NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL
STATEMENTS
NOTE 1 – Organization and Basis of Presentation
Organization
Yuma Energy, Inc., a Delaware corporation (“Yuma” and
collectively with its subsidiaries, the “Company”), is
an independent Houston-based exploration and production company
focused on acquiring, developing and exploring for conventional and
unconventional oil and natural gas resources. Historically, the
Company’s operations have focused on onshore properties
located in central and southern Louisiana and southeastern Texas
where it has a long history of exploration and development
activity, and more recently, the Company has entered the Permian
Basin. In addition, the Company has non-operated positions in the
East Texas Woodbine and the Bakken Shale in North Dakota, and
operated positions in Kern County, California.
On
October 26, 2016, Yuma Energy, Inc., a California corporation
(“Yuma California”), merged (the “Reincorporation
Merger”) with and into Yuma. Pursuant to the Reincorporation
Merger, Yuma California was reincorporated in Delaware as Yuma.
Immediately thereafter, a wholly owned subsidiary of Yuma merged
(the “Davis Merger”) with and into privately-held Davis
Petroleum Acquisition Corp., a Delaware corporation
(“Davis”). As a result of the Davis Merger, Davis
became a wholly owned subsidiary of Yuma.
Prior
to the Reincorporation Merger, each share of Yuma
California’s existing 9.25% Series A Cumulative Redeemable
Preferred Stock (the “Yuma California Series A Preferred
Stock”) was converted into 35 shares of common stock of Yuma
California (“Yuma California Common Stock”). As a
result of the closing of the Reincorporation Merger, each share of
Yuma California Common Stock was converted into one-twentieth of
one share (the “Reverse Stock Split”) of common stock
of Yuma (the “common stock”). As a result of the
Reverse Stock Split, Yuma issued an aggregate of approximately 4.75
million shares of its common stock.
As a
result of the Davis Merger, Yuma issued approximately 7.45 million
shares of its common stock to the former stockholders of
Davis’ common stock. Yuma also issued approximately 1.75
million shares of Series D Convertible Preferred Stock of Yuma
(the “Series D Preferred Stock”) to existing Davis
preferred stockholders. Upon completion of the Reincorporation
Merger and the Davis Merger, there was an aggregate of
approximately 12.2 million shares of common stock outstanding and
1.75 million shares of Series D Preferred Stock
outstanding.
At the
closing of the Davis Merger, Davis appointed a majority of the
board of directors of Yuma. Four out of the five members of
Yuma’s board of directors prior to the closing of the Davis
Merger continued to serve on the board of directors of Yuma, with
one of those four directors having been appointed by Davis. Three
additional directors were appointed by Davis. The Davis Merger was
accounted for as a “reverse acquisition” and a
recapitalization since the former common stockholders of Davis have
control over the combined company through their post-merger 61.1%
ownership of the common stock and majority representation on
Yuma’s board of directors.
The
Davis Merger was accounted for as a business combination in
accordance with ASC 805 Business Combinations (“ASC
805”). ASC 805, among other things, requires assets acquired
and liabilities assumed to be measured at their acquisition date
fair value. Although Yuma was the legal acquirer, Davis was the
accounting acquirer. The historical financial statements are
therefore those of Davis. Hence, the financial statements included
in this report reflect (i) the historical results of Davis prior to
the Davis Merger; (ii) the combined results of the Company
following the Davis Merger; (iii) the acquired assets and
liabilities of Davis at their historical cost; and (iv) the fair
value of Yuma’s assets and liabilities as of the closing of
the Davis Merger.
Basis of Presentation
The
accompanying unaudited consolidated financial statements of the
Company and its wholly owned subsidiaries have been prepared in
accordance with Article 8-03 of Regulation S-X for interim
financial statements required to be filed with the Securities and
Exchange Commission (“SEC”). The information furnished
herein reflects all adjustments that are, in the opinion of
management, necessary for the fair presentation of the
Company’s Consolidated Balance Sheets as of June 30, 2017,
and December 31, 2016; the Consolidated Statements of Operations
for the three and six months ended June 30, 2017 and 2016; the
Consolidated Statement of Changes in Equity for the six months
ended June 30, 2017; and the Consolidated Statements of Cash Flows
for the six months ended June 30, 2017 and 2016. The
Company’s Consolidated Balance Sheet at December 31, 2016 is
derived from the audited consolidated financial statements of the
Company at that date.
The
preparation of financial statements in conformity with the
generally accepted accounting principles of the United States of
America (“GAAP”) requires management to make estimates
and assumptions that affect the reported amounts of assets and
liabilities, the 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. For further information, see
Note 2 in the Notes to Consolidated Financial Statements contained
in the Company’s Annual Report on Form 10-K for the year
ended December 31, 2016.
Interim
period results are not necessarily indicative of results of
operations or cash flows for the full year and accordingly, certain
information normally included in financial statements and the
accompanying notes prepared in accordance with GAAP has been
condensed or omitted. These financial statements should be read in
conjunction with the Company’s Annual Report on Form 10-K for
the year ended December 31, 2016. The Company has evaluated events
or transactions through the date of issuance of these unaudited
consolidated financial statements.
When required for comparability, reclassifications are made to the
prior period financial statements to conform to the current year
presentation. Reclassifications include moving COPAS overhead
recoveries from lease operating expenses to general and
administrative expenses, moving certain other revenue to offset
lease operating expense, moving commodity derivative gains (losses)
from expenses to other income (expense), moving regulatory interest
from general and administrative to interest expense, and moving
gain (loss) on other property and equipment from operating expenses
to other income (expense).
