Sow Good Inc. - Annual Report: 2012 (Form 10-K)

FORM 10-K

U.S. SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

[X] ANNUAL REPORT UNDER SECTION 13 OR 15(D) OF

THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended: December 31, 2012

Commission file number 000-53952

(Formerly Ante5, Inc.)

(Name of registrant as in its charter)

10275 Wayzata Blvd. Suite 310, Minnetonka, Minnesota 55305

(Address of principal executive offices) (Zip Code)

(952) 426-1241

Registrant’s telephone number, including area code

Securities registered under 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 |_| 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 |_| 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 |_|

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 |_|

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.

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

Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes |_| No |X|

The aggregate market value of voting stock held by non-affiliates of the registrant was approximately $20,053,907 as of June 30, 2012 (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 27, 2013.

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, 2012, we controlled the rights to mineral leases covering approximately 12,256 net acres for prospective drilling to the Bakken and/or Three Forks formations. Looking forward, we are pursuing the following objectives:

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

Recent Developments

Peerless/ElectraWorks Settlement

We inherited assets from our former parent company prior to our spin off. These historical assets relate to our former parent company’s business as WPT Enterprises, Inc., when it created internationally branded products through the development, production and marketing of televised programming based on gaming themes. The primary historical gaming asset was our license agreement with Peerless Media, Ltd. (“Peerless”) and ElectraWorks, Ltd. (“ElectraWorks”), subsidiaries of PartyGaming, PLC (collectively “PartyGaming”), an international online casino gaming company. On July 9, 2012, we formed a wholly-owned subsidiary in the state of Nevada called Poker Interest, LLC. Commensurate with the formation of this entity we assigned all rights and obligations obtained pursuant to an Asset Purchase Agreement, dated August 24, 2009 from Peerless to this newly formed entity. On September 27, 2012, the Company entered into a settlement agreement with Peerless/ElectraWorks to settle claims regarding their performance under the license agreement. Under the settlement agreement Peerless/ElectraWorks has paid the Company $11.0 million in two installments of $5.5 million on October 30, 2012 and December 17, 2012, and is obligated to pay the Company another $2.5 million on or before December 31, 2013. In addition, Peerless/ElectraWorks will make payments to the Company upon certain contingencies related to the passage of federal or state legislation permitting real money online poker and Peerless/ElectraWorks or one of their affiliates obtaining such a license. The maximum amount of these contingent payments is $6.5 million with the amount determined based on how such legislation is enacted. Under the settlement agreement the Company has released its rights to the royalty stream and no further payments are due from Peerless/ElectraWorks other than those set forth in the settlement agreement.

The Company has paid attorneys’ fees of $1.84 million as well as various costs out of the Peerless /Electra settlement proceeds and is obligated to pay an additional $160,000 in attorneys’ fee upon receipt of the remaining $2.5 million due from Peerless/ElectraWorks. In addition, as a result of an incentive arrangement with the Company’s former President, Chief Executive Officer and Secretary, Steve Lipscomb that was approved by WPT Enterprises, Inc.’s Board of Directors in February 2009, Mr. Lipscomb is receiving 5% of the settlement payments, net of attorneys’ fees and other costs as such amounts are received by the Company.

Deloitte & Touche Settlement

On October 5, 2012, the Company and other parties entered into a settlement agreement with Deloitte & Touche, LLP ("Deloitte & Touche") to settle all claims between the parties arising out of the case of WPT Enterprises, Inc. v. Deloitte & Touche, before the Superior Court of the State of California, County of Los Angeles (the "Litigation"). The claims in the Litigation were assigned to the Company as part of the Company’s distribution (spin-off) agreement with Ante4, Inc. On November 1, 2012, after satisfying obligations to various parties, including litigation counsel, the Company received $5.4 million of net proceeds under the settlement agreement as its share of the settlement proceeds. The parties have agreed to stipulate to the dismissal of the Litigation and to a mutual release of all claims.

Reincorporation into Nevada

We completed a reincorporation into the state of Nevada on December 10, 2012. Our Board approved resolutions authorizing the Company to reincorporate into Nevada. Our stockholders also approved the reincorporation by written consent.

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 March 15, 2013, we controlled approximately 12,971 net acres in the Williston Basin. In addition, the Company owned working interests in 91 gross wells representing 3.20 net wells that are preparing to drill, drilling, awaiting completion, complete or producing.

We control some properties in which we may have control of the drilling unit. We currently anticipate selling or trading some or all of our interest in these properties in order to relinquish controlling interest to an operator capable of developing the properties.

Through alliances we have with partners on the ground 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 rapidly expanding Bakken and Three Forks trends. Because we purchase smaller 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 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.

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.

Our proven oil and gas reserves were 2.4 million barrel of oil equivalents (BOE’s) as of December 31, 2012 and 0.5 million barrel of oil equivalents (BOE’s) as of December 31, 2011.

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. 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. We will assess each drilling opportunity on a case-by-case basis going forward. We will participate in wells that we expect to meet our return thresholds based upon our estimates of ultimate recoverable crude oil and natural gas and other factors. In 2011 we participated in the drilling of all new wells that included any of our acreage. In 2012 we participated in the drilling of all new wells that included any of our acreage with the exception of two gross wells totaling 0.02 net wells. At present time, we expect to participate in the majority of the wells proposed to us, but will decline drilling opportunities that we believe will not meet our return criteria over a long-term horizon.

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 pipelines 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 anticipate some of our leases will expire prior to being held by production.  We did not have any leases expire in 2012.

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 originally proposed in 2011 establishing new air emission controls for oil and natural gas production and natural gas processing operations. The EPA’s rule package includes standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. 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. 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.

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 hydraulic fracturing’s potential impacts. Several states, including Montana and North Dakota where our properties are located, have also proposed or adopted legislative or regulatory restrictions on hydraulic fracturing. 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. Many states and the federal government have enacted legislation directed at controlling greenhouse gas emissions. Future legislation and regulation could impose additional restrictions in connection with our drilling and production activities and favor use of alternative energy sources, which could increase operating costs and reduce demand for crude oil products. As such, our business could be materially adversely affected by domestic and international legislation targeted at controlling climate change.

Employees

We currently have five full time employees: our chief executive officer, chief financial officer, vice president of land, corporate controller and a staff accountant. Our chief executive officer, Kenneth DeCubellis, is responsible for all material policy-making decisions, with the support of James Moe, our chief financial officer. As drilling and production activities continue to increase, we may hire additional technical or administrative personnel as appropriate. We are using and will continue to use the services of independent consultants and contractors to perform various professional services, particularly in the area of land services and reservoir engineering. 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 310, Minnetonka, Minnesota 55305. Our office space consists of approximately 1,142 square feet leased pursuant to a lease agreement that commenced on May 1, 2012 on a month to month basis. The owner of 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

Risks Related to our Business

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.

We own some properties in which we may have control of the drilling unit. We currently anticipate selling or trading some of the acres within these properties in order for our ownership to be reduced so that we would not have control of the drilling unit or entering into other arrangements in order to not be the operator of such drilling units. Since we do not have the ability to operate the drilling unit, if we are unable to sell or trade these properties or enter into other arrangement with a potential operator of the drilling units, the lease could lapse or we would be required to incur significant additional costs to operate the drilling unit.

The possibility of a global financial crisis may significantly impact our business and financial condition for the foreseeable future.

The ongoing credit crisis and related turmoil in the global financial system may adversely impact our business and our financial condition, and we may face challenges if conditions in the financial markets do not improve. Our ability to access the capital markets may be restricted at a time when we would like, or need, to raise financing, which could have a material negative impact on our flexibility to react to changing economic and business conditions. The economic situation could have a material negative impact on operators upon whom we are dependent for drilling our wells, our lenders or customers, causing them to fail to meet their obligations to us. Additionally, market conditions could have a material negative impact on potential future crude oil hedging arrangements if our counterparties are unable to perform their obligations or seek bankruptcy protection. We believe we will need additional capital and financing to fund our future land acquisitions and drilling. There is no assurance that additional capital or financing will be available to us on terms that are acceptable to us or at all.

