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 drilling, developing and producing
both oil and natural gas assets. The Company also has acreage in
the Permian Basin of West Texas (Yoakum County, Texas), with the
potential for additional oil and natural gas reserves. Finally, the
Company has non-operated positions in the East Texas Woodbine and
had operated positions in Kern County, California, which were sold
in April 2019.
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 Sheet as of March 31, 2019;
the Consolidated Statements of Operations for the three months
ended March 31, 2019 and 2018; the Consolidated Statement of
Changes in Stockholders’ Equity for the three months ended
March 31, 2019 and 2018; and the Consolidated Statements of Cash
Flows for the three months ended March 31, 2019 and 2018. The
Company’s Consolidated Balance Sheet at December 31, 2018 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 1 in the Notes to Consolidated Financial Statements contained
in the Company’s Annual Report on Form 10-K for the year
ended December 31, 2018.
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, 2018. 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.
The consolidated financial statements have been prepared on a going
concern basis; however, see Note 2 – Liquidity and Going
Concern for additional information.
Recently Issued Accounting
Pronouncements
The accounting standard-setting organizations frequently issue new
or revised accounting rules. The Company regularly reviews new
pronouncements to determine their impact, if any, on the financial
statements.
Accounting Pronouncement Recently Adopted
In February 2016, the Financial Accounting Standards Board
(“FASB”) issued Accounting Standards Update
(“ASU”) 2016-02, Leases (Topic 842): Amendments to the
FASB Accounting Standards Codification (“ASU 2016-02”).
In January 2018, the FASB issued ASU No. 2018-01, Leases (Topic
842): Land Easement Practical Expedient for Transition to Topic 842
(“ASU 2018-01”). In July 2018, the FASB issued ASU No.
2018-11, Leases (Topic 842): Targeted Improvements (“ASU
2018-11”). Together, these related amendments to GAAP
represent ASC Topic 842, Leases (“ASC Topic 842”). ASC
Topic 842 requires an entity to recognize an asset and lease
liability for all qualifying leases. Classification of leases as
either a finance or operating lease determines the recognition,
measurement and presentation of expenses. This accounting standards
update also requires certain quantitative and qualitative
disclosures about leasing arrangements.
The new standard was effective for the Company in the first quarter
of 2019 and the Company adopted the new standard using a modified
retrospective approach, with the date of initial application on
January 1, 2019. Consequently, upon transition, the Company
recognized an asset and a lease liability with no retained earnings
impact. The Company is applying the following practical expedients
as provided in ASC Topic 842 which provide elections
to:
●
not
apply the recognition requirements to short-term leases (a lease
that at commencement date has a lease term of 12 months or less and
does not contain a purchase option);
●
not
reassess whether a contract contains a lease, lease classification
and initial direct costs; and
●
not
reassess certain land easements in existence prior to January 1,
2019.
Through the Company’s implementation process, it evaluated
each of its lease arrangements and enhanced its systems to track
and calculate additional information required upon adoption of this
standards update. The Company’s adoption did not have a
material impact on its consolidated balance sheet as of January 1,
2019, with the primary impact relating to the recognition of assets
and operating lease liabilities for operating leases which
represents less than a 5% change to total assets and total
liabilities.
Adoption of the new standard did not materially impact the
Company’s consolidated statements of operations or
stockholders’ equity. Leases acquired to explore for or use
minerals, oil or natural gas resources, including the right to
explore for those natural resources and rights to use the land in
which those natural resources are contained, are not within the
scope of the standards update (see Note 15 – Commitments and
Contingencies).
NOTE 2 – Liquidity and Going Concern
The
factors and uncertainties described below, as well as other factors
which include, but are not limited to, declines in the
Company’s production, the Company’s failure to
establish commercial production on its Permian properties, no
available capital to maintain and develop its properties, and its
substantial working capital deficit of approximately $40 million,
raise substantial doubt about the Company’s ability to
continue as a going concern for the twelve months following the
issuance of these financial statements. The consolidated financial
statements have been prepared on a going concern basis of
accounting, which contemplates continuity of operations,
realization of assets, and satisfaction of liabilities and
commitments in the normal course of business. The consolidated
financial statements do not include any adjustments that might
result from the outcome of the going concern
uncertainty.
On
October 26, 2016, the Company 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 Société
Générale (“SocGen”), as administrative agent,
SG Americas Securities, LLC, as lead arranger and bookrunner, and
the lenders signatory thereto (collectively with SocGen, the
“Lender”).
The
credit facility was $34.0 million as of March 31, 2019, and the
Company was, and is, fully drawn, leaving no availability on the
line of credit. All of the obligations under the Credit Agreement,
and the guarantees of those obligations, are secured by
substantially all of the Company’s assets.
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.
The
Credit Agreement contains customary financial and 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.
The
Company is not in compliance under the credit facility with its (i)
total debt to EBITDAX covenant for the trailing four quarter
period, (ii) current ratio covenant, (iii) EBITDAX to interest
expense covenant for the trailing four quarter period, (iv) the
liquidity covenant requiring the Company to maintain unrestricted
cash and borrowing base availability of at least $4.0 million, and
(v) obligation to make interest only payments. The Company
currently is not making any payments of interest under the credit
facility and anticipates future non-compliance under the credit
facility for the foreseeable future until the Company effects a
restructuring of its debt obligations. Due to this non-compliance,
as well as the credit facility maturity in 2019, the Company
classified its entire bank debt as a current liability in its
financial statements as of March 31, 2019. On October 9, 2018, the
Company received a notice and reservation of rights from the
administrative agent under the Credit Agreement advising that an
event of default had occurred and continues to exist by reason of
the Company’s noncompliance with the liquidity covenant
requiring us to maintain cash and cash equivalents and borrowing
base availability of at least $4.0 million. As a result of the
default, the Lender may accelerate the outstanding balance under
the Credit Agreement, increase the applicable interest rate by 2.0%
per annum or commence foreclosure on the collateral securing the
loans. As of the date of this filing, the Lender has not
accelerated the outstanding amount due and payable on the loans,
increased the applicable interest rate or commenced foreclosure
proceedings, but may exercise one or more of these remedies in the
future. As required under the Credit Agreement, the Company
previously entered into hedging arrangements with SocGen and BP
Energy Company (“BP”) pursuant to International Swaps
and Derivatives Association Master Agreements (“ISDA
Agreements”).
