BLACK RIDGE OIL & GAS, INC.
CONDENSED STATEMENTS OF CASH FLOWS
(Unaudited)
|
|
For the Three Months
|
|
|
|
Ended March 31,
|
|
|
|
2017
|
|
|
2016
|
|
CASH FLOWS FROM OPERATING ACTIVITIES
|
|
|
|
|
|
|
|
|
Net loss
|
|
$
|
(152,717
|
)
|
|
$
|
(7,915,513
|
)
|
Loss from discontinued operations, net of income taxes
|
|
|
–
|
|
|
|
(7,226,719
|
)
|
Loss from continuing operations
|
|
|
(152,717
|
)
|
|
|
(688,794
|
)
|
|
|
|
|
|
|
|
|
|
Adjustments to reconcile net loss from continuing operations to net cash
provided by (used in) operating activities from continuing operations:
|
|
|
|
|
|
|
|
|
Depreciation and amortization
|
|
|
3,100
|
|
|
|
3,885
|
|
Loss on sale of property and equipment
|
|
|
4,714
|
|
|
|
–
|
|
Common stock options issued to employees and directors
|
|
|
159,492
|
|
|
|
157,824
|
|
Decrease (increase) in current assets:
|
|
|
|
|
|
|
|
|
Due from Black Ridge Holdings Company LLC
|
|
|
587
|
|
|
|
–
|
|
Prepaid expenses
|
|
|
25,645
|
|
|
|
(18,013
|
)
|
Increase (decrease) in current liabilities:
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
|
17,259
|
|
|
|
19,060
|
|
Accrued expenses
|
|
|
10,520
|
|
|
|
20,378
|
|
Net cash provided by (used in) operating activities from continuing operations
|
|
|
68,600
|
|
|
|
(505,660
|
)
|
Net cash provided by operating activities from discontinued operations
|
|
|
–
|
|
|
|
247,277
|
|
Net cash provided by (used in) operating activities
|
|
|
68,600
|
|
|
|
(258,383
|
)
|
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM INVESTING ACTIVITIES
|
|
|
|
|
|
|
|
|
Proceeds from sale of property and equipment
|
|
|
2,160
|
|
|
|
–
|
|
Net cash provided by investing activities from continuing operations
|
|
|
2,160
|
|
|
|
–
|
|
Net cash used in investing activities from discontinued operations
|
|
|
–
|
|
|
|
(1,149,789
|
)
|
Net cash provided by (used in) investing activities
|
|
|
2,160
|
|
|
|
(1,149,789
|
)
|
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM FINANCING ACTIVITIES
|
|
|
|
|
|
|
|
|
Net cash provided by financing activities of discontinued operations
|
|
|
–
|
|
|
|
1,400,000
|
|
Net cash provided by financing activities
|
|
|
–
|
|
|
|
1,400,000
|
|
|
|
|
|
|
|
|
|
|
NET CHANGE IN CASH
|
|
|
70,760
|
|
|
|
(8,172
|
)
|
CASH AT BEGINNING OF PERIOD
|
|
|
66,269
|
|
|
|
228,194
|
|
CASH AT END OF PERIOD
|
|
$
|
137,029
|
|
|
$
|
220,022
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SUPPLEMENTAL INFORMATION:
|
|
|
|
|
|
|
|
|
Interest paid
|
|
$
|
–
|
|
|
$
|
1,114,527
|
|
Income taxes paid
|
|
$
|
–
|
|
|
$
|
–
|
|
|
|
|
|
|
|
|
|
|
NON-CASH INVESTING AND FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
Net change in accounts payable for purchase of oil and gas properties
|
|
$
|
–
|
|
|
$
|
(237,303
|
)
|
See accompanying notes to financial statements.
BLACK RIDGE OIL & GAS, INC.
Notes to Financial Statements
Note 1 – Organization and Nature of
Business
Effective April 2, 2012, Ante5, Inc. changed
its corporate name to Black Ridge Oil & Gas, Inc., and continues to be quoted on the OTCQB under the trading symbol “ANFC”.
Black Ridge Oil & Gas, Inc. (formerly Ante5, Inc.) (the “Company”) became an independent company in April 2010.
We became a publicly traded company when our shares began trading on July 1, 2010. Since October 2010, we had been engaged
in the business of acquiring oil and gas leases and participating in the drilling of wells in the Bakken and Three Forks trends
in North Dakota and Montana.
On June 21, 2016 we closed on a debt restructuring
transaction with our secured lenders as described in Note 3 – Debt Restructuring. Following the transaction, our focus has
been managing the oil and gas assets in which we continue to have an indirect minority interest. Our management services agreement
related to those same oil and gas assets was terminated on April 3, 2017, effective June 30, 2017, as described in Note 18 –
Subsequent Events. In addition, we will continue to pursue distressed asset acquisitions in the Bakken and/or Three Forks and other
formations that may be acquired with our existing joint venture partners or other capital providers.
Note 2 – Basis of Presentation and
Significant Accounting Policies
The interim condensed financial statements
included herein, presented in accordance with United States generally accepted accounting principles and stated in US dollars,
have been prepared by the Company, without audit, pursuant to the rules and regulations of the Securities and Exchange Commission.
Certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted
accounting principles have been condensed or omitted pursuant to such rules and regulations, although the Company believes that
the disclosures are adequate to not make the information presented misleading.
These statements reflect all adjustments, which
in the opinion of management, are necessary for fair presentation of the information contained therein. Except as otherwise disclosed,
all such adjustments are of a normal recurring nature. It is suggested that these interim condensed financial statements be read
in conjunction with the audited financial statements for the year ended December 31, 2016, which were included in our
Annual Report on Form 10-K. The Company follows the same accounting policies in the preparation of interim reports.
Reclassifications
As discussed in Note 3 – Debt Restructuring,
income, expense and cash flows from the restructured operations for the three months ended March 31, 2016 have been reclassified
as net loss and cash flows from discontinued operations.
Use of Estimates
The preparation of financial statements in
conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the
reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements
and the reported amount of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Environmental Liabilities
The oil and gas industry is subject, by its
nature, to environmental hazards and clean-up costs. At this time, management knows of no substantial losses from environmental
accidents or events which would have a material effect on the Company.