We may be unable to obtain the additional capital that we need to implement our business plan, which could restrict our ability to grow.

We have entered into a $20 million revolving credit facility (of which $16.5 million is currently available) secured by substantially all of our assets, but that credit facility may not be available to us if we are not in compliance with its terms and conditions. We had drawn a net $5,748,844 as of December 31, 2012 and had no additional draws through March 15, 2013. We will require additional 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 also expect to seek equity financing to finance our expected drilling and completion costs. 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 decline, 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. 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.

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. We began to generate revenues from operations during 2011, and have incurred operating losses since our inception in April 2010. 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; 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.

We are highly dependent on Kenneth DeCubellis, our chief executive officer, and our other executive officer 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 (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.

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.

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.

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 we will need to operate our business in the areas in which we expect to operate. 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.

We have a history of losses which may continue and negatively impact our ability to achieve our business objectives.

We had net income of $4,911,410 in the fiscal year ended December 31, 2012, however before settlement income, net of settlement expenses and related income taxes, the Company had a loss of approximately $1,444,485 (see Item 7 – Managements’ Discussion and Analysis of Financial Condition and Results of Operations - Non-GAAP Financial Measures). We incurred net losses of $2,482,255 for the fiscal year ended December 31, 2011. We cannot assure you that we can achieve or sustain profitability on a quarterly or annual basis in the future. Our operations are subject to the risks and competition inherent in the oil and natural gas industry. We cannot assure you that future operations will be profitable. Revenues and profits, if any, will depend upon various factors, including whether we will be able to expand our revenues. We may not achieve our business objectives and the failure to achieve such goals would have an adverse impact on our business, financial condition and result of operations.

Downward adjustments in our proved reserve estimates and lower oil and natural gas prices may cause us to record ceiling test write-downs.

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. We recognized a ceiling test write-down of $2.4 million for the year ended December 31, 2011 due to a downward adjustment in our proved reserve estimate primarily associated with an adjustment to one well in which we own a large percentage. The Company incurred an impairment charge primarily due to this well’s substantially reduced production levels since resuming production. We did not incur a ceiling test write-down for the year ended December 31, 2012. We may recognize additional write-downs in the future if commodity prices decline or if we experience substantial downward adjustments to our estimated proved reserves.

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 engage in hedging activities that could result in financial losses, which may adversely affect investments in our common stock.

We may enter into swap arrangements from time-to-time to hedge our expected production depending on reserves and market conditions. While intended to reduce 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. In addition, such transactions may expose us to the risk of loss in certain circumstances, including instances in which our production is less than expected, there is a widening of price differentials between delivery points for our production, or the counterparties to our hedging agreements fail to perform under the contracts. In addition, the Dodd-Frank Act includes provisions relating to derivative contracts. While the ultimate impact of the Dodd-Frank Act on our derivatives activities is not known, it could ultimately have an adverse impact on us.

Risks Related To Our Industry

Crude oil and natural gas prices are very volatile. A protracted period of depressed crude oil and natural gas prices may adversely 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 worldwide financial and credit crisis reduced the availability of liquidity and credit to fund the continuation and expansion of industrial business operations worldwide. The shortage of liquidity and credit combined with recent substantial losses in worldwide equity markets led to a worldwide economic recession. The slowdown in economic activity caused by future similar recessions could reduce worldwide demand for energy resulting in lower crude oil and natural gas prices and restrict our access to liquidity and credit. Lower crude oil and natural gas prices may not only decrease our revenues on a per unit basis but also may reduce the amount of crude oil and natural gas that we can produce economically, potentially lowering our reserves. A substantial or extended decline in crude oil or natural gas prices may 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 may also reduce our ability to borrow or obtain credit to finance our operations.

Drilling for and producing crude oil and natural gas are high risk activities with many uncertainties and may not be commercially successful, and the advanced technologies we use cannot eliminate exploration risk.

Our future success will depend on the success of our development, production and exploration activities. Our crude oil and natural gas exploration and production activities are subject to numerous risks beyond our control; including the risk that drilling will not result in commercially viable crude oil or natural gas production. These risks are more acute in the early stages of exploration. Our decisions to purchase, explore, develop or otherwise exploit prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. Our cost of drilling, completing and operating wells is often uncertain before drilling commences. Overruns in budgeted expenditures are common risks that can make a particular project uneconomical. Our expenditures on exploration may not result in new discoveries of crude oil or natural gas in commercially viable quantities. Projecting the costs of implementing an exploratory drilling program is difficult due to the inherent uncertainties of drilling in unknown formations, the costs associated with encountering various drilling conditions, such as over-pressured zones and tools lost in the hole, and changes in drilling plans and locations as a result of prior exploratory wells or additional seismic data. Even when used and properly interpreted, three-dimensional (3-D) seismic data and visualization techniques only assist geoscientists in identifying subsurface structures and hydrocarbon indicators. Such data and techniques do not allow the interpreter to know conclusively if hydrocarbons are present or economically producible. In addition, the use of three-dimensional (3-D) seismic data becomes less reliable when used at increasing depths. We could incur losses as a result of expenditures on unsuccessful wells. If exploration costs exceed our estimates, or if our exploration efforts do not produce results which meet our expectations, our exploration efforts may not be commercially successful, which could adversely impact our ability to generate revenues from our operations. Further, many factors may curtail, delay or cancel drilling, including the following:

As a non-operator of oil and gas wells, we do not have sufficient control to manage these conditions, and the risks from them cannot entirely be eliminated. The presence of one or a combination of these factors at our properties could adversely affect our business, financial condition or results of operations.

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.

Estimates of crude oil and natural gas reserves that we make may be inaccurate and our actual revenues may be lower than our financial projections.

We make estimates of crude oil and natural gas reserves, upon which we base our financial projections. We make these reserve estimates using various assumptions, including assumptions as to crude 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, engineers and other advisors to make accurate assumptions. Economic factors beyond our control, such as crude oil and natural gas prices and interest rates, will also impact the value of our reserves. Determining the amount of crude oil and natural gas recoverable from various formations where we have exploration and production activities involves great uncertainty. The process of estimating crude oil and natural gas reserves is complex and will require us to use significant assumptions in the evaluation of available geological, geophysical, engineering and economic data for each property. As a result, our reserve estimates will be inherently imprecise. Actual future production, crude oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable crude oil and natural gas reserves may vary substantially from those we estimate. If actual production results vary substantially from our reserve estimates, this could materially reduce our revenues 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.

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.

Our operating partners may have difficulty distributing our production, which could harm our financial condition.

In order to sell the crude oil and natural gas that we are able to produce, the operators of our wells may have to make arrangements for storage and distribution to the market. We will rely on local infrastructure and the availability of transportation for storage and shipment of our products, but infrastructure development and storage and transportation facilities may be insufficient for our needs at commercially acceptable terms in the localities in which we operate. This situation could be particularly problematic to the extent that our operations are conducted in remote areas that are difficult to access, such as areas that are distant from shipping and/or pipeline facilities. These factors may affect our ability to explore and develop properties and to store and transport our crude oil and natural gas production, increasing our expenses. Furthermore, weather conditions or natural disasters, actions by companies doing business in one or more of the areas in which we will operate, or labor disputes may impair the distribution of crude oil and/or natural gas and in turn diminish our financial condition or ability to maintain our operations.

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.

Our business will suffer if we 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 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.

Challenges to our properties may impact our financial condition.

Title to crude oil and natural gas interests is often not capable of conclusive determination without incurring substantial expense. While we intend to make appropriate inquiries into the title of properties and other development rights we acquire, title defects may exist. In addition, we may be unable to obtain adequate insurance for title defects on a commercially reasonable basis or at all. If title defects do exist, it is possible that we may lose all or a portion of our right, title and interests in and to the properties to which the title defects relate. If our property rights are reduced, our ability to conduct our exploration, development and production activities may be impaired. To mitigate title problems, operators of the drilling units that we have an interest in follow common industry practice of obtaining a title opinion from a qualified crude oil and natural gas attorney prior to the drilling operations of a well.

