Attached files

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EX-10.32 - FIFTH AMENDMENT TO CREDIT AGREEMENT - Black Ridge Oil & Gas, Inc.blackridge_10k-ex1032.htm
EXCEL - IDEA: XBRL DOCUMENT - Black Ridge Oil & Gas, Inc.Financial_Report.xls
EX-10.33 - THIRD AMENDMENT TO SECOND LIEN CREDIT AGREEMENT - Black Ridge Oil & Gas, Inc.blackridge_10k-ex1033.htm
EX-23.2 - CONSENT - Black Ridge Oil & Gas, Inc.blackridge_10k-ex2302.htm
EX-32.1 - CERTIFICATION - Black Ridge Oil & Gas, Inc.blackridge_10k-ex3201.htm
EX-31.1 - CERTIFICATION - Black Ridge Oil & Gas, Inc.blackridge_10k-ex3101.htm
EX-31.2 - CERTIFICATION - Black Ridge Oil & Gas, Inc.blackridge_10k-ex3102.htm
EX-32.2 - CERTIFICATION - Black Ridge Oil & Gas, Inc.blackridge_10k-ex3202.htm
EX-99.1 - REPORT OF NETHERLAND, SEWELL & ASSOCIATES, INC. - Black Ridge Oil & Gas, Inc.blackridge_10k-ex9901.htm

U.S. SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-K

 

 

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

THE SECURITIES EXCHANGE ACT OF 1934

 

For the fiscal year ended: December 31, 2014

 

Commission file number 000-53952

 

 

 

(Name of registrant as in its charter)

 

Nevada   27-2345075
(State of Incorporation)   (I.R.S. Employer Identification No.)

 

10275 Wayzata Blvd. Suite 100, Minnetonka, Minnesota 55305

(Address of principal executive offices) (Zip Code)

 

(952) 426-1241

Registrant’s telephone number, including area code

 

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

 

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

 

 

Title of Each Class

Name of Each Exchange On

Which Registered

   
COMMON STOCK OTCQB

 

 

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

 

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

 

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

 

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 ☒      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.     ☒

 

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

 

Large accelerated filer ☐     Accelerated filer ☐  

Non-accelerated filer

(Do not check if a smaller reporting company)

☐     Smaller reporting company

 

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

 

The aggregate market value of voting stock held by non-affiliates of the registrant was approximately $27,172,118 as of June 30, 2014 (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 26, 2015.

 
 

 

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:

 

·volatility or decline of our stock price;
·low trading volume and illiquidity of our common stock, and possible application of the SEC’s penny stock rules;
·potential fluctuation in quarterly results;
·our failure to earn and collect payments owed to us;
·material defaults on monetary obligations owed us, resulting in unexpected losses;
·inability to effectively manage our hedging activities;
·inadequate capital to acquire working interests in oil and gas prospects and to participate in the drilling and production of oil and other hydrocarbons;
 ·

our inability to meet financial covenants and restrictions associated with our debt agreements;

·unavailability of oil and gas prospects to acquire;
·decline in oil prices;
·failure to discover or produce commercial quantities of oil, natural gas or other hydrocarbons;
·cost overruns incurred on our oil and gas prospects, causing unexpected operating deficits;
·drilling of dry holes;
·acquisition of oil and gas leases that are subsequently lost due to the absence of drilling or production;
·dissipation of existing assets and failure to acquire or grow a new business;
·litigation, disputes and legal claims involving outside parties; and
·risks related to our ability to be listed on a national securities exchange and meet listing requirements.

 

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.

 

2
 

 

TABLE OF CONTENTS

 

PART 1    
ITEM 1 Business 4
ITEM 1A Risk Factors 12
ITEM 1B Unresolved Staff Comments 32
ITEM 2 Properties 32
ITEM 3 Legal Proceedings 39
ITEM 4 Mine Safety Disclosures 39
     
PART II    
ITEM 5 Market for Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities 40
ITEM 6 Selected Financial Data 41
ITEM 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations 42
ITEM 7A Quantitative and Qualitative Disclosures About Market Risk 56
ITEM 8 Financial Statements and Supplementary Data 58
ITEM 9 Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 59
ITEM 9A Controls and Procedures 59
ITEM 9B Other Information 60
     
PART III    
ITEM 10 Directors, Executive Officers, and Corporate Governance 61
ITEM 11 Executive Compensation 66
ITEM 12 Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 71
ITEM 13 Certain Relationships and Related Transactions, and Director Independence 73
ITEM 14 Principal Accounting Fees and Services 74
     
PART IV    
ITEM 15 Exhibits, Financial Statement Schedules 76
SIGNATURES   80

 

3
 

 

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, 2014, we had proven oil and gas reserves of 5.4 million barrels of oil equivalents, owned interest in 247 gross (7.88 net) producing oil and gas wells, and controlled the rights to mineral leases covering approximately 10,000 net acres for prospective drilling to the Bakken and/or Three Forks formations. The following table provides a summary of important information regarding our assets:

 

As of December 31, 2014
    Productive Wells       Proved    
Net Acres (1)   Gross   Net   Average Daily Production (2)   Reserves   PV-10 (3)
            (Boe per day)   (000's Boe)   ($000)
10,000   247   7.88   1,190   5,356   100,335

 

(1)Includes leases encompassing approximately 1,100 net acres that we estimate will expire in 2015

(2)Represents average daily production over the three months ended December 31, 2014

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

 

Looking forward, we are pursuing the following objectives:

 

·acquire high-potential mineral leases;
·access appropriate capital markets to fund continued acreage acquisition and drilling activities;
·develop and maintain strategic industry relationships;
·attract and retain talented associates;
·actively manage commodity price risk;
·operate a low overhead non-operator business model; and
·become a low cost producer of hydrocarbons.

 

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

 

4
 

 

Recent Developments

 

Amended and Restated Credit Agreements

 

On March 30, 2015, we amended the Credit Facilities (the “Credit Facilities”) to (i) extend the termination date of the Loan Commitment on the Senior Credit Facility (as defined in the Agreement) from August 8, 2016 to January 15, 2017; (ii) decrease the Borrowing Base Amount from $35 million to $34 million on the Senior Credit Facility; and (iii) make certain other changes to the covenants in both the Senior and Subordinated Credit Facilities.

 

Our credit agreement with Cadence Bank, N.A. (the “Bank”) (the “Senior Credit Facility”) was amended in March of 2015 (“the “Senior Credit Fifth Amendment”) to extend the termination date of the Loan Commitment from August 8, 2016 to January 15, 2017, decrease the borrowing base from $35 million to $34 million and to waive the Net Debt to EBITDAX Ratio and the Collateral Coverage Ratio covenants for the quarter ending March 31, 2015. In addition, the Amendment, for purposes of determining compliance with financial covenants, changes the Maximum Net Debt to EBITDAX Ratio and the Minimum Collateral Coverage Ratio. Whereas the Senior Credit Facility initially provided for a Maximum Net Debt to EBITDAX Ratio of 3.50 to 1.00 as of the end of each quarter commencing with the quarter ending March 31, 2015, the Amendment revises the Maximum Net Debt to EBITDAX Ratio to 3.65 to 1.00 for the quarter ending December 31, 2015, and 3.50 to 1.00 for the quarter ending March 31, 2016 and thereafter. In addition, whereas the Senior Credit Facility initially provided for a Minimum Collateral Coverage Ratio of 0.80 to 1.00 as of the end of each quarter commencing with the quarter ending March 31, 2015, the Amendment revises the Minimum Collateral Coverage Ratio to 0.80 to 1.00 for the quarter ending June 30, 2015, and 0.70 to 1.00 for the quarter ending September 30, 2015, and 0.80 to 1.00 for the quarter ending December 31, 2015 and thereafter.

 

Our credit agreement with Chambers Energy Management, LP, as administrative agent (“Chambers”), and several other lenders (the “Subordinated Credit Facility”) was amended in March of 2015 (the “Subordinated Credit Third Amendment”) to waive the Net Leverage Ratio and the Collateral Coverage Ratio covenants for the quarter ending March 31, 2015. In addition, the Amendment, for purposes of determining compliance with financial covenants, changes the Maximum Net Leverage Ratio and the Minimum Collateral Coverage Ratio. Whereas the Subordinated Credit Facility initially provided for a Maximum Net Leverage Ratio of 3.50 to 1.00 as of the end of each quarter commencing with the quarter ending March 31, 2015, the Amendment revises the Maximum Net Leverage Ratio to 3.65 to 1.00 for the quarter ending December 31, 2015, and 3.50 to 1.00 for the quarter ending March 31, 2016 and thereafter. In addition, whereas the Subordinated Credit Facility initially provided for a Minimum Collateral Coverage Ratio of 0.80 to 1.00 as of the end of each quarter commencing with the quarter ending March 31, 2015, the Amendment revises the Minimum Collateral Coverage Ratio to 0.80 to 1.00 for the quarter ending June 30, 2015, and 0.70 to 1.00 for the quarter ending September 30, 2015, and 0.80 to 1.00 for the quarter ending December 31, 2015 and thereafter.

 

Other Developments

 

Potential Reverse Stock Split

 

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

 

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

 

 

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

 

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

 

 

5
 

 

Business

 

The Company’s focus is the acquisition, exploration, development and production of crude oil and natural gas properties, primarily in the Bakken and Three Forks trends in North Dakota and Montana. As of February 28, 2015, we controlled approximately 9,400 net acres in the Williston Basin. In addition, as of February 28, 2015, the Company owned working interests in 349 gross wells representing 10.97 net wells that are preparing to drill, drilling, awaiting completion, completing or producing.

 

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

 

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

 

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

 

Additionally, we believe that ensuring we have the capital to acquire and develop properties is crucial to our success. We strive to maintain strong relationships with our lenders and financial partners in order to ensure capital is available when opportunities come available.

 

Our proven oil and gas reserves were 5.4 million barrel of oil equivalents (BOE’s) as of December 31, 2014 and 4.5 million BOE’s as of December 31, 2013.

 

Production Methods

 

We primarily engage in crude oil and natural gas exploration and production by participating on a pro-rata basis with operators in wells drilled and completed in spacing units that include our acreage under lease. We are generally a minority working interest owner in our wells. We typically depend on drilling partners to propose, permit and engage the drilling of wells. Prior to commencing drilling, our partners are required to provide all owners of mineral interests within the designated spacing unit the opportunity to participate in the drilling costs and revenues of the well to the extent of their pro-rata share of such interest within the spacing unit. 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, anticipated crude oil and natural gas pricing and other factors.

 

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

 

6
 

 

Competition

 

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

 

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

 

Marketing and Customers

 

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

 

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

 

Principal Agreements Affecting Our Ordinary Business

 

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

 

In general, our lease agreements stipulate three to five year terms including extension options. Bonuses and royalty rates are negotiated on a case-by-case basis consistent with industry standard pricing. Once a well is drilled, or production is established, depending on the lease terms, the acreage in a well’s drilling unit is considered “held by production,” meaning the lease on that particular acreage continues as long as oil or gas is being produced. Generally, other locations within the drilling unit created for a well may also be drilled at any time with no time limit as long as the lease is held by production. In the event a lease is not developed prior to lease expiration, the Company completes an economic evaluation of the expiring lease and makes a strategic decision to exercise an available option, attempt to extend the lease, or allow it to expire. As a result of these evaluations and taking into consideration other acquisition opportunities available to the Company, we expect a portion of our leases will expire prior to being held by production. The Company had leases encompassing 4,202 net acres expire in 2014 and leases encompassing 543 net acres expire in 2013. We estimate that leases encompassing approximately 1,100 net acres will expire in 2015. All of the costs associated with the lease expirations in 2014 and the leases we estimate will expire in 2015 have been transferred to the full cost pool and were subject to depletion in 2014.

 

7
 

 

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:

 

·require the acquisition of a permit or other authorization before construction or drilling commences and for certain other activities;
·limit or prohibit construction, drilling and other activities on certain lands lying within wilderness and other protected areas; and
·impose substantial liabilities for pollution resulting from its operations.

 

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.

 

8
 

 

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

 

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

 

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

 

The underground injection of oil and natural gas wastes are regulated by the Underground Injection Control program authorized by the Safe Drinking Water Act. The primary objective of injection well operating requirements is to ensure the mechanical integrity of the injection apparatus and to prevent migration of fluids from the injection zone into underground sources of drinking water. Substantially all of the oil and natural gas production in which we have interest is developed from unconventional sources that require hydraulic fracturing as part of the completion process. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into the formation to stimulate gas production. Legislation to amend the Safe Drinking Water Act to repeal the exemption for hydraulic fracturing from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, were proposed in recent sessions of Congress. The U.S. Congress continues to consider legislation to amend the Safe Drinking Water Act to subject hydraulic fracturing operations to regulation under the Act’s Underground Injection Control Program to require disclosure of chemicals used in the hydraulic fracturing process.

 

9
 

 

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

 

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

 

Climate Change

 

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

 

In the United States, legislative and regulatory initiatives are underway to limit greenhouse gas (“GHG”) emissions. The U.S. Congress has considered legislation that would control GHG emissions through a “cap and trade” program and several states have already implemented programs to reduce GHG emissions. The U.S. Supreme Court determined that GHG emissions fall within the federal Clean Air Act, or the CAA, definition of an “air pollutant.” In response the EPA promulgated an endangerment finding paving the way for regulation of GHG emissions under the CAA. In 2010, the EPA issued a final rule, known as the “Tailoring Rule,” that makes certain large stationary sources and modification projects subject to permitting requirements for greenhouse gas emissions under the Clean Air Act. On June 23, 2014, the U.S. Supreme Court in Utility Air Regulatory Group v. EPA, held that the EPA’s “Tailoring Rule” was invalid, but held that if a source was subject to Prevention of Significant Deterioration (“PSD”) or Title V based on emissions of conventional pollutants like sulfur dioxide, particulates, nitrogen dioxide, carbon monoxide, ozone or lead, then the EPA could also require the source to control GHG emissions and the source would have to install Best Available Control Technology to do so. As a result, a source no longer is required to meet PSD and Title V permitting requirements based solely on its GHG emissions, but may still have to control GHG emissions if it is an otherwise regulated source. On February 23, 2014, Colorado became the first state in the nation to adopt rules to control methane emissions from oil and gas facilities. Subsequently, the Obama administration has approved rules that would require controls on methane emissions from certain oil and gas facilities. To the extent our third party operating partners are required to further control methane emissions, such controls could impact our business.

 

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

 

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

 

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

 

Employees

 

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

 

Office Locations

 

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

 

Financial Information about Segments and Geographic Areas

 

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

 

Available Information – Reports to Security Holders

 

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

 

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

 

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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.

 

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

 

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

 

·the timing and amount of capital expenditures;
·their expertise and financial resources;
·approval of other participants in drilling wells;
·selection of technology; and
·the rate of production of reserves, if any.

 

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

 

The last several years has seen increased activity and investment in the Williston Basin, although this activity has subsided over recent months as oil prices have dropped. To the extent activity in the Williston Basin increases, competition for equipment, labor and supplies is also expected to increase. Likewise, higher oil, natural gas and NGL prices generally increase the demand for equipment, labor and supplies, and can lead to shortages of, and increasing costs for, drilling equipment, services and personnel. The lower oil prices may also result in some suppliers of equipment, labor and supplies ceasing operations in the Williston Basin. Shortages of, or increasing costs for, experienced drilling crews and equipment and services could restrict our operating partners’ ability to drill the wells and conduct the operations that we currently expect.

 

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

 

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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 Senior Credit Facility and a Subordinated Credit Facility that allow for borrowings up to $50 million and $75 million, respectively, with current availability of $34 million and $30 million, respectively, secured by substantially all of our assets, but the two credit facilities may not be available to us if we are not in compliance with their terms and conditions. We had drawn $22.6 million on the Senior Credit Facility and $30 million on the Subordinated Credit Facility as of December 31, 2014 and have net draws of an additional $3.35 million on the Senior Credit Facility as of March 25, 2015. 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 continue to decline as they have recently, our revenues will likely decrease and such decreased revenues may increase our requirements for capital. If the amount of capital we are able to raise from financing activities, together with our revenues from operations, is not sufficient to satisfy our capital needs (even to the extent that we reduce our operations), we may be required to cease our operations, divest our assets at unattractive prices or obtain financing on unattractive terms. 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.

 

Our credit agreements contain operating and financial restrictions that may restrict our business and financing activities.

 

Our credit agreements contain, or any future indebtedness we incur may contain, a number of restrictive covenants that impose significant operating and financial restrictions on us, including restrictions on our ability to, among other things:

 

·declare or pay any dividend or make any other distributions on, purchase or redeem our equity interests or purchase or redeem subordinated debt;
·make certain investments;
·incur or guarantee additional indebtedness or issue certain types of equity securities;
·create certain liens;
·sell assets; and
·consolidate, merge or transfer all or substantially all of our assets.

