Item 2. MANAGEMENTS
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
This discussion and
analysis of our financial condition and results of operations should be read in
conjunction with our financial statements and notes thereto included in this
quarterly report on Form 10-Q (the Quarterly Report) and the audited financial
statements and notes thereto included in our annual report on Form 10-K for the
year ended December 31, 2014 (the 2014 Annual Report), as filed with the
SEC on October 3, 2016. In addition to historical
information, this discussion and analysis contains forward-looking statements
that involve risks, uncertainties, and assumptions. Our actual results may
differ materially from those anticipated in these forward-looking statements as
a result of certain factors, including but not limited to those identified in
the 2014 Annual Report in the section entitled Risk Factors.
Overview
Bakken Resources, Inc. (the
Company, BRI, we, us, or our) is an independent energy company focused
on holding
non-working
interests
in oil and natural gas
properties throughout North America. Bakkens primary focus since inception has
been the Williston Basin in western North Dakota. The Company owns mineral
rights to approximately 7,200 gross acres and 1,600 net mineral acres of land
located about 8 miles southeast of Williston, North Dakota. The Companys assets
consist generally of net mineral acres spanning from the sub-surface to the base
of the so-called rock unit in an area commonly referred to as the Bakken
formation.
A non-working interest
simply means that the Company doesnt bear either the risk or the financial
burden attributable to exploration and production of oil and natural gas wells.
The Company simply invests in successful wells or projects that have
demonstrated a high degree of success. The Company partners with strong
operators to explore and develop oil and natural gas from company leases.
During the second quarter
of 2015, the Company received royalty and overriding royalty payments on
seventy-five (75) producing oil wells seventy-two (72) of which also produce
natural gas. This production and proved reserves are as follows:
|
Producing
|
Average
|
Proved
|
Percent
|
Q2
of 2015
|
|
Wells
|
Daily
|
Reserves
|
Proved
|
Average
|
|
|
Production
|
|
Developed
|
Price
|
Oil
|
75
|
11,158 Bbls
|
51,616,122 Bbls
|
28%
|
44.48
|
Natural Gas
|
72
|
10,686 MCF
|
78,670,481 MCF
|
22%
|
3.32
|
Bbls = Barrels MCF =
thousand cubic feet
The leases comprising the
Companys mineral rights average 17%. When the mineral rights were transferred
from Holms Energy LLC., Holms Energy LLC. retained a 5% overriding royalty.
Therefore, these mineral rights currently bear to us an average 12% royalty (17%
less 5%) from the oil and gas produced on such lands until November 2020. At
that time the 5% overriding royalty currently held by Holms Energy, LLC, a
related private Nevada company (Holms Energy) will revert back to the Company.
The Companys average net royalty interest is further reduced by the approved
North Dakota Industrial Commission (NDIC) well spacing units attributable to
each of the sixteen spacing units. The net average royalty percentage through
the second quarter was .8%.
We currently have leases
with three contracted oil drilling operators on various parcels of land
constituting the 7,200 gross acres (and approximately 1,600 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: (1) Oasis Petroleum, (2) Continental Resources, Inc., and (3) 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, Lessees can lose their leases.
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 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 Company sold these 800 net mineral acres to a third party in
February of 2014. The Company retained a two percent (2%) overriding royalty on
the sale of these mineral rights.
9
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 the Asset
Purchase Agreement with Holms Energy on December 10, 2010, MLS changed its name
to Bakken Resources, Inc. These transactions and the resulting change 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 from leasing its mineral
acreage. BRIs mineral acreage consists of approximately 1,600 net mineral acres
located primarily in McKenzie County, North Dakota. Such 1,600 net mineral acres
are currently spread across 17 spacing units. Operators covering BRIs minerals
have been approved for up to 15 wells per spacing unit (typically 1,280 acres),
but generally petition for permits prior to the commencement of drilling in a
particular spacing unit. If this holds for all spacing units under which BRI has
mineral acres, BRI would have a royalty interest in up to 187 wells. Note,
however, that the royalties due to BRI under any particular well vary based on
the number of acres BRI has under any particular spacing unit with a producing
well.
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 2,900 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 which include permitted
for Three Forks wells may result an increased number of total wells from which
the Company may derive royalty income.
When a horizontal well is
drilled in the area where the subject property is located, it is typically
drilled down about 10,800 vertical feet and then a down-hole directional
drilling tool is utilized to flatten the hole to 90 degrees and drill
horizontally down to 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. The Company also has 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/well-activity.
The information provided in
the website 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 in the
table are NDIC file numbers which can be used to search 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.
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. All
of the Companys current leases currently have active drilling operations and
are likely to have active operations in the foreseeable future.
Results of Operations
Comparison of the Three
and Six Months Ended June 30, 2015 and June 30, 2014
Key Trends.