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.

Penalties we may incur could impair our business.

Failure to comply with government regulations could subject us to civil and criminal penalties, could require us to forfeit property rights, and may affect the value of our assets. We may also be required to take corrective actions, such as installing additional equipment or taking other actions, each of which could require us to make substantial capital expenditures. We could also be required to indemnify our employees in connection with any expenses or liabilities that they may incur individually in connection with regulatory action against them. As a result, our future business prospects could deteriorate due to regulatory constraints, and our profitability could be impaired by our obligation to provide such indemnification to our employees.

Federal or state hydraulic fracturing legislation could increase our costs or restrict our access to oil and natural gas reserves.

Hydraulic fracturing using fluids other than diesel is currently exempt from regulation under the federal Safe Drinking Water Act, but opponents of hydraulic fracturing have called for further study of the technique’s environmental effects and, in some cases, a moratorium on the use of the technique. Several bills have been offered in Congress that, if implemented, would subject all hydraulic fracturing to regulation under the Safe Drinking Water Act and require disclosure of materials used in the hydraulic fracturing process. Congress has also directed the EPA’s Office of Research and Development (ORD) to investigate the possible relationships between hydraulic fracturing and drinking water. The Study of the Potential Impacts of Hydraulic Fracturing on Drinking Water Resources: Progress Report was published in December 2012, but the information gathered to date cannot be used to draw scientific conclusions. Technical workshops and roundtables are scheduled for 2013, and a draft report of study results is expected in late 2014. Further, under the federal Clean Water Act, the EPA is currently developing standards for treating wastewater produced by natural gas extraction from underground shale formations. The EPA plans to publish a proposed rule in 2014. Several states are considering legislation to regulate hydraulic fracturing practices, including restrictions on its use in environmentally sensitive areas. Some municipalities have significantly limited or prohibited drilling activities, or are considering doing so.

Although it is not possible at this time to predict the final outcome of the ORD’s study or the requirements of any additional federal or state legislation or regulation regarding hydraulic fracturing, any new federal or state, or local restrictions on hydraulic fracturing that may be imposed in areas in which we conduct business, such as the Bakken and Three Forks areas, could significantly increase our operating, capital and compliance costs as well as delay or halt our ability to develop oil and natural gas reserves.

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 coming to market of crude oil and natural gas reserves that we are able to discover and develop, 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 options and issuance of common stock under our incentive plans.

As of December 31, 2012, we had options for 4,149,001 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, 4,463,375 shares of our common stock may be issued upon the exercise of warrants held by certain of our stockholders. If the stockholders 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 revolving credit facility, 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 and OTCBB. Should we fail to remain traded on the OTCQB and OTCBB or not be able to be traded on the OTCQB and OTCBB, 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 and OTCBB, 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.

ITEM 1B. Unresolved Staff Comments

None.

ITEM 2. Properties

Executive Offices

Our executive offices are located at 10275 Wayzata Boulevard, Suite 310, Minnetonka, Minnesota 55305. We lease 1,142 square feet pursuant to a lease agreement that commenced on May 1, 2012 on a month-to-month basis. 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 $1,142 per month, plus common area operations and maintenance charges, and monthly parking fees of $240 per month, for the first year commencing on May 1, 2012, and increases of $24 per month for each of the subsequent four 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, 2012, the Company controls approximately 12,256 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.

Acreage

The following table summarizes our estimated gross and net developed and undeveloped acreage by state and resource play at December 31, 2012. Net acreage represents our percentage ownership of gross acreage.

Recent Acreage Acquisitions

In 2012, we acquired leasehold interests covering an aggregate of approximately 2,306 net mineral acres in our key prospect areas for an average of $1,409 per net acre.

Recent Divestitures

In 2012, we sold leasehold interests covering an aggregate of approximately 506 net mineral acres in our key prospect areas for an average of $3,741 per net acre. The proceeds of the sales were applied to reduce the capitalized costs of oil and gas properties.

Undeveloped Acreage Expirations

The following table sets forth the number of gross and net undeveloped acres as of December 31, 2012 that will expire over the next three fiscal years unless production is established within the spacing units covering the acreage prior to the expiration dates:

Of the net acres that expire in 2013, 2014 and 2015, we have 161, 7, and 250 acres, respectively, which are under a well that is currently completed, awaiting completion, drilling, preparing to drill or permitted.

In addition, of the remaining undeveloped acreage leases that expire in 2013, 2014 and 2015, there are 1,483, 2,741 and 207 acres, respectively, in which we have options to extend the lease.

During 2012, we had no leases expire.

Productive Oil Wells

The following table summarizes gross and net productive oil wells by state at December 31, 2012 and 2011. A net well represents our percentage ownership of a gross well. The following table does not include wells in which our interest is limited to royalty and 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, 2012 and 2011. The wells are at various stages of completion and the costs incurred are included in unevaluated oil and 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, 2012 and 2011, respectively. As of December 31, 2012 and 2011 we were selling oil and natural gas from a total of 66 gross wells (approximately 2.30 net wells) and 24 gross wells (approximately 0.68 net wells), respectively. All data presented below is derived from accrued revenue and production volumes for the relevant period indicated. We entered into the oil & gas industry in October of 2010.

Reserves

We completed our most recent reserve calculations as of December 31, 2012.

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 accumulated 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 and Associates, Inc. (“NSAI”), an independent reservoir engineering firm, as our third-party engineering firm with the preparation of our December 31, 2012 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, 2012, 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.

We expect that our proved undeveloped reserves will continue to be converted to proved developed producing reserves as additional wells are drilled within our acreage. We do not have any material amounts of proved undeveloped reserves that have remained undeveloped for five years or more.

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.

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, 2012 and 2011.

ITEM 3. LEGAL PROCEEDINGS

On September 27, 2012, the Company entered into a settlement agreement with Peerless/ElectraWorks to settle claims regarding their performance under the license agreement. Under the settlement agreement Peerless/ElectraWorks has paid the Company $11.0 million in two installments of $5.5 million on October 30, 2012 and December 17, 2012, and is obligated to pay the Company another $2.5 million payable on or before December 31, 2013. In addition, Peerless/ElectraWorks will make payments to the Company upon certain contingencies related to the passage of federal or state legislation permitting real money online poker and Peerless/ElectraWorks or one of their affiliates obtaining such a license. The maximum amount of these contingent payments is $6.5 million with the amount determined based on how such legislation is enacted. Under the settlement agreement the Company has released its rights to the royalty stream and no further payments are due from Peerless/ElectraWorks other than those set forth in the settlement agreement.

The Company has paid attorneys’ fees of $1.84 million as well as various costs out of the Peerless /Electra settlement proceeds and is obligated to pay an additional $160,000 in attorneys’ fee upon receipt of the remaining $2.5 million due from Peerless/ElectraWorks. In addition, as a result of an incentive arrangement with the Company’s former President, Chief Executive Officer and Secretary, Steve Lipscomb that was approved by WPT Enterprises, Inc.’s Board of Directors in February 2009, Mr. Lipscomb is receiving 5% of the settlement payments; net of attorneys’ fees and other costs as such amounts are received by the Company.

On October 5, 2012, the Company and other parties entered into a settlement agreement with Deloitte & Touche, LLP ("Deloitte & Touche") to settle all claims between the parties arising out of the case of WPT Enterprises, Inc. v. Deloitte & Touche, before the Superior Court of the State of California, County of Los Angeles (the "Litigation"). The claims in the Litigation were assigned to the Company as part of the Company’s distribution (spin-off) agreement with Ante4, Inc. On November 1, 2012, after satisfying obligations to various parties, including litigation counsel, the Company received $5.4 million of net proceeds under the settlement agreement as its share of the settlement proceeds. The parties have agreed to stipulate to the dismissal of the Litigation and to a mutual release of all claims.

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 trades on the OTCBB under the symbol “ANFC.” The range of high and low bid information for each fiscal quarter during 2012 and 2011 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 OTC BB on March 15, 2013 was $0.63 per share.