Cash and Cash Equivalents
Cash equivalents include money market accounts
which have maturities of three months or less. For the purpose of the statements of cash flows, all highly liquid investments with
an original maturity of three months or less are considered to be cash equivalents. Cash equivalents are stated at cost plus accrued
interest, which approximates market value. No cash equivalents were on hand at March 31, 2017 and December 31, 2016.
Cash in Excess of FDIC Insured Limits
The Company maintains its cash in bank deposit
accounts which, at times, may exceed federally insured limits. Accounts are guaranteed by the Federal Deposit Insurance Corporation
(FDIC) and the Securities Investor Protection Corporation (SIPC) up to $250,000 and $500,000, respectively, under current regulations.
The Company had approximately $-0- and $-0- in excess of FDIC and SIPC insured limits at March 31, 2017 and December 31, 2016,
respectively. The Company has not experienced any losses in such accounts.
BLACK RIDGE OIL & GAS, INC.
Notes to Financial Statements
Website Development Costs
The Company accounts for website development
costs in accordance with ASC 350-50, “Accounting for Website Development Costs” (“ASC 350-50”), wherein
website development costs are segregated into three activities:
|
1)
|
Initial stage (planning), whereby the related costs are expensed.
|
|
2)
|
Development (web application, infrastructure, graphics), whereby the related costs are capitalized
and amortized once the website is ready for use. Costs for development content of the website may be expensed or capitalized depending
on the circumstances of the expenditures.
|
|
3)
|
Post-implementation (after site is up and running: security, training, administration), whereby
the related costs are expensed as incurred. Upgrades are usually expensed, unless they add additional functionality.
|
We have capitalized a total of $56,660 of website
development costs from inception through March 31, 2017. We depreciate our website development costs on a straight line basis over
the estimated useful life of the assets, which is currently three years. We have recognized depreciation expense on these website
costs of $-0- and $-0- for the three months ended March 31, 2017 and 2016, respectively, as all website development costs have
been fully depreciated.
Income Taxes
The Company recognizes deferred tax assets
and liabilities based on differences between the financial reporting and tax basis of assets and liabilities using the enacted
tax rates and laws that are expected to be in effect when the differences are expected to be recovered. The Company provides a
valuation allowance for deferred tax assets for which it does not consider realization of such assets to be more likely than not.
Basic and Diluted Loss Per Share
The basic net loss per share is computed by
dividing the net loss (the numerator) by the weighted average number of common shares outstanding for the period (the denominator).
Diluted net loss per common share is computed by dividing the net loss by the weighted average number of common shares and potential
common shares outstanding (if dilutive) during each period. Potential common shares include stock options, warrants and restricted
stock. The number of potential common shares outstanding relating to stock options, warrants and restricted stock is computed using
the treasury stock method. For the periods presented, potential dilutive securities had an anti-dilutive effect and were not included
in the calculation of diluted net loss per common share.
Fair Value of Financial Instruments
Under FASB ASC 820-10-05, the Financial Accounting
Standards Board establishes a framework for measuring fair value in generally accepted accounting principles and expands disclosures
about fair value measurements. This Statement reaffirms that fair value is the relevant measurement attribute. The adoption of
this standard did not have a material effect on the Company’s financial statements as reflected herein. The carrying amounts
of cash, accounts payable and accrued expenses reported on the balance sheets are estimated by management to approximate fair value
primarily due to the short term nature of the instruments.
The Company had no items that required fair
value measurement on a recurring basis.
Property and Equipment
Property and equipment that are not oil and
gas properties are recorded at cost and depreciated using the straight-line method over their estimated useful lives of three to
seven years. Expenditures for replacements, renewals, and betterments are capitalized. Maintenance and repairs are charged to operations
as incurred. Long-lived assets, other than oil and gas properties, are evaluated for impairment to determine if current circumstances
and market conditions indicate the carrying amount may not be recoverable. The Company has not recognized any impairment losses
on non-oil and gas long-lived assets. Depreciation expense was $3,100 and $3,885 for the three months ended March 31, 2017 and
2016, respectively.
Revenue Recognition
The Company recognizes management fee income
as services are provided.
The Company recognized oil and gas revenues
from its former interests in producing wells when production was delivered to, and title was transferred to, the purchaser and
to the extent the selling price is reasonably determinable. Oil and gas revenues are reflected as a component of discontinued operations
on the statements of operations.
BLACK RIDGE OIL & GAS, INC.
Notes to Financial Statements
Asset Retirement Obligations
The Company records the fair value of a liability
for an asset retirement obligation in the period in which the well is spud or the asset is acquired and a corresponding increase
in the carrying amount of the related long-lived asset. The liability is accreted to its present value each period, and the capitalized
cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded
amount, a gain or loss is recognized. The expense related to accretion of the discount on the asset retirement liability is reflected
as a component of discontinued operations on the statement of operations for the three months ended March 31, 2016.
Full Cost Method
The Company followed the full cost method of
accounting for oil and gas operations in 2016 whereby all costs related to the exploration and development of oil and gas properties
were initially capitalized into a single cost center ("full cost pool"). The Company had no oil and gas operations in
2017 as they were disposed as part of the debt restructuring transaction on June 21, 2016 described in Note 3 – Debt Restructuring.
Capitalized costs included land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties,
costs of drilling directly related to acquisition, and exploration activities. Internal costs that were capitalized were directly
attributable to acquisition, exploration and development activities and did not include costs related to the production, general
corporate overhead or similar activities. Costs associated with production and general corporate activities were expensed in the
period incurred. Capitalized costs for the three month period ended March 31, 2016 are summarized as follows:
|
|
Three Months
Ended
|
|
|
|
March 31, 2016
|
|
Capitalized Certain Payroll and Other Internal Costs
|
|
$
|
–
|
|
Capitalized Interest Costs
|
|
|
7,219
|
|
Total
|
|
$
|
7,219
|
|
Proceeds from sales of proved properties were
credited to the full cost pool, with no gain or loss recognized, unless such a sale would significantly altered the relationship
between capitalized costs and the proved reserves attributable to these costs. A significant alteration would typically involve
a sale of 20% or more of the proved reserves related to a single full cost pool. The Company assessed all items classified as unevaluated
property on a quarterly basis for possible impairment or reduction in value. The assessment included consideration of the following
factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity;
the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period
in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion
of the associated leasehold costs were transferred to the full cost pool and were then subject to amortization.