 

As a result of these covenants, we are limited in the manner in which we conduct our business, and we may be unable to engage in favorable business activities or finance future operations or capital needs.

 

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Our ability to comply with some of the foregoing covenants and restrictions may be affected by events beyond our control. If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired. A failure to comply with the covenants, ratios or tests in our Credit Facilities or any future indebtedness could result in an event of default under our Credit Facilities or our future indebtedness, which, if not cured or waived, could have a material adverse effect on our business, financial condition and results of operations. If an event of default under our Credit Facilities occurs and remains uncured, the lenders thereunder:

 

·would not be required to lend any additional amounts to us;
·could elect to declare all borrowings outstanding, together with accrued and unpaid interest and fees, to be due and payable;
·may have the ability to require us to apply all of our available cash to repay these borrowings; and
·may prevent us from making debt service payments under our other agreements.

 

An event of default or acceleration under our Credit Facilities could result in an event of default and acceleration under other future indebtedness. Conversely, an event of default or acceleration under any future indebtedness could result in an event of default and acceleration under our Credit Facilities. In addition, our obligations under the Senior Credit Facility are collateralized by perfected first priority liens and security interests on substantially all of our assets and if we are unable to repay our indebtedness under the Credit Facilities, the lenders could seek to foreclose on our assets.

 

Our leverage and debt service obligations may adversely affect our financial condition, results of operations and business prospects.

 

Our level of indebtedness could affect our operations in several ways, including the following:

 

·require us to dedicate a substantial portion of our cash flow from operations to service our existing debt, thereby reducing the cash available to finance our operations and other business activities and could limit our flexibility in planning for or reacting to changes in our business and the industry in which we operate;
·increase our vulnerability to economic downturns and adverse developments in our business;
·limit our ability to access the capital markets to raise capital on favorable terms or to obtain additional financing for working capital, capital expenditures or acquisitions or to refinance existing indebtedness;
·place restrictions on our ability to obtain additional financing, make investments, lease equipment, sell assets and engage in business combinations;
·place us at a competitive disadvantage relative to competitors with lower levels of indebtedness in relation to their overall size or less restrictive terms governing their indebtedness; and
·make it more difficult for us to satisfy our obligations under our debt agreements and increase the risk that we may default on our debt obligations.

 

Our ability to meet our expenses and debt obligations will depend on our future performance, which will be affected by financial, business, economic, regulatory and other factors. We will not be able to control many of these factors, such as economic conditions and governmental regulation. We depend on our revolving credit facilities for future capital needs, because we use operating cash flows for investing activities and borrow as needed. We cannot be certain that our cash flow will be sufficient to allow us to pay the principal and interest on our current and future debt and meet our other obligations. If we do not have enough money, we may be required to refinance all or part of our debt, sell assets, borrow more money or raise equity. We may not be able to refinance our debt, sell assets, borrow more money or raise equity on terms acceptable to us, if at all. Our ability to comply with the financial and other restrictive covenants in our indebtedness will be affected by the levels of cash flow from our operations and future events and circumstances beyond our control. Failure to comply with these covenants would result in an event of default under our indebtedness, and such an event of default could adversely affect our business, financial condition and results of operations.

 

Availability under our Senior Credit Facility is determined semi-annually, as well as upon the occurrence of certain events, by the lenders in their sole discretion, based primarily on reserve reports that reflect our banks’ projections of future commodity prices at such time. Significant declines in natural gas, NGL or oil prices may result in a decrease in our borrowing base. We would anticipate prolonged depression of pricing may equate to decreases in our borrowing base, which may or may not be offset by increases in production. Any increase in the borrowing base requires the consent of all the lenders. If as a result of a borrowing base redetermination outstanding borrowings are in excess of the borrowing base, we must repay such excess borrowings within 90 days. We do not currently have any substantial unpledged properties, and we may not have the financial resources in the future to make any mandatory principal prepayments required under the Senior Credit Facility.

 

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We may not be able to generate enough cash flow to meet our debt obligations.

 

We expect our earnings and cash flow to vary significantly from year to year due to the cyclical nature of our industry. As a result, the amount of debt that we can service in some periods may not be appropriate for us in other periods. Additionally, our future cash flow may be insufficient to meet our debt obligations and commitments. Any insufficiency could negatively impact our business. A range of economic, competitive, business and industry factors will affect our future financial performance, and, as a result, our ability to generate cash flow from operations and to pay our debt. Many of these factors, such as oil and natural gas prices, economic and financial conditions in our industry and the global economy or competitive initiatives of our competitors, are beyond our control.

 

If we do not generate enough cash flow from operations to satisfy our debt obligations, we may have to undertake alternative financing plans, such as:

 

·refinancing or restructuring our debt;
·selling assets;
·reducing or delaying capital investments; or
·seeking to raise additional capital.

 

However, we cannot assure you that undertaking alternative financing plans, if necessary, would allow us to meet our debt obligations. Our inability to generate sufficient cash flow to satisfy our debt obligations, or to obtain alternative financing, could materially and adversely affect our business, financial condition, results of operations and prospects.

 

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

 

Borrowings under our Credit Facilities bear interest at variable rates and expose us to interest rate risk. If interest rates increase and we are unable to effectively hedge our interest rate risk, our debt service obligations on the variable rate indebtedness would increase even if the amount borrowed remained the same, and our net income and cash available for servicing our indebtedness would decrease. A one percent increase in interest rates on the debt outstanding under our Credit Facilities as of December 31, 2014 would cost us approximately $545,000 in additional annual interest expense.

 

Despite our current level of indebtedness, we may still be able to incur substantially more debt. This could further exacerbate the risks associated with our substantial indebtedness.

 

We may be able to incur substantial additional indebtedness in the future, subject to certain limitations, including under our Credit Facilities and under any future debt agreements. If new debt is added to our current debt levels, the related risks that we now face could increase. Our level of indebtedness could, for instance, prevent us from engaging in transactions that might otherwise be beneficial to us or from making desirable capital expenditures. This could put us at a competitive disadvantage relative to other less leveraged competitors that have more cash flow to devote to their operations. In addition, the incurrence of additional indebtedness could make it more difficult to satisfy our existing financial obligations.

 

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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 in 2013 we had our first operating profit 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 officers and employees. The loss of one or more of them, upon whose knowledge, leadership and technical expertise we rely, would harm our ability to execute our business plan.

 

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

 

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.

 

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

 

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

 

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.

 

At December 31, 2014 and 2013, we performed impairment reviews using prices that reflect an average of monthly prices for the respective year as prescribed pursuant to the SEC’s guidelines and were not required to take a ceiling test write-down. The average prices used in the December 31, 2014 impairment review are significantly higher than the actual and currently forecasted prices in 2015. As lower average monthly pricing is reflected in the trailing 12-month average pricing calculation, the present value of our future net revenues would decline and impairment could be recognized. If this significantly lower pricing environment persists we expect we could be required to write down the value of our oil and gas properties. Given the current oil and natural gas pricing environment, we believe we could have noncash ceiling test write-downs of our oil and natural gas properties in 2015. The quarterly ceiling test considers many factors including reserves, capital expenditure estimates and trailing 12-month average prices. SEC defined prices for each quarter in 2014 were as follows:

 

   WTI Spot   Henry Hub 
   Oil Price   Gas Price 
SEC Defined prices for the 12 Months Ended  (per Bbl)   (per MMBtu) 
December 31, 2014  $94.99   $4.35 
September 30, 2014  $99.08   $4.24 
June 30, 2014  $100.27   $4.10 
March 31, 2014  $98.43   $3.99 

 

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

 

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

 

· the volume, pricing and duration of our oil and natural gas hedging contracts;
· actual prices we receive for oil, natural gas and NGLs;
· our actual operating costs in producing oil, natural gas and NGLs;
· the amount and timing of our capital expenditures;
· the amount and timing of actual production; and
· changes in governmental regulations or taxation.

 

The timing of both our production and our incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves, which could adversely affect our business, results of operations and financial condition.

 

At December 31, 2014, the PV-10 value of our proved reserves, using mandated SEC pricing, totaled approximately $100.3 million. Commodity prices have decreased significantly in the last nine months. If commodity prices used in our year-end valuation were decreased to reflect more recent NYMEX strip pricing and expected tax and capital expenditure adjustments, our PV-10 value at December 31, 2014 could decrease by approximately 52%.

 

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

 

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

 

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

 

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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:

 

· meet our capital needs;
· expand our systems effectively or efficiently or in a timely manner;
· allocate our human resources optimally;
· identify and engage qualified employees and consultants, or retain valued employees and consultants; or
· incorporate effectively the components of any business that we may acquire in our effort to achieve growth.

 

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

 

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

 

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

 

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

 

·a counterparty to our derivative contracts is unable to satisfy its obligations under the contracts;
·our production is less than expected; or
·there is a widening of price differentials between the delivery points for our production and the delivery point assumed in the derivative arrangement.

 

Our derivative activities expose us to potential regulatory risks.

 

The Federal Trade Commission (“FTC”), Federal Regulatory Commission (“FERC”) and the Commodities Futures Trading Commission (“CFTC”) have statutory authority to monitor certain segments of the physical and futures energy commodities markets. These agencies have imposed broad regulations prohibiting fraud and manipulation of such markets. With regard to derivative activities that we undertake with respect to oil, natural gas, NGLs, or other energy commodities, we are required to observe the market-related regulations enforced by these agencies. Failure to comply with such regulations, as interpreted and enforced, could have a material adverse effect on our business, results of operations and financial condition.

 

 

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

 

In July of 2010, the United States Congress enacted the Dodd-Frank Wall Street Reform and Consumer Protection Act (“Dodd-Frank Act”), which contains measures aimed at increasing the transparency and stability of the over-the-counter (“OTC”) derivatives market and preventing excessive speculation. In November 2013, the CFTC re-proposed implementing regulations imposing position limits for certain physical commodity contracts in the major energy markets and economically equivalent futures, options and swaps, with exemptions for certain bona fide hedging positions. The CFTC’s initial position limit rules were vacated by a federal court in 2012. It is not clear when the newly-proposed rules on position limits would become effective. CFTC rules under the Dodd-Frank Act also may impose clearing and trade execution requirements in connection with our derivative activities; although currently those requirements do not extend to derivatives based on physical commodities in the energy markets and some or all of our derivatives activities may be exempt from such requirements based on our non-financial end-user status. Regulations issued under the Dodd-Frank Act also may require certain counterparties to our derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty. Such spin-offs may occur at any time until mid-2015 depending on regulators’ decisions to allow a transitional period for a given counterparty. The legislation and regulations could significantly increase the cost of derivative contracts (including from swap recordkeeping and reporting requirements and through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. We maintain an active hedging program related to oil price risks. The Dodd-Frank Act and rules and regulations thereunder could reduce trading positions and the market-making activities of our counterparties. If we reduce our use of derivatives as a result of legislation and regulations or any resulting changes in the derivatives markets, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures or to make payments on our debt obligations. Finally, the legislation was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our business, our financial condition, and our results of operations.

 

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

 

We have net operating loss (“NOL”) carryforwards that we may use to offset against taxable income for U.S. federal income tax purposes. At December 31, 2014, we had an estimated NOL carryforward of approximately $28.1 million for United States federal tax return purposes. However, Section 382 of the Internal Revenue Code of 1986, as amended, may limit the NOLs that we may use in any year for U.S. federal income tax purposes in the event of certain changes in ownership of our company. Any limitation on our ability to use NOLs could, depending on the extent of such limitation, result in higher U.S. federal income taxes being paid (and therefore a reduction in cash) than if such NOLs were available as an offset against such income for U.S. federal income tax reporting purposes. In addition, if the limitation under Section 382 is triggered, it could result in a significant charge to earnings in the period in which it is triggered.

 

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

 

A significant portion of our acreage is not currently held by production or held by operations. Unless production in paying quantities is established or operations are commenced on units containing these leases during their terms, the leases will expire. If our leases expire and we are unable to renew the leases, we will lose our right to participate in the development of the related properties. Drilling plans for these areas are generally in the discretion of third party operators and are subject to change based on various factors that are beyond our control, such as: the availability and cost of capital, equipment, services and personnel; seasonal conditions; regulatory and third party approvals; oil, NGL and natural gas prices; results of title work; gathering system and other transportation constraints; drilling costs and results; and production costs. As of December 31, 2014, we estimate that we had leases that were not developed that represented 1,104 net acres potentially expiring in 2015, 217 net acres potentially expiring in 2016, 433 net acres potentially expiring in 2017 and 1,952 net acres potentially expiring in 2018 and beyond.

 

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

 

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

 

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

 

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

 

The amount available for borrowing under our credit facility is subject to a borrowing base which is determined by our lenders, at their discretion, taking into account our estimated proved reserves and is subject to periodic redeterminations based on pricing models determined by the lenders at such time. The decline in oil and natural gas prices in the latter half of 2014 adversely impacted the value of our estimated proved reserves and, in turn, the market values used by our lenders to determine our borrowing base. Oil and natural gas prices have fallen significantly since their early third quarter 2014 levels. For example, oil prices declined 50% from over $105 per Bbl in the latter part of July to near $53 per Bbl on December 31, 2014, and natural gas prices have declined 25% from over $3.85 per Mcf to below $2.89 per Mcf over the same period. In addition, the actual and forecasted prices for 2015 have also declined since year-end. If commodity prices (particularly oil prices) remain at these levels, it will have an adverse effect on our reserves and borrowing base and reduce our ability to replace our reserves.

 

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

 

Approximately 62% of our estimated net barrel of oil equivalents of proved reserves were classified as proved undeveloped as of December 31, 2014. Development of these reserves may take longer and require higher levels of capital expenditures than we currently anticipate. Delays in the development of our reserves or increases in costs to drill and develop such reserves will reduce the PV-10 value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could cause us to have to reclassify our proved reserves as unproved reserves.

 

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

 

Our principal exposures to credit risk are through receivables resulting from the sale of our oil and natural gas production ($4.1 million in receivables at December 31, 2014), which operating partners market on our behalf to energy marketing companies, refineries and their affiliates.

 

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

 

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:

 

·changes in global supply and demand for crude oil and natural gas;
·the actions of the Organization of Petroleum Exporting Countries;
·the price and quantity of imports of foreign crude oil and natural gas;
·competitive measures implemented by our competitors and by domestic and foreign governmental bodies;
·political conditions in nations that traditionally produce and export significant quantities of crude oil and natural gas (including military and other conflicts in the Middle East and surrounding geographic region) and regulations and tariffs imposed by exporting and importing nations;
·domestic and foreign economic volatility and stability;
·the level of global crude oil and natural gas exploration and production activity;
·the level of global crude oil and natural gas inventories;
·weather conditions;
·technological advances affecting energy consumption;
·domestic and foreign governmental regulations;
·proximity and capacity of crude oil and natural gas pipelines and other transportation facilities;
·the price and availability of competitors’ supplies of crude oil and natural gas in captive market areas; and
·the price and availability of alternative fuels to replace or compete with crude oil and natural gas

 

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The recent drop in oil and gas prices has reduced the availability of liquidity and credit to fund the continuation and expansion in the oil and gas industry. 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.

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

·the high cost, shortages or delivery delays of equipment and services;
·shortages of or delays in obtaining water for hydraulic fracturing operations;
·unexpected operational events;
·facility or equipment malfunctions;
·adverse weather conditions, such as freezing temperatures and storms.
·title problems;
·pipeline ruptures or spills;
·compliance with environmental and other governmental requirements;
·unusual or unexpected geological formations;
·loss of drilling fluid circulation;
·formations with abnormal pressures;
·environmental hazards, such as oil, natural gas or well fluids spills or releases, pipeline or tank ruptures and discharges of toxic gas;
·fires;
·blowouts, craterings and explosions;
·uncontrollable flows of oil, natural gas or well fluids; and
·pipeline capacity curtailments.

 

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

 

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.

 

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

 

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

 

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

 

Drilling 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.

 

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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.

 

Regulation of crude oil transportation by rail.

 

A portion of our crude oil production is transported to market centers by rail. In response to recent train derailments occurring in the United States and Canada in 2013, the U.S. National Transportation Safety Board issued a series of recommendations on January 23, 2014 aimed at addressing safety risks relating to the transportation of crude oil by rail.

