeping and reporting requirements and through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. We maintain an active hedging program related to oil price risks, although we unwound many of the hedge positions that we held in September 2015. The Dodd-Frank Act and rules and regulations thereunder could reduce trading positions and the market-making activities of our counterparties. If we reduce our use of derivatives as a result of legislation and regulations or any resulting changes in the derivatives markets, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures or to make payments on our debt obligations. Finally, the legislation was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our business, our financial condition, and our results of operations.

Our business is subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of doing business.

Our operational interests, as operated by our third-party operating partners, are regulated extensively at the federal, state and local levels. Environmental and other governmental laws and regulations have increased the costs to plan, design, drill, install, operate and abandon oil and natural gas wells. Under these laws and regulations, our company (either directly or indirectly through our operating partners) could also be liable for personal injuries, property and natural resource damage and other damages. Failure to comply with these laws and regulations may result in the suspension or termination of our business and subject us to administrative, civil and criminal penalties. Moreover, public interest in environmental protection has increased in recent years, and environmental organizations have opposed, with some success, certain drilling projects.

Part of the regulatory environment in which we do business includes, in some cases, legal requirements for obtaining environmental assessments, environmental impact studies and/or plans of development before commencing drilling and production activities. In addition, our activities are subject to the regulations regarding conservation practices and protection of correlative rights. These regulations affect our business and limit the quantity of natural gas we may produce and sell. A major risk inherent in the drilling plans in which we participate is the need for our operators to obtain drilling permits from state and local authorities. Delays in obtaining regulatory approvals or 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 the development of our properties. Additionally, the oil and natural gas regulatory environment could change in ways that might substantially increase the financial and managerial costs of compliance with these laws and regulations and, consequently, adversely affect our profitability. At this time, we cannot predict the effect of this increase on our results of operations. Furthermore, we may be put at a competitive disadvantage to larger companies in our industry that can spread these additional costs over a greater number of wells and larger operating staff.

Environmental risks may adversely affect our business.

All phases of the crude oil and natural gas business present environmental risks and hazards and are subject to environmental regulation pursuant to a variety of federal, state and municipal laws and regulations. Environmental legislation provides for, among other things, restrictions and prohibitions on spills, releases or emissions of various substances produced in association with crude oil and natural gas operations. The legislation also requires that wells and facility sites be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. Compliance with such legislation can require significant expenditures, and a breach may result in the imposition of fines and penalties, some of which may be material.

Environmental legislation is evolving in a manner we expect may result in stricter standards and enforcement, larger fines and liability and potentially increased capital expenditures and operating costs. The discharge of crude oil, natural gas or other pollutants into the air, soil or water may give rise to liabilities to governments and third parties and may require us to incur costs to remedy such discharge. The application of environmental laws to our business may cause us to curtail our production or increase the costs of our production, development or exploration activities.

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

Hydraulic fracturing is used extensively by our third-party operating partners. The hydraulic fracturing process is typically regulated by state oil and natural gas commissions. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The Safe Drinking Water Act (the “SDWA”) regulates the underground injection of substances through the Underground Injection Control (“UIC”) program. While hydraulic fracturing generally is exempt from regulation under the UIC program, the EPA has taken the position that hydraulic fracturing with fluids containing diesel fuel is subject to regulation under the UIC program as “Class II” UIC wells. On October 21, 2011, the EPA announced its intention to propose federal Clean Water Act regulations governing wastewater discharges from hydraulic fracturing and certain other natural gas operations. In addition, the Department of Interior (“DOI”) published a revised proposed rule on May 24, 2013 that would update existing regulation of hydraulic fracturing activities on Federal and Indian lands, including requirements for disclosure, well bore integrity and handling of flowback water. The revised proposed rule was subject to an extended 90-day public comment period, which ended on August 23, 2013. To date, no final rule has been issued.

The EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities, and a committee of the U.S. House of Representatives is also conducting an investigation of hydraulic fracturing practices. The EPA issued a Progress Report in December 2012. In March, 2013, the EPA’s Scientific Advisory Board (“SAB”) formed an ad hoc panel of experts who are reviewing the Progress Report on the study. In August 2014, EPA announced that it planned to release the draft assessment for public comment and peer review. As part of these studies, both the EPA and the House committee have requested that certain companies provide them with information concerning the chemicals used in the hydraulic fracturing process. These studies, depending on their results, could spur initiatives to regulate hydraulic fracturing under the SDWA or otherwise. Congress has in recent legislative sessions considered legislation to amend the SDWA, including legislation that would repeal the exemption for hydraulic fracturing from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, were proposed in recent sessions of Congress. The U.S. Congress may consider similar SDWA legislation in the future.

On August 16, 2012, the EPA published final regulations under the Clean Air Act (“CAA”) that establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA promulgated New Source Performance Standards (“NSPS”) establishing emission limits for sulfur dioxide (SO2) and volatile organic compounds (VOCs). The final rule requires a 95% reduction in VOCs emitted by mandating the use of reduced emission completions or “green completions” on all hydraulically-fractured gas wells constructed or refractured after January 1, 2015. The rules also establish new requirements regarding emissions from compressors, controllers, dehydrators, storage tanks and other production equipment. In response to numerous requests for reconsideration of these rules from both industry and the environmental community and court challenges to the final rules, the EPA announced its intention to issue revised rules in 2013. The EPA published revised portions of these rules on September 23, 2013 for VOC emissions for production oil and gas storage tanks, in part phasing in emissions controls on storage tanks past October 15, 2013. On December 19, 2014, the EPA published updates to its NSPS for the oil and gas industry.

In addition, several state and local governments are considering or have adopted legislative or regulatory restrictions on hydraulic fracturing through additional permit requirements, operational restrictions, and temporary or permanent bans on hydraulic fracturing in certain environmentally sensitive areas such as watersheds. For example, Montana and North Dakota have both adopted regulations recently requiring the disclosure of all fluids, additives, and chemicals used in the hydraulic fracturing process. And, in 2014, North Dakota adopted new requirements aimed at capturing gas and reducing flaring.

A number of lawsuits and enforcement actions have been initiated across the country alleging that hydraulic fracturing practices have adversely impacted drinking water supplies, use of surface water, and the environment generally. If new laws or regulations that significantly restrict hydraulic fracturing, such as amendments to the SDWA, are adopted, such laws could make it more costly for us and difficult for our third party operating partners to perform fracturing to stimulate production from tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, if hydraulic fracturing is further regulated at the federal or state level, our third-party operating partners fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs.

In March of 2015, the Department of the Interior unveiled new regulations for hydraulic fracturing on federal lands. Any such federal or state legislative or regulatory changes with respect to hydraulic fracturing could cause us to incur substantial compliance costs or result in operational delays, and the consequences of any failure to comply by us or our third-party operating partners could have a material adverse effect on our financial condition and results of operations. Until such pending or threatened legislation or regulations are finalized and implemented, it is not possible to estimate their impact on our business.

Any of the above risks could impair our ability to manage our business and have a material adverse effect on our operations, cash flows and financial position.

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

The EPA has determined that emissions of certain “greenhouse gases” (“GHG”) present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. Based on its findings, the EPA has begun adopting and implementing regulations to restrict emissions of greenhouse gases under existing provisions of the Clean Air Act (the “CAA”). On September 22, 2009, the EPA issued a final rule requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the U.S. beginning in 2011 for emissions occurring in 2010. On November 30, 2010, the EPA published a final rule expanding its existing greenhouse gas emissions reporting rule to include certain petroleum and natural gas facilities, which rule requires data collection beginning in 2011 and reporting beginning in 2012. Our operating partners were required to report certain of their greenhouse gas emissions under this rule by September 28, 2012. On May 12, 2010, the EPA also issued a “tailoring” rule, which makes certain large stationary sources and modification projects subject to permitting requirements for greenhouse gas emissions under the CAA. On June 23, 2014, the U.S. Supreme Court inUtility Air Regulatory Group v. EPA, held that the EPA’s “Tailoring Rule” was invalid, but held that if a source was subject to PSD or Title V based on emissions of conventional pollutants like sulfur dioxide, particulates, nitrogen or dioxide, carbon monoxide, ozone and lead, then the EPA could also require the source to control GHGS and would have to install Best Available Control Technology to do so. As a result, a source no longer is required to meet PSD and Title V permitting requirements based solely on its GHG emissions. On February 23, 2014, Colorado became the first state in the nation to adopt rules to control methane emissions from Colorado oil and gas facilities. Subsequently, the Obama administration has approved rules that would require controls on methane emissions from oil and gas facilities. In addition, the EPA has continued to adopt GHG regulations of other industries, such as the September 2013 proposed GHG rule that, if finalized, would set new source performance standards for new coal-fired and natural gas-fired power plants. As a result of this continued regulatory focus, future GHG regulations of the oil and gas industry remain a possibility.

In addition, the U.S. Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases, though it is yet to do so, and almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances that correspond to their annual emissions of GHGs. The number of allowances available for purchase is reduced each year in an effort to achieve the overall GHG reduction goal. As the number of GHG emission allowances declines each year, the cost or value of such allowances is expected to escalate significantly. The adoption of legislation or regulatory programs to reduce emissions of greenhouse gases could require our third-party operating partners, and indirectly us, to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas produced by our operational interests. Consequently, legislation and regulatory programs to reduce emissions of greenhouse gases could have an adverse effect on our business, financial condition and results of operations.

Regulation of GHG emissions could also result in reduced demand for our production, as oil and natural gas consumers seek to reduce their own GHG emissions. Any regulation of GHG emissions, including through a cap-and-trade system, technology mandate, emissions tax, reporting requirement or other program, could have a material adverse effect on our business, results of operations and financial condition. In addition, to the extent climate change results in more severe weather and significant physical effects, such as increased frequency and severity of storms, floods, droughts and other climatic effects, our own, our third-party operating partners or our customers' operations may be disrupted, which could result in a decrease in our available products or reduce our customers' demand for our products.

Further, there have been various legislative and regulatory proposals at the federal and state levels to provide incentives and subsidies to (i) shift more power generation to renewable energy sources and (ii) support technological advances to drive less energy consumption. These incentives and subsidies could have a negative impact on oil, natural gas and NGL consumption.

Any of the above risks could impair our ability to manage our business and have a material adverse effect on our operations, cash flows and financial position.

Decommissioning costs are unknown and may be substantial, and unplanned costs could divert resources from other projects.

We may become responsible for costs associated with abandoning and reclaiming wells, facilities and pipelines which we use for production of crude oil and natural gas reserves. Abandonment and reclamation of these facilities and the costs associated therewith is often referred to as “decommissioning.” We accrue a liability for decommissioning costs associated with our wells, but have not established any cash reserve account for these potential costs in respect of any of our properties. If decommissioning is required before economic depletion of our properties or if our estimates of the costs of decommissioning exceed the value of the reserves remaining to cover such decommissioning costs, we may have to draw on funds from other sources to satisfy such costs. The use of other funds to satisfy such decommissioning costs could impair our ability to focus capital investment in other areas of our business.

The inability of one or more of our operating partners to meet their obligations to us may adversely affect our financial results.

Our principal exposures to credit risk are through receivables resulting from the sale of our oil and natural gas production ($4.2 million in receivables at December 31, 2015), which operating partners market on our behalf to energy marketing companies, refineries and their affiliates.

We are subject to credit risk due to the concentration of our oil and natural gas receivables with a limited number of operating partners. This concentration may impact our overall credit risk since these entities may be similarly affected by changes in economic and other conditions. The inability or failure of our operating partners to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results.

Our variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to increase significantly.

Borrowings under our Credit Facilities bear interest at variable rates and expose us to interest rate risk. If interest rates increase and we are unable to effectively hedge our interest rate risk, our debt service obligations on the variable rate indebtedness would increase even if the amount borrowed remained the same, and our net income and cash available for servicing our indebtedness would decrease. A one percent increase in interest rates on the debt outstanding under our Credit Facilities as of December 31, 2015 would cost us approximately $600,000 in additional annual interest expense.

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

In February 2016, President Obama's Administration released its proposed federal budget for fiscal year 2017 that would, if enacted into law, make significant changes to United States tax laws, including the elimination of certain key U.S. federal income tax preferences currently available to oil and gas exploration and production companies. Such changes include, but are not limited to:

It is unclear, however, whether any such changes will be enacted or how soon such changes could be effective. The passage of any legislation containing these or similar changes in U.S. federal income tax law could eliminate or defer certain tax deductions that are currently available with respect to oil and gas exploration and development, and any such changes could negatively affect our financial condition and results of operations.

An additional fee on oil may be imposed as a result of future legislation.

The Obama Administration's proposed federal budget for fiscal year 2017 would, if enacted into law, impose an additional $10.25 per barrel fee on oil to be phased-in over five years. Details on this proposal have not been made publicly available. It is unclear whether this proposed fee will be enacted or how soon it would be effective. The passage of an additional fee on oil could negatively affect our financial condition and results of operations.

We have a limited operating history and may not be successful in becoming profitable.

We have a limited operating history. Our business operations must be considered in light of the risks, expenses and difficulties frequently encountered in establishing a business in the crude oil and natural gas industries. There can be no assurance that our business operations will prove to be successful in the long-term. Our future operating results will depend on many factors, including: our ability to raise adequate working capital; success of our development and exploration; prices and demand for natural gas and crude oil; the level of our competition; our ability to attract and maintain key management and employees; and our ability to efficiently explore, develop and produce sufficient quantities of marketable natural gas or crude oil in a highly competitive and speculative environment while maintaining quality and controlling costs. To sustain profitable operations in the future, we must, alone or with others, successfully manage these factors, as well as continue to develop ways to enhance our production efforts. Despite our best efforts, we may not be successful in our exploration or development efforts, or obtain required regulatory approvals. There is a possibility that some of our wells may never produce natural gas or crude oil.

Strategic relationships upon which we may rely are subject to change, which may diminish our ability to conduct our operations.business.

