Sow Good Inc. - Annual Report: 2015 (Form 10-K)

U.S. SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

x ANNUAL REPORT UNDER SECTION 13 OR 15(D) OF

THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended: December 31, 2015

Commission file number 000-53952

Black Ridge Oil & Gas, Inc.

(Exact name of registrant as specified in its charter)

10275 Wayzata Blvd. Suite 100, Minnetonka, Minnesota 55305

(Address of principal executive offices) (Zip Code)

(952) 426-1241

Registrant’s telephone number, including area code

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

Securities registered pursuant to Section 12(g) of the Act:

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

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

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§229.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No o

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

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

The aggregate market value of voting stock held by non-affiliates of the registrant was approximately $10,625,746 as of June 30, 2015 (computed by reference to the last sale price of a share of the registrant’s Common Stock on that date as reported by OTC Bulletin Board).

There were 47,979,990 shares outstanding of the registrant’s common stock as of March 28, 2016.

CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS

We are including the following discussion to inform our existing and potential security holders generally of some of the risks and uncertainties that can affect our company and to take advantage of the “safe harbor” protection for forward-looking statements that applicable federal securities law affords.

From time to time, our management or persons acting on our behalf may make forward-looking statements to inform existing and potential security holders about our company. All statements other than statements of historical facts included in this report regarding our financial position, business strategy, plans and objectives of management for future operations and industry conditions are forward-looking statements. When used in this report, forward-looking statements are generally accompanied by terms or phrases such as “estimate,” “project,” “predict,” “believe,” “expect,” “anticipate,” “target,” “plan,” “intend,” “seek,” “goal,” “will,” “should,” “may” or other words and similar expressions that convey the uncertainty of future events or outcomes. Items making assumptions regarding actual or potential future sales, market size, collaborations, trends or operating results also constitute such forward-looking statements.

Forward-looking statements involve inherent risks and uncertainties, and important factors (many of which are beyond our control) that could cause actual results to differ materially from those set forth in the forward-looking statements include the following:

We have based these forward-looking statements on our current expectations and assumptions about future events. While our management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks and uncertainties, most of which are difficult to predict and many of which are beyond our control. Accordingly, results actually achieved may differ materially from expected results in these statements. Forward-looking statements speak only as of the date they are made. You should consider carefully the statements in “Item 1A. Risk Factors” and other sections of this report, which describe factors that could cause our actual results to differ from those set forth in the forward-looking statements.

Readers are urged not to place undue reliance on these forward-looking statements, which speak only as of the date of this report. We assume no obligation to update any forward-looking statements in order to reflect any event or circumstance that may arise after the date of this report, other than as may be required by applicable law or regulation. Readers are urged to carefully review and consider the various disclosures made by us in our reports filed with the United States Securities and Exchange Commission (the “SEC”) which attempt to advise interested parties of the risks and factors that may affect our business, financial condition, results of operation and cash flows. If one or more of these risks or uncertainties materialize, or if the underlying assumptions prove incorrect, our actual results may vary materially from those expected or projected.

TABLE OF CONTENTS

PART I

ITEM 1. BUSINESS

Overview

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 had proven oil and gas reserves of 2.3 million barrels of oil equivalents, owned interest in 349 gross (10.95 net) producing oil and gas wells, and controlled the rights to mineral leases covering approximately 8,100 net acres for prospective drilling to the Bakken and/or Three Forks formations. The following table provides a summary of important information regarding our assets:

⁽¹⁾Includes leases encompassing approximately 1,114 net acres that we estimate will expire in 2016

⁽²⁾Represents average daily production over the three months ended December 31, 2015

⁽³⁾PV-10 is a non-GAAP financial measure. For further information and reconciliation to the most directly comparable GAAP measure, see “Item 2. Properties-Proved Reserves.”

During 2015 commodity prices for crude oil, natural gas and Natural gas liquids (“NGLs”) experienced sharp declines, and this downward trend has accelerated further into the first quarter of 2016, with crude oil prices reaching a twelve-year low in February 2016.

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 or May of 2016. Following such transaction, our focus will be on managing the oil and gas assets in which we will continue to have an indirect minority interest. 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 traded on the OTCQB under the trading symbol “ANFC.”

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:

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 business operations of BRHC, including but not limited 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 in place until January 1, 2017.

The summaries of the LLC Agreement, Management Services Agreement, Asset Contribution Agreement, and Debt Contribution Agreement in this Form 10-K do not purport to be complete and are qualified by reference to the LLC Agreement, Management Services Agreement, Asset Contribution Agreement, and Debt Contribution Agreement which will be filed as exhibits to the Company's Information Statement filed on Form Schedule 14C which will be filed as soon as practical by the Company.

Other Developments

Potential Reverse Stock Split

Our Board approved resolutions authorizing the Company to implement a reverse stock split of the Company’s outstanding shares of Common Stock at a ratio of up to 1:10 and any related amendment to the Company’s certificate of incorporation. Our stockholders have also approved the amendment by written consent.

Our Board of Directors or a committee of the Board of Directors has the authority to decide whether to implement a reverse stock split and the exact amount of the split within the foregoing range, if it is to be implemented. If the reverse split is implemented, the number of issued and outstanding shares of Common Stock would be reduced in accordance with the exchange ratio selected by the Board of Directors or a committee thereof. The total number of authorized shares of Common Stock will be reduced proportionately as a result of the reverse stock split and the total number of shares of authorized preferred stock will remain unchanged at 20,000,000 shares.

We believe that a reverse split would, among other things, (i) better enable the Company to obtain a listing on a national securities exchange, (ii) facilitate higher levels of institutional stock ownership, where investment policies generally prohibit investments in lower-priced securities and (iii) better enable the Company to raise funds to finance its planned operations. There can be no assurance however that we will be able to obtain a listing on a national securities exchange even if we implement the reverse stock split.

AS OF THE DATE OF THIS FILING, OUR BOARD HAS NOT TAKEN ANY ACTION TO MAKE THE POTENTIAL REVERSE STOCK SPLIT EFFECTIVE.

Business

The Company’s focus 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 February 29, 2016, we controlled approximately 7,400 net acres in the Williston Basin. In addition, as of February 29, 2016, the Company owned working interests in 376 gross wells representing 11.15 net wells that are preparing to drill, drilling, awaiting completion, completing or producing.

We believe we create value through selectively targeting acquisition of acreage positions with attractive returns on the capital employed by evaluating, amongst other factors, reserve potential, operator performance, anticipated well costs and anticipated operating expenses.

With the experience and connections of our personnel in the Williston Basin region, we believe that we are able to create value through opportunistic acreage acquisitions. We believe our business model enhances our ability to identify and acquire high value acreage in the Bakken and Three Forks trends. Because we purchase minority interests in multiple drilling units, we are able to diversify our risk across numerous wells. We believe that our prospective success revolves around our ability to acquire mineral leases and participate in drilling activities by virtue of our ownership of such rights and through our experience and the relationships we have developed in the Williston Basin.

As a non-operating working interest partner, we participate in drilling activities primarily on a heads-up basis. Before a well is spud, an operator is required to offer all mineral lease owners in the designated well spacing unit the right to participate in the drilling and production of the well. Drilling costs and revenues from oil and gas sales are split pro-rata based on acreage ownership in the designated drilling unit. We rely on our operator partners to identify specific drilling sites, permit, and engage in the drilling process. As a non-operator we are focused on maintaining a low overhead structure.

Our proven oil and gas reserves were 2.3 million barrel of oil equivalents (Boe’s) as of December 31, 2015 and 5.4 million Boe’s as of December 31, 2014.

Production Methods

We primarily engage in crude oil and natural gas exploration and production by participating on a pro-rata basis with operators in wells drilled and completed in spacing units that include our acreage under lease. We are generally a minority working interest owner in our wells. We typically depend on drilling partners to propose, permit and engage the drilling of wells. Prior to commencing drilling, our partners are required to provide all owners of mineral interests within the designated spacing unit the opportunity to participate in the drilling costs and revenues of the well to the extent of their pro-rata share of such interest within the spacing unit. Going forward as we manage the oil and gas assets for BRHC and for other joint venture partners, we will assess each drilling opportunity on a case-by-case basis. We will participate in wells that we expect to meet BRHC’s and any other of our other joint venture partners’ return thresholds based upon our estimates of ultimate recoverable crude oil and natural gas, anticipated crude oil and natural gas pricing and other factors.