NOTE 2 – Changes in Accounting
Principles
Not Yet Adopted
In May 2017, the
Financial Accounting Standards Board
(“FASB”)
issued ASU
2017-09, “Compensation – Stock Compensation (Topic
718): Scope of Modification Accounting.” The purpose of
this update is to provide clarity as to which modifications of
awards require modification accounting under Topic 718, whereas
previously issued guidance frequently resulted in varying
interpretations and a diversity of practice. An entity should
employ modification accounting unless the following are met: (1)
the fair value of the award is the same immediately before and
after the award is modified; (2) the vesting conditions are the
same under both the modified award and the original award; and (3)
the classification of the modified award is the same as the
original award, either equity or liability. Regardless of whether
modification accounting is utilized, award disclosure requirements
under Topic 718 remain unchanged. ASU 2017-09 will be effective for
annual or any interim periods beginning after December 15, 2017.
The Company does not believe adoption of ASU 2017-09 will have a
material impact on its financial statements.
In
August 2016, the FASB issued ASU 2016-15, “Statement of Cash
Flows (Topic 230): Classification of Certain Cash Receipts and Cash
Payments,” which provides clarification on how certain cash
receipts and cash payments are presented and classified on the
statement of cash flows. This ASU is effective for annual and
interim periods beginning after December 15, 2017 and is required
to be adopted using a retrospective approach if practicable, with
early adoption permitted. The Company does not expect the adoption
of this ASU to have a material impact on its Consolidated
Statements of Cash Flows.
In
February 2016, the FASB issued ASU 2016-02, “Leases,” a
new lease standard requiring lessees to recognize lease assets and
lease liabilities for most leases classified as operating leases
under previous GAAP. The guidance is effective for fiscal years
beginning after December 15, 2018 with early adoption permitted.
The Company will be required to use a modified retrospective
approach for leases that exist or are entered into after the
beginning of the earliest comparative period in the financial
statements. The Company is currently evaluating the impact, if any,
of adopting this standard on its Consolidated Financial
Statements.
In
January 2016, the FASB issued ASU 2016-01, “Recognition and
Measurement of Financial Assets and Financial Liabilities,”
which changes certain guidance related to the recognition,
measurement, presentation and disclosure of financial instruments.
This update is effective for fiscal years beginning after December
15, 2017, including interim periods within those fiscal years.
Early adoption is not permitted for the majority of the update, but
is permitted for two of its provisions. The Company is evaluating
the new guidance, but does not believe that it will materially
impact the Company’s consolidated financial statement
presentation.
In May
2014, the FASB issued ASU No. 2014-09, “Revenue from
Contracts with Customers (Topic 606).” In March, April, and
May of 2016, the FASB issued rules clarifying several aspects of
the new revenue recognition standard. The new guidance is effective
for fiscal years and interim periods beginning after December 15,
2017. This guidance outlines a new, single comprehensive model for
entities to use in accounting for revenue arising from contracts
with customers and supersedes most current revenue recognition
guidance, including industry-specific guidance. This new revenue
recognition model provides a five-step analysis in determining when
and how revenue is recognized. The new model will require revenue
recognition to depict the transfer of promised goods or services to
customers in an amount that reflects the consideration a company
expects to receive in exchange for those goods and services. The
new standard also requires more detailed disclosures related to the
nature, amount, timing, and uncertainty of revenue and cash flows
arising from contracts with customers. The Company will not early
adopt the standard although early adoption is permitted. The
Company is currently evaluating whether to apply the retrospective
approach or modified retrospective approach with the cumulative
effect recognized as of the date of initial application. The
Company is currently evaluating the impact the standard is expected
to have on its consolidated financial statements by evaluating
current revenue streams and evaluating contracts under the revised
standards.
Recently adopted
The
FASB issued ASU 2017-01, “Business Combinations (Topic 805):
Clarifying the Definition of a Business,” which assists in
determining whether a transaction should be accounted for as an
acquisition or disposal of assets or as a business. This ASU
provides a screen that when substantially all of the fair value of
the gross assets acquired, or disposed of, are concentrated in a
single identifiable asset, or a group of similar identifiable
assets, the set will not be considered a business. If the screen is
not met, a set must include an input and a substantive process that
together significantly contribute to the ability to create an
output to be considered a business. This ASU is effective for
annual and interim periods beginning in 2018 and is required to be
adopted using a prospective approach, with early adoption permitted
for transactions not previously reported in issued financial
statements. The Company adopted this ASU on January 1, 2017, and
expects that the adoption of this ASU could have a material impact
on future consolidated financial statements as future oil and gas
asset acquisitions may not be considered businesses.
The
FASB issued ASU 2016-09, “Compensation—Stock
Compensation (Topic 718): Improvements to Employee Share-Based
Payment Accounting,”
which
simplifies the accounting for
share-based payment transactions, including the income tax
consequences, classification of awards as either equity or
liabilities, classification on the statement of cash flows, and
accounting for forfeitures. The Company adopted this ASU on January
1, 2017, and does not expect the adoption of this standard to have
a material impact on the Company’s future consolidated
financial statements.
The
FASB issued ASU 2014-15, “Presentation of Financial
Instruments – Going Concern,” which requires management
of an entity to evaluate whether there are conditions or events,
considered in the aggregate, that raise substantial doubt about the
entity’s ability to continue as a going concern within one
year after the date that the financial statements are issued or
available to be issued. This update is effective for annual periods
ending after December 15, 2016. The Company does not expect the
adoption of this standard to have a material impact on the
Company’s consolidated financial statements.