Our ability to successfully acquiredevelop additional properties, to increaseassets for our reserves, to participate in drilling opportunities and to identify and enter into commercial arrangements with customerspartners under the umbrella that we manage will depend on developing and maintaining close working relationships with industry participants. Our success will also depend on our ability to select and evaluate suitable properties for our partners and to consummate transactions in a highly competitive environment. These realities are subject to change and our inability to maintain close working relationships with industry participants or continue to acquireidentify suitable properties may impair our ability to execute our business plan.

To continue to develop our business, we will use the business relationships of our management and develop new relationships to enter into strategic relationships. These relationships may take the form of mineral lease purchase agreements, joint ventures, joint operating agreements, referral agreements and other contractual arrangements with outside individuals and crude oil and natural gas companies. We may not be able to establish these strategic relationships, or if established, we may not be able to maintain them. In addition, the dynamics of our relationships with strategic partners may require us to incur expenses or undertake activities that we would not otherwise be inclined to do independent of these strategic relationships. If sufficient strategic relationships are not established and maintained, our business prospects, financial condition and results of operations may be materially adversely affected.

We may not be able to effectively manage our growth, which may harm our profitability.

Our strategy envisions the expansion of our business. If we fail to effectively manage our growth, our financial results could be adversely affected. Growth may place a strain on our management systems and resources. We must continue to refine and expand our business capabilities, our systems and processes and our access to financing sources. As we grow, we must continue to hire, train, supervise and manage new employees. We cannot assure that we will be able to:

If we are unable to manage our growth, our financial condition and results of operations may be materially adversely affected.

We may not be able to develop crude oil and natural gas reserves on an economically viable basis, and our reserves and production may decline as a result.

On a long-term basis, our viability depends on our ability to find or acquire, develop and commercially produce additional crude oil and natural gas reserves. Even if we continue to succeed in discovering crude oil and/or natural gas reserves, we cannot assure that these reserves will be capable of production levels we project or in sufficient quantities to be commercially viable. Without the addition of reserves through acquisition, exploration or development activities, our reserves and production will decline over time as reserves are produced. Our future reserves will depend not only on our ability to develop then-existing properties, but also on our ability to identify and acquire additional suitable producing properties or prospects, to find markets for the crude oil and natural gas we develop and to effectively distribute our production into our markets. Future crude oil and natural gas exploration may involve unprofitable efforts, not only from dry wells, but from wells that are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other costs. There is no assurance that advanced technology in the oil and gas industry such as three dimensional (3-D) seismic data and visualization techniques will result in the discovery of commercial quantities of hydrocarbons. Completion of a well does not assure a profit on the investment or recovery of drilling, completion and operating costs. In addition, drilling hazards or environmental damage could greatly increase the cost of operations, and various field operating conditions may adversely affect the production from successful wells. These conditions include delays in obtaining governmental approvals or consents, shut-downs of connected wells resulting from extreme weather conditions, problems in storage and distribution and adverse geological and mechanical conditions. As a non-operator of oil and gas wells, we do not have sufficient control to manage these conditions, and the risks from them generally cannot entirely be eliminated. Therefore, these conditions could diminish our revenue and cash flow levels and result in the impairment of our crude oil and natural gas interests.

Drilling new wells could result in new liabilities, which could endanger our interests in our properties and assets.

There are risks associated with the drilling of crude oil and natural gas wells, including encountering unexpected formations or pressures, premature declines of reservoirs, blow-outs, craterings, sour gas releases, fires and spills, among others. The occurrence of any of these events could significantly increase our costs or reduce our revenues or cause substantial losses, impairing our future operating results. WeCompany may become subject to liability for pollution, blow-outs or other hazards. We may seekthe requirements of the Investment Company Act of 1940, which would limit the Company’s business operations and require the Company to maintain insurance (including insurance maintained by our industry operators) with respectspend significant resources to these hazards; however, such insurance has limitations on liability that may not be sufficient to cover the full extent of such liabilities. The payment of such liabilities could reduce the funds available to us or could, in an extreme case, result in a total loss of our properties and assets. Moreover, we may not be able to maintain adequate insurance in the future at rates that are considered reasonable. Crude oil and natural gas production operations are also subject to all the risks typically associatedcomply with such operations, including premature decline of reservoirs and the invasion of water into producing formations.

Our business will suffer if we, or the operators of our properties, cannot obtain or maintain necessary licenses.act.

Our operations require licenses, permitsThe Investment Company Act of 1940 (the “Investment Company Act”) defines an “investment company” as an issuer that is engaged in the business of investing, reinvesting, owning, holding or trading in securities and owns investment securities having a value exceeding 40 percent of the issuer's unconsolidated assets, excluding cash items and securities issued by the federal government. While we believe that a reasonable investor would not conclude that we are engaged primarily in some cases renewals of licensesinvesting in securities based on our continued focus on acquiring, investing in, and permits from various governmental authorities. Our ability (ormanaging oil and gas assets, the abilitycurrent composition of our industry operators)assets, including our ownership of BRAC shares, could contribute to obtain, sustaina conclusion that we meet the threshold definition of an investment company. While the Investment Company Act also has several exclusions and exceptions that we would seek to rely upon to avoid being deemed an investment company, our reliance on any such exclusions or renew such licenses and permits on acceptable termsexceptions may be misplaced resulting in violation of the Investment Company Act, the consequences of which can be significant. For example, investment companies that fail to register under the Investment Company Act are prohibited from conducting business in interstate commerce, which includes selling securities or entering into other contracts in interstate commerce. Section 47(b) of the Investment Company Act provides that a contract made, or whose performance involves, a violation of the Investment Company Act is unenforceable by either party unless a court finds that enforcement would produce a more equitable result than non-enforcement. Similarly, a court may not deny rescission to any party seeking to rescind a contract that violates the Investment Company Act, unless the court finds that denial of rescission would produce more equitable result than granting rescission.

If we are be deemed to be an investment company under the Investment Company Act, Rule 3a-2 of the Investment Company Act provides that inadvertent or transient investment companies will not be treated as investment companies subject to change in regulations and policies and to the discretionprovisions of the applicable governmental authorities, among other factors. Our inability, Investment Company Act provided the issuer has the requisite intent to be engaged in a non-investment business, evidenced by the issuer’s business activities and an appropriate resolution of the issuer’s board of directors, within one year from the commencement of the earlier of (1) the date on which the issuer owns securities and/or cash having a value exceeding 50% of the inabilityvalue of our industry operators,such issuer's total assets on either a consolidated or unconsolidated basis, or (2) the date on which an issuer owns or proposes to obtain, or our lossacquire investment securities (as defined in section 3(a) of or denialthe Act) having a value exceeding 40% of extensionthe value of anysuch issuer's total assets (exclusive of these licenses or permits could hamper our abilitygovernment securities and cash items) on an unconsolidated basis. If the Company becomes an inadvertent investment company, and fails to produce revenues from our operations or otherwise materially adversely affect our financial condition and resultsmeet the requirements of operations.

We will rely on technology to conduct our business, and our technology could become ineffective or obsolete.

We rely on technology, including geographic and seismic analysis techniques and economic models, to develop our reserve estimates and to guide our acquisition, exploration, development and production activities. Wethe transient investment company exemption under Rule 3a-2 of the Investment Company Act, then we will be required to continually access enhancedregister as an investment company with the SEC.

The ramifications of becoming an investment company, both in terms of the restrictions it would have on our company and updated technologythe cost of compliance, would be significant. For example, in addition to maintain our capability andexpenses related to avoid obsolescence. The costs of doing so may be substantial and may be higher thaninitially registering as an investment company, the costs that we anticipate for technology maintenance and development. If we are unableInvestment Company Act also imposes various restrictions with regard to maintain the technology available to us, our ability to manageenter into affiliated transactions, the diversification of our assets and our ability to borrow money. If we became subject to the Investment Company Act at some point in the future, our ability to continue pursuing our business and to compete mayplan would be impaired. Further, even if we are able to maintain technical effectiveness, such technology may not be the most efficient means of reaching our objectives, in which case we may incur higher operating costs than we would were our technology more efficient.severely limited.

Risks Related to our Common Stock

The market price of our common stock is, and is likely to continue to be, highly volatile and subject to wide fluctuations.

The market price of our common stock is likely to continue to be highly volatile and could be subject to wide fluctuations in response to a number of factors, some of which are beyond our control, including but not limited to:

These and other factors are largely beyond our control, and the impact of these risks, singly or in the aggregate, may result in material adverse changes to the market price of our common stock and our results of operations and financial condition.

Our operating results may fluctuate significantly, and these fluctuations may cause the price of our common stock to decline.

Our operating results will likely vary in the future primarily as the result of fluctuations in our revenues and operating expenses, including the expenses that we incur the prices of crude oil and natural gas in the commodities markets and other factors. If our results of operations do not meet the expectations of current or potential investors, the price of our common stock may decline.

Shareholders will experience dilution upon the exercise of outstanding warrants and options and issuance of common stock under our incentive plans.

As of December 31, 2015,2019, we had options for 7,055,50022,492 shares of common stock outstanding under our 2012 Amended and Restated Stock Incentive Plan and options for an additional 11,712 shares of common stock outstanding under our 2016 Non-Qualified Stock Option Plan. Our 2012 Amended and RestatedIn addition, our 2020 Stock Incentive Plan permits us(the “2020 Equity Plan”) was approved by written consent of a majority of shareholders of record as of November 12, 2019 and adopted by the Board on December 5, 2019. On February 26, 2020, the Board granted an aggregate amount of 240,000 stock options to issue up to 7,500,000purchase shares of ourthe Company’s common stock either upon exercise of stock options granted under such plan or through restricted stock awards under such plan.to several officers, directors, and employees pursuant to the 2020 Equity Plan. If the holders of outstanding options exercise those options or our compensation committee or full board of directors determines to grant additional stock awards under our incentive plan, shareholders may experience dilution in the net tangible book value of our common stock. In addition, 8,548,375 shares of our common stock may be issued upon the exercise of warrants. If the holders of the outstanding warrants exercise their warrants, shareholders may experience dilution in the net tangible book value of our common stock. Further, the sale or availability for sale of the underlying shares in the marketplace as a result of the exercise of existing options and the grant of additional options and the exercise of the warrants could depress our stock price.

We do not expect to pay dividends in the foreseeable future.

We do not intend to declare dividends for the foreseeable future, as we anticipate that we will reinvest any future earnings in the development and growth of our business. In addition, our current Credit Facilities, and other debt arrangements we may enter into in the future precludeswill likely preclude us from paying dividends. Therefore, investors will not receive any funds unless they sell their common stock, and shareholders may be unable to sell their shares on favorable terms or at all. Investors cannot be assured of a positive return on investment or that they will not lose the entire amount of their investment in our common stock.

We may issue additional stock without shareholder consent.

Our board of directors has authority, without action or vote of the shareholders, to issue all or part of our authorized but unissued shares. Additional shares may be issued in connection with future financing, acquisitions, employee stock plans, or otherwise. Any such issuance will dilute the percentage ownership of existing shareholders. We are also currently authorized to issue up to 20,000,000 shares of preferred stock. The board of directors can issue preferred stock in one or more series and fix the terms of such stock without shareholder approval. Preferred stock may include the right to vote as a series on particular matters, preferences as to dividends and liquidation, conversion and redemption rights and sinking fund provisions. The issuance of preferred stock could adversely affect the rights of the holders of common stock and reduce the value of the common stock. In addition, specific rights granted to holders of preferred stock could discourage, delay or prevent a transaction involving a change in control of our company, even if doing so would benefit our shareholders. Such issuance could also discourage proxy contests and make it more difficult for you and other shareholders to elect directors of your choosing and to cause us to take other corporate actions you desire.

There is currently a limited trading market for our common stock and we cannot ensure that one will ever develop or be sustained.

To date there has not been a significant liquid trading market for our common stock. We cannot predict how liquid the market for our common stock might become. We currently do not satisfy the initial listing standards for any major securities exchange, although we intend to apply for such an exchange listing when we are able. Currently our common stock is traded on the OTCQB. Should we fail to remain traded on the OTCQB or not be able to be traded on the OTCQB, the trading price of our common stock could suffer, the trading market for our common stock may be less liquid and our common stock price may be subject to increased volatility. Furthermore, for companies whose securities are quoted on the OTCQB, it may be more difficult (i) to obtain accurate quotations, (ii) to obtain coverage for significant news events because major wire services generally do not publish press releases about such companies and (iii) to obtain needed capital.

Offers or availability for sale of a substantial number of shares of our common stock may cause the price of our common stock to decline.

If our stockholders sell substantial amounts of our common stock in the public market, or upon the expiration of any statutory holding period under Rule 144, or issued upon the exercise of outstanding options or warrants, it could create a circumstance commonly referred to as an “overhang” and in anticipation of which the market price of our common stock could fall. The existence of an overhang, whether or not sales have occurred or are occurring, also could hinder our ability to raise additional financing through the sale of equity or equity-related securities in the future at a time and price that we deem reasonable or appropriate.

If we undergo a reverse split of our common stock, which our Board and shareholders have currently approved that we do subject to the Board’s determination of the ratio of up to 1:10, the value of our common stock may be less than the market value of the common stock before the split multiplied by the split ratio.

As set forth in our information statement, filed with the SEC on March 26, 2012, our Board and shareholders have approved a reverse split of up to 1:10; we may in the future undergo a reverse stock split. After completion of such a reverse split, the post-split market price of our common stock may be less than the pre-split price multiplied by the split ratio. In addition, a reduction in the shares available in the public float may impair the liquidity in the market for our common stock which may reduce the value of our common stock. There is no assurance that the reverse stock split will allow us to meet the listing requirements of a national exchange. If we issue additional shares in the future, it will likely result in the dilution of our existing stockholders.

Risks Related to the BRHC Transaction

If we fail to complete the BRHC Transaction, the Company’s business may be harmed.