Capitalized costs associated with impaired
properties and properties having proved reserves, estimated future development costs, and asset retirement costs under FASB ASC
410-20-25 were depleted and amortized on the unit-of-production method based on the estimated gross proved reserves as determined
by independent petroleum engineers. The costs of unproved properties were withheld from the depletion base until such time as they
are either developed or abandoned.
Capitalized costs of oil and gas properties
(net of related deferred income taxes) could not exceed an amount equal to the present value, discounted at 10% per annum, of the
estimated future net cash flows from proved oil and gas reserves plus the cost of unproved properties (adjusted for related income
tax effects). Should capitalized costs exceed this ceiling, an impairment was recognized. The present value of estimated future
net cash flows was computed by applying the arithmetic average first day price of oil and natural gas for the preceding twelve
months to estimated future production of proved oil and gas reserves as of the end of the period, less estimated future expenditures
to be incurred in developing and producing the proved reserves and assuming continuation of existing economic conditions. Such
present value of proved reserves' future net cash flows excludes future cash outflows associated with settling asset retirement
obligations. When this comparison indicated an excess carrying value, the excess was charged to earnings as an impairment expense.
The Company recognized an impairment loss of $5,219,000 during the three months ended March 31, 2016. The impairment loss is reflected
as a component of discontinued operations on the statement of operations for the period.
Stock-Based Compensation
The Company adopted FASB guidance on stock
based compensation upon inception at April 9, 2010. Under FASB ASC 718-10-30-2, all share-based payments to employees, including
grants of employee stock options, are recognized in the income statement based on their fair values. Expense related to common
stock and stock options issued for services and compensation totaled $159,492 and $157,824 for the three months ended March 31,
2017 and 2016, respectively, using the Black-Scholes options pricing model and an effective term of 6 to 6.5 years based on the
weighted average of the vesting periods and the stated term of the option grants and the discount rate on 5 to 7 year U.S. Treasury
securities at the grant date.
BLACK RIDGE OIL & GAS, INC.
Notes to Financial Statements
Uncertain Tax Positions
Effective upon inception at April 9, 2010,
the Company adopted standards for accounting for uncertainty in income taxes. These standards prescribe a recognition threshold
and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken
in a tax return. These standards also provide guidance on de-recognition, classification, interest and penalties, accounting in
interim periods, disclosure, and transition.
Various taxing authorities may periodically
audit the Company’s income tax returns. These audits include questions regarding the Company’s tax filing positions,
including the timing and amount of deductions and the allocation of income to various tax jurisdictions. In evaluating the exposures
connected with these various tax filing positions, including state and local taxes, the Company records allowances for probable
exposures. A number of years may elapse before a particular matter, for which an allowance has been established, is audited and
fully resolved. Black Ridge Oil & Gas, Inc. has not yet undergone an examination by any taxing authorities.
The assessment of the Company’s tax position
relies on the judgment of management to estimate the exposures associated with the Company’s various filing positions.
Derivative Instruments and Price Risk Management
During the 2016 period, while the Company had
oil and gas operations, the Company entered into derivative contracts, including price swaps, caps and floors, which required payments
to (or receipts from) counterparties based on the differential between a fixed price and a variable price for a fixed quantity
of crude oil without the exchange of underlying volumes. The notional amounts of these financial instruments were based on a portion
of the expected production from existing wells.
Any realized gains and losses were recorded
to gain (loss) on settled derivatives and unrealized gains or losses as a result of mark-to market valuations were recorded to
gain (loss) on the mark-to-market of derivatives and are included as a component of loss from discontinued operations on the statements
of operations.
Recent Accounting Pronouncements
New accounting pronouncements are issued by
the Financial Accounting Standards Board (“FASB”) that are adopted by the Company as of the specified effective date.
If not discussed below, management believes there have been no developments to recently issued accounting standards, including
expected dates of adoption and estimated effects on our financial statements, from those disclosed in our Annual Report on Form
10-K for the year ended December 31, 2016.
Note 3 – Debt Restructuring
On March 29, 2016, the Company entered into
an Asset Contribution Agreement with Black Ridge Holding Company, LLC, a Delaware limited liability company (“BRHC”)
which was recently formed by the Company to contribute and assign to BRHC, all of the Company's (i) oil and gas assets (including
working capital and tangible and intangible assets) (the “Assets”), (ii) outstanding balances under that certain Credit
Agreement between the Company, as borrower, and Cadence Bank, N.A. (“Cadence”), as lender (the “Cadence Credit
Facility”) and the outstanding balances under that certain Credit Agreement between the Company, as borrower, and the several
banks and other financial institutions or entities from time to time parties thereto (the “Chambers”), and Chambers,
as administrative agent (the “Chambers Credit Facility”) and (iii) all current liabilities related to the Assets, in
exchange for 5% of the issued and outstanding Class A Units (the “Class A Units”) in BRHC (the “Asset Contribution”).
On March 29, 2016, affiliates of Chambers Energy Management, LP (“Chambers”) (specifically, Chambers Energy Capital
II, LP and CEC II TE, LLC (collectively, the “Chambers Affiliates”)) entered into a Debt Contribution Agreement between
BRHC and the Chambers Affiliates, pursuant to which BRHC issued a number of Class A Units representing 95% of the Class A Units
of BRHC to the Chambers Affiliates in exchange for the release of BRHC's obligations under the Chambers Credit Facility (the “Satisfaction
of Debt” and, together with the Asset Contribution, the “BRHC Transaction”). Concurrent with the Satisfaction
of Debt, each warrant originally issued with the Chambers Credit Facility was automatically retired and cancelled. The closing
of the BRHC Transaction was subject to the Company obtaining the approval of stockholders holding a majority of its outstanding
capital stock and to the Company having assigned the Cadence Credit Agreement to BRHC with Cadence’s consent, and BRHC and
Cadence entering into any applicable amendment agreements related to such assignment and waiver of financial covenant ratio compliance
for the quarter ended December 31, 2015 and quarter ending March 31, 2016.
On June 21, 2016,
the Company satisfied all of these conditions and, for accounting purposes, the BRHC Transaction was closed. The parties agreed
that the BRHC Transaction, the Asset Contribution and the Satisfaction of Debt were effective, for valuation purposes, as of April
1, 2016.
BLACK RIDGE OIL & GAS, INC.