As of March 15, 2013, there were approximately 1,937 record holders of our common stock, not including shares held in “street name” in brokerage accounts which is unknown. As of March 15, 2013, there were approximately 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, 2012:

For the fiscal years ended December 31, 2012 and 2011, we issued a total of 2,110,000 and 2,053,000 stock options, respectively, pursuant to our 2012 Amended and Restated Stock Incentive Plan. There were 2,122,999 and -0- options cancelled during the years ended December 31, 2012 and 2011, respectively. Included in the 2012 stock options issued and stock options cancelled, were stock options that certain officers and employees of the Company agreed to have cancelled in exchange for new stock option agreements. Under the new stock option agreements, covering 1,510,000 options, each optionee’s original number of stock options remained the same.

See Notes 3 and 11 to our audited financial statements included herein for additional information about our equity compensation plans.

Warrants

For the fiscal years ended December 31, 2012 and 2011, we issued a total of 585,000 and 3,878,375 warrants, respectively, to purchase shares of registered or unregistered common stock.

Unregistered Issuance of Equity Securities

We did not issue securities during the fiscal year ending December 31, 2012 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, 2012, we controlled the rights to mineral leases covering approximately 12,256 net acres for prospective drilling to the Bakken and/or Three Forks formations. Looking forward, we are pursuing the following objectives:

We believe the following are the key drivers to our business performance:

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

Overview of 2012 results

During 2012, we achieved the following financial and operating results:

Operationally, our 2012 performance reflects a year of successfully executing our strategy of developing our acreage position and building a long-life reserve base. Our success enabled us to increase proved reserves by 1.9 million BOE, which is 26 times 2012 production. During 2012, production increased 227% to 73,933 BOE as compared to 2011 production of 22,624 BOE. The increase in 2012 production was driven by a 238% increase in producing net wells from 0.68 net wells at December 31, 2011 to 2.30 net wells at December 31, 2012.

Total revenues increased 214% in 2012 compared to 2011 driven by higher production and partially offset by a decrease in average realized prices on a BOE basis of 3.9% in 2012 compared to 2011. Significant changes in crude oil and natural gas prices can have a material impact on our results of operations and our balance sheet.

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 a 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, 2012, we did not incur a ceiling test impairment. During the year ended December 31, 2011 we incurred a capitalized ceiling impairment charge of $2,392,742. 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.

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, 2012 and 2011.

The following table summarizes selected items from the statement of operations for the years ended December 31, 2012 and 2011.

Revenues:

We recognized $6,022,540 in revenues from sales of crude oil and natural gas for the year ended December 31, 2012 compared to revenues of $1,917,719 for the year ended December 31, 2011, an increase of $4,104,821, or 214%. These revenues are due to the drilling and development of producing wells. We had 66 gross producing wells as of December 31, 2012, and an additional nine wells that were either in the drilling preparation, drilling, awaiting completion, or completing stages, compared to 24 gross producing wells, and an additional 16 wells that were either in the drilling preparation, drilling, awaiting completion, or completing stages as of December 31, 2011.

The Company acquired a lease for mineral rights from the State of North Dakota on February 14, 2012 for 110 acres or an 8.7% working interest in the Dahl Federal 2-15H well that spud on January 6, 2012. The acreage we purchased lies within the riverbed of the Missouri River and there is currently third-party litigation ongoing in the State of North Dakota pertaining to the state’s ownership claim to similar riparian acreage.  We have signed an AFE for the well and the operator has agreed to retroactively honor the AFE if the state is successful in defending its ownership claim. As a result we have not capitalized any of the AFE costs or recognized any sales from this well. The well started production on May 21, 2012. Had we recognized the revenue from this well we would have recorded approximately an additional $468,000 in oil and gas sales for the year ended December 31, 2012. In the event the state is not successful in defending its ownership claim, the state is required to refund the Company the cost to purchase the lease.

Expenses:

Production expenses and taxes

Our production expenses of $649,603 and production taxes of $692,527 for the year ended December 31, 2012, and $527,844 and $214,363 for the year ended December 31, 2011, are comprised of certain production costs involved in the development of producing reserves in the Bakken formation. Combined, they represent approximately 22% and 39% of the oil and gas sales for the year ended December 31, 2012 and 2011, respectively. Our production expenses and taxes are greater in total than the comparative period due to our rapid expansion and increased acreage holdings. The expenses during the year ended December 31, 2011 were greater as a percentage of sales primarily as a result of one well that experienced high costs transporting and disposing well water throughout the last half of 2011 and continuing into the first quarter of 2012. The operator has decreased those costs for that well during the last three quarters of 2012 to normal operating levels. We anticipate costs related to well water disposal will continue at near normal levels.

General and administrative expenses

General and administrative expenses for the year ended December 31, 2012 were $3,530,643, compared to $1,850,536 for the year ended December 31, 2011. The increase for 2012 as compared to 2011 was $1,680,107, or 91%, and is primarily related to increased expenses for compensation and professional fees as a result of hiring additional employees and professionals needed to support our expanding operations as we grow our oil and gas operations. Additionally, general and administrative expenses increased as a result of a one-time expense of $438,539 related to the fair value of common stock granted as a non-refundable deposit on acreage acquisitions that we decided not to complete and increased non-contingent legal costs associated with litigation settlement activity that have been expensed as incurred. The acquisition agreement was terminated in June of 2012. Legal costs associated with the Peerless/ElectraWorks litigation were $333,176 and $165,251 for years ended December 31, 2012 and 2011, respectively, and legal costs associated with the Deloitte & Touche litigation were $37,758 and $35,315 for the same periods.

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 $2,443,482 for the year ended December 31, 2012, compared to $919,631 for the year ended December 31, 2011, an increase of $1,523,851, or 166%. The increase was due primarily due to our expansion and acquisitions of oil and gas properties during 2012 and 2011.

Impairment of oil and gas properties

Impairment of oil and gas properties for the year ended December 31, 2012 was $-0-, compared to $2,392,742 for the year ended December 31, 2011, a decrease of $2,392,742, or 100%. Capitalized costs of oil and 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. This comparison indicated an excess carrying value in 2011, as such the excess was charged to earnings as an impairment expense, in the amount of $2,392,742 during the year ended December 31, 2011. No such impairment was necessary in 2012.

Depreciation

Depreciation expense for the year ended December 31, 2012 was $24,206, compared to $14,043 for the year ended December 31, 2011. The increase in depreciation expense for 2012 as compared to 2011 of $10,163, or 72%, was due to the additional depreciation associated with the purchase of office equipment and website development in the latter half of 2011 and early 2012.

Net operating loss

The net operating loss for the year ended December 31, 2012 was $1,322,478, compared to $4,001,949 for the year ended December 31, 2011, a decrease of $2,679,471, or 67% for 2012 as compared to 2011. Our net operating loss in 2012 consisted primarily of oil and gas production costs, professional fees, officer salaries and depletion expense, netted against our oil and gas income, incurred as we expanded our oil and gas business, in addition to a one-time expense of $438,539 in 2012 related to the fair value of common stock granted as a non-refundable deposit on acreage acquisitions that we decided not to complete. Our net operating loss in 2011 consisted primarily of an impairment charge of $2,392,742 related to our ceiling test, which was caused by substantially reduced production levels and increased operating costs in one of our largest wells.

Other income and (expenses)

Other income and (expenses) for the year ended December 31, 2012 was $9,954,489, compared to ($161,211) for the year ended December 31, 2011, a net difference of $10,115,700.

The net other income and (expenses) for the year ended December 31, 2012 consisted of a net gain of $11,145,895 due to the settlement, net of expenses, of the Peerless/ElectraWorks arbitration and the Deloitte & Touche litigation, $1,872 of interest income earned on money market accounts, ($1,193,278) of interest expense. Interest expense includes ($317,652) of amortized warrant costs and ($190,580) of amortized debt issuance costs for the year ended December 31, 2012 Amortization of the warrants and debt issuance costs on the PrenAnte5 Credit Agreement were accelerated due to the Company’s repayment and voluntary termination of the revolving credit facility on April 12, 2012.