The Company cannot guarantee that the BRHC Transaction will be completed. Following the Company’s public announcement of the BRHC Transaction, third parties may be unwilling to enter into material agreements with the Company. Landowners may prefer to enter into sale agreements with the Company’s competitors because they perceive that the relationships are likely to be more stable. If the Company fails to complete the BRHC Transaction, the failure to maintain existing relationships or enter into new relationships may adversely affect the Company’s business, results of operations and financial condition.

The Company will incur significant expenses in connection with the BRHC Transaction.

The Company expects to pay legal fees, accounting fees and costs related to the BRHC Transaction whether the BRHC Transaction closes or not. Any significant expenses or payment obligations incurred by the Company in connection with the BRHC Transaction could adversely affect its financial condition and cash position.

If the BRHC Transaction disrupts the operations of the Company’s business and prevents the Company from realizing intended benefits, the business may be harmed.

The BRHC Transaction may disrupt the Company’s business and prevent it from realizing intended benefits as a result of a number of obstacles, such as: (i) the loss of key employees; (ii) the failure to adjust or implement its business strategies; (iii) additional expenditures required to facilitate the BRHC Transaction; and (iv) the diversion of management’s attention from the Company’s day-to-day operations.

Risks Related to the Business after the BRHC Transaction

The Company will have limited assets to generate cash to pay general and administrative expenses.

Following the closing of the BRHC Transaction, our assets will consist solely of our Class A Unit Membership Interest in BRHC and our interest in Merced Black Ridge, LLC. We will be reliant on the fees under our Management Services Agreement with BRHC and our management agreement with Merced Black Ridge, LLC in order to generate revenues until there are distributions related to such interests. We will continue to have general and administrative expenses to remain a public company.

Chambers may not provide additional funding to BRHC and any additional funding will reduce the Company’s Class A Units percentage ownership.

Chambers has committed $30 million of additional financing, of which $10 million will be invested at closing, which may be called by the BRHC Board subject to certain conditions. Capital calls may only be done with the approval of the BRHC Board. Chambers will control the BRHC Board. Any additional investment by Chambers shall serve to proportionately reduce the Company's Class A Units percentage ownership in BRHC.

Chambers will control BRHC and may engage in a sale of the interests in BRHC that will require the Company to sell all of its interests and the stockholders of the Company will have no right to consent to such sale.

Under the BRHC LLC Agreement, if Chambers sells all or substantially all of it is interests in BRHC, then Chambers can require the at the Company sell its interests in BRHC. As a condition though of the BRHC Transaction, Chambers requires that the Board be permitted to dispose of the Class A Units and Class B Units in BRHC without any subsequent consent of the Company’s stockholders. Nevada law permits a corporation to sell, lease or exchange all of its property and assets with only approval by the Company’s Board. As such, the Company may sell, lease or exchange all or substantially all of its assets (including its Class A Units and Class B Units in BRHC) without the consent of the Company’s stockholders, upon approval by the Board.

The Company may become subject to the requirements of the Investment Company Act of 1940, which would limit the Company’s business operations and require the Company to spend significant resources to comply with such act.

The Investment Company Act of 1940 (the “Investment Company Act”) defines an “investment company” as an issuer that is engaged in the business of investing, reinvesting, owning, holding or trading in securities and owns investment securities having a value exceeding 40 percent of the issuer's unconsolidated assets, excluding cash items and securities issued by the federal government. Because the value of our interest in BRHC will exceed 40 percent of our unconsolidated assets, excluding cash and government securities, we may meet this threshold definition of investment company. However, the Investment Company Act also excludes from this definition any person substantially all of whose business consists of owning or holding oil, gas or other mineral royalties or leases or fractional interests therein, or certificates of interest or participation relating to such mineral royalties or leases. We believe that we may satisfy this oil and gas company exception to the definition of investment company after consummation of the BRHC Transaction. If our reliance on the oil and gas company exclusion from the definition of investment company is misplaced, we may be in violation of the Investment Company Act, the consequences of which can be significant. For example, investment companies that fail to register under the Investment Company Act are prohibited from conducting business in interstate commerce, which includes selling securities or entering into other contracts in interstate commerce. Section 47(b) of the Investment Company Act provides that a contract made, or whose performance involves, a violation of the Investment Company Act is unenforceable by either party unless a court finds that enforcement would produce a more equitable result than non-enforcement. Similarly, a court may not deny rescission to any party seeking to rescind a contract that violates the Investment Company Act, unless the court finds that denial of rescission would produce more equitable result than granting rescission.

If in the future the nature of our business changes such that the oil and gas company exception to the threshold definition of investment company is not available to us or if we are unable to rely on the oil and gas company exception because our interest in oil and gas interests is indirect through our ownership in BRHC, we may be deemed to be an investment company under the Investment Company Act. However, Rule 3a-2 of the Investment Company Act provides that inadvertent or transient investment companies will not be treated as investment companies subject to the provisions of the Investment Company Act provided the issuer has the requisite intent to be engaged in a non-investment business, evidenced by the issuer’s business activities and an appropriate resolution of the issuer’s board of directors, within one year from the commencement of the earlier of (1) the date on which the issuer owns securities and/or cash having a value exceeding 50% of the value of such issuer's total assets on either a consolidated or unconsolidated basis, or (2) the date on which an issuer owns or proposes to acquire investment securities (as defined in section 3(a) of the Act) having a value exceeding 40% of the value of such issuer's total assets (exclusive of government securities and cash items) on an unconsolidated basis. If the Company becomes an inadvertent investment company, and fails to meet the requirements of the transient investment company exemption under Rule 3a-2 of the Investment Company Act, then we will be required to register as an investment company with the SEC.

The ramifications of becoming an investment company, both in terms of the restrictions it would have on our company and the cost of compliance, would be significant. For example, in addition to expenses related to initially registering as an investment company, the Investment Company Act also imposes various restrictions with regard to our ability to enter into affiliated transactions, the diversification of our assets and our ability to borrow money. If we became subject to the Investment Company Act at some point in the future, our ability to continue pursuing our business plan would be severely limited.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

Executive Offices

Our executive offices are located at 10275 Wayzata Boulevard,110 North Fifth Street, Suite 100, Minnetonka,410, Minneapolis, Minnesota 55305. We lease 2,81355403. Our office space consists of approximately 2,786 square feet leased pursuant to a month-to-month lease agreement that commenced on May 1, 2012 and was amended effective November 15, 2013. In accordance with this lease, our lease term remains on a month-to-month basis, provided that either party may provide 90 day notice to terminate the lease, with base rents of $2,110 per month, plus common area operations and maintenance charges, and monthly parking fees of $240 per month, for the period from November 15, 2013 to October 31, 2014, and increases of $117 per month beginning November 1, 2014 and each of the subsequent three year periods. The owner of the building in which we are located is a company wholly owned by our chairman of the board of directors.agreement.

Leasehold Properties

As of December 31, 2015, the Company controls approximately 8,100 net acres all in the Bakken and Three Forks trends in North Dakota and Montana. The leases we control have an initial minimum term of three years from the date acquired.

Acreage

The following table summarizes our estimated gross and net developed and undeveloped acreage by state at December 31, 2015. Net acreage represents our percentage ownership of gross acreage.

Recent Acreage Acquisitions

In 2015, we acquired leasehold interests covering an aggregate of approximately 9 net mineral acres in our key prospect areas.

Recent Divestitures

In 2015, we sold leasehold interests covering an aggregate of approximately 14 net mineral acres and rights to individual wellbores for total proceeds of $127,348. The proceeds of the sales were applied to reduce the capitalized costs of oil and natural gas properties.

Undeveloped Acreage Expirations

The following table sets forth the number of gross and net undeveloped acres as of December 31, 2015 that will expire over the next three fiscal years and thereafter unless production is established within the spacing units covering the acreage prior to the expiration dates:

Of the remaining undeveloped acreage leases that expire in 2016, 2017 and 2018, there are 112 acres, -0- acres and -0- acres, respectively, in which we have options to extend the lease.

During 2015, we had leases encompassing 1,866 net acres expire with carrying costs of approximately $2.0 million that have been transferred to the full cost pool subject to depletion. Of the leases encompassing 1,114 net acres expiring in 2016, we estimate that all of those net acres with carrying costs of approximately $0.7 million will expire prior to the commencement of production activities. Additionally, we have reduced the basis of the leasehold interests of the remaining 788 acres expiring in future periods to reflect the market value of those leasehold interests. The carrying costs of the leasehold interests we estimate will expire in 2016 have also been transferred to the full cost pool and are subject to depletion. We do not believe the acreage expirations are material to our operating plan in future periods.

Productive Oil Wells

The following table summarizes gross and net productive oil wells by state at December 31, 2015 and 2014. A net well represents our percentage ownership of a gross well. The Company purchased or participated in the completion of 102 gross (3.07 net) wells in the period ending December 31, 2015 and participated in the completion of 94 gross (3.01 net) wells in the period ended December 31, 2014. The Company had no dry wells drilled in either the year ended December 31, 2015 or 2014. The following table does not include wells in which our interest is limited to overriding royalty interests. The following table also does not include wells which were awaiting completion, in the process of completion or awaiting flow back subsequent to fracture stimulation.

Exploratory Oil Wells

The following table summarizes gross and net exploratory wells as of December 31, 2015 and 2014. The wells are at various stages of completion and the costs incurred are included in unevaluated oil and natural gas properties on our balance sheet.

Research and Development

We do not anticipate performing any significant product research and development under our plan of operation.

Delivery Commitments

We do not currently have any delivery commitments for product obtained fromunder our wells.

Drilling and Other Exploratory and Development Activities

Production History

The following table presents information about our produced oil and gas volumes during the years ended December 31, 2015 and 2014, respectively. Asplan of December 31, 2015 and 2014 we were selling oil and natural gas from a total of 349 gross wells (approximately 10.95 net wells) and 247 gross wells (approximately 7.88 net wells), respectively. All data presented below is derived from accrued revenue and production volumes for the relevant period indicated.operation.

Reserves

We completed our most recent reserve calculations as of December 31, 2015.

Preparation of our reserve report is outlined in our Sarbanes-Oxley Act Section 404 internal control procedures. Our procedures require that our reserve report be prepared by a third-party registered independent engineering firm at the end of every year based on information we provide to such engineer. For our year-end reports we utilized a contracted internal reserve engineer to aid in the preparation of our reserve estimates. Our internal reserve engineer holds a Bachelor of Science degree in Petroleum and Natural Gas Engineering from Pennsylvania State University and has over 35 years of experience in North America and International exploration and production activities. We accumulate historical production data for our wells, calculate historical lease operating expenses and differentials, update working interests and net revenue interests, obtain updated authorizations for expenditure (“AFEs”) from our operations department and obtain geological and geophysical information from operators. This data is forwarded to our third-party engineering firm for review and calculation. Our Chief Executive Officer provides a final review of our reserve report and the assumptions relied upon in such report.

We have utilized Netherland, Sewell & Associates, Inc. (“NSAI”), an independent reservoir engineering firm, as our third-party engineering firm with the preparation of our December 31, 2015 reserve report. The selection of NSAI was approved by our Audit Committee. NSAI is a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-2699. Within NSAI, the technical persons primarily responsible for preparing the estimates set forth in the NSAI reserves report incorporated herein are Mr. Dan Paul Smith and Mr. John Hattner. Mr. Smith has been practicing consulting petroleum engineering at NSAI since 1980. Mr. Smith is a Licensed Professional Engineer in the State of Texas (License No. 49093) and has over 30 years of practical experience in petroleum engineering and in the estimation and evaluation of reserves. He graduated from Mississippi State University in 1973 with a Bachelor of Science Degree in Petroleum Engineering. Mr. Hattner has been practicing consulting petroleum geology at NSAI since 1991. Mr. Hattner is a Licensed Professional Geoscientist in the State of Texas, Geology, (License No. 559) and has over 30 years of practical experience in petroleum geosciences, with over 20 years of experience in the estimation and evaluation of reserves. He graduated from University of Miami, Florida, in 1976 with a Bachelor of Science Degree in Geology; from Florida State University in 1980 with a Master of Science Degree in Geological Oceanography; and from Saint Mary's College of California in 1989 with a Master of Business Administration Degree. Both technical principals meet or exceed 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; both are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.

The proved reserves tables below summarize our estimated proved reserves as of December 31, 2015, based upon reports prepared by NSAI. The reports of our estimated proved reserves in their entirety are based on the information we provide to them.

In accordance with applicable requirements of the SEC, estimates of our net proved reserves and future net revenues are made using average prices at the beginning of each month in the 12-month period prior to the date of such reserve estimates and are held constant throughout the life of the properties (except to the extent a contract specifically provides for escalation).

The reserves set forth in the NSAI report for the properties are estimated by performance methods or analogy. In general, reserves attributable to producing wells and/or reservoirs are estimated by performance methods such as decline curve analysis which utilizes extrapolations of historical production data. Reserves attributable to non-producing and undeveloped reserves included in our report are estimated by analogy. The estimates of the reserves, future production, and income attributable to properties are prepared using the economic software package PHDWin Petroleum Economic Evaluation Software, a copyrighted program of TRC Consultants, L.C.

To estimate economically recoverable crude oil and natural gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future of production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be demonstrated to be economically producible based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined as of the effective date of the report. With respect to the property interests we own, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, production taxes, recompletion and development costs and product prices are based on the SEC regulations, geological maps, well logs, core analyses, and pressure measurements.

The reserve data set forth in the NSAI report represents only estimates, and should not be construed as being exact quantities. They may or may not be actually recovered, and if recovered, the actual revenues and costs could be more or less than the estimated amounts. Moreover, estimates of reserves may increase or decrease as a result of future operations.

Reservoir engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be measured in an exact manner. There are numerous uncertainties inherent in estimating crude oil and natural gas reserves and their estimated values, including many factors beyond our control. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geologic interpretation and judgment. As a result, estimates of different engineers, including those used by us, may vary. In addition, estimates of reserves are subject to revision based upon actual production, results of future development and exploration activities, prevailing crude oil and natural gas prices, operating costs and other factors. The revisions may be material. Accordingly, reserve estimates are often different from the quantities of crude oil and natural gas that are ultimately recovered and are highly dependent upon the accuracy of the assumptions upon which they are based. Our estimated net proved reserves, included in our SEC filings, have not been filed with or included in reports to any other federal agency.