NOTE 3 – Asset Impairments
The
Company’s oil and natural gas properties are accounted for
using the full cost method of accounting, under which all
productive and nonproductive costs directly associated with
property acquisition, exploration and development activities are
capitalized. These capitalized costs (net of accumulated DD&A
and deferred income taxes) of proved oil and natural gas properties
are subject to a full cost ceiling limitation. The ceiling limits
these costs to an amount equal to the present value, discounted at
10%, of estimated future net cash flows from estimated proved
reserves less estimated future operating and development costs,
abandonment costs (net of salvage value) and estimated related
future income taxes. In accordance with SEC rules, prices used are
the 12 month average prices, calculated as the unweighted
arithmetic average of the first-day-of-the-month price for each
month within the 12 month period prior to the end of the reporting
period, unless prices are defined by contractual arrangements.
Prices are adjusted for “basis” or location
differentials. Prices are held constant over the life of the
reserves. The Company’s second quarter of 2017 full cost
ceiling calculation was prepared by the Company using (i) $48.95
per barrel for oil, and (ii) $3.01 per MMBTU for natural gas as of
June 30, 2017. If unamortized costs capitalized within the cost
pool exceed the ceiling, the excess is charged to expense and
separately disclosed during the period in which the excess occurs.
Amounts thus required to be written off are not reinstated for any
subsequent increase in the cost center ceiling. During the three
month periods ended June 30, 2017 and 2016, the Company recorded
full cost ceiling impairments after income taxes of $-0- and $7.7
million, respectively. During the six month periods ended June 30,
2017 and 2016, the Company recorded full cost ceiling impairments
after income taxes of $-0- and $17.5 million,
respectively.
NOTE 4 – Asset Retirement Obligations
The
Company has asset retirement obligations (“AROs”)
associated with the future plugging and abandonment of oil and
natural gas properties and related facilities. The accretion of the
ARO is included in the Consolidated Statements of Operations.
Revisions to the liability typically occur due to changes in the
estimated abandonment costs, well economic lives and the discount
rate.
The
following table summarizes the Company’s ARO transactions
recorded during the six months ended June 30, 2017 in accordance
with the provisions of FASB ASC Topic 410, “Asset Retirement
and Environmental Obligations”
:
|
|
|
|
Asset
retirement obligations at December 31, 2016
|
$
10,196,383
|
Liabilities
incurred
|
-
|
Liabilities
settled
|
(99,594
)
|
Liabilities
sold
|
(418,527
)
|
Accretion
expense
|
280,023
|
Revisions
in estimated cash flows
|
70,145
|
|
|
Asset
retirement obligations at June 30, 2017
|
$
10,028,430
|
Based
on expected timing of settlements, $388,643 of the ARO is
classified as current at June 30, 2017.
NOTE 5 – Fair Value Measurements
Certain financial instruments are reported at fair value on the
Company’s Consolidated Balance Sheets. Under fair value
measurement accounting guidance, fair value is defined as the
amount that would be received from the sale of an asset or paid for
the transfer of a liability in an orderly transaction between
market participants, i.e., an exit price. To estimate an exit
price, a three-level hierarchy is used. The fair value hierarchy
prioritizes the inputs, which refer broadly to assumptions market
participants would use in pricing an asset or a liability, into
three levels. The Company uses a market valuation approach based on
available inputs and the following methods and assumptions to
measure the fair values of its assets and liabilities, which may or
may not be observable in the market.
Fair Value of Financial Instruments (other than Commodity
Derivative Instruments, see below) –
The carrying values of financial instruments,
excluding commodity derivative instruments, comprising current
assets and current liabilities approximate fair values due to the
short-term maturities of these instruments.
Derivatives
– The fair
values of the Company’s commodity derivatives are considered
Level 2 as their fair values are based on third-party pricing
models which utilize inputs that are either readily available in
the public market, such as natural gas and oil forward curves and
discount rates, or can be corroborated from active markets or
broker quotes. These values are then compared to the values given
by the Company’s counterparties for reasonableness. The
Company is able to value the assets and liabilities based on
observable market data for similar instruments, which results in
the Company using market prices and implied volatility factors
related to changes in the forward curves. Derivatives are also
subject to the risk that counterparties will be unable to meet
their obligations.
|
Fair value measurements at June 30, 2017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets:
|
|
|
|
|
Commodity
derivatives – oil
|
$
-
|
$
2,585,652
|
$
-
|
$
2,585,652
|
Commodity
derivatives – gas
|
-
|
2,534
|
-
|
2,534
|
Total
assets
|
$
-
|
$
2,588,186
|
$
-
|
$
2,588,186
|
|
Fair value measurements at December 31, 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities:
|
|
|
|
|
Commodity
derivatives – oil
|
$
-
|
$
956,997
|
$
-
|
$
956,997
|
Commodity
derivatives – gas
|
-
|
1,599,005
|
-
|
1,599,005
|
Total
liabilities
|
$
-
|
$
2,556,002
|
$
-
|
$
2,556,002
|
Derivative instruments listed above include swaps and three-way
collars (see Note 6 – Commodity Derivative
Instruments).
Debt
– The
Company’s debt is recorded at the carrying amount on its
Consolidated Balance Sheets (see Note 10 – Debt and Interest
Expense). The carrying amount of floating-rate debt approximates
fair value because the interest rates are variable and reflective
of market rates.
Asset Retirement Obligations
– The Company estimates the fair value of
AROs upon initial recording based on discounted cash flow
projections using numerous estimates, assumptions and judgments
regarding such factors as the existence of a legal obligation for
an ARO, amounts and timing of settlements, the credit-adjusted
risk-free rate to be used and inflation rates (see Note 4 –
Asset Retirement Obligations). Therefore, the Company has
designated these liabilities as Level 3.
NOTE 6 – Commodity Derivative Instruments
Objective and Strategies for Using Commodity Derivative
Instruments
– In order to mitigate the effect of
commodity price uncertainty and enhance the predictability of cash
flows relating to the marketing of the Company’s crude oil
and natural gas, the Company enters into crude oil and natural gas
price commodity derivative instruments with respect to a portion of
the Company’s expected production. The commodity derivative
instruments used include futures, swaps, and options to manage
exposure to commodity price risk inherent in the Company’s
oil and natural gas operations.