Notes to Financial Statements
The terms of the Class A Units of BRHC are
set forth in the limited liability company agreement of BRHC (the “LLC Agreement”), which became effective upon the
closing of the BRHC Transaction. All distributions by BRHC of cash or other property, and whether upon liquidation or otherwise,
are to be made as follows:
|
•
|
First, 100% to the Class A Members, pro rata, until each Class A Member has received distributions
in aggregate totaling the then Class A Preference, which is an amount equal to a 10.0% internal rate of return on the invested
capital amount.
|
|
•
|
Second, 90% to the Class A Members, pro rata, and 10% to the Class B Members, pro rata, until such
time as the aggregate distributions to Chambers equals 250% of the capital contribution of its Class A Units.
|
|
•
|
Third, 80% to the Class A Members, pro rata, and 20% to the Class B Members, pro rata.
|
BRHC is managed by the BRHC Board, which is
responsible for the conduct of the day-to-day business of BRHC and the management, oversight and disposition of the assets of BRHC.
The initial BRHC Board is comprised of three managers, consisting of two managers appointed by Chambers and one member from the
Company.
In addition, under the LLC Agreement, Chambers
committed to contribute up to $30 million cash (the “Chambers Investment Commitment”) to BRHC in exchange for Class
A Units. At Closing, Chambers funded $10 million (the “Initial Chambers Investment”) of the Chambers Investment Commitment,
the proceeds of which were used to reduce outstanding amounts owed by BRHC to Cadence under the Cadence Credit Facility and for
general corporate purposes. The remaining $20 million (the “Subsequent Chambers Investment”), subject to certain conditions,
could be called from time to time during the Investment Period by the board of managers of BRHC (the “BRHC Board”).
The Initial Chambers Investment and any Subsequent Chambers Investment shall serve to proportionately reduce the Company's Class
A Units percentage ownership in BRHC. The investment period is the lesser of three years or such time as the entire Chambers Investment
Commitment has been called by the BRHC Board (the “Investment Period”). Any portion of Chambers Investment Commitment
not called by the BRHC Board prior to the expiration of the Investment Period will be cancelled. In no event will Chambers be required
to make a capital contribution in an amount in excess of its undrawn commitment.
The Company was granted 1,000,000 Class B Units
in BRHC at the Closing of the BRHC Transaction. At the discretion of the BRHC’s Board of Managers, the Company may be granted
additional Class B Units in BRHC, and in turn, the Company may transfer such Class B Units to certain members of the Company's
management. Subject to certain conditions, the Class B Units will entitle the holders to participate in any future distributions
of BRHC after distributions equal to the capital contributions and preferred return have been made to the holders of Class A Units
of BRHC.
At the closing of the BRHC Transaction, the
Company entered into a Management Services Agreement with BRHC. Under the Management Services Agreement, the Company provides services
to BRHC with respect to the business operations of BRHC, including but not limited to locating, investigating and analyzing potential
non-operator oil and gas projects and day-to-day operations related to such projects. The Company is paid a fee under the Management
Services Agreement intended to cover the costs of providing such services and is reimbursed for certain third party expenses. The
term of the Management Services Agreement commenced on the closing of the BRHC Transaction and continued indefinitely, until terminated,
which required a three month notice by the terminating party. The management services agreement was terminated by BRHC on April
3, 2017, effective June 30, 2017, as describe in Note 18 – Subsequent Events.
As a result of the transaction, the Company
recorded a gain on debt restructuring of $41,621,150 calculated as the difference between our final ownership interest in BRHC,
after conversion of debt to equity and the equity contribution of the Initial Chambers Investment within BRHC and the Company’s
retention of a 3.88% ownership interest in BRHC at the date of the restructuring, and the net book value of the assets and liabilities
the Company transferred to BRHC.
BLACK RIDGE OIL & GAS, INC.
Notes to Financial Statements
The
income and expense associated with the operating activities contributed in the BRHC Transaction are reflected as “Loss from
discontinued items, net of income taxes” on our condensed statement of operations for the three months ended March 31, 2016.
The items included in “Loss from discontinued operations, net of income taxes” are as follows:
|
|
For the Three
|
|
|
|
Months Ended
|
|
|
|
March 31, 2016
|
|
|
|
|
|
Oil and gas sales
|
|
$
|
2,662,555
|
|
Gain (loss) on the mark-to-market of derivatives
|
|
|
(15,887
|
)
|
Total revenues
|
|
|
2,646,668
|
|
|
|
|
|
|
Operating expenses:
|
|
|
|
|
Production expenses
|
|
|
747,757
|
|
Production taxes
|
|
|
275,948
|
|
General and administrative expenses
|
|
|
165,399
|
|
Depletion of oil and gas properties
|
|
|
2,022,504
|
|
Impairment of oil and gas properties
|
|
|
5,219,000
|
|
Accretion of discount on asset retirement obligations
|
|
|
8,133
|
|
Total operating expenses
|
|
|
8,438,741
|
|
|
|
|
|
|
Net operating loss
|
|
|
(5,792,073
|
)
|
|
|
|
|
|
Other income (expense):
|
|
|
|
|
Interest expense
|
|
|
(1,434,646
|
)
|
Total other income (expense)
|
|
|
(1,434,646
|
)
|
|
|
|
|
|
Loss before provision for income taxes
|
|
|
(7,226,719
|
)
|
|
|
|
|
|
Provision for income taxes
|
|
|
–
|
|
|
|
|
|
|
Net loss
|
|
$
|
(7,226,719
|
)
|
Note 4 – Prepaid Expenses
Prepaid expenses consist of the following:
|
|
March 31,
|
|
|
December 31,
|
|
|
|
2017
|
|
|
2016
|
|
Prepaid insurance costs
|
|
$
|
11,541
|
|
|
$
|
43,324
|
|
Prepaid employee benefits
|
|
|
11,729
|
|
|
|
11,844
|
|
Prepaid office and other costs
|
|
|
37,977
|
|
|
|
31,724
|
|
Total prepaid expenses
|
|
$
|
61,247
|
|
|
$
|
86,892
|
|
BLACK RIDGE OIL & GAS, INC.
Notes to Financial Statements
Note 5 – Investment in Black Ridge
Holding Company, LLC
The investment in Black Ridge Holding Company,
LLC represents our equity interest in Black Ridge Holding Company, LLC following the debt restructuring and related activity as
described in Note 3 – Debt Restructuring. We account for the investment using the cost method.