The net other income and (expenses) for the year ended December 31, 2011 consisted of $1,717 of interest income earned on money market accounts, ($101,956) of interest expense. Interest expenses consisted of ($87,084) of expenses incurred on amortized warrant costs and ($14,872) of amortized debt issuance costs. We also incurred a loss of ($1,061) on the disposal of assets, and ($97,686) of indemnification expenses related to payments made pursuant to previously unidentified tax obligations prior to our spin-off on April 16, 2010. In addition, we recognized a gain on debt settlement of $36,151 related to the settlement of certain accounts payable liabilities for legal fees incurred prior to our spin-off on April 16, 2010, and a gain on sale of oil and gas equipment of $1,924.

Income taxes

We had income tax expense of $3,720,601 for the year ended December 31, 2012 compared to income tax benefits of $1,680,905 for the year ended December 31, 2011, a difference of $5,401,506 comparing 2012 to 2011, primarily due to additional income tax expense related to the Peerless/ElectraWorks settlement and D&T settlement.

Net income (loss)

The net income for the year ended December 31, 2012 was $4,911,410, compared to a net loss of ($2,482,255) for the year ended December 31, 2011. Our net income in 2012 consisted primarily of settlement income, net of expenses and income taxes, of $6,355,895 related to our settlement of the Peerless/ElectraWorks arbitration and the Deloitte & Touche litigation. Revenue from our oil and gas sales as well as oil and gas production costs, professional fees, officer salaries and interest costs related to our credit facility have increased in 2012 as compared to 2011 as we aggressively expanded our oil and gas operations compared to our relatively new oil and gas operations during 2011. Decreasing the Company’s net income in 2012 were a one-time expense of $438,539 related to the fair value of common stock granted as a non-refundable deposit on acreage acquisitions that we decided not to complete and non-contingent legal and other costs of $370,934 in 2012 compared to $200,566 in 2011 related litigation settlement activity. Additionally, the Company had income tax expense of $3,720,601 in 2012 compared to income tax benefits of $1,680,905 in 2011, the difference driven primarily by the tax effect of our litigation settlements.

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, computed based on our effective tax rate of approximately 43%, of $4,790,000 for the year Ended December 31, 2012.

Our Adjusted EBITDA for the year ended December 31, 2012 includes settlement income, net of settlement expenses, of $11,145,895.

Liquidity and capital resources

The following table summarizes our total current assets, liabilities and working capital at December 31, 2012 and 2011.

Revolving Credit Facility

On April 4, 2012, the Company entered into a Secured Revolving Credit Agreement with Dougherty Funding, LLC as Lender which was subsequently amended on September 5, 2012 and December 14, 2012 with an Amended and Restated Secured Revolving Credit Agreement (collectively the “Credit Facility”). Under the terms of the amended Credit Facility, up to $20,000,000 maximum is available from time to time (i) to fund, or to reimburse the Company for, the Company’s pro-rata share of development and production costs for oil wells that relate to the Company’s oil and gas leasehold interests for which there is a valid and enforceable Authorization for Expenditure and that are incurred from and after the date of the Credit Facility, and (ii) to reimburse the Company for amounts that the Company paid from its own funds or from funds that it borrowed under its previous credit facility from Prenante5, LLC as agent pursuant to the Revolving Credit and Security Agreement dated May 2, 2011 (the “Previous Credit Facility”). Of the $20 million Credit Facility, $16.5 million is currently available. If the Company has not successfully completed an equity offering of at least $10,000,000 by August 31, 2014, then advances will no longer be available under the Credit Facility.

Interest on the unpaid principal balance of the Credit Facility accrues and is payable monthly at 9.25% per year. The Company must also pay the Lender quarterly a commitment fee in an amount equal to 0.25% of the average line of credit available, but not advanced, for the previous quarter. The Company must make payments equal to 90% of the Company’s earnings before taxes, depreciation and amortization (excluding certain items as defined in the Credit Agreement) on a quarterly basis as a principal payment on the Loan.

The Credit Facility is secured by substantially all of the Company’s assets and has typical representations and warranties, covenants, and events of default, including, subject to certain exceptions, incurrence of additional indebtedness. The Credit Agreement requires that the Company meet certain conditions to obtain additional advances under the Credit Facility, including providing certain documentation related to the Company’s oil and gas properties. The Lender has the right to approve advances for properties which are not held by production. In addition, the Company must maintain available cash and specified cash equivalents in an amount that is not less than the greater of (i) $300,000 and (ii) 12 months’ then-regularly scheduled payments of interest on the outstanding amount of advances.

The Credit Facility will mature on August 1, 2015. The Credit Facility may be prepaid with thirty (30) days written notice at any time. In connection with the amended financing, the Company agreed to issue Dougherty Funding, LLC warrants to purchase up to 900,000 shares of the Company’s common stock, of which 585,000 shares have currently been issued, at an exercise price of $0.38. The warrants expire on August 31, 2015.

We took our first draw on April 12, 2012 of $2,450,000, and used $2,051,722 of the proceeds to repay and terminate our outstanding PrenAnte5 revolving credit facility, including interest of $51,722, and we have taken subsequent draws (net of repayments) of $3,298,844 through December 31, 2012 and used the proceeds to pay for our development of oil and gas wells.

We anticipate that we may incur operating losses in the next twelve months. Although our revenues are expected to grow as our wells are placed into production, our revenues are not expected to exceed our investment developing oil and gas wells and our operating costs throughout 2013. However, our availability under our Credit Facility provides ample funding for our property acquisition and development plans throughout 2013. Our prospects still must be considered in light of the risks, expenses and difficulties frequently encountered by companies in their early stage of development. Such risks for us include, but are not limited to, potential failure to earn revenues or to sufficiently monetize certain claims that we have for payments that are owed to us; an inability to identify investment and expansion targets; and dissipation of existing assets. To address these risks, we must, among other things, seek growth opportunities through investment and acquisitions in the oil and gas industry, effectively monitor and manage our claims for payments that are owed to us, implement and successfully execute our business strategy, respond to competitive developments, and attract, retain and motivate qualified personnel. We cannot assure that we will be successful in addressing such risks, and the failure to do so could have a material adverse effect on our business prospects, financial condition and results of operations.

Satisfaction of our cash obligations for the next 12 months

As of December 31, 2012, our balance of cash and cash equivalents was $1,417,340. Our plan for satisfying our cash requirements for the next twelve months, in addition to our revenues from oil and gas sales is through draws on our credit facility, potential sale of shares of our common stock, third party financing, and/or traditional bank financing.

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, 2012 to make future payments under certain contracts, aggregated by category of obligation, for specified time periods:

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, 2012, we had five employees, our chief executive officer, Kenneth DeCubellis, our chief financial officer, James Moe, and three 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 and continue to acquire more 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 crude oil and natural gas production will heavily influence our revenue, profitability, access to capital and future rate of growth. Crude 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. Historically, the markets for crude oil and natural gas have been volatile, and 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 will generally increase or decrease along with any increases or decreases in crude oil or natural gas prices, but the exact impact on our income is indeterminable given the variety of expenses associated with producing and selling crude oil that also increase and decrease along with crude oil prices.

Interest Rate Risk

Our revolving credit facility has a fixed interest rate of 9.25%. To the extent that the interest rate is fixed, interest rate changes would affect the instrument’s fair market value but would not impact results of operations or cash flows. Conversely, for any portion of our future borrowings that may have a floating interest rate, interest rate changes will not affect the fair market value of the instrument but will impact future results of operations and cash flows.

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

BLACK RIDGE OIL & GAS, INC.

CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2012 AND 2011

CONTENTS

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors

Black Ridge Oil & Gas, Inc.

We have audited the accompanying consolidated balance sheets of Black Ridge Oil & Gas, Inc. (the “Company”) as of December 31, 2012 and 2011 and the related consolidated statements of operations, stockholders' equity, and cash flows for the years then ended. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated 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 consolidated 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 consolidated financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Black Ridge Oil & Gas, Inc. as of December 31, 2012 and 2011, and the results of its operations and cash flows for the periods described above in conformity with U.S. generally accepted accounting principles.

