| |
UNITED
STATES
SECURITIES AND
EXCHANGE COMMISSION
WASHINGTON,
D.C. 20549
FORM
10-K/A
(Amendment No. 2)
| [X] | Annual Report under Section 13 or 15(d) of the Securities Exchange Act of 1934 for the fiscal year ended December 31, 2013. | |
| [ ] | Transition Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the transition period from _____ to _____. |
Commission File Number: 000-53632
BAKKEN RESOURCES, INC.
(Exact name
of small business issuer as specified in its
charter)
| Nevada | 26-2973652 |
| (State or other jurisdiction of | (I.R.S. employer |
| incorporation or organization) | identification number) |
825 Great Northern
Boulevard
Expedition Block, Suite 304
Helena, Montana
59601
(Address of principal executive offices and zip code)
(406)
442-9444
(Registrant’s telephone
number, including area code)
Securities
registered pursuant to Section
12(b) of the Act:
None
Securities
registered pursuant to Section
12(g) of the Act:
Common Stock, $.001 par value
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. YES [ ] NO [X]
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Exchange Act. YES [ ] NO [X]
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the past 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 [X]
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Indicate by check mark if the disclosure of delinquent filers in response to Item 405 of Regulation S-K is not contained in this herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X]
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definition of “accelerated filer,” “larger accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
| Large accelerated filer [ ] | Accelerated filer [ ] | Non-accelerated filer [ ] | Smaller reporting company [X] |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). YES [ ] NO [X]
The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant, as of the fiscal year ending December 31, 2013 is $6,134,777 based on the average closing price of the Registrant’s common stock as currently listed on the OTC Bulletin Board exchange. Shares of Common Stock held by each officer and director and in that such persons may be deemed to be affiliates of the registrant. The determination of affiliate status is not necessarily a conclusive determination for any other purpose. The shares of our company are currently listed on the OTC Bulletin Board exchange, symbol “BKKN”.
Number of shares outstanding of the issuer’s common stock as of August 31, 2016 is 56,735,350 shares.
DOCUMENTS INCORPORATED BY
REFERENCE
Amendment No. 1 to Bakken’s Annual Report on Form 10-K/A for fiscal year ended December 31, 2013 Access No. 0001206774-16-007150, submitted to Edgar on Thursday, September 1, 2016
EXPLANATORY NOTE
This Amendment No. 2 to the Annual Report on Form 10-K for the period ending December 31, 2013 is being filed to (a) include the signatures of additional directors, (b) include the date of the report of the independent registered public accounting firm, and (c) include various non-material edits to the filing that were not included to Amendment No. 1 to the Annual Report on Form 10-K for the period ending December 31, 2013, which was filed on September 1, 2016.
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CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING INFORMATION
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, industry conditions, and indebtedness covenant compliance 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 contemplating or making assumptions about, actual or potential future sales, market size, collaborations, and 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 company's control) that could cause actual results to differ materially from those set forth in the forward-looking statements, including the following: general economic or industry conditions, nationally and/or in the communities in which our company conducts business, changes in the interest rate environment, legislation or regulatory requirements, conditions of the securities markets, our ability to raise capital, changes in accounting principles, policies or guidelines, financial or political instability, acts of war or terrorism, other economic, competitive, governmental, regulatory and technical factors affecting our company's operations, products, services and prices.
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, contingencies 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 “Commission” or “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.
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BAKKEN RESOURCES,
INC.
ANNUAL REPORT OF FORM 10-K
FOR FISCAL YEAR ENDED DECEMBER 31, 2013
PART I
Overview and Background
Bakken Resources, Inc. (the “Company,” “BRI,” “we,” “us,” or “our”) owns mineral rights to approximately 7,200 gross acres and 2,400 net mineral acres of land located about 8 miles southeast of Williston, North Dakota. The Company’s net mineral acres consist generally of 2,400 net mineral acres deriving from the sub-surface to the base of the rock unit in the region commonly referred to as the Bakken formation. Approximately 800 of such 2,400 net mineral acres, consist also of mineral rights extending below the Bakken formation (which include, without limitation, the source rock commonly referred to as the Three Forks formation(s)).
These mineral rights currently bear to us an average of 12% royalty from the oil and gas produced on such lands until November 2020, at which time a 5% overriding royalty currently held by Holms Energy, LLC, a private Nevada company (“Holms Energy”) will revert back to the Company. The Holms Energy overriding royalty is a common practice in the oil and natural gas industry. When mineral rights are sold it is a usual and customary practice for the seller to retain a portion of the royalty stream. This retained royalty is usually stated in percentage terms; that is, the percentage points of the original royalty stream that is retained by the seller. In the case of Holms Energy, the Asset Purchase Agreement provided a five percentage point retained overriding royalty. Therefore, Holms Energy retains five percentage points of a seventeen percentage point royalty stream, or 29.41% (5/17). The Company’s Annual Report on Form 10-K for the year ended December 31, 2011 contained an erroneous example of this overriding royalty.
The overriding royalty, 5/17 or 29.41%, is applied to Bakken’s monthly net royalty paid by the company’s well operators, Oasis Petroleum, Continental Resources, and Statoil. The operators discount the gross monthly production value (gross oil and natural gas volume times the current unit price) by the company’s net mineral interest to derive the company’s net monthly royalty. The Holms Energy overriding royalty factor (29.41%) is then applied to the net monthly royalty to derive the monthly override payment. The methodology employed by Bakken is consistent with the methodology employed by Oasis Petroleum and Continental Resources to calculate the overriding royalty that Bakken retained with the sale of certain mineral rights to Apollo Global Management in February 2014. Bakken has consistently applied this methodology since the company’s inception. Prior SEC filings included examples which erroneously discussed the application of the overriding royalty and included examples of such.
|
Overriding royalty calculation example: Missoula 1-21H | ||
| ○ |
Gross Mineral Acres: 640.00 (Independently Confirmed by Third Party Certified Landman) | |
| ○ |
Net Mineral Interest: 16.18993% (Independently Confirmed by Third Party Certified Landman) | |
| ○ |
Net Mineral Acres: 103.62 (640.00 x 16.18993%) | |
| ○ |
Stated Lease Royalty Percentage: 17% | |
| ○ |
North Dakota Industrial Commission Established Spacing Unit: 1280 acres | |
| ○ |
Bakken Net Royalty Percentage: 1.3761433% (derived as (103.62 x 17%)/1280) | |
| ○ |
December 2013 Oil Production: 4,565 Barrels (Continental Resources 1/2014 Remittance Statement) | |
| ○ |
December 2013 Oil Sales Price: 85.8941 (Continental Resources Remittance Statement) | |
| ○ |
Post Production Costs - $206.31 | |
Holms Energy Override: 5/17 x 4,565 barrels x $85.8941 per barrel x 1.3761433% - $206.31 Post Production Costs = $1,587.04
According to the U.S. Geological Survey, the Bakken Formation, is “a thin but widespread unit within the central and deeper portions of the Williston Basin in Montana, North Dakota, and the Canadian Provinces of Saskatchewan and Manitoba. The formation consists of three members: (1) lower shale member, (2) middle sandstone member, and (3) upper shale member. Each succeeding member is of greater geographic extent than the underlying member. Both the upper and lower shale members are organic-rich marine shale of fairly consistent lithology; they are the petroleum source rocks and part of the continuous reservoir for hydrocarbons produced from the Bakken Formation. The middle sandstone member varies in thickness, lithology, and petrophysical properties, and local development of matrix porosity enhances oil production in both continuous and conventional Bakken reservoirs.” (source: USGS Fact Sheet, April 2008). Generally, the source rock commonly referred to as the “Three Forks Formation” is located geologically below the Bakken formation.
We currently have leases with three contracted oil drilling operators on various parcels of land constituting the 7,200 gross acres (and approximately 2,400 net mineral acres) on which we have mineral rights royalty interests. The contracted oil drilling companies with whom we are parties in interest pursuant to lease agreements (collectively, the “Lessees”) that we acquired rights to in November 2010 include: Oasis Petroleum, Continental Resources, Inc., and Statoil ASA. We have no rights to influence the activities conducted by these Lessees of our mineral rights, but if the Lessees do not accomplish the agreed upon drilling programs within the timeline, they can lose their leases.
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The predecessor to our company was incorporated on June 6, 2008, under the laws of the state of Nevada, under the name Multisys Language Solutions, Inc. (“MLS”). Holms Energy contributed the primary assets that formed the basis of our current business operations. In connection with the closing of the transactions resulting in the contribution of the mineral rights held by Holms Energy in November 2010, Holms Energy received forty million (40,000,000) shares of common stock of the Company. Holms Energy retained a 5% overriding royalty (until November 2020, at which time it reverts back to the Company) on all gross revenue generated from the Company's gas and oil production royalty revenues.
Also in connection with the November 2010 transactions, the Company purchased approximately 800 net mineral acres from the Revocable Living Trust of Rocky G. Greenfield and Evenette G. Greenfield. The mineral rights received by the Company from the contribution by Holms Energy in connection with the November 2010 transactions included mineral rights from the surface to the base of the Bakken formation. The mineral rights received by the Company from the Greenfields include all mineral rights from the surface to the basement. After closing of the Asset Purchase Agreement with Holms Energy, on December 10, 2010, MLS changed its name to Bakken Resources, Inc. These transactions and changes of control are described below under Acquisition of Assets.
Description of Oil Leases and Oil Production
BRI currently derives its primary source of revenue from royalties generated by leasing its mineral acreage. BRI’s mineral acreage consists of approximately 2,400 net mineral acres located primarily in McKenzie County, North Dakota. Such 2,400 net mineral acres are currently spread across 16 spacing units. Operators in the area where BRI’s minerals are located have been approved for up to eight wells per spacing unit (typically 1,280 acres), but generally petition for permits prior to the commencement of drilling in a particular spacing unit. Assuming this would apply for all spacing units under which BRI has mineral acres, BRI would have a royalty interest in up to 112 wells. Note, however, that the royalties due to BRI under any particular well would vary based on the number of acres BRI has under any particular spacing unit where there is a producing well. An example of an application for permit to drill a horizontal well is shown below. This permit is for a well in the area where BRI’s minerals are located (section 21, T152N R100W). Section 21 currently has 7 wells drilled. Order number 20946 of the North Dakota Industrial Commission shows that Oasis Petroleum, one of the operators in the BRI mineral acres area, has applied for up to 8 wells per 1280-acre spacing unit (1st page of order 20946 follows).
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As of December 31, 2013, BRI received royalty income primarily from 28 Bakken formation producing wells, 12 Three Forks formation wells, and 3 Madison formation producing wells. During 2013, the dollar amount of such royalties received from the aggregate number of producing wells was approximately $4,000,000. BRI has interest under several other wells which have been drilled and are likely producing, but for which royalties have yet to be received as of December 31, 2013. BRI is currently receiving royalty income from five wells which have been determined to be drilled in the Three Forks formation.
With respect to drilling operations, pursuant to the North Dakota Oil and Gas Commission, long lateral deep horizontal multi-stage fracking wells in the Bakken Formation must be permitted in spacing unit of not less than 640 acres, up to 5,560 acres, with some exceptions. The spacing units have to be approved and permitted in advance of drilling by the North Dakota Oil and Gas Commission. Recently, the North Dakota Industrial Commission (“NDIC”) has approved multi-well permits for wells drilled in the Three Forks formation along several of the defined “benches” typically associated with separate geologic benchmarks contained in the Three Forks formation. Since approximately one-third of the Company’s current net mineral acres include acreage in the Three Forks formation, any increase in the drilling operations on the Company’s net mineral acres may result in an increased number of total wells from which the Company may derive royalty income.
When our lessees drill a horizontal well in the area where the subject property is located, they typically drill down to about 10,800 vertical feet and then utilize a downhole directional drilling tool to flatten the hole to 90 degrees and drill horizontally down the oil and gas producing formation. Horizontal directional drilling provides more contact area to the oil bearing formation than a typical vertical well. This method of drilling together with fracking is referred to as an enhanced oil recovery method, and is the primary source of recovery from the Bakken Formation. BRI does, however, have interests in certain wells not drilled into the Bakken Formation.
Well activity information for wells in which the company has mineral interest is compiled in a table which is available on the Company web site at http://www.BakkenResourcesInc.com/WellActivity.php.
The information provided in our website’s table is categorized by well name, the operator, field and pool, the NDIC identifying number, and the well status and location description. Well status is defined by several categories: Producing; Confidential; Drilling; and Permitted Location to Drill. The table is updated as new information becomes available on the NDIC website at https://www.dmr.nd.gov/oilgas/. Included on the table are NDIC file numbers which can be used when searching for information for each well listed on the BRI webpage. Individuals may subscribe to the NDIC website following the prompts on the homepage. A premium service subscription is also available for a fee.
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Currently, most of the leases covering the Company’s mineral acres contain what is commonly referred to as “continuous drilling clauses”. Generally, a continuous drilling clause requires an operator to maintain active drilling operations in order to hold or extend an oil and gas lease past the natural expiration date of the lease. A majority of the Company’s current leases currently have active drilling operations and are likely to have active operations in the foreseeable future.
Acquisition of Assets
On June 11, 2010, Multisys Language Solutions, Inc. or MLS, Multisys Acquisition, and Holms Energy entered into an Option to Purchase Assets Agreement, pursuant to which Holms Energy agreed to grant Multisys Acquisition an option to exercise an Asset Purchase Agreement to assign all right, title, and interest of specific Holms Energy owned oil and gas mineral rights to Multisys Acquisition. On November 26, 2010, MLS completed an initial closing of a private placement in the amount of $1,545,000 that issued 6,180,000 shares at $0.25 per share and 3,090,000 three-year warrants exercisable for 3,090,000 shares at $.50 per share, callable at $0.01 per share at any time after November 26, 2011, if the underlying shares are registered, and the common stock trades for 20 consecutive trading days at an average closing sales price of $1.00 or more. Such warrants are now expired. The option agreement expired on its terms before the Asset Purchase Agreement was executed. Despite the expiration of the option, the Asset Purchase Agreement was duly executed by all parties and hence is a legally binding agreement.
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We concurrently exercised the option with Holms Energy and executed an Asset Purchase Agreement by and between MLS, Holms Energy, and Multisys Acquisition in order to acquire certain interests in mineral rights and assets from Holms Energy. The option was exercised on November 26, 2010, and the Asset Purchase Agreement was entered into on November 26, 2010 by paying the consideration to Holms Energy detailed in the Asset Purchase Agreement. Under the Asset Purchase Agreement, Multisys Acquisition paid Holms Energy $100,000, issued Holms Energy 40,000,000 shares of restricted common stock, and granted to Holms Energy a 5% overriding royalty on all revenue generated from the Holms Property (defined herein) for ten years from the date of the acquisition closing (i.e. November 2010). With the issuance of the 40,000,000 shares to the Holms Energy members, the Holms Energy members own a controlling interest in BRI. Holms Energy disbursed 40,000,000 shares to its members on a ratable ownership basis as a liquidating dividend to members.
The Asset Purchase Agreement related to the acquisition of: (1) certain Holms Energy mineral rights in oil and gas rights on approximately 7,200 gross acres and 2,400 net mineral acres of land located in McKenzie County, 8 miles southeast of Williston, North Dakota (the “Holms Property”); (2) potential production royalty income from wells to be drilled on the property whose oil and gas mineral rights are owned by Holms Energy; and (3) the transfer of all right, title and interest to an Option to Purchase the mineral rights from Rocky G. Greenfield and Evenette G. Greenfield entered into between Holms Energy and the Revocable Living Trust of Rocky G. Greenfield and Evenette G. Greenfield related to purchasing additional oil and gas mineral rights and production royalty income on the Holms Property for One Million Six Hundred Forty Nine Thousand ($1,649,000) Dollars (the “Greenfield Option”) (altogether, the “Asset Acquisition”). The Greenfield mineral rights were acquired by Multisys Acquisition through the Asset Purchase Agreement with Holms Energy on November 12, 2010. Holms Energy entered into a $485,000 one month non-interest bearing loan from BRI (the “Greenfield Note”) to complete the initial payment of $400,000 for the purchase of the Greenfield mineral rights. The purchase price of the Greenfield mineral rights under the agreement with Holms Energy (which was assumed by the Company in connection with the completion of the November 2010 transactions) was an aggregate of $1,649,000 plus interest as follows: an initial payment of $400,000; installment payments generally in the amount of $30,000 per quarter plus interest at 5% per annum for 8 years and an original balloon payment in the amount of $289,000 (which is subject to reduction in the event the Company accelerates payments under the Greenfield Note). The scheduled installment payments of $30,000 per quarter are subject to the amount of 35% of net revenues received in connection with the purchased Greenfield mineral rights. Payments made in excess of the amounts originally scheduled are applied to the outstanding principal amount of the loan. The collateral for the Greenfield Note are the Greenfield mineral rights. Under the terms of the loan from BRI to Holms Energy, Holms Energy, in conjunction with the entry into the Asset Purchase Agreement on November 26, 2010, assigned the Greenfield mineral rights to Multisys Acquisition in exchange for forgiveness of $385,000 of the loan. The other $100,000 of the loan was to be applied to the Asset Purchase Agreement between BRI and Holms Energy, and on November 26, 2010, that $100,000 was applied to the Asset Purchase Agreement and the loan was forgiven.
Although the Greenfield Note included an eight year amortization of the former Greenfield properties, the Company accelerated these payments, retiring the debt in 2013.
In conjunction with the exercise of the option and execution of the Asset Purchase Agreement with Holms Energy, Multisys Acquisition acquired the rights to the Asset Purchase Agreement between Holms Energy and the Greenfields and therefore purchased the gas and oil production royalty rights of the Revocable Living Trust of Rocky G. Greenfield and Evenette G. Greenfield.
Change of Control of Bakken Resources, Inc.
After the closing of the Asset Purchase Agreement on November 26, 2010 which involved, in part, the issuance of 40 million (40,000,000) shares of BRI common stock to Holms Energy, the Company subsequently declared a special liquidating dividend distribution of such 40 million shares to its members. Following such distribution, the members of Holms Energy beneficially then held in aggregate approximately 76.2% of the outstanding shares of common stock of Multisys Language Solutions after the closing of the Asset Purchase Agreement on November 26, 2010. After the closing of the transaction, based on an informal agreement in place, the current directors of MLS appointed the nominees designated by Holms Energy as members of the board of directors of MLS on December 1, 2010. Subsequently, the officers and directors of MLS resigned their positions, clearing the way for the appointment of new executive officers by a new board of directors of MLS. Pursuant to the authorization from MLS stockholders for the amendment of the articles of incorporation of MLS at a special meeting of stockholders, MLS changed its corporate name from Multisys Language Solutions, Inc. to Bakken Resources, Inc. on December 10, 2010 to reflect its new business focus.
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Business Strategy
We plan to focus on evolving into a growth-orientated independent energy company engaged in the acquisition, exploration, exploitation, and development of oil and natural gas properties. We plan to initially focus our activities mainly in the Williston Basin, a large sedimentary basin in eastern Montana, Western North and South Dakota, and Southern Saskatchewan known for its rich deposits of petroleum and potash. To date, we have collected approximately $6.6 million in revenues from royalties generated from our mineral rights.
Per our business plan and strategy, we have pursued relationships to gather information on future potential oil and gas drilling projects and explored and contemplated possible joint partnerships in other drilling programs. We previously announced our acquisition of mineral acreage in the Duck Lake region of Western Montana, in a potential oil play commonly referred to as the Alberta Bakken. We also announced our acquisition of a 17% working interest in an operating well located in Archer County, Texas. The Company remains in discussion with various groups for strategic partnerships and plans to announce the completion of such arrangements if and when they are consummated.
Geology of the Bakken Formation and the Three Forks Formation
The geological formation, as well as many other criteria, determines the production level of any commercial wells, which impact the potential future royalty revenue, if any. The following profile of the Williston Basin gives an idea as to the value of our mineral assets. Our leases are in a geographic area known as the Williston Basin, which is a large intracratonic sedimentary basin in eastern Montana, western North and South Dakota and southern Saskatchewan known for its rich deposits of petroleum and potash. The basin is a geologic structural basin but not a topographic depression; it is transected by the Missouri River. The oval-shaped depression extends approximately 475 miles (764 km) north-south and 300 miles (480 km) east-west. The map below shows the general location of the Bakken Formation and the Alberta Bakken (not intended to show or represent the location of any oil fields). (Source: http://seekingalpha.com/article/284628-the-alberta-bakken-the-smaller-sibling-offers-compelling-prospects).
The smaller area shown in the northwest portion of Montana shows generally the location of mineral acreage BRI purchased in Fall 2011 (referred to as the “Duck Lake Property”). Drilling has not begun on the Duck Lake Property.
The Bakken formation has received considerable recognition for its oil production capabilities. Oil was discovered in this formation in 1951 but production was difficult to achieve at that time. Technological developments and improvements since then have given operators the capabilities in recent years to develop the formation. In April 2008, the United States Geological Service (USGS) released a report estimating the amount of oil recoverable with current technology ranged from 3.0 to 4.3 billion barrels. At the same time, the State of North Dakota also released a report estimating recoverable oil at 2.1 billion barrels. Other industry estimates place the total oil available, which includes oil that cannot be recovered with current technology, at 18 billion barrels. The USGS is currently further reassessing the amount of technically recoverable oil in the Bakken formation and such report is expected to be released in late 2014.
There are several formations below the subsurface of the Bakken formation known commonly as the Three Forks. Evaluative wells have already been drilled to these “benches” of the Three Forks. Operators have recently begun exploratory drilling into these benches. Several operators have announced plans to evaluate high density drilling possibilities to these benches. The graphic below shows a development pilot program Continental has announced as part of its Three Forks drilling program.
(Source: Seeking Alpha (http://seekingalpha.com/article/1248431-bakken-the-downspacing-bounty-and-birth-of-array-fracking)
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The drilling pattern in this graphic is known as array drilling. The offset pattern of drilling is expected to allow high density drilling for a spacing unit (1,280 acres). The goal is to increase the number of wells without impacting the number of barrels produced from each well.
BRI owns mineral acres in the Three Forks formation through its ownership of the former Greenfield mineral assets.
According to the NDIC’s Oil and Gas Division, the Bakken Shale in the Williston Basin is over 11,000 ft. deep at the center of the formation and rises to 3,100 ft. on the edges of the basin. The Bakken Formation is composed of three distinct members. The first layer averages twenty three feet in depth and consists of blackish marine shale. The second member runs from 30 ft. to 80 ft. and composed of interbedded limestone, siltstone, sandstone and dolomite. The bottom member is a dark black marine shale that averages 10 ft. to 30 ft. in thickness. All three formations that make up the Bakken are rich in an organic material called Kerogen. When Kerogen is heated (thermogenic processes) or broken down by organic means (biogenic processes), natural gas and oil are created. The Bakken Formation is capped by a very thick limestone formation called the Lodgepole. It is because of this limestone cap that there is so much gas and oil trapped in the shale horizon. The Bakken Formation is what is considered a thermally mature deposit and the oil from the Bakken has a 41 specific gravity and is deemed to be commercially high grade crude oil.
