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UNITED
STATES
SECURITIES AND
EXCHANGE COMMISSION
WASHINGTON,
D.C. 20549
FORM
10-K/A
(Amendment No. 2)
[X]
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Annual Report under Section 13 or 15(d) of the Securities Exchange Act of 1934 for the fiscal year ended
December 31, 2013.
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[
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Transition
Report pursuant to Section 13 or 15(d) of the
Securities Exchange Act of
1934 for the
transition period
from _____ to _____.
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Commission File Number:
000-53632
BAKKEN RESOURCES, INC.
(Exact name
of small business issuer as specified in its
charter)
Nevada
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26-2973652
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(State or other jurisdiction of
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(I.R.S. employer
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incorporation or organization)
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identification number)
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825 Great Northern
Boulevard
Expedition Block, Suite 304
Helena, Montana
59601
(Address of principal executive offices and zip code)
(406)
442-9444
(Registrants 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
registrants 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 [ ]
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Accelerated
filer [ ]
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Non-accelerated filer [ ]
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Smaller
reporting company [X]
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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 Registrants 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 issuers common stock as of August 31, 2016 is 56,735,350
shares.
DOCUMENTS INCORPORATED BY
REFERENCE
Amendment No. 1 to Bakkens 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
ITEM 1. BUSINESS.
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 Companys 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 Companys 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 Bakkens monthly net royalty paid by the companys
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 companys net mineral interest to
derive the companys 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 companys inception. Prior SEC filings
included examples which erroneously discussed the application of the overriding
royalty and included examples of such.
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Overriding royalty
calculation example: Missoula 1-21H
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Gross Mineral Acres:
640.00 (Independently Confirmed by Third Party Certified
Landman)
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Net Mineral Interest:
16.18993% (Independently Confirmed by Third Party Certified
Landman)
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Net Mineral Acres:
103.62 (640.00 x 16.18993%)
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Stated Lease Royalty
Percentage: 17%
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North Dakota
Industrial Commission Established Spacing Unit: 1280
acres
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Bakken Net Royalty
Percentage: 1.3761433% (derived as (103.62 x 17%)/1280)
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December 2013 Oil
Production: 4,565 Barrels (Continental Resources 1/2014 Remittance
Statement)
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December 2013 Oil
Sales Price: 85.8941 (Continental Resources Remittance
Statement)
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Post Production Costs
- $206.31
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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. BRIs 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 BRIs
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 BRIs 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 (1
st
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 Companys current net
mineral acres include acreage in the Three Forks formation, any increase in the
drilling operations on the Companys 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 websites 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 Companys 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 Companys 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 NDICs 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
|
●
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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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Table of Contents
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
InformationReports 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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Table of Contents
ITEM 1A. RISK FACTORS
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;
|
●
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their expertise and financial resources;
|
●
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approval of other participants in drilling
wells;
|
●
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selection of technology; and
|
●
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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 operators 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;
|
●
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success of the development and exploration
program conducted by the oil company Lessees operating on our
property;
|
●
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demand for natural gas and oil;
|
●
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the level of our competition;
|
●
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our ability to attract and maintain key
management and employees; and
|
●
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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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Table of Contents
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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Table of Contents
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:
●
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the validity of our assumptions about reserves,
future production, revenues and costs;
|
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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;
|
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in the case of an acquisition, a significant
increase in our interest expense or financial leverage if we incur
additional debt to finance acquisitions;
|
●
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the assumption of unknown
liabilities, losses or costs for which we are not indemnified or for which
our indemnity is inadequate;
|
●
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an inability to hire, train or
retain qualified personnel to manage and operate our growing business and
assets; and
|
●
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an increase in our costs or a
decrease in our revenues associated with any potential royalty owner or
landowner claims or disputes;
|
●
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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.
20
Table of Contents
Net Royalty Interest
Volatility
The Companys 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 Companys 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 Companys 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 Companys 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 arms 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 Companys royalty revenue may be adversely impacted by
such an affiliate sale.