We do not manage our commodities marketing activities internally, but our operating partners generally market and sell crude oil and natural gas produced from wells in which we have an interest. Our operating partners coordinate the transportation of our crude oil production from our wells to appropriate distribution points pursuant to arrangements that such partners negotiate and maintain with various parties purchasing the production. We understand that our partners generally sell our production to a variety of purchasers at prevailing market prices under separately negotiated short-term contracts. The price at which production is sold generally is tied to the spot market for crude oil. Williston Basin Light Sweet Crude from the Bakken source rock is generally 41-42 API crude oil and is readily accepted into the pipeline infrastructure.

Competition

The crude oil and natural gas industry is intensely competitive, and we compete with numerous other crude oil and natural gas exploration and production companies. Most of these companies have substantially greater resources than we have. Our competitors not only explore for and produce crude oil and natural gas, but many also conduct midstream and refining operations and market petroleum products on a regional, national or worldwide basis. These additional operations may enable them to pay more for exploratory prospects and productive crude oil and natural gas properties than us. They also may have more resources to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit.

Our larger or integrated competitors may have the resources to absorb the burden of existing and changing federal, state, and local laws and regulations more easily than we can, which would adversely affect our competitive position. Our ability to discover reserves and acquire additional properties in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. In addition, we may be at a disadvantage in acquiring crude oil and natural gas properties and bidding for exploratory prospects because we have fewer financial and human resources than other companies in our industry.

Marketing and Customers

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

Our crude oil production is expected to be sold at prices tied to the spot crude oil markets. Our natural gas production is expected to be sold under short-term contracts and priced based on first of the month index prices or on daily spot market prices. We rely on our operating partners to market and sell our production. Our operating partners include a variety of exploration and production companies, from large publicly-traded companies to small, privately-owned companies.

Principal Agreements Affecting Our Ordinary Business

We do not own any physical real estate, but, instead, our acreage is comprised of leasehold interests subject to the terms of lease agreements that provide our company the right to drill and maintain wells in specific geographic areas. All lease arrangements that comprise our acreage positions are established using industry-standard terms that have been established and used in the crude oil and natural gas industry in North Dakota. Most of our leases are acquired from other parties that obtained the original leasehold interest prior to our acquisition of the leasehold interest.

In general, our lease agreements stipulate three to five year terms including extension options. Bonuses and royalty rates are negotiated on a case-by-case basis consistent with industry standard pricing. Once a well is drilled, or production is established, depending on the lease terms, the acreage in a well’s drilling unit is considered “held by production,” meaning the lease on that particular acreage continues as long as oil or gas is being produced. Generally, other locations within the drilling unit created for a well may also be drilled at any time with no time limit as long as the lease is held by production. In the event a lease is not developed prior to lease expiration, the Company completes an economic evaluation of the expiring lease and makes a strategic decision to exercise an available option, attempt to extend the lease, or allow it to expire. As a result of these evaluations and taking into consideration other acquisition opportunities available to the Company, we expect a portion of our leases will expire prior to being held by production. The Company had leases encompassing 1,866 net acres expire in 2015 and leases encompassing 4,202 net acres expire in 2014. We estimate that leases encompassing approximately 1,114 net acres will expire in 2016. All of the costs associated with the lease expirations in 2015 and the leases we estimate will expire in 2016 have been transferred to the full cost pool and were subject to depletion in 2015.

Governmental Regulation and Environmental Matters

Our operations are subject to various rules, regulations and limitations impacting the crude oil and natural gas exploration and production industry as a whole.

Regulation of Crude Oil and Natural Gas Production

Our crude oil and natural gas exploration, production and related operations, when developed, are subject to extensive rules and regulations promulgated by federal, state, tribal and local authorities and agencies. For example, North Dakota and Montana require permits for drilling operations, drilling bonds and reports concerning operations, and impose other requirements relating to the exploration and production of crude oil and natural gas. Such states may also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of crude oil and natural gas properties, the establishment of maximum rates of production from wells, and the regulation of spacing, plugging and abandonment of such wells. Failure to comply with any such rules and regulations can result in substantial penalties. The regulatory burden on the crude oil and natural gas industry will most likely increase our cost of doing business and may affect our profitability. Although we believe we are currently in substantial compliance with all applicable laws and regulations, because such rules and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws. Significant expenditures may be required to comply with governmental laws and regulations and may have a material adverse effect on our financial condition and results of operations.

Environmental Matters

Our operations and properties are subject to extensive and changing federal, state and local laws and regulations relating to environmental protection, including the generation, storage, handling, emission, transportation and discharge of materials into the environment, and relating to safety and health. The recent trend in environmental legislation and regulation generally is toward stricter standards, and this trend will likely continue. These laws and regulations may:

The permits required for our operations may be subject to revocation, modification and renewal by issuing authorities. Governmental authorities have the power to enforce their regulations, and violations are subject to fines and injunctions. In the opinion of management, we are in substantial compliance with current applicable environmental laws and regulations, and have no material commitments for capital expenditures to comply with existing environmental requirements. Nevertheless, changes in existing environmental laws and regulations or in interpretations of them could have a significant impact on our company, as well as the crude oil and natural gas industry in general.

The Comprehensive Environmental, Response, Compensation, and Liability Act (“CERCLA”) and comparable state statutes impose strict, joint and several liability on owners and operators of sites and on persons who disposed of or arranged for the disposal of “hazardous substances” found at such sites. It is not uncommon for the neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. The Federal Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes govern the disposal of “solid waste” and “hazardous waste”, and authorize the imposition of substantial fines and penalties for noncompliance. Although CERCLA currently excludes petroleum from its definition of “hazardous substance,” state laws affecting our operations may impose clean-up liability relating to petroleum and petroleum related products. In addition, although RCRA classifies certain crude oil field wastes as “non-hazardous,” such exploration and production wastes could be reclassified as hazardous wastes thereby making such wastes subject to more stringent handling and disposal requirements.

The Endangered Species Act (“ESA”) seeks to ensure that activities do not jeopardize endangered or threatened animal, fish and plant species, nor destroy or modify the critical habitat of such species. Under ESA, exploration and production operations, as well as actions by federal agencies, may not significantly impair or jeopardize the species or its habitat. ESA provides for criminal penalties for willful violations of the Act. Other statutes that provide protection to animal and plant species and that may apply to our operations include, but are not necessarily limited to, the Fish and Wildlife Coordination Act, the Fishery Conservation and Management Act, the Migratory Bird Treaty Act and the National Historic Preservation Act. Although we believe that our operations will be in substantial compliance with such statutes, any change in these statutes or any reclassification of a species as endangered could subject our company to significant expenses or could force our company to discontinue certain operations.

On April 17, 2012, the EPA finalized rules establishing new air emission controls for oil and natural gas production and natural gas processing operations. The EPA’s rule package includes New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds (“VOCs”) and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. On August 5, 2013, the EPA issued final updates to its 2012 VOC performance standards for storage tanks. The rules establish specific new requirements regarding emissions from compressors, dehydrators, storage tanks and other production equipment. In addition, the rules revise leak detection requirements for natural gas processing plants. These rules may require a number of modifications to the operations of our third-party operating partners, including the installation of new equipment to control emissions from compressors. On January 15, 2015, the EPA announced that it will initiate a rulemaking to set standards for methane and VOC emissions from new and modified oil and gas production sources and natural gas-processing and transmission sources. Although we cannot predict the cost to comply with these new requirements at this point, compliance with these new rules could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our business.

These new regulations and proposals and any other new regulations requiring the installation of more sophisticated pollution control equipment could have a material adverse impact on our business, results of operations and financial condition.