Due to the Company’s liquidity position all proven undeveloped reserves not committed to be developed as of December 31, 2015 have been removed from the reserves due to uncertainties about the Company’s ability to fund future development.

______________________

The tables above assume prices and costs discounted using an annual discount rate of 10% without future escalation, without giving effect to non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization, or federal income taxes. The “Pre-tax PV10%” values of our proved reserves presented in the foregoing tables may be considered a non-GAAP financial measure as defined by the SEC.

Uncertainties are inherent in estimating quantities of proved reserves, including many risk factors beyond our control. Reserve engineering is a subjective process of estimating subsurface accumulations of crude oil and natural gas that cannot be measured in an exact manner. As a result, estimates of proved reserves may vary depending upon the engineer valuing the reserves. Further, our actual realized price for our crude oil and natural gas is not likely to average the pricing parameters used to calculate our proved reserves. As such, the crude oil and natural gas quantities and the value of those commodities ultimately recovered from our properties will vary from reserve estimates.

Based on the results of our December 31, 2015 reserve analysis, our proved reserves decreased approximately 56% from, 5,355,726 Boe at December 31, 2014 to 2,335,197 Boe at December 31, 2015, primarily due to revisions of previous quantity estimates. We incurred approximately $18.1 million of capital expenditures for drilling activities and $0.1 million for acreage and other expenditures during the year ended December 31, 2015, all of which increased our proved developed reserves. No other expenditures materially contributed to the development of proved developed reserves in 2015. As of December 31, 2015, we had 46,988 Boe of proved undeveloped reserves, which is a decrease of 3,282,044 Boe, or 99%, compared with 3,329,032 Boe of proved undeveloped reserves at December 31, 2014. The decrease in proved undeveloped reserves is primarily due to revisions of previous quantity estimates driven by the drop in oil prices, conversion of proved undeveloped reserves to proved developed reserves and removal of proved undeveloped reserves not committed to be developed as of December 31, 2015 due to uncertainties about the Company’s ability to fund future development. During 2015, our progress toward converting proved undeveloped reserves to proved developed reserves included the drilling and completion of 102 gross (3.07 net) undeveloped wells at a total estimated net capital cost of $23.8 million.

During 2015, we had a negative revision of 2,067,486 Boe, or 62%, of our December 31, 2014 estimated proved undeveloped reserves balance. The primary cause for these revisions related to wells that were non-economical due to lower oil prices and wells that were removed due to uncertainties around the Company’s ability to fund future development. The following table details the changes in the quantity of proved undeveloped reserves during the year ended December 31, 2015:

Depletion of Oil and Natural Gas Properties

Our depletion expense is driven by many factors including certain exploration costs involved in the development of producing reserves, production levels and estimates of proved reserve quantities and future developmental costs. The following table presents our depletion expenses for the years ended December 31, 2015 and 2014.

Impairment of Oil and Natural Gas Properties

As a result of currently prevailing low commodity prices and their effect on the proved reserve values of properties in 2015, we recorded a non-cash ceiling test impairment of $71,272,000 for the year ended December 31, 2015. The Company did not have any impairment of its proved oil and gas properties for the year ended December 31, 2015. The impairment charge affected our reported net income but did not reduce our cash flow. The following table presents our impairment charges for the years ended December 31, 2015 and 2014.

ITEM 3. LEGAL PROCEEDINGS

From time to time, we may become involved in various lawsuits and legal proceedings which arise in the ordinary course of business. However, litigation is subject to inherent uncertainties, and an adverse result in these or other matters may arise from time to time that may harm our business. We are not presently a party to any material litigation, nor to the knowledge of management is any litigation threatened against us, which may materially affect us.

ITEM 4. MINE SAFETY DISCLOSURES

None.

PART II

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

Common Stock

Our common stock is currently quoted on the OTCQB under the symbol “ANFC.” The range of high and low bid information for each fiscal quarter during 2015 and 2014 are set forth below:

The above quotationsQuotations on the OTCQB reflect inter-dealer prices, without retail markup, mark-down, or commission and may not necessarily represent actual transactions. The closing price of

Effective February 21, 2020, our common stock on the OTCQB on March 24, 2016 was $0.07 per share.underwent a 1-for-300 reverse split, which is retrospectively reflected throughout this Form 10-K/A.

As of March 24, 2016,15, 2020, there were approximately 1,900330 record holders of our common stock, not including shares held in “street name” in brokerage accounts which is unknown. As of March 24, 2016,15, 2020, there were 47,979,9901,600,484 shares of common stock outstanding on record.

Dividends

We have not declared or paid any dividends on our common stock since our inception and do not anticipate paying dividends for the foreseeable future. The payment of dividends is subject to the discretion of our board of directors and will depend, among other things, upon our earnings, our capital requirements, our financial condition, and other relevant factors. We intend to reinvest any earnings in the development and expansion of our business. Any cash dividends in the future to common shareholders will be payable when, as and if declared by our board of directors, based upon the board’s assessment of our financial condition and performance, earnings, need for funds, capital requirements, prior claims of preferred stock to the extent issued and outstanding, and other factors, including income tax consequences, restrictions and applicable laws.There can be no assurance, therefore, that any dividends on our common stock will ever be paid.

Equity Compensation Plan Information

Effective March 2, 2012, the 2012 Amended and Restated Stock Incentive Plan (the “2012 Plan”) was approved by our Board and the holders of a majority of our outstanding shares, replacing the Ante5, Inc. 2010 Stock Incentive Plan. Amongst other things, ourthe 2012 Amended and Restated Stock Incentive Plan increased the number of shares reserved under the Plan to a total of 7,500,00025,000 shares of our common stock. The following table sets forth certain information regarding the 2012 Plan as of December 31, 2019:

For the fiscal years ended December 31, 2019 and 2018, we issued no stock options pursuant to the 2012 Plan. There were 908 and 246 options cancelled or forfeited pursuant to the 2012 Plan during the years ended December 31, 2019 and 2018, respectively.

Effective December 12, 2016, the 2016 Non-Qualified Stock Option Plan (the “2016 Plan”) was approved by our Board. Amongst other things, the 2016 Plan authorized a total of 12,712 shares of our common stock. The following table sets forth certain information regarding our 2012 Amended and Restated Stock Incentive2016 Plan as of December 31, 2015:2019:

For the fiscal years ended December 31, 20152019 and 2014,2018, we issued a total of 1,000,000 and 632,500no stock options respectively, pursuant to our 2012 Amended and Restated Stock Incentivethe 2016 Plan. There were 1,153,334833 and 63,500-0- options cancelled or forfeited pursuant to the 2016 Plan during the years ended December 31, 20152019 and 2014,2018, respectively.

Warrants

We didn’t issue any warrants to purchase shares of registered or unregistered common stock for the fiscal years ended December 31, 20152019 and 2014.2018, respectively. There were 585,000 and 330,000no warrants forfeited or expired during the years ended December 31, 20152019 and 2014,2018. There were -0- and 150 warrants exercised during the years ended December 31, 2019 and 2018, respectively. A total of 1,300 warrants were outstanding as of December 31, 2019.

Unregistered Issuance of Equity Securities

We did not issue securities during the fiscal year ending December 31, 2015 in transactions exempt from registration that were not previously included in a Quarterly Report on Form 10-Q or in a Current Report on Form 8-K filed by us with the SEC.None.

ITEM 6. SELECTED FINANCIAL DATA.

Not applicable.

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion should be read in conjunction with our financial statements and notes to those statements. In addition to historical information, the following discussion and other parts of this annual report contain forward-looking information that involves risks and uncertainties.

Overview and Outlook

We are an oil and natural gas exploration and production company. Our properties are located in North Dakota and Montana. Our corporate strategy is the acquisition, exploration, development and production of crude oil and natural gas properties, primarily in the Bakken and Three Forks trends in North Dakota and Montana. As of December 31, 2015, we controlled the rights to mineral leases covering approximately 8,100 net acres for prospective drilling to the Bakken and/or Three Forks formations.

Looking forward, we are in the midst of satisfying the conditions to close on a restructuring transaction with our secured lenders that is described below in “Recent Developments.” We expect to complete such transaction in April 2015. Following such transaction, our focus will be on managing the oil and gas assets that we will continue to have an indirect minority interest in. In addition, we will continue to pursue distressed asset acquisitions in the Bakken and/or Three Forks formation that may be acquired with capital from our secured lenders as part of the restructuring terms, existing joint venture partners or other capital providers.

Effective April 2, 2012, we changed our name to Black Ridge Oil & Gas, Inc. Our common stock is still tradedquoted on the OTCQB under the trading symbol “ANFC.”

OverviewAs the sponsor and manager of 2015 resultsBlack Ridge Acquisition Corp. (“BRAC”) beginning in May of 2017, the Company was focused on identifying and closing a business combination for BRAC, which closed on August 9, 2019. Upon BRAC (renamed Allied Esports Entertainment, Inc. following the merger or “AESE”, and hereafter named as such following the merger) completing its business combination, we continued to provide additional management services to BRAC until December 31, 2019.

During 2015, we hadFollowing the following financial and operating results:

Operationally, our 2015 performance reflects a year of successfully executing our strategy of growing production while curtailing investment in new wells beyond our commitments at the beginningclose of the year. Our proved reserves decreased by 3.0 million Boe, inMerger, the Company commenced a large part duestrategic review to identify, review and explore alternatives for the Company, including a 99% decrease in proved undeveloped reservesmerger, acquisition, or a business combination. The Company currently owns 2,685,500 Sponsor Shares. Of those shares, 537,100 of the Sponsor Shares are subject to distribution rights to officers and directors under the 2018 Management Incentive Plan dated March 6, 2018. Black Ridge is evaluating plans for the remaining Sponsor Shares which could include a distribution of some or all of the Sponsor Share proceeds after expiration of the lock-up agreement on August 9, 2020, presuming that as of such date AESE has repaid or converted amounts it owes pursuant to the drop in the pricebridge financing Note Purchase Agreement and Notes dated as of oil has made much of our inventory in undeveloped wells uneconomicOctober 11, 2018 and we have removed all uncommitted proved undeveloped reserves due to uncertainties about the Company’s ability to fund future development. During 2015, production increased 46% to 425,625 Boe as compared to 2014 production of 291,780 Boe. The increase in 2015 production was driven by a 39% increase in net producing wells from 7.88 net wells at December 31, 2014 to 10.95 net wells at December 31, 2015.May 17, 2019.

Total revenues from oilBRAC Business Combination

On December 19, 2018, BRAC entered into an Agreement and gas sales decreased 28%Plan of Reorganization (the “Merger Agreement”) with Black Ridge Merger Sub, Corp., a Delaware corporation and wholly-owned subsidiary of BRAC’s (“Merger Sub”), Allied Esports Entertainment, Inc. (“Allied Esports”), Ourgame International Holdings Ltd. (“Ourgame”), Noble Link Global Limited, a wholly-owned subsidiary of Ourgame (“Noble”), and Primo Vital Ltd., also a wholly-owned subsidiary of Ourgame (“Primo”).

Pursuant to the Agreement, as amended on August 5, 2019, (i) Noble merged with and into Allied Esports (the “Redomestication Merger”) with Allied Esports continuing as the surviving entity in 2015 comparedsuch merger and (ii) immediately after the Redomestication Merger, Merger Sub merged with and into Allied Esports with Allied Esports continuing as the surviving entity of such merger (the “Transaction Merger” and together with the Redomestication Merger, the “Mergers” or the “Proposed Business Combination”) and became a wholly-owned subsidiary of BRAC. The Mergers closed on August 9, 2019 (the “Closing Date”).

The Mergers resulted in BRAC acquiring two of Ourgame’s global esports and entertainment assets, Allied Esports and WPT. Allied Esports is a premier esports entertainment company with a global network of dedicated esports properties and content production facilities. WPT is the creator of the World Poker Tour® (WPT®) – the premier name in internationally televised gaming and entertainment with brand presence in land-based tournaments, television, online and mobile. The transaction strategically combined the globally recognized Allied Esports brand with the three-pronged business model of the iconic World Poker Tour, featuring in-person experiences, multiplatform content and interactive services, to 2014 driven by a decreaseleverage the high-growth opportunities in average realized prices on a Boe basis, before the effect of settled derivatives of 51% and offset by a 46% increase in production in 2015 compared to 2014. Significant changes in crude oil and natural gas prices can have a material impact on our results of operations and our balance sheet.global esports industry.

Further information regarding the Business Combination, the combined company following consummation of the Business Combination and the risks related to the business of the combined company following consummation of the Business Combination can be found in BRAC’s Current Report on Form 8-K filed with the Securities and Exchange Commission on December 20, 2018, the preliminary proxy statement filed by BRAC with the Securities and Exchange Commission on February 15, 2019 (and subsequently amended on April 29, 2019, May 20, 2019 and June 5, 2019 and the definitive proxy statement filed by BRAC with the Securities and Exchange Commission on June 12, 2019.

The Extension Meeting

On July 9, 2019, BRAC held a special meeting of its stockholders (the “Meeting”). At the Meeting, BRAC’s stockholders considered a proposal to adopt and approve an amendment to BRAC’s amended and restated certificate of incorporation (the “Charter”) to extend the date that BRAC has to consummate a business combination (the “Extension”) to August 10, 2019. The amendment was approved by the stockholders and filed with the Secretary of State of the State of Delaware on July 9, 2019.

In connection with this vote, the holders of 9,246,727 shares of BRAC’s common stock properly exercised their right to convert their shares into cash at a conversion price of approximately $10.29 per share resulting in $95,125,574 in Trust Account assets being distributed back to shareholders. In connection with the Extension, BROG, loaned $30,000 to BRAC to be placed in the Trust Account for the benefit of the public shares that were not converted. The loan is non-interest bearing and is evidenced by a promissory note issued by BRAC on the same date. The loan was repaid by BRAC on August 12, 2019.