On
March 14, 2019, the Company received a notice of an event of
default under its ISDA Agreement with SocGen (the “SocGen
ISDA”). Due to the default under the ISDA Agreement, SocGen
unwound all of the Company’s hedges with them. The notice
provides for a payment of approximately $347,129 to settle the
Company’s outstanding obligations thereunder related to
SocGen’s hedges, which is included in accounts payable at
March 31, 2019. On March 19, 2019, the Company received a notice of
an event of default under its ISDA Agreement with BP (the “BP
ISDA”). Due to the default under the ISDA Agreement, BP also
unwound all of the Company’s hedges with them. The notice
provides for a payment of approximately $775,725 to settle the
Company’s outstanding obligations thereunder related to
BP’s hedges, which is included in accounts payable at March
31, 2019.
During
the first quarter of 2019, the Company agreed to sell its Kern
County, California properties, and closed on the sale in April 2019
for net proceeds of approximately $1.8 million. As additional
consideration for the sale of the assets, if WTI Index for oil
equals or exceeds $65 in the six months following closing and
maintains that average for twelve consecutive months then the buyer
agreed to pay the Company an additional $250,000. Net proceeds of
approximately $1.2 million were used for the repayment of
borrowings under the credit facility, and approximately $600,000
was retained by the Company for working capital
purposes.
The
Company has initiated several strategic alternatives to mitigate
its limited liquidity (defined as cash on hand and undrawn
borrowing base), its financial covenant compliance issues, and to
provide it with additional working capital to develop its existing
assets.
On
October 22, 2018, the Company retained Seaport Global Securities
LLC, an investment banking firm, to advise the Company on its
strategic and tactical alternatives, including possible
acquisitions and divestitures. On March 1, 2019, the Company hired
a Chief Restructuring Officer, and subsequently on March 28, 2019,
appointed that person as Interim Chief Executive
Officer.
The
Company continues to reduce its operating and general and
administrative costs, and has curtailed its planned 2019 capital
expenditures.
The
Company plans to take further steps to mitigate its limited
liquidity, which may include, but are not limited to, restructuring
its existing debt; selling additional assets; further reducing
general and administrative expenses; seeking merger and acquisition
related opportunities; and potentially raising proceeds from
capital markets transactions, including the sale of debt or equity
securities. There can be no assurance that the exploration of
strategic alternatives will result in a transaction or otherwise
improve the Company’s limited liquidity and that the Company
will continue as a going concern.
NOTE 3 – Revenue Recognition
The Company recognizes revenues to depict the transfer of control
of promised goods or services to its customers in an amount that
reflects the consideration to which it expects to be entitled to in
exchange for those goods or services.
Crude oil and condensate are sold through month-to-month evergreen
contracts. The price for Louisiana production is tied to an index
or a weighted monthly average of posted prices with certain
adjustments for gravity, Basic Sediment and Water
(“BS&W”) and transportation. Generally, the index
or posting is based on customary industry spot prices. Pricing for
the Company’s California properties is based on an average of
specified posted prices, adjusted for gravity and transportation.
The Company’s natural gas is sold under month-to-month
contracts with pricing tied to either first of the month index or a
monthly weighted average of purchaser prices received. Natural gas
liquids are sold under month-to-month or year-to-year contracts
usually tied to the related natural gas contract. Pricing is based
on published prices for each product or a monthly weighted average
of purchaser prices received.
Sales of crude oil, condensates, natural gas and natural gas
liquids (“NGLs”) are recognized at the point control of
the product is transferred to the customer. Virtually all of the
Company’s contracts’ pricing provisions are tied to a
market index, with certain adjustments based on, among other
factors, whether a well delivers to a gathering or transmission
line, quality of the oil or natural gas, and prevailing supply and
demand conditions. As a result, the price of the crude oil,
condensate, natural gas, and NGLs fluctuates to remain competitive
with other available crude oil, natural gas, and NGLs
supplies.
Revenue is measured based on consideration specified in the
contract with the customer, and excludes any amounts collected on
behalf of third parties. The Company recognizes revenue in the
amount that reflects the consideration it expects to be entitled to
in exchange for transferring control of those goods to the
customer. The contract consideration in the Company’s
variable price contracts is typically allocated to specific
performance obligations in the contract according to the price
stated in the contract. Amounts allocated in the Company’s
fixed price contracts are based on the stand-alone selling price of
those products in the context of long-term, fixed price contracts,
which generally approximates the contract price.
The Company records revenue in the month production is delivered to
the purchaser. However, settlement statements for certain natural
gas and NGL sales may not be received for 30 to 90 days after the
date production is delivered, and as a result, the Company is
required to estimate the amount of production delivered to the
purchaser and the price that will be received for the sale of the
product. The Company records the differences between its estimates
and the actual amounts received for product sales in the month that
payment is received from the purchaser. Any identified differences
between its revenue estimates and actual revenue received
historically have not been significant. For the three months ended
March 31, 2019 and 2018, revenue recognized in the reporting period
related to performance obligations satisfied in prior reporting
periods was not material.
Gain or loss on derivative instruments is not considered revenue
from contracts with customers. The Company may use financial or
physical contracts accounted for as derivatives as economic hedges
to manage price risk associated with normal sales, or in limited
cases may use them for contracts the Company intends to physically
settle but do not meet all of the criteria to be treated as normal
sales.
Natural Gas and Natural Gas Liquids Sales
Under the Company’s natural gas processing contracts, it
delivers natural gas to a midstream processing entity at the
wellhead or the inlet of the midstream processing entity’s
system. The midstream processing entity gathers and processes the
natural gas and remits proceeds to the Company for the resulting
sales of NGLs and residue gas. In these scenarios, the Company
evaluates whether it is the principal or the agent in the
transaction. For those contracts where the Company has concluded it
is the principal and the ultimate third party is its customer, the
Company recognizes revenue on a gross basis, with transportation,
gathering, processing and compression fees presented as an expense
in its lease operating and production costs in the Consolidated
Statements of Operations.
In certain natural gas processing agreements, the Company may elect
to take its residue gas and/or NGLs in-kind at the tailgate of the
midstream entity’s processing plant and subsequently market
the product. Through the marketing process, the Company delivers
product to the ultimate third-party purchaser at a contractually
agreed-upon delivery point and receives a specified index price
from the purchaser. In this scenario, the Company recognizes
revenue when control transfers to the purchaser at the delivery
point based on the index price received from the purchaser. The
gathering, processing and compression fees attributable to the gas
processing contract, as well as any transportation fees incurred to
deliver the product to the purchaser, are presented as lease
operating and production costs in the Consolidated Statements of
Operations.
Crude Oil and Condensate Sales
The Company sells oil production at the wellhead and collects an
agreed-upon index price, net of pricing differentials. In this
scenario, revenue is recognized when control transfers to the
purchaser at the wellhead at the net price received.