/s/ M&K CPAS, PLLC

www.mkacpas.com

Houston, Texas

March 22, 2013

BLACK RIDGE OIL & GAS, INC. (Formerly Ante5, Inc.)

CONSOLIDATED BALANCE SHEETS

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

BLACK RIDGE OIL & GAS, INC. (Formerly Ante5, Inc.)

CONSOLIDATED STATEMENTS OF OPERATIONS

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

BLACK RIDGE OIL & GAS, INC. (Formerly Ante5, Inc.)

CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY

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

BLACK RIDGE OIL & GAS, INC. (Formerly Ante5, Inc.)

CONSOLIDATED STATEMENTS OF CASH FLOWS

The accompanying notes are an integral part of these consolidated 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 OTC QB and OTC BB 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 consolidated 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).

Principles of Consolidation

The accompanying consolidated financial statements include the accounts of the following entities, all of which are under common control and ownership:

⁽¹⁾ Wholly-owned subsidiary.

The consolidated financial statements herein contain the operations of the wholly-owned subsidiary listed above. All significant inter-company transactions have been eliminated in the preparation of these financial statements. The parent company, Black Ridge Oil & Gas, Inc. and subsidiary, Poker Interests, LLC will be collectively referred to herein as the “Company”, or “Black Ridge”. The Company's headquarters are located in Minnetonka, Minnesota and substantially all of its operations are within the United States.

These statements reflect all adjustments, consisting of normal recurring adjustments, which in the opinion of management are necessary for fair presentation of the information contained therein.

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.

Reclassifications

In the current year, the Company separately classified debt issuance costs in the financial statements. For comparative purposes, amounts in prior periods have been reclassified to conform to current year presentation.

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.

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 for which the Company may be currently liable.

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. Cash and cash equivalents consist of the following:

Cash in Excess of FDIC and SIPC 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) and the Securities Investor Protection Corporation (SIPC) up to $250,000 and $500,000, respectively, under current regulations. The Company had approximately $917,340 and $402,952 in excess of FDIC and SIPC insured limits at December 31, 2012 and 2011, respectively. The Company has not experienced any losses in such accounts.

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 $796,233 and $66,921 of debt issuance costs during the years ended December 31, 2012 and 2011, respectively, of which the unamortized balance of debt issuance costs at December 31, 2012 and 2011 was $657,702 and $52,049, respectively. Amortization of debt issuance costs charged to interest expense was $190,580 and $14,872 for the years ended December 31, 2012 and 2011, respectively. When a loan is paid in full, 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, 2012. We have recognized depreciation expense on these website costs of $18,630 and $3,507 for the years ended December 31, 2012 and 2011, 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 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 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 $24,206 and $14,043 for the years ended December 31, 2012 and 2011, respectively.

Revenue Recognition and Gas Balancing

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 proven 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 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, 2012 and 2011, 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, 2012, the Company sold approximately 509 net acres for total proceeds of $1,893,649. During the year ended December 31, 2011, the Company sold approximately 123 net acres for total proceeds of $336,925. 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 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. We recognized $-0- and $2,392,742 of impairment costs during the years ended December 31, 2012 and 2011, respectively.

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 didn’t consider any purchasers to represent a material concentration to our sales for the years ended December 31, 2012 or 2011, 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 two (2) and three (3) operators during the years ended December 31, 2012 and 2011, respectively, representing 44% and 80% of total oil and gas revenues and 28% and 65% of total oil and gas accounts receivable as of December 31, 2012 and 2011, respectively. As of December 31, 2012 and 2011, we had 66 and 24 gross producing wells, respectively, and 2.30 and 0.68 net producing wells, respectively. As of December 31, 2012 and 2011, these two (2) and three (3) operating partners operated 38% and 46% of these gross producing wells, respectively.

Impairment

FASB ASC 360-10-35-21 requires that assets to be held and used be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Oil and gas properties accounted for using the full cost method of accounting (which the Company uses) are excluded from this requirement but continue to be subject to the full cost method's impairment rules.

FASB ASC 310-40 requires that impaired loans be measured based on the present value of expected future cash flows discounted at the loan’s effective interest rate or, as a practical expedient, at the loan’s observable market price or the fair value of the collateral if the loan is collateral dependent.

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, 2012 and 2011 are as follows:

Stock options and warrants excluded from the calculation of diluted EPS because their effect was antidilutive were 7,513,709 and 6,047,375 as of December 31, 2012 and 2011, respectively.

Stock-Based Compensation

The Company adopted FASB guidance on stock based compensation upon inception at April 9, 2010. 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 common stock and stock options issued for services and compensation totaled $1,288,448 and $753,860 for the years ended December 31, 2012 and 2011, respectively, including $438,539 and $43,120, respectively, of common stock valued at the fair market value based on the Company’s closing trading price on the date of grant. 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

Effective upon inception at April 9, 2010, the Company adopted new standards for accounting for uncertainty in income taxes. 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.

Various taxing authorities 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, Inc. has not yet undergone an examination by any taxing authorities. The Company had indemnified Voyager Oil and Gas (Ante4), however, for any unrecognized liabilities which was limited to $2,500,000, and terminated on or about April 15, 2012, subject to customary exceptions from these limitations. In July of 2011 the Internal Revenue Service completed an examination of federal income tax returns of Voyager Oil and Gas (Ante4) for the years ended January 3, 2010 and December 28, 2008. As a result of the examination we reimbursed Voyager Oil and Gas for their payments of $11,417 of federal taxes and, based on the federal examination, amended state returns in California that totalled an additional $48,666 in state taxes. In addition, we reimbursed Voyager Oil and Gas for their payments of an additional $37,903 in California payroll taxes related to an underpayment by Ante4 from 2010.

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

Recently Adopted

Fair Value Measurement — In May 2011, the FASB issued Fair Value Measurement (Topic 820) — Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs (ASU 2011-04), which provides clarifications regarding existing fair value measurement principles and disclosure requirements, and also specific new guidance for items such as measurement of instruments classified within stockholders’ equity. These requirements were effective for interim and annual periods beginning after December 15, 2011. We implemented the accounting and disclosure guidance effective January 1, 2012, and the implementation did not have a material impact on our financial statements. For required fair value measurement disclosures, see Note 7.

Comprehensive Income — In June 2011, the FASB issued Comprehensive Income (Topic 220) — Presentation of Comprehensive Income (ASU 2011-05), which requires the presentation of the components of net income, the components of OCI and total comprehensive income in either a single continuous financial statement of comprehensive income or in two separate, but consecutive financial statements of net income and comprehensive income. These updates do not affect the items reported in OCI or the guidance for reclassifying such items to net income. These requirements were effective for interim and annual periods beginning after December 15, 2011. We implemented the financial statement presentation guidance effective January 1, 2012. The adoption of ASU 2011-05 did not have a material impact on our financial position or results of operations.

Recently Issued

Balance Sheet Offsetting — In December 2011, the FASB issued Balance Sheet (Topic 210) — Disclosures about Offsetting Assets and Liabilities (ASU 2011-11), which requires disclosures regarding netting arrangements in agreements underlying derivatives, certain financial instruments and related collateral amounts, and the extent to which an entity’s financial statement presentation policies related to netting arrangements impact amounts recorded to the financial statements. These disclosure requirements do not affect the presentation of amounts in the balance sheets, and are effective for annual reporting periods beginning on or after January 1, 2013, and interim periods within those annual reporting periods. We do not expect the implementation of this disclosure guidance to have a material impact on our financial statements.

Recent Accounting Pronouncements Not Yet Adopted

Various accounting standards and interpretations were issued in 2012 with effective dates subsequent to December 31, 2012. We have evaluated the recently issued accounting pronouncements that are effective in 2013 and believe that none of them will have a material effect on our financial position, results of operations or cash flows when adopted.