Amendment to the Business Combination Agreement

On August 5, 2019, BRAC entered into an amendment (the “Amendment”) to the Business Combination Agreement. The Amendment reduced the closing condition originally contained in the Business Combination Agreement requiring BRAC to have minimum cash on hand following the proper exercise of conversion rights by the holders of public shares from at least $80,000,000 to $22,000,000. This condition was waived by Ourgame prior to the close of the Business Combination. The Business Combination Agreement also originally provided for BRAC to repay $35,000,000 of indebtedness of Allied Esports and the World Poker Tour owed to Ourgame in cash at the closing of the transactions (the “Closing”). Pursuant to the Amendment, the parties agreed that instead of paying the full $35,000,000 in cash at the Closing, BRAC would (i) assume $10,000,000 of the debt obligations of Ourgame and Noble (including an additional $1,200,000 of accrued interest) and (ii) repay Ourgame the remaining balance of $23,800,000 by paying $3,500,000 in cash to Ourgame and its designees, issuing to Ourgame and its designees 2,928,679 shares of BRAC’s common stock and Ourgame retaining $1,000,000 of the proceeds of such loans to pay its transaction expenses incurred in the Merger. In connection with entering into the Amendment, BROG agreed to transfer an aggregate of 600,000 shares of BRAC’s common stock held by it to Ourgame.

In connection with the execution of the Amendment, the parties entered into an amendment and acknowledgment agreement (“Acknowledgment Agreement”) whereby the terms of the previously issued convertible notes (“Notes”) of Allied Esports and WPT (collectively “AEII/WPT”) whereby bridge holders provided $14 million to be used for the operations of AEII/WPT were amended. Pursuant to the Acknowledgement Agreement, the bridge holders have agreed to defer repayment of the Notes to one year and two weeks following the Closing (the “Maturity Date”). In consideration of agreeing to the deferred repayment, the bridge holders will be paid an additional six months of interest (i.e., a total of 18 months of interest) to the extent any bridge holder elects not to convert their Note to equity. BRAC agreed to assume the debt under the Notes as part of the mergers contemplated by the Agreement, and agreed that the debt will be secured by all the assets of BRAC following the Closing. BROG, as the Sponsor, has also agreed that it will not make any further transfer of its securities of BRAC, subject to certain exceptions, until the debt is repaid. The Notes are convertible at any time by a holder between the Closing and the Maturity Date at the “Conversion Price.” The “Conversion Price” is the lesser of $8.50 per share or the price at which shares are issued to Ourgame or its affiliates in connection with the mergers.

In July and August 2019, BRAC and BROG also entered into several share purchase agreements (the “Purchase Agreements”) with several parties (collectively referred to as the “Purchasers”). Pursuant to the Purchase Agreements, the Purchasers agreed to purchase an aggregate of $18,000,000 of shares of BRAC’s common stock in open market or privately negotiated transactions. If the Purchasers are unable to purchase the full $18,000,000 of shares of common stock in open market or privately negotiated transactions, BRAC will issue to the Purchasers newly issued shares at the Closing at a per-share price equal to the per-share amount held in BRAC’s trust account (currently approximately $10.30 per share), and having an aggregate value equal to the difference between $18,000,000 and the dollar amount of shares purchased by them in the open market or in privately negotiated transactions. One of the agreements also contains certain restrictions on the use of cash from the purchase. At the Closing, BRAC agreed to issue to the Purchasers 1.5 shares of common stock for every 10 shares purchased by them under the Purchase Agreements. Additionally, BROG agreed to transfer an aggregate of 720,000 shares held by it of BRAC common stock to the Purchasers. Pursuant to the Purchase Agreements, BRAC was required to file a registration statement with the SEC as promptly as practicable following Closing to register the resale of any securities purchased by the Purchasers that are not already registered and cause such registration statement to become effective as soon as possible. The registration statement was filed by AESE on September 20, 2019 and became effective on October 3, 2019. The Purchasers included a $3 million investment from Lyle Berman, a member of the board of directors of both BRAC and BROG and the largest shareholder of BROG. Additionally, $5 million will be held in an escrow account and its usage will be limited to specific capital projects.

Closing of the Business Combination

The Business Combination was closed on August 9, 2019. In connection with the closing, the holders of 3,015,124 shares of the Company’s common stock properly exercised their right to convert their shares into cash at a conversion price of approximately $10.31 per share resulting in $31,080,410 in Trust Account assets being distributed back to shareholders. Additionally, the Purchasers fulfilled their purchase commitments purchasing approximately $12.1 million of BRAC’s shares in the open market or through privately negotiated transactions and directly purchasing 479,546 additional shares of BRAC common stock for $4.9 million directly from BRAC.

Commensurate with the Business Combination BROG converted $600,000 of convertible loans to BRAC into 60,000 units (comprised 66,000 shares after conversion of stock rights and 60,000 warrants with terms similar to the IPO warrants). The remaining $150,000 in convertible loans were returned in cash by BRAC to BROG. Additionally, the underwriter agreed to an amendment to its agreement, modifying its payment due at the close of the Business Combination to $4 million, $2 million in cash and $2 million in equity. Other advisors used in the transaction agreed to accept payment for $3.8 million in contingent fees in BRAC equity.

Upon, the close of the Business Combination, BROG owned 2,685,500 shares of BRAC stock, representing approximately 11.6% of the outstanding shares of BRAC. As per the Black Ridge Oil & Gas, Inc. 2018 Management Incentive Plan, 20% of the shares, or 537,100 shares, owned by BROG are committed to employees and directors of the Company. Additionally, as the conditions warranting BROG’s treatment of BRAC as a VIE have been eliminated, BRAC will no longer be accounted for as a VIE and consolidated for financial statement reporting purposes from the date of the closing of the Business Combination forward.

Going Concern Uncertainty

As of December 31, 2019, the Company had a cash balance was $108,756 and total working capital of negative $1,289,995. We will continue to have general and administrative expenses to remain a public company and continue with our business plan. The Company’s liquidity outlook has changed sincecash on hand would be insufficient to cover our current cash needs over the third quarter of 2015 due to continued low commodity prices, which are expected to result in significantly lower levels of cash flow from operating activities in the future as the Company’s current commodity derivative contracts expire, and have limited the Company’s ability to access the capital markets. In addition, the Senior Credit Facility is subject to scheduled redeterminations of its borrowing base, semi-annually in April and October, based primarily on reserve reports using lender commodity price expectations at such time. Continued low commodity prices, reductions in the Company’s capital budget and the resulting reserve write-downs, along with the maturity schedule of the Company’s hedges, are expected to adversely impact the upcoming April redeterminations and will likely have a significant negative impact on the Company’s liquidity.next year.

As a result of these and other factors, the following issues have adversely impacted the Company’s abilityWe continue to continue as a going concern:

As described above in “Recent Developments” we have negotiated a restructuring with Chambers. Our Board believes the terms of the BRHC Transaction are in the best interest of all stakeholders and will permit the stockholders of the Company to preserve an equity stake in the Company which will reflect the value of the assets in BRHC both positively and negatively depending upon the change in commodity prices and well performance going forward. Chambers shall immediately invest $10 million into BRHC to reduce the Cadence Credit Facility debt to levels that are more reasonable in the current commodity price environment, and also commit an additional $20 million to BRHC for general corporate purposes which may be called at the sole discretion of the BRHC Board. This commitmentpursue sources of additional capital by Chambers, totaling $30 million wasthrough various financing transactions or arrangements, including joint venturing of projects, equity financing or other means. We may not feasible for the Company because of the relative lack of capital available frombe successful in identifying suitable funding transactions in a sufficient time period or at all, and we may not obtain the capital markets and without restructuring the Company’s balance sheet.we require by other means. If we do not succeed in raising additional capital, our resources may not be sufficient to fund our business.

The BRHC Transaction also allows the Company’s management team to continue managing the Company’s assets on behalf of BRHC. Furthermore, the management team can focus efforts on acquiring distressed assets in partnership with Chambers, Merced Capital via the existing Merced Black Ridge, LLC joint venture, as well as other potential joint ventures. Our management and Board believe that the opportunity to acquire distressed assets with our partners presents an opportunity for significant value creation for shareholders.

The report of the Company’s independent registered public accounting firm that accompanies its audited consolidated financial statements in this Annual Report on Form 10-K10-K/A contains an explanatory paragraph regarding the substantial doubt about the Company’s ability to continue as a going concern. The consolidated financial statements do not include any adjustments that might result from the outcome of the going concern uncertainty.

Overview of 2019 results

Our 2019 results were largely dominated by managing, searching for potential business combination candidates for BRAC and ultimately closing the Business Combination. We earned $466,595 in management fees for the year ended December 31, 2019, from our management agreement with BRAC subsequent to the Business Combination.

Our general and administrative expenses remained relatively consistent throughout 2019, driven primarily by salaries and benefits amounting to $1,172,745. Our stock-based and deferred compensation included $1,396,460 of expense related to the 2018 Management Incentive Plan (the “2018 Plan”), and $100,526 of expense related to the amortization of stock options.

Application of Critical Accounting Policies

Our discussion and analysis of our financial condition and results of operations are based upon our financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities. On an ongoing basis, we evaluate our estimates, including those related to impairment of property, plant and equipment, intangible assets, deferred tax assets and fair value computation using the Black Scholes option pricing model. We base our estimates on historical experience and on various other assumptions, such as the trading value of our common stock and estimated future undiscounted cash flows, that we believe to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying value of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates under different assumptions or conditions. We believe that our estimates, including those for the above-described items, are reasonable.

Critical Accounting Policies

The establishment and consistent application of accounting policies is a vital component of accurately and fairly presenting our financial statements in accordance with generally accepted accounting principles in the United States (GAAP), as well as ensuring compliance with applicable laws and regulations governing financial reporting. While there are rarely alternative methods or rules from which to select in establishing accounting and financial reporting policies, proper application often involves significant judgment regarding a given set of facts and circumstances and a complex series of decisions.

Method of Accounting

The method of accounting we use to account for our crude oil and natural gas investments determines what costs are capitalized and how these costs are ultimately matched with revenues and expensed.

We utilize the full cost method of accounting to account for our crude oil and natural gas investments instead of the successful efforts method because we believe it more accurately reflects the underlying economics of our programs to explore and develop crude oil and natural gas reserves. The full cost method embraces the concept that dry holes and other expenditures that fail to add reserves are intrinsic to the crude oil and natural gas exploration business. Thus, under the full cost method, all costs incurred in connection with the acquisition, development and exploration of crude oil and natural gas reserves are capitalized. These capitalized amounts include the costs of unproved properties, internal costs directly related to acquisitions, development and exploration activities, asset retirement costs, geological and geophysical costs and capitalized interest. Although some of these costs will ultimately result in no additional reserves, they are part of a program from which we expect the benefits of successful wells to more than offset the costs of any unsuccessful ones. The full cost method differs from the successful efforts method of accounting for crude oil and natural gas investments. The primary difference between these two methods is the treatment of exploratory dry hole costs. These costs are generally expensed under the successful efforts method when it is determined that measurable reserves do not exist. Geological and geophysical costs are also expensed under the successful efforts method. Under the full cost method, both dry hole costs and geological and geophysical costs are initially capitalized and classified as unproved properties pending determination of proved reserves. If no proved reserves are discovered, these costs are then amortized with all the costs in the full cost pool.

Capitalized amounts except unproved costs are depleted using the units of production method. The depletion expense per unit of production is the ratio of the sum of our unamortized historical costs and estimated future development costs to our proved reserve volumes. Estimation of hydrocarbon reserves relies on professional judgment and use of factors that cannot be precisely determined. Subsequent reserve estimates materially different from those reported would change the depletion expense recognized during the future reporting periods.

To the extent the capitalized costs in our full cost pool (net of depreciation, depletion and amortization and related deferred taxes) exceed the sum of the present value (using a 10% discount rate and based on period-end crude oil and natural gas prices) of the estimated future net cash flows from our proved crude oil and natural gas reserves and the capitalized cost associated with our unproved properties, we would have a capitalized ceiling impairment. Such costs would be charged to operations as a reduction of the carrying value of crude oil and natural gas properties. The risk that we will be required to write down the carrying value of our crude oil and natural gas properties increases when crude oil and natural gas prices are depressed, even if the low prices are temporary. In addition, capitalized ceiling impairment charges may occur if we experience poor drilling results or estimations of our proved reserves are substantially reduced. A capitalized ceiling impairment is a reduction in earnings that does not impact cash flows, but does impact operating income and shareholders’ equity. Once recognized, a capitalized ceiling impairment charge to crude oil and natural gas properties cannot be reversed at a later date. The risk that we will experience ceiling test impairment increases when crude oil and natural gas prices are depressed or if we have substantial downward revisions in our estimated proved reserves. During the year ended December 31, 2015 we incurred a non-cash impairment charge of $71,272,000. We did not incur an impairment charge in the 2014. No assurance can be given that we will not experience capitalized ceiling impairment charges in future periods. In addition, capitalized ceiling impairment charges may occur if estimates of proved hydrocarbon reserves are substantially reduced or estimates of future development costs increase significantly.

Crude Oil and Natural Gas Reserves

The determination of depreciation, depletion and amortization expense as well as impairments that are recognized on our crude oil and natural gas properties will be highly dependent on the estimates of the proved crude oil and natural gas reserves attributable to our properties. Our estimate of proved reserves will be based on the quantities of crude oil and natural gas which geological and engineering data demonstrate, with reasonable certainty, to be recoverable in the future years from known reservoirs under existing economic and operating conditions. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation, and judgment. For example, we must estimate the amount and timing of future operating costs, production taxes and development costs, all of which may in fact vary considerably from actual results. In addition, as the prices of crude oil and natural gas and cost levels change from year to year, the economics of producing our reserves may change and therefore the estimate of proved reserves may also change. Any significant variance in these assumptions could materially affect the estimated quantity and value of our reserves.