The following table presents the Company’s revenues
disaggregated by product source. Sales taxes are excluded from
revenues.
|
Three
Months Ended March 31,
|
|
|
|
Sales
of natural gas and crude oil:
|
|
|
Crude
oil and condensate
|
$
2,199,023
|
$
3,066,258
|
Natural
gas
|
1,180,408
|
1,791,251
|
NGLs
|
599,246
|
788,027
|
Total
revenues
|
$
3,978,677
|
$
5,645,536
|
|
|
|
|
|
|
|
|
|
Transaction Price Allocated to Remaining Performance
Obligations
A significant number of the Company’s product sales are
short-term in nature with a contract term of one year or less. For
those contracts, the Company has utilized the practical expedient
exempting the Company from disclosure of the transaction price
allocated to remaining performance obligations if the performance
obligation is part of a contract that has an original expected
duration of one year or less.
For the Company’s product sales that have a contract term
greater than one year, it has utilized the practical expedient
which states that the Company is not required to disclose the
transaction price allocated to remaining performance obligations if
the variable consideration is allocated entirely to a wholly
unsatisfied performance obligation. Under these sales contracts,
each unit of product generally represents a separate performance
obligation; therefore future volumes are wholly unsatisfied and
disclosure of the transaction price allocated to remaining
performance obligations is not required.
Contract Balances
Receivables from contracts with customers are recorded when the
right to consideration becomes unconditional, generally when
control of the product has been transferred to the customer.
Receivables from contracts with customers were $1,828,375 and
$2,282,200 as of March 31, 2019 and December 31, 2018,
respectively, and are reported in trade accounts receivable, net on
the Consolidated Balance Sheets. The Company currently has no other
assets or liabilities related to its revenue contracts, including
no upfront or rights to deficiency payments.
NOTE 4 – 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 full cost
ceiling limitation limits these costs to an amount equal to the
present value, discounted at 10%, of estimated future cash flows
from estimated proved reserves less estimated future operating and
development costs, abandonment costs (net of salvage value) and
estimated related future deferred 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 first quarter of 2019 full cost
ceiling calculation was prepared by the Company using (i) $63.06
per barrel for oil, and (ii) $3.07 per MMBTU for natural gas as of
March 31, 2019. 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.
Based
on a thorough analysis of the Company’s assets, the following
three major contributors account for an impairment for the first
quarter of fiscal year 2019: (i) the finalization of the Kern
County, California property sale for proceeds substantially less
than PV10 value of the proved producing and non-producing assets
(approximately $5 million of the impairment); (ii) a final downward
revision with respect to the Lac Blanc LP #2 well, which went off
production in February 2019, and is now not expected to return to
production (approximately $3 million of the impairment); and (iii)
the decrease in the 12 month rolling SEC prices used at March 31,
2019, compared to December 31, 2018, primarily due to a reduction
in oil and plant product prices of approximately 3% (approximately
$3 million of the impairment). As a result of this review, the
Company recorded a full cost ceiling impairment charge of $11.45
million. During the three month period ended March 31, 2018, the
Company did not record any full cost ceiling
impairments.
See
Note 14 – Divestitures and Oil and Gas Asset Sales for a
discussion of impairments made to assets held for
sale.
NOTE 5 – 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 three months ended March 31, 2019 in
accordance with the provisions of FASB ASC Topic 410, “Asset
Retirement and Environmental Obligations”:
|
|
|
|
Asset
retirement obligations at December 31, 2018
|
$
11,271,859
|
Liabilities
incurred
|
-
|
Liabilities
settled
|
-
|
Accretion
expense
|
137,120
|
Revisions
in estimated cash flows
|
-
|
|
|
Asset
retirement obligations at March 31, 2019
|
$
11,408,979
|
Based
on expected timing of settlements, $128,539 of the ARO is
classified as current at March 31, 2019.
NOTE 6 – Fair Value Measurements
Certain financial instruments are reported at fair value on the
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.
As previously disclosed, there were no outstanding commodity
derivatives as of March 31, 2019.
|
Fair
value measurements at December 31, 2018
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets:
|
|
|
|
|
Commodity
derivatives – oil
|
$
-
|
$
922,562
|
$
-
|
$
922,562
|
Commodity
derivatives – gas
|
-
|
(158,376
)
|
-
|
$
(158,376
)
|
Total
assets
|
$
-
|
$
764,186
|
$
-
|
$
764,186
|
Derivative instruments listed above are related to swaps (see Note
7 – 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), which approximates fair value.
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 5 –
Asset Retirement Obligations). Therefore, the Company has
designated the initial recording of these liabilities as Level
3.
Assets Held for Sale
–
The fair values of property, plant and equipment, classified as
assets held for sale, and related impairments, which are calculated
using Level 3 inputs, are discussed in Note 14 – Divestitures
and Oil and Gas Asset Sales.
NOTE 7 – Commodity Derivative Instruments
As
required under the Credit Agreement, the Company previously entered
into hedging arrangements with SocGen and BP pursuant to ISDA
Agreements. On March 14, 2019, the Company received a notice of an
event of default under the “SocGen ISDA. Due to the default
under the SocGen ISDA Agreement, SocGen unwound all of the
Company’s hedges with them. The notice provides for a payment
of approximately $347,129 to settle the Company’s outstanding
obligations thereunder related to SocGen’s hedges which is
included in accounts payable at March 31, 2019. On March 19, 2019,
The Company received a notice of an event of default under its BP
ISDA. Due to the default under the BP ISDA, BP also unwound all of
the Company’s hedges with them. The notice provides for a
payment of approximately $775,725 to settle the Company’s
outstanding obligations thereunder related to BP’s hedges
which is included in accounts payable at March 31,
2019.
Counterparty Credit Risk
– Commodity derivative
instruments expose the Company to counterparty credit risk. The
Company did not have any commodity derivative instruments at March
31, 2019. Commodity derivative contracts are executed under ISDA
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.