Horizontal Drilling
Horizontal or directional drilling has revolutionized the way the oil and gas wells are being drilled in the Williston Basin. The reason that horizontal drilling is changing the oil and gas business is that a well drilled horizontally through a formation that contains oil and gas should produce many more times that of a vertical well. A vertical well will only penetrate a limited area of the productive zone, whereas a well drilled horizontally may penetrate up to 10,000’ of the zone. This also means that previously tight shale formations such as the Bakken formation can result in prolific production.
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The Bakken formation has poor porosity which reduces the ability of the gas and oil to flow out of this horizon. Recently, horizontal drilling of lateral holes combined with hydraulic fracturing (commonly referred to as ‘fracking’) has resulted in substantial production from thick formations that have poor porosity. It should be noted, however, that porosity and the permeability of the oil shale rock can vary widely and unpredictably over short distances, thus dry wells can be found next to prolific wells with little explanation geologically.
Fracking is a procedure whereby packers (plugs) are set every 250’ to 300’ and up to ten 2,000 horsepower hydraulic pumps deliver high pressure fluids that contain a high percentage of round ceramic beads and sand are utilized as proppants and keep the fissures and fractures open along the bedding-planes that are created by the high pressure fluids. The fissures and channels created by the high pressure fluid and held open by the ceramic beads that are left behind; provide a pathway to allow the gas and oil to flow into the drill hole.
Two technologies are currently being used to enhance horizontal drilling: (1) log while drilling (“LWD”); and (2) drill string radar (“DST”). LWD uses long sensors which read gamma radiation given off by the formation, which provides real time information to the drillers and this information is gathered and assists drillers to drill in the optimum sections of the formation. DST provides information to the driller on the surface as to what direction, angle and depth the well is being drilled. The combination of the two technologies greatly assists keeping the drill bit in the optimum location within the Bakken formation. Below is a diagram example of horizontal drilling.
Governmental Regulations
Our operations are not directly subject to various rules, regulations and limitations impacting the oil and natural gas exploration and production industry as whole, however, operators who operate on our properties may be impacted by such rules and regulations.
Regulation of Oil and Natural Gas Production. Oil and natural gas exploration, production and related operations, when developed, are subject to extensive rules and regulations promulgated by federal, state and local authorities and agencies. For example, the state of North Dakota and Montana requires permits for exploration drilling, operation of commercial wells, submission of several reports concerning operations of wells and imposes other requirements relating to the production of oil and natural gas. Such states may also have statutes and regulations addressing conservation matters, including provisions for the unitization or pooling of 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 by our operators can result in substantial penalties, which in turn may impact the amount of royalty revenue we derive from our leased properties. Although we believe that we are currently in substantial compliance with all applicable laws and regulations, to the extent they apply to us, 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
The following environmental discussion may be applicable directly to our operators; however, we could be indirectly impacted, since environmental laws and regulations could significantly impact production of the wells on our properties. Our operators and properties are impacted by 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, as such regulations relate to our operators. 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. |
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The permits required by our operators 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 or injunctions, or both. 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 thereof could have a significant impact on BRI, as well as the 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 liabilities 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 excludes petroleum from its definition of “hazardous substance,” state laws affecting our operators may impose clean-up liability relating to petroleum and petroleum related products. In addition, although RCRA classifies certain 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.
Our operations are also subject to the federal Clean Water Act and analogous state laws. The Clean Water Act and similar state acts regulate other discharges of wastewater, oil, and other pollutants to surface water bodies, such as lakes, rivers, wetlands, and streams. Failure to obtain permits for such discharges could result in civil and criminal penalties, orders to cease such discharges, and costs to remediate and pay natural resources damages. Under the Clean Water Act, the U.S. Environmental Protection Agency (“EPA”) has adopted regulations concerning discharges of storm water runoff. This program requires covered facilities to obtain individual permits, or seek coverage under a general permit. Some of our properties may require permits for discharges of storm water runoff and our operators may apply for storm water discharge permit coverage and updating storm water discharge management practices at some of our facilities. These laws also require the preparation and implementation of Spill Prevention, Control, and Countermeasure Plans in connection with on-site storage of significant quantities of oil.
The federal Clean Air Act and comparable state laws regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. In addition, the EPA has developed and continues to develop stringent regulations governing emissions of toxic air pollutants at specified sources. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations. The operations provided by our operators, may be, in certain circumstances and locations, subject to permits and restrictions under these statutes for emissions of air pollutants.
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 operators will be in substantial compliance with such statutes, any change in these statutes or any reclassification of a species as endangered could subject our operators to significant expenses or could force our operators to discontinue certain operations altogether, which could materially impact our revenues.
Competition
The oil and natural gas industry is intensely competitive, and we compete with numerous other oil and gas exploration and production companies who may also be seeking oil well operators for leasehold interests. Many of these companies have substantially greater resources than we have. Not only do they explore for and produce oil and natural gas, but many also carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. The operations of other companies may be able to pay more for exploratory prospects and productive oil and natural gas properties. They may also have more resources to define, evaluate, bid for, and purchase a greater number of properties and prospects than our financial or human resources permit.
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Our larger or integrated competitors may have the resources to be better able to absorb the burden of existing, and any changes to federal, state, and local laws and regulations more easily than we can, which would adversely affect our competitive position. Our ability to determine reserves and acquire additional properties in the future will be dependent upon our ability and resources to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. In addition, we may be at a disadvantage in producing oil and natural gas properties and bidding for exploratory prospects, because we have fewer financial and human resources than many other companies in our industry. Should a larger and better financed company decide to directly compete with us, and be successful in its efforts, our business could be adversely affected.
Marketing and Customers
The market for oil and natural gas that our operators depends on factors beyond our control, including the extent of domestic production and imports of oil and natural gas, the proximity and capacity of natural gas pipelines and other transportation facilities, demand for oil and natural gas, the marketing of competitive fuels and the effects of state and federal regulation. The oil and gas industry also competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers.
Our production royalties derived from oil and gas production from our properties are expected to be sold by the Lessees at prices tied to the spot oil markets. We derive certain royalty revenues from gas produced from wells drilled on our property, but currently this amount is small relative to the royalties we receive from oil production. We will be required to rely on the Lessees to market and sell any future gas production.
Employees and Consultants
We currently have two full-time employees and one part-time employee, respectively, Val Holms, President, Chief Executive Officer and Chairman; Karen Midtlyng, Secretary and Director and David Deffinbaugh, Chief Financial Officer and Director. All of our appointed executives have entered into written employments agreements. As drilling production activities continue to increase by our Lessees, and if additional revenue from production royalties develops as anticipated and continues to increase, we may hire additional technical, operational or administrative personnel as appropriate. We are using and will continue to use the services of independent consultants and contractors to perform various professional services. We believe that this use of third-party service providers may enhance our ability to contain general and administrative expenses.
Office Location
Our offices are located at 1425 Birch Ave., Suite A, Helena, MT 59601. We also maintain a presence in New York City with a part-time office.
Available Information—Reports to Security Holders
Our website address is www.bakkenresourcesinc.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, Section 16 reports for officers and directors, and amendments to those reports as soon as reasonably practicable 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.
In addition, BRI regularly monitors and maintains information relating to drilling activity on wells which it has a mineral interest. Such information can also be found on our website.
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You should carefully consider the risks, uncertainties, and other factors described below. The statements contained in or incorporated herein that are not historic facts are forward-looking statements that are subject to risks and uncertainties that could cause actual results to differ materially from those set forth in or implied by forward-looking statements. Any of the factors could materially and adversely affect our business, financial condition, operating results and prospects and could negatively impact the market price of our common stock. Also, you should be aware that the risks and uncertainties described below are not the only ones we face. Additional risks and uncertainties, of which we are not yet aware, or that we currently consider to be immaterial may also impair our business operations.
Risks Associated with Our Business
We are an early stage company. We may never attain profitability.
We have a limited operating history for you to consider in evaluating our business and prospects. Our business relies upon receiving royalties on our lease mineral assets. The business of acquiring, exploring for, developing and producing hydrocarbon reserves is inherently risky. Our operations are therefore subject to all of the risks inherent in acquiring, exploring for, developing and producing hydrocarbon reserves, particularly in light of our limited experience in undertaking such activities. We may never overcome these obstacles.
Our business is speculative and dependent upon the implementation of our business plan and our ability to enter into agreements with third parties for the rights to exploit potential oil and natural gas reserves on terms that will be commercially viable for us.
Our current business model relies exclusively on uncertain future royalty payments as a source of future revenue. We have no influence on the activities conducted by the Lessees with regards to the exploitation of mineral rights owned by the company.
Our current business model relates to the potential generation of revenue from royalties tied to certain leases. These leases have been granted to experienced exploration and operating companies, both of whom have prior experience in drilling deep lateral multi-fracture horizontal wells. Even after wells are drilled on property where the Company owns mineral rights, future income may be uncertain. Pursuant to the terms and conditions of the leases, we have no influence with regard to when the drilling will be undertaken, no decision making ability as to the location of any future wells and no influence as to the rate the wells are produced, if the operators are successful, of which there is no assurance. In the event the Lessees fail to meet their drilling commitment, the company has only three options: (1) it can agree to grant an extension; (2) it can renegotiate the terms of the existing leases; or (3) it can legally terminate the leases.
We may be unable to obtain additional capital or generate significant production royalty income that we will require to implement our business plan, which could restrict our ability to grow.
We expect that our current capital and our other existing resources will be sufficient only to provide a limited amount of working capital, and the potential of production royalty revenues generated from our oil and gas mineral rights properties, of which there is no assurance, may not be sufficient to fund both our continuing operations and our planned growth. We may require additional capital to continue to operate our business beyond the initial phase of development and to further expand our exploration and development programs to additional properties. We may be unable to obtain additional capital, and if we are able to secure additional capital, it may not be pursuant to terms deemed to be favorable to BRI and its shareholders.
Future acquisitions and future exploration, development, production and marketing activities, as well as our administrative requirements (such as salaries, insurance expenses and general overhead expenses, as well as legal compliance costs and accounting expenses) may require a substantial amount of additional capital and cash flow.
We may pursue sources of additional capital through various financing transactions or arrangements, including joint venturing of projects, debt financing, equity financing or other means. We may not be successful in locating 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 operations going forward beyond twelve months from now.
Any additional capital raised through the sale of equity may dilute the ownership percentage of our stockholders. This 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. 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, and issuances of incentive awards under equity employee incentive plans, which may have a further dilutive effect.
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Our ability to obtain financing may be impaired by such factors as the capital markets (both generally and in the oil and gas industry in particular), our status as a new enterprise without a significant demonstrated operating history, production royalty revenue from our mineral rights property, currently our only oil and natural gas property and prices of oil and natural gas on the commodities markets (which will impact the amount of asset-based financing available to us) and/or the loss of key management. Further, if oil and/or natural gas prices on the commodities markets decline, our revenues from the anticipated royalties will 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.
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, such as convertible notes or warrants, which may adversely impact our financial condition.
Under the terms of the lease agreements with our contract oil drilling company leaseholders or Lessees, we have very little control over the number of wells that our Lessees choose to drill on our mineral rights properties and how much production they generate.
Our current business model relates to the potential generation of revenue from royalties tied to certain leases on property covered in part by mineral rights owned by us. These leases have been granted to Lessees who are experienced exploration and operating oil companies, who have prior experience in drilling deep lateral multi-fracture horizontal wells. Pursuant to the terms and conditions of the leases, we have no influence with regard to when the drilling will be undertaken, no decision making ability as to the location of any future wells and no influence as to the rate the wells are produced, if the operators are successful, of which there is no assurance.
The success and timing of development activities by Lessees will depend on a number of factors that will largely be out 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 have no control over the operational effectiveness or financial wherewithal of our operators.
Our current business model relies heavily upon our operators and their operational effectiveness and financial wherewithal. Therefore, our operating revenue and cash flow may be heavily impacted if our operators are not effective or accurate when determining our net royalty revenue.
Similarly, our business model is heavily predicated upon our operator’s ability to pay royalty when due and to have sufficient capital to maintain existing wells and to drill new wells.
We have no previous operating history in the oil and gas industry, which may raise substantial doubt as to our ability to successfully develop profitable business operations.
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 oil and natural gas industries. There is nothing at this time on which to base an assumption 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 the development and exploration program conducted by the oil company Lessees operating on our property; |
| ● | demand for natural gas and oil; |
| ● | the level of our competition; |
| ● | our ability to attract and maintain key management and employees; and |
| ● | the ability of the of the oil company Lessees to efficiently explore, develop and produce sufficient quantities of marketable natural gas or oil in a highly competitive and speculative environment while maintaining quality and controlling costs. |
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To achieve profitable operations in the future, we are primarily dependent upon the oil company Lessees to successfully execute on the factors stated above, along with continuing to develop strategies and relationships to enhance our revenue by financially participating and investing in various drilling programs with third parties. Despite their best efforts, our Lessees may not be successful in their exploration or development efforts or obtain required regulatory approvals on the property where BRI is entitled to a production royalty. There is a possibility that some, or most, of the wells to be drilled on our mineral rights properties may never produce natural gas or oil.
Our management team does not have extensive experience in public company matters, which could impair our ability to comply with legal and regulatory requirements.
Our management team has had limited public company management experience or responsibilities, which could impair our ability to comply with legal and regulatory requirements such as the Sarbanes-Oxley Act of 2002 and other federal securities laws applicable to reporting companies, including filing required reports and other information required on a timely basis. It may be expensive to implement programs and policies in an effective and timely manner that adequately respond to increased legal, regulatory compliance and reporting requirements imposed by such laws and regulations, and we may not have the resources to do so. Our failure to comply with such laws and regulations could lead to the imposition of fines and penalties and further result in the deterioration of our business and decreased value of our stock.
If we fail to maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud.
Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results could be harmed. We cannot be certain that our efforts to maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to continue to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002. Any failure to maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet certain reporting obligations.
Our lack of diversification will increase the risk of an investment in BRI, and our financial condition and results of operations may deteriorate if we fail to diversify.
Our business focus predominately is on the oil and gas industry on our oil and gas mineral rights property, located in McKenzie County, North Dakota. Larger companies have the ability to manage their risk by diversification. However, we currently 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, enhancing our risk profile. If we cannot diversify or expand our operations, our financial condition and results of operations could deteriorate. We have been solely dependent on the expertise of our Lessees as the operator of our property.
Uncertain future royalty payment and limited influence on future drilling and exploration.
Our current business model relates to the potential generation of revenue from royalties tied to certain leases owned by us. These leases have been granted to experienced exploration and operating companies, both of whom have prior experience in drilling deep lateral multi-fracture horizontal wells. Pursuant to the terms and conditions of the leases, we have no influence with regard to when the drilling will be undertaken, no decision making ability as to the location of any future wells and no influence as to the rate the wells are produced, there are no assurances as to the success of the operators.
Strategic relationships upon which we may rely on are subject to change, which may diminish our ability to conduct our operations.
Our ability to successfully acquire additional mineral rights properties, to participate in drilling opportunities, and to identify and enter into commercial arrangements with other third party companies will depend on developing and maintaining close working relationships with industry participants and 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 may impair our ability to grow.
To continue to develop our business, we will endeavor to use the business relationships of our management to identify, screen, and enter into strategic relationships, which may take the form of joint ventures with other private parties and contractual arrangements with other operating oil and gas exploration companies. We may not be able to establish these strategic relationships, or if established, we may not be able to maintain them. Even if we are able to engage in joint venture and enter into strategic investment relationships with existing operators, they may not be pursuant to terms and conditions that are favorable to us. In addition, the dynamics of our relationships with strategic partners may require us to incur expenses or undertake activities we would not otherwise be inclined to in order to fulfill our obligations to these partners or maintain our relationships. If our strategic relationships are not established or maintained, our business prospects may be limited, which could diminish our ability to conduct our operations.
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Our acquisition or disposition strategy will subject us to certain risks associated with the inherent uncertainty in evaluating such transactions.
Our decision to acquire or dispose of a property will depend in part on the evaluation of data obtained from production reports and engineering studies, geophysical and geological analyses and seismic and other information, the results of which are often inconclusive and subject to various interpretations. Also, our reviews of acquired properties are inherently incomplete because it generally is not feasible to perform an in-depth review of the individual properties involved in each acquisition. Similarly, if we elect to see any of our current assets, we cannot be assured that all material information will be available to us to adequately evaluate the merits of such a sale. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit us to become sufficiently familiar with the properties to assess fully their deficiencies and potential. Inspections may not always be performed on every well, and environmental problems, such as ground water contamination, are not necessarily observable even when an inspection is undertaken.
Any acquisition involves other potential risks, including, among other things:
| ● | the validity of our assumptions about reserves, future production, revenues and costs; |
| ● | in the case of an acquisition, a decrease in our liquidity by using a significant portion of our cash from operations or borrowing capacity to finance acquisitions; |
| ● | in the case of an acquisition, a significant increase in our interest expense or financial leverage if we incur additional debt to finance acquisitions; |
| ● | the assumption of unknown liabilities, losses or costs for which we are not indemnified or for which our indemnity is inadequate; |
| ● | an inability to hire, train or retain qualified personnel to manage and operate our growing business and assets; and |
| ● | an increase in our costs or a decrease in our revenues associated with any potential royalty owner or landowner claims or disputes; |
| ● | in the case of any disposition, the risk that any such transaction may be undervalued based on information that may become available following the disposition of such assets |
Competition in obtaining rights to explore and develop oil and gas reserves and for our Lessee to market any future production may impair our business.
The oil and gas industry is highly competitive. This competition is increasingly intense as prices of oil and natural gas on the commodities markets have increased in recent years. 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 acquisitions. If we are unable to compete effectively or adequately respond to competitive pressures, this inability may materially adversely affect our results of operation and financial condition.
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.
Reliance on Consultants
Since Bakken uses a number of consultants, such consultants may not be subject to the standard internal controls that the Company has for its employees. Therefore, certain risks may be difficult for the Company to detect with respect to its consultants, such as direct, day-to-day oversight of consultant activities.
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Net Royalty Interest Volatility
The Company’s cumulative net royalty interest is a result of (a) the product of net mineral acreage for each well and (b) the royalty percentage divided by (c) the spacing unit acreage declared by the state of North Dakota. The Company’s cumulative net royalty interest is subject to volatility for the following reasons:
| 1) |
Split Mineral Estate: When the minerals were transferred into the Company from HEDC, only the mineral rights from the surface to the base of the Bakken formation were transferred. Therefore, the Company does not accrue royalty revenue from gross production from the any formation below the Bakken formation relating to the mineral rights that were purchased from HEDC. | ||
| 2) |
Varying Lease Royalty Percentages: The Company has sixteen different leases, each with stated royalty percentages that vary from 16% to 20%. Each lease can support many wells. Therefore, the Company’s cumulative net royalty interest is affected by the number of wells producing from each lease. If more wells are producing from leases with lower stated royalty percentages, this will reduce the Company’s net royalty interests and reduce revenue as well. |
Operator Affiliate Sales
Many oil and natural gas production companies (operators) have wholly owned subsidiaries that purchase natural gas for resale. These sales, called affiliate sales, are not the result of an arm’s length transaction and are sometimes not permitted under the applicable mineral lease. Since royalties are based upon the gross revenue from the wellhead sale, the Company’s royalty revenue may be adversely impacted by such an affiliate sale.
Large Shareholders
Certain shareholders hold large portions of shares of the Company’s stock. As a result, the possibility exists that significant actions (such as voting or changing members of the Company’s Board of Directors) may occur by written consent rather than following a publicly filed document soliciting the vote or consent of the Company’s shareholders.
Risks Relating to the Ownership of Bakken Resources, Inc. Common Stock
Risks relating to low priced stocks will likely apply to our common stock.
Although our common stock is approved for trading on the OTC Bulletin Board, there has only been little trading activity in the stock. Accordingly, there is limited history on which to estimate the future trading price range of the common stock. If the common stock trades below $5.00 per share, trading in the common stock will be subject to the requirements of certain rules promulgated under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), which require additional disclosure by broker-dealers in connection with any trades involving a stock defined as a penny stock (generally, any non-FINRA equity security that has a market price share of less than $5.00 per share, subject to certain exceptions). Such rules require the delivery, prior to any penny stock transaction, of a disclosure schedule explaining the penny stock market and the risks associated therewith and impose various sales practice requirements on broker-dealers who sell penny stocks to persons other than established customers and accredited investors (generally defined as an investor with a net worth in excess of $1,000,000 or annual income exceeding $200,000 individually or $300,000 together with a spouse). For these types of transactions, the broker-dealer must make a special suitability determination for the purchaser and have received the purchaser’s written consent to the transaction prior to the sale. The broker-dealer also must disclose the commissions payable to the broker-dealer, current bid and offer quotations for the penny stock and, if the broker-dealer is the sole market-maker, the broker-dealer must disclose this fact and the broker-dealer’s presumed control over the market. Such information must be provided to the customer orally or in writing before or with the written confirmation of trade sent to the customer. Monthly statements must be sent disclosing recent price information for the penny stock held in the account and information on the limited market in penny stocks. The additional burdens imposed upon broker-dealers by such requirements could discourage broker-dealers from effecting transactions in the common stock which could severely limit the market liquidity of the common stock and the ability of holders of the common stock to sell it.
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Limitations on the liability of our directors and officers under our Articles of Incorporation and our Bylaws may result in us indemnifying such officers and directors.
Our Articles of Incorporation include provisions to eliminate, to the fullest extent permitted by Nevada General Corporation Law as in effect from time to time, the personal liability of directors of BRI for monetary damages arising from a breach of their fiduciary duties as directors. The Articles of Incorporation also includes provisions to the effect that we shall, to the maximum extent permitted from time to time under the laws of the State of Nevada, indemnify any director or officer. In addition, our bylaws require us to indemnify, to the fullest extent permitted by law, any director, officer, employee or agent of BRI for acts which such person reasonably believes are not in violation of our corporate purposes as set forth in the Articles of Incorporation.
Potential future issuances of additional common and preferred stock would dilute our current stockholders.
We are authorized to issue up to 100,000,000 shares of common stock. To the extent of such authorization, the board of directors of BRI will have the ability, without seeking stockholder approval, to issue additional shares of common stock in the future for such consideration as the board of directors may consider sufficient. The issuance of additional common stock in the future will reduce the proportionate ownership and voting power of the common stock offered hereby. We are also authorized to issue up to 10,000,000 shares of preferred stock, the rights and preferences of which may be designated in series by the board of directors. To the extent of such authorization, such designations may be made without stockholder approval. The designation and issuance of series of preferred stock in the future would create additional securities which would have dividend and liquidation preferences over the currently outstanding common stock. In addition, the ability to issue any future class or series of preferred stock could impede a non-negotiated change in control and thereby prevent stockholders from obtaining a premium for their common stock.
There is no assurance that a liquid public market for our common stock will develop.
Although our shares of common stock are currently eligible for quotation on the OTC Bulletin Board and the Pink Sheets, there has been no significant trading in our common stock. There has been no long term established public trading market for our common stock, and there can be no assurance that a regular and established market will be developed and maintained for the securities in the future. There can also be no assurance as to the depth or liquidity of any market for the common stock or the prices at which holders may be able to sell the shares.