Futures
contracts and commodity price swap agreements are used to fix the
price of expected future oil and natural gas sales at major
industry trading locations such as Henry Hub, Louisiana for natural
gas and Cushing, Oklahoma for oil. Basis swaps are used to fix or
float the price differential between product prices at one market
location versus another. Options are used to establish a floor
price, a ceiling price, or a floor and ceiling price (collar) for
expected future oil and natural gas sales.
A
three-way collar is a combination of three options: a sold call, a
purchased put, and a sold put. The sold call establishes the
maximum price that the Company will receive for the contracted
commodity volumes. The purchased put establishes the minimum price
that the Company will receive for the contracted volumes unless the
market price for the commodity falls below the sold put strike
price, at which point the minimum price equals the reference price
(e.g., NYMEX) plus the excess of the purchased put strike price
over the sold put strike price.
While
these instruments mitigate the cash flow risk of future reductions
in commodity prices, they may also curtail benefits from future
increases in commodity prices.
The
Company does not apply hedge accounting to any of its derivative
instruments. As a result, gains and losses associated with
derivative instruments are recognized currently in
earnings.
Counterparty Credit Risk
– Commodity derivative
instruments expose the Company to counterparty credit risk. The
Company’s commodity derivative instruments are with
Société Générale (“SocGen”) and BP
Energy Company. Commodity derivative contracts are executed under
master agreements which allow the Company, in the event of default,
to elect early termination of all contracts. If the Company chooses
to elect early termination, all asset and liability positions would
be netted and settled at the time of election.
Commodity
derivative instruments open as of June 30, 2017 are provided below.
Natural gas prices are New York Mercantile Exchange
(“NYMEX”) Henry Hub prices, and crude oil prices are
NYMEX West Texas Intermediate (“WTI”).
|
|
|
|
|
|
|
|
NATURAL
GAS (MMBtu):
|
|
|
|
Swaps
|
|
|
|
Volume
|
1,098,912
|
1,725,133
|
373,906
|
Price
|
$
3.13
|
$
3.00
|
$
3.00
|
|
|
|
|
3-way
collars
|
|
|
|
Volume
|
85,806
|
-
|
-
|
Ceiling
sold price (call)
|
$
3.39
|
-
|
-
|
Floor
purchased price (put)
|
$
3.03
|
-
|
-
|
Floor
sold price (short put)
|
$
2.47
|
-
|
-
|
|
|
|
|
CRUDE
OIL (Bbls):
|
|
|
|
Swaps
|
|
|
|
Volume
|
67,191
|
195,152
|
156,320
|
Price
|
$
52.24
|
$
53.17
|
$
53.77
|
|
|
|
|
3-way
collars
|
|
|
|
Volume
|
54,289
|
-
|
-
|
Ceiling
sold price (call)
|
$
77.00
|
-
|
-
|
Floor
purchased price (put)
|
$
60.00
|
-
|
-
|
Floor
sold price (short put)
|
$
45.00
|
-
|
-
|
Derivatives for each commodity are netted on the Consolidated
Balance Sheets. The following table presents the fair value and
balance sheet location of each classification of commodity
derivative contracts on a gross basis without regard to
same-counterparty netting:
|
|
|
|
|
Asset
commodity derivatives:
|
|
|
Current
assets
|
$
1,793,070
|
$
734,464
|
Noncurrent
assets
|
1,121,217
|
54,380
|
|
2,914,287
|
788,844
|
|
|
|
Liability
commodity derivatives:
|
|
|
Current
liabilities
|
(286,364
)
|
(2,074,915
)
|
Noncurrent
liabilities
|
(39,737
)
|
(1,269,931
)
|
|
(326,101
)
|
(3,344,846
)
|
|
|
|
Total
commodity derivative instruments
|
$
2,588,186
|
$
(2,556,002
)
|
Net gains (losses) from commodity derivatives on the Consolidated
Statements of Operations are comprised of the
following:
|
Three Months Ended June 30,
|
Six Months Ended June 30,
|
|
|
|
|
|
|
|
|
|
|
Derivative
settlements
|
$
451,975
|
$
524,412
|
$
550,675
|
$
1,059,900
|
Mark
to market on commodity derivatives
|
1,686,105
|
(1,270,064
)
|
5,144,188
|
(1,349,238
)
|
Net
gains (losses) from commodity derivatives
|
$
2,138,080
|
$
(745,652
)
|
$
5,694,863
|
$
(289,338
)
|
NOTE 7 – Preferred Stock
The
Company issued an aggregate of 1,754,179 shares of Series D
Preferred Stock as part of the completion of the Davis Merger to
former holders of Series A Preferred Stock, which is convertible
into shares of the Company’s common stock. Each share of
Series D Preferred Stock is convertible into a number of shares of
common stock determined by dividing the original issue price, which
was $11.0741176, by the conversion price, which is currently
$11.0741176. The conversion price is subject to adjustment for
stock splits, stock dividends, reclassification, and certain
issuances of common stock for less than the conversion price. As of
June 30, 2017, the Series D Preferred Stock had a liquidation
preference of approximately $20.4 million and a conversion rate of
$11.0741176 per share. The Series D Preferred Stock provides for
cumulative dividends of 7.0% per annum, payable in-kind. The
Company issued 62,209 shares of Series D Preferred Stock as in-kind
dividends for the six months ended June 30, 2017. The Company does
not have any dividends in arrears at June 30, 2017.