 

The NTSB recommended (i) increased route planning for hazardous materials to avoid sensitive areas and population centers, (ii) development and implementation of a rail carrier audit program to determine whether rail carriers that transport petroleum products have properly considered and implemented emergency response capabilities, including response protocols for the discharge of the entire quantity of crude oil on a train, and (iii) a program designed to ensure that shippers and rail carriers are properly classifying hazardous material cargo and that they have implemented appropriate safety and security procedures. On February 25, 2014, the U.S. Department of Transportation issued an emergency order mandating that any person offering crude oil into transportation comply with proper testing, classification, and handling procedures. The NTSB has recommended that all tank cars used to carry crude oil be reinforced to make them more resistant to punctures if trains derail. This recommendation has not yet been adopted by the Pipeline and Hazardous Materials Safety Administration ("PHMSA").

 

On July 23, 2014, PHMSA and the Federal Rail Administration issued a Notice of Proposed Rulemaking and companion Advanced Notice of Proposed Rulemaking that propose, among other things, (i) enhanced tank car standards for certain trains carrying crude oil (and other flammable liquids) and a requirement that older DOT 111 tank cars be phased out within two years if they are not retrofitted to comply with the new tank car design standards and a classification and testing program for mined gases and liquids, (ii) oil spill response plans for crude-carrying trains, and (iii) securement requirements for unattended rail cars carrying crude oil, ethanol and other flammable liquids and hazardous materials. The proposed rules are expected to be finalized in early 2015. Any requirement to retrofit and upgrade existing rail tankers (DOT-111 or other models) could increase the cost and reduce the availability of rail transportation of crude oil.

 

The adoption of additional federal, state, provincial or local laws or regulations, including any voluntary measures by the rail industry regarding railcar design or crude oil and liquid hydrocarbon rail transport activities, or efforts by local communities to restrict or limit rail traffic involving crude oil, could affect our business by increasing compliance costs and decreasing demand for our services, which could adversely affect our financial position and cash flows. Moreover, any disruptions in the operations of railroads, including those due to shortages of railcars, weather-related problems, flooding, drought, accidents, mechanical difficulties, strikes, lockouts or bottlenecks, could have a material adverse effect on our business.

 

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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, or the operators of our properties, cannot obtain or maintain necessary licenses.

 

Our operations require licenses, permits and in some cases renewals of licenses and permits from various governmental authorities. Our ability (or the ability of our industry operators) to obtain, sustain or renew such licenses and permits on acceptable terms is subject to change in regulations and policies and to the discretion of the applicable governmental authorities, among other factors. Our inability, or the inability of our industry operators, to obtain, or our loss of or denial of extension of, any of these licenses or permits could hamper our ability to produce revenues from our operations or otherwise materially adversely affect our financial condition and results of operations.

 

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.

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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:

 

·dilution caused by our issuance of additional shares of common stock and other forms of equity securities, which we expect to make in connection with future capital financings to fund our operations and growth, to attract and retain valuable personnel and in connection with future strategic partnerships with other companies;
·announcements of new acquisitions, reserve discoveries or other business initiatives by us or our competitors;
·our ability to take advantage of new acquisitions, reserve discoveries or other business initiatives;
·fluctuations in revenue from our crude oil and natural gas business as new reserves come to market;
·changes in the market for crude oil and natural gas commodities and/or in the capital markets generally;
·changes in the demand for crude oil and natural gas, including changes resulting from economic conditions, governmental regulation or the introduction or expansion of alternative fuels;
·quarterly variations in our revenues and operating expenses;
·changes in the valuation of similarly situated companies, both in our industry and in other industries;
·challenges associated with timely SEC filings;
·illiquidity and lack of marketability by being an OTC traded stock;
·changes in analysts’ estimates affecting our company, our competitors and/or our industry;
·changes in the accounting methods used in or otherwise affecting our industry;
·additions and departures of key personnel;
·announcements of technological innovations or new products available to the crude oil and natural gas industry;
·announcements by relevant governments pertaining to incentives for alternative energy development programs;
·fluctuations in interest rates and the availability of capital in the capital markets; and

·significant sales of our common stock, including sales by selling shareholders following the registration of shares under a prospectus.

 

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.

 

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

 

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

 

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

 

As of December 31, 2014, we had options for 7,208,834 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, 9,133,375 shares of our common stock may be issued upon the exercise of warrants. If the holders of the outstanding warrants exercise their warrants, shareholders may experience dilution in the net tangible book value of our common stock. Further, the sale or availability for sale of the underlying shares in the marketplace as a result of the exercise of existing options, the grant of additional options, and the exercise of the warrants could depress our stock price.

 

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

 

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

 

We may issue additional stock without shareholder consent.

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

 

ITEM 1B. UNRESOLVED STAFF COMMENTS

 

None.

 

 

ITEM 2. PROPERTIES

 

Executive Offices

 

Our executive offices are located at 10275 Wayzata Boulevard, Suite 100, Minnetonka, Minnesota 55305. We lease 2,813 square feet pursuant to a month-to-month lease agreement that commenced on May 1, 2012 and was amended effective November 15, 2013. In accordance with this lease, our lease term remains on a month-to-month basis, provided that either party may provide 90 day notice to terminate the lease, with base rents of $2,110 per month, plus common area operations and maintenance charges, and monthly parking fees of $240 per month, for the period from November 15, 2013 to October 31, 2014, and increases of $117 per month beginning November 1, 2014 and each of the subsequent three year periods. The owner of the building in which we are located is a company wholly owned by our chairman of the board of directors.

 

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Leasehold Properties

 

As of December 31, 2014, the Company controls approximately 10,000 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 at December 31, 2014. Net acreage represents our percentage ownership of gross acreage.

 

       Undeveloped     
   Developed Acreage   Acreage   Total Acreage 
   Gross   Net   Gross   Net   Gross   Net 
North Dakota   30,858    6,065    9,107    3,594    39,965    9,659 
Montana   760    197    128    112    888    309 
Total:   31,618    6,262    9,235    3,706    40,853    9,968 

 

Recent Acreage Acquisitions

 

In 2014, we acquired leasehold interests covering an aggregate of approximately 374 net mineral acres in our key prospect areas.

 

Recent Divestitures

 

In 2014, we sold leasehold interests covering an aggregate of approximately 502 net mineral acres and rights to individual wellbores for total proceeds of $1,360,920 for an average selling price of $2,709 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, 2014 that will expire over the next three fiscal years and thereafter unless production is established within the spacing units covering the acreage prior to the expiration dates:

 

               Expiring 2018 
   Expiring 2015   Expiring 2016   Expiring 2017   and Thereafter 
   Gross   Net   Gross   Net   Gross   Net   Gross   Net 
North Dakota   3,916    1,104    2,107    105    840    433    2,244    1,952 
Montana           128    112                 
Total:   3,916    1,104    2,235    217    840    433    2,244    1,952 

 

Of the remaining undeveloped acreage leases that expire in 2015, 2016 and 2017, there are 268 acres, 112 acres and -0- acres, respectively, in which we have options to extend the lease.

 

During 2014, we had leases encompassing 4,202 net acres expire with carrying costs of approximately $6.2 million that have been transferred to the full cost pool subject to depletion. Of the leases encompassing 1,104 net acres expiring in 2015, we estimate that all of those net acres with carrying costs of approximately $1.9 million will expire prior to the commencement of production activities. The carrying costs of the leases we estimate will expire in 2015 have also been transferred to the full cost pool and are subject to depletion. We do not believe the acreage expirations are material to our operating plan in future periods.

 

33
 

Productive Oil Wells

 

The following table summarizes gross and net productive oil wells by state at December 31, 2014 and 2013. A net well represents our percentage ownership of a gross well. The Company purchased or participated in the completion of 94 gross (3.01 net) wells in the period ending December 31, 2014 and participated in the completion of 87 gross (2.57 net) wells in the period ended December 31, 2013. The Company had no dry wells drilled in either the year ended December 31, 2014 or 2013. The following table does not include wells in which our interest is limited to overriding royalty interests. The following table also does not include wells which were awaiting completion, in the process of completion or awaiting flow back subsequent to fracture stimulation.

 

   December 31, 2014   December 31, 2013 
   Gross   Net   Gross   Net 
North Dakota   242    7.52    152    4.79 
Montana   5    0.36    1    0.08 
Total:   247    7.88    153    4.87 

 

Exploratory Oil Wells

 

The following table summarizes gross and net exploratory wells as of December 31, 2014 and 2013. The wells are at various stages of completion and the costs incurred are included in unevaluated oil and gas properties on our balance sheet.

 

   December 31, 2014   December 31, 2013 
   Gross   Net   Gross   Net 
North Dakota           6    0.13 
Montana                
Total:           6    0.13 

 

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.

 

 

 

 

 

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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, 2014 and 2013, respectively. As of December 31, 2014 and 2013 we were selling oil and natural gas from a total of 247 gross wells (approximately 7.88 net wells) and 153 gross wells (approximately 4.87 net wells), respectively. All data presented below is derived from accrued revenue and production volumes for the relevant period indicated.

 

   Years Ended December 31, 
   2014   2013 
Net Production:          
Oil (Bbl)   256,256    99,979 
Natural Gas (Mcf)   213,141    52,973 
Barrel of Oil Equivalent (Boe)   291,780    108,808 
           
Average Sales Prices:          
Oil (per Bbl)  $78.64   $89.58 
Effect of settled derivatives on average price (per Bbl)  $1.99   $0.54 
Oil net of settled derivatives (per Bbl)  $80.63   $90.12 
Natural Gas (per Mcf)  $4.46   $6.04 
Effect of settled derivatives on average price (per Mcf)  $   $ 
Natural gas net of settled derivatives (per Mcf)  $4.46   $6.04 
Realized price on a Boe basis, net of derivatives  $74.08   $85.75 
           
Average Production Costs:          
Oil (per Bbl)  $10.07   $11.06 
Natural Gas (per Mcf)  $0.58   $0.75 
Barrel of Oil Equivalent (Boe)  $9.27   $10.53 

 

Reserves

 

We completed our most recent reserve calculations as of December 31, 2014.

 

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

 

35
 

We have utilized Netherland, Sewell & Associates, Inc. (“NSAI”), an independent reservoir engineering firm, as our third-party engineering firm with the preparation of our December 31, 2014 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, 2014, 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.

 

36
 

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 began conducting oil and gas operations in 2011, at which point we first publicly disclosed our proved undeveloped reserves. As such, there are no PUD reserves on the books for more than five years from initial booking.

 

SEC Pricing Proved Reserves(1)
       Natural       Pre-Tax 
   Crude Oil   Gas   Total   PV10% 
   (barrels)   (Mcf)   (BOE)(2)   Value(3) 
PDP Properties   1,688,300    1,276,466    1,901,044    58,938,700 
PDNP Properties   111,215    86,610    125,650    4,743,100 
PUD Properties   2,998,416    1,983,691    3,329,032    36,652,900 
Total Proved Properties   4,797,931    3,346,767    5,355,726    100,334,700 

_______________________

  (1) The SEC Pricing Proved Reserves table above values crude oil and natural gas reserve quantities and related discounted future net cash flows as of December 31, 2014 assuming a constant realized price of $83.26 per barrel of crude oil and a constant realized price of $7.10 per Mcf of natural gas. The values presented in both tables above were calculated by NSAI.
  (2) BOE are computed based on a conversion ratio of one BOE for each barrel of crude oil and one BOE for every 6,000 cubic feet (i.e., 6 Mcf) of natural gas.
  (3) Pre-tax PV10% may be considered a non-GAAP financial measure as defined by the SEC and is derived from the standardized measure of discounted future net cash flows, which is the most directly comparable standardized financial measure. Pre-tax PV10% is computed on the same basis as the standardized measure of discounted future net cash flows but without deducting future income taxes. We believe Pre-tax PV10% is a useful measure for investors for evaluating the relative monetary significance of our crude oil and natural gas properties. We further believe investors may utilize our Pre-tax PV10% as a basis for comparison of the relative size and value of our reserves to other companies because many factors that are unique to each individual company impact the amount of future income taxes to be paid. Our management uses this measure when assessing the potential return on investment related to our crude oil and natural gas properties and acquisitions. However, Pre-tax PV10% is not a substitute for the standardized measure of discounted future net cash flows. Our Pre-tax PV10% and the standardized measure of discounted future net cash flows do not purport to present the fair value of our crude oil and natural gas reserves. The pre-tax PV10% values of our Total Proved Properties in the tables above differ from the tables reconciling our pre-tax PV10% value on the following page of this Annual Report due to rounding differences in certain tables of NSAI’s reserve report.

 

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

 

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

 

Based on the results of our December 31, 2014 reserve analysis, our proved reserves increased approximately 18% from, 4,537,591 BOE at December 31, 2013 to 5,355,726 BOE at December 31, 2014, primarily due to acquisitions, extensions, discoveries, and other additions related to drilling activity in and adjacent to our Bakken/Three Forks acreage. We incurred approximately $29.0 million of capital expenditures for drilling activities and $3.2 million for acreage and other expenditures during the year ended December 31, 2014, all of which directly contributed to the increase in our proved developed reserves. No other expenditures materially contributed to the development of proved developed reserves in 2014. As of December 31, 2014, we had 3,329,032 BOE of proved undeveloped reserves, which is a decrease of 172,488 BOE, or 5%, compared with 3,501,520 BOE of proved undeveloped reserves at December 31, 2013. The decrease in proved undeveloped reserves is primarily due to acquisitions, extensions, discoveries, and other additions related to drilling activity in and adjacent to our Bakken/Three Forks acreage offset by Proved undeveloped reserves that were developed and moved to proved producing reserves during the year. During 2014, our progress toward converting proved undeveloped reserves to proved developed reserves included the drilling and completion of 60 gross (1.26 net) undeveloped wells at a total estimated net capital cost of $11.3 million.

 

During 2014, we had a negative revision of 261,592 BOE, or 7%, of our December 31, 2013 estimated proved undeveloped reserves balance. The primary cause for these revisions related to wells that were non-economical due to lower oil prices. The following table details the changes in the quantity of proved undeveloped reserves during the year ended December 31, 2014:

 

   Proved 
   Undeveloped 
   Reserves 
   (BOE) 
January 1, 2014   3,501,520 
Revisions of previous quantity estimates   (261,592)
Extensions, discoveries and other additions   644,851 
Sales of reserves in place   (20,062)
PUD's converted to PDP's in 2014   (535,685)
December 31, 2014   3,329,032 

 

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, 2014 and 2013.

 

   Years Ended December 31, 
   2014   2013 
Depletion of oil and natural gas properties  $9,359,952   $3,705,156 

 

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ITEM 3. LEGAL PROCEEDINGS

 

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

 

 

ITEM 4. MINE SAFETY DISCLOSURES

 

None.

 

 

 

 

 

 

 

 

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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 OTCQB under the symbol “ANFC.” The range of high and low bid information for each fiscal quarter during 2014 and 2013 are set forth below:

 

   Sales Price 
   High   Low 
Year Ended December 31, 2014          
First Quarter  $1.04   $0.60 
Second Quarter  $0.93   $0.54 
Third Quarter  $0.94   $0.65 
Fourth Quarter  $0.75   $0.19 
           
Year Ended December 31, 2013          
First Quarter  $0.80   $0.45 
Second Quarter  $0.79   $0.60 
Third Quarter  $0.95   $0.55 
Fourth Quarter  $0.78   $0.50 

 

The above quotations reflect inter-dealer prices, without retail markup, mark-down, or commission and may not necessarily represent actual transactions. The closing price of our common stock on the OTCQB on March 23, 2015 was $0.27 per share.

 

As of March 23, 2015, there were approximately 1,900 record holders of our common stock, not including shares held in “street name” in brokerage accounts which is unknown. As of March 23, 2015, there were 47,979,990 shares of common stock outstanding on record.

 

Dividends

 

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

 

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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, 2014:

 

Number of securities to be issued upon exercise of outstanding stock options  Weighted-average exercise price of outstanding stock options  Number of securities remaining available for future issuance under equity compensation plans
7,208,834  $0.56  231,166

 

For the fiscal years ended December 31, 2014 and 2013, we issued a total of 632,500 and 2,657,500 stock options, respectively, pursuant to our 2012 Amended and Restated Stock Incentive Plan. There were 63,500 and 166,667 options cancelled during the years ended December 31, 2014 and 2013, respectively.

 

Warrants

 

For the fiscal years ended December 31, 2014 and 2013, we issued a total of -0- and 5,000,000 warrants, respectively, to purchase shares of registered or unregistered common stock. There were 330,000 and -0- warrants forfeited during the years ended December 31, 2014 and 2013, respectively.

 

Unregistered Issuance of Equity Securities

 

We did not issue securities during the fiscal year ending December 31, 2014 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.

 

 

 

 

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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, 2014, we controlled the rights to mineral leases covering approximately 10,000 net acres for prospective drilling to the Bakken and/or Three Forks formations. Looking forward, we are pursuing the following objectives:

 

Acquire high-potential mineral leases;

Access appropriate capital markets to fund continued acreage acquisition and drilling activities;

Develop and maintain strategic industry relationships;

Attract and retain talented associates;

Operate a low overhead non-operator business model; and

Become a low cost producer of hydrocarbons.