The Federal Water Pollution Control Act of 1972, or the Clean Water Act (the “CWA”), imposes restrictions and controls on the discharge of produced waters and other pollutants into navigable waters. Permits must be obtained to discharge pollutants into state and federal waters and to conduct construction activities in waters and wetlands. The CWA and certain state regulations prohibit the discharge of produced water, sand, drilling fluids, drill cuttings, sediment and certain other substances related to the oil and gas industry into certain coastal and offshore waters without an individual or general National Pollutant Discharge Elimination System discharge permit. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. Costs may be associated with the treatment of wastewater and/or developing and implementing storm water pollution prevention plans. The CWA and comparable state statutes provide for civil, criminal and administrative penalties for unauthorized discharges of oil and other pollutants and impose liability on parties responsible for those discharges, for the costs of cleaning up any environmental damage caused by the release and for natural resource damages resulting from the release.

The underground injection of oil and natural gas wastes are regulated by the Underground Injection Control program authorized by the Safe Drinking Water Act. The primary objective of injection well operating requirements is to ensure the mechanical integrity of the injection apparatus and to prevent migration of fluids from the injection zone into underground sources of drinking water. Substantially all of the oil and natural gas production in which we have interest is developed from unconventional sources that require hydraulic fracturing as part of the completion process. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into the formation to stimulate gas production. Legislation to amend the Safe Drinking Water Act to 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 continues to consider legislation to amend the Safe Drinking Water Act to subject hydraulic fracturing operations to regulation under the Act’s Underground Injection Control Program to require disclosure of chemicals used in the hydraulic fracturing process.

Scrutiny of hydraulic fracturing activities continues in other ways. The federal government is currently undertaking several studies of the potential impacts of hydraulic fracturing. Several states, including Montana and North Dakota, where our properties are located, have also proposed or adopted legislative or regulatory restrictions on hydraulic fracturing. A number of municipalities in other states, including Colorado and Texas, have banned hydraulic fracturing. New York State’s ban on hydraulic fracturing was recently upheld by the Courts. We cannot predict whether any other legislation will ever be enacted and if so, what its provisions would be if additional levels of regulation and permits were required through the adoption of new laws and regulations at the federal or state level, which could lead to delays, increased operating costs and process prohibitions that would materially adversely affect our revenue and results of operations.

The National Environmental Policy Act, or NEPA, establishes a national environmental policy and goals for the protection, maintenance and enhancement of the environment and provides a process for implementing these goals within federal agencies. A major federal agency action having the potential to significantly impact the environment requires review under NEPA. Many of the activities of our third-party operating partners are covered under categorical exclusions which results in a shorter NEPA review process. The Council on Environmental Quality has announced an intention to reinvigorate NEPA reviews and on March 12, 2012, issued final guidance that may result in longer review processes that could lead to delays and increased costs that could materially adversely affect our revenues and results of operations.

Climate Change

Significant studies and research have been devoted to climate change and global warming, and climate change has developed into a major political issue in the United States and globally. Certain research suggests that greenhouse gas emissions contribute to climate change and pose a threat to the environment. Recent scientific research and political debate has focused in part on carbon dioxide and methane incidental to crude oil and natural gas exploration and production.

In the United States, legislative and regulatory initiatives are underway to limit greenhouse gas (“GHG”) emissions. The U.S. Congress has considered legislation that would control GHG emissions through a “cap and trade” program and several states have already implemented programs to reduce GHG emissions. The U.S. Supreme Court determined that GHG emissions fall within the federal Clean Air Act, or the CAA, definition of an “air pollutant.” In response the EPA promulgated an endangerment finding paving the way for regulation of GHG emissions under the CAA. In 2010, the EPA issued a final rule, known as the “Tailoring Rule,” that makes certain large stationary sources and modification projects subject to permitting requirements for greenhouse gas emissions under the Clean Air Act. On June 23, 2014, the U.S. Supreme Court in Utility Air Regulatory Group v. EPA, held that the EPA’s “Tailoring Rule” was invalid, but held that if a source was subject to Prevention of Significant Deterioration (“PSD”) or Title V based on emissions of conventional pollutants like sulfur dioxide, particulates, nitrogen dioxide, carbon monoxide, ozone or lead, then the EPA could also require the source to control GHG emissions and the source 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, but may still have to control GHG emissions if it is an otherwise regulated source. On February 23, 2014, Colorado became the first state in the nation to adopt rules to control methane emissions from oil and gas facilities. Subsequently, the Obama administration has approved rules that would require controls on methane emissions from certain oil and gas facilities. To the extent our third party operating partners are required to further control methane emissions, such controls could impact our business.

In addition, in September 2009, the EPA issued a final rule requiring the reporting of GHGs from specified large GHG emission sources in the United States beginning in 2011 for emissions in 2010. On November 30, 2010, the EPA published a final rule expanding its existing GHG emissions reporting to include onshore and offshore oil and natural gas systems beginning in 2012. Our third party operating partners are required to report their greenhouse gas emissions under these rules. Because regulation of GHG emissions is relatively new, further regulatory, legislative and judicial developments are likely to occur. Such developments may affect how these GHG initiatives will impact us. Moreover, while the U.S. Supreme Court held in its June 2011 decision American Electric Power Co. v. Connecticut that, with respect to claims concerning GHG emissions, the federal common law of nuisance was displaced by the federal Clean Air Act, the Court left open the question of whether tort claims against sources of GHG emissions alleging property damage may proceed under state common law. There thus remains some litigation risk for such claims. Due to the uncertainties surrounding the regulation of and other risks associated with GHG emissions, we cannot predict the financial impact of related developments on us.

Legislation or regulations that may be adopted to address climate change could also affect the markets for our products by making our products more or less desirable than competing sources of energy. To the extent that our products are competing with higher greenhouse gas emitting energy sources, our products would become more desirable in the market with more stringent limitations on greenhouse gas emissions. To the extent that our products are competing with lower greenhouse gas emitting energy sources such as solar and wind, our products would become less desirable in the market with more stringent limitations on greenhouse gas emissions. We cannot predict with any certainty at this time how these possibilities may affect our operations.

The majority of scientific studies on climate change suggest that stronger storms may occur in the future in the areas where we operate, although the scientific studies are not unanimous. Although operators may take steps to mitigate physical risks from storms, no assurance can be given that future storms will not have a material adverse effect on our business.

Employees

We currently have 8 full time employees. We may hire additional technical or administrative personnel as appropriate. However, we do not expect a significant change in the number of full time employees over the next 12 months based upon our currently-projected business plan. We are using and will continue to use the services of independent consultants and contractors to perform various professional services. We believe that this use of third-party service providers enhances our ability to contain general and administrative expenses.

Office Locations

Our executive offices are located at 10275 Wayzata Boulevard, Suite 100, Minnetonka, Minnesota 55305. Our office space consists of approximately 2,813 square feet leased pursuant to a month to month lease agreement that commenced on May 1, 2012 and was amended on November 15, 2013. The company that owns the building in which we are located is a company wholly owned by our chairman of the board of directors.

Financial Information about Segments and Geographic Areas

We have not segregated our operations into geographic areas given the fact that all of our production activities occur within the Williston Basin in North Dakota and Montana.

Available Information – Reports to Security Holders

Our website address is www.blackridgeoil.com. We make available on this website, free of charge, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports after we electronically file those materials with, or furnish those materials to, the SEC. These filings are also available to the public at the SEC’s Public Reference Room at 100 F Street, NE, Room 1580, Washington, DC 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Electronic filings with the SEC are also available on the SEC internet website at www.sec.gov.

We also post to our website our Audit Committee Charter and our Code of Ethics, in addition to all pertinent company contact information.

ITEM 1A. RISK FACTORS

If we are unable to repay or refinance our existing and future debt as it becomes due, whether at maturity or as a result of acceleration, we may be unable to continue as a going concern.

We have significant indebtedness under our Senior Credit Facility and a Subordinated Credit Facility (collectively “Credit Facilities”). As of February 29, 2016, we had an aggregate amount of approximately $61.37 million, including accrued PIK interest, outstanding under our Credit Facilities (with additional borrowing capacity of $3.45 million). As a result of our indebtedness, we use a significant portion of our cash flow to pay interest and principal (when due) on our Credit Facilities, which reduces the cash available to finance our operations and other business activities and limits our flexibility in planning for or reacting to changes in our business and the industry in which we operate.