The market price of our common stock is, and is likely to continue to be, highly volatile and subject to wide fluctuations.
In the event that a public market for our common stock is created, market prices for the common stock will be influenced by many factors, some of which are beyond our control, including:
| ● | 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 our competitors; |
| ● | our ability to take advantage of new acquisitions, reserve discoveries or other business initiatives; |
| ● | fluctuations in revenue from our oil and gas business as new reserves come to market; |
| ● | changes in the market for oil and natural gas commodities and/or in the capital markets generally; |
| ● | changes in the demand for oil and natural gas, including changes resulting from 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; |
| ● | 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 oil and 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 stockholders 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/or our results of operations and financial condition.
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Litigation
The Company is currently and has been a defendant in several lawsuits brought by various company shareholders. The outcome of litigation could, in the extreme, undermine the company’s liquidity by draining cash in its defense and potential judgments, could undermine profitability, and could undermine Bakken’s stock price if the litigation caused an inordinate amount of shares to hit the marketplace in a short time period.
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 production royalty, assuming commercial oil and gas is discovered on our mineral rights property. Our revenues and operating expenses, expenses that we incur regarding investments in drilling programs with other partners, the prices of oil and natural gas in the commodities markets and other factors, may all cause significant fluctuations in our operating results. If our results of operations do not meet the expectations of current or potential investors, the price of our common stock may decline.
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. Therefore, investors will not receive any funds unless they sell their common stock, and stockholders 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 and warrants.
Risks Related To the Oil and Gas Industry
Oil and natural gas prices are very volatile. A protracted period of oil and natural gas prices below the prices currently in effect may adversely affect our business, financial condition, results of operations, or cash flows.
The oil and gas markets are very volatile, and we cannot predict future oil and natural gas prices. The price our oil company Lessees receive for oil and natural gas production on our mineral rights property heavily influences our royalty revenue, profitability, access to capital and future rate of growth. The prices our Lessees receive for their production and the levels of their production depend on numerous factors beyond our control. These factors include, but are not limited to, the following:
| ● | The domestic and foreign supply of oil and nature gas; |
| ● | The current level of prices and expectations about future prices of oil and natural gas; |
| ● | The level of global oil and natural gas exploration and production; |
| ● | The cost of exploring for, developing, producing and delivering oil and natural gas; |
| ● | The price of foreign oil and natural gas imports; |
| ● | Political and economic conditions in oil producing regions, including the Middle East, Africa, South America and Russia; |
| ● | The ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls; |
| ● | Speculative trading in oil and natural gas derivative contracts; |
| ● | The level of consumer product demand; |
| ● | Weather conditions and other natural disasters; |
| ● | Risks associated with operating drilling rigs; |
| ● | Technological advances affecting energy consumption; |
| ● | Domestic and foreign governmental regulations and taxes; |
| ● | The continued threat of terrorism and the impact of military and other action, including U.S. military operations in the Middle East; |
| ● | The availability, proximity and capacity of oil and natural gas transportation, processing, storage and refining facilities; |
| ● | The price and availability of alternative fuels; and |
| ● | Overall domestic and global economic conditions. |
Furthermore, the recent worldwide financial and credit crisis has reduced the availability of liquidity and credit to fund the continuation and expansion of industrial business operations worldwide. The shortage of liquidity and credit combined with recent substantial losses in worldwide equity markets has led to a worldwide economic recession. The slowdown in economic activity caused by such recession has reduced worldwide demand for energy and resulted in lower oil and natural gas prices.
Lower oil and natural gas prices will decrease the revenues of our Lessees, but also may reduce the amount of oil and natural gas that the Lessees can produce economically and therefore potentially lower our anticipated production royalty income. A substantial or extended decline in oil or natural gas prices may result in impairments of our proved oil and gas property, if it reaches production, of which there is no assurance 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 any such shortfall. Lower oil and natural gas prices may also reduce BRI’s ability to establish a borrowing base under a credit agreement, which is determined at the discretion of the lenders based on the collateral value of any proved reserves.
23
Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect our business, financial condition, or results of operations.
Initially, our future success will depend on the success of our development, exploitation, production, and exploration activities conducted by our Lessees as our operators on our mineral rights property. Oil and natural gas exploration and production activities are subject to numerous risks beyond our control; including the risk that drilling will not result in commercially viable oil or natural gas production. Our decisions to participate in drilling projects, purchase mineral rights, explore, develop or otherwise exploit prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. The cost of drilling, completing, and operating wells is often uncertain before drilling commences. Overruns in budgeted expenditures are common risks that can make a particular project uneconomical. Furthermore, many factors may curtail, delay or cancel drilling, including the following:
| ● | delays imposed by or resulting from compliance with regulatory requirements; |
| ● | pressure or irregularities in geological formations; |
| ● | shortages of or delays in obtaining qualified personnel or equipment, including drilling rigs and CO2; |
| ● | equipment failures or accidents; |
| ● | adverse weather conditions, such as freezing temperatures, hurricanes and storms; |
| ● | unexpected operational events, including accidents; |
| ● | reductions in oil and natural gas prices; |
| ● | proximity to and capacity of transportation facilities; |
| ● | title problems; and |
| ● | limitations in the market for oil and natural gas. |
Exploration for oil and gas is risky and may not be commercially successful, and the advanced technologies to be used by our oil company Lessees cannot eliminate exploration risk, which could impair our ability to generate revenues from our production royalty income.
Our future success will depend on the success of exploratory drilling conducted by the Lessees on our mineral rights property. Oil and gas exploration involves a high degree of risk. These risks are more acute in the early stages of exploration. Our ability to produce revenue and our resulting financial performance are significantly affected by the prices we receive for oil and natural gas produced from wells on our acreage, if any. Especially in recent years, the prices at which oil and natural gas trade in the open market have experienced significant volatility, and will likely continue to fluctuate in the foreseeable future due to a variety of influences including, but not limited to, the following:
| ● | domestic and foreign demand for oil and natural gas by both refineries and end users; |
| ● | the introduction of alternative forms of fuel to replace or compete with oil and natural gas; |
| ● | domestic and foreign reserves and supply of oil and natural gas; |
| ● | competitive measures implemented by our competitors and domestic and foreign governmental bodies; |
| ● | political climates in nations that traditionally produce and export significant quantities of 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; |
| ● | weather conditions; and |
| ● | domestic and foreign economic volatility and stability. |
Expenditures on exploration on our mineral rights property may not result in new discoveries of oil or natural gas in commercially viable quantities. It is difficult to project the costs of implementing exploratory horizontal drilling programs on our acreage due to the inherent uncertainties of drilling in unknown formations, the costs associated with encountering various drilling conditions, such as over-pressured zones and tools lost in the hole, and changes in drilling plans and locations as a result of prior exploratory wells or additional seismic data and interpretations thereof.
Even when used and properly interpreted, three-dimensional (3-D) seismic data and visualization techniques only assist geoscientists in identifying subsurface structures and hydrocarbon indicators. They do not allow the interpreter to know conclusively if hydrocarbons are present or economically producible. In addition, the use of three-dimensional (3-D) seismic data becomes less reliable when used at increasing depths. Our Lessees could incur losses as a result of expenditures on unsuccessful wells on our acreage. If exploration costs exceed estimates, or if exploration efforts do not produce results which meet expectations of our Lessees, exploration efforts may not be commercially successful, which could adversely impact our Lessees’ ability to generate revenues from operations on our acreage.
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Estimates of proved oil and natural gas reserves are uncertain and any material inaccuracies in these reserve estimates will materially affect the quantities and the value of our reserves.
The process of estimating oil and natural gas reserves is complex. This process requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for such reservoir. Therefore, these estimates are inherently imprecise. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will vary from those estimated. Any significant variance could materially affect the estimated quantities and the value of our reserves.
Our oil company Lessees may not be able to develop oil and gas reserves on an economically viable basis on our mineral rights property.
If our oil company lessees succeed in discovering oil and/or natural gas reserves, we cannot be assured that these reserves will be capable of long-term sustainable production levels or in sufficient quantities to be commercially viable. On a long-term basis, our viability depends on our Lessees’ ability to find or acquire, develop and commercially produce additional oil and natural gas reserves on our acreage. Our future revenue will depend not only on the Lessees ability to develop our acreage, but also on our ability to identify and acquire additional suitable producing properties or prospects, to find markets for the oil and natural gas if we can develop a prospect and to effectively distribute any production into our markets.
Future oil and gas exploration may involve unprofitable efforts, not only from dry wells, but from holes that are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other costs. 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. While our Lessees will endeavor to effectively manage these conditions, they cannot be assured of doing so optimally, and they will not be able to eliminate them completely in any case. Therefore, these conditions could diminish our royalty revenue and cash flow levels and result in the impairment of our oil and natural gas interests.
Environmental regulations may adversely affect our business.
All phases of the oil and 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 oil and 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 oil, natural gas, or other pollutants into the air, soil or water may give rise to liabilities to governments and third parties and may require us to incur costs to remedy such discharge.
The application of environmental laws to our business may cause us to curtail our production or increase the costs of our production, development or exploration activities.
Federal or state hydraulic fracturing legislation could increase our Lessees’ costs or restrict their access to oil and natural gas reserves.
Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. The process involves the injection of water, sand and chemicals under pressure into the targeted subsurface formations to fracture the surrounding rock and stimulate production. Hydraulic fracturing using fluids other than diesel is currently exempt from regulation under the federal Safe Drinking Water Act (the “SDWA”), but opponents of hydraulic fracturing have called for further study of the technique’s environmental effects and, in some cases, a moratorium on the use of the technique. Several proposals have been submitted to Congress that, if implemented, would subject all hydraulic fracturing to regulation under SDWA. Eliminating this exemption could establish an additional level of regulation and permitting at the federal level that could lead to Our Lessees’ operational delays or increased their operating costs and could result in additional regulatory burdens that could make it more difficult to perform hydraulic fracturing and increase our Lessees’ cost of compliance and doing business. In addition, the EPA’s Office of Research and Development is conducting a scientific study to investigate the possible relationships between hydraulic fracturing and drinking water. The results of that study, which are expected to be available in draft during 2014 for peer review and public comment, could advance the development of additional regulations.
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Moreover, the EPA has announced that it will develop effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities in 2014. The U.S. Department of Energy has conducted an investigation into practices the agency could recommend to better protect the environment from drilling using hydraulic fracturing completion methods and issued a report in 2011 on immediate and longer-term actions that may be taken to reduce environmental and safety risks of shale gas development. Also, in May 2013, the federal Bureau of Land Management published a supplemental notice of proposed rulemaking governing hydraulic fracturing on federal and Indian oil and gas leases that would require public disclosure of chemicals used in hydraulic fracturing, confirmation that wells used in fracturing operations meet appropriate construction standards, and development of appropriate plans for managing flowback water that returns to the surface. These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the federal SDWA or other regulatory mechanisms.
Although it is not possible at this time to predict the final outcome of the se ongoing or proposed studies or the requirements of any additional federal or state legislation or regulation regarding hydraulic fracturing, any new federal, state, or local restrictions on hydraulic fracturing that may be imposed in areas where we conduct business, such as the Bakken and Three Forks areas, could significantly increase our Lessees’ operating, capital and compliance costs as well as delay or halt our ability to develop oil and natural gas reserves.
Possible regulation related to global warming and climate change could have an adverse effect on our operations and demand for oil and natural gas.
Based on findings by the EPA in December 2009 that emissions of GHGs present and endangerment to public health and the environment because emissions of such gases are contributing to warming of the Earth’s atmosphere and other climatic changes, the EPA adopted regulations under existing provisions of the CAA that establish PSD construction and Title V operating permit reviews for certain large stationary sources that are potential major sources of GHG emissions. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards that will be established by the states or the EPA. The EPA has also adopted rules requiring the monitoring and reporting of GHG emissions from specified sources in the United States, including, among others, certain onshore oil and natural gas production facilities on an annual basis, which includes certain f our operations. While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting those GHGs. If Congress undertakes comprehensive tax reform in the coming year, it is possible that such reform may include a carbon tax, which could impose additional direct costs on our operations and reduce demand for refined products. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events; if any such effects were to occur, they could have an adverse effect on our Lessees’ exploration and production operations.
Our business will suffer if we cannot obtain or maintain necessary licenses.
Our oil company Lessees’ proposed exploration and drilling operations on our mineral rights property will require licenses, permits, bonds, and in some cases renewals of licenses and permits from various governmental authorities. Our Lessees’ ability 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 governments, among other factors. Our Lessees’ inability to obtain, or our loss of or denial of extension of, any of these licenses or permits could hamper our ability to produce revenues from our operations.
Lessees may have difficulty distributing oil or natural gas production, which could harm our financial condition.
In order to sell the oil and natural gas that our Lessees may be able to produce, they will have to make arrangements for storage and distribution to the market. They 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 their needs at commercially acceptable terms in the immediate area of our leases. This 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 Lessees’ ability to explore and develop our property and to store and transport oil and natural gas production and may increase expenses.
Furthermore, weather conditions or natural disasters, actions by companies doing business in one or more of the areas where our property is located. Labor disputes may impair the distribution of oil and/or natural gas and in turn diminish our financial condition or ability to generate royalty income, if commercial wells are drilled and completed on our property, of which there is no assurance.
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Challenges to our property rights may impact our financial condition.
Title to oil and 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, if a legal dispute concerning such property occurs, 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 Lessees’ ability to conduct our exploration, development and production activities may be impaired.
Certain U.S. federal income tax deductions currently available with respect to oil and gas exploration and development may be eliminated as a result of proposed legislation.
President Obama’s budget proposal for fiscal year 2014 recommended the elimination of certain key United States federal income tax preferences currently available to oil and natural gas exploration and production companies. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for United States production activities for oil and gas production, and (iv) the extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether any such changes or similar changes will be enacted or, if enacted, how soon any such changes could become effective. The passage of this legislation or any other similar changes in U.S. federal income tax law could affect certain tax deductions that are currently available with respect to oil and gas exploration and production. Any such changes could have an adverse effect on our financial position, results of operations and cash flows primarily because such changes may impact the operations of our operators from whom we currently derive substantially all of our revenues.
We are not geographically diversified and rely almost exclusively on production from the Bakken Formation.
Production and transportation costs in the Bakken Formation are high relative to some other oil-producing regions in the United States. Seasonal weather conditions in this particular region of the United States can become severe, which may further impact both production and transportation costs. Even though the Bakken Formation is widely believed to be capable of producing large quantities of oil and natural gas using horizontal drilling techniques, the predictions underlying that belief could prove to be incorrect, and horizontal drilling techniques may not continue to be effective or may be impacted by changes in applicable law or regulations. There is also no guarantee that the specific portions of the Bakken Formation comprising the Company’s assets will be profitable even if the Bakken Formation as a whole continues to generate profitability. These risks result from only a few of the things upon which continued operational success in the Bakken region relies, and the Company cannot anticipate every reason the Bakken Formation may become economically unprofitable for the Company. If one or more of these or any other risk materializes (whether foreseen or not), the impact could materially harm the Company because the majority of its assets are located in the Bakken region.
Description of Certain Property and Leases
General
On December 1, 2010, BRI entered into a one-year office lease for its principal office in Helena, Montana, renewable for up to five years, for a 2,175 square foot executive office, for a monthly charge of $1,600 for the first year; $1,800 second year; $2,000 third year; $2,200 fourth year; and $2,400 fifth year. In addition to the principal office, BRI also maintains a part-time office in New York City which is fixed at $3,000 per month.
The Company also maintains an apartment in Helena, Montana to provide accommodation to the Chief Financial Officer who travels to Helena weekly to work at the principal office. The monthly rent for the apartment is $650 per month and is under a one year lease that expired in October 2013 and renewed on a month to month basis thereafter.
As of December 31, 2013 BRI owns mineral rights for 7,200 (net 2,400) acres in the Bakken/Three Forks in North Dakota and approximately 2,200 acres in the Duck Lake area of Montana. We own a 50% net mineral interest in the Duck Lake acreage minerals. The Duck Lake Property is currently unleased.
The BRI mineral rights are leased primarily to three well operators, Oasis Petroleum, Continental Resources and Statoil ASA (formerly, Brigham Oil). As of December 31, 2013, we have received division orders and/or royalty payments for thirty (30) Bakken formation wells, twelve (12) Three Forks formation wells, and three (3) Madison formation wells.
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The Duck Lake mineral rights were leased until September 2013 but have not been developed as of December 31, 2013.
On September 21, 2011, the Company’s Board of Directors approved the purchase of the Duck Lake minerals from Lincoln Green, Inc (“LGI”). Under the terms of the agreement, the Company agreed to pay LGI $250,000 for approximately a 50% interest in 2,200 net mineral acres. No drilling operations have commenced yet on the Duck Lake property.
The following table presents information about the produced oil and gas volumes for the years ended December 31, 2013 and 2012. The information comes from the NDIC website and royalty payments received from the well operators. As of December 31, 2013, the Company has received division orders for thirty (30) Bakken formation wells, twelve (12) Three Forks formation wells, and three Madison formation wells. The reported amounts are from those wells. The Company did not begin operations until late 2010.
| Year Ended | ||||||
| December 31 | ||||||
| 2013 | 2012 | |||||
| Net Production | ||||||
| Oil (Bbl) | 3,354,315 | 1,316,591 | ||||
| Natural Gas (Mcf) | 2,822,795 | 442,447 | ||||
| Average Sales Price | ||||||
| Oil (per Bbl) | $ | 85.25 | $ | 85.16 | ||
| Natural Gas (per Mcf) | $ | 5.72 | $ | 6.19 | ||
The Company’s royalty payments from the production noted above vary by well. Wells are drilled in spacing units which are typically initially set by the NDIC at 1,280 acres or two sections but can include up to four sections. The royalty percentage is determined based on the amount of mineral interest acreage owned by BRI and the lease rate for that acreage. Because the mineral interest owned by BRI varies by well, the royalty percentage also varies. Our average royalty for the thirty (30) Bakken formation wells and twelve (12) Three Forks formation wells is approximately 1.35%. Using the numbers shown above, if the reported oil production was sold at the average sales price of $85.16 per barrel, gross revenue would be $285,854,724. Multiplying the average royalty percentage of 1.35% times the gross revenue results in a royalty payment of $3,859,039. Actual royalty payments received by BRI in 2013 total $3,972,570.
Depletion of oil and natural gas properties
Our depletion expense is driven by estimates of well production, estimates of number of wells to be drilled and the cost to acquire mineral leases. Depletion expense of $444,737 was recorded in 2012. Depletion expense of $325,598 was recorded during the year ended December 31, 2013.
Location of BRI’s Mineral Rights
The following contains the descriptions and map of the locations where our mineral acreage is currently located (also includes locations of certain wells located on our properties).
| TOWNSHIP 151 NORTH, RANGE 100 WEST | |
| Section 5: | Lot 3 (40.06), 4 (40.02), S/2 NW/4, SW/4NE/4, E/2SW/4, SE/4SW/4 |
| Section 6: | Lots 2, 3; SW1/4 NE1/4, SE1/4, NWI/4, NW1/4 SE1/4, SE1/4, SE1/4 |
| TOWNSHIP 152 NORTH, RANGE 100 WEST | |
| Section 5: | SW1/4 SW1/4 |
| Section 6: | S1/2 SE1/4, SE1/4 SW1/4 Lot 14, |
| Section 7: | Lots 1,2,3,4; E1/2 SW1/4, E1/2, E1/2 NW1/4 |
| Section 8: | SE 1/4 SE 1/4, SW1/4, W1/2 NWl/4,SE 1/4 NW1/4, SW1/4 SE1/4 |
| Section 9: | Lots 1,2,3,4; SW 1/4 NW1/4, NE 1/4 SW1/4, SW1/4 SE 1/4, |
| Sl/2 SW1/4, NW1/4 SWl/4, SE1/4 SE1/4 | |
| Section 10: | Lots 2, 3,4; S 1/2 SW1/4 |
| Section 15: | NE 1/4 NW1/4 |
| Section 17: | NE 1/4, E1/2 NW1/4, NW1/4 NW1/4, N1/2 SW1/4 NW1/4, SE ¼, |
| E1/2 SW1/4, S1/2 SW1/4, NW1/4, W1/2 SW1/4 | |
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| Section 18: | N1/2 NE1/4, NE1/4 NW1/4, Lot 1 | |
| Section 20: | All | |
| Section 21: | All | |
| Section 22: | W 1/2 W1/2, SE1/4 SW1/4, NE1/4 SE1/4, S1/2, SE1/4, NE1/4 | |
| SW1/4 NW1/4 SE1/4, E1/2 NWl/4 | ||
| Section 23: | W1/2 SWl/4 | |
| Section 29: | NE1/4, N1/2 NW1/4 | |
| Section 30: | Lots 3,4; El/2 SWl/4, W1/2 SE 1/4 | |
| Section 31: | Lots 1,2,3,4; E1/2 W1/2, E1/2 | |
| Section 32: | SE 1/4 NW1/4, W1/2 W1/2, NE 1/4SW ¼, SENE, NESE | |
| TOWNSHIP 152 NORTH, RANGE 101 WEST | ||
| Section 1: | SE 1/4 SE 1/4 | |
| Section 12: | SE1/4 NE1/4, E1/2 SE1/4, NE1/4 NE1/4 | |
| Section 13: | N1/2 NE1/4, NW1/4 | |
| Section 24: | SW1/4 | |
| Section 25: | NW 1/4 NE 1/4, S1/2 NE 1/4, N1/2 NW 1/4, SE1/4 NW1/4, NE 1/4 | |
| SW1/4, N1/2 SE1/4, SE1/4SE1/4 | ||
| Section 26: | SE 1/4 | |
| Section 35: | NE 1/4NE 1/4, S1/2 NE 1/4, SE 1/4 NW1/4 | |
To read this table or to check the location on a map, begin with the heading at the top and read down the side for a specific section, then read across for the description of the acreage owned by BRI. For example, in Township 151 North, Range 100 West, BRI owns acreage in Section 6. Specifically, BRI owns Lots 2 and 3 in that Section. In addition, we also own the Southwest quarter of the Northeast quarter of the section, the Southeast quarter, the Northwest quarter, the Northwest quarter of the Southeast quarter.
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Well Map Updated January
2013
Map Shows Drilling Units for
Bakken Resources, Inc.
McKenzie
County, N.D.
(Each section is
approximately 640 acres or one (1) square mile)
Description of Oil Leases and Oil Production
As of December 31, 2013, our properties in North Dakota are leased primarily to three operators: Oasis Petroleum, Continental Resources, and Statoil ASA. The executed oil leases cover various parcels of land in the same general region, primarily in McKenzie County, North Dakota. The leases have lease periods of between 3 and 8 years with starting dates from March 2003 to December 2009. All but three of the leases have landowner royalties’ payable by the oil company Lessees on gross proceeds from oil and gas production of 17%. Currently, most of the leases covering the Company’s mineral acres contain what is commonly referred to as “continuous drilling clauses”. Generally, a continuous drilling clause requires an operator to maintain active drilling operations in order to hold or extend an oil and gas lease past the natural expiration date of the lease. A majority of the Company’s current leases currently have active drilling operations and are likely to have active operations in the foreseeable future.