 

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

 

·The ability of the Company to acquire acreage at a price that is significantly below the acreage value when fully developed;
·The ability of operators to successfully drill wells on the acreage position we hold and incur customary costs;
·The price per barrel of oil;
·The number of producing wells we own and the performance of those wells; and
·Our ability to raise capital to fund drilling costs and acreage acquisitions.

 

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

 

Overview of 2014 results

 

During 2014, we achieved the following financial and operating results:

 

·168% production growth compared to 2013;
·18% proved reserve growth on a Boe basis compared to 2013;
·35% growth in the value of our SEC Pricing Proved Reserves as determined by our independent reservoir engineering firm;
·Purchased or participated in the completion of 94 gross (3.01 net) wells;
·Realized gains from hedges on our 2014 production of $0.5 million and had $7.8 million of unrealized gains on the mark-to-market of hedges on 295 thousand barrels of our future production
·Ended the year with 2.83 net wells preparing to drill, drilling, awaiting completion, or completing;
·Realized an average selling price of $78.64 per barrel of oil sold, before the effect of settled derivatives, as compared to $89.58 in 2013, a decrease of 12.21%;
·Ended the year with $12.4 million of availability under our Credit Facilities; and
·Realized $8.9 million of cash flow from operating activities.

 

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Operationally, our 2014 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 0.8 million BOE, which is 2.8 times our 2014 production. During 2014, production increased 168% to 291,780 BOE as compared to 2013 production of 108,808 BOE. The increase in 2014 production was driven by a 62% increase in net producing wells from 4.87 net wells at December 31, 2013 to 7.88 net wells at December 31, 2014.

 

Total revenues from oil and gas sales increased 127% in 2014 compared to 2013 driven by the 168% increase in production and offset by a decrease in average realized prices on a BOE basis, before the effect of settled derivatives, of 15.2% in 2014 compared to 2013. 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.

 

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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 years ended December 31, 2014 and 2013, we did not incur impairment pursuant to our ceiling test. 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.

 

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Asset Retirement Obligations

 

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

 

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

 

Revenue Recognition

 

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

 

Derivative Instrument Activities

 

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

 

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

 

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

 

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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.

 

 

 

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Results of Operations for the Years Ended December 31, 2014 and 2013.

 

The following table summarizes selected items from the statement of operations for the years ended December 31, 2014 and 2013.

 

   Years Ended December 31, 
   2014   2013 
Oil and gas sales  $21,102,823   $9,276,656 
Gain on settled derivatives   511,451    53,482 
Gain (loss) on the mark-to-market of derivatives   7,793,421    (213,676)
Total revenues:   29,407,695    9,116,462 
           
Operating expenses:          
Production expenses   2,705,763    1,145,686 
Production taxes   2,203,501    1,015,907 
General and administrative   2,891,641    2,299,757 
Depletion of oil and gas properties   9,359,952    3,705,156 
Accretion of discount on asset retirement obligations   22,361    9,019 
Depreciation and amortization   29,138    24,001 
Total operating expenses:   17,212,356    8,199,526 
           
Net operating income   12,195,339    916,936 
           
Total other income (expense)   (5,284,264)   (2,018,446)
           
Income (loss) before provision for income taxes   6,911,075    (1,101,510)
           
Provision for income taxes   2,559,195    698,851 
           
Net income (loss)  $4,351,880   $(402,659)

 

Oil and Natural Gas Sales

 

We recognized $21,102,823 in oil and gas sales for the year ended December 31, 2014, compared to oil and gas sales of $9,276,656 for the year ended December 31, 2013, an increase of $11,826,167, or 127%. Our oil and gas sales are generated from the drilling and development of producing wells. We had 7.88 net producing wells as of December 31, 2014, and an additional 2.83 net wells that were either in the drilling preparation, drilling, awaiting completion, or completing stages, compared to 4.87 net producing wells, and an additional 1.36 net wells that were either in the drilling preparation, drilling, awaiting completion, or completing stages as of December 31, 2013.

 

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 $230,000 and $451,000 in oil and gas sales for the years ended December 31, 2014 and 2013 respectively. 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.

 

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Derivatives

 

We had gains on settled derivatives of $511,451 and $53,482 for the years ended December 31, 2014 and 2013, respectively.

 

We had mark-to-market derivative gain of $7,793,421 in 2014 and a mark-to-market derivative loss of $213,676 in 2013, resulting in a net derivative asset of $7,579,745 as of December 31, 2014.

 

Expenses:

 

Production expenses

 

Production expenses were $2,705,763 and $1,145,686 for the years ended December 31, 2014 and 2013, respectively, an increase of $1,560,077, or 136%. Our production expenses are greater in the comparative period due to our rapid expansion and increased acreage holdings. Production expenses as a percentage of oil and gas sales increased from 12.4% in 2013 to 12.8% in 2014. On a per Boe basis, production expenses decreased from $10.53 per Boe to $9.27 per Boe, primarily due to decreased water disposal costs and workover and related expenses.

 

Production taxes

 

Production taxes were $2,203,501 and $1,015,907 for the year ended December 31, 2014 and 2013, respectively, an increase of $1,187,594, or 117%. Production taxes are based on realized oil and gas sales. Production taxes represent 10.4% and 11.0% of oil and gas sales, respectively for 2014 and 2013, the decrease driven by increased gas production, which has a lower tax rate as a percentage of our total sales.

 

General and administrative expenses

 

General and administrative expenses for the year ended December 31, 2014 were $2,891,641, compared to $2,299,757 for the year ended December 31, 2013. The increase for 2014 as compared to 2013 was $591,884, or 26%, and is primarily attributed to increased head count as staffing has increased to accommodate our increased production. On a per unit basis, general and administrative expenses decreased 53% from $21.14 per BOE produced in 2013 to $9.91 per Boe produced in 2014, as our general and administrative costs grew at a far slower rate than our production.

 

Depletion of oil and natural gas properties

 

Our depletion expense is driven by many factors, including certain exploration costs involved in the development of producing reserves, production levels and estimates of proved reserve quantities and future developmental costs. We recognized depletion expense of $9,359,952 for the year ended December 31, 2014, compared to $3,705,156 for the year ended December 31, 2013, an increase of $5,654,796, or 153%. The increase was due primarily to increased production as our production on a Boe basis increased 168%. Additionally, during 2014 we moved approximately $1.9 million in costs associated with expected 2015 lease expirations into our depreciable cost pool, increasing our depreciation by approximately $98,000, or 2% of the 153% year over year increase.

 

Depreciation

 

Depreciation expense for the year ended December 31, 2014 was $29,138, compared to $24,001 for the year ended December 31, 2013.

 

Accretion

 

Expenses for accretion of our discount on asset retirement obligation for the year ended December 31, 2014 was $22,361, compared to $9,019 for the year ended December 31, 2013.

 

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Other income and (expenses)

 

Other income and (expenses) for the year ended December 31, 2014, resulted in a net expense of $5,284,264, compared to a net expense of $2,018,446 for the year ended December 31, 2013, resulting in a net increase of $3,265,818.

 

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

 

The net other income and (expenses) for the year ended December 31, 2013, consisted of a net gain of $361,505 due to an additional settlement proceed, net of expenses, related to the Peerless/ElectraWorks settlement resulting from the legalization of on-line gaming in New Jersey, $408 of interest income earned on money market accounts and $2,380,359 of interest expense. Interest expense includes $307,822 of amortized warrant costs and $750,155 of amortized loan origination costs. Amortization of the fair value of the warrants and loan origination costs related to the Dougherty facility were accelerated in 2013 due to termination of the Dougherty credit facility in the third quarter of 2013 as part of our refinancing.

 

Provision for Income Taxes

 

We had income tax expense of $2,559,195 for the year ended December 31, 2014, compared to an income tax benefit of $698,851 for the year ended December 31, 2013. The increased expense for 2014, compared to 2013, was $3,258,046, and was primarily due to our net income created primarily by the non-cash gain on the mark-to-market of derivatives.

 

Net income (loss)

 

The net income for 2014 was $4,351,880, compared to net a loss in 2013 of $402,659. Operating income, consisting of total revenue less operating expenses, was $12,195,339 and $916,936 in 2014 and 2013, respectively. The mark-to-market gains on derivatives amounted to $7,793,421 and realized gains on settled derivatives were $511,451 in 2014, and contributed significantly to the increase in operating income. Additionally, production and revenues increased faster than administrative expenses contributing to the increase in operating income. Offsetting the increase in operating income, interest expense increased $2,904,877, as we funded a portion of well development and property acquisitions through increases in our debt. Income tax expense increased $3,258,046, as pretax income increased by $8,012,585.

 

 

 

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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:

 

   Years Ended December 31, 
   2014   2013 
Net income (loss)  $4,351,880   $(402,659)
Subtract:          
Loss (gain) on mark-to-market of derivatives, net of tax(a)   (4,909,421)   134,676 
Settlement income, net of tax (b)       (227,505)
Adjusted net income (loss)  $(557,541)  $(495,488)
           
Weighted average common shares outstanding - basic   47,979,990    47,979,990 
Weighted average common shares outstanding - fully diluted   49,179,725    47,979,990 
           
Net income (loss) per common share - basic  $0.09   $(0.01)
Subtract:          
Loss (gain) on mark-to-market of derivatives, net of tax   (0.10)   (0.00)
Settlement income per common share, net of tax       (0.00)
Adjusted net income (loss) per common share - basic  $(0.01)  $(0.01)
           
Net income (loss) per common share - fully diluted  $0.09   $(0.01)
Subtract:          
Loss (gain) on mark-to-market of derivatives, net of tax   (0.10)   (0.00)
Settlement income per common share, net of tax       (0.00)
Adjusted net income (loss) per common share - fully diluted  $(0.01)  $(0.01)

 

(a)Adjusted to reflect tax (expense) benefit, computed based on our effective tax rates of approximately 37% in 2014 and 2013, of ($2,884,000) and $79,000, respectively, for the years ended December 31, 2014 and 2013.
(b)Adjusted to reflect tax expense, computed based on our effective tax rate of approximately 37% in 2013, of $134,000, for the year ended December 31, 2013.

 

 

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   Years Ended December 31, 
   2014   2013 
Net income (loss)  $4,351,880   $(402,659)
Add back:          
Interest expense, net, excluding amortization of warrant based financing costs   4,656,069    2,072,129 
Income tax provision   2,559,195    (698,851)
Depreciation, depletion, and amortization   9,389,090    3,729,157 
Accretion of abandonment liability   22,361    9,019 
Share-based compensation and expense   1,207,114    951,639 
Losses (gains) on the mark-to-market of derivatives   (7,793,421)   213,676 
           
Adjusted EBITDA  $14,392,288   $5,874,110 

 

Our Adjusted EBITDA for the year ended December 31, 2013 includes settlement income, net of settlement expenses, of $361,505.

 

Liquidity and capital resources

 

The following table summarizes our total current assets, liabilities and working capital at December 31, 2014 and 2013.

 

   December 31, 
   2014   2013 
Current Assets  $9,448,043   $4,296,618 
           
Current Liabilities  $10,348,697   $8,597,588 
           
Working Capital  $(900,654)  $(4,300,970)

 

As of December 31, 2014 we had negative working capital of $900,654.

 

The following table summarizes our cash flows during the years ended December 31, 2014 and 2013, respectively.

 

   Years Ended 
   December 31, 
   2014   2013 
Net cash provided by operating activities  $8,941,815   $6,085,365 
Net cash used in investing activities   (29,143,086)   (32,338,413)
Net cash provided by financing activities   19,145,606    25,986,055 
           
Net change in cash and cash equivalents  $(1,055,665)  $(266,993)

 

Our net cash flows from operations are primarily affected by production volumes and commodity prices. Net cash provided by operating activities was $8,941,815 and $6,085,365 for the years ended December 31, 2014 and 2013, respectively, an increase of $2,856,450. The increase was primarily due to increased operating income offset by the unrealized gain on mark-to-market of derivatives included in operating income and the net change in current assets and current liabilities. Changes in current assets and liabilities, aside from those associated with settlement activity, resulted in a decrease in cash of approximately $2,370,769 and $920,547 in 2014 and 2013, respectively, a net decrease of $1,450,222 for 2014, as compared to 2013.

 

Net cash used in investing activities was $29,143,086 and $32,338,413 for the years ended December 31, 2014 and 2013, respectively, a decrease of $3,195,327. The decrease was primarily due to a decrease in purchases and development of oil and gas properties of $7,286,317. Purchases of oil and gas properties in 2014 amounted to $3,164,469 and we paid $21,574,938 in well development costs. Investing activity in 2014 also included advances of $5,822,086 to operators for future well development and proceeds from the sale of oil and gas properties of $1,441,929. In 2013, we acquired the CPX properties for $20,680,032. Additionally in 2013, cash applied to the purchase of oil and gas properties totaled $11,345,692, including $4,150,622 of purchases of oil and gas properties and $7,195,070 paid for the development of oil and gas wells. In 2013, we also advanced operators $882,604 for future well development and received $608,387 in proceeds from the sale of oil and gas properties.

 

Net cash provided from financing was $19,145,606 and $25,986,055 for the years ended December 31, 2014 and 2013, respectively, a decrease of $6,840,449. We drew $19,400,000 and $26,851,156, net of repayments, on our credit facilities in 2014 and 2013, respectively. We paid $254,394 and $865,101 in debt issuance costs in 2014 and 2013, respectively, with the activity in 2013 primarily related to refinancing activity.

 

51
 

 

Senior Credit Facility and Subordinated Credit Facilities

 

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

 

Availability under the Senior Credit Facility is at all times subject to the then-applicable borrowing base, determined by Cadence in a manner consistent with the normal and customary oil and gas lending practices of Cadence. Availability was initially set at $7 million and is subject to periodic redeterminations and was $35 million as of December 31, 2014, and subsequently amended to $34 million on March 30, 2015. Subject to availability under the borrowing base, the Company may borrow, repay and re-borrow funds in amounts of $250,000, or more. At the Company’s election, the unpaid principal balance of any borrowings under the Senior Credit Facility may bear interest at either (i) the Base Rate, as defined in the Senior Credit Facility, plus the applicable margin, which varies from 1.00% to 1.50% or (ii) the LIBOR rate, as defined in the Senior Credit Facility, plus the applicable margin, which varies from 3.00% to 3.50%. Interest is payable for Base Rate loans on the last business day of the month and for LIBOR loans on the last LIBOR business day of each LIBOR interest period. The Company is also required to pay a quarterly fee of 0.50% on any unused portion of the borrowing base, as well as a facility fee of 0.90% of the initial and any subsequent additions to the borrowing base.

 

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

 

As of December 31, 2014 the Company had borrowings of $22.6 million outstanding under the Senior Credit Agreement.

 

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

 

52
 

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

 

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

 

The first funding from the Subordinated Credit Facility occurred on September 9, 2013 at which time we drew $14,700,000, net of a $300,000 original issue discount, from the Subordinated Credit Agreement and used $10,226,057 of those proceeds to repay and terminate the Dougherty revolving credit facility. We have drawn an additional $14,700,000, net of $300,000 in original issue discounts, in additional draws through December 31, 2014.

 

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

 

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

 

53
 

In connection with the Subordinated Credit Facility, the Company agreed to issue to the lenders detachable warrants to purchase up to 5,000,000 shares of the Company’s common stock at an exercise price of $0.65 per share. The warrants expire on August 8, 2018. Proceeds from the loan were allocated between the debt and equity based on the relative fair values at the time of issuance, resulting in a debt discount of $2,473,576 at issuance that is presented as a debt discount on the balance sheet and is being amortized using the effective interest method over the life of the credit facility, which matures on June 30, 2017. A total of $628,195 and $199,632 was amortized during the years ended December 31, 2014 and 2013. The remaining unamortized balance of the debt discount attributable to the warrants is $1,645,749 as of December 31, 2014.

 

Dougherty Revolving Credit Facility (former credit facility)

 

On April 4, 2012, the Company entered into a Secured Revolving Credit Agreement with Dougherty Funding LLC (“Dougherty”) 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 “Dougherty Credit Facility”).

 

The Dougherty Credit Facility provided for a maximum available amount of $20 million, of which $16.5 million was available prior to termination of the facility, with interest payable on the outstanding balance at a rate of 9.25% per year and a maturity date of August 1, 2015. In connection with the amended financing, the Company issued Dougherty Funding, LLC warrants to purchase 585,000 shares of the Company’s common stock at an exercise price of $0.38 per share. 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 predecessor PrenAnte5 revolving credit facility, including interest of $51,722.