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
|
$
-
|
$
1,031,614
|
Noncurrent
assets
|
-
|
98,530
|
Total
asset commodity derivatives
|
-
|
1,130,144
|
|
|
|
Liability
commodity derivatives:
|
-
|
|
Current
liabilities
|
-
|
(280,456
)
|
Noncurrent
liabilities
|
-
|
(85,502
)
|
Total
liability commodity derivatives
|
-
|
(365,958
)
|
|
|
|
Total
commodity derivative instruments
|
$
-
|
$
764,186
|
Net losses from commodity derivatives on the Consolidated
Statements of Operations are comprised of the
following:
|
Three
Months Ended March 31,
|
|
|
|
|
|
|
Derivative
settlements
|
$
(1,076,497
)
|
$
(529,364
)
|
Mark
to market on commodity derivatives
|
(764,186
)
|
(721,896
)
|
Net
losses from commodity derivatives
|
$
(1,840,683
)
|
$
(1,251,260
)
|
NOTE 8 – Preferred Stock
Each
share of the Company’s Series D Convertible Preferred Stock,
$0.001 par value per share (the “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
$6.5838109. 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 March 31,
2019, the Series D Preferred Stock had a liquidation preference of
approximately $23.0 million. The Series D Preferred Stock provides
for cumulative dividends of 7.0% per annum, payable in-kind. In
payment of the dividend, the Company issued 35,232 shares of Series
D Preferred Stock during the three months ended March 31, 2019. The
Company does not have any dividends in arrears at March 31,
2019.
NOTE 9 – Stock-Based Compensation
2014 Long-Term Incentive Plan
On
October 26, 2016, Yuma assumed the Yuma Energy, Inc., a California
corporation (“Yuma California”), 2014 Long-Term
Incentive Plan (the “2014 Plan”), which was approved by
the shareholders of Yuma California. Under the 2014 Plan, Yuma
could 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.
At
March 31, 2019, 106,046 shares of the 2,495,000 shares of common
stock originally authorized under the 2014 Plan remained available
for future issuance.
However, upon adoption of the
Company’s 2018 Long-Term Incentive Plan on June 7, 2018, none
of these remaining shares will be issued.
2018 Long-Term Incentive Plan
The
Company’s Board adopted the Yuma Energy, Inc. 2018 Long-Term
Incentive Plan (the “2018 Plan”), and its stockholders
approved the 2018 Plan at the Annual Meeting on June 7, 2018. The
2018 Plan will replace the 2014 Plan; however, the terms and
conditions of the 2014 Plan and related award agreements will
continue to apply to all awards granted under the 2014
Plan.
The
2018 Plan expires on June 7, 2028, and no awards may be granted
under the 2018 Plan after that date. However, the terms and
conditions of the 2018 Plan will continue to apply after that date
to all 2018 Plan awards granted prior to that date until they are
no longer outstanding.
Under
the 2018 Plan, the Company may grant stock options, RSAs, RSUs,
SARs, performance units, performance bonuses, stock awards and
other incentive awards to employees or those of the Company’s
subsidiaries or affiliates, subject to the terms and conditions set
forth in the 2018 Plan. The Company 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, subject to the
conditions set forth in the 2018 Plan. Generally, all classes of
the Company’s employees are eligible to participate in the
2018 Plan.
The
2018 Plan provides that a maximum of 4,000,000 shares of the
Company’s common stock may be issued in conjunction with
awards granted under the 2018 Plan. Shares of common stock
cancelled, settled in cash, forfeited, withheld, or tendered by a
participant to satisfy exercise prices or tax withholding
obligations will be available for delivery pursuant to other
awards. At March 31, 2019, all of the 4,000,000 shares of common
stock authorized under the 2018 Plan remain available for future
issuance.
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 vesting, 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
March 31, 2019, the Company did not grant any RSAs under the 2014
Plan or the 2018 Plan. As of March 31, 2019, there were a total of
333,334 stock options outstanding, with a weighted average exercise
price of $2.56 per share, a contractual life of approximately 8.05
years, and an aggregate intrinsic value of $0.00 per share. Of the
total stock options outstanding, 255,320 were exercisable, with a
weighted average exercise price of $2.56.
At
March 31, 2019, there were a total of 28,857 unvested RSAs, with a
weighted average grant-date fair value of $2.56 per
share.
Liability Based Awards –
During the three months ended
March 31, 2019, the Company did not grant any liability-based
awards under the 2014 Plan or the 2018 Plan. As of March 31, 2019,
there were 530,447 unvested cash-settled SARs with a weighted
average fair value of $0.04 per share.
Share Buy-back –
During the three months ended March
31, 2019, the Company purchased 17,208 common shares from employees
at a cost of $1,945 in satisfaction of employee tax obligations
upon the vesting of RSAs.
Total
share-based compensation expenses recognized for the three months
ended March 31, 2019 and 2018 were ($152,039), due primarily to
liability-based SARs declining in value and significant forfeitures
of equity-based RSAs and stock options, and $296,293, respectively.
No share-based compensation was capitalized during either
period.
NOTE 10 – Debt and Interest Expense
Long-term
debt consisted of the following:
|
|
|
|
|
|
|
|
|
Senior
credit facility
|
$
34,000,000
|
$
34,000,000
|
Installment
loan due 6/23/19 originating from the financing of
|
|
|
insurance
premiums at 6.14% interest rate
|
342,527
|
742,953
|
Total
debt
|
34,342,527
|
34,742,953
|
Less:
current maturities
|
(34,342,527
)
|
(34,742,953
)
|
Total
long-term debt
|
$
-
|
$
-
|
Senior Credit Facility
The
Company is currently in default under its Credit Agreement due to
non-compliance with the financial covenants and failure to pay
interest. As of March 31, 2019, the credit facility had a borrowing
base of $34.0 million and the Company was fully drawn under the
credit facility leaving no availability.
On
October 26, 2016, the Company and three of its subsidiaries, as the
co-borrowers, entered into the Credit Agreement with the Lender.
The Company’s obligations under the Credit Agreement are
guaranteed by its subsidiaries and are secured by liens on
substantially all of the Company’s assets, including a
mortgage lien on oil and natural gas properties covering at least
95% of the PV-10 value of the proved oil and gas properties
included in the determination of the borrowing base.
The
borrowing base is generally subject to redetermination on April 1st
and October 1st of each year, as well as special redeterminations
described in the Credit Agreement (no redetermination occurred on
April 1, 2019). 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 December 31, 2018 was 6.53% for LIBOR-based debt
and 8.50% for prime-based debt. 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 the
Company’s 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 on the last day of each quarter, 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 for the four fiscal quarters ending
on the last day of the fiscal quarter immediately preceding such
date of determination, and a ratio of EBITDAX to interest expense
of not less than 2.75 to 1.0 for the four fiscal quarters ending on
the last day of the fiscal quarter immediately preceding such date
of determination, and cash and cash equivalent investments together
with borrowing availability under the Credit Agreement of at least
$4.0 million. 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.