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The following table describes in general a representative sample of the leases held by the Company. From time to time, leases may be divided or consolidated among various lessees without prior consent or notification to the Company so such table is intended for illustrative purposes only.
| Total | ||||||||||||
| Landowner | ||||||||||||
| Legal | Lease | Gross | Net | Original | Current | Royalty | ||||||
| Description | Period | Acres | Acres | Leasee | Leasee | Percentage | ||||||
| 151N, R100W, Section 6: Lots 2(40.00),3(40.00), SE4NW4, SW4NE4 | 7/29/08-7/29/13 | 1203.10 | 614.36 | Empire Oil |
Statoil | 17.00% | ||||||
| 152N, R100W, Sec 8: NW4NW4, S2NW4, SW4, S2SE4, NE4NE4 | " | Empire Oil |
Oasis Petroleum |
17.00% | ||||||||
| 152N, R100W, Sec 9: Lots 1(21.20), 2(26.60),
3(42.10), 4(43.00), SW4NW4, SW4, S2SE4 |
" | Empire Oil |
Continental Resources |
18.75/20% | ||||||||
| 152N, R100W, Sec 10: Lots 2(18.80),3(17.20),4(34.20), S2SW4 | " | Empire Oil |
Continental Resources |
17.00% | ||||||||
| 152N, R100W, Sec 15: NE4NW4 | " | Empire Oil |
Oasis Petroleum |
17.50% | ||||||||
| 152N, R101W, Sec 1: SE4SE4 | " | Empire Oil |
Oasis Petroleum |
17.00% | ||||||||
| 152N, R100W, Sec 5: SWSW | 7/14/08-7/14/13 | 193.38 | 95.30 | Empire Oil |
Oasis Petroleum |
17.00% | ||||||
| 152N, R100W, Sec 6: Lot 14(33.38) S2SE, SESW | " | Empire Oil |
Oasis Petroleum |
17.00% | ||||||||
| 152N, R100W, Sec 7: Lot 1(33.53), Lot 2(33.55), E2NW4, NE4 | 3/1/05-3/1/12 | 307.08 | 150.87 | Sundance | Oasis Petroleum |
16-17.5% | ||||||
| 152N, R100W, Sec 17: All plus all accretions and riparian rights thereto | 9/9/03-9/9/11 | 2227.22 | 792.86 | Empire Oil |
Oasis Petroleum |
17.00% | ||||||
| 152N, R100W, Sec:7: Lots 3(33.63), 4(33.59), E2SW, SE Plus all accretions and riparian rights thereto | “ | Empire Oil |
Oasis Petroleum |
16-17.5% | ||||||||
| 152N, R100W, Sec 20 All | " | Empire Oil |
Oasis Petroleum |
17.00% | ||||||||
| 152N, R100W, Sec 21 All | " | Empire Oil |
Continental Resources |
17.00% | ||||||||
| 152N, R100W, Sec 18: Lot 1(33.63), NENW, N2NE | 5/21/09-5/21/12 | 393.63 | 153.45 | Empire Oil |
Oasis Petroleum |
18.75% | ||||||
| 152N, R101W, Sec 13: N2NE, NW | " | Empire Oil |
Oasis Petroleum |
18.75/20% | ||||||||
| 152N, R100W, Sec 22: W2, SE4 | 1/19/05-1/19/12 | 480.00 | 156.57 | Armstrong | Oasis Petroleum |
17-17.5% | ||||||
| 152N, R100W, Sec 23: W2SW | 7/14/08-7/14/11 | 80.00 | 19.43 | Empire Oil |
Continental Resources |
20.00% | ||||||
| 152N, R100W Sec 29: NE, N2NW | 11/24/04-11/24/11 | 1028.68 | 140.98 | Empire Oil |
Oasis Petroleum |
17.00% | ||||||
| 152N, 100W, Sec 30, Lot 3 (34.31), Lot 4
(34.37), E1/2SW1/4, W1/2SE1/4 |
||||||||||||
| 152N, 101W, Sec 24 SW1/4 | ||||||||||||
| 152N, R101W, Sec 25: NWNE, S2NE, N2NW, SENW,
NESW, N2SE, SESE |
" | Empire Oil |
Statoil | 17.00% | ||||||||
| 152N, R100W, Sec 31: Lot 1(34.43), 2(34.49),
3(34.55), 4(34.61), E2W2, E2 |
7/14/08-6/10/12 | 858.08 | 197.27 | Empire Oil |
Oasis Petroleum |
16.67-17% | ||||||
| 152N, R100W, Sec 32: W2W2, SENW, NESW | " | Empire Oil |
Oasis Petroleum |
17.00% | ||||||||
| 4/8/2008 - | 6.93 | Diamond | ||||||||||
| 152N, R101W, Sec 26 SE, except 6.32 acres | 4/8/2011 | 153.68 | Resources | 17% | ||||||||
| 152N, R101W, Sec 35: E 1/2 NE 1/4, SW 1/4 NE 1/4, SE 1/4 NW 1/4 | 9/13/2002 - 9/13/2005 |
160.00 | 7.22 | Diamond Resources |
Statoil | 15/22% |
Note: The gross and net amounts are slightly lower than amounts that appear elsewhere in this document. There are 160 gross mineral acres and 78 net mineral acres not covered by lease.
31
The landowner royalty interest is the revenue royalty paid by the contracted oil drilling company (Oasis Petroleum for example) on whatever oil and gas revenue they generate from the particular lease. If Oasis Petroleum generates $100,000 in oil and gas revenue from acreage subject to the BRI landowner royalty of 17%, BRI would receive in royalty payments of $17,000 (assuming that we have 100% of the acreage under the applicable spacing unit). Using the same example, pursuant to the 5% overriding royalty interest on all oil and gas revenue received by BRI from the assets purchased from Holms Energy for ten years (measured from the date of purchase), Holms Energy would receive a 5% over-riding royalty payment of $5,000 from BRI, thus resulting in a net payment of $12,000 to BRI. Royalties paid to BRI are adjusted to reflect the number of net mineral acres underlying the spacing under which the producing well is drilled.
To illustrate, the leases with Oasis Petroleum do not specify which geological formation must be drilled, but they are specific to oil and gas hydrocarbon drilling. The leases do not impose any performance criteria on the Lessees except the date that well is required to be drilled. We have no control over any operating decisions made by Oasis Petroleum as it relates to: (1) which formation it will drill; (2) levels at which the well will be produced; (3) who Oasis Petroleum uses as contractor for drilling and completing wells; (4) who Oasis Petroleum sells the oil and gas to; or (5) any influence on any aspect of recovery.
Once a well is drilled and production established, of which there is no assurance, the lease is considered “held by production,” meaning the lease continues as long as oil is being produced. As of December 31, 2013, drilling activity on the Company’s mineral acreage is likely to hold by production most if not all of the Company’s leases Several of our leases, however, require the operator to have “continuous” drilling operations which would require the operator to continue drilling activities in order to qualify the lease to be held by production. 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. The Company is currently conducting an internal audit of its leases and mineral acreage holdings.
Given the recent drilling activity on our properties as well as the relatively recent development of horizontal drilling techniques in general, a proven reserve estimate is not obtainable at this time. Operators have estimated that the range of recoverable barrels of oil from a particular producing well can vary from 200,000 to as high as 1,000,000 barrels during its viable lifetime. (Source: http://www.milliondollarwayblog.com/p/faq.html)
On April 2, 2012, BRI was served with a summons relating to a complaint filed by Allan Holms, both individually and derivatively through Roil Energy, LLC. Allan Holms is the half-brother of BRI’s CEO, Val Holms. The complaint (filed in the Superior Court of the State of Washington located in Spokane County) names, among others, Joseph Edington, Val and Mari Holms, Holms Energy, LLC and BRI as defendants. The Complaint primarily alleges breach of contract, tortious interference with prospective business opportunity and fraud. The complaint focuses on events allegedly occurring around February and March 2010 whereby Allan Holms alleged an oral agreement took place whereby he was to receive up to 40% of the originally issued equity of Roil Energy, LLC. Allan Holms alleges Roil Energy was originally intended to be the predecessor entity to BRI. Both Mr. Val Holms, our CEO, and BRI dispute such allegations in their entirety and intend to and have vigorously defended against such claims. This case went to trial in November 2013. Following trial, the Court issued conclusions that the evidence presented in this case did not support Allan Holms’ claims that an oral agreement existed. Post-trial motions are currently being heard in this case and final judgment is expected to be issued following the conclusion of such post-trial motions.
On June 6, 2012, the Company filed a Temporary Restraining Order (the “TRO”) and Verified Complaint for Injunctive Relief against McKinley Romero, Peter Swan Investment Consulting Ltd and IWJ Consulting Group, LLC (collectively, the “Defendants”), in connection with the Defendants’ request to the transfer agent to remove restrictive legends from an aggregate of 4.7 million shares, which the Company believes were improperly obtained by the Defendants. The Company obtained the TRO from the Second Judicial District Court of the State of Nevada, County of Washoe on June 6, 2012 enjoining the Defendants from seeking removal of the restrictive legends. On a scheduled hearing on June 26, 2012 the judge in this matter ruled in favor of the Company’s motion for a preliminary injunction. The order granting such preliminary injunction was issued from this court on August 14, 2012. This matter is pending the Company’s motion for final judgment in favor of the Company.
In March 2013, the Company received notice of a complaint titled Gillis v. Bakken Resources, Inc., Case No. A-13-675280-B, filed in the District Court of the State of Nevada for Clark County. Mr. Gillis, the plaintiff in this matter (the “Gillis Case”), is the trustee of the Bruce and Marilyn Gillis 1987 Trust. Mr. Gillis is the Trustee of such trust. Mr. Gillis is alleging that Client breached certain registration rights obligations pursuant to an equity investment made at or around November 2010. The Court in this matter granted class certification and class notice in March 2014. The Company denies the validity of the claims made in the Gillis Case and intends to vigorously defend against such claims.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
32
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES.
Market Information
BRI’s common stock was approved for quotation on the OTC Bulletin Board of the National Association of Securities Dealers (“NASD”) on July 29, 2009, under the symbol “MLTX”, and that symbol was changed to “BKKN” on December 17, 2010. A limited public market for our common stock has developed on the OTC Bulletin Board. For purposes of this Item the existence of limited or sporadic quotations should not of itself be deemed to constitute an “established public trading market”.
For any market that develops for our common stock, the sale of “restricted securities” (common stock) pursuant to Rule 144 of the Securities and Exchange Commission by members of management or any other person to whom any such securities were issued or may be issued in the future may have a substantial adverse impact on any such public market. Present members of management and shareholders at December 2, 2010 when BRI ceased to be a “shell” company, satisfied the one year holding period of Rule 144 for public sales of their respective holdings in accordance with Rule 144 on December 2, 2011. See the caption “Recent Sales of Unregistered Securities”, of this Item, below. A minimum holding period of one year is required for resales under Rule 144 for shareholders of former shell companies, along with other pertinent provisions, including publicly available information concerning BRI, limitations on the volume of restricted securities which can be sold in any ninety (90) day period, the requirement of unsolicited broker’s transactions and the filing of a Notice of Sale on Form 144. The quoted bid or asked price for the shares of common stock of BRI for the quarterly periods from January 1, 2013 through December 31, 2013 ranged from $0.10 to $0.28.
Holders
The number of record holders of BRI’s common stock as of the date of this Report is approximately 157.
Dividends
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 have not paid or declared any dividends upon our common stock since our inception and, by reason of our present financial status and our contemplated financial requirements; we do not anticipate paying any dividends upon our common stock in the foreseeable future.
We have never declared or paid any cash dividends. We currently do not intend to pay cash dividends in the foreseeable future on the shares of common stock. We intend to reinvest any earnings or proceeds we may receive in the development or expansion of our business. There can be no assurance that any dividends on the common stock will ever be paid because any cash dividends in the future to common stockholders will be payable when, as and if declared by our Board of Directors, based upon the Board’s assessment of:
| ● | our financial condition; |
| ● | earnings; |
| ● | need for funds; |
| ● | capital requirements; |
| ● | prior claims of preferred stock to the extent issued and outstanding; and |
| ● | other factors, including any applicable laws. |
Securities Authorized for Issuance under Equity Compensation Plans
Stock Option Plan
The Board of Directors of our predecessor approved the Stock Option Plan on November 3, 2008 and then on June 16, 2010, authorized an increase in the total common stock, $.001 par value, available in the Company's 2008 Non-Qualified Stock Option and Stock Appreciation Rights Plan from one million (1,000,000) shares to five million (5,000,000) shares (the “2008 Option Plan”), to be granted to officers, directors, consultants, advisors, and other key employees of BRI and its subsidiaries. This was ratified by the shareholders on November 12, 2010 (when the Company was known as Multisys Language Solutions, Inc.). The total number of options that can be granted under the plan will not exceed 5,000,000 shares. Non-qualified stock options will be granted by the Board of Directors with an option price not less than the fair market value of the shares of common stock to which the non-qualified stock option relates on the date of grant. In no event may the option price with respect to an incentive stock option granted under the stock option plan be less than the fair market value of such common stock.
Each option granted under the 2008 Option Plan will be assigned a time period for exercising not to exceed ten years after the date of the grant. Certain other restrictions will apply in connection with this plan when some awards may be exercised. This plan is intended to encourage directors, officers, employees and consultants to acquire ownership of common stock. The opportunity so provided is intended to foster in participants a strong incentive to put forth maximum effort for BRI’s continued success and growth, to aid in retaining individuals who put forth such effort, and to assist in attracting the best available individuals to BRI in the future.
33
The following table sets forth information about the common stock available for issuance under compensatory plans and arrangements as of December 31, 2013. There are no equity compensation plans not approved by security holders.
| Plan Category | Number of securities to be issued | Weighted-average exercise | Number of securities remaining |
| upon exercise of outstanding | price of outstanding options, | available for future issuance under | |
| options, warrants, and rights. | warrants, and rights | equity compensation plans (excluding | |
| securities reflected in column (a)) | |||
| (a) | (b) | (c) | |
| Equity compensation plan | |||
| approved by security holders | 500,000 | $0.10 | 4,500,000 |
| Total | 500,000 | $0.10 | 4,500,000 |
The transfer agent of BRI is Nevada Agency and Transfer Company, located at 50 W Liberty St, Ste 880, Reno, NV, 89501.
Recent Sales of Unregistered Securities; Use of Proceeds from Unregistered Securities
Since December 31, 2012, the Company has not entered in any sales of unregistered securities.
ITEM 6. SELECTED FINANCIAL DATA
Not applicable for smaller reporting companies.
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
Caution Regarding Forward-Looking Information
All statements contained in this Form 10-K, other than statements of historical facts, that address future activities, events or developments are forward-looking statements, including, but not limited to, statements containing the words “believe,” “expect,” “anticipate,” “intends,” “estimate,” “forecast,” “project,” and similar expressions. All statements other than statements of historical fact are statements that could be deemed forward-looking statements, including any statements of the plans, strategies and objectives of management for future operations; any statements concerning proposed new acquisitions, products, services, developments or industry rankings; any statements regarding future economic conditions or performance; any statements of belief; and any statements of assumptions underlying any of the foregoing. These statements are based on certain assumptions and analyses made by us in light of our experience and our assessment of historical trends, current conditions and expected future developments as well as other factors we believe are appropriate under the circumstances. However, whether actual results will conform to the expectations and predictions of management is subject to a number of risks and uncertainties described under “Risk Factors” under Item 1A above that may cause actual results to differ materially.
Consequently, all of the forward-looking statements made in this Form 10-K are qualified by these cautionary statements and there can be no assurance that the actual results anticipated by management will be realized or, even if substantially realized, that they will have the expected consequences to or effects on our business operations. Readers are cautioned not to place undue reliance on such forward-looking statements as they speak only of the Company's views as of the date the statement was made. The Company undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.
Overview
BRI is an oil and gas company, with leased mineral interest properties located mostly in the Bakken. As of December 31, 2013, the Company owns mineral rights to approximately 7,200 gross acres and 2,400 net mineral acres of land located about 8 miles southeast of Williston, North Dakota. Our current and proposed operations consist of holding certain mineral rights which presently entitle the Company to royalty rights on average of 12% from the oil and gas produced on such lands. We have no rights to influence the activities conducted by the Lessees of our mineral rights. We will primarily focus on evolving the Company into a growth-orientated independent energy company engaged in the acquisition, exploration, exploitation, and development of oil and natural gas properties; focusing our activities mainly in the Williston Basin, a large sedimentary basin in eastern Montana, Western North and South Dakota, and Southern Saskatchewan known for its rich deposits of petroleum and potash.
34
BRI has continued to evaluate projects potentially complementary to its core business operations, including projects located in Idaho, Colorado and Texas. In addition, the Company has begun active discussions with industry and regulatory authorities on potential enhanced oil recovery (EOR) projects for application initially in the Williston Basin.
From time to time, we have raised funds from private investors. On February and March, 2011, we entered into agreements relating to the private placement of $745,000 of our securities through the sale of 2,980,000 shares of our common stock at $0.25 per share, with 1,490,000 total warrant shares attached that are exercisable at $.50 per share for three years from the date of these respective sales and callable at $0.01 per share at any time after the respective closing dates, if the underlying shares are registered and the common stock trades for 20 consecutive trading days at an average closing sales price of $.75 or more. In conjunction with the private placement, there was $139,075 in offering costs. The placement was undertaken by the officers of the Company. The private placement of these securities was exempt from registration under pursuant to Section 4(2) of the Securities Act of 1933, as amended. The proceeds from these sales of unregistered securities were used to fund Company operations. With the conclusion of the February and March 2011 closings, the raise under the original private placement which commenced in November 2010 for $2.5 million were completed in full.
In May and June 2011, we entered into a series of convertible debt agreements with certain investors in an aggregate amount of $300,000. Such notes bear an annual interest rate of 6% and shall be converted into shares of common stock of the Company upon the closing of a qualified equity financing round prior to December 31, 2011. Conversion, if it occurs, would be at a 25% discount to the price per share of the qualified financing round. Interest on the Notes shall not be deemed payable in the event of an equity conversion pursuant to a qualified financing round. The Company issued the notes pursuant to the exemption from registration afforded by the provisions of Section 4(2) of the Securities Act and Rule 506 of Regulation D thereunder. In January 2012, holders of $155,000 of such notes elected to convert at a price of $0.375 per share. Also in January 2012, holders of $95,000 of note elected to extend such notes until June 30, 2012. Such notes have since been paid in full.
In September 2011 and February 2012, we sold an aggregate of 150,000 shares of common stock of the Company at $0.50 per share pursuant to subscription agreements. The February 2012 investors also received 25,000 warrants exercisable at $0.75 per share reflecting 50% of the original investment amount. The Company received gross proceeds of $75,000 in connection with this sale. The Company issued the shares and warrants pursuant to the exemption from registration afforded by the provisions of Section 4(2) of the Securities Act and Rule 506 of Regulation D thereunder.
Results of Operations
Our general and administrative costs decreased from $124,407 for the year ended December 31, 2012, to $107,615 for the year ended December 31, 2013. This decrease was attributable primarily to supplies, administrative expenses, consulting fees, professional fees, travel costs, and stock issued for Director compensation. The following tables provide selected financial data about our company as of December 31, 2013, and December 31, 2012.
| (Restated) | December 31, | |||||
| December 31, | 2012 | |||||
| Balance Sheets Data: | 2013 | |||||
| Cash | $ | 1,523,601 | $ | 693,320 | ||
| Mineral rights and leases, property, plant and | ||||||
| equipment and oil and gas properties, net of | ||||||
| accumulated depletion and depreciation | 823,045 | 1,471,399 | ||||
| Total assets | 4,493,702 | 2,919,849 | ||||
| Total current liabilities | 1,378,527 | 374,860 | ||||
| Long-term portion installment | - | 847,119 | ||||
| Stockholders’ equity | 3,115,175 | 1,697,870 | ||||
| Total liabilities and stockholders’ equity | $ | 4,493,702 | $ | 2,919,849 | ||
35
| (Restated) Year | |||||||
| Selected Statements of | Ended December | Year Ended | |||||
| Operations Data: | 31, 2013 | December 31, 2012 | |||||
| Revenue | $ | 3,972,570 | $ | 1,727,818 | |||
| Payroll | 338,173 | 330,534 | |||||
| Professional fees | 1,154,246 | 969,390 | |||||
| General and administrative | 107,615 | 124,407 | |||||
| Net Income (Loss) | 1,321,587 | (399,403 | ) | ||||
| Net Loss Per Common Share | $ | 0.02 | $ | (0.01 | ) | ||
Our cash in the bank at December 31, 2013 was $1,523,601. Net cash used in financing activities during the year ended December 31, 2013 was $842,011 due to payments made on debt. Net cash used in financing activities during the year ended December 31, 2012 was $277,993 including $25,000 from proceeds from the sale of common stock offset by payments made on debt of $302,993.
As more wells have been drilled and begun producing, BRI’s cash inflow has improved significantly. The Company expects this trend to continue over the next twelve months.
Net cash provided by operating activities for the year ended December 31, 2013, was $1,672,292 compared to net cash provided by operating activities of $84,362 for the year ended December 31, 2012. For the year ended December 31, 2013, our total operating expenses were $2,134,388 as compared to $1,878,910 for the year ended December 31, 2012, which increase is primarily attributable to increased professional fees offset by decreased depreciation and depletion. We expect our use of cash for operating expenses to continue at approximately $80,000 per month over the next twelve months compared to the year ended December 31, 2013. Our material financial obligations include legal fees, public reporting expenses, transfer agent fees, bank fees, and other recurring fees.
For the year ended December 31, 2013, professional fees were a significant portion of our operating expense. Professional fees can be broken down into the following categories: (i) consultant fees totaled $128,923; (ii) legal costs totaled $857,106; (iii) stock based compensation was $95,718; and (iv) other professional fees (accounting, auditing, and transfer agent services) totaled $56,508. The Company anticipates these fees will be similar in 2014.
There were no unusual or infrequent events or transactions or any significant economic changes that materially affected the amount of reported income from continuing operations.
As noted above, royalty payments received by the Company increased substantially. BRI expects this trend to continue as the Bakken formation wells begin to infill on our mineral acreage. As new wells are drilled and begin to produce, both revenue and cash royalties should increase.
A review of the financial statements shows a significant increase in revenue compared with the previous year. This increase is attributable to the number of new wells being completed and producing. At the beginning of 2013, the Company received royalty payments on twelve Bakken formation wells. By the end of 2013, BRI received royalty payments on an aggregate of forty-one (41) Bakken, Three Forks, and Madison formation wells.
36
Liquidity and Capital Resources
As of December 31, 2013 we had cash of $1,523,601. Due to the increased royalty payments, the company has been cash positive in 2013. Given our recent rate of use of cash in our operations we believe we have sufficient capital to carry on operations for the next year. Our long term capital requirements and the adequacy of our available funds will depend on many factors, including the reporting company costs, public relations fees, and operating expenses, among others.