The information regarding present value of the future net cash flows attributable to our proved crude oil and natural gas reserves are estimates only and should not be construed as the current market value of the estimated crude oil and natural gas reserves attributable to our properties. Thus, such information includes revisions of certain reserve estimates attributable to our properties included in the prior year’s estimates. These revisions reflect additional information from subsequent activities, production history of the properties involved and any adjustments in the projected economic life of such properties resulting from changes in crude oil and natural gas prices. Any future downward revisions could adversely affect our financial condition, our borrowing ability, our future prospects and the value of our common stock.

The estimates of our proved crude oil and natural gas reserves used in the preparation of our financial statements are prepared by a registered independent petroleum consultant in accordance with the rules promulgated by the SEC.

Asset Retirement Obligations

We may have significant obligations to plug and abandon our crude oil and natural gas wells and related equipment. Liabilities for asset retirement obligations are recorded at fair value in the period incurred. The related asset value is increased by the same amount. Asset retirement costs included in the carrying amount of the related asset are subsequently allocated to expense as part of our depletion calculation. Additionally, increases in the discounted asset retirement liability resulting from the passage of time are reported as accretion of discount on asset retirement obligations expense on our Statement of Operations.

Estimating future asset retirement obligations requires us to make estimates and judgments regarding timing, existence of a liability, as well as what constitutes adequate restoration. We use the present value of estimated cash flows related to our asset retirement obligations to determine the fair value. Present value calculations inherently incorporate numerous assumptions and judgments, which include the ultimate retirement and restoration costs, inflation factors, credit adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the present value of our existing asset retirement obligation liability, a corresponding adjustment will be made to the carrying cost of the related asset.

Revenue Recognition

We derive revenue primarily from the sale of the crude oil and natural gas from our interests in producing wells; hence our revenue recognition policy for these sales is significant. We recognize revenue from the sale of crude oil and natural gas when production is delivered to, and title has transferred to, the purchaser and to the extent the selling price is reasonably determinable. Settlements for hydrocarbon sales can occur up to two months, or more, after the end of the month in which the crude oil, natural gas or other hydrocarbon products were produced. We estimate and accrue for the value of these sales using information available to us at the time our financial statements are generated. Differences are reflected in the accounting period that payments are received from the operator.

Derivative Instrument Activities

We use derivative instruments to manage a portion of the market risks resulting from fluctuations in the prices of oil and natural gas. We may periodically enter into derivative contracts, including price swaps, caps and floors, which require payments to (or receipts from) counterparties based on the differential between a fixed price and a variable price for a fixed quantity of oil or natural gas without the exchange of underlying volumes. The notional amounts of these financial instruments are based on expected production from existing wells. We have, and may continue to use exchange traded futures contracts and option contracts to hedge the delivery price of oil at a future date.

All derivative positions are carried at their fair value on the balance sheet and are marked-to-market at the end of each period. Any realized gains and losses are recorded to gain (loss) on settled derivatives and unrealized gains or losses are recorded to (losses) gains on the mark-to-market of derivative instruments on the statements of comprehensive income rather than as a component of accumulated other comprehensive income.

The resulting cash flows from derivatives are reported as cash flows from operating activities.

Income Taxes

Deferred tax assets are recognized for temporary differences in financial statement and tax basis amounts that will result in deductible amounts and carry-forwards in future years. Deferred tax liabilities are recognized for temporary differences that will result in taxable amounts in future years. Deferred tax assets and liabilities are measured using enacted tax law and tax rate(s) for the year in which we expect the temporary differences to be deducted or settled. The effect of a change in tax law or rates on the valuation of deferred tax assets and liabilities is recognized in income in the period of enactment. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized. Significant future taxable income would be required to realize this net tax asset.

Estimating the amount of the valuation allowance is dependent on estimates of future taxable income, alternative minimum tax income, and changes in shareholder ownership that would trigger limits on use of net operating losses under Internal Revenue Code Section 382.

Fair Value of Financial Instruments

Our cash and cash equivalents, investments, accounts receivable and accounts payable are stated at cost which approximates fair value due to the short-term nature of these instruments. In January 2010, the FASB issued an amendment to the accounting standards related to the disclosures about an entity’s use of fair value measurements. Among these amendments, entities will beare required to provide enhanced disclosures about transfers into and out of the Level 1 (fair value determined based on quoted prices in active markets for identical assets and liabilities) and Level 2 (fair value determined based on significant other observable inputs) classifications, provide separate disclosures about purchases, sales, issuances and settlements relating to the tabular reconciliation of beginning and ending balances of the Level 3 (fair value determined based on significant unobservable inputs) classification and provide greater disaggregation for each class of assets and liabilities that use fair value measurements. We do not expect that the adoption of this new standard will have a material impact to our financial statements.

Use of Estimates

In accordance with accounting principles generally accepted in the United States, management utilizes estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements, as well as the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Our estimates of our proved crude oil and natural gas reserves, future development costs, estimates relating to certain crude oil and natural gas revenues and expenses, fair value of certain investments, and deferred income taxes are or will be the most critical to our financial statements.

Results of Operations for the Years Ended December 31, 20152019 and 2014.2018.

The following table summarizes selected items from the statement of operations for the years ended December 31, 20152019 and 2014.2018.

Oil and Natural Gas Sales

We recognized $15,104,629

Management Fee Revenue

The Company earned $466,595 in oil and gas salesmanagement fees for the year ended December 31, 2015, compared2019, from its management agreement with BRAC subsequent to oil and gas sales of $21,102,823 forthe Mergers. The Company did not earn any management fees during the year ended December 31, 2014, a decrease of $5,998,194, or 28%. Our oil and gas sales are generated from the drilling and development of producing wells. We had 10.95 net producing wells as of December 31, 2015, and an additional 0.18 net wells that were either in the drilling preparation, drilling, awaiting completion, or completing stages, compared to 7.88 net producing wells, and an additional 2.83 net wells that were either in the drilling preparation, drilling, awaiting completion, or completing stages as of December 31, 2014.

Included in the revenues for the year ended December 31, 2015 were revenues of approximately $1,170,000 related to production from prior fiscal years for the Dahl Federal. Recognition of the Dahl Federal revenues was delayed until title issues related to riparian rights in the Missouri River were resolved.

Derivatives

We had gains on settled derivatives of $11,477,653 and $511,451 for the years ended December 31, 2015 and 2014, respectively.

We had a mark-to-market derivative loss of $6,425,345 in 2015 and a mark-to-market derivative gain of $7,793,421 in 2014, resulting in a net derivative asset of $1,154,400 as of December 31, 2015.

Expenses:

Production Expenses

Production expenses were $3,767,444 and $2,705,763 for the years ended December 31, 2015 and 2014, respectively, an increase of $1,061,681, or 39%. Our production expenses are greater in the comparative period due to our 46% increase in production on a Boe basis comparing 2015 over 2014. On a per Boe basis, production expenses decreased from $9.27 per Boe to $8.85 per Boe, primarily due to decreased water disposal costs, particularly in the latter half of 2015 as the low water cut on the Teton project wells helped drive a decrease in water disposal costs per Boe.

Production Taxes

Production taxes were $1,574,110 and $2,203,501 for the year ended December 31, 2015 and 2014, respectively, a decrease of $629,391, or 29%. Production taxes are based on realized oil and gas sales. Production taxes represent 10.4% and 10.4% of oil and gas sales, respectively for 2015 and 2014.2018. 

General and Administrative Expenses

Salaries and Benefits

Salaries and benefits for the year ended December 31, 2019 were $1,172,745 compared to $1,199,729 for the year ended December 31, 2018, a decrease of $26,984 or 2%. The decrease in salaries and benefits was primarily due to a headcount decrease during the fourth quarter of 2019, offset by increased health benefit costs and a base salary increase for the CEO.

Stock-based Compensation

Stock-based compensation expense for the year ended December 31, 2019 was $1,496,986, compared to $310,731 for year ended December 31, 2018, an increase of $1,186,255 or 382%. Included in the expense for year ended December 31, 2019, was $1,396,460 of expense related to the 2018 Management Incentive Plan (the “2018 Plan”). Amortization of stock options decreased by $210,205 as a significant group of options became fully amortized at the end of 2018.

Professional Services

General and administrative expenses related to professional services were $132,505 for the 2019 period, compared to $105,796 for the 2018 period, an increase of $26,709 or 25%. The increase was primarily due to legal costs related to a reverse stock split and proposed business combinations.

Other General and Administrative Expenses

Other general and administrative expenses for the year ended December 31, 20152019 were $3,023,631,$259,968, compared to $2,891,641$250,088 for the year ended December 31, 2014.2018, an increase of $9,880, or 4%. The increase for 2015 as comparedis attributable to 2014 was $131,990, or 5%,increased insurance costs, travel, and is primarily attributed to salary increases. On a per Boe basis, generalmeals and administrative expenses decreased 28% from $9.91 per Boe produced in 2014 to $7.10 per Boe produced in 2015, as our general and administrative costs grew at a far slower rate than our production.entertainment expenses.

Depletion of Oil and Natural Gas Properties

Our depletion expense is driven by many factors, including certain exploration costs involved in the development of producing reserves, production levels and estimates of proved reserve quantities and future developmental costs. We recognized depletion expense of $9,278,108 for the year ended December 31, 2015, compared to $9,359,952 for the year ended December 31, 2014, a decrease of $81,844, or 1%. The decrease was due primarily to decreases in the depreciable cost pool due to impairment losses offset by increases in production. On a per Boe basis, depletion expense decreased 32% from $32.08 per Boe produced in 2014 to $21.80 per Boe produced in 2015, as the impairment reduced the cost pool used for calculating depreciation.

Impairment of Oil and Natural Gas Properties

As a result of currently prevailing low commodity prices and their effect on the proved reserve values of properties in 2015, we recorded a non-cash ceiling test impairment of $71,272,000 or $167.45 per Boe for the year ended December 31, 2015. The Company did not have any impairment of its proved oil and gas properties for the year ended December 31, 2014. The impairment charge affected our reported net income but did not reduce our cash flow.

Accretion of Discount on Asset Retirement Obligations

Expenses for accretion of our discount on asset retirement obligation for the year ended December 31, 2015 was $32,574, compared to $22,361 for the year ended December 31, 2014.

Depreciation

Depreciation expense for the year ended December 31, 20152019 was $16,295,$872, compared to $29,138$9,472 for year ended December 31, 2018. The decrease is attributable to certain equipment becoming fully amortized.

Other Income (Expense)

In the year ended December 31, 2014.2019, other income was $15,480,563, consisting of the gain upon deconsolidation of BRAC of $26,322,687 and an offsetting merger incentive expense of $5,874,000 to recognize the cost related to transferring shares of AESE stock to the former owners of Allied Esports and WPT and other investors as incentive to participate in the merger, as partially offset by a net loss on investments in Allied Esports Entertainment, Inc. of $4,968,175.

Other Income and (Expenses)

Other income and (expenses) forIn the year ended December 31, 2015, resulted in2018, other income was $2,139,496, consisting primarily of net settlement income of $2,137,500 resulting from the final settlement of the contingent portion of a net expense of $8,122,850, compared to a net expense of $5,284,264 for the year ended December 31, 2014, resulting in a net increase of $2,838,586, or 54%.2012 settlement agreement.

The net other income and (expenses) for the year ended December 31, 2015, consisted of $13,398 of other income and $8,136,248 of interest expense. Interest expense includes $1,645,749 of amortized warrant costs, $751,019 of amortized loan origination costs and $426,734 of amortized original issue discounts, and was reduced by $362,075 of capitalized interest costs. The amortization of warrant costs, loan origination costs and original issue discounts was accelerated in 2015 to expense the remaining balances as of December 31, 2015 as the Company was in default of its loan agreements and the balances are now due on demand.

The net other income and (expenses) for the year ended December 31, 2014, consisted of $972 of interest income and $5,285,236 of interest expense. Interest expense includes $628,125 of amortized warrant costs, $326,258 of amortized loan origination costs and $144,904 of amortized original issue discounts, and was reduced by $372,673 of capitalized interest costs.

Provision for Income Taxes

WeThe Company had an income tax benefit of $6,593,040 for the year ended December 31, 2015, compared to anno income tax expense in the 2019 or 2018 periods, as the Company continues to reserve against any deferred tax assets due to the uncertainty of $2,559,195 for the year ended December 31, 2014. The tax benefits for the year ended December 31, 2015 was primarily driven by the Company’s loss before provision for income taxesrealization of $76,930,075. The tax expense for the year ended December 31, 2014 was primarily driven by the Company’s income before provision for income taxes of $6,911,075.any benefit.

Net Income (Loss) from Discontinued Operations

The net loss for 2015 was $70,337,035, compared to net income in 2014 of $4,351,880. Operating income (loss), consisting of total revenue less operating expenses, was $(68,807,255) and $12,195,339 in 2015 and 2014, respectively. In 2015 the loss is dominated by the impairment charge of $71,272,000. In 2014, the mark-to-market gains on derivatives amounted to $7,793,421 and realized gains on settled derivatives were $511,451, and contributed significantly to the increase in operating income. Adding to the operating loss in 2015 and offsetting the increase in operating income 2014, interest expense increased $2,851,012, as we funded a portion of well development and property acquisitions through increases in our debt. The income tax benefit of $6,593,040 reduced out net loss in 2015, while the income tax expense of $2,559,195 decreased our net income in 2014.