As of the December 31, 2015, we are out of compliance with our collateral coverage ratio restrictive covenant contained in our agreements under our Credit Facilities and based on our projections expect to be out of compliance on other restrictive covenants throughout 2016 unless those requirements are waived or amended. Additionally, the borrowing base under our Senior Credit Facility is subject to redetermination on April 1, 2016. As we have failed to comply with the restrictive covenant contained in our Credit Facilities, the result is an Event of Default (as defined in the applicable agreements) which permits acceleration of the indebtedness under certain circumstances and permits our secured lenders to foreclose on substantially all of our assets which secure such debt. Any accelerated debt would become immediately due and payable.

Our Board has approved a restructuring transaction with Chambers as described above in “Recent Developments.” Closing on this proposed restructuring transaction is subject to obtaining the approval of stockholders holding a majority of our outstanding stock and the consent of the lender on our Senior Credit Facility. There is no assurance that the restructuring transaction will be completed. The uncertainty associated with our ability to meet our obligations as they become due raises substantial doubt about our ability to continue as a going concern. 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-K contains an explanatory paragraph regarding the substantial doubt about the Company’s ability to continue as a going concern.

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

Availability under our revolving credit facility is currently subject to a borrowing base of $32 million. The borrowing base is subject to scheduled semiannual (April 1 and October 1) and other elective borrowing base redeterminations based upon, among other things, projected revenues from and asset values of the oil and natural gas properties securing the revolving credit facility. Our lender can adjust the borrowing base and the borrowings permitted to be outstanding under our revolving credit facility. Reductions in estimates of our oil, NGL and natural gas reserves will result in a reduction in our borrowing base (even if prices are kept constant). Given the ongoing decline in commodity prices for oil, NGL and natural gas, it is likely that reductions in our borrowing base could also arise from other factors, including but not limited to:

As of December 31, 2015, we had $27.75 million of borrowings outstanding under our Senior Credit Facility and have net draws of an additional $1.05 million on the Senior Credit Facility as of March 25, 2016. Any significant reduction in our borrowing base as a result of such borrowing base redeterminations or otherwise will negatively impact our liquidity and our ability to fund our operations and, as a result, would have a material adverse effect on our financial position, results of operation and cash flow. Further, if the outstanding borrowings under our revolving credit facility were to exceed the borrowing base as a result of any such redetermination, we could be required to repay the excess. As part of the BRHC Transaction, the Senior Credit Facility will be assigned to BRHC and any repayments that are required to be made as a result of the redetermination will be made by BRHC through additional capital contributions from Chambers. If the BRHC Transaction is not completed, we may not have sufficient funds to make such repayments. If we do not have sufficient funds and we are otherwise unable to negotiate renewals of our borrowings or arrange new financing, we may have to sell significant assets. Any such sale could have a material adverse effect on our business and financial results.

Crude oil and natural gas prices are very volatile. A protracted period of depressed crude oil and natural gas prices has adversely affected and may continue to affect our business, financial condition, results of operations and cash flows.

The crude oil and natural gas markets are very volatile, and we cannot predict future crude oil and natural gas prices. The price we receive for our crude oil and natural gas production heavily influences our revenue, profitability, access to capital and future rate of growth. The prices we receive for our production and the levels of our production depend on numerous factors beyond our control. These factors include, but are not limited to, the following:

The recent drop in oil and gas prices has reduced the availability of liquidity and credit to fund continuation and expansion in the oil and gas industry. Lower crude oil and natural gas prices have not only decreased our revenues on a per unit basis but also reduced the amount of crude oil and natural gas that we can produce economically, lowering our reserves. A substantial or extended decline in crude oil or natural gas prices, such as we have experienced beginning in 2014 and has continued to the present has resulted in and will continue to result in impairments of our proved crude oil and natural gas properties and may materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures. To the extent commodity prices received from production are insufficient to fund planned capital expenditures; we will be required to reduce spending or borrow to cover any such shortfall. Lower crude oil and natural gas prices have already reduced and continue to reduce our borrowing base under our revolving credit facility, which is determined at the discretion of our lenders based on the collateral value of our proved reserves that have been mortgaged to the lenders and is subject to redetermination periodically as provided in our credit agreement.

We may be unable to obtain the additional capital or joint venture partners that we need to implement our business plan.

We currently have a Senior Credit Facility and a Subordinated Credit Facility with current availability of $32 million and $30 million, respectively, secured by substantially all of our assets. Due to a restrictive covenant violation, we are out of compliance with the two credit facilities and either facility may not be available to us in the future depending on the outcome of our efforts to regain compliance. We had drawn $27.75 million on the Senior Credit Facility and $30 million on the Subordinated Credit Facility as of December 31, 2015 and have net draws of an additional $1.05 million on the Senior Credit Facility as of March 25, 2016. We will require additional sources of capital to continue to grow our business through acquisitions and to further expand our exploration and development programs. We may be unable to obtain additional capital or financing if and when required, or upon terms that are acceptable to us. Future acquisitions and future exploration, development, production and marketing activities, as well as our administrative requirements will require a substantial amount of capital and cash flow. We may pursue sources of additional capital through various financing transactions or arrangements, including joint venturing of projects, debt financing, equity financing or other means. We may not be successful in identifying suitable financing transactions in the time period required or at all, and we may not obtain the capital we require by other means. If we do not succeed in raising additional capital, our resources may not be sufficient to fund our planned expansion of operations in the future.

Any additional capital raised through the sale of equity would dilute the ownership percentage of our shareholders. Raising any such capital could also result in a decrease in the fair market value of our equity securities because our assets would be owned by a larger pool of outstanding equity holders. The terms of securities we issue in future capital transactions may be more favorable to our new investors, and may include preferences, superior voting rights and the issuance of other derivative securities. In addition, we have granted and will continue to grant equity incentive awards under our equity incentive plans, which may have a further dilutive effect. Our ability to obtain financing, if and when necessary, may be impaired by such factors as the capital markets (both generally and in the crude oil and natural gas industry in particular), our limited operating history, the location of our crude oil and natural gas properties, and prices of crude oil and natural gas on the commodities markets (which will impact the amount of asset-based financing available to us) and the departure of key employees. Further, if crude oil or natural gas prices on the commodities markets continue to decline as they have recently, our revenues will likely decrease and such decreased revenues may increase our requirements for capital. If the amount of capital we are able to raise from financing activities, together with our revenues from operations, is not sufficient to satisfy our capital needs (even to the extent that we reduce our operations), we may be required to cease our operations, divest our assets at unattractive prices or obtain financing on unattractive terms. As a result of the defaults on our debt financing and our ongoing capital needs, we have negotiated the terms of the BRHC Transaction. See “Recent Developments – BRHC Transaction.” The BRHC Transaction will substantially change our direct capital needs. We may incur substantial costs in pursuing future capital financing, including investment banking fees, legal fees, accounting fees, securities law compliance fees, printing and distribution expenses and other costs. We may also be required to recognize non-cash expenses in connection with certain securities we may issue, which may adversely impact our financial condition.

Estimates of crude oil and natural gas reserves are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

Determining the amount of oil and natural gas recoverable from various formations involves significant complexity and uncertainty. No one can measure underground accumulations of oil or natural gas in an exact way. Oil and natural gas reserve engineering requires subjective estimates of underground accumulations of oil and/or natural gas and assumptions concerning future oil and natural gas prices, production levels, and operating and development costs. Some of our reserve estimates are made without the benefit of a lengthy production history, and are less reliable than estimates based on a lengthy production history. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may prove to be inaccurate.

We routinely make estimates of oil and natural gas reserves in connection with managing our business and preparing reports to our lenders and investors. We make these reserve estimates using various assumptions, including assumptions as to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Some of these assumptions are inherently subjective, and the accuracy of our reserve estimates relies in part on the ability of our management team, reserve engineers and other advisors to make accurate assumptions. Any significant variance from these assumptions by actual figures could greatly affect our estimates of reserves, the economically recoverable quantities of oil, natural gas and NGLs attributable to any particular group of properties, the classifications of reserves based on risk of recovery, and estimates of the future net cash flows. Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, often result in the actual quantities of oil, natural gas and NGLs we ultimately recover being different from our reserve estimates. Any significant variance could materially affect the estimated quantities and present value of reserves shown in this Annual Report on Form 10-K and subsequent reports we file with the SEC. In addition, we may adjust estimates of net proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and any other factors, many of which are beyond our control.