Liquidity is a measure of a company’s ability to meet potential cash requirements. We have historically met our capital requirements through the issuance of stock and convertible debt. In the future, we anticipate we will be able to provide the necessary liquidity we need by the revenues generated from the royalties paid to us from oil and gas operations on our existing properties, however, if we do not generate sufficient sales revenues we will continue to finance our operations through equity or debt financings.
The following table summarizes total current assets, total current liabilities and working capital at December 31, 2013.
| (Restated) | ||
| December 31, | ||
| 2013 | ||
| Current Assets | $ | 3,670,657 |
| Current Liabilities | $ | 1,378,527 |
| Working Capital | $ | 2,292,130 |
Current Assets include cash, accounts receivable, accrued royalty receivable, and prepaid expenses. A significant portion of our current assets comes from accrued royalty receivable. The Company accrues royalty revenue based on reported production of the wells. New wells sometimes report production up to 150 days before beginning payments to royalty owners. This can result in a substantial receivable balance. Based on past history, BRI expects to receive accrued royalty revenue in full.
In addition, in 2013, the Company did not receive certain accrued royalties in the amount of approximately $1.9 million from one of its operators in 2013 as a result of a lis pendens filed in North Dakota relating to the Company’s lawsuit with Allan Holms in the State of Washington. The Company received substantially all of such accrued royalties in the first quarter of 2014.
Current Liabilities include accounts payable, accrued expenses and the current portion of long term debt. The most significant portion of current liabilities comes from accrued expenses for royalty payable and production tax passed to the Company as part of the royalty payments. Accrued royalty payable is paid only upon receipt of revenue. Accrued production tax is withheld by the operators from the royalty payments.
As of December 31, 2013, we have collected approximately $6,608,526 in royalty payments from our wells under production. We received our first royalty check in August 2011. As of December 31, 2013, we have received royalty checks primarily from the production of forty-one (41) wells.
Satisfaction of our cash obligations for the next 12 months
Based on an analysis of our current cash position and cash flow the Company expects to fund our current operating plans internally. The use of outside funding or joint ventures is not an essential element of current operations. Such outside funding may be needed if BRI determines a need to increase operations or if any of our current expenses increase significantly.
Since inception, we have primarily financed cash flow requirements through debt financing and issuance of common stock for cash and services. As and if we expand operational activities, we may continue to experience net negative cash flows from operations, pending receipt of sales or development fees, and may be required to obtain additional financing to fund operations through common stock offerings and debt borrowings to the extent necessary to provide working capital.
37
Over the next twelve months we believe that existing capital and anticipated funds from operations will be sufficient to sustain current operations. We may seek additional capital in the future to fund growth and expansion through additional equity or debt financing or credit facilities. No assurance can be made that such financing would be available, and if available it may take either the form of debt or equity. In either case, the financing could have a negative impact on our financial condition and our Stockholders.
We anticipate the next six months will continue to show operating income. This is due to the number of wells showing production and collection of royalty payments from that production. We have collected approximately $6,608,526 in royalty payments from August 2011 to December 2013 from production on forty-one (41) wells. We have information that an additional six (6) wells are either in production or are in confidential status. Although we believe that income from our wells will likely reduce or eliminate operating losses in the near future, we have no control over the timing of when we will receive such royalty payments. In addition, there can give no assurance that we will be successful in addressing operational risks as previously identified under the "Risk Factors" section, and the failure to do so can have a material adverse effect on our business prospects, financial condition and results of operations.
The table below shows the wells located on BRI mineral acreage as of December 31, 2013.
| Well Name | Formation | Status |
| Oasis Petroleum Operated Wells | ||
| Lindvig 14-12H | Madison | Producing |
| Schmitz 44-30H | Madison | Producing |
| Lyle 1-35H | Madison | Producing |
| Brier 5200 42-22 H | Bakken | Producing |
| Hysted 44-19H | Three Forks | Producing |
| Stewart 12-29H | Bakken | Producing |
| Bering 5200 12-29H | Bakken | Producing |
| Catch Federal 5201 11-12H | Bakken | Producing |
| Cliff Federal 5200 14-5H | Bakken | Producing |
| Lefty 5200 13-30H | Bakken | Producing |
| Casey 5200 13-30B | Bakken | Producing |
| Zaye Federal 5201 3-2H | Bakken | Producing |
| Doris H 5200 14-20B | Bakken | Producing |
| Leanne 5201 41-24B | Bakken | Producing |
| Taylor N 5200 14-2B | Bakken | Producing |
| Sully 5200 11-30B | Bakken | Producing |
| Inigo 5200 43-20B | Bakken | Producing |
| Pingora 5200 41-20B | Bakken | Producing |
| Pikes 5200 41-20B | Bakken | Producing |
| John Federal 5201 41-12B | Bakken | Permitted |
| Birdhead 5200 41-22T | Three Forks | Producing |
| Elery H 5200 14-20T | Three Forks | Producing |
| Carol JA 5200 14-29T | Three Forks | Producing |
| Morrison 5200 11-30B | Bakken | Producing |
| Shields 5200 43-20T | Three Forks | Producing |
| Leo 5200 43-20B | Bakken | Producing |
| Toby 5200 43-20T | Three Forks | Producing |
| Sherman 5200 41-20T | Three Forks | Producing |
| Newberry 5200 41-20T | Three Forks | Producing |
| Mabel Federal 5201 41-12T | Three Forks | Permitted |
| Ida 5200 21-28B | Bakken | Drilling |
| Jade 5200 21-28T | Three Forks | Confidential |
| Lefty 14-30 3B | Bakken | Drilling |
| Hysted 14-30 2B | Bakken | Permitted |
| Brier 5200 11-27 8T2 | Three Forks | Permitted |
38
| Continental Resources Operated Wells | ||
| Missoula 1-21H | Bakken | Producing |
| Anderson 1-45H | Bakken | Producing |
| Alpha 3-14H | Bakken | Producing |
| Alpha 1-14H | Bakken | Producing |
| Alpha 2-14H | Bakken | Producing |
| Missoula 2-21H | Bakken | Producing |
| Missoula 3-21H | Three Forks | Producing |
| Missoula 4-21H | Three Forks | Producing |
| Missoula 6-21H | Three Forks | Producing |
| Missoula 7-21H | Bakken | Producing |
| Missoula 5-21H | Bakken | Confidential |
| Alfsvaag 1-13H | Bakken | Producing |
| Florida 2-11H | Bakken | Drilling |
| Florida 3-11H | Bakken | Producing |
| Jerry 1-8H | Bakken | Producing |
| Statoil/Brigham Operated Wells | ||
| William 25-26 #1H | Three Forks | Producing |
| Patent Gate 7-6 #1H | Bakken | Producing |
| Forest 26-35 #1H | Bakken | Producing |
Off-Balance Sheet Arrangements
We currently do not have any off-balance sheet arrangement that have or are reasonably likely to have a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors.
Critical Accounting Policies and Estimates
This discussion and analysis of our financial condition and results of operations are based on our financial statements that have been prepared under accounting principles generally accepted in the United States of America. The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires our management to make 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 and the reported amounts of revenue and expenses during the reporting period. Actual results could materially differ from those estimates. All significant accounting policies have been disclosed in Note 2 to the consolidated financial statements for the years ended December 31, 2013 and 2012 contained herewith. Our critical accounting policies are discussed below.
Use of estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America 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 amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Revenue Recognition
The Company follows the guidance the FASB Accounting Standards Codification for revenue recognition. The Company recognizes revenue when it is realized or realizable and earned. The Company considers revenue realized or realizable and earned when all of the following criteria are met: (i) persuasive evidence of an arrangement exists, (ii) the product has been shipped or the services have been rendered to the customer, (iii) the sales price is fixed or determinable, and (iv) collectability is reasonably assured.
Under the royalty and lease agreements obtained as part of the exercised Option to Purchase Asset Agreement, the Company recognizes revenue when production occurs under our leased property as shown on the operator run tickets and information available through the North Dakota Industrial Commission’s website. The royalty income is calculated monthly.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Not applicable.
39
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
40
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders
of
Bakken Resources, Inc.
Helena,
Montana
We have audited the consolidated balance sheet of Bakken Resources, Inc. as of December 31, 2013, and the related consolidated statements of operations, stockholders’ equity, and cash flows for the year then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audit. The financial statements of Bakken Resources, Inc. as of December 31, 2012, were audited by other auditors whose report dated April 12, 2013, expressed an unqualified opinion on those statements.
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 audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the 2013 consolidated financial statements referred to above present fairly, in all material respects, the financial position of Bakken Resources, Inc. as of December 31, 2013, and the results of its operations and its cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America.
As discussed in Note 10 to the financial statements, the 2013 financial statements have been restated to correct misstatements to the financial statements.
/s/ DeCoria, Maichel, & Teague
DeCoria, Maichel & Teague P.S.
Spokane, Washington
August 22, 2016
41
BAKKEN RESOURCES,
INC.
CONSOLIDATED BALANCE SHEETS
| December 31, 2013 | ||||||||
| (Restated see Note 10) | December 31, 2012 | |||||||
| ASSETS | ||||||||
| CURRENT ASSETS | ||||||||
| Cash | $ | 1,523,601 | $ | 693,320 | ||||
| Accounts receivable | 2,126,104 | 745,226 | ||||||
| Prepaids | 20,952 | 9,904 | ||||||
| Total Current Assets | 3,670,657 | 1,448,450 | ||||||
| PROPERTY, PLANT AND EQUIPMENT, net of
accumulated depreciation of $22,376 and $13,620 |
15,272 | 24,028 | ||||||
| PROVED MINERAL RIGHTS AND LEASES, net of accumulated
depletion of $845,227 and $519,629 |
689,773 | 1,129,371 | ||||||
| PROVED OIL AND GAS PROPERTIES, using
successful efforts accounting, net of accumulated depletion of $0 |
68,000 | 68,000 | ||||||
| UNPROVED MINERAL RIGHTS AND LEASES | 50,000 | 250,000 | ||||||
| Total Assets | $ | 4,493,702 | $ | 2,919,849 | ||||
| LIABILITIES AND STOCKHOLDERS' EQUITY | ||||||||
| CURRENT LIABILITIES: | ||||||||
| Accounts payable | $ | 42,564 | $ | 78,562 | ||||
| Accrued liabilities | 183,494 | 7,153 | ||||||
| Royalty payable to related party | 403,222 | 169,145 | ||||||
| Related party payable | 235,500 | — | ||||||
| Income tax payable | 513,747 | — | ||||||
| Current portion installment | — | 120,000 | ||||||
| Total Current Liabilities | 1,378,527 | 374,860 | ||||||
| Long-term portion installment | — | 847,119 | ||||||
| Total Liabilities | 1,378,527 | 1,221,979 | ||||||
| COMMITMENT AND CONTINGENCIES (see Note 7) | ||||||||
| STOCKHOLDERS' EQUITY: | ||||||||
| Preferred stock, $.001 par value, 10,000,000
shares authorized, none issued or outstanding |
— | — | ||||||
| Common stock, $.001 par value, 100,000,000
shares authorized, 56,735,350 shares issued and outstanding |
56,735 | 56,735 | ||||||
| Additional paid-in capital | 3,496,296 | 3,400,578 | ||||||
| Accumulated deficit | (437,856 | ) | (1,759,443 | ) | ||||
| Total Stockholders' Equity | 3,115,175 | 1,697,870 | ||||||
| Total Liabilities and Stockholders' Equity | $ | 4,493,702 | $ | 2,919,849 | ||||
See accompanying notes to the consolidated financial statements.
42
BAKKEN RESOURCES, INC.
CONSOLIDATED STATEMENTS OF
OPERATIONS
| Years Ended | ||||||||
| December 31, | ||||||||
| 2013 | ||||||||
| (Restated see Note 10) | 2012 | |||||||
| REVENUES | $ | 3,972,570 | $ | 1,727,818 | ||||
| OPERATING EXPENSES: | ||||||||
| Depreciation and depletion | 334,354 | 453,629 | ||||||
| Payroll | 338,173 | 330,534 | ||||||
| Professional fees | 1,154,246 | 969,390 | ||||||
| Loss on impairment of asset | 200,000 | 950 | ||||||
| General and administrative expenses | 107,615 | 124,407 | ||||||
| Total Operating Expenses | 2,134,388 | 1,878,910 | ||||||
| INCOME (LOSS) FROM OPERATIONS | 1,838,182 | (151,092 | ) | |||||
| OTHER INCOME (EXPENSES): | ||||||||
| Interest income | 833 | 1,418 | ||||||
| Other income | — | 505 | ||||||
| Loss on extinguishment of debt | (22,092 | ) | ||||||
| Gain on interest settlement | 15,608 | — | ||||||
| Interest expense | (19,228 | ) | (228,142 | ) | ||||
| Total other income (expenses) | (2,847 | ) | (248,311 | ) | ||||
| NET INCOME (LOSS) BEFORE INCOME TAXES | 1,835,334 | (399,403 | ) | |||||
| Income tax expense | 513,747 | — | ||||||
| NET INCOME (LOSS) | $ | 1,321,587 | $ | (399,403 | ) | |||
| NET INCOME (LOSS) PER COMMON SHARE | ||||||||
| - BASIC AND DILUTED: | $ | 0.02 | $ | (0.01 | ) | |||
| Weighted average common shares outstanding | ||||||||
| - basic | 56,735,350 | 55,927,169 | ||||||
| - diluted | 56,819,276 | 55,927,169 | ||||||
See accompanying notes to the consolidated financial statements.
43
BAKKEN RESOURCES, INC.
CONSOLIDATED STATEMENTS OF
STOCKHOLDERS' EQUITY
YEARS ENDED DECEMBER 31, 2013 (Restated see Note 10) AND
2012
| Additional | Total | |||||||||||||||||
| Common Stock | Paid-in | Accumulated | Stockholders’ | |||||||||||||||
| Shares | Amount | Capital | Deficit | Equity | ||||||||||||||
| Balances - December 31, 2011 | 56,467,500 | $ | 56,468 | $ | 2,732,457 | $ | (1,360,040 | ) | $ | 1,428,885 | ||||||||
| Common stock issued for conversion of | ||||||||||||||||||
| debt and interest | 417,850 | 417 | 156,277 | — | 156,694 | |||||||||||||
| Common stock issued for cash | 50,000 | 50 | 24,950 | — | 25,000 | |||||||||||||
| Options expense | — | — | 290,369 | — | 290,369 | |||||||||||||
| Warrants issued for induced conversion | ||||||||||||||||||
| of debt | — | — | 174,233 | — | 174,233 | |||||||||||||
| Warrants issued with debt extensions | — | — | 22,092 | — | 22,092 | |||||||||||||
| Common stock returned to the Company | ||||||||||||||||||
| and cancelled | (200,000 | ) | (200 | ) | 200 | — | — | |||||||||||
| Net loss | — | — | — | (399,403 | ) | (399,403 | ) | |||||||||||
| Balances - December 31, 2012 | 56,735,350 | 56,735 | 3,400,578 | (1,759,443 | ) | 1,697,870 | ||||||||||||
| Options expense | — | — | 95,718 | — | 95,718 | |||||||||||||
| Net income (As Restated) | — | — | — | 1,321,587 | 1,321,587 | |||||||||||||
| Balances - December 31, 2013 (As Restated) | 56,735,350 | $ | 56,735 | $ | 3,496,296 | $ | (437,856 | ) | $ | 3,115,175 | ||||||||
See accompanying notes to the consolidated financial statements.
44
BAKKEN RESOURCES, INC.
CONSOLIDATED STATEMENTS OF
CASH FLOWS
| Years Ended | ||||||||
| December 31, | ||||||||
| 2013 (Restated | ||||||||
| see Note 10) | 2012 | |||||||
| CASH FLOWS FROM OPERATING ACTIVITIES: | ||||||||
| Net income (loss) | $ | 1,321,587 | $ | (399,403 | ) | |||
| Adjustments to reconcile net income (loss) to net cash used in operating activities | ||||||||
| Depreciation and depletion expense | 334,354 | 453,629 | ||||||
| Options expense | 95,718 | 290,369 | ||||||
| Loss on disposal of fixed asset | 950 | |||||||
| Loss on impairment of asset | 200,000 | |||||||
| Warrants issued for induced conversion of debt | — | 174,233 | ||||||
| Gain on interest settlement | (15,608 | ) | — | |||||
| Loss on extinguishment of debt | — | 22,092 | ||||||
| Consulting services paid through transfer of fixed asset | — | 1,598 | ||||||
| Changes in operating assets and liabilities: | ||||||||
| Accounts receivable | (1,380,878 | ) | (559,764 | ) | ||||
| Prepaids | (11,047 | ) | (6,214 | ) | ||||
| Accounts payable | (35,999 | ) | 62,677 | |||||
| Royalty payable to related party | 234,077 | 87,199 | ||||||
| Accrued liabilities | 180,841 | (26,853 | ) | |||||
| Related party payable | 235,500 | — | ||||||
| Income tax liability | 513,747 | — | ||||||
| Deferred income | — | (16,151 | ) | |||||
| NET CASH PROVIDED BY OPERATING ACTIVITIES | 1,672,292 | 84,362 | ||||||
| CASH FLOWS FROM INVESTING ACTIVITIES: | ||||||||
| Cash paid for acquisition of oil and gas property | (68,000 | ) | ||||||
| Cash paid for acquisition of property and equipment | — | (1,312 | ) | |||||
| NET CASH USED IN INVESTING ACTIVITIES | — | (69,312 | ) | |||||
| CASH FLOWS FROM FINANCING ACTIVITIES: | ||||||||
| Payments made on installment | (842,011 | ) | (302,993 | ) | ||||
| Proceeds from sale of common stock, net of offering costs | — | 25,000 | ||||||
| NET CASH USED IN FINANCING ACTIVITIES | (842,011 | ) | (277,993 | ) | ||||
| NET CHANGE IN CASH | 830,281 | (262,943 | ) | |||||
| Cash at beginning of year | 693,320 | 956,263 | ||||||
| Cash at end of year | $ | 1,523,601 | $ | 693,320 | ||||
| SUPPLEMENTAL DISCLOSURE OF CASH FLOWS INFORMATION: | ||||||||
| Interest paid | $ | 19,288 | $ | 65,669 | ||||
| NONCASH INVESTING AND FINANCING ACTIVITIES: | ||||||||
| Settlement of installment from reduced acreage in mineral property | $ | 114,000 | $ | 200 | ||||
| Common stock issued to settle debt and accrued interest | — | 156,694 | ||||||
See accompanying notes to the consolidated financial statements.
45
BAKKEN RESOURCES, INC.
NOTES TO THE CONSOLIDATED
FINANCIAL STATEMENTS
NOTE 1 - ORGANIZATION AND OPERATIONS
Bakken Resources, Inc. (“BRI”) was incorporated on June 6, 2008 in Nevada. On June 11, 2010, BRI and Bakken Development Corporation, its wholly-owned Nevada subsidiary entered into an Option to Purchase Assets Agreement with Holms Energy to purchase certain oil and gas production royalty rights on land in North Dakota. This option was exercised on November 26, 2010.
Formation of BR Metals, Inc.
On January 13, 2011, the Company formed BR Metals, Inc. in Nevada. BR Metals Inc. is a wholly owned subsidiary of the Company and engages in the business of identifying, screening, evaluating, and acquiring precious metals properties in the Western United States.
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of presentation
The accompanying financial statements and related notes have been prepared in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”).
Basis of consolidation
The consolidated financial statements include those of Bakken Resources, Inc. and its wholly-owned subsidiaries, Bakken Development Corporation. and BR Metals, Inc. (collectively, the “Company”). All material intercompany balances and transactions have been eliminated in consolidation.
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 amounts of revenues and expenses during the reporting period. Estimates are made with regard to income taxes, asset impairments and depreciation.
Cash equivalents
The Company considers all highly liquid investments with a maturity of three months or less when purchased to be cash equivalents.
Allowance for doubtful accounts
The Company evaluates its accounts receivables for collectability and establishes an allowance for bad debts through a review of several factors including historical collection experience, current aging status of the customer accounts, and financial condition of our customers. As of December 31, 2013 and 2012, no allowance for doubtful accounts was recorded.
Property and equipment
Property and equipment is recorded at cost. Expenditures for major additions and betterments are capitalized. Maintenance and repairs are charged to operations as incurred. Depreciation of property and equipment is computed by the straight-line method (after taking into account their respective estimated residual values) over the assets’ estimated useful life. Upon sale or retirement of equipment, the related cost and accumulated depreciation are removed from the accounts and any gain or loss is reflected in statements of operations. Depreciation expense for the years ended December 31, 2013 and 2012 was $8,756 and $8,892 respectively.
Oil and Gas Properties and Mineral Rights
The Company applies the successful efforts method of accounting for oil and gas properties. The Company owns royalty interests and one working interest. The Company capitalizes asset-acquisition costs. Unproved oil and gas properties and mineral rights are periodically assessed to determine whether they have been impaired, and any impairment in value is charged to expense. The costs of proved properties are depleted on an equivalent unit-of-production basis. The reserve base used to calculate depletion is the sum of proved reserves. During 2013 and 2012, the Company impaired the value of an asset referred to as "Duck Lake." The impairment related to an overstatement stemming from what the Company believes was an incorrect valuation of the underlying asset. Overstatement of the Duck Lake property value appears to have been related to misconduct by our CEO, Val M. Holms. Depletion expense for 2013 and 2012 was $325,598 and $444,737, respectively.
46
Asset Retirement Obligations
The Company follows ASC 410 of the FASB Accounting Standards Codification which requires entities to record the fair value of a liability for legal obligations associated with the retirement obligations of tangible long-lived assets in the period in which it is incurred. This standard requires the Company to record a liability for the fair value of the dismantlement and plugging and abandonment costs excluding salvage values. When the liability is initially recorded, the entity increases the carrying amount of the related long-lived asset. Over time, accretion of the liability is recognized each period and the capitalized cost is amortized over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement. During 2013 and 2012, the Company has not recorded any asset retirement obligations.
Impairment of long-lived assets
The Company follows paragraph 360-10-35-17 of the FASB Accounting Standards Codification for its long-lived assets. The Company’s long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable.
The Company assesses the recoverability of its long-lived assets by comparing the projected undiscounted net cash flows associated with the related long-lived asset or group of long-lived assets over their remaining estimated useful lives against their respective carrying amounts. Impairment, if any, is based on the excess of the carrying amount over the fair value of those assets. Fair value is generally determined using the asset’s expected future discounted cash flows or market value, if readily determinable. If long-lived assets are determined to be recoverable, but the newly determined remaining estimated useful lives are shorter than originally estimated, the net book values of the long-lived assets are depreciated over the newly determined remaining estimated useful lives. The Company recognized an impairment cost of $950 at December 31, 2012 due to a computer that was damaged beyond repair.
The Company determined that the value of an asset referred to as “Duck Lake” was impaired during the year ended December 31, 2013 (see Notes 3 and 10).