Large
Shareholders
Certain shareholders hold
large portions of shares of the Companys stock. As a result, the possibility
exists that significant actions (such as voting or changing members of the
Companys Board of Directors) may occur by written consent rather than following
a publicly filed document soliciting the vote or consent of the Companys
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 purchasers
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-dealers
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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Table of Contents
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:
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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;
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announcements of new acquisitions, reserve
discoveries or other business initiatives by our competitors;
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our ability to take advantage of new
acquisitions, reserve discoveries or other business initiatives;
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fluctuations in revenue from our
oil and gas business as new reserves come to market;
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changes in the market for oil and
natural gas commodities and/or in the capital markets generally;
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changes in the demand for oil and
natural gas, including changes resulting from the introduction or
expansion of alternative fuels;
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quarterly variations in our
revenues and operating expenses;
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changes in the valuation of
similarly situated companies, both in our industry and in other
industries;
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changes in analysts estimates
affecting our company, our competitors and/or our industry;
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changes in the accounting methods
used in or otherwise affecting our industry;
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additions and departures of key
personnel;
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announcements of technological
innovations or new products available to the oil and gas industry;
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announcements by relevant
governments pertaining to incentives for alternative energy development
programs;
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fluctuations in interest rates
and the availability of capital in the capital markets; and
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significant sales of our common
stock, including sales by selling stockholders following the registration
of shares under a prospectus.
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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
companys liquidity by draining cash in its defense and potential judgments,
could undermine profitability, and could undermine Bakkens 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:
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The domestic and foreign supply of oil and
nature gas;
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The current level of prices and expectations
about future prices of oil and natural gas;
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The level of global oil and natural gas
exploration and production;
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The cost of exploring for,
developing, producing and delivering oil and natural gas;
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The price of foreign oil and
natural gas imports;
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Political and economic conditions
in oil producing regions, including the Middle East, Africa, South America
and Russia;
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The ability of members of the
Organization of Petroleum Exporting Countries to agree to and maintain oil
price and production controls;
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Speculative trading in oil and
natural gas derivative contracts;
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The level of consumer product
demand;
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Weather conditions and other
natural disasters;
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Risks associated with operating
drilling rigs;
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Technological advances affecting
energy consumption;
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Domestic and foreign governmental
regulations and taxes;
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The continued threat of terrorism
and the impact of military and other action, including U.S. military
operations in the Middle East;
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The availability, proximity and
capacity of oil and natural gas transportation, processing, storage and
refining facilities;
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The price and availability of
alternative fuels; and
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Overall domestic and global
economic conditions.
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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 BRIs 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.
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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:
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delays imposed by or resulting from compliance
with regulatory requirements;
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pressure or irregularities in geological
formations;
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shortages of or delays in obtaining qualified
personnel or equipment, including drilling rigs and CO
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equipment failures or
accidents;
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adverse weather conditions, such
as freezing temperatures, hurricanes and storms;
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unexpected operational events,
including accidents;
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reductions in oil and natural gas
prices;
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proximity to and capacity of
transportation facilities;
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title problems; and
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limitations in the market for oil
and natural gas.
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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:
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domestic and foreign demand for oil and natural
gas by both refineries and end users;
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the introduction of alternative forms of fuel
to replace or compete with oil and natural gas;
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domestic and foreign reserves and supply of oil
and natural gas;
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competitive measures implemented
by our competitors and domestic and foreign governmental bodies;
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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;
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weather conditions; and
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domestic and foreign economic
volatility and stability.
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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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Table of Contents
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 techniques
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 EPAs 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 Earths 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 Earths 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 Obamas 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 Companys 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.
ITEM 2. PROPERTIES.
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
Companys 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 Companys 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 BRIs
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
|
28
Table of Contents
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.
29
Table of Contents
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 Companys 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 Companys current leases currently have
active drilling operations and are likely to have active operations in the
foreseeable future.