Further, we are monitoring the joint standard-setting efforts of the Financial Accounting Standards Board and the International Accounting Standards Board. There are a large number of pending accounting standards that are being targeted for completion in 2013 and beyond, including, but not limited to, standards relating to revenue recognition, accounting for leases, fair value measurements, accounting for financial instruments, disclosure of loss contingencies and financial statement presentation. Because these pending standards have not yet been finalized, at this time we are not able to determine the potential future impact that these standards will have, if any, on our financial position, results of operations or cash flows.

Note 3 – Related Party

During the years ended December 31, 2012 and 2011, we granted various awards to our Officers and Directors as compensation for their services. These related party grants are fully disclosed in Note 10 below.

Former Financing Arrangement

On May 2, 2011, we entered into a Revolving Credit and Security Agreement (the “PrenAnte5 Credit Agreement”) with certain lenders (collectively, the “Lenders” and individually a “Lender”) and Prenante5, LLC, as agent for the Lenders (PrenAnte5, LLC, in such capacity, the “Agent”). The facility provided $10 million in financing to be made available for drilling projects on the Company’s North Dakota Bakken and Three Forks position. The Company drew $2,000,000 utilizing the PrenAnte5 Credit Agreement in February of 2012 and subsequently paid in full and terminated the agreement in April of 2012.

Morris Goldfarb, one of the Company’s former directors, participated as a Lender through the Agent with a commitment amount of $1.5 million in the facility. In consideration for his participation through the agent, Mr. Goldfarb was issued 75,000 warrants (his pro-rata share as a Lender) with the same terms and conditions as the other warrants issued in connection with the closing of the PrenAnte5 Credit Agreement. The warrants vested on the May 2, 2012, the one year anniversary of the grant and are exercisable until May 1, 2016 at an exercise price of $0.95 per share. The total estimated value using the Black-Scholes Pricing Model, based on a volatility rate of 97% and a call option value of $0.7837, was $58,781, and was amortized over the three year life of the credit agreement and the amortization was accelerated in 2012 to fully amortize the remaining unamortized value upon termination of the agreement. The Company recognized compensation expense of $45,719 and $13,062 during the years ended December 31, 2012 and 2011, respectively.

Other Related Party Transactions

A former officer of the Company, Steve Lipscomb, received a commission of 5% of a royalty stream from Peerless Media Ltd., recorded on the balance sheet as of December 31, 2011 as a contingent consideration receivable, as a result of an incentive arrangement with Mr. Lipscomb that was approved by Ante4’s Board of Directors in February 2009. Mr. Lipscomb has received a total of $26,468 and $23,170 during the years ended December 31, 2012 and 2011, respectively, of which $19,071 in royalties were received by Mr. Lipscomb while an officer of the Company in 2012. As a result of the settlement of litigation related to the same agreement, Mr. Lipscomb was due 5% of the settlement payments from the litigation settlement amounting to approximately $548,827 of which $432,593 was paid in 2012 and the remaining $116,234 is due upon receipt by the Company of the final settlement payment from Peerless Media, Ltd.

We have subleased and currently lease office space on a month to month basis where the lessor is an entity owned by our former CEO and current Chairman of the Board of Directors, Bradley Berman. The sublease agreement was cancelled and we entered into a direct lease on April 30, 2012 to expand and occupy approximately 1,142 square feet of office space. 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 $1,142 per month, plus common area operations and maintenance charges, and monthly parking fees of $240 per month, for the first year commencing on May 1, 2012, and subject to increases of $24 per month for each of the subsequent four year periods. We have paid a total of $26,546 and $13,208 to this entity during the years ended December 31, 2012 and 2011, respectively.

We also paid a total of $-0- and $10,562 to an entity owned by our former CEO and current Chairman of the Board of Directors, Bradley Berman for administrative services provided during the years ended December 31, 2012 and 2011, respectively.

Note 4 – Oil and Gas Properties

The following tables summarize gross and net productive oil wells by state at December 31, 2012 and 2011. A net well represents our percentage ownership of a gross well. The following tables do not include wells in which our interest is limited to royalty and overriding royalty interests. The following tables also do not include wells which were awaiting completion, in the process of completion or awaiting flow back subsequent to fracture stimulation.

The Company’s oil and gas properties consist of all acreage acquisition costs (including cash expenditures and the value of stock consideration), drilling costs and other associated capitalized costs. As of December 31, 2012 and 2011, our principal oil and gas assets included approximately 12,256 and 10,457 net acres, respectively, located in North Dakota and Montana.

The following table summarizes our capitalized costs for the purchase and development of our oil and gas properties for the years ended December 31, 2012 and 2011:

2012 Acquisitions

During 2012, the Company purchased approximately 2,306 net mineral acres of oil and gas properties in North Dakota and Montana. In consideration for the assignment of these mineral leases, we paid the sellers a total of approximately $3,249,347. Of these acquisitions, 110 acres acquired on February 14, 2012 were acquired from the State of North Dakota. The operator of this well has filed a lawsuit against the state challenging the state’s ownership in these mineral rights. As a result, we have not capitalized any Authorization for Expenditure costs (“AFE”) or recognized any sales from this well. In the event the operator is successful in their litigation with the state, the state is required to refund our original purchase price for the lease.

2012 Divestitures

During 2012, the Company sold approximately 506 net mineral acres of oil and gas properties in North Dakota for total proceeds of $1,893,649. No gain or loss was recorded pursuant to the sales.

2011 Acquisitions

During 2011, the Company purchased approximately 6,867 net mineral acres of oil and gas properties in North Dakota and Montana. In consideration for the assignment of these mineral leases, we paid the sellers a total of approximately $12,507,552, including 3,852,851 shares of common stock valued at $4,940,269.

2011 Divestitures

On December 30, 2011, the Company sold a total of approximately 123 net acres at $2,750 per acre for total proceeds of $336,925. No gain or loss was recorded pursuant to the sale.

Note 5 – Asset Retirement Obligation

The Company has asset retirement obligations associated with the future plugging and abandonment of proved properties and related facilities. Under the provisions of FASB ASC 410-20-25, the fair value of a liability for an asset retirement obligation is recorded in the period in which it is incurred 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. The Company has no assets that are legally restricted for purposes of settling asset retirement obligations.

The following table summarizes the Company’s asset retirement obligation transactions recorded in accordance with the provisions of FASB ASC 410-20-25 during the years ended December 31, 2012 and 2011:

Note 6 – Litigation Settlements and Contingent Consideration Receivable

Peerless Settlement

As a result of a transaction between Ante4, Inc. (“Ante4”) and Peerless Media Ltd. (“Peerless”) during fiscal year 2009, pursuant to which, Ante4 sold substantially all of its operating assets (the “Transaction”) and a spin-off on April 16, 2010 to Ante5, Inc., now Black Ridge Oil & Gas, Inc. (the “Company”), the Company was entitled to receive, in perpetuity, 5% of gross gaming revenue and 5% of other revenue of Peerless generated by Ante4’s former business and assets that were sold to Peerless in the Transaction, subject to a 5% commission presented as Royalties Payable on the balance sheet. Peerless had guaranteed a minimum payment to the Company of $3 million for such revenue over the three-year period following the closing of the Transaction on November 2, 2009. The Company prepared a discounted cash flow model to determine an estimated fair value of this portion of the purchase price as of November 2, 2009. This value was recorded on the balance sheet of Ante4. In connection with the spin-off described above, on April 16, 2010 Ante4 distributed this asset to its wholly-owned subsidiary, Ante5, Inc., which was spun-off and a registration statement was filed on Form 10-12/A, along with an Information Statement with the Securities and Exchange Commission for the purpose of spinning off the Ante5 shares from Ante4, Inc. to its stockholders of record on April 15, 2010. The following is a summary of the contingency consideration receivable and related royalties payable through December 31, 2012:

On September 27, 2012, the Company entered into a settlement agreement with Peerless and ElectraWorks, Ltd. (“ElectraWorks”) to settle all claims regarding Peerless’s performance of obligations with respect to the business purchased by Peerless from Ante4, Inc. in November 2009 (the "Litigation"). The Litigation was pending before Judicial Arbitration and Mediation Services (JAMS) in Los Angeles, California. Under the settlement agreement, Peerless/ElectraWorks will pay the Company $13.5 million, of which $11,000,000 was received by the Company in 2012 and the remaining $2.5 million is payable on or before December 31, 2013. In addition, Peerless/ElectraWorks will make payments to the Company upon certain contingencies related to the passage of federal or state legislation permitting real money online poker and Peerless/ElectraWorks or one of their affiliates obtaining such a license. The maximum amount of these contingent payments is $6.5 million with the amount determined based on how such legislation is enacted. Under the settlement agreement the Company has released its rights to the royalty stream and no further payments are due from Peerless/ElectraWorks other than those set forth in the settlement agreement.