Fair value of financial instruments
The Company follows paragraph 825-10-50-10 of the FASB Accounting Standards Codification for disclosures about fair value of its financial instruments and has adopted paragraph 820-10-35-37 of the FASB Accounting Standards Codification to measure the fair value of its financial instruments. Paragraph 820-10-35-37 of the FASB Accounting Standards Codification establishes a framework for measuring fair value in generally accepted accounting principles (GAAP), and expands disclosures about fair value measurements. To increase consistency and comparability in fair value measurements and related disclosures, paragraph 820-10-35-37 of the FASB Accounting Standards Codification establishes a fair value hierarchy which prioritizes the inputs to valuation techniques used to measure fair value into three (3) broad levels. The fair value hierarchy gives the highest priority to quoted prices (unadjusted) in active markets for identical assets or liabilities and the lowest priority to unobservable inputs. The three (3) levels of fair value hierarchy defined by paragraph 820-10-35-37 of the FASB Accounting Standards Codification are below:
| Level 1 | Quoted market prices available in active markets for identical assets or liabilities as of the reporting date. |
| Level 2 | Pricing inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. |
| Level 3 | Pricing inputs that are generally observable inputs and not corroborated by market data. |
The carrying amounts of financial instruments, such as cash, approximate their fair values because of the short maturity of these instruments.
The Company does not have any assets or liabilities measured at fair value on a recurring basis, consequently, the Company did not have any fair value adjustments for assets and liabilities measured at fair value at December 31, 2013 or 2012, nor gains or losses are reported in the statement of operations that are attributable to the change in unrealized gains or losses relating to those assets and liabilities still held at the reporting date for 2013 or 2012. As of December 31, 2013, the Company also had assets that, under certain conditions, are subject to measurement at fair value on a non-recurring basis like those associated with oil and gas producing properties, and mineral rights and leases, and other long-lived assets. For these assets, measurement at fair value in periods subsequent to their initial recognition is applicable if any of these assets are determined to be impaired. If recognition of these assets at their fair value becomes necessary, such measurements will be determined utilizing Level 3 inputs.
47
Revenue recognition
The Company follows the guidance of paragraph 605-10-S99-1 of the FASB Accounting Standards Codification for revenue recognition. The Company recognizes revenue when it is realized or realizable and earned. The Company considers revenue realized or realizable and earned when all of the following criteria are met: (i) persuasive evidence of an arrangement exists, (ii) the product has been shipped or the services have been rendered to the customer, (iii) the sales price is fixed or determinable, and (iv) collectability is reasonably assured.
Revenues reflected on the income statement are net of production taxes, royalty, expense, and other deductions.
Under the royalty and lease agreements obtained as part of the exercised Option to Purchase Asset Agreement, the Company recognizes revenue when production occurs under the 14 separate mineral leases granted or amended between September 9, 2009 and December 10, 2009, whereby: 1) Oasis Petroleum, Inc., 2) Brigham Resources, and 3) Continental Resources, Inc. purchased the rights to explore, drill and develop oil and gas on the Holms Property acquired pursuant to the Agreement. The royalty income is calculated monthly and the Company recognizes royalty income as production is reported by well on the North Dakota Industrial Commission website.
Stock-based compensation for obtaining employee services
The Company accounted for its stock based compensation under the recognition and measurement principles of the fair value recognition provisions of ASC 718. All transactions in which goods or services are the consideration received for the issuance of equity instruments are accounted for based on the fair value of the consideration received or the fair value of the equity instrument issued, whichever is more reliably measurable. The measurement date used to determine the fair value of the equity instrument issued is the earlier of the date on which the third-party performance is complete or the date on which it is probable that performance will occur.
The fair value of options, if any, is estimated on the date of grant using a Black-Scholes option-pricing valuation model. The ranges of assumptions for inputs are as follows:
| - | The Company uses historical data to estimate employee termination behavior. The expected life of options granted is derived from paragraph 718-10-S99-1 of the FASB Accounting Standards Codification and represents the period of time the options are expected to be outstanding. | ||
| - | The expected volatility is based on a combination of the historical volatility of the comparable companies’ stock over the contractual life of the options. | ||
| - | The risk-free interest rate is based on the U.S. Treasury yield curve in effect at the time of grant for periods within the contractual life of the option. | ||
| - | The expected dividend yield is based on the Company’s current dividend yield as the best estimate of projected dividend yield for periods within the contractual life of the option. |
The Company’s policy is to recognize compensation cost for awards with only service conditions and a graded vesting schedule on a straight-line basis over the requisite service period for the entire award, if any. Additionally, the Company’s policy is to issue new shares of common stock to satisfy stock option exercises.
The Company adopted a “2008 Non-Qualified Stock Option and Stock Appreciation Rights Plan” on June 6, 2008. This plan was initiated to encourage and enable officers, directors, consultants, advisors and other key employees of the Company to acquire and retain a proprietary interest in the Company by ownership of its common stock. 1,000,000 of the authorized shares of the Company’s common stock may be subject to, or issued pursuant to, the terms of the plan. On November 8, 2010 the Company increased the authorized shares to 5,000,000. The Company granted 500,000 stock options from the Company’s 2008 Non-Qualified Stock Option Plan during 2012. No options were granted in 2013.
48
Equity instruments issued to parties other than employees for acquiring goods or services
The Company accounted for equity instruments issued to parties other than employees for acquiring goods or services under the recognition and measurement principles of the fair value recognition provisions of section 505-50-30 of the FASB Accounting Standards Codification. All transactions in which goods or services are the consideration received for the issuance of equity instruments are accounted for based on the fair value of the consideration received or the fair value of the equity instrument issued, whichever is more reliably measurable. The measurement date used to determine the fair value of the equity instrument issued is the earlier of the date on which the third-party performance is complete or the date on which it is probable that performance will occur. The fair value of the warrants is estimated on the date of grant using a Black-Scholes option-pricing valuation model. The ranges of assumptions for inputs are as follows:
| - | The expected life of warrants granted is derived from paragraph 718-10-S99-1 of the FASB Accounting Standards Codification and represents the period of time the warrants are expected to be outstanding. | ||
| - | The expected volatility is based on a combination of the historical volatility of the comparable companies’ stock over the contractual life of the warrants. | ||
| - | The risk-free interest rate is based on the U.S. Treasury yield curve in effect at the time of grant for periods within the contractual life of the warrants. | ||
| - | The expected dividend yield is based on the Company’s current dividend yield as the best estimate of projected dividend yield for periods within the contractual life of the warrants. |
Reclassifications
Certain amounts in the prior period financial statements have been reclassified for comparative purposes to conform to the presentation in the current period financial statements. Reclassified amounts were not material to the financial statements.
Income tax
The Company accounts for income taxes under paragraph 710-10-30-2 of the FASB Accounting Standards Codification. Deferred income tax assets and liabilities are determined based upon differences between the financial reporting and tax bases of assets and liabilities and are measured using the enacted tax rates and laws that will be in effect when the differences are expected to reverse. Deferred tax assets are reduced by a valuation allowance to the extent management concludes it is more likely than not that the assets will not be realized. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in the statements of operations in the period that includes the enactment date.
The Company accrued $513,747 for federal and state income tax liability for 2013.
Net income or loss per common share
Net income or loss per common share is computed pursuant to paragraph 260-10-45-10 of the FASB Accounting Standards Codification. Basic net income or loss per share is computed by dividing net loss by the weighted average number of shares of common stock outstanding during the period. Diluted net income or loss per share is computed by dividing net loss by the weighted average number of shares of common stock and potentially outstanding shares of common stock during each period to reflect the potential dilution that could occur from common shares issuable through stock warrants. 333,332 common stock options were included in the diluted calculations, while 1,872,001 common stock warrants were excluded from the calculation of diluted loss per share for the year ended December 31, 2013, as the effect would have been anti-dilutive.
Commitments and contingencies
The Company follows subtopic 450-20 of the FASB Accounting Standards Codification to report accounting for contingencies. Liabilities for loss contingencies arising from claims, assessments, litigation, fines and penalties and other sources are recorded when it is probable that a liability has been incurred and the amount of the assessment can be reasonably estimated.
Cash flows reporting
The Company has adopted paragraph 230-10-45-24 of the FASB Accounting Standards Codification for cash flows reporting, classifies cash receipts and payments according to whether they stem from operating, investing, or financing activities and provides definitions of each category, and uses the indirect or reconciliation method (“Indirect method”) as defined by paragraph 230-10-45-24 of the FASB Accounting Standards Codification to report net cash flow from operating activities by adjusting net income to reconcile it to net cash flow from operating activities by removing the effects of (a) all deferrals of past operating cash receipts and payments and all accruals of expected future operating cash receipts and payments and (b) all items that are included in net income that do not affect operating cash receipts and payments.
Recently issued accounting pronouncements
We do not expect the adoption of recently issued accounting pronouncements to have a significant impact on our results of operations, financial position or cash flows.
49
NOTE 3 – ACQUISITION OF MINERAL RIGHTS
Acquisition of Royalty Interests
On June 11, 2010, the Company entered into an Option to Purchase Assets Agreement with Holms Energy, LLC, pursuant to which Holms Energy agreed to grant Multisys Acquisition an option to exercise an Asset Purchase Agreement to assign all right, title, and interest of specific Holms Energy owned assets to Multisys Acquisition, with Holms Energy members holding a controlling interest in Multisys as a result of the exercise of the option. The option was exercised on November 26, 2010 and the Asset Purchase Agreement was entered into on November 26, 2010 by paying the consideration to Holms Energy detailed in the Asset Purchase Agreement. Under the Asset Purchase Agreement, Multisys Acquisition paid Holms Energy $100,000, issued Holms Energy 40,000,000 shares of restricted common stock, and granted to Holms Energy a 5% overriding royalty on all revenue generated from the Holms Property for ten years from the date of the acquisition closing. The issuance of the 40,000,000 shares to the Holms Energy members resulted in a Change in Control as the Holms Energy members obtained a controlling interest in Multisys. With the Holms Energy members obtaining a controlling interest in the Company, the mineral rights acquired from Holms were recorded at Holms Energy’s cost basis of zero. The $100,000 cash paid to Holms was recorded as a stockholder distribution.
The Asset Purchase Agreement related to the acquisition of: 1) certain Holms Energy mineral rights in oil and gas rights on approximately 7,200 gross acres and 2,400 net mineral acres of land located in McKenzie County, 8 miles southeast of Williston, North Dakota; 2) potential production royalty income from wells to be drilled on the property whose mineral rights are owned by Holms Energy; and 3) the transfer of all right, title and interest to an Option to Purchase the Greenfield mineral rights entered into between Holms Energy and Rocky and Evenette Greenfield dated June 18, 2010 related to purchasing additional mineral rights and production royalty income on the Holms Property for $1,649,000.
The Greenfield Option was subsequently exercised by Holms Energy on November 12, 2010, and those Greenfield mineral rights were acquired by Multisys Acquisition through the Asset Purchase Agreement with Holms Energy. Holms Energy exercised the Greenfield option and executed the Asset Purchase Agreement on the Greenfield mineral rights on November 12, 2010 using $385,000 of a $485,000 one month non-interest bearing loan from Multisys to complete the initial payment of $400,000, of which $15,000 was already paid by Holms Energy. The collateral for the loan was the Greenfield mineral rights.
Under the terms of the loan from Multisys to Holms Energy, Holms Energy, in conjunction with the entry into the Asset Purchase Agreement on November 26, 2010, assigned the Greenfield mineral rights to Multisys Acquisition in exchange for forgiveness of $385,000 of the loan. The other $100,000 of the loan was to be applied to the Asset Purchase Agreement between Multisys and Holms Energy, and on November 26, 2010, that $100,000 was applied to the Asset Purchase Agreement and the loan was forgiven. After exercise of the option and executing the asset purchase agreement with Holms Energy, Multisys Acquisition purchased the gas and oil production royalty rights of Rocky and Evenette Greenfield for an aggregate of $1,249,000 plus interest as follows: installment payments in the amount of $120,000 per year, or $30,000 per quarter plus interest at 5% per annum for 8 years and a balloon payment in the amount of $289,000.
As of December 31, 2012, the aggregate unpaid balance under the installment note was $967,119. Under the terms of the agreement, in the event that a comprehensive mineral title search revealed that the net acres acquired by the Company were less than 824.5 net mineral acres, the purchase price and corresponding installment note would be reduced by $2,000 per acre. During July 2013, a comprehensive mineral title search was completed and it was determined that the Company acquired 57 less acres than originally stated in the mineral rights acquisition agreement. Accordingly, the carrying value of the proved mineral rights and the amount owed under the corresponding installment note were reduced by $2,000 per acre, or $114,000. In addition, the interest previously accrued and paid on this $114,000 of principal was forgiven resulting in a further reduction of principal in the amount of $11,108 and a reduction of accrued interest in the amount of $4,500. The Company recognized a gain on the settlement of interest of $15,608 and a reduction to the carrying value of the proved mineral rights of $114,000 during the year ended December 31, 2013. Upon completion of the comprehensive mineral title search and settlement of the installment note and interest, the Company paid in full the remaining principal balance of the installment note of $842,011. The outstanding balance was $0 as of December 31, 2013.
On September 21, 2011, the Company purchased an undivided 50% interest in minerals contained in approximately 2,200 acres located in Glacier County, Montana (also referred to as Duck Lake). The purchase price of these rights was $250,000. It has been determined through a subsequent independent investigation that these mineral rights likely were deliberately overvalued by $200,000 by an executive officer. The rights carrying cost has been adjusted to reflect the correct value, $50,000.
Depletion expense recorded on the mineral rights for 2013 and 2012 was $325,598 and $444,737, respectively.
Acquisition of Working Interest
On July 3, 2012, the Company purchased a 17% working interest in an oil well located in Archer County, Texas for $68,000 cash from Holms Energy, which is owned by an officer of the Company. The property was not yet producing as of December 31, 2013.
50
NOTE 4 – RELATED PARTY TRANSACTIONS
Royalty payable – officer
In connection with the acquisition of the Holms Property (see Note 3), the Company granted to Holms Energy, which is owned by an officer of the Company, a 5% overriding royalty on all revenue generated from the Holms Property for ten years from the date of the acquisition closing. As of December 31, 2013 and 2012, the royalty payable was $403,222 and 169,145, respectively. The corresponding royalty expense was $801,078 and $520,066, respectively.
Since 2011, errors in accruing overriding royalties payable to Holms Energy have existed. Management has analyzed the effect of these errors and restated the Company’s 2013 accrued royalties payable to correct the cumulative effect of the errors (see Note 10).
Related Party Payable
Historically net royalty payments received from Oasis Petroleum for production emanating from mineral rights owned by Holms Energy Development Corporation (a related party) have been included in net royalty payments due the Company. Oasis Petroleum did not recognize Holms Energy Development Corporation (HEDC) until November 2014. As a result, the Company has included amounts in its previously reported revenues that are revenues of HEDC. Management has analyzed the effect of these errors and restated the Company’s 2013 revenues to correct the cumulative effect of the errors (see Note 10). At December 31, 2013 the Company has accrued $235,500 payable to HEDC as a result of this correction.
Joint Venture Agreement: On July 3, 2012 the Company purchased a 17% working interest in an oil well located in Archer County, Texas for a price of $68,000 cash from Holms Energy Development Corp. (“HEDC”). HEDC is owned by Val Holms, our CEO. This transaction was reviewed by the Company’s independent directors and approved by our Board, with Mr. Holms recusing himself from such Board vote.
In 2011, HEDC acquired a 51% working interest of a 78.25% net revenue interest in the Jennings AA and BB leases in Archer County Texas and the Jennings 3A well. Bill Baber, who is now a company director, retained a 3% override in the transaction. HEDC has an exclusive right to operate these wells.
Bill Baber Overriding Royalty: In early 2011, HEDC acquired a 51% working interest of a 78.25% net revenue interest in the Jennings AA and BB leases in Archer County Texas and the Jennings 3A well. Bill Baber retained a 3% override in the transaction. HEDC has an exclusive right to operate these wells.
At the time of the transaction, Bill Baber was not a Bakken board member. Mr. Baber joined board in December 2011 upon Steve Armstrong’s resignation.
Mr. Baber did not receive any payments in 2013 relating to this overriding royalty.
NOTE 5 – CONVERTIBLE NOTES PAYABLE
During May and June 2011, the Company borrowed $300,000 from investors. The notes were unsecured, bore interest at 6% per annum and originally matured on December 31, 2011. The notes were convertible at the holders’ option into common stock of the Company at a $0.375 per share. In addition, each of the notes would automatically convert into the next equity financing with gross proceeds of at least $2,000,000 at the lower of $0.375 or a 25% discount to the per share sales price of the $2,000,000 equity financing. The Company evaluated the conversion option for a beneficial conversion feature under FASB ASC 470-20 and determined that none existed.
In connection with these notes, the Company paid cash commissions of $21,000. The commissions were recorded as deferred financing costs and were amortized over the life of the notes using the effective interest rate method. The amount was fully amortized during 2011.
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$155,000 of the notes and $1,694 of accrued interest were converted into 417,850 common shares during 2012. In connection with the conversions, the note holders were issued 206,667 common stock warrants. The warrants are exercisable at $0.75 per share, vest immediately and have a term of 4 years. The fair value of the warrants was determined to be $174,233 using the Black-Scholes option pricing model. The key assumptions utilized in the model include the closing market price of the Company’s common stock of $1.20, expected term of 4 years, volatility of 85.79%, risk-free interest rate of 0.89% and zero expected dividends. The conversion was accounted for as an induced conversion and the fair value of the warrants of $174,233 was expensed during the year ended December 31, 2012.$95,000 of the notes was extended until June 30, 2012. In connection with the extensions, the Company issued the note holders an aggregate of 25,334 common stock warrants. The warrants are exercisable at $0.75 per share, vest immediately and have a term of 5 years. The fair value of the warrants was determined to be $22,092 using the Black-Scholes option pricing model. The key assumptions utilized in the model include the closing market price of the Company’s common stock of $1.20, expected term of 5 years, volatility of 81.79%, risk-free interest rate of 0.89% and zero expected dividends. The Company evaluated the extension of these notes under FASB ASC 470-50 and determined that the modification was substantial and qualified as a debt extinguishment. The extinguishment loss recognized as a result of the loan extensions was $22,092 for the year ended December 31, 2012. This $95,000 of the notes was repaid in full during 2012. The remaining $50,000 of the notes was also repaid in cash during 2012.
NOTE 6 – STOCKHOLDERS’ EQUITY
Common Stock and Common Stock Warrants
During March 2011, the Company entered into a consulting agreement and issued the consultant 100,000 units which vest over six months. Each unit consists of two shares of common stock plus one common stock purchase warrant that are exercisable at $0.50 per share for a term of three years from the date of issuance, callable at $0.01 per share at any time after one year from the date of sale, if the underlying shares are registered and the common stock trades for 20 consecutive trading days at an average closing sales price of $0.75 or more. The fair value of the grant was determined to be $50,000 and it was recognized over the service period of six months. As of December 31, 2011, these shares are fully vested and included in the shares issued for services in the consolidated statements of stockholders’ equity. During 2012, these units were returned to the Company and canceled.
During 2012, the Company sold 25,000 common stock units at $0.50 per unit to a private investor. Each unit consists of two shares of common stock plus one common stock purchase warrant that are exercisable at $0.50 per share for a term of three years from date of issuance, callable at $0.01 per share at any time after one year from the date of sale, if the underlying shares are registered and the common stock trades for 20 consecutive trading days at an average closing sales price of $.75 or more, for a total of 50,000 shares of common stock and 25,000 warrants sold, total cash of $25,000 was received net of offering costs of $0.
During 2012, the Company issued an aggregate of 417,850 common shares for the conversion of debt and interest (see Note 5). During 2013, no common stock or warrants were issued or retired. The table below summarizes the Company’s warrant activity for 2013 and 2012:
| Number of | Weighted | |||||
| Warrant | Average | |||||
| Shares | Exercise Price | |||||
| Balance, December 31, 2011 | 5,746,667 | $ | 0.480 | |||
| Granted | 75,334 | 0.750 | ||||
| Canceled | — | 0.750 | ||||
| Balance, December 31, 2012 | 5,822,001 | $ | 0.500 | |||
| Expired | (3,950,000 | ) | 0.480 | |||
| Balance, December 31, 2013 | 1,872,001 | $ | 0.530 | |||
| Exercisable, December 31, 2012 | 5,822,001 | $ | 0.500 | |||
| Exercisable, December 31, 2013 | 1,872,001 | $ | 0.530 | |||
At December 31, 2013, the range of exercise prices and the weighted average remaining contractual life of the warrants outstanding were $0.25 to $0.75 and 0.48 years, respectively. The exercisable warrants outstanding at December 31, 2013 had an intrinsic value of $0. At December 31, 2012, the range of exercise prices and the weighted average remaining contractual life of the warrants outstanding were $0.25 to $0.75 and 1.10 years, respectively.
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Common Stock Options
During March 2012, the Company granted an aggregate of 500,000 common stock options to officers and Directors. The options are exercisable at $0.10 per share and vest one-third immediately and one-third each year over the next two years. The fair value of the options was determined to be $400,548 using the Black-Scholes option pricing model. The key assumptions utilized in the model include the closing market price of the Company’s common stock of $0.90, expected terms between 1 and 2 years, volatility of 68.94%, risk-free interest rate of 0.41% and zero expected dividends. The fair value is being expensed over the vesting period of the options. Option expense of $95,718 and $290,369 was recognized during the years ended December 31, 2013 and 2012, respectively. The remaining $14,461 will be expensed through March 2014.
The table below summarizes the Company’s option activity for 2013 and 2012:
| Number of | Weighted | ||||
| Option | Average | ||||
| Shares | Exercise Price | ||||
| Balance, December 31, 2011 | — | $ | — | ||
| Granted | 500,000 | 0.100 | |||
| Balance, December 31, 2012 | 500,000 | $ | 0.100 | ||
| Balance, December 31, 2013 | 500,000 | 0.100 | |||
| Exercisable, December 31, 2012 | 166,666 | $ | 0.100 | ||
| Exercisable, December 31, 2013 | 500,000 | $ | 0.100 | ||
At December 31, 2013, the exercise price and the weighted average remaining contractual life of the options outstanding were $0.10 and 0.22 years, respectively. The exercisable options outstanding at December 31, 2013 had an intrinsic value of $21,667. At December 31, 2012, the exercise price and the weighted average remaining contractual life of the options outstanding were $0.10 and 1.22 years, respectively, the exercisable options outstanding at December 31, 2012 had an intrinsic value of $30,000.
NOTE 7 - COMMITMENTS AND CONTINGENCIES
On December 1, 2010, BRI entered into a one-year office lease, renewable for up to five years, for a 2,175 square foot executive office at 1425 Birch Ave., Suite A, Helena, MT 59601, for a monthly charge of $1,600 for the first year; $1,800 second year; $2,000 third year; $2,200 fourth year; and $2,400 fifth year. BRI also maintains a part-time office in New York City which is fixed at $3,000 per month. The Company maintains an apartment in Helena, MT to provide accommodation to the Chief Financial Officer when working in Helena each week. The apartment is under a one year lease that expired October 31, 2013 and the monthly rent was $650.