Note 6 – Property and Equipment
Property and equipment at March 31, 2017 and December 31, 2016,
consisted of the following:
|
|
March 31,
|
|
|
December 31,
|
|
|
|
2017
|
|
|
2016
|
|
Property and equipment
|
|
$
|
128,155
|
|
|
$
|
140,547
|
|
Less: Accumulated depreciation and amortization
|
|
|
(109,710
|
)
|
|
|
(112,128
|
)
|
Total property and equipment, net
|
|
$
|
18,445
|
|
|
$
|
28,419
|
|
During the three months ended March 31, 2017
we sold certain assets with a net book value of $6,874 for proceeds of $2,160, resulting in a loss on disposal of $4,714.
The following table shows depreciation, depletion, and amortization
expense by type of asset:
|
|
Three Months Ended
|
|
|
|
March 31,
|
|
|
|
2017
|
|
|
2016
|
|
Depletion of costs for evaluated oil and gas properties
(1)
|
|
$
|
–
|
|
|
$
|
2,022,504
|
|
Depreciation and amortization of other property and equipment
|
|
|
3,100
|
|
|
|
3,885
|
|
Total depreciation, amortization and depletion
|
|
$
|
3,100
|
|
|
$
|
2,026,389
|
|
(1)
Presented as a component of loss
from discontinued operations, net of income taxes.
Impairment of Oil and Gas Properties
As a result of currently prevailing low commodity
prices and their effect on the proved reserve values of properties in 2016, we recorded a non-cash ceiling test impairment of $5,219,000
for the three months ended March 31, 2016. The expense associated with the impairment is presented as a component of loss from
discontinued operations, net of income taxes as described in Note 3 – Debt Restructuring. The impairment charge affected
our reported net income but did not reduce our cash flow.
Note 7 – Oil and Gas Properties
The following table summarizes gross and net
productive oil wells by state at March 31, 2016. A net well represents our percentage ownership of a gross well. The following
table does not include wells in which our interest is limited to royalty and overriding royalty interests. The following table
also does not include wells which were awaiting completion, in the process of completion or awaiting flow back subsequent to fracture
stimulation.
|
|
March 31, 2016
|
|
|
|
Gross
|
|
|
Net
|
|
North Dakota
|
|
|
352
|
|
|
|
10.64
|
|
Montana
|
|
|
5
|
|
|
|
0.37
|
|
Total
|
|
|
357
|
|
|
|
11.01
|
|
The Company’s oil and gas properties
consisted of all acreage acquisition costs (including cash expenditures and the value of stock consideration), drilling costs and
other associated capitalized costs. As of March 31, 2016 our principal oil and gas assets included approximately 7,030
net acres, respectively, located in North Dakota and Montana and were disposed by the Company on June 21, 2016 as part of the debt
restructuring transaction summarized in Note 3 – Debt Restructuring.
BLACK RIDGE OIL & GAS, INC.
Notes to Financial Statements
The following table summarizes our capitalized
costs for the purchase and development of our oil and gas properties for the three months ended March 31, 2016:
|
|
Three Months
Ended
|
|
|
|
March 31, 2016
|
|
Purchases of oil and gas properties and development costs for cash
|
|
$
|
1,149,789
|
|
Purchase of oil and gas properties accrued at period-end
|
|
|
6,662,200
|
|
Purchase of oil and gas properties accrued at beginning of period
|
|
|
(6,899,503
|
)
|
Capitalized asset retirement costs
|
|
|
–
|
|
Total purchase and development costs, oil and gas properties
|
|
$
|
912,486
|
|
2016 Acquisitions
During the three months ended March 31, 2016,
we did not purchase any oil and gas properties.
2016 Divestitures
During the three months ended March 31, 2016,
we did not sell any oil and gas properties.
Note 8 – Asset Retirement
Obligation
The Company had asset retirement obligations
(ARO) associated with the future plugging and abandonment of proved properties and related facilities prior to the disposition
of the Company’s oil and gas operations as part of its debt restructuring summarized in Note 3 – Debt Restructuring.
Under the provisions of FASB ASC 410-20-25, the fair value of a liability for an asset retirement obligation is recorded in the
period in which it is incurred and a corresponding increase in the carrying amount of the related long lived asset. The liability
is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset.
If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized. The Company has no assets
that are legally restricted for purposes of settling ARO.
The following table summarizes the Company’s
asset retirement obligation transactions recorded in accordance with the provisions of FASB ASC 410-20-25 during the three months
ended March 31, 2016:
|
|
Three Months
Ended
|
|
|
|
March 31, 2016
|
|
Beginning ARO
|
|
$
|
368,089
|
|
Liabilities incurred for new wells placed in production
|
|
|
–
|
|
Accretion of discount on ARO (a component of loss from
discontinued operations)
|
|
|
8,133
|
|
Ending ARO
|
|
$
|
376,222
|
|
Note 9 – Related Party
Prior to July 1, 2016 the Company leased office
space on a month to month basis where the lessor was an entity owned by our former CEO and current Chairman of the Board of Directors,
Bradley Berman. Pursuant to the lease, we occupied approximately 2,813 square feet of office space. We terminated the lease concurrent
with our move to another location on June 30, 2016. The lease had base rents of $2,110 per month, plus common area operations and
maintenance charges, and monthly parking fees of $240 per month, for the period from November 15, 2013 to October 31, 2014, and
was subject to increases of $117 per month beginning November 1, 2014 and for each of the subsequent annual periods. We paid a
total of $17,276 to this entity during the three months ended March 31, 2016.
Note 10 – Derivative Instruments
The Company was required to recognize all derivative
instruments on the balance sheet as either assets or liabilities measured at fair value. The Company did not designated its derivative
instruments as cash flow hedges for accounting purposes and, as such, marked its derivative instruments to fair value and recognized
the realized and unrealized changes in fair value in its statements of operations under the captions “Loss on settled derivatives”
and “Loss on the mark-to-market of derivatives” as a component of loss from discontinued operations.
BLACK RIDGE OIL & GAS, INC.
Notes to Financial Statements
The Company had utilized swap and collar derivative
contracts. While the use of these derivative instruments limited the downside risk of adverse price movements, their use also limited
the upside revenue potential of upward price movements.
For a fixed price swap contract, the counterparty
is required to make a payment to the Company if the settlement price for any settlement period is less than the swap price and
the Company is required to make a payment to the counterparty if the settlement price for any period is greater than the swap price.