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

Our operators’ drilling activities are subject to many risks, including the risk that they will not discover commercially productive reservoirs. Drilling for oil or natural gas can be uneconomical, not only from dry holes, but also from productive wells that do not produce sufficient revenues to be commercially viable. In addition, drilling and producing operations on our acreage may be curtailed, delayed or canceled by our operators as a result of other factors, including:

Any of these events can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination, loss of wells and regulatory penalties.

We ordinarily maintain insurance against various losses and liabilities arising from our operations; however, insurance against all operational risks is not available to us. Additionally, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could therefore occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could have a material adverse impact on our business activities, financial condition and results of operations.

Due to the sustained decrease in oil and natural gas prices, we have taken significant writedowns of our oil and natural gas properties. If oil and natural gas prices remain depressed, we may be required to make further writedowns of our oil and natural gas properties.

We use the full cost method of accounting to account for our oil and natural gas operations. Accordingly, we capitalize the cost to acquire, explore for and develop oil and natural gas properties. Under full cost accounting rules, the net capitalized costs of oil and natural gas properties may not exceed a “full cost ceiling” which is based upon the present value of estimated future net cash flows from proved reserves, including the effect of hedges in place, discounted at 10%, plus the lower of cost or fair market value of unproved properties. If at the end of any fiscal period we determine that the net capitalized costs of oil and natural gas properties exceed the full cost ceiling, we must charge the amount of the excess to earnings in the period then ended. This is called a “ceiling test write-down.” This charge does not impact cash flow from operating activities, but does reduce our net income and stockholders’ equity.

During 2015 we were required to write down the carrying value of certain of our oil and natural gas properties, and further writedowns could be required in the future. Writedowns may occur when oil and natural gas prices are low, or if we have downward adjustments to our estimated proved reserves, increases in our estimates of operating or development costs, deterioration in drilling results or mechanical problems with wells where the cost to redrill or repair is not supported by the expected economics.

During 2015, we performed impairment reviews using prices that reflect an average of monthly prices for the respective year as prescribed pursuant to the SEC’s guidelines. As a result, during 2015 we recorded impairments of $71.2 million. The average prices used in the December 31, 2015 impairment review are significantly higher than the actual and currently forecasted prices in 2016. As lower average monthly pricing is reflected in the trailing 12-month average pricing calculation, the present value of our future net revenues would decline and additional impairments could be recognized. If this significantly lower pricing environment persists we expect we could be required to write down the value of our oil and natural gas properties further. Given the current oil and natural gas pricing environment, we believe we could have additional noncash ceiling test write-downs of our oil and natural gas properties in 2016. The quarterly ceiling test considers many factors including reserves, capital expenditure estimates and trailing 12-month average prices. SEC defined prices for each quarter in 2015 were as follows:

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 periods of higher costs as activity levels in the Williston Basin fluctuate or if commodity prices rise. These increases could reduce our profitability, cash flow, and ability to complete development activities as planned.

The recent decline in commodity prices has resulted in significantly reduced activity levels in the Williston Basin. However, if and when activity in 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 also result in some suppliers of equipment, labor and supplies ceasing operations in 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 commodity 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, we will likely be impacted more acutely by factors affecting our industry or the regions in which we operate than we would if our business were more diversified, increasing our risk profile. If we do not diversify our operations, our financial condition and results of operations could deteriorate. 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.

Our derivative activities could result in financial losses or could reduce our cash flow.

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 adverse effect on our business, results of operations and financial condition.

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, we had an estimated NOL carryforward of approximately $23.8 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 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, 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. 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 in Utility 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.

Our ability to successfully acquire additional properties, to increase our reserves, to participate in drilling opportunities and to identify and enter into commercial arrangements with customers 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 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 acquire 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. We may become subject to liability for pollution, blow-outs or other hazards. We may seek to maintain insurance (including insurance maintained by our industry operators) with respect 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 associated 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.

Our operations require licenses, permits and in some cases renewals of licenses and permits from various governmental authorities. Our ability (or the ability of our industry operators) to obtain, sustain or renew such licenses and permits on acceptable terms is subject to change in regulations and policies and to the discretion of the applicable governmental authorities, among other factors. Our inability, or the inability of our industry operators, to obtain, or our loss of or denial of extension of, any of these licenses or permits could hamper our ability to produce revenues from our operations or otherwise materially adversely affect our financial condition and results 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. We will be required to continually access enhanced and updated technology to maintain our capability and to avoid obsolescence. The costs of doing so may be substantial and may be higher than the costs that we anticipate for technology maintenance and development. If we are unable to maintain the technology available to us, our ability to manage our business and to compete may 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.

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, we had options for 7,055,500 shares of common stock outstanding under our 2012 Amended and Restated Stock Incentive Plan. Our 2012 Amended and Restated Stock Incentive Plan permits us to issue up to 7,500,000 shares of our common stock either upon exercise of stock options granted under such plan or through restricted stock awards under such 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, 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, precludes 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, Suite 100, Minnetonka, Minnesota 55305. We lease 2,813 square feet 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.

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 from 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. As 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.

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 quotations reflect inter-dealer prices, without retail markup, mark-down, or commission and may not necessarily represent actual transactions. The closing price of our common stock on the OTCQB on March 24, 2016 was $0.07 per share.

As of March 24, 2016, there were approximately 1,900 record holders of our common stock, not including shares held in “street name” in brokerage accounts which is unknown. As of March 24, 2016, there were 47,979,990 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 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, our 2012 Amended and Restated Stock Incentive Plan increased the number of shares reserved under the Plan to a total of 7,500,000 shares of our common stock. The following table sets forth certain information regarding our 2012 Amended and Restated Stock Incentive Plan as of December 31, 2015:

For the fiscal years ended December 31, 2015 and 2014, we issued a total of 1,000,000 and 632,500 stock options, respectively, pursuant to our 2012 Amended and Restated Stock Incentive Plan. There were 1,153,334 and 63,500 options cancelled during the years ended December 31, 2015 and 2014, respectively.

Warrants

We didn’t issue any warrants to purchase shares of registered or unregistered common stock for the fiscal years ended December 31, 2015 and 2014. There were 585,000 and 330,000 warrants forfeited or expired during the years ended December 31, 2015 and 2014, respectively.

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.

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 traded on the OTCQB under the trading symbol “ANFC.”

Overview of 2015 results

During 2015, we had 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 beginning of the year. Our proved reserves decreased by 3.0 million Boe, in a large part due to a 99% decrease in proved undeveloped reserves as the drop in the price of oil has made much of our inventory in undeveloped wells uneconomic 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.

Total revenues from oil and gas sales decreased 28% in 2015 compared to 2014 driven by a decrease 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.

Going Concern Uncertainty

The Company’s liquidity outlook has changed since 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.

As a result of these and other factors, the following issues have adversely impacted the Company’s ability 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 commitment of additional capital by Chambers, totaling $30 million was not feasible for the Company because of the relative lack of capital available from the capital markets and without restructuring the Company’s balance sheet.

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-K 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.

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 be 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, 2015 and 2014.

The following table summarizes selected items from the statement of operations for the years ended December 31, 2015 and 2014.

Oil and Natural Gas Sales

We recognized $15,104,629 in oil and gas sales for the year ended December 31, 2015, compared to oil and gas sales of $21,102,823 for 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.

General and Administrative Expenses

General and administrative expenses for the year ended December 31, 2015 were $3,023,631, compared to $2,891,641 for the year ended December 31, 2014. The increase for 2015 as compared to 2014 was $131,990, or 5%, and is primarily attributed to salary increases. On a per Boe basis, general 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.

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, 2015 was $16,295, compared to $29,138 for the year ended December 31, 2014.

Other Income and (Expenses)

Other income and (expenses) for the year ended December 31, 2015, resulted in 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%.

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

We had an income tax benefit of $6,593,040 for the year ended December 31, 2015, compared to an income tax expense 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 taxes 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.