Litigation
On April 2, 2012, BRI was served with a summons relating to a complaint filed by Allan Holms, both individually and derivatively through Roil Energy, LLC. Allan Holms is the half-brother of BRI’s CEO, Val Holms. The complaint (filed in the Superior Court of the State of Washington located in Spokane County) names, among others, Joseph Edington, Val and Mari Holms, Holms Energy, LLC and BRI as defendants. The Complaint primarily alleges breach of contract, tortious interference with prospective business opportunity and fraud. The complaint focuses on events allegedly occurring around February and March 2010 whereby Allan Holms alleged an oral agreement took place whereby he was to receive up to 40% of the originally issued equity of Roil Energy, LLC. Allan Holms alleges Roil Energy was originally intended to be the predecessor entity to BRI. After various court proceedings, the Washington Court of Appeals affirmed a trial court’s ruling against the plaintiff and reversed the trial court’s ruling against certain of the defendants. The Company believes the possibility of any future economic damages to BRI to be unlikely.
On June 6, 2012, the Company filed a Temporary Restraining Order (the “TRO”) and Verified Complaint for Injunctive Relief against McKinley Romero, Peter Swan Investment Consulting Ltd and IWJ Consulting Group, LLC (collectively, the “Defendants”), in connection with the Defendants’ request to the transfer agent to remove restrictive legends from an aggregate of 4.7 million shares, which the Company believes were improperly obtained by the Defendants. The Company obtained the TRO from the Second Judicial District Court of the State of Nevada, County of Washoe on June 6, 2012 enjoining the Defendants from seeking removal of the restrictive legends. On a scheduled hearing on June 26, 2012 the judge in this matter ruled in favor of the Company’s motion for a preliminary injunction. The order granting such preliminary injunction was issued from this court on August 14, 2012. The Company obtained a default judgment against the Defendants on June 12, 2014.
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In March 2013, the Company received notice of a complaint titled Gillis v. Bakken Resources, Inc., Case No. A-13-675280-B, filed in the District Court of the State of Nevada for Clark County. Mr. Gillis, the plaintiff in this matter (the “Gillis Case”), is the trustee of the Bruce and Marilyn Gillis 1987 Trust. Mr. Gillis is alleging that Client breached certain registration rights obligations pursuant to an equity investment made at or around November 2010. The Court in this this matter granted class certification and class notice in March 2014. The Company settled this matter in September 2014.
NOTE 8 – INCOME TAXES
The Company uses the liability method, where deferred tax assets and liabilities are determined based on the expected future tax consequences of temporary differences between the carrying amounts of assets and liabilities for financial and income tax reporting purposes. During 2012, the Company incurred net losses and, therefore, has no tax liability. The net deferred tax asset generated by the loss carry forward has been fully reserved as of December 31, 2013 and 2012. During 2013, the Company generated taxable income and incurred a total tax provision of $513,747. There was no available net operating loss carry forward as of December 31, 2013.
The income tax provision differs from the amount of income tax determined by applying the Federal Income Tax Rate to pre-tax income from continuing operations due to the following items:
| 2013 | |||||||
| (Restated | |||||||
| see Note 10) | 2012 | ||||||
| Income tax at statutory rate (34%) | $ | 624,013 | $ | - | |||
| Effect of state income taxes | 127,097 | ||||||
| Change in valuation allowance | (219,600 | ) | - | ||||
| Other | (17,763 | ) | - | ||||
| Income tax expense | $ | 513,747 | $ | - | |||
The provision for income taxes consists of the following for 2013 and 2012:
| 2013 | ||||||
| (Restated | ||||||
| see Note 10) | 2012 | |||||
| Current: | ||||||
| Federal | $ | 390,208 | $ | - | ||
| State: | ||||||
| Montana | 65,549 | - | ||||
| North Dakota | 57,990 | - | ||||
| Income tax expense | $ | 513,747 | $ | - | ||
At December 31, 2013 and 2012, deferred tax assets consisted of the following:
| 2013 | 2012 | ||||||
| Impairment losses not deductible for tax | $ | 79,400 | $ | 299,000 | |||
| Valuation allowance | (79,400 | ) | (299,000 | ) | |||
| Net deferred tax asset | $ | - | $ | - | |||
The Company has no unrecognized tax benefits at December 31, 2013 or 2012. It is not anticipated that there will be any significant changes to unrecognized tax benefits within the next twelve months. If interest and penalties were to be assessed, we would charge interest to interest expense, and penalties to other operating expense. At December 31, 2013, fiscal years 2010 through 2013 remain subject to examination by federal and state tax authorities.
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NOTE 9 – SUBSEQUENT EVENTS
On February 4, 2014, the Company sold a portion of its producing property for an aggregate sale price of $7,871,248 in cash and a 2% retained royalty on proceeds derived from such sold mineral assets. 10% of the cash sale price is escrowed for a period of 90 days (subject to certain adjustments) pending title review and confirmation. The property sold consists of the 767 net mineral acres acquired by the Company as part of the acquisition of the “Greenfield mineral interests” described in Note 3 herein. During the year ended December 31, 2013, 36% of total revenue was generated from the property that was sold.
In February 2014, the Company agreed to indemnify one of its operators, Oasis Petroleum, against any losses Oasis may incur as a result of a lawsuit filed in North Dakota claiming rights to the Company’s acreage. As a result, Oasis removed the suspension it had placed on royalties based on production on the Company’s net mineral acres.
In March 2014, the Company received notice of a complaint titled Manuel Graiwer and TJ Jesky v. Val Holms, Herman Landeis, Karen Midtlyng, David Deffinbaugh, Bill Baber, W. Edward Nichols and Wesley Paul, Case No. CV14 00544, filed in the Second Judicial District Court of the State of Nevada for Washoe County. Mssrs. Graiwer and Jesky, the plaintiffs in this matter (the “Graiwer Case”), bring action on behalf of the Company derivatively, and the Company is also named as a nominal defendant. Mssrs. Graiwer and Jesky are shareholders of the Company and allege breach of fiduciary duty, gross negligence, corporate waste, unjust enrichment and civil conspiracy against one or more of the named defendants. The Company and is also informed that each of the other named defendants denies the validity of the claims made in the Graiwer Case and each intends to vigorously defend against such claims, as applicable.
In late 2014, the Company discovered that the former CEO may have been involved in inappropriate activities. A thorough independent investigation was initiated. The investigation concluded that it is highly likely that inappropriate activities had taken place. The investigation has been turned over to federal authorities for further investigation. As a result of the investigation, the company has filed a lawsuit to recover monetary damage to the corporation including the costs incurred to complete the investigation.
The Company’s Audit Committee chair, Ed Nichols, resigned from the Audit Committee and the Board of Directors in March 2015. Subsequently, the Company engaged a special investigator to continue the investigation initiated by the Company’s Audit Committee, and the Company’s Chairman and CEO, Val Holms, took a paid leave of absence during the investigation.
The Company’s founder and CEO, Val M. Holms, was terminated in May 2016 on the basis of fraud and other allegations levied against him.
In May 2016, the Company entered into a financing agreement with Eagle Private Equity (Eagle). The agreement included conversion rights if certain events occurred. In July 2016, a triggering event occurred, which granted Eagle the right to convert debt into equity having the equivalent of 60 million shares of The Company’s common stock.
NOTE 10 – RESTATEMENT
The 2013 financial statements have been restated to reflect the following errors:
| 1. | Duck Lake: The Company has become aware of certain allegations regarding the conduct of our now-former CEO. During our investigation, the Company received information indicating that the Duck Lake mineral rights may have been deliberately overstated by $200,000. We have reduced this asset value accordingly. | |
| 2. | Three Forks
Wells: The deeds transferring the mineral rights from Toll Reserve Consortium, Inc. to
Bakken Resources Inc. were limited to production emanating from the surface to the base of the
Bakken Formation. Any production emanating from formations below the Bakken formation, such as
the Three Forks formation, was retained by Toll Reserve (now Holms Energy Development
Corporation).
In September 2014, the Company discovered five wells producing from the Three Forks Formation, which were previously accounted for as wells producing from the Bakken Formation. Our operators paid Bakken in err for production from those wells, and the Company booked the royalty payments as revenue. This resulted in an overstatement in revenue royalty from 2011 through 2013. Management has determined that the effect on periods prior to 2013 was immaterial and has restated 2013’s financial statement by $235,500 in order to correct the errors relating to fiscal year 2013. | |
| 3. | Royalty Payable: When Holms Energy LLC (a related party) transferred mineral rights to production emanating from the surface to the base of the Bakken formation, Holms Energy, LLC retained a 5% retained (or overriding) royalty. However, our royalty accrual calculation omitted post-production costs, resulting in overstating our royalty payable account and royalty expense account from 2011 through 2013 by a total amount of $210,927. | |
| 4. | Royalty Revenue: The Company engaged the services of a landman to determine the company’s net royalty interests in each producing well in order to more accurately determine accrued royalty revenue and verify payments from operators. But the landman’s information proved to be largely incorrect. This caused the Company to incorrectly accrue royalty revenues and receivables from 2011 through 2013. In order to address the issue, the Company engaged a nationally reputed landman company, which properly determined reliable information. Accordingly, we have restated accrued royalty revenue and royalty receivables for the effected period. The net effect on royalty revenue adjusted in 2013 increased royalty revenue by $24,654. | |
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| 5. | Accounts Receivable Adjustment: In 2013, an adjusting entry had been made that was reflected in our Annual Report on Form 10-K that had been filed in 2014. This adjusting entry incorrectly reduced revenue and accounts receivable by $114, 459. Also, we restated accounts receivable to recognize the accrued production taxes separately on the balance sheet of $183,494. |
The impact of the royalty and asset overvaluation issue is as follows:
Impact on Consolidated Balance Sheet as of December 31, 2013
| As Previously Reported | Restatement | As Restated | ||||||||||
| Accounts receivable | $ | 1,938,457 | $ | 187,647 | $ | 2,126,104 | ||||||
| Unproved mineral rights and leases | 250,000 | (200,000 | ) | 50,000 | ||||||||
| Total restated assets | $ | 2,188,457 | $ | (12,353 | ) | $ | 2,176,104 | |||||
| Related party payable | - | 235,500 | 235,500 | |||||||||
| Royalty payable related party | 614,149 | (210,927 | ) | 403,222 | ||||||||
| Accrued liabilities | - | 183,494 | 183,494 | |||||||||
| Total restated liabilities | 1,170,460 | (208,067 | ) | 822,216 | ||||||||
| Accumulated deficit | (217,436 | ) | 220,420 | (437,856 | ) | |||||||
| Stockholders’ equity | 3,335,595 | 220,420 | 3,115,175 | |||||||||
| Total restated liabilities & stockholders’ equity | $ | 4,506,055 | $ | 4,493,702 | ||||||||
Impact on Consolidated Statement of Operations as of December 31, 2013
| As Previously Reported | Restatement | As Restated | ||||||||
| Revenue | $ | 3,992,989 | $ | (20,419 | ) | $ | 3,972,570 | |||
| Loss on impairment of asset | - | 200,000 | 200,000 | |||||||
| Net income after taxes | 1,542,007 | (220,420 | ) | 1,321,587 | ||||||
| Net income per share | $ | 0.03 | $ | (0.01 | ) | $ | 0.02 | |||
Impact on Consolidated Statement of Cash Flows as of December 31, 2013
| As Previously Reported | Restatement | As Restated | |||||||||
| Net income | $ | 1,542,007 | $ | 220,420 | $ | 1,321,587 | |||||
| Loss on impairment of asset | - | 200,000 | 200,000 | ||||||||
| Change in: | |||||||||||
| Accounts receivable | 1,193,231 | 187,647 | 1,380,878 | ||||||||
| Related party payable | - | 235,500 | 235,500 | ||||||||
| Royalty payable related party | 445,004 | (210,927 | ) | 234,077 | |||||||
| Accrued liabilities | (2,653 | ) | 183,494 | 180,841 | |||||||
| Net cash provided by operating activities | $ | 1,672,292 | $ | 1,672,292 | |||||||
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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A CONTROLS AND PROCEDURES
Management is responsible for establishing and maintaining adequate control over financial reporting. Internal control over financial reporting is defined in Rule 13a-15(f) or 15d-15(f) promulgated under the Securities Exchange Act of 1934, as amended, as a process designed by, or under the supervision of, a company’s principal executive and principal financial officers and effected by a company’s board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles and includes those policies and procedures that:
| ● | Pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the company; |
| ● | Provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and |
| ● | Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company’s assets that could have a material effect on the financial statements. |
Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, assessed the effectiveness of our internal control over financial reporting as of December 31, 2013.
A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis.
We identified material weaknesses in our internal control over financial reporting as of December 31, 2013 because certain elements of an effective control environment were not present including the financial reporting processes and procedures, and internal control procedures by our board of directors as we have yet to establish an audit committee and our full board has not been adequately performing those functions. The material weaknesses identified include the following:
| ● | There exists a significant overlap between management and our board of directors, with three of our six directors being members of management. This does not allow for multiple levels of supervision and review. |
| ● | Additionally, since we only have two full time and one part time employees, it has not been possible to ensure appropriate segregation of duties between incompatible functions and formalized monitoring procedures have not, as of December 31, 2013, been established or implemented. |
Based on this assessment and the material weaknesses described above, management has concluded that internal control over financial reporting was not effective as of December 31, 2013.
This annual report does not include an attestation report of the company’s registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by the company’s registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit the company to provide only management’s report in this annual report. We intend to take the following steps as soon as practicable to remediate the material weaknesses we identified:
| ● | We will and have appointed a Chief Financial Officer. |
| ● | We will segregate incompatible functions using existing personnel where possible or, given sufficient capital resources, we will hire additional personnel to perform those functions. |
| ● | We will, and have, appointed additional outside directors, particularly those who may have experience with regard to financial reporting, financial reporting processes and procedures and internal control procedures. |
| ● | To the extent we can attract outside directors, we plan to form an audit committee to review and assist the board with its oversight responsibilities and appoint a financial expert to be the chairperson of such audit committee. |
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Changes in Internal Control Over Financial Reporting
As of the end of the period covered by this Report, there have been no changes in internal control over financial reporting (as defined in Rule 13a-15(f) of the Exchange Act) during the quarter ended December 31, 2013, that materially affected, or are reasonably likely to materially affect, our company’s internal control over financial reporting.
However, beginning in July 2014, the company overhauled its internal control processes and procedures. These sweeping changes included written procedures, better processes to ensure correct net mineral interests and royalty payments, and verification processes to ensure the producing formation for each well. We have engaged a respected certified land and title firm to verify all net mineral interests, reconciled the company’s net royalty interest to each operator. We also began verifying each month’s production and producing formation with the North Dakota Industrial Commission database for each producing well. The company’s mineral estate is split; the company’s has mineral rights only to the base of the Bakken formation.
Through these newly implemented procedures, the Company determined that five wells had been erroneously identified by the company, Oasis Petroleum, and Continental Resources as producing from the Bakken formation rather than the Three Forks formation. The company discovered that many of the net royalty interests applied primarily by Oasis Petroleum were incorrect. In addition, the company discovered that the methodology employed to calculate accrued royalty payable was incorrect.
Upon discovery of these issues, the Company immediately communicated these to the Company’s outside auditors, MaloneBailey, to discuss the appropriate accounting treatment and proper disclosures. The Company’s original determination to the restate the financial statements for the year ending December 31, 2013 resulted from this discovery.
In addition, the Company determined a number of additional errors existed requiring restatement of the financial statements including: an asset that was acquired in 2011, called Duck Lake, was deliberately over valued by $200,000, the overriding royalty accrual for the Holms Energy LLC override was overstated, the royalty revenue and royalty accounts receivable that had been accrued from 2011 – 2013 were calculated using incorrect net royalty interests, and a 2013 adjusting entry was made incorrectly.
None.
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
| ● | Directors, Executive Officers, Promoters and Control Persons |
The members of our board of directors serve for one year terms and are elected at the next annual meeting of stockholders, or until their successors have been elected. The officers serve at the pleasure of the board of directors. Pursuant to the acquisition of Holms Energy’s assets, some members of Holms Energy became the officers and directors of BRI effective upon closing of the acquisition agreement.
The following table sets forth BRI’s directors and executive officers as of December 31, 2013. The previous directors of BRI appointed the nominees designated by Holms Energy as members of the board of directors of BRI. Subsequently, the current officers and directors of BRI resigned their positions at BRI, clearing the way for the appointment of new executive officers by the new board of directors of BRI. Directors are elected for a period of one year and thereafter serve until the next annual meeting at which their successors are duly elected by the stockholders. Officers and other employees serve at the will of the board of directors and hold office until their death, resignation or removal from office.
| Name | Age | Position |
| Val M. Holms | 66 | Chief Executive Officer, President, and Director |
| David Deffinbaugh | 54 | Chief Financial Officer and Director |
| Karen S. Midtlyng | 55 | Secretary and Director |
| Herman R. Landeis | 81 | Director |
| Bill M. Baber | 62 | Director |
| W. Edward Nichols | 71 | Director |
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Family Relationships
There are no family relationships among our directors or officers.
Business Experience
The following is a brief account of the education and business experience of each director and executive officer during at least the past five years, indicating each person’s business experience, principal occupation during the period, and the name and principal business of the organization by which they were employed of those directors and the key members of the management team who became the officers, directors, and key employees of BRI on or after December 1, 2010 after the Asset Acquisition:
Val M. Holms – 66, President, Chief Executive Officer, and Director. After being honorably discharged from the United States Marine Corps, 4th Force Reconnaissance Division in Vietnam in 1969, he was the founder, sole owner and operator of Holms Building Services, Inc., a licensed general contracting company based in Missoula, Montana until 1984. Beginning in 1971 until the present, Mr. Holms has been a private investor, a part time independent land man, organized several oil and gas limited partnerships, purchased and sold mineral leases, and arranged various oil and gas joint ventures in Montana, Oklahoma, Texas, and North Dakota. From 1984 to 1988, he attended Rhema Bible Institute. Mr. Holms and his wife Mari Holms are the managing members of Holms Energy, LLC.
David Deffinbaugh – 54, Chief Financial Officer and Director. Mr. Deffinbaugh graduated from the University of Montana in 1982 with a Bachelor of Science degree in Business Administration, Accounting. After graduation, he worked in the family business until 1990. From 1990 to March 1992, he worked for the Montana Corporation where he assisted in the preparation of SEC financial reports along with regulatory reporting for an insurance subsidiary. From March 1992 through August 1996, he worked for Crop Growers Corporation where he was involved in various accounting functions as the company went from a private company through an IPO to a public company. From September 1996 through the present, he has maintained an accounting and financial services practice providing services to individuals and businesses in Montana and other states On May 14, 2011, Mr. Deffinbaugh was appointed as the Company’s Chief Financial Officer.
Karen S. Midtlyng – 55, Secretary and Director. Ms. Midtlyng holds an associate degree from the University of Montana, Helena College of Technology. From 1978 to 2005, she was employed by U.S. Geological Survey (“USGS”), Water Science Center, Helena, MT. During her 27 years with the USGS she was responsible for start to finish production of several USGS scientific reports, fact sheets, and electronic documents. Ms. Midtlyng also co-authored several USGS publications. From 2005 to 2010, she provided services to a small business in the Helena area, which included establishing and implementing business processes.
Herman R. Landeis – 81, Director. Mr. Landeis was the Western Region Tax Manager for Marathon Oil Corporation, based out of Casper, Wyoming, from 1972 until he retired in 1992. Previously, Mr. Landeis worked as a professional Draftsman for Marathon Oil Corporation from 1955 until 1972, except for a two year leave of absence to serve in the Military (Army), where he was honorably discharged. As a Tax Manager for Marathon Oil Corporation, he was responsible for and managed a variety of financial matters related to property tax negotiations, valuation of company owned assets and property, and conducting various financial analysis on operations in the Western United States. These properties included the Interstate Pipeline running from Montana to Missouri, properties in Alaska, five off-shore platforms and numerous operating oil and gas properties in the Western United States. Since his retirement in 1992, he has acted as a consultant to the oil and gas industry related to special projects involving tax matters, appraisals and valuation of property. Mr. Landeis received a Certified License as a Professional Appraiser from the University of Nebraska in 1972.
Bill M. Baber – 62, Director. Mr. Baber has 37 years of experience in the field of drilling, completing, operating and maintenance of oil and gas wells. In addition, Mr. Baber also provides sources and arranges for the maintenance of oil/gas rigs and other heavy machinery used in drilling operations. Mr. Baber regularly consults with clients on drilling operations and regulatory requirements. For the past 15 years, Mr. Baber has conducted his business through his entity, Bill M. Baber Oil Field Equipment.
W. Edward Nichols – 71, Director. Mr. Nichols has owned and operated gas processing plants in Kansas and Wyoming, and also co-owned and operated oil drilling, production and gas gathering companies in Kansas. Mr. Nichols has served as a Director and member of the Executive Committee of several public companies, including General Environmental Corporation, Gulfstar Energy Corporation and EnviroMart.com. He is currently chairman of the Board of Directors of Three Forks, Inc. and previously served in a similar capacity at Gulfstar Energy Corporation. He also serves as a consultant and in-house counsel for Travelpayer Systems Limited, a financial transaction processing and settlement company in the United Kingdom. In addition, Mr. Nichols is an attorney with Nichols & Nichols in Denver, Colorado and is authorized to practice in the states of Colorado and Kansas, the United States Federal Courts, and Supreme Court of the United States. He is also Managing Director of Nichols & Company LLC, a management consulting firm. Previously, Mr. Nichols was Senior Partner in Nichols and Wolfe, a national municipal bond law firm. He was instrumental in structuring and providing Approving Legal Opinions for several hundred million dollars of General Obligation Bonds, Tax Anticipation Notes and Revenue Bonds. He has since worked as a consultant with public and private companies in the U.S., Europe and the Far East and has extensive international relationships with investment banking firms, accounting and brokerage firms.
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Involvement in Certain Legal Proceedings
To our knowledge, during the past ten years, no present director or executive officer of our company: (1) filed a petition under the federal bankruptcy laws or any state insolvency law, nor had a receiver, fiscal agent, or similar officer appointed by a court for the business or present of such a person, or any partnership in which he was a general partner at or within two years before the time of such filing, or any corporation or business association of which he was an executive officer within two years before the time of such filing; (2) was convicted in a criminal proceeding or named subject of a pending criminal proceeding (excluding traffic violations and other minor offenses); (3) was the subject of any order, judgment or decree, not subsequently reversed, suspended or vacated, of any court of competent jurisdiction, permanently or temporarily enjoining him from or otherwise limiting the following activities: (i) acting as a futures commission merchant, introducing broker, commodity trading advisor, commodity pool operator, floor broker, leverage transaction merchant, associated person of any of the foregoing, or as an investment advisor, underwriter, broker or dealer in securities, or as an affiliated person, director of any investment company, or engaging in or continuing any conduct or practice in connection with such activity; (ii) engaging in any type of business practice; (iii) engaging in any activity in connection with the purchase or sale of any security or commodity or in connection with any violation of federal or state securities laws or federal commodity laws; (4) was the subject of any order, judgment or decree, not subsequently reversed, suspended or vacated, of any federal or state authority barring, suspending or otherwise limiting for more than 60 days the right of such person to engage in any activity described above under this Item, or to be associated with persons engaged in any such activity; (5) was found by a court of competent jurisdiction in a civil action or by the Securities and Exchange Commission to have violated any federal or state securities law and the judgment was not subsequently reversed, suspended or vacated; (6) was found by a court of competent jurisdiction in a civil action or by the Commodity Futures Trading Commission to have violated any federal commodities law, and the judgment in such civil action or finding by the Commodity Futures Trading Commission has not been subsequently reversed, suspended or vacated.