30
Table of Contents
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
Table of Contents
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 Companys mineral
acreage is likely to hold by production most if not all of the Companys 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
)
ITEM 3. LEGAL
PROCEEDINGS.
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 BRIs 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 Companys 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 Companys 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
Table of Contents
PART II
ITEM 5. MARKET FOR
REGISTRANTS COMMON EQUITY, RELATED STOCKHOLDER MATTERS, AND ISSUER PURCHASES OF
EQUITY SECURITIES.
Market Information
BRIs 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 brokers
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 BRIs 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 Boards 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 BRIs 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
Table of Contents
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. MANAGEMENTS
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
Table of Contents
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
Table of Contents
|
|
(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, BRIs 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
Table of Contents
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
companys 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 Companys 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
Table of Contents
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
Table of Contents
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 Commissions website. The royalty income is calculated
monthly.
ITEM 7A. QUANTITATIVE
AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Not applicable.
39
Table of Contents
ITEM 8. FINANCIAL
STATEMENTS AND SUPPLEMENTARY DATA
40
Table of Contents
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
Table of Contents
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
Table of Contents
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
Table of Contents
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
Table of Contents
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
Table of Contents
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
Table of Contents
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 Companys 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 assets 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
Table of Contents
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 Companys current dividend yield
as the best estimate of projected dividend yield for periods within the
contractual life of the option.
|
The Companys 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 Companys 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 Companys 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 Companys 2008 Non-Qualified Stock Option Plan
during 2012. No options were granted in 2013.
48
Table of Contents
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 Companys 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
Table of Contents
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 Energys 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
Table of Contents
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 Companys 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 Companys 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 Companys 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 Armstrongs 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.
51
Table of Contents
$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 Companys 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 Companys 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 Companys 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.
52
Table of Contents
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 Companys 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 Companys 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 BRIs 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 courts ruling against the plaintiff and
reversed the trial courts 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
Companys 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.
53
Table of Contents
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.
54
Table of Contents
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 Companys acreage. As a result, Oasis removed the suspension it
had placed on royalties based on production on the Companys 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 Companys 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 Companys Audit Committee, and the Companys Chairman and CEO, Val Holms, took a paid leave of absence during the investigation.
The Companys 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 Companys 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
2013s 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 companys net
royalty interests in each producing well in order to more accurately determine accrued royalty revenue
and verify payments from operators. But the landmans 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.
|
55
Table of Contents
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
|
56
Table of Contents
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 companys principal
executive and principal financial officers and effected by a companys 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 companys 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 companys registered public accounting firm
regarding internal control over financial reporting. Managements report was not
subject to attestation by the companys registered public accounting firm
pursuant to temporary rules of the Securities and Exchange Commission that
permit the company to provide only managements 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.
|
57
Table of Contents
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 companys 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 companys net royalty interest to each operator. We also began verifying
each months production and producing formation with the North Dakota Industrial
Commission database for each producing well. The companys mineral estate is
split; the companys 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 Companys outside
auditors, MaloneBailey, to discuss the appropriate accounting treatment and
proper disclosures. The Companys 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.
ITEM 9B
OTHER INFORMATION
None.
PART III
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
Energys 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 BRIs 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
|
58
Table of Contents
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 persons 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, 4
th
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 Companys 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.
59
Table of Contents
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
Companys executive officers, directors and persons who own more than 10% of the
Companys 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 Directors 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.
60
Table of Contents
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 managements 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 officers 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
|
|
|
|
|
|
|
|
|
|
|
61
Table of Contents
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. Holms 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)
|
|
*
|
62
Table of Contents
|
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 Companys 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 Bakkens monthly net royalty paid by the companys
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 companys net mineral interest to
derive the companys 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 companys 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 Armstrongs 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.
63
Table of Contents
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 Committees
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.
64
Table of Contents
PART IV
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
|
65
Table of Contents
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
|
|
|
|
66
Table of Contents
SIGNATURES
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
|
67