NOTE 8 – Stock-Based Compensation
2014 Long-Term Incentive Plan
On
October 26, 2016, Yuma assumed the Yuma California 2014 Long-Term
Incentive Plan (the “2014 Plan”), which was approved by
the shareholders of Yuma California. The shareholders of Yuma
California originally approved the 2014 Plan at the special meeting
of shareholders on September 10, 2014 and the subsequent amendment
to the 2014 Plan at the special meeting of shareholders on October
26, 2016. Under the 2014 Plan, Yuma may grant stock options,
restricted stock awards (“RSAs”), restricted stock
units (“RSUs”), stock appreciation rights
(“SARs”), performance units, performance bonuses, stock
awards and other incentive awards to employees of Yuma and its
subsidiaries and affiliates. Yuma may also grant nonqualified stock
options, RSAs, RSUs, SARs, performance units, stock awards and
other incentive awards to any persons rendering consulting or
advisory services and non-employee directors of Yuma and its
subsidiaries, subject to the conditions set forth in the 2014 Plan.
Generally, all classes of Yuma’s employees are eligible to
participate in the 2014 Plan.
The
2014 Plan provides that a maximum of 2,495,000 shares of common
stock may be issued in conjunction with awards granted under the
2014 Plan. As of the closing of the Reincorporation Merger, there
were awards for approximately 179,165 shares of common stock
outstanding. Awards that are forfeited under the 2014 Plan will
again be eligible for issuance as though the forfeited awards had
never been issued. Similarly, awards settled in cash will not be
counted against the shares authorized for issuance upon exercise of
awards under the 2014 Plan.
The
2014 Plan provides that a maximum of 1,000,000 shares of common
stock may be issued in conjunction with incentive stock options
granted under the 2014 Plan. The 2014 Plan also limits the
aggregate number of shares of common stock that may be issued in
conjunction with stock options and/or SARs to any eligible employee
in any calendar year to 1,500,000 shares. The 2014 Plan also limits
the aggregate number of shares of common stock that may be issued
in conjunction with the grant of RSAs, RSUs, performance unit
awards, stock awards and other incentive awards to any eligible
employee in any calendar year to 700,000 shares.
At June
30, 2017, 942,816 shares of the 2,495,000 shares of common stock
originally authorized under active share-based compensation plans
remained available for future issuance. Yuma generally issues new
shares to satisfy awards under employee share-based payment plans.
The number of shares available is reduced by awards
granted.
The
Company accounts for stock-based compensation in accordance with
FASB ASC Topic 718, “Compensation – Stock
Compensation”.
The guidance requires that all
stock-based payments to employees and directors, including grants
of RSUs, be recognized over the requisite service period in the
financial statements based on their fair values.
RSAs,
SARs and Stock Options granted to officers and employees generally
vest in one-third increments over a three-year period, or with
three year cliff vestings, and are contingent on the
recipient’s continued employment. RSAs granted to directors
generally vest in quarterly increments over a one-year
period.
Equity Based Awards –
During the three months ended
June 30, 2017, the Company granted 329,491 RSAs, along with 893,617
Stock Options which had an exercise price of $2.56.
Liability Based Awards –
During the three months ended
June 30, 2017, the Company granted 1,623,371 SARs which are
liability based, and will be settled in cash. The exercise price
for the SARs was $4.40.
Total
share-based compensation expenses recognized for the three months
ended June 30, 2017 and 2016 were $385,097 (none capitalized) and
$1,087,471 (net of capitalized amount of $1,715,810), respectively.
For the six months ended June 30, 2017 and 2016, total share-based
compensation expenses recognized were $436,832 (none capitalized)
and $1,284,395 (net of capitalized amount of $1,715,810),
respectively.
NOTE 9 – Earnings Per Common Share
Earnings
per common share – Basic is calculated by dividing net income
(loss) attributable to common shareholders by the weighted average
number of shares of common stock outstanding during the period.
Earnings per common share – Diluted assumes the conversion of
all potentially dilutive securities, and is calculated by dividing
net income (loss) attributable to common shareholders by the sum of
the weighted average number of shares of common stock outstanding
plus potentially dilutive securities. Earnings per common share
– Diluted considers the impact of potentially dilutive
securities except in periods where their inclusion would have an
anti-dilutive effect. Equity, including the average number of
shares of common stock and per share amounts, has been
retroactively restated to reflect the Davis Merger.
A
reconciliation of earnings per common share is as
follows:
|
Three Months Ended June 30,
|
Six Months Ended June 30,
|
|
|
|
|
|
|
|
|
|
|
Net
income (loss) attributable to common stockholders
|
$
(512,696
)
|
$
(14,009,121
)
|
$
1,749,819
|
$
(26,779,958
)
|
|
|
|
|
|
Weighted
average common shares outstanding
|
|
|
|
|
Basic
|
12,235,286
|
7,442,381
|
12,223,337
|
7,448,222
|
Add
potentially dilutive securities:
|
|
|
|
|
Unvested
restricted stock awards
|
-
|
-
|
184,659
|
-
|
Stock
appreciation rights
|
-
|
-
|
-
|
-
|
Stock
options
|
-
|
-
|
-
|
-
|
Series
A preferred stock
|
-
|
-
|
-
|
-
|
Series
D preferred stock
|
-
|
-
|
-
|
-
|
Diluted
weighted average common shares outstanding
|
12,235,286
|
7,442,381
|
12,407,996
|
7,448,222
|
|
|
|
|
|
Net
income (loss) per common share:
|
|
|
|
|
Basic
|
$
(0.04
)
|
$
(1.88
)
|
$
0.14
|
$
(3.60
)
|
Diluted
|
$
(0.04
)
|
$
(1.88
)
|
$
0.14
|
$
(3.60
)
|
NOTE 10 – Debt and Interest Expense
Long-term
debt consisted of the following:
|
|
|
|
|
|
|
|
|
Senior
credit facility
|
$
32,000,000
|
$
39,500,000
|
Installment
loan due 7/15/17 originating from the financing of
|
|
|
insurance
premiums at 4.38% interest rate
|
86,558
|
599,341
|
Total
debt
|
32,086,558
|
40,099,341
|
Less:
current maturities
|
(86,558
)
|
(599,341
)
|
Total
long-term debt
|
$
32,000,000
|
$
39,500,000
|
Senior Credit Facility
In
connection with the closing of the Davis Merger on October 26,
2016, Yuma and three of its subsidiaries, as the co-borrowers,
entered into a credit agreement providing for a $75.0 million
three-year senior secured revolving credit facility (the
“Credit Agreement”) with SocGen, as administrative
agent, SG Americas Securities, LLC (“SG Americas”), as
lead arranger and bookrunner, and the Lenders signatory thereto
(collectively with SocGen, the “Lender”).