The first half of 2015 witnessed
several trends that are driving net income:
●
|
Oil and Natural Gas Prices
: Oil and natural gas unit prices have
declined sharply since hitting highs in June. Currently, these unit prices
are 54% lower than their 2014 peak. While we believe prices will increase,
it may be a couple of years before they return to levels greater than $70
per barrel.
|
|
|
●
|
Oil and Natural Gas Production
Levels
: Although unit
prices are down, production is at record highs. The higher production is
attributed to the substantial increase in producing wells since 2014.
However, a slowdown in the number of new producing wells
was seen in the second quarter 2015. The
higher production is not sufficient to offset the impact of lower prices,
and operating revenue is down substantially from 2014.
|
10
●
|
Net Royalty Interest
: The new producing wells have boosted
production and revenue, but have driven net royalty percentage down by
more than 16% (.9659% versus .8032%). The lower net royalty percentage
when coupled with lower gross revenue affects the bottom
line.
|
|
|
●
|
Legal and Investigation Related
Costs
: Operating expenses
have increased due to high legal fees attributed to ongoing litigation and
the ongoing internal investigation.
|
Collectively, these trends
have created an operating loss for the first six months of 2015.
Unit prices are expected to
increase over the next two years, thus driving revenue upward. Legal fees are
also expected to decrease significantly as the remaining lawsuits are resolved
and the investigation costs end.
Revenue
. We generated net revenue (gross revenue less
production taxes and deductions) for the three months ended June 30, 2015
totaling $235,202 compared to revenue of $423,113 for the three months June 30,
2014. The decrease relative to 2014 reflects the sale of the Greenfield assets
(33% of total mineral acres), declining oil and natural gas unit prices
(fifty-four percent 54%), and lower net royalty interest. Although unit prices
are down relative to the second quarter 2014, production is up substantially
from 2014. For the six months ending June 30, 2015, oil production totaled two
million (2,000,000) barrels versus one million four hundred thousand barrels
(1,400,000) during the first six months of 2014. This represents a forty-six
percent increase (46%). Natural gas topped one million nine hundred thousand
(1,900,000) MCF for the six months ended June 30, 2015 versus one million four
hundred thousand (1,400,000) MCF in 2014, or a thirty-seven percent (37%)
increase.
While lower unit prices and
higher production affected revenue, the Companys net royalty interest also
declined in the six months ended June 30, 2015. The Companys net royalty
interest is affected by the acreage attributed to each spacing unit as well as
the producing formation. The increase in the number of wells producing from the
Three Forks formation producing wells decreases our net royalty interest since
the Company only accrues a two (2) percentage point retained royalty on these
wells. Similarly, as the Companys well portfolio grows in areas where our
acreage is lower, our average net royalty interest declines. During the first
half of 2015 we our average net royalty interest was .80% versus 1.12% in the
first half of 2014.
Throughout 2014, the
Company saw many new wells begin producing and this trend continued into 2015.
The producing well count at June 30, 2015, seventy-four (74), increased by
twenty-four (24) wells compared to June 30, 2014. The Company currently has
seventy-four (74) producing wells, seven (7) wells in confidential status, and
twenty-nine (29) wells being drilled.
Revenue is driven by
product unit prices and volume. Although the Company sold 33% of its mineral
rights in 2014 and production unit prices have declined more than fifty four
percent (54%) since 2014 highs, new well production is partially offsetting
lower prices. As unit prices rebound, new production continue to drive revenue
and profitability. The State of North Dakota establishes spacing rules that
dictate how many wells can be drilled and operated over a defined area (acres).
Based on current spacing units, the Company has current well capacity totaling
one hundred ninety wells (190). Therefore, the Company has capacity for an
additional eighty (80) wells. These potential additional wells offer little risk
since they will be drilled into known reserves where existing wells are already
producing successfully. Therefore, current year and future revenue will likely
continue to increase without a significant increase in operating
expenses.
Typically, royalty checks
from oil well operators can be delivered anytime between sixty (60) to one
hundred and fifty (150) days following the month of initial production.
Following oil well production, the operator will usually seek a division order
title opinion from an attorney which would describe the ownership of the
production. Following issuance of this opinion, the operator generally issues
division orders which sets forth payments to the royalty holders. North Dakota
law requires payment of eighteen (18%) annual interest if royalty payments are
not made within one hundred and fifty (150) days after oil or gas produced by
the well is marketed. For additional information regarding the rights of royalty
holders, see the Royalty Owner Information Center link found on the website
for the North Dakota Petroleum Council, www.ndoil.org. To date,
the Company has not received any payments of interest for royalty payments that
have not been made within 150 days of oil or gas production.