At
March 31, 2019, the Company was not in compliance under the credit
facility with its (i) total debt to EBITDAX covenant for the
trailing four quarter period, (ii) current ratio covenant, (iii)
EBITDAX to interest expense covenant for the trailing four quarter
period, (iv) the liquidity covenant requiring the Company to
maintain unrestricted cash and borrowing base availability of at
least $4.0 million, and (v) obligation to make an interest only
payment for the quarters ended December 31, 2018 and March 31,
2019. In addition, the Company currently is not making payments of
interest due under the credit facility and anticipates future
non-compliance under the credit facility for the foreseeable future
until the Company effects a restructuring of its debt obligations.
Due to this non-compliance as well as the credit facility maturity
in 2019, the Company classified its entire bank debt as a current
liability in the consolidated financial statements. On October 9,
2018, the Company received a notice and reservation of rights from
the administrative agent under the Credit Agreement advising that
an event of default has occurred and continues to exist by reason
of the Company’s noncompliance with the liquidity covenant
requiring the Company to maintain cash and cash equivalents and
borrowing base availability of at least $4.0 million. As a result
of the default, the Lender may accelerate the outstanding balance
under the Credit Agreement, increase the applicable interest rate
by 2.0% per annum or commence foreclosure on the collateral
securing the loans. As of the date of this filing, the Lender has
not accelerated the outstanding amount due and payable on the
loans, increased the applicable interest rate or commenced
foreclosure proceedings, but may exercise one or more of these
remedies in the future. The Company has commenced discussions with
the Lender concerning a forbearance agreement or waiver of the
event of default; however, there can be no assurance that the
Lender and the Company will come to any agreement regarding a
forbearance or waiver of the event of default. As required under
the Credit Agreement, the Company previously entered into hedging
arrangements with SocGen and BP pursuant to ISDA Agreements. On
March 14, 2019, the Company received a notice of an event of
default under the SocGen ISDA. Due to the default under the SocGen
ISDA, SocGen unwound all of the Company’s hedges with them.
The notice provides for a payment of approximately $347,129 to
settle the Company’s outstanding obligations thereunder
related to SocGen’s hedges which is included in accounts
payable at March 31, 2019. On March 19, 2019, the Company received
a notice of an event of default under the BP ISDA. Due to the
default under the BP ISDA, BP also unwound all of the
Company’s hedges with them. The notice provides for a payment
of approximately $775,725 to settle the Company’s outstanding
obligations thereunder, related to BP’s hedges which is
included in accounts payable at March 31, 2019.
The
Company incurred commitment fees in connection with the Credit
Agreement of $-0- and $14,335 during the three months ended March
31, 2019 and 2018, respectively.
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.
See Note 9 – Stock-Based Compensation, which describes
outstanding stock options, RSAs and SARs granted under the 2014
Plan and the provisions of the 2018 Plan adopted on June 7,
2018.
NOTE 12 – Loss Per Common Share
Loss
per common share – Basic is calculated by dividing net loss
attributable to common stockholders by the weighted average number
of shares of common stock outstanding during the period. Loss per
common share – Diluted assumes the conversion of all
potentially dilutive securities, and is calculated by dividing net
loss attributable to common stockholders by the sum of the weighted
average number of shares of common stock outstanding plus
potentially dilutive securities. Loss per common share –
Diluted considers the impact of potentially dilutive securities
except in periods where their inclusion would have an anti-dilutive
effect.
A
reconciliation of loss per common share is as
follows:
|
Three
Months Ended March 31,
|
|
|
|
|
|
|
Net
loss attributable to common stockholders
|
$
(16,040,865
)
|
$
(3,536,937
)
|
|
|
|
Weighted
average common shares outstanding
|
|
|
Basic
|
23,195,043
|
22,813,130
|
Add
potentially dilutive securities:
|
|
|
Unvested
restricted stock awards
|
-
|
-
|
Stock
appreciation rights
|
-
|
-
|
Stock
options
|
-
|
-
|
Series
D preferred stock
|
-
|
-
|
Diluted
weighted average common shares outstanding
|
23,195,043
|
22,813,130
|
|
|
|
Loss
per common share:
|
|
|
Basic
|
$
(0.69
)
|
$
(0.16
)
|
Diluted
|
$
(0.69
)
|
$
(0.16
)
|
For the
three months ended March 31, 2019, the Company excluded 28,857
shares of unvested restricted stock awards, 715,213 stock
appreciation rights, 333,334 stock options, and 2,076,472 shares of
Series D Preferred Stock in calculating diluted earnings per share,
as the effect was anti-dilutive. For the three months ended March
31, 2018, the Company excluded 187,153 shares of unvested
restricted stock awards, 1,707,619 stock appreciation rights,
893,617 stock options, and 1,937,262 shares of Series D Preferred
Stock in calculating diluted earnings per share, as the effect was
anti-dilutive.
NOTE 13 – Income Taxes
The
Company’s effective tax rate was 0.00% for the three months
ended March 31, 2019 and 2018. Differences between the U.S. federal
statutory rate of 21% in 2019 and 2018 and the Company’s
effective tax rates are due to the tax effects of valuation
allowances recorded against the deferred tax assets.
As of
March 31, 2019, the Company had federal net operating loss
carryforwards of approximately $187.8 million, of which $173.2
million expire between 2022 and 2038. Of this amount, approximately
$59.5 million is subject to limitation under Section 382 of the
Internal Revenue Code of 1986, as amended (the “Code”),
which could result in some amounts expiring prior to being
utilized. The remaining $14.6 million of federal net operating loss
may be carried forward indefinitely. The Company has $87.6 million
of state net operating losses which expire between 2019 and
2038.
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 14 – Divestitures and Oil and Gas Asset
Sales
During
the first quarter of 2019, the Company agreed to sell its Kern
County, California properties, and closed on the sale in April 2019
for approximately $1.8 million in net proceeds. As additional
consideration for the sale of the assets, if the WTI index for oil
equals or exceeds $65 in the six months following closing and
maintains that average for twelve consecutive months, then the
buyer shall pay to the Company an additional $250,000. Under the
full cost method of accounting, no gain or loss was recognized on
the sale. The net proceeds were used for the repayment of
borrowings under the credit facility and working
capital.
NOTE 15 – 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 the Permian Basin of Yoakum County,
Texas. In connection with the JDA, the Company now holds a 62.5%
working interest in approximately 4,823 acres (3,014 net acres) as
of March 31, 2019. As the operator of the property covered by the
JDA, the Company is committed as of March 31, 2019 to spend an
additional $241,649 by March 2020.