Non-GAAP Financial Measures

In addition to reporting netNet income (loss) as defined under GAAP, we also present Adjusted Net Income (Loss) and Adjusted EBITDA. We define Adjusted Net Income (Loss) as net income excluding settlement income, net of settlement expenses, and tax. We define Adjusted EBITDA as net income before (i) interest expense, (ii) income taxes, (iii) depreciation, depletion and amortization, (iv) accretion of abandonment liability, and (v) non-cash expenses relatingfrom discontinued operations relates to share based payments recognized under ASC Topic 718. We believe the use of non-GAAP financial measures provides useful information to investors regarding our current financial performance; however, Adjusted Net Income (Loss) and Adjusted EBITDA do not represent, and should not be considered alternatives to GAAP measurements. We believe these measures are useful in evaluating our fundamental core operating performance. Specifically, we believe the non-GAAP Adjusted Net Income (Loss) and Adjusted EBITDA results provide useful information to both management and investors by excluding certain income and expenses that our management believes are not indicative of our core operating results. Although we use AdjustedBRAC during the periods prior to deconsolidation. Net Income (Loss)income (loss) from discontinued operations consisted of a loss of $7,421,050, compared to income of $1,261,200, a difference of $8,682,250. During the 2019 period, there were contingent closing costs from BRAC’s underwriter and Adjusted EBITDAother investment bankers involved in the merger of $7,917,500. Interest from investments in the trust account for the benefit of potential redeeming shareholders was $2,474,371 in 2018, but decreased to manage our business, including$1,780,992 in 2019, due to trust account redemptions and the preparation of our annual operating budget and financial projections, we believe that non-GAAP financial measures have limitations and do not reflect allwithdrawal of the amounts associated with our resultsremaining assets at the time of operations as determined in accordance with GAAP and that these measures should only be used to evaluate our results of operations in conjunction with the corresponding GAAP financial measures. A reconciliation of Adjusted Net Income (Loss) and Adjusted EBITDA to Net Income, GAAP, are included below:Mergers.

^(a)Adjusted to reflect tax (expense) benefit, computed based on our effective tax rates of approximately 9% in 2015 and 37% 2014, of $578,000 and $(2,884,000) respectively, for the years ended December 31, 2015 and 2014.

^(b)Adjusted to reflect tax benefit, computed based on our effective tax rate of approximately 9% in 2015, of $6,414,000, for the year ended December 31, 2015.

Liquidity and capital resourcesCapital Resources

The following table summarizes our total current assets, liabilities and working capital at December 31, 20152019 and 2014.2018.

As of December 31, 20152019, we had negative working capital of $61,855,057, including $60,350,629 of debt that has been reclassified to a current liability as it is in default.$1,289,995.

The following table summarizes our cash flows during the years ended December 31, 20152019 and 2014,2018, respectively.

Our net cash flows from operations are primarily affected by production volumes and commodity prices.

Net cash provided byused in operating activities was $15,620,168$9,709,780 and $8,941,815$187,936 for the years ended December 31, 20152019 and 2014,2018, respectively, an increasea year over year increased use of $6,678,353.$9,521,844. The increaseincreased use was primarily due to increased operating cash generated from realized gains on mark-to-marketnet settlement income $2,250,000 received in 2018, and an increase of derivatives$8,682,250 in net losses in discontinued operations of $11,477,653 on 2015 as compared $511,451 in 2014.BRAC due primarily to the recognition of $7,917,500 of contingent fees upon BRAC’s business combination. Changes in current assets and liabilitiesworking capital from continuing operating activities resulted in an increase in cash of approximately $785,176 in 2015 and$7,360 during the year ended December 31, 2019, as compared to a decrease in cash of $2,370,769$20,357 for the same period in 2014, a net increase of $3,155,945 for 2015 as compared to 2014.the previous year.

Net cash used inprovided by investing activities was $20,586,656$6,883,062 and $29,143,086$213,897 for the years ended December 31, 20152019 and 2014, respectively, a decrease2018, respectively. In both periods virtually all the cash was provided from discontinued operations and was the result of $8,556,430. The decrease was primarily due to a decrease in purchasestransfers and development of oil and natural gas properties of $4,025,403. Purchases of oil and natural gas properties in 2015 amounted to $102,928 and we paid $20,611,076 in well development costs. Purchases of oil and natural gas properties in 2014 amounted to $3,164,469 and we paid $21,574,938 in well development costs. In 2015 we received proceedswithdrawals from the saleTrust Account, other than $6,046 of oil and natural gas properties of $127,348. Investing activity in 2014 included advances of $5,822,086 to operators for future well development and proceeds from the sale of oil and natural gas properties of $1,441,929.equipment purchases during 2019.

Net cash provided fromby financing activities was $5,100,000$1,431,974 and $19,145,606$450 for the years ended December 31, 20152019 and 2014, respectively, a decrease of $14,045,606. We drew $5,150,000 and $19,400,000, net of repayments, on our credit facilities in 2015 and 2014,2018, respectively. We paid $50,000 and $254,394 in debt issuance costs in 2015 and 2014, respectively.

Senior Credit Facility and Subordinated Credit Facilities

The Company, as borrower, entered into a Credit Agreement dated August 8, 2013 and amendments thereto dated December 13, 2013, March 24, 2014, April 21, 2014, September 11, 2014, March 30, 2015 and August 10, 2015 (as amended, the “Senior Credit Agreement”) with Cadence Bank, N.A. (“Cadence”), as lender (the “Senior Credit Facility”). Under the termsAll of the Senior Credit Agreement, a senior secured revolving line2019 activity was the result of creditactivities in the maximum aggregate principal amount of $50 million is available from time to time (i) for direct investment in oil and gas properties, (ii) for general working capital purposes, including the issuance of letters of credit, and (iii) to refinance the then existing debt under the Company’s former credit facility with Dougherty Funding LLC.

Availability under the Senior Credit Facility is at all times subject to the then-applicable borrowing base, determined by Cadence in a manner consistent with the normal and customary oil and gas lending practices of Cadence. Availability was initially set at $7 million and is subject to periodic redeterminations. The availability was $32 million as of December 31, 2015. The next scheduled borrowing base amount determination date is April 1, 2016. Subject to availability under the borrowing base, the Company may borrow, repay and re-borrow funds in amounts of $250,000 or more. At the Company’s election, the unpaid principal balance of any borrowings under the Senior Credit Facility may bear interest at either (i) the Base Rate, as defined in the Senior Credit Facility, plus the applicable margin, which varies from 1.00% to 1.50% or (ii) the LIBOR rate, as defined in the Senior Credit Facility, plus the applicable margin, which varies from 3.00% to 3.50%. Interest is payable for Base Rate loans on the last business day of the month and for LIBOR loans on the last LIBOR business day of each LIBOR interest period. The Company is also required to pay a quarterly fee of 0.50% on any unused portion of the borrowing base, as well as a facility fee of 0.90% of the initial and any subsequent additions to the borrowing base.

The Senior Credit Facility’s maturity date of August 8, 2016, was subsequently amended to January 15, 2017 pursuant to the amendment on March 30, 2015. The Company may prepay the entire amount of Base Rate loans at any time, and may prepay the entire amount of LIBOR loans upon at least three business days’ notice to Cadence. The Senior Credit Facility is secured by first priority interests in mortgages on substantially all of the Company’s assets, including but not limited to the Company’s mineral interests in North Dakota and Montana.

The Company had borrowings of $27.75 million and $22.6 million outstanding under the Senior Credit Agreement as of December 31, 2015 and December 31, 2014, respectively.

The Company, as borrower, entered into a Second Lien Credit Agreement dated August 8, 2013 and amendments thereto dated December 13, 2013, March 24, 2014, April 21, 2014, September 11, 2014, March 30, 2015, and August 10, 2015 (as amended, the “Subordinated Credit Agreement”) by and among the Company, as borrower, Chambers Energy Management, LP, as administrative agent (“Chambers”), and the several other lenders named therein (the “Subordinated Credit Facility”). Under the Subordinated Credit Facility, term loans in the aggregate principal amount of up to $75 million are available from time to time (i) to repay the Previous Credit Facility, (ii) for fees and closing costs in connection with both the Senior Credit Facility and the Subordinated Credit Facility (together, the “Credit Facilities”), and (iii) general corporate purposes.

The Subordinated Credit Agreement provided initial commitment availability of $25 million, which was subsequently amended to the current availability of $30 million, with the remaining commitments subject to the approval of Chambers and other customary conditions. The Company may borrow the available commitments in amounts of $5 million or more and shall not request borrowings of such loans more than once a month, provided that the initial draw was at least $15 million. Loans under the Subordinated Credit Facility shall be funded net of a 2% OID. The unpaid principal balance of borrowings under the Subordinated Credit Facility bears interest at the Cash Interest Rate plus the PIK Interest Rate. The Cash Interest Rate is 9.00% per annum plus a rate per annum equal to the greater of (i) 1.00% and (ii) the offered rate for three-month deposits in U.S. dollars that appears on Reuters Screen LIBOR 01 as of 11:00 a.m. (London time) on the second full LIBOR business day preceding the first day of each calendar quarter. The PIK Interest Rate is equal to 4.00% per annum. Interest is payable on the last day of each month. The Company is also required to pay an annual nonrefundable administration fee of $50,000 and a monthly availability fee computed at a rate of 0.50% per annum on the average daily amount of any unused portion of the available amount under the commitment.

The Subordinated Credit Facility matures on June 30, 2017. Upon at least three business days’ written notice, the Company may prepay the entire amount under the loans, together with accrued interest. Each prepayment made prior to the second anniversary of the funding date, as defined in the Subordinated Credit Facility, shall be accompanied by a make-whole amount, as defined in the Subordinated Credit Agreement. Prepayments made on or after the second anniversary of the funding date shall be accompanied by an applicable premium, as set forth in the Subordinated Credit Agreement. The Subordinated Credit Facility is secured by second priority interests on substantially all of the Company’s assets, including but not limited to second priority mortgages on the Company’s mineral interests in North Dakota and Montana.

The first funding from the Subordinated Credit Facility occurred on September 9, 2013 at which time we drew $14.7 million, net of a $300,000 original issue discount, from the Subordinated Credit Agreement and used $10,226,057 of those proceeds to repay and terminate a previously outstanding revolving credit facility. We have drawn an additional $14.7 million, net of $300,000 original issue discounts, through December 31, 2015. The Company had borrowings of $30 million and $30 million outstanding under the Subordinated Credit Facility as of December 31, 2015 and December 31, 2014, respectively.

Intercreditor Agreements and Covenants

Cadence and Chambers have entered into an Intercreditor Agreement dated August 8, 2013 (the “Intercreditor Agreement”). The Intercreditor Agreement provides that any liens on the assets of the Company securing indebtedness under the Subordinated Credit Facility are subordinate to liens on the assets securing indebtedness under the Senior Credit Facility and sets forth the respective rights, obligations and remedies of the lenders under the Senior Credit Facility with respect to their first priority liens and the lenders under the Subordinated Credit Facility with respect to their second priority liens.

The Credit Facilities, as amended, require customary affirmative and negative covenants for credit facilities of the respective types and sizes for companies operating in the oil and gas industry, as well as customary events of default. Furthermore, the Credit Facilities contain financial covenants that require the Company to satisfy certain specified financial ratios. The Senior Credit Agreement requires the Company to maintain, as of the last day of each fiscal quarter of the Company, (i) a collateral coverage ratio (reserve value plus consolidated working capital to adjusted indebtedness) of at least 0.65 to 1.00 through the quarter ending June 30, 2014, 0.70 to 1.00 for the quarters ending September 30, 2014 and December 31, 2014, was waived for the quarters ending March 31, 2015 and June 30, 2015, and 0.70 to 1.00 for the quarter ending September 30, 2015, and 0.80 to 1.00 for the quarter ending December 31, 2015 and thereafter, (ii) a ratio of current assets, including debt facility available to be drawn, to current liabilities of a minimum of 1.0 to 1.0, except for the quarter ending June 30, 2014, which was waived, (iii) a net debt to EBITDAX, as defined in the Senior Credit Agreement, ratio of 3.75 to 1.00 for the quarter ended March 31, 2014, 4.25 to 1.00 for the quarters ended June 30, 2014 and September 30, 2014, 4.00 to 1.00 for the quarter ended December 31, 2014, was waived for the quarters ended March 31, 2015 and June 30, 2015, and 3.50 to 1.00 for the quarter ending September 30, 2015, and 3.65 to 1.00 for the quarter ending December 31, 2015, and 3.50 to 1.00 for the quarter ending March 31, 2016 and thereafter, in each case calculated on a modified trailing four quarter basis, (iv) a maximum senior leverage ratio of not more than 2.5 to 1.0 calculated on a modified trailing four quarter basis, and (v) a minimum interest coverage ratio of not less than 3.0 to 1.0. The Subordinated Credit Agreement requires the Company to maintain, as of the last day of each fiscal quarter of the Company, (i) a collateral coverage ratio (reserve value plus consolidated working capital to adjusted indebtedness) of at least 0.65 to 1.00 through the quarter ending June 30, 2014, 0.70 to 1.00 for the quarters ending September 30, 2014 and December 31, 2014, was waived for the quarters ending March 31, 2015 and June 30, 2015, and 0.70 to 1.00 for the quarter ending September 30, 2015, and 0.80 to 1.00 for the quarter ending December 31, 2015 and thereafter, (ii) a consolidated net leverage ratio (adjusted total indebtedness less the amount of unrestricted cash equivalents to consolidated EBITDA) of no more than 3.75 to 1.00 for the quarter ending March 31, 2014, 4.25 to 1.00 for the quarters ending June 30, 2014 and September 30, 2014, 4.00 to 1.00 for the quarter ending December 31, 2014, was waived for the quarters ending March 31, 2015 and June 30, 2015, and 3.50 to 1.00 for the quarter ending September 30, 2015, and 3.65 to 1.00 for the quarter ending December 31, 2015, and 3.50 to 1.00 for the quarter ending March 31, 2016 and thereafter, calculated on a modified trailing four quarter basis, (iii) a consolidated cash interest coverage ratio (consolidated EBITDA to consolidated cash interest expense) of no less than 2.5 to 1.0, calculated on a modified trailing four quarter basis and (iv) a ratio of consolidated current assets to consolidated current liabilities of at least 1.0 to 1.0, except for the quarter ending June 30, 2015 when the covenant was waived. In addition, each of the Credit Facilities requires that the Company enter into hedging agreements based on anticipated oil production from currently producing wells as agreed to by the lenders.