Operating
Expenses
. Operating expenses fell
sharply, $889,736, or forty nine percent (49%)for the six months ended June 30,
2015 compared to June 30, 2014, driven by substantially lower legal and
professional fees ($704,697 versus $929,674). Several contracted positions have
been consolidated into existing staff. Legal costs are also decreasing as a
result of Director and Officers insurance reimbursement for costs relating to
the derivative lawsuit, and as the number of outstanding litigations has
decreased. General and administrative expenses were $58,545 for the six months
ended June 30, 2015 compared to $48,347 for the same period in 2014 reflecting
higher insurance costs
Net loss for the second
quarter 2015 totaled $287,593 versus $789,582 in the second quarter 2014. Lower
revenue driven by lower unit prices could not be offset by lower operating
costs.
11
Our material financial
obligations include our salaries paid to our three current employees, fees paid
to outside consultants, public company reporting expenses, transfer agent fees,
bank fees, and other recurring fees.
Liquidity and Capital
Resources
As of June 30, 2015, the
Company had cash of $6,014,652 compared to $6,334,092 as of December 31, 2014.
As of June 30, 2015, the Company has expended $725,750 to acquire the Big Willow
lease.
Operating costs consist
mainly of salaries, office rent and professional fees and is consistent with
general operating cash used in prior quarters. Net cash provided (used) in
operations for the period ended June 30, 2015 was $489,440
compared to $489,492 during the six months ended June 30, 2014. The
increase reflects higher professional fees attributable to the number of
lawsuits in which the Company is currently involved and the internal
investigation costs. 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.
In the future, we
anticipate we will be able to provide the necessary liquidity from royalty
revenues related to sale of oil reserves of existing properties. No assurances,
however, can be given that such royalties will continue to be received. As of
June 30, 2015, the royalty revenues received have been sufficient to provide
liquidity during the previous twelve months. If the Company does not generate
sufficient revenues it will continue to finance operations through equity or
debt financings.
We will continue to
evaluate additional properties containing mineral rights that we may seek to
acquire. With respect to transactions involving the acquisition of additional
mineral rights or other business collaboration transactions, we may seek to
issue shares of our common stock or other equity to finance part or all such
acquisitions or transactions. To the extent that such acquisitions or
transactions require cash payments, such payments will likely have a material
impact on our liquidity.
Our proposed operations may
require additional capital from outside sources. However, we may not be
successful in obtaining cash from new or existing agreements, or in receiving
royalty payments under our existing leases. In addition, we cannot be sure that
additional financing will be available when needed or that, if available,
financing will be obtained on terms favorable to us or to our stockholders.
Having insufficient funds may require us to delay, scale back, or eliminate some
or all of our business development activities. Failure to obtain adequate
financing also may adversely affect our ability to operate as a going concern.
If we raise additional funds from the issuance of equity securities, substantial
dilution to our existing stockholders would likely result. If we raise
additional funds by incurring debt financing, the terms of the debt may involve
significant cash payment obligations as well as covenants and specific financial
ratios that may restrict our ability to operate our business.
Satisfaction of our
cash obligations for the next twelve (12) months
A critical component of our
operating plan impacting our continued existence is the ability to obtain
additional capital through additional equity or debt financing and JV drilling
partnerships. In the event we cannot obtain the necessary capital to pursue our
strategic plan, we may have to cease or significantly curtail our operations.
This would materially impact our ability to continue operations. However, due to
our low base overhead, we are not dependent on new capital if we do not wish to
develop our drilling programs or buy up working interests in potential wells
during the next twelve (12) months.
Since inception, we have
financed cash flow requirements through debt financing and issuance of common
stock for cash and services. As we expand operational activities, we may
continue to experience net negative cash flows from operations, pending receipt
of sales or development fees, and will be required to obtain additional
financing to fund operations through common stock offerings and debt borrowings
to the extent necessary to provide working capital.
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 have information that an
additional thirty six (36) wells are either permitted, drilling, or are in
confidential status. Although we believe that our 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 be no assurance that we will be successful in addressing
operational risks, and the failure to do so can have a material adverse effect
on our business prospects, financial condition and results of operations.
12
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, Estimates, and Judgments
Our financial statements
are prepared in accordance with GAAP. The preparation of these financial
statements requires us to make estimates and judgments that affect the reported
amounts of assets and liabilities, 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. We continually evaluate our
estimates and judgments, the most critical of which are those related to revenue
recognition, the timing of the royalty revenues, and income taxes. We base our
estimates and judgments on historical experience and other factors that we
believe to be reasonable under the circumstances. Materially different results
can occur as circumstances change and additional information becomes known.
Besides the estimates
identified above that are considered critical, we make many other accounting
estimates in preparing our financial statements and related disclosures. All
estimates, whether or not deemed critical, affect reported amounts of assets,
liabilities, revenues, and expenses, as well as disclosures of contingent assets
and liabilities. These estimates and judgments are also based on historical
experience and other factors that are believed to be reasonable under the
circumstances. Materially different results can occur as circumstances change
and additional information becomes known, even for estimates and judgments that
are not deemed critical.
For further information,
refer to the consolidated financial statements and notes thereto included in the
Companys annual report on Form 10-K for the year ended December 31,
2014.