 

On September 9, 2013, we repaid the Dougherty Credit Facility with proceeds from the Subordinated Credit Facility.

 

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 2015. However, we believe our credit facilities will provide sufficient funding for our property acquisition and development plans through those same periods. 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, 2014, our balance of cash and cash equivalents was $94,682. 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 facilities, sale of properties that do not meet our investment criteria, and potential sale or use of shares of our stock.

 

54
 

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, 2014 to make future payments under certain contracts, aggregated by category of obligation, for specified time periods:

 

   Payment Due by Period 
Contractual  Less than           More than     
Obligations  1 Year   1-3 Years   3-5 Years   5 Years   Total 
Senior Credit Facility  $   $22,600,000   $   $   $22,600,000 
Subordinated Credit Facility       30,000,000            30,000,000 
Cash Interest Expense on Debt (1)   4,129,267    5,617,616            9,746,883 
PIK interest (2)       4,593,929            4,593,929 
AFE Commitments (3)   16,513,219                16,513,219 
Total  $20,642,486   $62,811,545   $   $   $83,454,031 

 

(1)Cash Interest on Senior Credit Facility and Subordinated Credit Facility is estimated assuming:
a)no principal repayment until the maturity date;
b)interest rate in effect as of December 31, 2014 remains in effect throughout life of loan; and
c)includes unused commitment fees and loan maintenance fees.
(2)PIK on Subordinated Credit Facility of 4% paid at Subordinated Credit Facility maturity date.
(3)Additional commitments on our Authorization for Expenditures (“AFE”) not accrued as of December 31, 2014.

 

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, 2014, we had eight employees, our chief executive officer, Kenneth DeCubellis, our chief financial officer, James Moe, our chief operating officer, Michael Eisele and five other employees. Currently, there are no organized labor agreements or union agreements and we do not anticipate any in the future.

 

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

 

Off-Balance Sheet Arrangements

 

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

 

55
 

 

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

 

Commodity Price Risk

 

The price we receive for our oil and natural gas production heavily influences our revenue, profitability, access to capital and future rate of growth. Oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand and other factors. Historically, the markets for oil and natural gas have been volatile, and our management believes these markets will likely continue to be volatile in the future. The prices we receive for our production depend on numerous factors beyond our control. Our revenue during 2014, generally would have increased or decreased along with any increases or decreases in oil or natural gas prices, but the exact impact on our income is indeterminable given the variety of expenses associated with producing and selling oil that also increase and decrease along with oil prices.

 

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

 

We generally use derivatives to economically hedge a significant, but varying portion of our anticipated future production over a rolling 36 month horizon. Any payments due to counterparties under our derivative contracts are funded by proceeds received from the sale of our production. Production receipts, however, lag payments to the counterparties. Any interim cash needs are funded by cash from operations or borrowings under our Credit Facilities.

 

The Company’s derivative contracts are settled based on reported settlement prices on commodity exchanges, with crude oil derivative settlements based on NYMEX West Texas Intermediate (“WTI”) pricing. The following table reflects open commodity swap contracts as of December 31, 2014, the associated volumes and the corresponding fixed price.

 

   Oil   Fixed 
Settlement Period  (Barrels)   Price 
Swaps-Crude Oil          
January 1, 2015 – December 31, 2015   24,000   $88.28 
January 1, 2015 – December 31, 2015   21,000   $89.70 
January 1, 2015 – December 31, 2015   12,000   $92.38 
January 1, 2015 – December 31, 2015   30,000   $90.16 
January 1, 2016 – December 31, 2016   60,000   $90.36 
January 1, 2016 – December 31, 2016   24,000   $88.15 
January 1, 2017 – December 31, 2017   78,000   $87.18 

 

As of December 31, 2014, we had a total volume on open commodity swaps of 249,000 barrels at a weighted average price of approximately $88.97.

 

56
 

 

The following table reflects the weighted average price of open commodity swap derivative contracts as of December 31, 2014, by year with associated volumes.

 

Weighted Average Price of
Open Commodity Swap Contracts
       Weighted 
   Volumes   Average 
Year  (Bbl)   Price 
2015   87,000   $89.84 
2016   84,000   $89.73 
2017   78,000   $87.18 

 

In addition to the open commodity swap contracts, we have entered into costless collar contracts. The costless collars are used to establish floor and ceiling prices on anticipated crude oil production. There were no premiums paid or received by us related to the costless collar contracts. The following table reflects open costless collar contracts as of December 31, 2014.

 

   Oil   Floor/Ceiling   
Term  (Barrels)   Price  Basis
Costless Collars – Crude Oil           
01/01/2015 – 12/31/2015   36,000   $75.00/$95.60  NYMEX
01/01/2016 – 06/30/2016   10,002   $80.00/$89.50  NYMEX

 

Interest Rate Risk

 

Our credit facilities are tied to LIBOR if and when the associated LIBOR rate goes above 1%. As a result, changes in interest rates can impact our financial results and cash flows. A 1% increase in short-term interest rates on our floating-rate debt as of December 31, 2014 would cost us approximately $545,000 in additional interest expense annually.

 

 

 

 

 

 

57
 

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

 

 

BLACK RIDGE OIL & GAS, INC.

 

FINANCIAL STATEMENTS

 

FOR THE YEARS ENDED DECEMBER 31, 2014 AND 2013

 

 

CONTENTS

 

 

Report of Independent Registered Public Accounting Firm F-1
   
Balance Sheets as of December 31, 2014 and 2013 F-2
   
Statements of Operations for the years ended December 31, 2014 and 2013 F-3
   
Statement of Stockholders’ Equity for the years ended December 31, 2014 and 2013 F-4
   
Statements of Cash Flows for the years ended December 31, 2014 and 2013 F-5
   
Notes to Financial Statements F-6
   
Supplemental Oil and Gas Information (Unaudited) F-30

 

 

 

 

 

58
 

Description: Description: G:\Clients\MKACPAS.com\designs\M&K-CPAS-PLLC-v2.jpg

 

 

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 

 

To the Board of Directors

Black Ridge Oil & Gas, Inc.

 

We have audited the accompanying balance sheets of Black Ridge Oil & Gas, Inc. (the “Company”) as of December 31, 2014 and 2013 and the related statements of operations, stockholders' equity, and cash flows for the years then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

 

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

 

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Black Ridge Oil & Gas, Inc. as of December 31, 2014 and 2013, 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 30, 2015

 

 

 

F-1
 

 

BLACK RIDGE OIL & GAS, INC.

BALANCE SHEETS

 

   December 31,   December 31, 
   2014   2013 
ASSETS          
           
Current assets:          
Cash and cash equivalents  $94,682   $1,150,347 
Derivative instruments   3,571,803     
Accounts receivable   5,740,171    1,905,467 
Advances to operators       1,214,662 
Prepaid expenses   41,387    26,142 
Total current assets   9,448,043    4,296,618 
           
Property and equipment:          
Oil and natural gas properties, full cost method of accounting          
Proved properties   112,418,105    79,361,432 
Unproved properties   591,121    2,798,795 
Other property and equipment   139,004    115,482 
Total property and equipment   113,148,230    82,275,709 
Less, accumulated depreciation, amortization, depletion and allowance for impairment   (18,902,524)   (9,513,434)
Total property and equipment, net   94,245,706    72,762,275 
           
Derivative instruments   4,007,942     
Debt issuance costs, net   701,019    772,883 
           
Total assets  $108,402,710   $77,831,776 
           
           
LIABILITIES AND STOCKHOLDERS' EQUITY          
           
Current liabilities:          
Accounts payable  $10,291,262   $8,453,709 
Accrued expenses   57,435    4,813 
Derivative instruments       139,065 
Total current liabilities   10,348,697    8,597,587 
           
Derivative instruments       74,611 
Asset retirement obligations   286,804    160,665 
Revolving credit facility and long term debt, net of discounts of $2,072,483 and $2,645,582, respectively   51,834,603    30,556,301 
Deferred tax liability   6,593,040    4,033,845 
           
Total liabilities   69,063,144    43,423,009 
           
Commitments and contingencies (See note 14)        
           
Stockholders' equity:          
Preferred stock, $0.001 par value, 20,000,000 shares authorized, no shares issued and outstanding        
Common stock, $0.001 par value, 500,000,000 shares authorized, 47,979,990 shares issued and outstanding   47,980    47,980 
Additional paid-in capital   33,651,714    33,072,795 
Retained earnings   5,639,872    1,287,992 
Total stockholders' equity   39,339,566    34,408,767 
           
Total liabilities and stockholders' equity  $108,402,710   $77,831,776 

 

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

 

 

F-2
 

BLACK RIDGE OIL & GAS, INC.

STATEMENTS OF OPERATIONS

 

   For the Years 
   Ended December 31, 
   2014   2013 
         
Oil and gas sales  $21,102,823   $9,276,656 
Gain on settled derivatives   511,451    53,482 
Gain (loss) on the mark-to-market of derivatives   7,793,421    (213,676)
Total revenues  $29,407,695   $9,116,462 
           
Operating expenses:          
Production expenses   2,705,763    1,145,686 
Production taxes   2,203,501    1,015,907 
General and administrative   2,891,641    2,299,757 
Depletion of oil and gas properties   9,359,952    3,705,156 
Accretion of discount on asset retirement obligations   22,361    9,019 
Depreciation and amortization   29,138    24,001 
Total operating expenses   17,212,356    8,199,526 
           
Net operating income   12,195,339    916,936 
           
Other income (expense):          
Interest income   972    408 
Interest (expense)   (5,285,236)   (2,380,359)
Settlement income       380,982 
Settlement expense       (19,477)
Total other income (expense)   (5,284,264)   (2,018,446)
           
Income (loss) before provision for income taxes   6,911,075    (1,101,510)
           
Provision for income taxes   (2,559,195)   698,851 
           
Net income (loss)  $4,351,880   $(402,659)
           
           
Weighted average common shares outstanding - basic   47,979,990    47,979,990 
Weighted average common shares outstanding - fully diluted   49,179,725    47,979,990 
           
Net income (loss) per common share - basic  $0.09   $(0.01)
Net income (loss) per common share - fully diluted  $0.09   $(0.01)

 

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

 

 

F-3
 

BLACK RIDGE OIL & GAS, INC.

STATEMENT OF STOCKHOLDERS' EQUITY

 

                   Additional       Total 
   Preferred Stock   Common Stock   Paid-In   Accumulated   Stockholders' 
   Shares   Amount   Shares   Amount   Capital   (Deficit)   Equity 
                             
Balance, December 31, 2012      $    47,979,990   $47,980   $29,847,212   $1,690,651   $31,585,843 
                                    
Common stock warrants granted as financing costs, presented as a debt discount                   2,473,576        2,473,576 
                                    
Common stock warrants granted as financing costs                   108,190        108,190 
                                    
Common stock options granted for services to employees                   643,817        643,817 
                                    
Net loss for the year ended December 31, 2013                       (402,659)   (402,659)
                                    
Balance, December 31, 2013      $    47,979,990   $47,980   $33,072,795   $1,287,992   $34,408,767 
                                    
Common stock options granted for services to employees                   578,919        578,919 
                                    
Net income for the year ended December 31, 2014                       4,351,880    4,351,880 
                                    
Balance, December 31, 2014      $    47,979,990   $47,980   $33,651,714   $5,639,872   $39,339,566 

 

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

 

 

F-4
 

BLACK RIDGE OIL & GAS, INC.

STATEMENTS OF CASH FLOWS

 

   For the Years 
   Ended December 31, 
   2014   2013 
CASH FLOWS FROM OPERATING ACTIVITIES          
Net income (loss)  $4,351,880   $(402,659)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:                
Depletion of oil and gas properties   9,359,952    3,705,156 
Depreciation and amortization   29,138    24,001 
Amortization of debt issuance costs   326,258    749,920 
Accretion of discount on asset retirement obligations   22,361    9,019 
Loss (gain) on the mark-to-market of derivatives   (7,793,421)   213,676 
Accrued payment in kind interest applied to long term debt   1,105,203    201,883 
Amortization of original issue discount on debt   144,904    28,362 
Amortization of debt discounts, warrants   628,195    199,632 
Common stock warrants granted as financing costs       108,190 
Common stock options issued to employees and directors   578,919    643,817 
Deferred income taxes   2,559,195    (698,851)
Decrease (increase) in current assets:          
Accounts receivable   (2,834,704)   (1,049,234)
Settlement receivable       2,500,000 
Prepaid expenses   (15,245)   21,013 
Increase (decrease) in current liabilities:          
Accounts payable   426,558    164,527 
Settlement payable       (160,000)
Settlement payable, related parties       (116,234)
Accrued expenses   52,622    (56,853)
Net cash provided by operating activities   8,941,815    6,085,365 
           
CASH FLOWS FROM INVESTING ACTIVITIES          
Proceeds from sale or swap of oil and gas properties   1,441,929    608,387 
Purchases of oil and gas properties and development capital expenditures   (24,739,407)   (32,025,724)
Advances to operators   (5,822,086)   (882,604)
Purchases of other property and equipment   (23,522)   (38,472)
Net cash used in investing activities   (29,143,086)   (32,338,413)
           
CASH FLOWS FROM FINANCING ACTIVITIES          
Advances from revolving credit facilities and long term debt   29,800,000    41,150,000 
Repayments on revolving credit facilities   (10,400,000)   (14,298,844)
Debt issuance costs   (254,394)   (865,101)
Net cash provided by financing activities   19,145,606    25,986,055 
           
NET CHANGE IN CASH   (1,055,665)   (266,993)
CASH AT BEGINNING OF PERIOD   1,150,347    1,417,340 
CASH AT END OF PERIOD  $94,682   $1,150,347 
           
           
SUPPLEMENTAL INFORMATION:          
Interest paid  $3,401,028   $1,104,688 
Income taxes paid  $   $ 
           
NON-CASH INVESTING AND FINANCING ACTIVITIES:          
Net change in accounts payable for purchase of oil and gas properties  $1,410,995   $5,335,656 
Advances to operators received in swap for oil and gas properties  $   $(1,200,000)
Advances to operators applied to purchase of oil and gas properties  $6,036,748   $2,218,237 
Advances to operators reclassified to accounts receivable  $1,000,000   $ 
Capitalized asset retirement costs, net of revision in estimate  $103,778   $84,501 
Fair value of detachable warrants granted in consideration of debt financing  $   $2,473,576 

 

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

F-5
 

BLACK RIDGE OIL & GAS, INC.

NOTES TO FINANCIAL STATEMENTS

 

Note 1 – Organization and Nature of Business

 

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

 

The Company’s focus is the acquisition, exploration, development and production of crude oil and natural gas properties, primarily in the Bakken and Three Forks trends in North Dakota and Montana. We believe that our prospective success revolves around our ability to acquire mineral rights and participate in drilling activities by virtue of our ownership of such rights and through the relationships we have developed with our operating partners.

 

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

 

 

Note 2Summary of Significant Accounting Policies

 

Basis of Accounting

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

 

Segment Reporting

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

 

Use of Estimates

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

 

Environmental Liabilities

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

 

F-6
 

BLACK RIDGE OIL & GAS, INC.

NOTES TO FINANCIAL STATEMENTS

 

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:

 

   December 31, 
   2014   2013 
Cash  $94,682   $1,112,356 
Money market funds       37,991 
Total  $94,682   $1,150,347 

 

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 $-0- and $862,356 in excess of FDIC and SIPC insured limits at December 31, 2014 and 2013, respectively. The Company has not experienced any losses in such accounts.

 

Advances to Operators

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

 

Debt Issuance Costs

Costs relating to obtaining certain debts are capitalized and amortized over the term of the related debt using the straight-line method, which approximates the effective interest method. The Company paid $254,394 and $865,101 of debt issuance costs during the years ended December 31, 2014 and 2013, respectively, of which the unamortized balance of debt issuance costs at December 31, 2014 and 2013 was $701,019 and $772,883, respectively. Amortization of debt issuance costs charged to interest expense was $326,258 and $749,920 for the years ended December 31, 2014 and 2013, 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:

 

1)Initial stage (planning), whereby the related costs are expensed.

 

2)Development (web application, infrastructure, graphics), whereby the related costs are capitalized and amortized once the website is ready for use. Costs for development content of the website may be expensed or capitalized depending on the circumstances of the expenditures.

 

3)Post-implementation (after site is up and running: security, training, admin), whereby the related costs are expensed as incurred. Upgrades are usually expensed, unless they add additional functionality.

 

We have capitalized a total of $56,660 of website development costs from inception through December 31, 2014. We have recognized depreciation expense on these website costs of $15,380 and $18,887 for the years ended December 31, 2014 and 2013, respectively.

 

F-7
 

BLACK RIDGE OIL & GAS, INC.