For a collar contract, the counterparty is required to make a payment to the Company if the settlement price for any settlement
period is below the floor price, the Company is required to make a payment to the counterparty if the settlement price for any
settlement period is above the ceiling price and no payment is required by either party if the settlement price for any settlement
period is between the floor price and the ceiling price.
The Company’s derivative contracts were
settled based on reported settlement prices on commodity exchanges, with crude oil derivative settlements based on NYMEX West Texas
Intermediate (“WTI”) pricing.
Derivative Gains and Losses
The following table presents realized and unrealized
gains and losses on derivative instruments for the periods presented:
|
|
Three Months
Ended
|
|
|
|
March 31, 2016
|
|
Realized gain (loss) on derivatives:
|
|
|
|
Crude oil fixed price swaps
|
|
$
|
–
|
|
Crude oil collars
|
|
|
–
|
|
Realized loss on derivatives, net
|
|
$
|
–
|
|
|
|
|
|
|
Gain (loss) on the mark-to-market of derivatives:
|
|
|
|
|
Crude oil fixed price swaps
|
|
$
|
(19,898
|
)
|
Crude oil collars
|
|
|
4,011
|
|
Gain (loss) on the mark-to-market of derivatives, net
|
|
$
|
(15,887
|
)
|
Note 11 – Fair Value of Financial
Instruments
The Company adopted FASB ASC 820-10 upon inception
at April 9, 2010. Under FASB ASC 820-10-5, fair value is defined as the price that would be received to sell an asset or paid to
transfer a liability in an orderly transaction between market participants at the measurement date (an exit price). The standard
outlines a valuation framework and creates a fair value hierarchy in order to increase the consistency and comparability of fair
value measurements and the related disclosures. Under GAAP, certain assets and liabilities must be measured at fair value, and
FASB ASC 820-10-50 details the disclosures that are required for items measured at fair value.
The Company had revolving credit facilities
that must be measured under the new fair value standard. The Company’s financial assets and liabilities are measured using
inputs from the three levels of the fair value hierarchy. The three levels are as follows:
Level 1 - Inputs are unadjusted quoted prices
in active markets for identical assets or liabilities that the Company has the ability to access at the measurement date.
Level 2 - Inputs include quoted prices for
similar assets and liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that
are not active, inputs other than quoted prices that are observable for the asset or liability (e.g., interest rates, yield curves,
etc.), and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market
corroborated inputs).
Level 3 - Unobservable inputs that reflect
our assumptions about the assumptions that market participants would use in pricing the asset or liability.
BLACK RIDGE OIL & GAS, INC.
Notes to Financial Statements
The following schedule summarizes the valuation
of financial instruments at fair value on a recurring basis in the balance sheets as of March 31, 2017 and December 31, 2016:
|
|
Fair Value Measurements at March 31, 2017
|
|
|
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
|
|
Assets
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
137,029
|
|
|
$
|
–
|
|
|
$
|
–
|
|
Total assets
|
|
|
137,029
|
|
|
|
–
|
|
|
|
–
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
|
–
|
|
|
|
–
|
|
|
|
–
|
|
|
|
$
|
137,029
|
|
|
$
|
–
|
|
|
$
|
–
|
|
|
|
Fair Value Measurements at December 31, 2016
|
|
|
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
|
|
Assets
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
66,269
|
|
|
$
|
–
|
|
|
$
|
–
|
|
Total assets
|
|
|
66,269
|
|
|
|
–
|
|
|
|
–
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
|
–
|
|
|
|
–
|
|
|
|
–
|
|
|
|
$
|
66,269
|
|
|
$
|
–
|
|
|
$
|
–
|
|
There were no transfers of financial assets
or liabilities between Level 1 and Level 2 inputs for the three months ended March 31, 2017 and December 31, 2016.
Note 12 – Revolving Credit Facilities
and Long Term Debt
The Company, as borrower, entered into a Credit
Agreement dated August 8, 2013 and amendments thereto dated December 13, 2013, March 24, 2014, April 21, 2014,
September 11, 2014, March 30, 2015 and August 10, 2015 (as amended, the “Senior Credit Agreement
”
)
with Cadence Bank, N.A. (“Cadence”), as lender (the “Senior Credit Facility”). Under the terms of the Senior
Credit Agreement, a senior secured revolving line of credit in the maximum aggregate principal amount of $50 million was available
from time to time (i) for direct investment in oil and gas properties, (ii) for general working capital purposes, including the
issuance of letters of credit, and (iii) to refinance the then existing debt under the Company’s former credit facility.
Availability under the Senior Credit Facility
was at all times subject to the then-applicable borrowing base, determined by Cadence in a manner consistent with the normal and
customary oil and gas lending practices of Cadence. Availability was initially set at $7 million and was subject to periodic
redeterminations. Subject to availability under the borrowing base, the Company could borrow, repay and re-borrow funds in amounts
of $250,000 or more. At the Company’s election, the unpaid principal balance of any borrowings under the Senior Credit Facility
may bear interest at either (i) the Base Rate, as defined in the Senior Credit Facility, plus the applicable margin, which varies
from 1.00% to 1.50% or (ii) the LIBOR rate, as defined in the Senior Credit Facility, plus the applicable margin, which varies
from 3.00% to 3.50%. Interest was payable for Base Rate loans on the last business day of the month and for LIBOR loans on the
last LIBOR business day of each LIBOR interest period. The Company was also required to pay a quarterly fee of 0.50% on any unused
portion of the borrowing base, as well as a facility fee of 0.90% of the initial and any subsequent additions to the borrowing
base.
The Senior Credit Facility’s maturity
date of August 8, 2016, was subsequently amended to January 15, 2017 pursuant to the amendment on March 30, 2015.
The Company could prepay the entire amount of Base Rate loans at any time, and could prepay the entire amount of LIBOR loans upon
at least three business days’ notice to Cadence. The Senior Credit Facility was secured by first priority interests in mortgages
on substantially all of the Company’s assets, including but not limited to the Company’s mineral interests in North
Dakota and Montana.
As part of the debt restructuring outline in
Note 3 – Debt Restructuring, the Company transferred the obligation with a balance outstanding of $29,400,000 under the Senior
Credit Facility to BRHC on June 21, 2016.