The
borrowing base of the credit facility was reaffirmed on May 19,
2017 at $44.0 million and subsequently reduced by $3.5 million to
$40.5 million after the Company completed the sale of certain oil
and gas properties for $5.5 million (prior to purchase price
adjustments). The borrowing base is generally subject to
redetermination on April 1st and October 1st of each year, but the
next redetermination is scheduled for September 15, 2017, as well
as special redeterminations described in the Credit Agreement. The
amounts borrowed under the Credit Agreement bear annual interest
rates at either (a) the London Interbank Offered Rate
(“LIBOR”) plus 3.00% to 4.00% or (b) the prime lending
rate of SocGen plus 2.00% to 3.00%, depending on the amount
borrowed under the credit facility and whether the loan is drawn in
U.S. dollars or Euro dollars. The interest rate for the credit
facility at June 30, 2017 was 4.98% and was based on LIBOR.
Principal amounts outstanding under the credit facility are due and
payable in full at maturity on October 26, 2019. All of the
obligations under the Credit Agreement, and the guarantees of those
obligations, are secured by substantially all of the
Company’s assets. Additional payments due under the Credit
Agreement include paying a commitment fee to the Lender in respect
of the unutilized commitments thereunder. The commitment rate is
0.50% per year of the unutilized portion of the borrowing base in
effect from time to time. The Company is also required to pay
customary letter of credit fees.
The
Credit Agreement contains a number of covenants that, among other
things, restrict, subject to certain exceptions, the
Company’s ability to incur additional indebtedness, create
liens on assets, make investments, enter into sale and leaseback
transactions, pay dividends and distributions or repurchase its
capital stock, engage in mergers or consolidations, sell certain
assets, sell or discount any notes receivable or accounts
receivable, and engage in certain transactions with
affiliates.
In
addition, the Credit Agreement requires the Company to maintain the
following financial covenants: a current ratio of not less than 1.0
to 1.0, a ratio of total debt to earnings before interest, taxes,
depreciation, depletion, amortization and exploration expenses
(“EBITDAX”) ratio of not greater than 3.5 to 1.0, a
ratio of EBITDAX to interest expense for the four fiscal quarters
ending on the last day of the fiscal quarter immediately preceding
such date of determination to be not less than 2.75 to 1.0, and
cash and cash equivalent investments together with borrowing
availability under the Credit Agreement of at least $4.0 million.
For fiscal quarters ending prior to and not including the fiscal
quarter ending December 31, 2017, EBITDAX will be calculated using
an annualized EBITDAX and interest expense will be calculated using
an annualized interest expense. Annualized EBITDAX for the
four-fiscal quarter period ending June 30, 2017 will be
deemed to equal EBITDAX for the three-fiscal quarter period
comprising the fiscal quarter ending December 31, 2016,
the fiscal quarter ending March 31, 2017 and the fiscal
quarter ending June 30, 2017, multiplied by four-thirds
(4/3). Annualized interest expense for the four-fiscal quarter
period ending June 30, 2017 will be deemed to equal
interest expense for the three-fiscal quarter period comprising the
fiscal quarter ending December 31, 2016, the fiscal
quarter ending March 31, 2017 and the fiscal quarter
ending June 30, 2017, multiplied by four-thirds (4/3).
The Credit Agreement contains customary affirmative covenants and
defines events of default for credit facilities of this type,
including failure to pay principal or interest, breach of
covenants, breach of representations and warranties, insolvency,
judgment default, and a change of control. Upon the occurrence and
continuance of an event of default, the Lender has the right to
accelerate repayment of the loans and exercise its remedies with
respect to the collateral. As of June 30, 2017 and December 31,
2016, the Company was in compliance with the covenants under the
Credit Agreement.
NOTE 11 – Stockholders’ Equity
Yuma is authorized to issue up to 100,000,000 shares of common
stock, $0.001 par value per share, and 20,000,000 shares of
preferred stock, $0.001 par value per share. The holders of common
stock are entitled to one vote for each share of common stock,
except as otherwise required by law. The Company has designated
7,000,000 shares of preferred stock as Series D Preferred
Stock.
The Company assumed the 2014 Plan upon the completion of the
Reincorporation Merger as described in Note 8 – Stock-Based
Compensation, which describes outstanding stock options, RSAs and
SARs granted under the 2014 Plan.
NOTE 12 – Income Taxes
The
Company’s effective tax rate for the three months ended June
30, 2017 and 2016 was 11.19% and 0.21%, respectively. The
difference between the statutory federal income taxes calculated
using a U.S. Federal statutory corporate income tax rate of 35% and
the Company’s effective tax rate of 11.19% for the three
months ended June 30, 2017 is primarily related to the valuation
allowance on the deferred tax assets and state income taxes. The
difference between the statutory federal income taxes calculated
using a U.S. Federal statutory corporate income tax rate of 35% and
the Company’s effective tax rate of 0.21% for the three
months ended June 30, 2016 is primarily related to the full
valuation allowance against its Federal and Louisiana net deferred
tax assets.