Throughput Commitment Agreement
On
August 1, 2014, Crimson Energy Partners IV, LLC, as operator of the
Company’s Chalktown properties, in which the Company has a
working interest, entered into a throughput commitment (the
“Commitment”) with ETC Texas Pipeline, Ltd. effective
April 1, 2015 for a five-year throughput commitment. In connection
with the Commitment, the operator and the Company failed to reach
the volume commitments in year two, and the Company anticipates
that a shortfall will exist through the expiration of the five-year
term, which expires in March 2020. Accordingly, the Company is
accruing the expected volume commitment shortfall amounts of
approximately $29,000 per month to lease operating expense
(“LOE”) based on production, which represents the
maximum amounts that could be owed based upon the Commitment. As of
March 31, 2019, $344,327 has been recorded in accrued expense for
the volume commitment shortfall.
Lease Agreements
The Company determines if an arrangement is a lease at inception of
the arrangement. To the extent that the Company determines an
arrangement represents a lease, that lease is classified as an
operating lease or a finance lease. The Company currently does not
have any finance leases. In accordance with ASC Topic 842,
operating leases are capitalized on the Company’s
Consolidated Balance Sheet through an asset and a corresponding
lease liability. Recorded assets represent the Company’s
right to use an underlying asset for the lease term and lease
liabilities represent its obligation to make lease payments arising
from the lease. Short-term leases that have an initial term of one
year or less are not capitalized.
The Company’s operating leases are reflected as right-of-use
lease assets, accrued liabilities-current and operating lease
liabilities on its Consolidated Balance Sheet. Operating lease
assets and liabilities are recognized at the commencement date of
an arrangement based on the present value of lease payments over
the lease term. In addition to the present value of lease payments,
the operating lease asset also includes any lease payments made to
the lessor prior to lease commencement, less any lease incentives
and initial direct costs incurred. Lease expense for operating
lease payments is recognized on a straight-line basis over the
lease term.
Nature of Leases
The Company leases certain office space, field and other equipment
under cancelable and non-cancelable leases to support its
operations. A more detailed description of significant lease types
is included below.
Office Agreements
The Company rents office space from third parties, structured with
non-cancelable terms. The Company has concluded its office
agreements represent operating leases with a lease term that equals
the primary non-cancelable contract term. Upon completion of the
primary term, both parties have substantive rights to terminate the
lease. As a result, enforceable rights and obligations do not exist
under the rental agreements subsequent to the primary
term.
Field Equipment and Compressors
The Company rents compressors and other equipment from third
parties in order to facilitate the downstream movement of its
production from its drilling operations to market, typically
structured with a non-cancelable primary term of one to two years,
and continuing thereafter on a month-to-month basis subject to
termination by either party. These compressors and other equipment
are critical to the Company’s ability to sell its production.
The Company has therefore concluded that its compressor and other
equipment rental agreements represent operating leases with a lease
term that extends through the expected life of the field reserves
(as opposed to the primary non-cancelable contract
term).
The Company enters into daywork contracts for
drilling/completion/workover rigs with third parties to support its
activities. The Company has concluded that these arrangements
represent short-term operating leases. The accounting guidance
requires the Company to make an assessment at contract commencement
if it is reasonably certain that it will exercise the option to
extend the term. The Company has determined that it cannot conclude
with reasonable certainty if it will choose to extend the contract
beyond its original term.
Significant Judgments
Discount Rate
The Company’s leases typically do not provide an implicit
rate. Accordingly, it is required to use its incremental borrowing
rate in determining the present value of lease payments based on
the information available at commencement date. The Company’s
incremental borrowing rate reflects the estimated rate of interest
that it would pay to borrow on a collateralized basis over a
similar term an amount equal to the lease payments in a similar
economic environment.
Practical Expedients and Accounting Policy Elections
Certain of the Company’s lease agreements include lease and
non-lease components. For all existing asset classes with multiple
component types, the Company has utilized the practical expedient
that exempts it from separating lease components from non-lease
components. Accordingly, the Company accounts for the lease and
non-lease components in an arrangement as a single lease
component.
In addition, for all of its existing asset classes, the Company has
made an accounting policy election not to apply the lease
recognition requirements to its short-term leases (that is, a lease
that, at commencement, has a lease term of twelve months or less
and does not include an option to purchase the underlying asset
that the Company is reasonably certain to exercise). Accordingly,
the Company recognizes lease payments related to its short-term
leases in its statement of operations on a straight-line basis over
the lease term, which has not changed from the prior recognition.
To the extent that there are variable lease payments, the Company
recognizes those payments in its Statement of Operations in the
period in which the obligation for those payments is
incurred.
The total lease expense for the three months ended March 31, 2019,
which is included in general and administrative expense and lease
operating expense, was $221,973.
Supplemental cash flow information related to the Company’s
operating leases is included in the table below:
|
|
|
|
Cash
paid for amounts included in the measurement of lease
liabilities
|
$
221,973
|
Supplemental balance sheet information related to operating leases
is included in the table below:
|
|
Right-of-use
lease assets
|
$
4,247,226
|
Accrued
liabilities - current
|
(840,535
)
|
Operating
lease liabilities - long-term
|
$
(3,406,691
)
|
The weighted average remaining lease term for the Company’s
operating leases is 7.1 years as of March 31, 2019, with a weighted
average discount rate of 10.5%.
Lease liabilities with enforceable contract terms that are greater
than one-year mature as follows:
|
|
|
|
|
|
Remainder
of 2019
|
$
665,919
|
2020
|
865,350
|
2021
|
839,613
|
2022
|
847,208
|
2023
|
823,806
|
Thereafter
|
2,344,570
|
Total
lease payments
|
6,386,466
|
Less
imputed interest
|
(2,139,240
)
|
Total
lease liability
|
$
4,247,226
|
Certain Legal Proceedings
From
time to time, the Company is party to various legal proceedings
arising in the ordinary course of business. The Company expenses or
accrues legal costs as incurred. A summary of the Company’s
legal proceedings is as follows:
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 selected an arbitrator, and the
arbitration hearing was held on March 29, April 12 and April 13,
2018. The parties submitted closing statements on April 30, 2018,
and the arbitrator issued her Final Arbitration Award
(the”Award”) on April 4, 2019.
The
Award granted the Company a $62,923 credit for Cardno’s
improper billing of insurance charges, and a $127,100 credit for
Cardno’s billing in excess of the contractual prices. After
the credits were applied, Cardno was awarded $114,186 on its claim.
The arbitrator also awarded Cardno $23,676 in prejudgment
interest.