Subordinated Credit Facility
The Company, as borrower, entered into a Second
Lien Credit Agreement dated August 8, 2013 and amendments thereto dated December 13, 2013, March 24, 2014,
April 21, 2014, September 11, 2014, March 30, 2015, and August 10, 2015 (as amended, the “Subordinated
Credit Agreement”) by and among the Company, as borrower, Chambers Energy Management, LP, as administrative agent (“Chambers”),
and the several other lenders named therein (the “Subordinated Credit Facility”). Under the Subordinated Credit Facility,
term loans in the aggregate principal amount of up to $75 million were available from time to time (i) to repay the Previous
Credit Facility, (ii) for fees and closing costs in connection with both the Senior Credit Facility and the Subordinated Credit
Facility (together, the “Credit Facilities”), and (iii) general corporate purposes.
BLACK RIDGE OIL & GAS, INC.
Notes to Financial Statements
The Subordinated Credit Agreement provided
initial commitment availability of $25 million, which was subsequently amended to $30 million, with the remaining commitments
subject to the approval of Chambers and other customary conditions. The Company could borrow the available commitments in amounts
of $5 million or more and could not request borrowings of such loans more than once a month, provided that the initial draw
was at least $15 million. Loans under the Subordinated Credit Facility were funded net of a 2% OID. The unpaid principal
balance of borrowings under the Subordinated Credit Facility bore interest at the Cash Interest Rate plus the PIK Interest Rate.
The Cash Interest Rate was 9.00% per annum plus a rate per annum equal to the greater of (i) 1.00% and (ii) the offered rate for
three-month deposits in U.S. dollars that appears on Reuters Screen LIBOR 01 as of 11:00 a.m. (London time) on the second full
LIBOR business day preceding the first day of each calendar quarter. The PIK Interest Rate was equal to 4.00% per annum. Interest
was payable on the last day of each month. The Company was also required to pay an annual nonrefundable administration fee of $50,000
and a monthly availability fee computed at a rate of 0.50% per annum on the average daily amount of any unused portion of the available
amount under the commitment.
The Subordinated Credit Facility was to mature
on June 30, 2017. Upon at least three business days’ written notice, the Company could prepay the entire amount
under the loans, together with accrued interest. Each prepayment made prior to the second anniversary of the funding date, as defined
in the Subordinated Credit Facility, would be accompanied by a make-whole amount, as defined in the Subordinated Credit Agreement.
Prepayments made on or after the second anniversary of the funding date were accompanied by an applicable premium, as set forth
in the Subordinated Credit Agreement. The Subordinated Credit Facility was secured by second priority interests on substantially
all of the Company’s assets, including but not limited to second priority mortgages on the Company’s mineral interests
in North Dakota and Montana.
The first funding from the Subordinated Credit
Facility occurred on September 9, 2013 at which time we drew $14,700,000, net of a $300,000 original issue discount,
from the Subordinated Credit Agreement and used $10,226,057 of those proceeds to repay and terminate a previously outstanding revolving
credit facility. We had drawn an additional $14,700,000, net of $300,000 original issue discounts, through June 21, 2016. The Company
had borrowings of $30.0 million outstanding under the Subordinated Credit Facility as of June 21, 2016. The obligations under
the Subordinated Credit Facility, $30.0 million of principal and $2,931,369 of PIK interest payable, were transferred to BRHC and
converted to equity in BRHC as part of the debt restructuring outlined in Note 3 - Debt Restructuring on June 21, 2016.
Intercreditor Agreements and Covenants
Cadence and Chambers had entered into an Intercreditor
Agreement dated August 8, 2013 (the “Intercreditor Agreement”). The Intercreditor Agreement provided that
any liens on the assets of the Company securing indebtedness under the Subordinated Credit Facility were subordinate to liens on
the assets securing indebtedness under the Senior Credit Facility and set forth the respective rights, obligations and remedies
of the lenders under the Senior Credit Facility with respect to their first priority liens and the lenders under the Subordinated
Credit Facility with respect to their second priority liens.
The Credit Facilities, as amended, required
customary affirmative and negative covenants for credit facilities of the respective types and sizes for companies operating in
the oil and gas industry, as well as customary events of default. Furthermore, the Credit Facilities contain financial covenants
that required the Company to satisfy certain specified financial ratios. The Senior Credit Agreement required the Company to maintain,
as of the last day of each fiscal quarter of the Company, (i) a collateral coverage ratio (reserve value plus consolidated working
capital to adjusted indebtedness) of at least 0.65 to 1.00 through the quarter ending June 30, 2014, 0.70 to 1.00 for
the quarters ending September 30, 2014 and December 31, 2014, was waived for the quarters ending March 31, 2015
and June 30, 2015, and 0.70 to 1.00 for the quarter ending September 30, 2015, and 0.80 to 1.00 for the quarter
ending December 31, 2015 and thereafter, (ii) a ratio of current assets, including debt facility available to be drawn,
to current liabilities of a minimum of 1.0 to 1.0, except for the quarter ending June 30, 2014, which was waived, (iii)
a net debt to EBITDAX, as defined in the Senior Credit Agreement, ratio of 3.75 to 1.00 for the quarter ended March 31, 2014,
4.25 to 1.00 for the quarters ended June 30, 2014 and September 30, 2014, 4.00 to 1.00 for the quarter ended
December 31, 2014, was waived for the quarters ended March 31, 2015 and June 30, 2015, and 3.50 to 1.00 for
the quarter ending September 30, 2015, and 3.65 to 1.00 for the quarter ending December 31, 2015, and 3.50
to 1.00 for the quarter ending March 31, 2016 and thereafter, in each case calculated on a modified trailing four quarter
basis, (iv) a maximum senior leverage ratio of not more than 2.5 to 1.0 calculated on a modified trailing four quarter basis, and
(v) a minimum interest coverage ratio of not less than 3.0 to 1.0. The Subordinated Credit Agreement required the Company to maintain,
as of the last day of each fiscal quarter of the Company, (i) a collateral coverage ratio (reserve value plus consolidated working
capital to adjusted indebtedness) of at least 0.65 to 1.00 through the quarter ending June 30, 2014, 0.70 to 1.00 for
the quarters ending September 30, 2014 and December 31, 2014, was waived for the quarters ending March 31, 2015
and June 30, 2015, and 0.70 to 1.00 for the quarter ending September 30, 2015, and 0.80 to 1.00 for the quarter ending
December 31, 2015 and thereafter, (ii) a consolidated net leverage ratio (adjusted total indebtedness less the amount
of unrestricted cash equivalents to consolidated EBITDA) of no more than 3.75 to 1.00 for the quarter ending March 31, 2014,
4.25 to 1.00 for the quarters ending June 30, 2014 and September 30, 2014, 4.00 to 1.00 for the quarter ending
December 31, 2014, was waived for the quarters ending March 31, 2015 and June 30, 2015, and 3.50 to 1.00 for
the quarter ending September 30, 2015, and 3.65 to 1.00 for the quarter ending December 31, 2015, and 3.50
to 1.00 for the quarter ending March 31, 2016 and thereafter, calculated on a modified trailing four quarter basis, (iii)
a consolidated cash interest coverage ratio (consolidated EBITDA to consolidated cash interest expense) of no less than 2.5 to
1.0, calculated on a modified trailing four quarter basis and (iv) a ratio of consolidated current assets to consolidated current
liabilities of at least 1.0 to 1.0, except for the quarter ending June 30, 2015 when the covenant was waived. In addition, each
of the Credit Facilities required that the Company enter into hedging agreements based on anticipated oil production from currently
producing wells as agreed to by the lenders.