NOTES TO FINANCIAL STATEMENTS

 

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 $29,138 and $24,001 for the years ended December 31, 2014 and 2013, respectively.

 

Revenue Recognition

The Company recognizes oil and gas revenues from its interests in producing wells when production is delivered to, and title has transferred to, the purchaser and to the extent the selling price is reasonably determinable. The Company uses the sales method of accounting for gas balancing of gas production and would recognize a liability if the existing 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, 2014 and 2013, respectively:

 

   Years Ended December 31, 
   2014   2013 
Capitalized Certain Payroll and Other Internal Costs  $61,861   $137,509 
Capitalized Interest Costs   372,673     
Total  $434,534   $137,509 

 

F-8
 

BLACK RIDGE OIL & GAS, INC.

NOTES TO FINANCIAL STATEMENTS

 

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, 2014, the Company sold approximately 502 net acres and rights to individual well bores for total proceeds of $1,441,929. During the year ended December 31, 2013, the Company sold approximately 189 net acres for total proceeds of $608,387. 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 no impairment costs during the years ended December 31, 2014 and 2013, 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 do not consider any purchasers to represent a material concentration to our sales for the years ended December 31, 2014 or 2013, as we believe any of our customers could easily be replaced.

 

Since we do not operate any of our wells, we depend on our drilling partner operators to perform the drilling and other operating activities required for all sales of oil and gas. These operators are also responsible for remitting to us our revenue proceeds and billing us for drilling costs and lease operating expenses incurred. We had material concentrations of accounts receivable owed from four (4) and four (4) operators during the years ended December 31, 2014 and 2013, respectively, representing 56% and 60% of total oil and gas revenues and 36% and 41% of total oil and gas accounts receivable as of December 31, 2014 and 2013, respectively. As of December 31, 2014 and 2013, we had 7.88 and 4.87 net producing wells, respectively. As of December 31, 2014 and 2013, these operating partners operated 38% and 37% of the net producing wells, respectively.

 

Basic and Diluted Loss Per Share

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

 

F-9
 

BLACK RIDGE OIL & GAS, INC.

NOTES TO FINANCIAL STATEMENTS

 

The reconciliation of the denominators used to calculate basic EPS and diluted EPS for the years ended December 31, 2014 and 2013 are as follows:

 

   Years Ended December 31, 
   2014   2013 
Weighted average common shares outstanding – basic   47,979,990    47,979,990 
Plus: Potentially dilutive common shares:          
Stock options and warrants   1,199,735     
Weighted average common shares outstanding – diluted   49,179,725    47,979,990 

 

Stock options and warrants excluded from the calculation of diluted EPS because their effect was anti-dilutive were 13,683,209 and 16,103,209 as of December 31, 2014 and 2013, 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 stock options issued for services and compensation totaled $578,919 and $643,817 for the years ended December 31, 2014 and 2013, respectively. The fair values of stock options were determined using the Black-Scholes options pricing model and an effective term of 6 to 6.5 years based on the weighted average of the vesting periods and the stated term of the option grants and the discount rate on 5 to 7 year U.S. Treasury securities at the grant date and are being amortized over the related implied service term, or vesting period.

 

Uncertain Tax Positions

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

 

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

 

Recent Accounting Pronouncements

Various accounting standards and interpretations were issued in 2014 with effective dates subsequent to December 31, 2014. We have evaluated the recently issued accounting pronouncements that are effective in 2015 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 2014 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.

 

 

F-10
 

BLACK RIDGE OIL & GAS, INC.

NOTES TO FINANCIAL STATEMENTS

 

Note 3 – Acquisition

 

On December 13, 2013, the Company acquired oil and natural gas properties from CP Exploration, LP (“CPX”) for approximately $20.6 million, net of purchase price adjustments (“the CPX Acquisition”). The properties acquired in the CPX Acquisition are comprised of leasehold interests in approximately 2,040 net mineral acres in the Williston Basin of North Dakota and interests in 43 gross (0.92 net) producing wells on the acquired leases.

 

The Company completed its valuation of the properties acquired in the CPX Acquisition which is summarized as follows:

 

Purchase price of Acquired Properties  $20,680,032 
      
Allocation of Purchase Price     
Proved Oil and Gas Properties  $20,517,903 
Unproved Oil and gas Properties   195,780 
Total fair value of oil and gas properties   20,713,683 
Asset retirement obligations (1)   (33,651)
Fair value of net assets acquired  $20,680,032 

 

(1)  The estimated fair value of the acquired asset retirement obligation was determined using the Company’s credit adjusted risk-free rate.

 

The following unaudited pro forma combined results of operations for the years ended December 31, 2014 and 2013 are presented as though the CPX Acquisition had been completed as of January 1, 2013. The pro forma combined results of operations for the years ended December 31, 2014 and 2013 have been prepared by adjusting the historical results of the Company to include the historical results of the properties acquired in the CPX Acquisition. The supplemental pro forma results of operations are provided for illustrative purposes only and not purport to be indicative of the actual results that would have been achieved by the combined company for the periods presented. The pro forma results of operations do not include any cost savings or other synergies that resulted from the CPX Acquisition or any estimated costs incurred to integrate the CPX Acquisition assets.

 

   Year Ended 
   December 31, 
   2013 
   (Unaudited) 
Boe Produced   160,432 
      
Revenues  $13,511,159 
Net operating income  $2,704,323 
Net income (loss)  $(45,154)
Income (loss) per common share     
Basic  $(0.00)
Diluted  $(0.00)

 

 

F-11
 

BLACK RIDGE OIL & GAS, INC.

NOTES TO FINANCIAL STATEMENTS

 

Note 4 – Related Party

 

During the years ended December 31, 2014 and 2013, we granted various awards to our Officers and Directors as compensation for their services. These related party grants are fully disclosed in Note 12 below.

 

Other Related Party Transactions

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. The 2012 lease was amended effective November 15, 2013 to occupy approximately 2,813 square feet of office space. In accordance with this lease, our lease term is on a month-to-month basis, provided that either party may provide 90 day notice to terminate the lease, with base rents of $2,110 per month, plus common area operations and maintenance charges, and monthly parking fees of $240 per month, for the period from November 15, 2013 to October 31, 2014 and subject to increases of $117 per month beginning November 1, 2014 and for each of the subsequent three year periods. We have paid a total of $69,300 and $34,350 to this entity during the years ended December 31, 2014 and 2013, respectively.

 

 

Note 5 – Property and Equipment

 

Property and equipment December 31, 2014 and 2013, consisted of the following:

 

   December 31, 
   2014   2013 
Oil and gas properties, full cost method:          
Evaluated costs  $112,418,105   $79,361,432 
Unevaluated costs, not subject to amortization or ceiling test   591,121    2,798,795 
    113,009,226    82,160,227 
Other property and equipment   139,004    115,482 
    113,148,230    82,275,709 
Less: Accumulated depreciation, amortization, depletion and impairments   (18,902,524)   (9,513,434)
Total property and equipment, net  $94,245,706   $72,762,275 

 

The following table shows depreciation, depletion, and amortization expense by type of asset:

 

   Years Ended 
   December 31, 
   2014   2013 
Depletion of costs for evaluated oil and gas properties  $9,359,952   $3,705,156 
Depreciation and amortization of other property and equipment   29,138    24,001 
Total depreciation, amortization and depletion  $9,389,090   $3,729,157 

 

 

F-12
 

BLACK RIDGE OIL & GAS, INC.

NOTES TO FINANCIAL STATEMENTS

 

Note 6 – Oil and Gas Properties

 

The following tables summarize gross and net productive oil wells by state at December 31, 2014 and 2013. 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.

 

   December 31, 2014   December 31, 2013 
   Gross   Net   Gross   Net 
North Dakota   242    7.51    152    4.79 
Montana   5    0.37    1    0.08 
    247    7.88    153    4.87 

 

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, 2014 and 2013, our principal oil and gas assets included approximately 10,000 and 14,300 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, 2014 and 2013:

 

   Years Ended December 31, 
   2014   2013 
Purchases of oil and gas properties and development costs for cash  $24,739,407   $32,025,724 
Purchase of oil and gas properties accrued at year-end   9,364,796    7,953,801 
Purchase of oil and gas properties accrued at the beginning of the year   (7,953,801)   (2,618,145)
Advances to operators applied to development of oil and gas properties   6,036,748    2,218,237 
Capitalized asset retirement obligations   103,778    84,501 
Total purchase and development costs, oil and gas properties  $32,290,928   $39,664,118 

 

2014 Acquisitions

During 2014, the Company purchased approximately 374 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 $3,102,568.

 

2014 Divestitures

During 2014, the Company sold approximately 502 net mineral acres of oil and gas properties and rights to individual well bores in North Dakota for total proceeds of $1,441,929. No gain or loss was recorded pursuant to the sales.

 

2013 Acquisitions

During 2013, including the CPX acquisition, the Company purchased approximately 3,571 net mineral acres of oil and gas properties in North Dakota and Montana. Additionally, in conjunction with the purchase of the net mineral acres we acquired 45 gross producing wells (1.23 net wells). In consideration for the assignment of these mineral leases and producing wells, we paid the sellers a total of approximately $24,693,145.

 

2013 Divestitures

During 2013, the Company sold approximately 189 net mineral acres of oil and gas properties in North Dakota for total proceeds of $608,387. No gain or loss was recorded pursuant to the sales.

 

2013 Acreage Swap

In 2013, we traded 950 acres to an operator in exchange for 160 acres in a different geographic location and a drilling carry for the well costs for our interests in 2 gross (0.12 net) wells valued at $1,200,000.

 

F-13
 

BLACK RIDGE OIL & GAS, INC.

NOTES TO FINANCIAL STATEMENTS

 

Undeveloped Acreage Expirations

During 2014 and 2013, we had leases encompassing 4,202 and 543 net acres, respectively, expire with carrying costs of $6,198,163 and $833,884, respectively that have been transferred to the full cost pool subject to depletion. We estimate that approximately 1,100 net acres with carrying costs of approximately $1,900,000 will expire prior to the commencement of production activities during 2015. The carrying costs of these leases, including those which we estimate will expire in 2015 have also been transferred to the full cost pool and are subject to depletion.

 

 

Note 7 – 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, 2014 and 2013:

 

   Years ended December 31, 
   2014   2013 
Beginning asset retirement obligation  $160,665   $67,145 
Revision in estimate of asset retirement obligation       (19,848)
Liabilities incurred for new wells placed in production   103,778    70,698 
Liabilities assumed in acquisition       33,651 
Accretion of discount on asset retirement obligations   22,361    9,019 
Ending asset retirement obligation  $286,804   $160,665 

 

 

Note 8 – Derivative Instruments

 

The Company is required to recognize all derivative instruments on the balance sheet as either assets or liabilities measured at fair value. The Company has not designated its derivative instruments as hedges for accounting purposes and, as such, marks its derivative instruments to fair value and recognizes the realized and unrealized changes in fair value in its statements of operations under the captions “Loss on Settled Derivatives” and “Losses on the mark-to-market of derivatives.”

 

The Company has utilized swap and collar derivative contracts to hedge against the variability in cash flows associated with the forecasted sale of crude oil production. While the use of these derivative instruments limits the downside risk of adverse price movements, their use also limits the upside revenue potential of upward price movements.

 

For a fixed price swap contract, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is less than the swap price and the Company is required to make a payment to the counterparty if the settlement price for any period is greater than the swap price. For a collar contract, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is below the floor price, the Company is required to make a payment to the counterparty if the settlement price for any settlement period is above the ceiling price and no payment is required by either party if the settlement price for any settlement period is between the floor price and the ceiling price.

 

The Company’s derivative contracts are settled based on reported settlement prices on commodity exchanges, with crude oil derivative settlements based on NYMEX West Texas Intermediate (“WTI”) pricing.

 

F-14
 

BLACK RIDGE OIL & GAS, INC.

NOTES TO FINANCIAL STATEMENTS

 

As of December 31, 2014, the Company had outstanding derivative contracts with respect to future production as follows:

 

Crude Oil Swaps        
   Oil   Fixed 
Settlement Period  (Barrels)   Price 
January 1, 2015 – December 31, 2015   24,000   $88.28 
January 1, 2015 – December 31, 2015   21,000   $89.70 
January 1, 2015 – December 31, 2015   12,000   $92.38 
January 1, 2015 – December 31, 2015   30,000   $90.16 
January 1, 2016 – December 31, 2016   60,000   $90.36 
January 1, 2016 – December 31, 2016   24,000   $88.15 
January 1, 2017 – December 31, 2017   78,000   $87.18 

 

Crude Oil Costless Collars        
   Oil   Floor/Ceiling     
Settlement Period  (Barrels)   Price   Basis 
January 1, 2015 – December 31, 2015   36,000    $75.00/$95.60    NYMEX 
January 1, 2016 – June 30, 2016   10,002    $80.00/$89.50    NYMEX 

 

As of December 31, 2014, the Company had total volume on open commodity swaps of 249,000 barrels at a weighted average price of approximately $88.97.

 

Derivative Gains and Losses

The following table presents realized and unrealized gains and losses on derivative instruments for the periods presented:

 

   Years Ended 
   December 31, 
   2014   2013 
Realized gain on derivatives:          
Crude oil fixed price swaps  $511,451   $53,482 
Crude oil collars        
Realized gain on derivatives, net  $511,451   $53,482 
           
Gain (loss) on the mark-to-market of derivatives:          
Crude oil fixed price swaps  $6,827,126   $(134,293)
Crude oil collars   966,295    (79,383)
Gain (loss) on the mark-to-market of derivatives, net  $7,793,421   $(213,676)

 

F-15
 

BLACK RIDGE OIL & GAS, INC.

NOTES TO FINANCIAL STATEMENTS

 

Balance Sheet Offsetting of Derivative Assets and Liabilities

ASU No 2011-11, Balance Sheet (Topic 210)-Disclosures about Offsetting Assets and Liabilities, requires an entity to disclose information about offsetting arrangements to enable financial statement users to understand the effects of netting arrangements on an entity’s financial position. The Company adopted the provision of the standard upon entering into our first derivative contract and has provided the applicable disclosures below with respect to its derivative instruments.

 

All of the Company’s derivative contracts are carried at their fair value in the condensed balance sheets under the captions “Current portion of derivative instruments” and “Derivative instruments”. Derivative instruments from the same counterparty that are subject to contractual terms which provide for net settlement are reported on a net basis in the condensed balance sheets. The following tables present the gross amounts of recognized derivative assets and liabilities, the amounts offset under the netting arrangements with counterparties, and the resulting net amounts presented in the condensed balance sheets for the periods presented, all at fair value.

 

   December 31, 2014   December 31, 2013 
       Gross   Net       Gross   Net 
   Gross   amounts   amounts of   Gross   amounts   amounts of 
   amounts of   offset   assets   amounts of   offset   assets 
   recognized   on balance   on balance   recognized   on balance   on balance 
   assets   sheet   sheet   assets   sheet   sheet 
Commodity derivative assets  $7,620,896   $(41,151)  $7,579,745   $   $   $ 

 

   December 31, 2014   December 31, 2013 
       Gross   Net       Gross   Net 
   Gross   amounts   amounts of   Gross   amounts   amounts of 
   amounts of   offset   liabilities   amounts of   offset   liabilities 
   recognized   on balance   on balance   recognized   on balance   on balance 
   liabilities   sheet   sheet   liabilities   sheet   sheet 
Commodity derivative liabilities  $   $   $   $(396,573)  $182,897   $(213,676)

 

 

The following table reconciles the net amounts disclosed above to the individual financial statement line items in the condensed balance sheets:

 

   December 31, 
   2014   2013 
Derivative assets  $3,571,803   $ 
Noncurrent derivative assets   4,007,942     
Net amount of assets on the balance sheet   7,579,745     
           
Derivative liabilities       (139,065)
Noncurrent derivative liabilities       (74,611)
Net amounts of liabilities on the balance sheet       (213,676)
Total derivative liabilities, net  $7,579,745   $(213,676)

  

F-16
 

BLACK RIDGE OIL & GAS, INC.

NOTES TO FINANCIAL STATEMENTS

 

Note 9 – 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.

 

 

 

 

 

F-17
 

BLACK RIDGE OIL & GAS, INC.