The Parish of St. Bernard v. Atlantic Richfield Co., et
al
On
October 13, 2016, two subsidiaries of the Company, Yuma Exploration
and Production Company, Inc. (“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. The case was removed to federal district
court for the Eastern District of Louisiana. A motion to remand was
filed and the Court officially remanded the case on July 6, 2017.
Exceptions for Exploration, YPC and the other defendants were
filed; however, the hearing for such exceptions was continued from
the original date of October 6, 2017 to November 22, 2017. The
November 22, 2017 hearing was continued without date because the
parties agreed the case will be de-cumulated into subcases, but the
details of this are yet to be determined. The case was removed
again on other grounds on May 23, 2018. On May 25, 2018, a Motion
was filed on behalf of certain defendants with the United States
Judicial Panel for Multi District Litigation (“JPMDL”)
for consolidated proceedings for all 41 pending cases filed in
Louisiana with claims that are substantially the same as those in
this case. A 42
nd
case has been added
as a “tag-along”. In the interim, plaintiffs timely
filed their Motion to Remand in the case. Hearing on the Motion
before the JPMDL was held on July 26, 2018 in Santa Fe, New Mexico,
and the JPMDL denied centralization by Order dated July 31, 2018.
The Order indicates Plaintiffs may be willing to consolidate all
cases pending in the Western District with those in the Eastern
District, although Defendants may not be amenable to same. That did
not occur and this case remains stayed. In the interim, an Order
was issued in another of the coastal cases pending in the Eastern
District of Louisiana lifting the stay and setting a schedule for
briefing for plaintiffs’ motion to remand (
Parish of Plaquemines v. Riverwood Production
Company, et al., No. 2:18-cv-05217,
Eastern District of Louisiana
). Judge
Martin L. C. Feldman is assigned to the
Riverwood
case and he will be the first
Judge in the Eastern District to decide on the remand, and
presumably the Judges assigned to other cases, including this one,
will follow his decision as relevant and appropriate. Oral argument
on the motion to remand in the
Riverwood
case has been repeatedly
continued, and was finally held on April 10, 2019. The Court has
not yet ruled, and there is still no ruling in the
Auster
case as reported below. It is
impossible to predict at this time whether this second removal will
keep the case in federal court. 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 consolidated financial
statements.
Cameron Parish vs. BEPCO LP, et al & 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 Petroleum Acquisition Corp.
(“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.
Davis has become a party to the Joint Defense and Cost Sharing
Agreements for these cases. Motions to remand were filed and the
Magistrate Judge recommended that the cases be remanded. The
Company was advised that the new District Judge assigned to these
cases is Judge Terry A. Doughty, and on May 9, 2018, Judge Doughty
agreed with the Magistrate Judge’s recommendation and the
cases were remanded to the 38
th
Judicial District
Court, Cameron Parish, Louisiana. The cases were removed again on
other grounds on May 23, 2018. On May 25, 2018, a Motion was filed
on behalf of certain defendants with the United States Judicial
Panel for Multi District Litigation (“JPMDL”) for
consolidated proceedings for all 41 pending cases filed in
Louisiana with claims that are substantially the same as those in
these cases. A 42
nd
case has been added
as a “tag-along”. In the interim, plaintiffs timely
filed their Motion to Remand in the cases. Hearing on the Motion
before the JPMDL was held on July 26, 2018 in Santa Fe, New Mexico,
and the JPMDL denied centralization by Order dated July 31, 2018.
The Order indicates Plaintiffs may be willing to consolidate all
cases pending in the Western District with those in the Eastern
District, although Defendants may not be amenable to same. That did
not occur. On October 1, 2018, all of the coastal cases pending in
the Western District of Louisiana, including these cases, were
re-assigned to the newly appointed District Judge, Judge Robert R.
Summerhays. On August 29, 2018, Magistrate Judge Kay signed an
Order providing for staged briefing on the plaintiffs’
motion(s) to remand in all the coastal cases pending in the Western
District, with the lowest numbered case (Parish of Cameron v.
Auster, No. 18-677, Western District of Louisiana) to proceed
first. In response to Defendants’ request for oral argument
in the Auster case, Judge Kay issued an electronic Order on October
18, 2018, denying that request and further stating, “The
issues have been thoroughly briefed and we do not find at this time
that oral argument would be helpful.” As noted above,
Magistrate Judge Kay previously recommended remand of these cases,
which recommendation was adopted by the District Judge then
assigned to the cases. Magistrate Judge Kay issued her Report and
Recommendations recommending remand based on the timeliness of the
second removal. Objections and replies were filed to the same and
the District Judge now assigned to the cases granted and held oral
argument on the objections to Magistrate Judge Kay’s Report
and Recommendations on January 16, 2019. The District Judge has not
yet ruled. It is impossible to predict at this time whether this
second removal will keep the cases in federal court. 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
consolidated financial statements.
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 and therefore, no
liability has been recorded on the Company’s consolidated
financial statements.
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 (Avanti) that would address
the rule for all through a test case. Exploration’s
case has been stayed pending adjudication of the test case. The
hearing for the Avanti test case was held on November 7, 2017, and
on December 6, 2017, the Board of Tax Appeals rendered judgment in
favor of the taxpayer in the first of these cases. The Department
of Revenue filed an appeal to this decision on January 5, 2018. The
Board of Tax Appeals case record has been lodged at the Louisiana
Third Circuit Court of Appeal in the Avanti test case. Oral
argument was held at the Third Circuit on Tuesday, February 26,
2019. On April 17, 2019, the Louisiana Third Circuit Court of
Appeal rendered a unanimous decision in the Avanti case affirming
the Board of Tax Appeals decision for the taxpayer. Currently, the
Louisiana Department of Revenue may seek a writ from the Louisiana
Supreme Court in the Avanti case. The Avanti case is not yet a
final decision. All other Board of Tax Appeals cases are stayed
pending the final decision in the Avanti case. 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 consolidated
financial statements.
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 aggregate amount of
approximately $500,000 is owed by the Company. The Company is
currently evaluating the merits of the claim, is reviewing the LDWF
analysis, and has now requested that the LDWF revise downward the
amount of area their claims of damages pertain to. At this point in
the regulatory 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
consolidated financial statements.
Miami Corporation – South Pecan Lake Field Area
P&A
The
Company, along with several other exploration and production
companies in the chain of title, received letters in June 2017 from
representatives of Miami Corporation demanding the performance of
well plugging and abandonment, facility removal and restoration
obligations for wells in the South Pecan Lake Field Area, Cameron
Parish, Louisiana. Apache is one of the other companies in the
chain of title, and after taking a field tour of the area, has sent
to the Company, along with BP and other companies in the chain of
title, a proposed work plan to comply with the Miami Corporation
demand. The Company is currently evaluating the merits of the claim
and awaiting further information. At this point in the 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 consolidated financial
statements.