BLACK RIDGE OIL & GAS, INC.
Notes to Financial Statements
Covenant Violations
The Company was out of compliance with the
collateral coverage ratio covenant as of March 31, 2016 and December 31, 2015 and the current ratio covenant as defined by the
Subordinated Credit Facility as of March 31, 2016. Additionally, the audit report the Company received with respect to its financial
statements as of December 31, 2015 contains an explanatory paragraph expressing uncertainty as to the Company’s ability to
continue as a going concern, the delivery of which constituted a default under both its Senior Credit Facility and Subordinated
Credit Facility. The Company received a waiver for all debt covenants as of December 31, 2015 and March 31, 2016 as part of the
debt restructuring outlined in Note 3 – Debt Restructuring.
The following presents components of interest
expense which is presented as a component of component of loss from discontinued operations, net of tax, on the Company’s
statement of operations for the three months ended March 31, 2016:
|
|
Three Months
Ended
|
|
|
|
March 31, 2016
|
|
Accrued PIK interest
|
|
$
|
330,740
|
|
Interest and commitment fees
|
|
|
1,111,125
|
|
Less interest capitalized to the full cost pool of our proved oil & gas properties
|
|
|
(7,219
|
)
|
|
|
$
|
1,434,646
|
|
Note 13 – Changes in Stockholders’
Equity
Preferred Stock
The Company has 20,000,000 authorized shares
of $0.001 par value preferred stock. No shares have been issued to date.
Common Stock
The Company has 500,000,000 authorized shares
of $0.001 par value common stock.
Note 14 –
Options
Options Granted
No options were granted during the three months
ended March 31, 2017 and 2016.
The Company recognized a total of $159,492,
and $157,824 of compensation expense during the three months ended March 31, 2017 and 2016, respectively, related to common stock
options issued to Employees and Directors that are being amortized over the implied service term, or vesting period, of the options.
The remaining unamortized balance of these options is $862,897 as of March 31, 2017.
Options Exercised
No options were exercised during the three
months ended March 31, 2017 and 2016.
Options Forfeited
No options were forfeited during the three months ended March 31,
2017 and 2016.
BLACK RIDGE OIL & GAS, INC.
Notes to Financial Statements
Note 15 – Warrants
Warrants Granted
No warrants were granted during the three months
ended March 31, 2017 and 2016.
Warrants Exercised
No warrants were exercised during the three months ended March 31,
2017 and 2016.
During 2016, all remaining warrants either expired or were forfeited
pursuant to our debt restructuring as described in Note 3- Debt Restructuring. The Company has no outstanding warrants as of March
31, 2017.
Note 16 – Income
Taxes
The Company accounts for income taxes under
ASC Topic 740,
Income Taxes,
which provides for an asset and liability approach of accounting for income taxes. Under this
approach, deferred tax assets and liabilities are recognized based on anticipated future tax consequences, using currently enacted
tax laws, attributed to temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes
and the amounts calculated for income tax purposes.
We currently estimate that our effective tax
rate for the year ending December 31, 2017 will be 0%. Losses incurred during the period from April 9, 2011 (inception) to March
31, 2017 could be used to offset future tax liabilities. Accounting standards require the consideration of a valuation allowance
for deferred tax assets if it is “more likely than not” that some component or all of the benefits of deferred tax
assets will not be realized. As of March 31, 2017, net deferred tax assets were $12,810,140, after an offsetting reduction in
deferred tax liabilities of $1,382, primarily related to net operating loss carryforwards. A valuation allowance of approximately $12,810,140
was applied to the remaining net deferred tax assets. We have not provided any valuation allowance against our deferred tax liabilities,
which were netted against our deferred tax assets.
The tax benefit for the three months ended
March 31, 2017 of $-0- was primarily driven by the Company’s loss before provision for income taxes and offset by the valuation
allowance on the resulting deferred tax asset.
In accordance with FASB ASC 740, the Company
has evaluated its tax positions and determined there are no significant uncertain tax positions as of any date on, or before March
31, 2017.
Note 17 – Commitments
and Contingencies
The Company from time to time may be involved
in various inquiries, administrative proceedings and litigation relating to matters arising in the normal course of business. The
Company is not aware of any inquiries or administrative proceedings and is not currently a defendant in any material litigation
and is not aware of any threatened litigation that could have a material effect on the Company.
Note 18 – Subsequent
Events
Cancelation of Management Services Agreement
and Sale of BRHC Assets
On April 3, 2017, we were notified by BRHC
of their termination of our Management Services Agreement and that they had finalized the sale of BRHC’s oil and gas assets
to a third party. On April 3, BRHC signed a Contribution Agreement that provides for the transfer of ownership and title of all
oil and gas assets held by BRHC in exchange for preferred membership interest in the acquiring LLC (the “BRHC Sale”).
Consistent with the terms of the Management Services Agreement, we will be paid for our management services for the three month
period ended June 30, 2017. Additionally, Chambers Energy Capital II, LP and CEC II TE, LLC, have agreed to purchase for cash our
3.88% equity share in BRHC, which is estimated to be approximately $1.0 million.
On April 12, 2017 Chambers contributed an additional
$1.1 million to BRHC as part of the Chambers Investment Commitment under the LLC agreement, thereby reducing the Company’s
ownership interest in BRHC from 3.88% to 3.78%.