NOTES TO FINANCIAL STATEMENTS

 

The following schedule summarizes the valuation of financial instruments at fair value on a recurring basis in the balances sheet as of December 31, 2014 and 2013:

 

   Fair Value Measurements at December 31, 2014 
   Level 1   Level 2   Level 3 
Assets               
Cash and cash equivalents  $94,682   $   $ 
Derivative Instruments (crude oil swaps and collars)       7,579,745     
Total assets   94,682    7,579,745     
Liabilities               
Revolving credit facilities and long term debt, net of discounts       51,834,603     
Total Liabilities       51,834,603     
   $94,682   $(44,254,858)  $ 

 

   Fair Value Measurements at December 31, 2013 
   Level 1   Level 2   Level 3 
Assets               
Cash and cash equivalents  $1,150,347   $   $ 
Total assets   1,150,347         
Liabilities               
Derivative Instruments (crude oil swaps and collars)       213,676     
Revolving credit facilities and long term debt, net of discounts       30,556,301     
Total Liabilities       30,769,977     
   $1,150,347   $(30,769,977)  $ 

 

There were no transfers of financial assets or liabilities between Level 1 and Level 2 inputs for the years ended December 31, 2014 and 2013.

 

Level 2 liabilities include revolving credit facilities. No fair value adjustment was necessary during the years ended December 31, 2014 and 2013.

 

 

Note 10 – Revolving Credit Facilities and Long Term Debt

 

Senior Credit Facility

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

 

Availability under the Senior Credit Facility is at all times subject to the then-applicable borrowing base, determined by Cadence in a manner consistent with the normal and customary oil and gas lending practices of Cadence. Availability was initially set at $7 million and is subject to periodic redeterminations. The availability was $35 million as of December 31, 2014, and subsequently amended to $34 million on March 30, 2015. Subject to availability under the borrowing base, the Company may borrow, repay and re-borrow funds in amounts of $250,000 or more. At the Company’s election, the unpaid principal balance of any borrowings under the Senior Credit Facility may bear interest at either (i) the Base Rate, as defined in the Senior Credit Facility, plus the applicable margin, which varies from 1.00% to 1.50% or (ii) the LIBOR rate, as defined in the Senior Credit Facility, plus the applicable margin, which varies from 3.00% to 3.50%. Interest is payable for Base Rate loans on the last business day of the month and for LIBOR loans on the last LIBOR business day of each LIBOR interest period. The Company is also required to pay a quarterly fee of 0.50% on any unused portion of the borrowing base, as well as a facility fee of 0.90% of the initial and any subsequent additions to the borrowing base.

 

F-18
 

BLACK RIDGE OIL & GAS, INC.

NOTES TO FINANCIAL STATEMENTS

 

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

 

The Company had borrowings of $22.6 million and 13 million outstanding under the Senior Credit Agreement as of December 31, 2014 and 2013, respectively.

 

Subordinated Credit Facility

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

 

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

 

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

 

The first funding from the Subordinated Credit Facility occurred on September 9, 2013 at which time we drew $14,700,000, net of a $300,000 original issue discount, from the Subordinated Credit Agreement and used $10,226,057 of those proceeds to repay and terminate the Dougherty revolving credit facility. We have drawn an additional $14,700,000, net of $300,000 original issue discounts, through December 31, 2014. The Company had borrowings of $30 million and $20 million outstanding under the Subordinated Credit Facility as of December 31, 2014 and 2013, respectively.

 

F-19
 

BLACK RIDGE OIL & GAS, INC.

NOTES TO FINANCIAL STATEMENTS

 

Intercreditor Agreements and Covenants

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

 

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

 

Debt Discount, Detachable Warrants

In connection with the Subordinated Credit Facility, the Company agreed to issue to the lenders detachable warrants to purchase up to 5,000,000 shares of the Company’s common stock at an exercise price of $0.65 per share. The warrants expire on August 8, 2018. Proceeds from the loan were allocated between the debt and equity based on the relative fair values at the time of issuance, resulting in a debt discount of $2,473,576 at issuance that is presented as a debt discount on the balance sheet and is being amortized using the effective interest method over the life of the credit facility, which matures on June 30, 2017. A total of $628,195 and $199,632 was amortized during the years ended December 31, 2014 and 2013. The remaining unamortized balance of the debt discount attributable to the warrants is $1,645,749 as of December 31, 2014.

 

Dougherty Revolving Credit Facility (former credit facility)

On April 4, 2012, the Company entered into a Secured Revolving Credit Agreement with Dougherty Funding, LLC (“Dougherty”) 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 “Dougherty Credit Facility”).

 

The Dougherty Credit Facility provided for a maximum available amount of $20 million, of which $16.5 million was available prior to termination of the facility, with interest payable on the outstanding balance at a rate of 9.25% per year and a maturity date of August 1, 2015. In connection with the amended financing, the Company issued Dougherty Funding LLC warrants to purchase 585,000 shares of the Company’s common stock at an exercise price of $0.38 per share. The warrants expire on August 31, 2015.

 

On September 9, 2013, we repaid the Dougherty Credit Facility with proceeds from the Subordinated Credit Facility.

 

F-20
 

BLACK RIDGE OIL & GAS, INC.

NOTES TO FINANCIAL STATEMENTS

 

 

Amounts outstanding under revolving credit facilities and long term debts consisted of the following as of December 31, 2014 and 2013, respectively:

 

   December 31, 
   2014   2013 
Senior Revolving Credit Facility, Cadence Bank, N.A.  $22,600,000   $13,000,000 
Subordinated Credit Agreement, Chambers   30,000,000    20,000,000 
PIK Interest on Subordinated Credit Agreement, Chambers   1,307,086    201,883 
           
Total credit facilities and long term debts   53,907,086    33,201,883 
Less: Unamortized OID   (426,734)   (371,638)
Less: Unamortized debt discount attributable to warrants   (1,645,749)   (2,273,944)
Total credit facilities and long term debts, net of discounts   51,834,603    30,556,301 
Less: current maturities        
           
Long term portion of credit facilities and long term debts  $51,834,603   $30,556,301 

 

Net proceeds of $29.4 million were received from our $30 million in advances due to $600,000 of OID pursuant to the Subordinated Credit Agreement at issuance that is presented as a debt discount on the balance sheet and is being amortized using the effective interest method over the life of the credit facility, which matures on June 30, 2017. A total of $144,904 and $28,362 was amortized during the years ended December 31, 2014 and 2013, respectively. The remaining unamortized balance of the debt discount attributable to the OID is $426,734 as of December 31, 2014.

 

The following presents components of interest expense for the years ended December 31, 2014 and 2013, respectively:

 

   Years Ended December 31, 
   2014   2013 
Credit Facilities, accrued PIK interest  $1,105,203   $201,883 
Credit Facilities, amortization of OID   144,904    28,362 
Credit Facilities, interest and commitment fees   3,453,349    1,092,372 
Credit Facilities, amortization of debt issuance costs   326,258    749,920 
Credit Facilities, amortization of warrant costs   628,195    307,822 
Capitalized interest   (372,673)    
   $5,285,236   $2,380,359 

 

 

Note 11 – Stockholders’ Equity

 

Preferred Stock

The Company has 20,000,000 authorized shares of $0.001 par value preferred stock. No shares have been issued to date.

 

Common Stock

The Company has 500,000,000 authorized shares of $0.001 par value common stock.

 

F-21
 

BLACK RIDGE OIL & GAS, INC.

NOTES TO FINANCIAL STATEMENTS

 

Note 12 – Options

 

The following table presents all options granted during the year ended December 31, 2014:

 

      Number       Term  Vesting  Black-Scholes Options   Total   Expense   Expense 
Grant     of   Strike   in  Term in  Pricing Model:   Fair   Recognized   Recognized 
Date  Recipient  Options   Price   Years(1)  Years(1)  Volatility  Call Value  Value   in 2014   in 2013 
12/22/14  Kenneth DeCubellis, CEO   58,000   $0.280   10  5  198%  $0.2237  $12,974   $64   $ 
12/22/14  James Moe, CFO   40,000   $0.280   10  5  198%  $0.2237   8,947    44     
12/22/14  Michael Eisele, COO   40,000   $0.280   10  5  198%  $0.2237   8,947    44     
12/22/14  Employee   36,000   $0.280   10  5  198%  $0.2237   8,053    40     
12/22/14  Employee   12,000   $0.280   10  5  198%  $0.2237   2,684    13     
12/22/14  Employee   12,000   $0.280   10  5  198%  $0.2237   2,684    13     
12/22/14  Employee   2,000   $0.280   10  5  198%  $0.2237   447    2     
12/8/14  Joseph Lahti, Director   100,000   $0.374   10  5  202%  $0.2956   29,563    372     
12/8/14  Benjamin Oehler, Director   100,000   $0.374   10  5  202%  $0.2956   29,563    372     
12/8/14  Bradley Berman, Director   100,000   $0.374   10  5  202%  $0.2956   29,563    372     
12/1/14  Employee   100,000   $0.379   10  5  193%  $0.2999   29,988    500     
02/10/14  Employee   27,500   $0.782   10  5  116%  $0.6778   18,639    1,976     
01/30/14  Employee   5,000   $0.630   10  5  115%  $0.5471   2,735    499     
       632,500                     $184,787   $4,311   $ 

 

 

 

 

 

 

F-22
 

BLACK RIDGE OIL & GAS, INC.

NOTES TO FINANCIAL STATEMENTS

 

The following table presents all options granted during the year ended December 31, 2013:

 

      Number       Term  Vesting  Black-Scholes Options   Total   Expense   Expense 
Grant     of   Strike   in  Term in  Pricing Model:   Fair   Recognized   Recognized 
Date  Recipient  Options   Price   Years(1)  Years(1)  Volatility  Call Value  Value   in 2014   in 2013 
12/12/13  Kenneth DeCubellis, CEO   750,000   $0.65   10  5  117%  $0.5675  $425,595   $85,120   $4,431 
12/12/13  James Moe, CFO   200,000   $0.65   10  5  117%  $0.5675   113,492    22,700    1,182 
12/12/13  Michael Eisele, COO   250,000   $0.65   10  5  117%  $0.5675   141,865    28,372    1,477 
12/12/13  Employee   175,000   $0.65   10  5  117%  $0.5675   99,306    19,860    1,034 
12/12/13  Employee   25,000   $0.65   10  5  117%  $0.5675   14,187    2,836    148 
12/12/13  Employee   10,000   $0.65   10  5  117%  $0.5675   5,675    1,136    59 
12/12/13  Joseph Lahti, Director   100,000   $0.65   10  5  117%  $0.5675   56,746    11,348    591 
12/12/13  Benjamin Oehler, Director   100,000   $0.65   10  5  117%  $0.5675   56,746    11,348    591 
12/12/13  Bradley Berman, Director   100,000   $0.65   10  5  117%  $0.5675   56,746    11,348    591 
10/30/13  Employee   20,000   $0.63   10  5  114%  $0.5443   10,886    2,176    370 
08/01/13  Michael Eisele, COO(2)   165,000   $0.64   10  5  114%  $0.5520   91,087    18,216    7,590 
01/24/13  Employee   12,500   $0.56   10  5  110%  $  0.4725   5,907    1,180    1,099 
01/24/13  Employee   70,000   $0.56   10  5  110%  $  0.4725   33,077    6,616    6,158 
01/24/13  Michael Eisele, COO   165,000   $0.56   10  5  110%  $  0.4725   77,968    15,592    14,514 
01/24/13  James Moe, CFO   115,000   $0.56   10  5  110%  $ 0.4725   54,341    10,868    10,116 
01/24/13  Kenneth DeCubellis, CEO   400,000   $0.56   10  5  110%  $0.4725   189,014    37,804    35,189 
       2,657,500                     $1,432,638   $286,520   $85,140 

 

(1)All options vest in equal annual installments, commencing one year from the date of the grant, are exercisable for 10 years from the date of the grant and are being amortized over the implied service term, or vesting period, of the options.
(2)Mr. Eisele was promoted to Chief Operating Officer effective August 1, 2013.

 

F-23
 

BLACK RIDGE OIL & GAS, INC.

NOTES TO FINANCIAL STATEMENTS

 

Options Cancelled

On August 22, 2014, 27,500 common stock options with a strike price of $0.782 were forfeited pursuant to the resignation of an employee.

 

On November 15, 2013, 166,667 common stock options were forfeited pursuant to the resignation of an officer.

 

No other options were cancelled during 2014 or 2013.

 

Options Expired

On November 30, 2014, a total of 12,000 options with a strike price of $0.92 per share expired.

 

On August 8, 2014, a total of 24,000 options with a strike price of $0.51 per share expired.

 

No options expired during the year ended December 31, 2013.

 

Options Exercised

No options were exercised during the year ended December 31, 2014 and 2013.

 

The following is a summary of information about the Stock Options outstanding at December 31, 2014.

 

            Shares Underlying
Shares Underlying Options Outstanding  Options Exercisable
      Weighted         
   Shares  Average  Weighted  Shares  Weighted
   Underlying  Remaining  Average  Underlying  Average
Range of  Options  Contractual  Exercise  Options  Exercise
Exercise Prices  Outstanding  Life  Price  Exercisable  Price
$0.03 - $1.00  7,208,834  7.77 years  $0.56  3,114,501  $0.65

 

The fair value of each option grant is estimated on the date of grant using the Black-Scholes option pricing model with the following weighted-average assumptions used for grants under the fixed option plan:

 

   December 31,   December 31, 
   2014   2013 
Average risk-free interest rates   2.00%    1.92% 
Average expected life (in years)   5    5 
Volatility   97%    114% 

 

The Black-Scholes option pricing model was developed for use in estimating the fair value of short-term traded options that have no vesting restrictions and are fully transferable. In addition, option valuation models require the input of highly subjective assumptions including expected stock price volatility. Because the Company’s employee stock options have characteristics significantly different from those of traded options and because changes in the subjective input assumptions can materially affect the fair value estimate, in management’s opinion the existing models do not necessarily provide a reliable single measure of the fair value of its employee stock options. During the years ended December 31, 2014 and 2013 there were no options granted with an exercise price below the fair value of the underlying stock at the grant date.

 

 

F-24
 

BLACK RIDGE OIL & GAS, INC.

NOTES TO FINANCIAL STATEMENTS

 

The following is a summary of activity of outstanding stock options:

 

       Weighted 
       Average 
   Number   Exercise 
   of Shares   Prices 
Balance, December 31, 2012   4,149,001   $0.58 
Options expired        
Options cancelled   (166,667)   (1.00)
Options granted   2,657,500    0.62 
Options exercised        
Balance, December 31, 2013   6,639,834    0.59 
Options expired   (36,000)   (0.65)
Options cancelled   (27,500)   (0.78)
Options granted   632,500    0.36 
Options exercised        
Balance, December 31, 2014   7,208,834    0.56 
           
Exercisable, December 31, 2014   3,114,501   $0.65 

 

The Company expensed $578,919 and $643,817 from the amortization of common stock options during the years ended December 31, 2014 and 2013, respectively.

 

 

Note 13 – Warrants

 

Warrants Granted

No warrants were granted during the year ended December 31, 2014.

 

On August 8, 2013, in connection with entering into the Subordinated Credit Facility, the Company agreed to issue to the lenders cashless warrants to purchase up to 5,000,000 shares of the Company’s common stock at an exercise price of $0.65 per share. The warrants expire on August 8, 2018. The estimated fair value using the Black-Scholes Pricing Model, based on a volatility rate of 114%, risk-free interest rate of 1.38% and a call option value of $0.4947 was $2,473,576 and is being amortized using the effective interest method over the life of the credit facility, which matures on June 30, 2017. Proceeds from the sale were allocated between the debt and equity based on the relative fair values at the time of issuance. The fair value of $2,473,576 is presented as a debt discount on the balance sheet and a total of $628,195 and $199,632 was amortized during the years ended December 31, 2014 and 2013, respectively. The remaining unamortized balance of those warrants is $1,645,749 as of December 31, 2014.

 

Warrants Cancelled

A total of 330,000 warrants with a strike price of $1.50 per share were voluntarily forfeited on December 30, 2014. No warrants were cancelled during the years ended December 31, 2013.

 

Warrants Expired

No warrants expired during the years ended December 31, 2014 and 2013.

 

Warrants Exercised

No warrants were exercised during the years ended December 31, 2014 and 2013.

 

F-25
 

BLACK RIDGE OIL & GAS, INC.

NOTES TO FINANCIAL STATEMENTS

 

The following is a summary of information about the Warrants outstanding at December 31, 2014:

 

            Shares Underlying
Shares Underlying Warrants Outstanding  Warrants Exercisable
      Weighted         
   Shares  Average  Weighted  Shares  Weighted
   Underlying  Remaining  Average  Underlying  Average
Range of  Warrants  Contractual  Exercise  Warrants  Exercise
Exercise Prices  Outstanding  Life  Price  Exercisable  Price
$0.38 - $1.50  9,133,375  2.61 years  $0.92  9,133,375  $0.92

 

The fair value of each warrant grant is estimated on the date of grant using the Black-Scholes option pricing model with the following weighted-average assumptions used for grants under the fixed option plan:

 

   December 31,
   2014  2013 
Average risk-free interest rates  N/A   1.38% 
Average expected life (in years)  N/A   5 
Volatility  N/A   114% 

 

The Black-Scholes option pricing model was developed for use in estimating the fair value of short-term traded options that have no vesting restrictions and are fully transferable. In addition, option valuation models require the input of highly subjective assumptions including expected stock price volatility. Because the Company’s warrants have characteristics significantly different from those of traded warrants and because changes in the subjective input assumptions can materially affect the fair value estimate, in management’s opinion the existing models do not necessarily provide a reliable single measure of the fair value of its warrants. During the years ended December 31, 2014 and 2013, there were no warrants granted with an exercise price below the fair value of the underlying stock at the grant date.