Net Income (Loss)

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 net 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 relating 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 Adjusted Net Income (Loss) and Adjusted EBITDA to manage our business, including the preparation of our annual operating budget and financial projections, we believe that non-GAAP financial measures have limitations and do not reflect all of the amounts associated with our results 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:

^(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 resources

The following table summarizes our total current assets, liabilities and working capital at December 31, 2015 and 2014.

As of December 31, 2015 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.

The following table summarizes our cash flows during the years ended December 31, 2015 and 2014, respectively.

Our net cash flows from operations are primarily affected by production volumes and commodity prices. Net cash provided by operating activities was $15,620,168 and $8,941,815 for the years ended December 31, 2015 and 2014, respectively, an increase of $6,678,353. The increase was primarily due to increased operating cash generated from realized gains on mark-to-market of derivatives of $11,477,653 on 2015 as compared $511,451 in 2014. Changes in current assets and liabilities resulted in an increase in cash of approximately $785,176 in 2015 and a decrease in cash of $2,370,769 in 2014, a net increase of $3,155,945 for 2015 as compared to 2014.

Net cash used in investing activities was $20,586,656 and $29,143,086 for the years ended December 31, 2015 and 2014, respectively, a decrease of $8,556,430. The decrease was primarily due to a decrease in purchases 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 proceeds from the sale 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.

Net cash provided from financing was $5,100,000 and $19,145,606 for the years ended December 31, 2015 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, 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 terms of the Senior Credit Agreement, a senior secured revolving line of credit 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 business operations of BRHC, including but not limited 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 in place until January 1, 2017.

Satisfaction of our cash obligations for the next 12 months

As of December 31, 2015, our balance of cash and cash equivalents was $228,194. Presuming the BRHC Transaction closes, our plan for satisfying our cash requirements for the next twelve months is through the terms of our management agreement.

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 we do not currently expect business costs to materially increase, higher prices for crude oil and natural gas could result in increases in the costs of materials, services and personnel.

Contractual obligations and commitments

The following table summarizes our obligations and commitments as of December 31, 2015 to make future payments under certain contracts, aggregated by category of obligation, for specified time periods:

⁽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, we had eight employees, our chief executive officer, Kenneth DeCubellis, our chief financial officer, James Moe, our chief operating officer, Michael Eisele and five 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 oil and gas business by participating in additional drilling opportunities and continuing to acquire new mineral leases, 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

The 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.

Interest Rate Risk

Our credit facilities are tied to LIBOR if and when the associated LIBOR 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.

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

BLACK RIDGE OIL & GAS, INC.

FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2015 AND 2014

CONTENTS

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors

Black Ridge Oil & Gas, Inc.

We have audited the accompanying balance sheets of Black Ridge Oil & Gas, Inc. (the “Company”) as of December 31, 2015 and 2014 and the related statements of operations, stockholders' equity, and cash flows for the years then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

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

In our opinion, the 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 covenants and has insufficient working capital, which raises substantial doubt about its ability to continue as a going concern. Management's plans regarding those matters 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.

BALANCE SHEETS

The accompanying notes are an integral part of these financial statements.

BLACK RIDGE OIL & GAS, INC.

STATEMENTS OF OPERATIONS

The accompanying notes are an integral part of these financial statements.

BLACK RIDGE OIL & GAS, INC.

STATEMENT OF STOCKHOLDERS' EQUITY

The accompanying notes are an integral part of these financial statements.

BLACK RIDGE OIL & GAS, INC.

STATEMENTS OF CASH FLOWS

The accompanying notes are an integral part of these financial statements.

BLACK RIDGE OIL & GAS, INC.

NOTES TO FINANCIAL STATEMENTS

Note 1 – Organization and Nature of Business

Effective April 2, 2012, Ante5, Inc. changed its corporate name to Black Ridge Oil & Gas, Inc., and continues to trade its common stock on the OTCQB under the trading symbol “ANFC”. Black Ridge Oil & Gas, Inc. (Formerly Ante5, Inc.) (the “Company”) became an independent company in April 2010 when the spin-off from our former parent company, Ante4, Inc. (now Emerald Oil, Inc. and also formerly known as Voyager Oil & Gas, Inc.), became effective. We became a publicly traded company when our shares began trading on July 1, 2010. Since October 2010, we have been engaged in the business of acquiring oil and gas leases and participating in the drilling of wells in the Bakken and Three Forks trends in North Dakota and Montana. Our strategy is to participate in the exploration, development and production of oil and gas reserves as a non-operating working interest owner in a growing, diversified portfolio of oil and gas wells. We aggressively seek to accumulate mineral leases to position us to participate in the drilling of new wells on a continuous basis. Occasionally we also purchase working interests in producing wells.

The Company’s focus 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. We believe that our prospective success revolves around our ability to acquire mineral rights and participate in drilling activities by virtue of our ownership of such rights and through the relationships we have developed with our operating partners.

As a non-operating working interest partner, we participate in drilling activities primarily on a heads-up basis. Before a well is spud, an operator is required to offer all mineral lease owners in the designated well spacing unit the right to participate in the drilling and production of the well. Drilling costs and revenues from oil and gas sales are split pro-rata based on acreage ownership in the designated drilling unit. We rely on our operator partners to identify specific drilling sites, permit, and engage in the drilling process. As a non-operator we are focused on maintaining a low overhead structure.

Note 2 – Summary of Significant Accounting Policies

Basis of Accounting

Our financial statements are prepared using the accrual method of accounting as generally accepted in the United States of America (U.S. GAAP) and the rules of the Securities and Exchange Commission (SEC).

Segment Reporting

FASB ASC 280-10-50 requires annual and interim reporting for an enterprise’s operating segments and related disclosures about its products, services, geographic areas and major customers. An operating segment is defined as a component of an enterprise that engages in business activities from which it may earn revenues and expenses, and about which separate financial information is regularly evaluated by the chief operating decision maker in deciding how to allocate resources. The Company operates as a single segment and will evaluate additional segment disclosure requirements as it expands its operations.

Use of Estimates

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

Environmental Liabilities

The oil and gas industry is subject, by its nature, to environmental hazards and clean-up costs. At this time, management knows of no substantial losses from environmental accidents or events which would have a material effect on the Company.

Cash and Cash Equivalents

Cash equivalents include money market accounts which have maturities of three months or less. For the purpose of the statements of cash flows, all highly liquid investments with an original maturity of three months or less are considered to be cash equivalents. Cash equivalents are stated at cost plus accrued interest, which approximates market value. The Company had no cash equivalents on hand as of December 31, 2015 and December 31, 2014.

Cash in Excess of FDIC Insured Limits

The Company maintains its cash in bank deposit accounts which, at times, may exceed federally insured limits. Accounts are guaranteed by the Federal Deposit Insurance Corporation (FDIC) up to $250,000, under current regulations. The Company didn’t have any funds in excess of FDIC insured limits at December 31, 2015 and 2014. The Company has not experienced any losses in such accounts.

BLACK RIDGE OIL & GAS, INC.

NOTES TO FINANCIAL STATEMENTS

Advances to Operators

The Company participates in the drilling of crude oil and natural gas wells with other working interest partners. Due to the capital intensive nature of crude oil and natural gas drilling activities, the working interest partner responsible for conducting the drilling operations may request advance payments from other working interest partners for their share of the costs. The Company expects such advances to be applied by working interest partners against joint interest billings for its share of the drilling operations within 120 days from when the advance is paid.

Debt Issuance Costs

Costs relating to obtaining certain debts are capitalized and amortized over the term of the related debt using the straight-line method, which approximates the effective interest method. The Company paid $50,000 and $254,394 of debt issuance costs during the years ended December 31, 2015 and 2014, respectively, of which the unamortized balance of debt issuance costs at December 31, 2015 and 2014 was $0 and $701,019, respectively. Amortization of debt issuance costs charged to interest expense was $751,019 and $326,258 for the years ended December 31, 2015 and 2014, respectively. When a loan is paid in full or becomes due on demand due to a default on the loan, any unamortized financing costs are removed from the related accounts and charged to interest expense.

Website Development Costs

The Company accounts for website development costs in accordance with ASC 350-50, “Accounting for Website Development Costs” (“ASC 350-50”), wherein website development costs are segregated into three activities:

We have capitalized a total of $56,660 of website development costs from inception through December 31, 2015. We have recognized depreciation expense on these website costs of $257 and $15,380 for the years ended December 31, 2015 and 2014, respectively.