John Hoffman v. Yuma Exploration & Production Company, Inc., et
al
This
lawsuit, filed on June 15, 2018 in Livingston Parish, Louisiana,
against the Company, Precision Drilling and Dynamic Offshore
relates to a slip and fall injury to Mr. Hoffman that occurred on
August 28, 2017. Mr. Hoffman was apparently an employee of a
subcontractor of a contractor performing services for the Company.
Precision has made demand for defense and indemnity against the
Company based on a contract entered into between the parties. The
defense and indemnity demand is being contested, primarily on the
grounds that the defense and indemnity obligation is barred by the
Louisiana Anti-Indemnity Act. The Company believes that its
contractor is responsible for injuries to employees of the
contractor or subcontractor and that their insurance coverage, or
insurance coverage maintained by the Company, should cover damages
awarded to Mr. Hoffman. The Company has notified its insurance
carrier of the lawsuit. Counsel believes that the claim will be
successfully defended, but even if the defense and indemnity claim
is legally enforceable, there is sufficient insurance in place to
cover the exposure. Accordingly, the defense and indemnity claim
does not represent any direct material exposure to the
Company.
Hall-Degravelles, L.L.C. v. Cockrell Oil Corporation, et
al
Avalon Plantation, Inc., et al v. Devon Energy Production Company,
L.P., et al
Avalon Plantation, Inc., et al v. American Midstream, et
al
The
Company, as a successor in interest from another company years ago,
along with 41 other companies in the chain of title, was named as a
defendant in these lawsuits brought in St. Mary Parish, Louisiana.
The substance of each of the petitions is virtually identical. In
each case, the plaintiff(s) are seeking to recover damages to their
property resulting from “oil and gas exploration and
production activities.” The cited grounds for these actions
include La. R.S. 30:29 (providing for restoration of property
affected by oilfield contamination) and C.C. art. 2688
(notification by the lessee to the lessor when leased property is
damaged). The plaintiffs have attempted to have these three cases
consolidated. A hearing on motion to consolidate was held on
January 15, 2019. At that time, Judge Sigur stated from the bench
that he did not have sufficient information to order consolidation.
A judgment to that effect has been signed by the judge. These cases
are in the very early stages. At this point, not all of the named
defendants have filed responsive pleadings. All of the defendants
who have responded at this point have, inter alia, filed exceptions
of vagueness due to the lack of specificity in the petitions which
makes it impossible to determine what action(s) any individual
defendant may have performed which would result in liability to the
plaintiffs. None of these exceptions are currently set for hearing.
The Company sold the leases that appear to be involved in this
litigation to Hilcorp Energy I, L.P., with an effective date of
September 1, 2016. The conveyance includes an indemnity provision
which appears to transfer liability for this type of damage to
Hilcorp, and at some point it will be necessary to invoke this
indemnity. The Company has notified its insurance carrier of the
claim but believes that the suit is without merit. No evaluation of
the likelihood of an unfavorable outcome or associated economic
loss can be made at this early stage, therefore no liability has
been recorded on the Company’s consolidated financial
statements.
Vintage Assets, Inc. v. Tennessee Gas Pipeline, L.L.C., et
al
On
September 10, 2018, the Company received a Demand for Defense and
Indemnity from High Point Gas Gathering, L.P. (HPGG) pursuant to
the 2010 Purchase and Sale Agreement between Texas Southeastern Gas
Gathering Company, et al and HPGG, et al. The demand related to a
judgment and permanent injunction entered against HPGG and three
other defendants on May 4, 2018 in the above referenced matter in
the U.S. District Court in the Eastern District of Louisiana. The
Company received a letter dated October 30, 2018 from HPGG
informing it that the May 4, 2018 judgment had been vacated. No
evaluation of the likelihood of an unfavorable outcome or
associated economic loss can be made at this early stage,
therefore, no liability has been recorded on Company’s
consolidated financial statements.
Texas General Land Office (“GLO”)
On
February 21, 2019, the GLO notified the Company that it would be
conducting an audit of oil and gas production and royalty revenue
for the period of September 2012 to August 2017 related to three of
the Company’s leases located in Chambers County, Texas and
four of the Company’s leases located in Jefferson County,
Texas. The exposure related to the audit is not currently
determinable and therefore, no liability has been recorded on the
Company’s consolidated financial statements.
Sam Banks v. Yuma Energy, Inc.
By
letter dated March 27, 2019, the Company’s Board of Directors
notified Sam L. Banks that it was terminating him as Chief
Executive Officer of the Company pursuant to the terms of his
amended and restated employment agreement dated April 20, 2017 (the
“Employment Agreement”). Mr. Banks has since resigned
from the board of directors of the Company. On March 28, 2019, Mr.
Banks filed a petition (the “Petition”) in the
189
th
Judicial District Court of Harris County, Texas, naming the Company
as defendant. The Petition alleges a breach of the Employment
Agreement and seeks severance benefits in the amount of
approximately $2.15 million. Counsel has engaged in early
settlement discussions with Plaintiff’s counsel, but at this
time, a settlement has not been reached. Counsel has filed an
answer in response to Mr. Banks’ lawsuit, and discovery is
proceeding. The Company intends to vigorously defend the lawsuit.
No evaluation of the likelihood of an unfavorable outcome or
associated economic loss can be made at this early stage;
therefore, no liability has been recorded on the Company’s
consolidated financial statements.
NOTE 16 – Subsequent Events
The
Company is not aware of any subsequent events which would require
recognition or disclosure in its consolidated financial statements,
except as noted below or disclosed in the Company’s filings
with the SEC.
An
Asset Purchase and Sale Agreement dated March 21, 2019, was
executed on behalf of Pyramid Oil, LLC and Yuma Energy, Inc. (the
“Sellers”) and an undisclosed buyer (the
“Buyer”) covering the sale of all of Seller’s
assets in Kern County, California. The sale closed on April 26,
2019. The Company received net proceeds of approximately $1.8
million. The effective date was April 1, 2019. As additional
consideration for the sale of the assets, if WTI Index for oil
equals or exceeds $65 in the six months following the closing and
maintains that average for twelve consecutive months, then the
buyer shall pay to the Company $250,000. A portion of the proceeds
were used for the repayment of borrowings under the credit facility
and the remainder for working capital.
As of
May 20, 2019, an additional 24,077 shares of restricted common
stock have been forfeited by employees who have left the
Company.