The
Company’s effective tax rate for the six months ended June
30, 2017 and 2016 was 0.24% and 0.10%, respectively. The difference
between the statutory federal income taxes calculated using a U.S.
Federal statutory corporate income tax rate of 35% and the
Company’s effective tax rate of 0.24% for the six months
ended June 30, 2017 is primarily related to the valuation allowance
on the deferred tax assets. The difference between the statutory
federal income taxes calculated using a U.S. Federal statutory
corporate income tax rate of 35% and the Company’s effective
tax rate of 0.10% for the six months ended June 30, 2016 is
primarily related to the full valuation allowance against its
Federal and Louisiana net deferred tax assets.
As of
June 30, 2017, the Company had federal and state net operating loss
carryforwards of approximately $130.1 million which expire between
2022 and 2037. Of this amount, approximately $61.3 million is
subject to limitation under Section 382 of the Internal Revenue
Code of 1986, as amended, which could result in some amounts
expiring prior to being utilized. Realization of a deferred tax
asset is dependent, in part, on generating sufficient taxable
income prior to expiration of the loss carryforwards.
The
Company provides for deferred income taxes on the difference
between the tax basis of an asset or liability and its carrying
amount in the financial statements in accordance FASB ASC Topic
740, “Income Taxes”. This difference will result in
taxable income or deductions in future years when the reported
amount of the asset or liability is recovered or settled,
respectively. In recording deferred tax assets, the Company
considers whether it is more likely than not that some portion or
all of the deferred income tax asset will be realized. The ultimate
realization of deferred income tax assets, if any, is dependent
upon the generation of future taxable income during the periods in
which those deferred income tax assets would be deductible. Based
on the available evidence, the Company has recorded a full
valuation allowance against its net deferred tax
assets.
NOTE 13 – Oil and Gas Asset Sales
On May 23, 2017, the Company announced the sale of certain oil and
natural gas properties for $5.5 million (prior to purchase price
adjustments) located in Brazos County, Texas held by a wholly owned
subsidiary and known as the El Halcón property. The
Company’s El Halcón property consisted of an average
working interest of approximately 10% (1,557 net acres) producing
approximately 140 Boe/d net from 50 Eagle Ford wells and one Austin
Chalk well.
NOTE 14 – Commitments and Contingencies
Joint Development Agreement
On
March 27, 2017, the Company entered into a Joint Development
Agreement (“JDA”) with two privately held companies,
both unaffiliated entities, covering an area of approximately 52
square miles (33,280 acres) in Yoakum County, Texas. In connection
with the JDA, the Company has acquired an 87.5% working interest in
approximately 2,491 acres (2,180 net acres) as of June 30, 2017. As
the operator of the property covered by the JDA, the Company is
committed to spend an additional $1.5 million by March 2020. The
Company intends to acquire additional leasehold acreage and begin
drilling its first joint venture well in 2017.
Throughput Commitment Agreement
On
August 1, 2014, Crimson, as operator of the Company’s
Chalktown properties, entered into a throughput commitment with ETC
Texas Pipeline, Ltd. effective April 1, 2015 for a five year
throughput commitment. In connection with the agreement, the
operator and the Company failed to reach the volume commitments in
year two, and the Company anticipates that a shortfall could exist
through the expiration of the five year throughput commitment,
which expires in March 2020. Accordingly, the Company is accruing
the expected volume commitment shortfall amounts based on
production to lease operating expense ("LOE") on a monthly basis.
On a net basis, the Company anticipates accruing approximately
$30,000 in LOE per month, which represents the maximum amounts that
could be owed based upon the contract.
Certain Legal Proceedings
From
time to time, the Company is party to various legal proceedings
arising in the ordinary course of business. While the outcome of
lawsuits cannot be predicted with certainty, the Company is not
currently a party to any proceeding that it believes, if determined
in a manner adverse to the Company, could have a potential material
adverse effect on its financial condition, results of operations,
or cash flows.
Ontiveros v. Pyramid Oil,
LLC, Yuma Energy, Inc. et al
.
In
September 2015, a suit was filed against Yuma and Pyramid Oil LLC
(“Pyramid”), a subsidiary of Yuma, styled Mark A.
Ontiveros and Louise D. Ontiveros, Trustees of The Ontiveros Family
Trust dated March 29, 2007 vs. Pyramid Oil, LLC, et al., Case
Number 15CV02959 in the Superior Court of California, County of
Santa Barbara, Cook Division. This was described in
Yuma’s Annual Report on Form 10-K for the year ended December
31, 2016. Pyramid and Texican entered into a Purchase, Sale,
Settlement and Release Agreement dated April 26, 2017, wherein
Pyramid and Texican settled their claims against each other and
Pyramid sold all of its interest in the leases, wells, equipment,
etc. to Texican. Pyramid retained certain P&A and clean-up
obligations on the Ontiveros property. The lawsuit with the
Ontiveros family subsequently was dismissed.
Yuma Energy, Inc. v. Cardno PPI Technology Services, LLC
Arbitration
On May
20, 2015, counsel for Cardno PPI Technology Services, LLC
(“Cardno PPI”) sent a notice of the filing of liens
totaling $304,209 on the Company’s Crosby 14 No. 1 Well and
Crosby 14 SWD No. 1 Well in Vernon Parish, Louisiana. The Company
disputed the validity of the liens and of the underlying invoices,
and notified Cardno PPI that applicable credits had not been
applied. The Company invoked mediation on August 11, 2015 on the
issues of the validity of the liens, the amount due pursuant to
terms of the parties’ Master Service Agreement
(“MSA”), and PPI Cardno’s breaches of the MSA.
Mediation was held on April 12, 2016; no settlement was
reached.