Income Taxes

The Company recognizes deferred tax assets and liabilities based on differences between the financial reporting and tax basis of assets and liabilities using the enacted tax rates and laws that are expected to be in effect when the differences are expected to be recovered. The Company provides a valuation allowance for deferred tax assets for which it does not consider realization of such assets to be more likely than not.

Fair Value of Financial Instruments

Under FASB ASC 820-10-05, the Financial Accounting Standards Board establishes a framework for measuring fair value in generally accepted accounting principles and expands disclosures about fair value measurements. This Statement reaffirms that fair value is the relevant measurement attribute. The adoption of this standard did not have a material effect on the Company’s financial statements as reflected herein. The carrying amounts of cash, accounts payable and accrued expenses reported on the balance sheets are estimated by management to approximate fair value primarily due to the short term nature of the instruments. The Company had no items that required fair value measurement on a recurring basis.

Non-Oil & Gas Property and Equipment

Property and equipment that are not oil and natural gas properties are recorded at cost and depreciated using the straight-line method over their estimated useful lives of three to seven years. Expenditures for replacements, renewals, and betterments are capitalized. Maintenance and repairs are charged to operations as incurred. Long-lived assets, other than oil and natural gas properties, are evaluated for impairment to determine if current circumstances and market conditions indicate the carrying amount may not be recoverable. The Company has not recognized any impairment losses on non-oil and gas long-lived assets. Depreciation expense was $16,295 and $29,138 for the years ended December 31, 2015 and 2014, respectively.

BLACK RIDGE OIL & GAS, INC.

NOTES TO FINANCIAL STATEMENTS

Revenue Recognition

The Company recognizes oil and gas revenues from its interests in producing wells when production is delivered to, and title has transferred to, the purchaser and to the extent the selling price is reasonably determinable. The Company uses the sales method of accounting for gas balancing of gas production and would recognize a liability if the existing proved reserves were not adequate to cover the current imbalance situation.

Asset Retirement Obligations

The Company records the fair value of a liability for an asset retirement obligation in the period in which the well is spud or the asset is acquired and a corresponding increase in the carrying amount of the related long-lived asset. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized.

Full Cost Method

The Company follows the full cost method of accounting for oil and gas operations whereby all costs related to the exploration and development of oil and natural gas properties are initially capitalized into a single cost center ("full cost pool"). Such costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling directly related to acquisition, and exploration activities. Internal costs that are capitalized are directly attributable to acquisition, exploration and development activities and do not include costs related to the production, general corporate overhead or similar activities. Costs associated with production and general corporate activities are expensed in the period incurred. Capitalized costs are summarized as follows for the years ended December 31, 2015 and 2014, respectively:

Proceeds from property sales will generally be credited to the full cost pool, with no gain or loss recognized, unless such a sale would significantly alter the relationship between capitalized costs and the proved reserves attributable to these costs. A significant alteration would typically involve a sale of 20% or more of the proved reserves related to a single full cost pool. During the year ended December 31, 2015, the Company sold approximately 14 net acres and rights to individual well bores for total proceeds of $127,348. During the year ended December 31, 2014, the Company sold approximately 502 net acres for total proceeds of $1,441,929. The Company assesses all items classified as unevaluated property on a quarterly basis for possible impairment or reduction in value. The assessment includes consideration of the following factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization.

Capitalized costs associated with impaired properties and properties having proved reserves, estimated future development costs, and asset retirement costs under FASB ASC 410-20-25 are depleted and amortized on the unit-of-production method based on the estimated gross proved reserves as determined by independent petroleum engineers. The costs of unproved properties are withheld from the depletion base until such time as they are either developed or abandoned.

Capitalized costs of oil and natural gas properties (net of related deferred income taxes) may not exceed an amount equal to the present value, discounted at 10% per annum, of the estimated future net cash flows from proved oil and gas reserves plus the cost of unproved properties (adjusted for related income tax effects). Should capitalized costs exceed this ceiling, impairment is recognized. The present value of estimated future net cash flows is computed by applying the arithmetic average first day price of oil and natural gas for the preceding twelve months to estimated future production of proved oil and gas reserves as of the end of the period, less estimated future expenditures to be incurred in developing and producing the proved reserves and assuming continuation of existing economic conditions. Such present value of proved reserves' future net cash flows excludes future cash outflows associated with settling asset retirement obligations. Should this comparison indicate an excess carrying value, the excess is charged to earnings as an impairment expense. The Company recognized impairments of oil and gas properties of $71,272,000 in the year ended December 31, 2015. No impairment was recognized during the year ended December 31, 2014.

BLACK RIDGE OIL & GAS, INC.

NOTES TO FINANCIAL STATEMENTS

Concentrations

Our revenue is solely derived from oil and gas sales to various purchasers, the market for which has very inelastic demand. Due to this, we do not consider any purchasers to represent a material concentration to our sales for the years ended December 31, 2015 or 2014, as we believe any of our customers could easily be replaced.

Since we do not operate any of our wells, we depend on our drilling partner operators to perform the drilling and other operating activities required for all sales of oil and gas. These operators are also responsible for remitting to us our revenue proceeds and billing us for drilling costs and lease operating expenses incurred. We had material concentrations of accounts receivable owed from four (4) and four (4) operators during the years ended December 31, 2015 and 2014, respectively, representing 70% and 56% of total oil and gas revenues and 73% and 49% of total oil and gas accounts receivable as of December 31, 2015 and 2014, respectively. As of December 31, 2015 and 2014, we had 10.95 and 7.88 net producing wells, respectively. As of December 31, 2015 and 2014, these operating partners operated 56% and 52% of the net producing wells, respectively.

Basic and Diluted Loss Per Share

Basic earnings per share (“EPS”) are computed by dividing net income (the numerator) by the weighted average number of common shares outstanding for the period (the denominator). Diluted EPS is computed by dividing net income by the weighted average number of common shares and potential common shares outstanding (if dilutive) during each period. Potential common shares include stock options, warrants and restricted stock. The number of potential common shares outstanding relating to stock options, warrants and restricted stock is computed using the treasury stock method.

The reconciliation of the denominators used to calculate basic EPS and diluted EPS for the years ended December 31, 2015 and 2014 are as follows:

For 2015, potential dilutive securities had an anti-dilutive effect and were not included in the calculation of diluted net loss per common share. Stock options and warrants excluded from the calculation of diluted EPS because their effect was anti-dilutive were 15,603,375 and 13,683,209 as of December 31, 2015 and 2014, respectively.

Stock-Based Compensation

Under FASB ASC 718-10-30-2, all share-based payments to employees, including grants of employee stock options, are to be recognized in the income statement based on their fair values. Pro forma disclosure is no longer an alternative. Amortization of the fair values of stock options issued for services and compensation totaled $623,700 and $578,919 for the years ended December 31, 2015 and 2014, respectively. The fair values of stock options were determined using the Black-Scholes options pricing model and an effective term of 6 to 6.5 years based on the weighted average of the vesting periods and the stated term of the option grants and the discount rate on 5 to 7 year U.S. Treasury securities at the grant date and are being amortized over the related implied service term, or vesting period.

Uncertain Tax Positions

In accordance with ASC 740, “Income Taxes” (“ASC 740”), the Company recognizes the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be capable of withstanding examination by the taxing authorities based on the technical merits of the position. These standards prescribe a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. These standards also provide guidance on de-recognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition.

BLACK RIDGE OIL & GAS, INC.

NOTES TO FINANCIAL STATEMENTS

Various taxing authorities can periodically audit the Company’s income tax returns. These audits include questions regarding the Company’s tax filing positions, including the timing and amount of deductions and the allocation of income to various tax jurisdictions. In evaluating the exposures connected with these various tax filing positions, including state and local taxes, the Company records allowances for probable exposures. A number of years may elapse before a particular matter, for which an allowance has been established, is audited and fully resolved. The Company has not yet undergone an examination by any taxing authorities.

The assessment of the Company’s tax position relies on the judgment of management to estimate the exposures associated with the Company’s various filing positions.