Section 16(a) Beneficial Ownership Reporting Compliance.
Section 16(a) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), requires the Company’s executive officers, directors and persons who own more than 10% of the Company’s outstanding common stock to file initial reports of ownership and changes in ownership with the Securities and Exchange Commission. Based solely on our review of Forms 3, 4 and 5 furnished to us and on written representations from certain reporting persons, we believe that the directors, executive officers, and our greater than 10% beneficial owners have complied in a timely manner with all applicable filing requirements for the fiscal year ended December 31, 2013.
Limitation of Liability of Directors
Pursuant to the Nevada General Corporation Law, our Articles of Incorporation exclude personal liability for our Directors for monetary damages based upon any violation of their fiduciary duties as Directors, except as to liability for any breach of the duty of loyalty, acts or omissions not in good faith or which involve intentional misconduct or a knowing violation of law, or any transaction from which a Director receives an improper personal benefit. This exclusion of liability does not limit any right which a Director may have to be indemnified and does not affect any Director’s liability under federal or applicable state securities laws. We have agreed to indemnify our directors against reasonable expenses, judgments, and amounts paid in settlement in connection with any claim against a Director if he acted in good faith and in a manner he believed to be in our best interests.
Election of Directors and Officers
Directors are elected to serve until the next annual meeting of stockholders and until their successors have been elected and qualified. Officers are appointed to serve until the meeting of the Board of Directors following the next annual meeting of stockholders and until their successors have been elected and qualified.
No executive officer or director of the Company has been the subject of any Order, Judgment, or Decree of any Court of competent jurisdiction, or any regulatory agency permanently or temporarily enjoining, barring suspending or otherwise limiting him from acting as an investment advisor, underwriter, broker or dealer in the securities industry, or as an affiliated person, director or employee of an investment company, bank, savings and loan association, or insurance company or from engaging in or continuing any conduct or practice in connection with any such activity or in connection with the purchase or sale of any securities.
No executive officer or director of the Company has been convicted in any criminal proceeding (excluding traffic violations) or is the subject of a criminal proceeding which is currently pending.
Except as set forth under Item 3 of this report, no executive officer or director of the Company is the subject of any pending legal proceedings.
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Audit Committee and Financial Expert
We do not have an Audit Committee, our directors and Chief Financial Officer (David Deffinbaugh) perform some of the same functions of an Audit Committee, such as: recommending a firm of independent certified public accountants to audit the annual financial statements; reviewing the independent auditors independence, the financial statements and their audit report; and reviewing management’s administration of the system of internal accounting controls.
David Deffinbaugh was appointed as Chief Financial Officer of BRI in May 2011, and is deemed our financial expert.
Code of Business Conduct and Ethics
A code of ethics relates to written standards that are reasonably designed to deter wrongdoing and to promote:
| (1) | Honest and ethical conduct, including the ethical handling of actual or apparent conflicts of interest between personal and professional relationships; | |
| (2) | Full, fair, accurate, timely and understandable disclosure in reports and documents that are filed with, or submitted to, the Commission and in other public communications made by an issuer; | |
| (3) | Compliance with applicable governmental laws, rules and regulations; | |
| (4) | The prompt internal reporting of violations of the code to an appropriate person or persons identified in the code; and | |
| (5) | Accountability for adherence to the code. | |
We have adopted a corporate code of ethics that applies to our principal executive officer, principal financial officer, principal accounting officer or controller, or persons performing similar functions.
Nominating Committee
We do not have a Nominating Committee or Nominating Committee Charter. Our board of directors perform some of the functions associated with a Nominating Committee.
ITEM 11. EXECUTIVE COMPENSATION
Summary Compensation Table
The table below sets forth the aggregate annual and long-term compensation paid by us for the fiscal years ended December 31, 2013 and 2012, to our Chief Executive Officer. Other than as set forth below, no executive officer’s salary and bonus exceeded $100,000 for the fiscal years 2013 or 2012.
| Change in | |||||||||
| Pension | |||||||||
| Value and | |||||||||
| Nonqualified | |||||||||
| Non-Equity | Deferred | ||||||||
| Name and | Stock | Option | Incentive Plan | Compensation | All other | ||||
| Principal | Salary | Bonus | Awards | Awards | Compensation | Earnings | Compensation | Total | |
| Position | Year | ($) | ($) | ($) | ($) | ($) | ($) | ($) | ($) |
| (a) | (b) | I | (d) | (e) | (f) | (g) | (h) | (i) | (j) |
| Val M. Holms | |||||||||
| Pres, CEO, & Dir. | 2013 | 180,000 | 0 | 0 | 0 | 0 | - | 0 | 180,000 |
| Val M. Holms | |||||||||
| Pres, CEO, & Dir. | 2012 | 180,000 | 0 | 0 | 0 | 0 | - | 0 | 180,000 |
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Narrative Disclosure to Summary Compensation Table
Mr. Val M. Holms, President and CEO of the Company was appointed to his executive position on December 1, 2010. Mr. Holm’s annual salary of $180,000 was agreed to be paid by the Company pursuant to his Employment Agreement entered into on February 1, 2011. In January 2013, the Board authorized a twelve-month extension of Mr. Holms’ Employment Agreement.
Outstanding Equity Awards at Fiscal Year End
There have been no options awards or equity awards given to any executive officers of BRI since inception on June 6, 2008, through the fiscal year ended December 31, 2013.
Compensation of Directors
The tables below show compensation for our non-employee directors for services as a director of the Company for the 2013 fiscal year. Compensation, as reflected in the tables which follow, is presented on the basis of rules of the Securities and Exchange Commission and does not, in the case of certain stock-based awards or accruals, necessarily represent the amount of compensation realized or which may be realized in the future.
| Stock Awards | Total | |||||
| Name(a) | ($)(b) | ($) | ||||
| W. Edward Nichols | $ | 66,745 | (b) | $ | 66,745 | |
| Bill Baber | $ | 66,745 | (b) | $ | 66,745 | |
(a) Our directors receive no fees or cash compensation for their services. Directors are, however, reimbursed for their actual out-of-pocket expenses associated with attending meetings and carrying out their obligations as directors.
(b) W. Edward Nichols and Bill Baber were granted 250,000 options each in 2012. One-third of the options vested immediately with the remaining options vesting quarterly over a two year period. The grant date fair value of each award was determined to be $200,274.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS.
The following table presents information about the beneficial ownership of our common stock on April 14, 2014, held by our directors and executive officers and by those persons known to beneficially own more than 5% of our capital stock. The percentage of beneficial ownership for the following table is based on 56,735,350 shares of common stock outstanding as of April 14, 2014.
Beneficial ownership is determined in accordance with the rules of the Securities and Exchange Commission and does not necessarily indicate beneficial ownership for any other purpose. Under these rules, beneficial ownership includes those shares of common stock over which the stockholder has sole or shared voting or investment power. It also includes (unless footnoted) shares of common stock that the stockholder has a right to acquire within 60 days after April 15, 2013, through the exercise of any option, warrant or other right. The percentage ownership of the outstanding common stock, however, is based on the assumption, expressly required by the rules of the Securities and Exchange Commission, that only the person or entity whose ownership is being reported has converted options or warrants into shares of our common stock.
Beneficial Ownership of Current Directors, Executive Officers and 5% Holders of the Company
| Percent of Outstanding Shares of | |||
| Name of Beneficial Owner (1) | Number of Shares | Common Stock (2) | |
| Val
M. Holms- CEO, President, and Director |
26,350,000 (3) | 46.83% | |
| Karen S. Midtlyng- Secretary, and Director |
2,250,000 (4) | 3.97% | |
| Herman R. Landeis - Director | 250,000 (5) | * | |
| Bill M. Baber - Director | 145,838 (6) | * | |
| W. Edward Nichols - Director | 145,838 (7) | * | |
| * | Less than 1% |
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| 1. | As used in this table, “beneficial ownership” means the sole or shared power to vote, or to direct the voting of, a security, or the sole or shared investment power with respect to a security (i.e., the power to dispose of, or to direct the disposition of, a security). The address of each person is care of the Company at 1425 Birch Ave. Suite A; Helena, MT 59601. | ||
| 2. | Figures are rounded to the nearest tenth of a percent. | ||
| 3. | Includes 26,350,000 shares held directly | ||
| 4. | Includes 2,250,000 shares held directly | ||
| 5. | Includes 250,000 shares held directly | ||
| 6. | Includes 83,333 vested shares of restricted shares and 60 days of vested shares as of April 15, 2013. 250,000 stock options were granted on March 20, 2012, with 1/3 vesting immediately and remaining 2/3 vesting over 24 month period. | ||
| 7. | Includes 83,333 vested shares of restricted shares and 60 days of vested shares as of April 15, 2013. 250,000 stock options were granted on March 20, 2012, with 1/3 vesting immediately and remaining 2/3 vesting over 24 month period. |
Change in Control
We are unaware of any
contract, or other arrangement or provision of our Articles or By-laws, the
operation of which may at a subsequent date result in a change of control of
BRI.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE.
Joint Venture Agreement: On July 3, 2012 the Company purchased a 17% working interest in an oil well located in Archer County, Texas for a price of $68,000 cash from Holms Energy Development Corp. (“HEDC”). HEDC is owned by Val Holms, our CEO. This transaction was reviewed by the Company’s independent directors and approved by our Board, with Mr. Holms recusing himself from such Board vote.
In 2011, HEDC acquired a 51% working interest of a 78.25% net revenue interest in the Jennings AA and BB leases in Archer County Texas and the Jennings 3A well. Bill Baber retained a 3% override in the transaction. HEDC has an exclusive right to operate these wells.
Holms Energy LLC. Overriding Royalty: When mineral rights are sold, it is a common practice in the oil and natural gas industry for the seller to retain a portion of the royalty stream. This retained royalty, referred to as an override royalty, is usually stated in percentage terms; that is, the percentage points of the original royalty stream retained by the seller. In 2010, Holms Energy sold certain mineral rights to the company. The resulting Asset Purchase Agreement provided a five percentage point retained overriding royalty. Therefore, Holms Energy retains five percentage points of a seventeen percentage point Bakken Resources Inc. royalty stream, or 29.41% (5/17).
The overriding royalty, 5/17 or 29.41%, is applied to Bakken’s monthly net royalty paid by the company’s well operators, Oasis Petroleum, Continental Resources, and Statoil. The operators discount the gross monthly production value (gross oil and natural gas volume times the current unit price) by the company’s net mineral interest to derive the company’s net monthly royalty. The Holms Energy overriding royalty factor (29.41%) is then applied to the net monthly royalty to derive the monthly override payment. The methodology employed by Bakken is consistent with the methodology employed by Oasis Petroleum and Continental Resources to calculate the overriding royalty that Bakken retained with the sale of certain mineral rights to Apollo Global Management in February 2014. Bakken has consistently applied this methodology since the company’s inception. Prior SEC filings included examples which erroneously discussed the application of the overriding royalty and included examples of such.
Transactions With Related Persons, Promoters, and Certain Control Persons
Bill Baber Overriding Royalty: In early 2011, HEDC acquired a 51% working interest of a 78.25% net revenue interest in the Jennings AA and BB leases in Archer County Texas and the Jennings 3A well. Bill Baber retained a 3% override in the transaction. HEDC has an exclusive right to operate these wells.
At the time of the transaction, Bill Baber was not a Bakken board member. Mr. Baber joined board in December 2011 upon Steve Armstrong’s resignation.
Bill Baber has not received any overriding royalty payments on these leases.
Herman Landeis Note Receivable with Val Holms: In 2013, Val Holms purchased a number of Indian artifacts from Herman Landeis. A note payable was executed by Holms totaling $100,000. As of December 31, 2013, only an initial $5,000 payment has been made on this note payable by Holms.
Promoters and Certain Control Persons
None.
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Director Independence
Our Board of Directors has determined that three of our six directors are currently “independent directors” as that term is defined in Rule 5605(a)(2) of the Marketplace Rules of the National Association of Securities Dealers. We are not presently required to have independent directors. If we ever become a listed issuer whose securities are listed on a national securities exchange or on an automated inter-dealer quotation system of a national securities association, which has independent director requirements, we intend to comply with all applicable requirements relating to director independence.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES.
The aggregate fees billed by our principal accountant for services rendered during the fiscal years ended December 31, 2013 and 2012, are set forth in the table below:
| Year ended | Year ended | |||||
| Fee Category | December 31, 2013 | December 31, 2012 | ||||
| Audit fees (1) | $ | 51,556 | $ | 55,950 | ||
| Audit-related fees (2) | — | — | ||||
| Tax fees (3) | — | — | ||||
| All other fees (4) | — | — | ||||
| Total fees | $ | 51,556 | $ | 55,950 | ||
| (1) | “Audit fees” consists of fees incurred for professional services rendered for the audit of annual financial statements, for reviews of interim financial statements included in our quarterly reports on Form 10-Q, and for services that are normally provided in connection with statutory and regulatory filings or engagements. | |
| (2) | “Audit-related fees” consists of fees billed for professional services that are reasonably related to the performance of the audit or review of our financial statements, but are not reported under “Audit fees.” | |
| (3) | “Tax fees” consists of fees billed for professional services relating to tax compliance, tax advice and tax planning. | |
| (4) | “All other fees” consists of fees billed for all other services, such as review of our registration statement on Form S-1. |
Audit Committee’s Pre-Approval Policies and Procedures
We do not at this time have an audit committee. Our Board of Directors (in lieu of an audit committee) pre-approves the engagement of our principal independent accountants to provide audit and non-audit services. Section 10A(i) of the Securities Exchange Act of 1934 prohibits our auditors from performing audit services for us as well as any services not considered to be “audit services” unless such services are pre-approved by the Board of Directors (in lieu of an audit committee) or unless the services meet certain minimum standards.
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ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
a) (1) Financial Statements See Item 8 in Part II of this report.
(2) All other financial statement schedules are omitted because the information required to be set forth therein is not applicable or because that information is in the financial statements or notes thereto.
(b) (3) Exhibits specified by Item 601 of Regulation S-K.
EXHIBIT INDEX
The following exhibit index shows those exhibits filed with this report and those incorporated herein by reference:
| Incorporated Herein by Reference | |||||
| Exhibits | Description of Document | Filed | Form | Exhibit | Filing Date |
| Herewith | |||||
| 3.1 | Articles of Incorporation | S-1 | 3.1 | 02-26-09 | |
| 3.2 | Bylaws | 8-K | 3.1 | 02-16-16 | |
| 4.1 | Non-Qualified Stock Option and Stock Appreciation Rights Plan adopted on June 10, 2008 | S-1 | 10.3 | 02-26-09 | |
| 4.2 | Form of Registration Rights Agreement 2010 | 10-K | 4.3 | 04-15-11 | |
| 4.3 | Form of Warrant 2010 | 10-K | 4.4 | 04-15-11 | |
| 4.4 | Form of Warrant 2011 (Convertible Bridge Loan) | 8-K | 10.1 | 05-25-11 | |
| 4.5 | Form of Convertible Promissory Note 2011 | 8-K | 10.2 | 05-25-11 | |
| 10.1 | Asset Purchase Agreement with Holms Energy, LLC entered into on November 26, 2010 | 8-K | 10.1 | 10-21-10 | |
| 10.2 | Asset Purchase Agreement between Holms Energy, LLC and Evenette and Rocky Greenfield entered into on November 12, 2010 | 8-K | 10.2 | 10-21-10 | |
| 10.3 | Promissory note with Holms Energy, LLC for $485,000 entered into on November 12, 2010 | 8-K | 10.2 | 11-18-10 | |
| 10.4 | Office Lease beginning December 1, 2010 | 10-K | 10.6 | 04-15-11 | |
| 10.5 | Form of Common Stock and Warrant Purchase Agreement 2010 | 10-K | 10.7 | 04-15-11 | |
| 10.6 | Employment Agreement by and between Bakken Resources, Inc. and David Deffinbaugh, dated effective as of January 1, 2012 | 10-K | 10.10 | 04-16-12 | |
| 10.7 | Employment Agreement by and between Bakken Resources, Inc. and Val M. Holms, dated March 12, 2013 | 8-K | 10.1 | 03-18-13 | |
| 10.8 | Employment Agreement by and between Bakken Resources, Inc. and Karen Midtlyng, dated March 12, 2013 | 8-K | 10.2 | 03-18-13 | |
| 10.9 | Form of Securities Purchase Agreement, entered into by Bakken Resources, Inc. on February 4, 2011 | 8-K | 10.1 | 02-09-11 | |
| 10.10 | Form of Securities Purchase Agreement, entered into by Bakken Resources, Inc. on March 18, 2011 | 8-K | 10.1 | 02-09-11 | |
| 10.11 | Oil and Gas Lease by and between Rocky Greenfield and Evenette Greenfield, Trustees of the Revocable Living Trust of Rocky Greenfield and Evenette Greenfield and Empire Oil Company dated July 29, 2008 | 10-K | 10.12 | 04-15-11 | |
| 10.12 | Oil and Gas Lease No.1 by and between Rocky Greenfield and Evenette Greenfield, Trustees of the Revocable Living Trust of Rocky Greenfield and Evenette Greenfield and Empire Oil Company dated July 14, 2008 | 10-K | 10.13 | 04-15-11 | |
| 10.13 | Amendment to Oil and Gas Lease by and between The Rocky Greenfield and Evenette Greenfield Revocable Living Trust, Rocky Greenfield and Evenette Greenfield, Trustees and Oasis Petroleum North America, LLC dated September 18, 2009 | 10-K | 10.14 | 04-15-11 | |
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| 10.14 | Extension, Amendment and Ratification of Oil and Gas Lease by and between Evenette Greenfield and Rocky Greenfield and The Armstrong Corporation dated September 9, 2003 | 10-K | 10.15 | 04-15-11 | |
| 10.15 | Extension, Amendment and Ratification of Oil and Gas Lease by and between Evenette Greenfield and The Armstrong Corporation dated November 24, 2004 | 10-K | 10.16 | 04-15-11 | |
| 10.16 | Oil and Gas Lease No.2 by and between Rocky Greenfield and Evenette Greenfield, Trustees of the Revocable Living Trust of Rocky Greenfield and Evenette Greenfield and Empire Oil Company dated July 14, 2008 | 10-K | 10.17 | 04-15-11 | |
| 10.17 | Oil and Gas Lease by and between Val Holms and Mari Holms, individually and as Trustees of the Val Holms and Mari Holms Revocable Living Trust and Empire Oil Company dated July 29, 2008 | 10-K | 10.18 | 04-15-11 | |
| 10.18 | Oil and Gas Lease by and between Val Holms and Mari Holms, individually and as Trustees of the Val Holms and Mari Holms Revocable Living Trust and Empire Oil Company dated July 14, 2008 | 10-K | 10.19 | 04-15-11 | |
| 10.19 | Oil and Gas Lease by and between Val Holms and Mari Holms, individually and as Trustees of the Val Holms and Mari Holms Revocable Living Trust and The Armstrong Corporation dated March 1, 2005 | 10-K | 10.20 | 04-15-11 | |
| 10.20 | Oil and Gas Lease by and between Val Holms and Mari Holms Revocable Living Trust, Val Holms and Maris Holms Trustees and The Armstrong Corporation dated September 9, 2003 | 10-K | 10.21 | 04-15-11 | |
| 10.21 | Oil and Gas Lease by and between Val Holms and Mari Holms, Trustees of the Val Holms and Mari Holms Revocable Living Trust and the Armstrong Corporation dated November 24, 2004 | 10-K | 10.22 | 04-15-11 | |
| 10.22 | Oil and Gas Lease by and between Val Holms and Mari Holms, individually and as Trustees of the Val Holms and Mari Holms Revocable Living Trust and Empire Oil Company dated July 14, 2008 | 10-K | 10.23 | 04-15-11 | |
| 10.23 | Form of Convertible Bridge Loan Agreement 2011 | 8-K | 10.1 | 05-25-11 | |
| 10.24 | Mineral Property Sale and Purchase Agreement Between John L. Reely, Lincoln Green, Inc. and Bakken Resources, Inc. dated effective as of September 21, 2011 | 8-K | 10.1 | 09-27-11 | |
| 31.1 | Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer | X | |||
| 31.2 | Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer | X | |||
| 32.1 | Section 1350 Certification of Chief Financial Officer and principal executive officer | X | |||
| EX-101.INS | XBRL Instance Document | X | |||
| EX-101.SCH | XBRL Taxonomy Extension Schema | X | |||
| EX-101.PRE | XBRL Taxonomy Extension Presentation Linkbase | X | |||
| EX-101.LAB | XBRL Taxonomy Extension Label Linkbase | X | |||
| EX-101.CAL | XBRL Taxonomy Extension Calculation Linkbase | X | |||
| EX-101.DEF | XBRL Taxonomy Extension Definition Linkbase | X |
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In accordance with Section 13 or 15(d) of the Exchange Act of 1934, as amended, the registrant caused this Annual Report on Form 10-K/A to be signed on its behalf by the undersigned, thereunto duly authorized, in Helena, MT on this 31st day of August, 2016.
| BAKKEN RESOURCES, INC. | ||
| Date: September 1, 2016 | By: | /s/ Dan Anderson |
| Dan Anderson | ||
| Chief Financial Officer | ||
In accordance with Section 13 or 15(d) of the Exchange Act of 1934, as amended, this Annual Report on Form 10-K/A has been signed below by the following persons on behalf of the registrant in the capacities indicated below on this 31st day of August, 2016.
| Date: September 1, 2016 | By: | /s/ Dan Anderson |
| Dan Anderson | ||
| Chief Financial Officer and Director | ||
| Date: September 1, 2016 | By: | /s/ Karen Midtlyng |
| Karen Midtlyng | ||
| Secretary and Director | ||
| Date: September 1, 2016 | By: | /s/ Bill M. Baber |
| Bill M. Baber | ||
| Director | ||
| Date: September 1, 2016 | By: | /s/ Herman R. Landeis |
| Herman R. Landeis | ||
| Director | ||
| Date: September 1, 2016 | By: | /s/ Solange Charas |
| Solange Charas | ||
| Director and audit committee chair | ||
| Date: September 1, 2016 | By: | /s/ Douglas L. Williams |
| Douglas L. Williams | ||
| Director and audit committee member | ||
| Date: September 1, 2016 | By: | |
| Val M. Holms | ||
| Director | ||
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