On May
12, 2016, Cardno filed a lawsuit in Louisiana state court to
enforce the liens; the Court entered an Order Staying Proceeding on
June 13, 2016, ordering that the lawsuit “be stayed pending
mediation/arbitration between the parties.” On June 17, 2016,
the Company served a Notice of Arbitration on Cardno PPI, stating
claims for breach of the MSA billing and warranty provisions. On
July 15, 2016, Cardno PPI served a Counterclaim for $304,209 plus
attorneys’ fees. The parties are currently engaged in the
arbitrator selection process. Management intends to pursue the
Company’s claims and to defend the counterclaim
vigorously.
Vintage Assets, Inc. v. Tennessee Gas Pipeline, L.L.C. et
al.
On October 24, 2016, Texas Southeastern Gas Gathering Company
("TGG"), a subsidiary of Yuma, was named as a defendant in an
action by Vintage Assets, Inc. in the United States District Court
for the Eastern District of Louisiana. This was described in
Yuma’s Annual Report on Form 10-K for the year ended December
31, 2016. Counsel for plaintiffs has been informed that TGG was
dissolved and terminated as of 2011, and has been furnished with
confirming documentation. Counsel for plaintiffs filed a motion for
dismissal of the claims against TGG without prejudice which was
granted by the Court on June 22, 2017.
The Parish of St. Bernard v. Atlantic Richfield Co., et
al
On
October 13, 2016, two subsidiaries of the Company, Exploration and
Yuma Petroleum Company (“YPC”), were named as
defendants, among several other defendants, in an action by the
Parish of St. Bernard in the Thirty-Fourth Judicial District of
Louisiana. The petition alleges violations of the State and Local
Coastal Resources Management Act of 1978, as amended, in the St.
Bernard Parish. The Company has notified its insurance
carrier of the lawsuit. Management intends to defend the
plaintiffs’ claims vigorously. At this point in the
legal process, no evaluation of the likelihood of an unfavorable
outcome or associated economic loss can be made; therefore no
liability has been recorded on the Company’s books. The case
has been removed to federal district court for the Eastern District
of Louisiana. A motion to remand has been filed, but has not yet
been ruled upon.
Davis - Cameron Parish vs. BEPCO LP, et al
&
Davis - Cameron
Parish vs. Alpine Exploration Companies, Inc.,
et al.
The
Parish of Cameron, Louisiana, filed a series of lawsuits against
approximately 190 oil and gas companies alleging that the
defendants, including Davis, have failed to clear, revegetate,
detoxify, and restore the mineral and production sites and other
areas affected by their operations and activities within certain
coastal zone areas to their original condition as required by
Louisiana law, and that such defendants are liable to Cameron
Parish for damages under certain Louisiana coastal zone laws for
such failures; however, the amount of such damages has not been
specified. Two of these lawsuits, originally filed February 4, 2016
in the 38th Judicial District Court for the Parish of Cameron,
State of Louisiana, name Davis as defendant, along with more than
30 other oil and gas companies. Both cases have been removed to
federal district court for the Western District of Louisiana. The
Company denies these claims and intends to vigorously defend them.
Motions to remand have been filed but have not yet been ruled
upon.
Louisiana, et al. Escheat Tax Audits
The
States of Louisiana, Texas, Minnesota, North Dakota and Wyoming
have notified the Company that they will examine the
Company’s books and records to determine compliance with each
of the examining state’s escheat laws. The review is being
conducted by Discovery Audit Services, LLC. The Company has engaged
Ryan, LLC to represent it in this matter. The exposure related to
the audits is not currently determinable.
Louisiana Severance Tax Audit
The
State of Louisiana, Department of Revenue, notified Exploration
that it was auditing Exploration’s calculation of its
severance tax relating to Exploration’s production from
November 2012 through March 2016. The audit relates to the
Department of Revenue’s recent interpretation of
long-standing oil purchase contracts to include a disallowable
“transportation deduction,” and thus to assert that the
severance tax paid on crude oil sold during the contract term was
not properly calculated. The Department of Revenue sent a
proposed assessment in which they sought to impose $476,954 in
additional state severance tax plus associated penalties and
interest. Exploration engaged legal counsel to protest
the proposed assessment and request a hearing. Exploration
then entered a Joint Defense Group of operators challenging similar
audit results. Since the Joint Defense Group is challenging
the same legal theory, the Board of Tax Appeals proposed to hear a
motion brought by one of the taxpayers that would address the rule
for all through a test case. Exploration’s case has
been stayed pending adjudication of the test case set for hearing
on November 7, 2017.
Louisiana Department of Wildlife and Fisheries
The
Company received notice from the Louisiana Department of Wildlife
and Fisheries (“LDWF”) in July 2017 stating that
Exploration has open Coastal Use Permits (“CUPs”)
located within the Louisiana Public Oyster Seed Grounds dating back
from as early as November 1993 and through a period ending in
November 2012. The majority of the claims relate to permits
that were filed from 2000 to 2005. Pursuant to the conditions
of each CUP, LDWF is alleging that damages were caused to the
oyster seed grounds and that compensation of an amount of
approximately $500,000 is owed by the Company. The Company is
currently evaluating the merits of the claim and is reviewing the
LDWF analysis.
Miami Corporation – South Pecan Lake Field Area
P&A
The
Company, along with several other E&P companies in the chain of
title, received letters from representatives of Miami Corporation
demanding the performance of well P&A, facility removal and
restoration obligations for wells in the South Pecan Lake Field
Area, Cameron Parish, Louisiana. The Company is currently
evaluating the merits of the claim.
NOTE 15 – Subsequent Events
The
Company is not aware of any subsequent events which would require
recognition or disclosure in the financial statements, except as
already recognized or disclosed in the Company’s filings with
the SEC.