Recent Accounting Pronouncements

From time to time, new accounting pronouncements are issued by the Financial Accounting Standards Board ("FASB") that are adopted by the Company as of the specified effective date. If not discussed, management believes that the impact of recently issued standards, which are not yet effective, will not have a material impact on the Company's financial statements upon adoption.

In May 2014, the FASB issued Accounting Standards Update (ASU) No. 2014-09, "Revenue from Contracts with Customers." The standard requires an entity to recognize revenue in a manner that depicts the transfer of goods or services to customers at an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU No. 2014-09 will supersede most of the existing revenue recognition requirements in United States GAAP when it becomes effective and is required to be adopted using one of two retrospective application methods. In August 2015, the FASB issued ASU No. 2015-14, "Revenue from Contracts with Customers – Deferral of the Effective Date," which approved a one year deferral of ASU 2014-09 for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. Early application is permitted as of the original effective date for annual reporting periods beginning after December 15, 2016, including interim reporting periods within that reporting period. The Company is currently evaluating the method of adoption and impact this standard will have on its financial statements and related disclosures.

In August 2014, the FASB issued ASU No. 2014-15, "Presentation of Financial Statements - Going Concern (Subtopic 205-40)." The new guidance addresses management's responsibility to evaluate whether there is substantial doubt about an entity's ability to continue as a going concern and in certain circumstances to provide related footnote disclosures. The standard is effective for the annual period beginning after December 15, 2016 and for annual and interim periods thereafter. Early adoption is permitted. The Company has chosen to adopt this pronouncement beginning with the issuance of this report due to the applicability to our current condition.

In April 2015, the FASB issued ASU No. 2015-03, "Interest – Imputation of Interest (Subtopic 835-30):  Simplifying the Presentation of Debt Issuance Costs," that requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by the amendments in this update. An entity is required to apply ASU 2015-03 for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. An entity should apply ASU 2015-03 on a retrospective basis, wherein the balance sheet of each individual period presented should be adjusted to reflect the period-specific effects of applying the new guidance. Upon transition, an entity is required to comply with the applicable disclosures for a change in an accounting principle. These disclosures include the nature of and reason for the change in accounting principle, the transition method, a description of the prior-period information that has been retrospectively adjusted, and the effect of the change on the financial statement line items. The Company is currently evaluating the impact that this new guidance will have on its financial statements.

In November 2015, the FASB issued ASU 2015-17, Balance Sheet Classification of Deferred Taxes, which eliminates the current requirement to present deferred tax liabilities and assets as current and noncurrent amounts in a classified statement of financial position. Instead, entities will be required to classify all deferred tax assets and liabilities as noncurrent in a statement of financial position. This standard is effective financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Early application is permitted. The Company elected early application of this ASU as of December 31, 2015, and has applied its provisions prospectively.

BLACK RIDGE OIL & GAS, INC.

NOTES TO FINANCIAL STATEMENTS

Note 3 – Going Concern

As shown in the accompanying financial statements, the Company has incurred losses from operations resulting in an accumulated deficit of ($64,697,163), as of December 31, 2015, the Company’s current liabilities exceeded its current assets by $61,855,057, which includes the current classification of all of the Company’s debt, and its total liabilities exceeded its total assets by $30,373,769. As of December 31, 2015, the Company is out of compliance with the collateral coverage ratio covenant contained in both its Senior Secured Facility and Subordinated Credit Facility which constitutes an event of default. These factors raise substantial doubt about the Company’s ability to continue as a going concern.

In August 2014, the FASB issued ASU No. 2014-15, "Presentation of Financial Statements - Going Concern (Subtopic 205-40)". The Company has chosen to adopt this pronouncement beginning with the issuance of this report due to the applicability to our current condition. The new guidance addresses management's responsibility to evaluate whether there is substantial doubt about an entity's ability to continue as a going concern and in certain circumstances to provide related footnote disclosures.

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.

BLACK RIDGE OIL & GAS, INC.

NOTES TO FINANCIAL STATEMENTS

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 business operations of BRHC, including but not limited 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 December 31, 2016 that BRHC shall pay the Company a termination fee equal to the amount that would have been paid if the Management Services Agreement was in place until December 31, 2016.

The Company believes that the BRHC Transaction and related actions will allow the Company to continue as a manager of the oil and gas assets in which we will continue to have an indirect minority interest. In addition, it will give us the flexibility 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.

However, the BRHC Transaction has not closed as of the date of this report and certain conditions remain to be met prior to closing. ASU 2014-15 does not allow the Company to consider a plan when evaluating going concern uncertainties until that plan has been fully implemented. As the Company’s plans are not fully implemented, there remains substantial doubt about the Company’s ability to continue as a going concern.

The financial statements do not include any adjustments that might result from the outcome of any uncertainty as to the Company’s ability to continue as a going concern. These financial statements also do not include any adjustments relating to the recoverability and classification of recorded asset amounts, or amounts and classifications of liabilities that might be necessary should the Company be unable to continue as a going concern.

Note 4 – Joint Venture

On July 20, 2015, the Company signed a definitive agreement with an affiliate of Merced Capital (“Merced”) to form a joint venture that will acquire and develop Williston Basin non-operated assets. The joint venture will be funded by Merced with an initial investment target of $50 Million. Investments will be subject to Merced approval, and will be managed by the Company.

The joint venture assets will be managed by the Company in exchange for a management fee and reimbursement of third party expenses, and, after certain investor hurdles are met, the Company will receive a share of profits in the joint venture. The Company will also have the option to co-invest up to 25% on acquisitions and capital expenditures alongside the venture and any such co-investments will reside directly with the Company. Upon the sale of joint venture assets, the Company will also have the option to bid and acquire the assets.

We have not yet commenced operations pursuant to this joint venture.

BLACK RIDGE OIL & GAS, INC.

NOTES TO FINANCIAL STATEMENTS

Note 5 – Dahl Federal Recognition

During the second quarter of 2015, we recognized well costs, revenues and expenses related to the Dahl Federal 2-15H (Dahl Federal) back to the inception of the well in 2012. The Company acquired the lease for mineral rights for the acreage related to the Dahl Federal from the State of North Dakota on February 7, 2012 for 110 acres or an 8.7% working interest in the Dahl Federal well that spud on January 6, 2012. The acreage we purchased lies within the riverbed of the Missouri River and there had been third-party litigation ongoing in the State of North Dakota pertaining to the state’s ownership claim to similar riparian acreage. We had signed an AFE for the well and the operator agreed to retroactively honor the AFE if the state was successful in defending its ownership claim. As the ownership of our acreage was not certain, we determined we could not recognize the well costs, revenues and expenses until the ownership questions were resolved. In April of 2015, after a North Dakota Supreme Court ruling in favor of the State and subsequent consensus by numerous parties as to the proper survey to be used in determining the high water mark of the Missouri River, the State of North Dakota began requesting payment of royalties for wells under similar circumstances from other operators. Because we believe the ownership questions have now been resolved, we capitalized all well costs since the well’s inception, and have recognized revenues and expenses from the Dahl Federal’s first production in May of 2012. We have capitalized $927,312 of well costs related to the original AFE and subsequent improvements. We recognized $1,170,236 of oil and gas revenues, $75,359 of operating expenses and $130,014 of production taxes during the year ended December 31, 2015 related to production prior to 2015 in addition to actual revenue and expenses for the period.

Note 6 – Related Party

During the years ended December 31, 2015 and 2014, we granted various awards to our Officers and Directors as compensation for their services. These related party grants are fully disclosed in Note 14 below.

Other Related Party Transactions

We currently lease office space on a month to month basis where the lessor is an entity owned by our Chairman of the Board of Directors, Bradley Berman for 2,813 square feet of office space. In accordance with this lease, our lease term is 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 subject to increases of $117 per month beginning November 1, 2014 and for each of the subsequent three year periods. As of December 31, 2015 the base rent is $2,344 per month. We have paid a total of $69,703 and $69,300 to this entity during the years ended December 31, 2015 and 2014, respectively.

Note 7 – Property and Equipment

Property and equipment December 31, 2015 and 2014, consisted of the following:

BLACK RIDGE OIL & GAS, INC.

NOTES TO FINANCIAL STATEMENTS