The Company was out of compliance with its collateral coverage ratio as of December 31, 2015. The Company is in compliance with all other covenants, as amended, for the period ending December 31, 2015.

Debt Discount, Detachable Warrants

In connection with the Subordinated Credit Facility, the Company agreed to issue to the lenders detachable warrants to purchase up to 5,000,000 shares of the Company’s common stock at an exercise price of $0.65 per share. The warrants expire on August 8, 2018. Proceeds from the loan were allocated between the debt and equity based on the relative fair values at the time of issuance, resulting in a debt discount of $2,473,576 at issuance that is presented as a debt discount on the balance sheet and is being amortized using the effective interest method over the life of the credit facility, which matures on June 30, 2017. A total of $1,645,749 and $628,195 was amortized during the years ended December 31, 2015 and 2014. Amortization was accelerated in 2015 to fully amortize the remaining balance. The remaining unamortized balance of the debt discount attributable to the warrants is $-0- as of December 31, 2015. As part of the BRHC Transaction described below, these warrants will be cancelled.

BRHC Transaction

As described above in “Recent Developments,” on March 29, 2016, the Company entered into an Asset Contribution Agreement with Black Ridge Holding Company, LLC, a Delaware limited liability company (“BRHC”) which was recently formed by the Company to contribute and assign to BRHC, all of the Company's (i) oil and gas assets (including working capital and tangible and intangible assets) (the “Assets”), (ii) outstanding balances under that certain Credit Agreement between the Company, as borrower, and Cadence Bank, N.A. (“Cadence”), as lender (the “Cadence Credit Facility”) and the outstanding balances under that certain Credit Agreement between the Company, as borrower, and the several banks and other financial institutions or entities from time to time parties thereto (the “Chambers”), and Chambers, as administrative agent (the “Chambers Credit Facility”) and (iii) all current liabilities related to the Assets, in exchange for 5% of the issued and outstanding Class A Units (the “Class A Units”) in BRHC (the “Asset Contribution”). On March 29, 2016, affiliates of Chambers Energy Management, LP (“Chambers”) (specifically, Chambers Energy Capital II, LP and CEC II TE, LLC (collectively, the “Chambers Affiliates”)) entered into a Debt Contribution Agreement between BRHC and the Chambers Affiliates, pursuant to which BRHC will issue a number of Class A Units representing 95% of the Class A Units of BRHC to the Chambers Affiliates in exchange for the release of BRHC's obligations under the Chambers Credit Facility (the “Satisfaction of Debt” and, together with the Asset Contribution, the “BRHC Transaction”). Concurrent with the Satisfaction of Debt, each warrant originally issued with the Chambers Credit Facility shall be automatically retired and cancelled. The closing of the BRHC Transaction is subject to the Company obtaining the approval of stockholders holding a majority of its outstanding capital stock and to the Company having assigned the Cadence Credit Agreement to BRHC with Cadence’s consent, and BRHC and Cadence entering into any applicable amendment agreements related to such assignment and waiver of financial covenant ratio compliance for the quarter ended December 31, 2015 and quarter ending March 31, 2016. The Company is currently in the process of preparing to satisfy both conditions.

The terms of the Class A Units of BRHC will be set forth in the limited liability company agreement of BRHC (the “LLC Agreement”), which will be effective upon the closing of the BRHC Transaction. All distributions by BRHC of cash or other property, and whether upon liquidation or otherwise, will be made as follows:

BRHC will be managed by the BRHC Board, which will be responsible for the conduct of the day-to-day business of BRHC and the management, oversight and disposition of the assets of BRHC. The initial BRHC Board will be comprised of three managers, consisting of two managers appointed by Chambers and one member from the Company.

In addition, under the LLC Agreement, Chambers will commit to contribute up to $30 million cash (the “Chambers Investment Commitment”) to BRHC in exchange for Class A Units. At Closing, Chambers shall fund $10 million (the “Initial Chambers Investment”) of the Chambers Investment Commitment, the proceeds of which shall be used to reduce outstanding amounts owed by BRHC to Cadence under the Cadence Credit Facility and for general corporate purposes. The remaining $20 million (the “Subsequent Chambers Investment”), subject to certain conditions, may be called from time to time during the Investment Period by the board of managers of BRHC (the “BRHC Board”). The Initial Chambers Investment and any Subsequent Chambers Investment shall serve to proportionately reduce the Company's Class A Units percentage ownership in BRHC. The investment period shall be the lesser of three years or such time as the entire Chambers Investment Commitment has been called by the BRHC Board (the “Investment Period”). Any portion of Chambers Investment Commitment not called by the BRHC Board prior to the expiration of the Investment Period will be cancelled. In no event will Chambers be required to make a capital contribution in an amount in excess of its undrawn commitment.

The Company will be granted 1,000,000 Class B Units in BRHC at the Closing of the BRHC Transaction. At the discretion of the BRHC’s Board of Managers, the Company may be granted additional Class B Units in BRHC, and in turn, the Company may transfer such Class B Units to certain members of the Company's management. Subject to certain conditions, the Class B Units will entitle the holders to participate in any future distributions of BRHC after distributions equal to the capital contributions and preferred return have been made to the holders of Class A Units of BRHC.

At the closing of the BRHC transaction, the Company will enter into a Management Services Agreement with BRHC. Under the Management Services Agreement, the Company will provide services to BRHC with respect to the businessdiscontinued operations of BRHC, including but not limitedBRAC, as compared to locating, investigating and analyzing potential non-operator oil and gas projects and day-to-day operations related to such projects. The Company will be paid a fee under the Management Services Agreement intended to cover the costs of providing such services and will be reimbursed for certain third party expenses. The term of the Management Services Agreement commences on the closing of the BRHC Transaction and continues indefinitely, unless terminated. The Management Services Agreement will provide termination provisions upon reasonable notice for both the BRHC and the Company as well as upon a change of control, provided that if the Management Services Agreement is terminated before January 1, 2017 that BRHC shall pay the Company a termination fee equal to the amount that would have been paid if the Management Services Agreement was$450 received from warrant exercises in place until January 1, 2017.2018.

Satisfaction of our cash obligations for the next 12 months

As of December 31, 2015,2019, our balance of cash and cash equivalents was $228,194. Presuming the BRHC Transaction closes,$108,756 and we had total working capital of negative $1,289,995. We expect to incur significant costs related to a potential business combination which will put a strain on our cash resources. Our plan for satisfying our cash requirements for the next twelve months is through cash on hand and additional financing in the termsform of our management agreement.equity or debt as needed.On March 12, 2020, the Company received a business loan from Cadence Bank, N.A. via a $700,000 Promissory Note, a Security Agreement by the Company and limited commercial guarantees by the Company’s Chief Executive Officer and Interim Chief Financial Officer and members of the Company’s Board of Directors (the “Guarantors”). The Note bears interest at a rate of 0.500 percentage points over the prime rate, currently 4.25% per annum, payable monthly, is due on March 9, 2021 and is secured by all of the Company’s rights, title and interests in and to 500,000 shares of the common stock of Allied Esports Entertainment Inc. (NASDAQ: AESE) currently owned by the Company and held in the Company’s brokerage account with RBC Capital Markets, LLC.

Effects of inflation and pricing

The crude oil and natural gas industry is very cyclical and the demand for goods and services of crude oil field companies, suppliers and others associated with the industry put extreme pressure on the economic stability and pricing structure within the industry. Typically, as prices for crude oil and natural gas increase, so do all associated costs. Conversely, in a period of declining prices, associated cost declines are likely to lag and may not adjust downward in proportion. Material changes in prices also impact our current revenue stream, estimates of future reserves, impairment assessments of crude oil and natural gas properties, and values of properties in purchase and sale transactions. Material changes in prices can impact the value of crude oil and natural gas companies and their ability to raise capital, borrow money and retain personnel. While weWe do not currently expect business costs to materially increase, higher prices for crude oilany significant effects from inflation and natural gas could result in increases in the costs of materials, services and personnel.pricing.

Contractual obligations and commitments

The following table summarizes ourWe have no significant obligations and commitments as of December 31, 20152019 to make future payments under certain contracts, aggregated by category of obligation, for specified time periods:contracts.

⁽¹⁾ Cash Interest on Senior Credit Facility and Subordinated Credit Facility is estimated assuming:

a) principal repayment on December 31, 2015, prior to maturity date as an event of default accelerates maturity;

b) interest rate in effect as of December 31, 2016 remains in effect throughout life of loan to contractual maturity date; and

c) includes unused commitment fees and loan maintenance fees.

⁽²⁾ PIK on Subordinated Credit Facility of 4% paid on December 31, 2016, prior to maturity date as an event of default accelerates maturity.

⁽³⁾ Additional commitments on our Authorization for Expenditures (“AFE”) not accrued as of December 31, 2015.

Summary of product and research and development that we will perform for the term of our plan

We are not anticipating significant research and development expenditures in the future.

Expected purchase or sale of plant and significant equipment

We do not anticipate the purchase or sale of any plant or significant equipment as such items are not required by us at this time.

Significant changes in the number of employees

As of December 31, 2015,2019, we had eightfive employees, our chief executive officer Kenneth DeCubellis, ourand interim chief financial officer, James Moe,Kenneth DeCubellis, our chief operating officer, Michael Eisele and fivethree other employees. Currently, there are no organized labor agreements or union agreements and we do not anticipate any in the future.

Assuming we are able to expand our oilidentify and gas close on abusiness by participating in additional drilling opportunities and continuing to acquire new mineral leases,combination; we may need to hire additional employees. In the interim, we intend to use the services of independent consultants and contractors to perform various professional services when appropriate. We believe the use of third-party service providers may enhance our ability to control general and administrative expenses and operate efficiently.

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on our financial condition, revenues, expenses, results of operations liquidity, capital expenditures or capital resources that are material to investors.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Price Risk

TheWe do not expect any significant effects from commodity price we receive for our oil and natural gas production heavily influences our revenue, profitability, access to capital and future rate of growth. Oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand and other factors. Historically, the markets for oil and natural gas have been volatile, and our management believes these markets will likely continue to be volatile in the future. The prices we receive for our production depend on numerous factors beyond our control. Our revenue during 2015, generally would have increased or decreased along with any increases or decreases in oil or natural gas prices, but the exact impact on our income is indeterminable given the variety of expenses associated with producing and selling oil that also increase and decrease along with oil prices.

We enter into derivative contracts to achieve a more predictable cash flow by reducing our exposure to oil price volatility. All of our derivative positions are carried at their fair value on the balance sheet and are marked-to-market at the end of each period. Any realized gains and losses are recorded to gain (loss) on settled derivatives and mark-to-market gains or losses are recorded to losses on the mark-to-market of derivatives on the statements of operations as a component of total revenues.

The Company’s derivative contracts are settled based on reported settlement prices on commodity exchanges, with crude oil derivative settlements based on NYMEX West Texas Intermediate (“WTI”) pricing. The following table reflects open commodity swap contracts as of December 31, 2015, the associated volumes and the corresponding fixed price.

As of December 31, 2015, we had a total volume on open commodity swaps of 29,000 barrels at a weighted average price of approximately $75.84.

The following table reflects the weighted average price of open commodity swap derivative contracts as of December 31, 2015, by year with associated volumes.

In addition to the open commodity swap contracts, we have entered into costless collar contracts. The costless collars are used to establish floor and ceiling prices on anticipated crude oil production. There were no premiums paid or received by us related to the costless collar contracts. The following table reflects open costless collar contracts as of December 31, 2015.

Derivative Liquidations

On September 24, 2015, the Company settled all its 2017 and 2018 derivative contracts and the majority of its 2016 derivative contracts prior to the expiration of their contractual maturities, resulting in the receipt of cash proceeds totaling $6,255,000. The resulting gain is included in gain (loss) on settled derivatives for the year ended December 31, 2015.risk.

Interest Rate Risk

Our credit facilities are tiedWe do not anticipate entering into any transactions that would expose us to LIBOR if and when the associated LIBORany direct interest rate goes above 1%. As a result, changes in interest rates can impact our financial results and cash flows. A 1% increase in short-term interest rates on our floating-rate debt as of December 31, 2015 would cost us approximately $600,000 in additional interest expense annually.risk.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA OF BLACK RIDGE OIL & GAS, INC.

BLACK RIDGE OIL & GAS, INC.

CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 20152019 AND 20142018

CONTENTS

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and

Stockholders of Black Ridge Oil & Gas, Inc.

Opinion on the Financial Statements

We have audited the accompanying balance sheets of Black Ridge Oil & Gas, Inc. (the “Company”)Company) as of December 31, 20152019 and 20142018, and the related statements of operations, stockholders'stockholders’ equity, and cash flows for each of the years then ended. in the two-year period ended December 31, 2019, and the related notes and schedules (collectively referred to as the financial statements). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the years in the two-year period ended December 31, 2019, in conformity with accounting principles generally accepted in the United States of America.

Restatement of the 2019 Financial Statements

As discussed in Note 17 to the consolidated financial statements, the accompanying 2019 financial statements have been restated to correct a misstatement.

Basis for Opinion

These financial statements are the responsibility of the Company'sCompany’s management. Our responsibility is to express an opinion on thesethe Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. OurAs part of our audits, included considerationwe are required to obtain an understanding 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'sCompany’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence supportingregarding the amounts and disclosures in the financial statements, assessingstatements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statement presentation.statements. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Black Ridge Oil & Gas, Inc. as of December 31, 2015 and 2014, and the results of its operations and cash flows for the periods described above 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 3 to the financial statements, due to the declining value of oil and gas reserves the Company has failed to comply with debt covenantssuffered a net loss from operations and has insufficient working capital,negative cash flows from operations, which raises substantial doubt about its ability to continue as a going concern. Management's plans regarding those matters are also are described in Note 3. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

/s/ M&K CPAS, PLLC

www.mkacpas.com

Houston, Texas

March 30, 2016

BLACK RIDGE OIL & GAS, INC.

CONSOLIDATED BALANCE SHEETS