 

The following is a summary of activity of outstanding warrants:

 

       Weighted 
       Average 
   Number   Exercise 
   of Shares   Prices 
Balance, December 31, 2012   4,463,375   $1.26 
Warrants expired        
Warrants cancelled        
Warrants granted   5,000,000    0.65 
Warrants exercised        
Balance, December 31, 2013   9,463,375    0.94 
Warrants expired        
Warrants cancelled   (330,000)   (1.50)
Warrants granted        
Warrants exercised        
Balance, December 31, 2014   9,133,375    0.92 
           
Exercisable, December 31, 2014   9,133,375   $0.92 

 

F-26
 

BLACK RIDGE OIL & GAS, INC.

NOTES TO FINANCIAL STATEMENTS

 

Note 14 – Income Taxes

 

We account for income taxes under the provisions of ASC Topic 740, Income taxes, which provides for an asset and liability approach for income taxes. Under this approach, deferred tax assets and liabilities are recognized based on anticipated future tax consequences, using currently enacted tax laws, attributable to temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts calculated for income tax purposes.

 

Our provision for income taxes for the years ended December 31, 2014 and 2013 consisted of the following:

 

   December 31, 
   2014   2013 
Current taxes  $   $ 
Deferred tax provision (benefit)   2,559,195    (698,851)
Valuation allowance        
Net income tax provision (benefit)  $2,559,195   $(698,851)

 

The effective income tax rate for the years ended December 31, 2014 and 2013 consisted of the following:

 

   December 31, 
   2014   2013 
Federal statutory income tax rate   35.00%    35.00% 
State income taxes   2.09%    2.35% 
Effect of statutory rate change on deferred taxes   (0.35%)   34.49% 
Permanent differences   0.07%    (0.17%)
Change in valuation allowance   0.22%    (8.23%)
Net effective income tax rate   37.03%    63.44% 

 

The Company’s state income tax rate as of December 31, 2014 decreased by 0.26% from 2.35% as of December 31, 2013, to 2.09%. This decrease in the effective tax rate is attributable to changes in the Company’s state apportionment factors in the current year. In 2013, due to the legal settlement amounts and non-oil & gas revenue the Company received during previous years being sourced to the state of Minnesota for income tax purposes, a larger percentage of the Company’s activity was expected to be apportioned to that state. As compared to North Dakota, the other state the Company files tax returns in which has a corporate income tax rate of 4.53%, the state of Minnesota has a 9.80% corporate income tax rate. This change in apportionment resulted in a 34.49% increase in the effective tax rate for 2013 based on its effect on the carrying value of the net deferred tax liability.

 

F-27
 

BLACK RIDGE OIL & GAS, INC.

NOTES TO FINANCIAL STATEMENTS

 

The components of the deferred tax assets and liabilities as of December 31, 2014 and 2013 are as follows:

 

   December 31, 
   2014   2013 
Deferred tax assets:          
Federal and state net operating loss carryovers  $10,438,275   $7,465,973 
Stock compensation   1,558,409    1,118,426 
Derivative liabilities       79,806 
Reorganization costs   49,693    50,040 
Asset retirement obligation   106,377    60,007 
Total deferred tax assets  $12,152,754   $8,774,252 
           
Deferred tax liabilities:          
Ceiling test impairment, intangible drilling costs and other exploration costs capitalized for financial reporting purposes  $(15,344,769)  $(12,229,818)
Derivative assets   (2,811,366)    
Property and equipment   (10,107)   (13,764)
Total deferred liabilities   (18,166,242)   (12,243,582)
           
Net deferred tax liabilities   (6,013,488)   (3,469,330)
Less: valuation allowance   (579,552)   (564,515)
Deferred tax liabilities  $(6,593,040)  $(4,033,845)

 

As of December 31, 2014, the Company has net operating loss carryover of approximately $28,142,712. Under existing Federal law, the net operating loss may be utilized to offset taxable income through the year ended December 31, 2032. A portion of the net operating loss carryover begins to expire in 2030.

 

ASC Topic 740 provides that a valuation allowance is recognized if, based on the weight of available evidence, it is more likely than not that some portion or all of the deferred tax asset will not be realized. The Company had recognized a valuation allowance reducing the carrying value of its deferred tax asset by $564,515 as of December 31, 2013. As of December 31, 2014 the Company has increased its valuation allowance by $15,037 to $579,552. This increase was to more accurately reflect an allowance on only a portion of its deferred tax assets which the Company believes it is more likely than not that the benefit of these assets will not be realized.

 

The Company files annual US Federal income tax returns and annual income tax returns for the states of Minnesota, North Dakota and Montana. We are not subject to income tax examinations by tax authorities for years before 2010 for all returns. Income taxing authorities have conducted no formal examinations of our past federal or state income tax returns and supporting records.

 

The Company adopted the provisions of ASC Topic 740 regarding uncertainty in income taxes. The Company has found no significant uncertain tax positions as of any date on or before December 31, 2014.

 

 

F-28
 

BLACK RIDGE OIL & GAS, INC.

NOTES TO FINANCIAL STATEMENTS

 

Note 15 – Commitments and Contingencies

 

The Company is involved in various inquiries, administrative proceedings and litigation relating to matters arising in the normal course of business. The Company is not currently a defendant in any material litigation and is not aware of any threatened litigation that could have a material effect on the Company. Management is not able to estimate the minimum loss to be incurred, if any, as a result of the final outcome of the matters arising in the normal course of business but believes they are not likely to have a material adverse effect upon the Company’s financial position or results of operations and, accordingly, no provision for loss has been recorded.

 

The Company periodically maintains cash balances at banks in excess of federally insured amounts. The extent of loss, if any, to be sustained as a result of any future failure of a bank or other financial institution is not subject to estimation at this time.

 

The Company commits to its participation in upcoming well development by signing an Authorization for Expenditure (“AFE”). As of December 31, 2014 the Company had committed to AFE’s of approximately $16.5 million beyond amounts previously paid or accrued. Additionally, 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. Our proportion of the well costs, based on the AFE and our working interest, is approximately $800,000. The well started production on May 21, 2012. Had we recognized the revenue and expenses from this well we would have recorded approximately an additional $230,000, $451,000 and $468,000 in oil and gas sales for the years ended December 31, 2014, 2013 and 2012, respectively, and $63,000, $110,000 and $124,000 of production taxes and operating expenses for the years ended December 31, 2014, 2013 and 2012, respectively. 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.

 

 

Note 16 – Subsequent Events

 

Debt Financing

From January 1, 2015 through March 26, 2015, the Company received cumulative advances, net of repayments, of $3.35 million pursuant to the Credit Facility with Cadence.

 

On March 30, 2015, we amended the Credit Facility with Cadence Bank, N.A. to extend the termination date of the Loan Commitment from August 8, 2016 to January 15, 2017, decrease the borrowing base from $35 million to $34 million and to waive the Net Debt to EBITDAX Ratio and the Collateral Coverage Ratio covenants for the quarter ending March 31, 2015. In addition, the Amendment, for purposes of determining compliance with financial covenants, changes the Maximum Net Debt to EBITDAX Ratio and the Minimum Collateral Coverage Ratio. Whereas the Senior Credit Facility initially provided for a Maximum Net Debt to EBITDAX Ratio of 3.50 to 1.00 as of the end of each quarter commencing with the quarter ending March 31, 2015, the Amendment revises the Maximum Net Debt to EBITDAX to 3.65 to 1.00 for the quarter ending December 31, 2015, and 3.50 to 1.00 for the quarter ending March 31, 2016 and thereafter. In addition, whereas the Senior Credit Facility initially provided for a Minimum Collateral Coverage Ratio of 0.80 to 1.00 as of the end of each quarter commencing with the quarter ending March 31, 2015, the Amendment revises the Minimum Collateral Coverage Ratio to 0.80 to 1.00 for the quarter ending June 30, 2015, and 0.70 to 1.00 for the quarter ending September 30, 2015, and 0.80 to 1.00 for the quarter ending December 31, 2015 and thereafter.

 

Our Subordinated Credit Facility was also amended on March 30, 2015, to waive the Net Leverage Ratio and the Collateral Coverage Ratio covenants for the quarter ending March 31, 2015. In addition, the Amendment, for purposes of determining compliance with financial covenants, changes the Maximum Net Leverage Ratio and the Minimum Collateral Coverage Ratio. Whereas the Subordinated Credit Facility initially provided for a Maximum Net Leverage Ratio of 3.50 to 1.00 as of the end of each quarter commencing with the quarter ending March 31, 2015, the Amendment revises the Maximum Net Leverage Ratio to 3.65 to 1.00 for the quarter ending December 31, 2015, and 3.50 to 1.00 for the quarter ending March 31, 2016 and thereafter. In addition, whereas the Subordinated Credit Facility initially provided for a Minimum Collateral Coverage Ratio of 0.80 to 1.00 as of the end of each quarter commencing with the quarter ending March 31, 2015, the Amendment revises the Minimum Collateral Coverage Ratio to 0.80 to 1.00 for the quarter ending June 30, 2015, and 0.70 to 1.00 for the quarter ending September 30, 2015, and 0.80 to 1.00 for the quarter ending December 31, 2015 and thereafter.

 

Oil and Gas Property Purchases

On March 10, 2015, the Company purchased 9.3571 net leasehold acres in oil and gas properties in North Dakota for approximately $102,928.

 

Oil and Gas Property Sales

On March 16, 2015, the Company sold 9 net leasehold acres of oil and gas properties in North Dakota for proceeds of $99,000.

 

F-29
 

SUPPLEMENTAL OIL AND GAS INFORMATION

(UNAUDITED)

 

Oil and Natural Gas Exploration and Production Activities

 

Oil and gas sales reflect the market prices of net production sold or transferred with appropriate adjustments for royalties, net profits interest, and other contractual provisions. Production expenses include lifting costs incurred to operate and maintain productive wells and related equipment including such costs as operating labor, repairs and maintenance, materials, supplies and fuel consumed. Production taxes include production and severance taxes. Depletion of oil and natural gas properties relates to capitalized costs incurred in acquisition, exploration, and development activities. Results of operations do not include interest expense and general corporate amounts. The results of operations for the Company's oil and natural gas production activities are provided in the Company's related statements of operations.

 

Costs Incurred and Capitalized Costs

 

Net capitalized costs related to the Company’s oil and gas producing activities were as follows:

 

   December 31, 
   2014   2013 
Proved oil and gas properties  $112,418,105   $79,361,432 
Unproved oil and gas properties   591,121    2,798,795 
Accumulated depreciation, depletion and amortization, and impairment   (18,820,963)   (9,461,011)
Total  $94,188,263   $72,699,216 

 

The Company incurred the following costs for oil and natural gas acquisition, exploration and development activities during the years ended December 31, 2014 and 2013:

 

   Years Ended 
   December 31, 
   2014   2013 
Costs incurred for the year:          
Proved property acquisition  $3,164,469   $24,177,260 
Unproved property acquisition       653,394 
Development   29,022,721    14,748,963 
Total  $32,187,150   $39,579,617 

 

Excluded costs for unproved properties are accumulated by year. Costs are reflected in the full cost pool as the drilling costs are incurred or as costs are evaluated and deemed impaired. The Company anticipates these excluded costs will be included in the depletion computation over the next five years. The Company is unable to predict the future impact on depletion rates. The following is a summary of capitalized costs excluded from depletion:

 

   Years Ended 
   December 31, 
   2014   2013 
Property acquisition  $591,121   $2,498,452 
Development       300,343 
Total  $591,121   $2,798,795 

 

F-30
 

SUPPLEMENTAL OIL AND GAS INFORMATION

(UNAUDITED)

 

Oil and Natural Gas Reserves and Related Financial Data

 

Information with respect to the Company's crude oil and natural gas producing activities is presented in the following tables. Reserve quantities, as well as certain information regarding future production and discounted cash flows, were determined by Netherland, Sewell & Associates, Inc., independent petroleum consultants based on information provided by the Company.

 

Oil and Natural Gas Reserve Data

 

The following tables present the Company's independent petroleum consultants' estimates of its proved oil and natural gas reserves. The Company emphasizes that reserves are approximations and are expected to change as additional information becomes available. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be measured in an exact way and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment.

 

   Oil   Natural 
   (Bbls)   Gas (Mcf) 
Proved developed and undeveloped reserves as of December 31, 2012   2,116,133    1,604,688 
Revisions of previous estimates   (287,354)   (246,121)
Extensions, discoveries and other additions   2,800,070    1,811,443 
Sale of reserves in place   (454,378)   (338,444)
Production   (99,979)   (52,973)
Proved developed and undeveloped reserves as of December 31, 2013   4,074,492    2,778,593 
Revisions of previous estimates   (201,995)   (131,966)
Extensions, discoveries and other additions   1,199,673    925,763 
Sale of reserves in place   (17,982)   (12,482)
Production   (256,257)   (213,141)
Proved developed and undeveloped reserves as of December 31, 2014   4,797,931    3,346,767 
           
Proved developed reserves:          
December 31, 2013   927,272    652,793 
December 31, 2014   1,799,515    1,363,076 
           
Proved undeveloped reserves:          
December 31, 2013   3,147,220    2,125,800 
December 31, 2014   2,998,416    1,983,691 

 

Proved reserves are estimated quantities of oil and natural gas, which geological and engineering data indicate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are included for reserves for which there is a high degree of confidence in their recoverability and they are scheduled to be drilled within the next five years.

 

The Company recognized significant additions in net quantities of its proved reserves relating to acquisitions, extensions, discoveries and other additions during the years ended December 31, 2014 and December 31, 2013. The Company’s increase in proved reserves during both of the years presented was primarily due to acquisitions, extensions, discoveries, and other additions related to drilling activity in and adjacent to our Bakken/Three Forks acreage. During that period, the Company’s net producing well count increased from 2.30 net wells at December 31, 2012 to 7.88 net wells at December 31, 2014. This rapid growth caused the Company’s proved reserves to grow significantly. As a percentage of total acquisitions, extensions, discoveries and other additions to proved reserves for the years ended December 31, 2014 and 2013, 48% and 83%, respectively, were to the Company’s proved undeveloped reserves.

 

F-31
 

SUPPLEMENTAL OIL AND GAS INFORMATION

(UNAUDITED)

 

 

The Company sold or swapped undeveloped acreage in 2013 that accounted for 510,785 BOE. This acreage was sold to diversify risk or because the proposed development of this acreage did not meet our return criteria.

 

During 2013, we had a negative revision of 328,374 BOE, or 14%, of our December 31, 2012 estimated proved reserves balance. The primary cause for these revisions was negative well performances. In 2013, within portions of our areas of operation, actual well results underperformed relative to the forecasts in our December 31, 2012 reserve report. The proved undeveloped forecasts in these areas were also adjusted to reflect these well performances in our December 31, 2013 reserve report. The majority of the negative revision in 2014 was due to proved undeveloped wells becoming uneconomic due to reductions in the price of oil.

 

Standardized Measure of Discounted Future Net Cash Inflows and Changes Therein

 

The following table presents a standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves and the changes in standardized measure of discounted future net cash flows relating to proved oil and natural gas were prepared in accordance with the provisions of ASC 932-235-50-5. Future cash inflows were computed by applying average prices of oil and natural gas for the first day of the last twelve months as of December 31, 2014 to estimated future production. Future production and development costs were computed by estimating the expenditures to be incurred in developing and producing the proved oil and natural gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. Future income tax expenses were calculated by applying appropriate year-end tax rates to future pretax cash flows relating to proved oil and natural gas reserves, less the tax basis of properties involved and tax credits and loss carryforwards relating to oil and natural gas producing activities. Future net cash flows are discounted at the rate of 10% annually to derive the standardized measure of discounted future cash flows. Actual future cash inflows may vary considerably, and the standardized measure does not necessarily represent the fair value of the Company's oil and natural gas reserves. The following is a summary of the Company’s standardized measure of discounted future cash flows for the years as indicated:

 

   Years Ended December 31, 
   2014   2013 
Future cash inflows  $423,219,613   $385,294,210