The Company is paying attorneys’ fees of $2 million, of which $1.84 million was paid in 2012, as well as various costs out of the proceeds. In addition, as a result of an incentive arrangement with Steve Lipscomb, a former officer of the Company that was approved by WPT Enterprises, Inc.’s Board of Directors in February 2009, Mr. Lipscomb is receiving 5% of the settlement payments, net of attorneys’ fees and other costs; as such amounts are received by the Company.

As of December 31, 2012, Company has recorded a receivable of $2.5 million for the remaining litigation settlement and payables of $160,000 and $116,233 related to remaining contingent attorneys’ fees payable and amounts due Mr. Lipscomb, respectively. The contingent consideration receivable of $5,479,241 and the royalty payable of $273,963 as of the settlement date were relieved as a part of the settlement resulting in a net gain of $5,745,895. The Company has expensed non-contingent expenses and fees associated with pursuing the settlement as those expenses and fees were incurred amounting to $333,176 and $165,251 for the years ended December 31, 2012 and 2011, respectively.

Deloitte & Touche Settlement

On October 5, 2012, the Company and other parties entered into a settlement agreement with Deloitte & Touche, LLP ("Deloitte & Touche") to settle all claims between the parties arising out of the case of WPT Enterprises, Inc. v. Deloitte & Touche, before the Superior Court of the State of California, County of Los Angeles (the "Litigation"). The claims in the Litigation were assigned to the Company as part of the Company’s distribution (spin-off) agreement with Ante4, Inc. On November 1, 2012, after satisfying obligations to various parties, including litigation counsel, the Company received $5.4 million of net proceeds under the settlement agreement as its share of the settlement proceeds, representing $9 million of settlement income and $3.6 million of related legal fees. The parties agreed to stipulate to the dismissal of the Litigation and to a mutual release of all claims. The Company has expensed non-contingent expenses and fees associated with pursuing the settlement as those expenses and fees were incurred amounting to $37,758 and $35,315 for the years ended December 31, 2012 and 2011, respectively.

Note 7 – Fair Value of Financial Instruments

The Company adopted FASB ASC 820-10 upon inception at April 9, 2010. Under FASB ASC 820-10-5, fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (an exit price). The standard outlines a valuation framework and creates a fair value hierarchy in order to increase the consistency and comparability of fair value measurements and the related disclosures. Under GAAP, certain assets and liabilities must be measured at fair value, and FASB ASC 820-10-50 details the disclosures that are required for items measured at fair value.

The Company has cash and cash equivalents and a revolving credit facility that must be measured under the fair value standard. The Company’s financial assets and liabilities are measured using inputs from the three levels of the fair value hierarchy. The three levels are as follows:

Level 1 - Inputs are unadjusted quoted prices in active markets for identical assets or liabilities that the Company has the ability to access at the measurement date.

Level 2 - Inputs include quoted prices for similar assets and liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability (e.g., interest rates, yield curves, etc.), and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market corroborated inputs).

Level 3 - Unobservable inputs that reflect our assumptions about the assumptions that market participants would use in pricing the asset or liability.

The following schedule summarizes the valuation of financial instruments at fair value on a recurring basis in the balances sheet as of December 31, 2012 and 2011:

There were no transfers of financial assets or liabilities between Level 1 and Level 2 inputs for the years ended December 31, 2012 and 2011.

Level 2 liabilities consist of revolving credit facilities. No fair value adjustment was necessary during the years ended December 31, 2012 and 2011.

Note 8 –Revolving Credit Facilities

PrenAnte5, LLC Revolving credit facility

On May 2, 2011, we entered into a Revolving Credit and Security Agreement (the “Credit Agreement”) with certain lenders (collectively, the “Lenders” and individually a “Lender”) and Prenante5, LLC, as agent for the Lenders (PrenAnte5, LLC, in such capacity, the “Agent”). The facility provided $10 million in financing to be made available for drilling projects on the Company’s North Dakota Bakken and Three Forks position. The facility terms stated it would be available for a period of three years over which time we may draw on the line seven times, pay the line down three times, and terminate the facility without penalty one time. The facility set the minimum total draw at $500,000 and required the Company, upon each draw, to provide the Lender with a compliance certificate that, along with other usual and customary financial covenants, stated that the Company has at least twelve months interest coverage on its balance sheet in cash. We received our first draw of $2,000,000 on February 24, 2012, and subsequently repaid the balance plus accrued interest of $51,722 on April 12, 2012 when we terminated the revolving credit facility.

Dougherty Funding, LLC Revolving credit facility

On April 4, 2012, the Company entered into a Secured Revolving Credit Agreement with Dougherty Funding, LLC as Lender which was subsequently amended on September 5, 2012 with an Amended and Restated Secured Revolving Credit Agreement (collectively the “Credit Facility”). Under the terms of the amended Credit Facility, up to $20,000,000 maximum is available from time to time (i) to fund, or to reimburse the Company for, the Company’s pro-rata share of development and production costs for oil wells that relate to the Company’s oil and gas leasehold interests for which there is a valid and enforceable Authorization for Expenditure and that are incurred from and after the date of the Credit Facility, and (ii) to reimburse the Company for amounts that the Company paid from its own funds or from funds that it borrowed under its previous credit facility from Prenante5, LLC as agent pursuant to the Revolving Credit and Security Agreement dated May 2, 2011 (the “Previous Credit Facility”). Of the $20 million Credit Facility, $16.5 million is currently available. If the Company has not successfully completed an equity offering of at least $10,000,000 by August 31, 2014, then advances will no longer be available under the Credit Facility.

Interest on the unpaid principal balance of the Credit Facility accrues and is payable monthly at 9.25% per year. The Company must also pay the Lender quarterly a commitment fee in an amount equal to 0.25% of the average line of credit available, but not advanced, for the previous quarter. The Company must make payments equal to 90% of the Company’s earnings before taxes, depreciation and amortization (excluding certain items as defined in the Credit Agreement) on a quarterly basis as a principal payment on the loan.

The Credit Facility is secured by substantially all of the Company’s assets and has typical representations and warranties, covenants, and events of default, including, subject to certain exceptions, incurrence of additional indebtedness. The Credit Agreement requires that the Company meet certain conditions to obtain additional advances under the Credit Facility, including providing certain documentation related to the Company’s oil and gas properties. The Lender has the right to approve advances for properties which are not held by production. In addition, the Company must maintain available cash and specified cash equivalents in an amount that is not less than the greater of (i) $300,000 and (ii) 12 months’ then-regularly scheduled payments of interest on the outstanding amount of advances.

The Credit Facility will mature on August 1, 2015. The Credit Facility may be prepaid with thirty (30) days written notice at any time. In connection with the amended financing, the Company agreed to issue Dougherty Funding, LLC warrants to purchase up to 900,000 shares of the Company’s common stock, of which 585,000 shares have currently been issued, at an exercise price of $0.38. The warrants expire on August 31, 2015.

We took our first draw on April 12, 2012 of $2,450,000, and used $2,051,722 of the proceeds to repay and terminate our outstanding PrenAnte5 revolving credit facility, including interest of $51,722.

Revolving credit facility consisted of the following as of December 31, 2012 and December 31, 2011, respectively:

The following presents components of interest expense by instrument type for the years ended December 31, 2012 and 2011, respectively: