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EX-99.7 - UNAUDITED PRO FORMA - Yuma Energy, Inc. | yuma_ex997.htm |
EX-99.3 - UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS - Yuma Energy, Inc. | yuma_ex993.htm |
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 8-K/A
(Amendment No. 2)
CURRENT REPORT
Pursuant to Section 13 or 15(d) of the Securities Exchange Act
of 1934
Date of Report: October 26, 2016
(Date of earliest event reported)
Yuma Energy, Inc.
(Exact name of registrant as specified in its charter)
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DELAWARE
(State or other jurisdiction
of incorporation)
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0001672326
(Commission File Number)
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94-0787340
(IRS Employer Identification No.)
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1177 West Loop South, Suite 1825
Houston, Texas 77027
(Address of principal executive offices) (Zip Code)
(713) 968-7000
(Registrant’s telephone number, including area
code)
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(Former name or former address, if changed since last
report)
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Check the
appropriate box below if the Form 8-K filing is intended to
simultaneously satisfy the filing obligation of the registrant
under any of the following provisions:
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☐
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Written
communications pursuant to Rule 425 under the Securities Act
(17 CFR 230.425)
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☐
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Soliciting
material pursuant to Rule 14a-12 under the Exchange Act (17
CFR 240.14a-12)
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Pre-commencement
communications pursuant to Rule 14d-2(b) under the Exchange
Act (17 CFR 240.14d-2(b))
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Pre-commencement
communications pursuant to Rule 13e-4(c) under the Exchange
Act (17 CFR 240.13e-4(c))
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Explanatory Note
As
previously disclosed in its Current Report on Form 8-K filed on
November 1, 2016 and as amended by Amendment No. 1 filed on
November 3, 2016 (collectively, the “Prior 8-K”) with the Securities
and Exchange Commission (the “SEC”), on October 26, 2016, Yuma
Energy, Inc., a Delaware corporation (the “Company”), completed
the agreement and plan of merger and reorganization dated as
of February 10, 2016, and as amended on September 2, 2016 (the
“Merger
Agreement”), with Yuma Energy, Inc., a California
corporation (“Yuma
California”), Yuma Merger Subsidiary, Inc., a Delaware
corporation and wholly-owned subsidiary of the Company
(“Merger
Subsidiary”), and Davis Petroleum Acquisition Corp.
(“Davis”),
providing for the merger of Yuma California with and into the
Company (the “Reincorporation
Merger”) and the merger of Merger Subsidiary with and
into Davis (the “Merger”).
The
Company is filing this Amendment No. 2 (“Amendment No. 2”) to the Prior 8-K
to include (i) the unaudited consolidated financial statements of
Davis as of and for the nine months ended September 30, 2016 and
2015, (ii) the unaudited consolidated financial statements of Yuma
California for the three and nine months ended September 30, 2016
and 2015, incorporated by reference, and (iii) the pro forma
financial statements giving effect to the Merger. Further, the
Company has incorporated by reference into this Amendment No. 2 the
audited financial statements of Yuma California for the years ended
December 31, 2015, 2014 and 2013. Finally, the Company has
incorporated by reference to this Amendment No. 2 the audited
financial statements of Davis for the years ended December 31, 2015
and 2014. Except as set forth herein, this Amendment No. 2 does not
amend, modify or update the disclosure contained in the Prior
8-K.
Item 2.01. Completion of Acquisition or
Disposition of Assets.
On
February 10, 2016 and as amended on September 2, 2016 (the
“First
Amendment”), Yuma California, the Company, Merger
Subsidiary, and Davis entered into the Merger
Agreement pursuant to which (i) Yuma California would
merge with and into the Company (the “Reincorporation Merger”), the
separate corporate existence of Yuma California would cease and the
Company would be the successor or surviving corporation of the
Reincorporation Merger, and (ii) following the Reincorporation
Merger, Merger Subsidiary would merge with and into Davis (the
“Merger”), with
Davis being the successor or surviving corporation of the Merger
and a wholly owned subsidiary of the Company. The Reincorporation
Merger and the Merger were completed on October 26, 2016. The
Company issued press releases regarding the Reincorporation Merger
and the Merger, which are attached to this Current Report on Form
8-K as Exhibits 99.1 and 99.2, respectively.
Immediately prior
to the consummation of the Reincorporation Merger, each share of
Series A Preferred Stock was converted into 35 shares of Yuma
California Common Stock, which included any accrued and unpaid
dividends on the Series A Preferred Stock as of immediately prior
to the consummation of the Reincorporation Merger. The conversion
was approved by the shareholders of Yuma California.
As part
of the consummation of the Reincorporation Merger, a 1-for-20
reverse stock split was effected, whereby (i) each share of Yuma
California Common Stock was converted into one-twentieth of one
share of Common Stock; (ii) each option to acquire Yuma California
Common Stock granted pursuant to Yuma California 2006 Equity
Incentive Plan (the “2006
Plan”) and outstanding immediately prior to the
consummation of the Reincorporation Merger was automatically
converted into the right to receive one-twentieth of one share of
Common Stock for each share of Yuma California Common Stock subject
to such option, on the same terms and conditions applicable to the
option to purchase Common Stock, except that the exercise price of
such option was multiplied by twenty; (iii) each outstanding share
of restricted stock of Yuma California granted pursuant to the Yuma
California 2011 Stock Option Plan (the “2011 Plan”) or Yuma
California’s 2014 Long-Term Incentive Plan (the
“2014 Plan”) was
automatically converted into the right to receive one-twentieth of
one share of Common Stock, on the same terms applicable to such
restricted stock award; and (iv) each stock appreciation right
granted pursuant to the 2014 Plan outstanding immediately prior to
the consummation of the Reincorporation Merger, whether vested or
unvested, exercisable or unexercisable, was automatically converted
into the right to receive one-twentieth of one share of Common
Stock for each share of Yuma California Common Stock subject to
such stock appreciation right, on the same terms and conditions
applicable to the stock appreciation right, except that the
exercise price was multiplied by twenty.
Upon
consummation of the Merger, Davis became a wholly owned subsidiary
of the Company and holders of Davis common stock received, in
exchange for such shares of common stock approximately 61.1% or
approximately 7,455,000 shares of the outstanding shares of Common
Stock and the holders of Davis preferred stock received
approximately 1,754,000 shares of the Company’s Series D
Convertible Preferred Stock, $0.001 par value per share (the
“Series D Preferred
Stock”), with a liquidation preference of
approximately $19.4 million and a conversion rate of $11.0471176
per share as described in the Certificate of Designation of the
Series D Preferred Stock (the “Certificate of Designation”) filed
with the Delaware Secretary of State on October 26,
2016.
2
The
foregoing description of the Reincorporation Merger and the Merger
is only a summary, does not purport to be complete, and is
qualified in its entirety by reference to the Merger Agreement and
the First Amendment, included with the Prior 8-K as Exhibit 2.1 and
Exhibit 2.1(a), respectively, and incorporated herein by
reference.
The
foregoing description of the Certificate of Designation is only a
summary, does not purport to be complete, and is qualified in its
entirety by reference to the Certificate of Designation, included
with the Prior 8-K as Exhibit 3.3 and incorporated herein by
reference.
Immediately
following the consummation of the Merger, the Company had
approximately 12,201,000 shares of Common Stock issued and
outstanding. The Common Stock began trading on the NYSE MKT under
the symbol “YUMA” on October 27, 2016. Pursuant to Rule
12g-3(a) adopted under the Securities Exchange Act of 1934, as
amended (the “Exchange
Act”), Yuma became the successor issuer of the Company
and thereby assumed its obligations under Section 12(b) of the
Exchange Act.
MANAGEMENT’S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS OF
DAVIS
The
following discussion should be read in conjunction with the
consolidated financial statements of Davis and the notes thereto
included elsewhere in this Current Report on Form 8-K. The
discussion includes certain forward-looking statements. For a
discussion of important factors which could cause actual results to
differ materially from the results referred to in the
forward-looking statements, see “Risk Factors – Risks
Relating to Davis’ Business” and “Cautionary Note
Regarding Forward-Looking Statements” in Yuma
California’s and Davis’ definitive proxy
statement/prospectus (the “Proxy Statement/Prospectus”),
included in the Company’s registration statement on Form S-4,
as amended (the “Form
S-4”), which Form S-4 was declared effective by the
SEC on September 22, 2016.
Overview
Davis’
financial results depend upon many factors, but are largely driven
by the volume of its oil and gas production and the price that it
receives for that production. Generally, producing oil
and gas properties begin their productive life at initial oil and
gas production rates that decline over time based on reservoir
characteristics, although operators may employ certain procedures
to enhance production. Davis’ various producing
properties have different reservoir characteristics that may be
expected to result in different levels of future production and
different rates of future decline. As reserves are produced
and sold, Davis must locate and develop, or acquire, new oil and
natural gas reserves to replace those being depleted by
production.
Davis’ Lac
Blanc field is a deep, high-pressure, conventional, South Louisiana
development with good-to-excellent reservoir quality.
Production is primarily natural gas from relatively high porosity
and permeability formations through a pressure-depletion drive
mechanism which allows relatively few boreholes to drain large
volumes. Davis has experienced moderate but relatively steady
decline rates at Lac Blanc over the life of the field to date and
Davis anticipates the continuation of such declines.
The
Chalktown field is an oily, tight-sand, Southeast Texas resource
play developed using horizontal wells and multi-stage hydraulic
fracturing. Well performance is characterized by high initial
production rates followed by the relatively steep production
decline rates. An aggressive drilling program is required to
maintain the field production rate because of the
characteristically high rate of production decline.
Davis’
Cameron Canal field is a conventional, South Louisiana field with
good-to-excellent reservoir quality that produces both oil and gas,
but it is not as deep as the Lac Blanc field and reservoir volumes
are not anticipated to be as large as some of those in the Lac
Blanc field. Davis anticipates moderate but steady
decline rates in the Cameron Canal field.
3
Critical Accounting Policies and Estimates
Oil and Gas Reserves
Davis’
engineering estimates of proved oil and natural gas reserves
directly impact financial accounting estimates, including DD&A
and the full cost ceiling limitation.
Davis’
estimates of proved oil and gas reserves constitute those
quantities of oil and gas, which, by analysis of geoscience and
engineering data, can be estimated with reasonable certainty to be
economically producible from a given date forward, from known
reservoirs, and under existing economic conditions, operating
methods, and government regulations prior to the time at which
contracts providing the right to operate expire, unless evidence
indicates that renewal is reasonably certain, regardless of whether
deterministic or probabilistic methods are used for the estimation.
At the end of each year, Davis’ proved reserves are estimated
by independent petroleum engineers. These estimates, however,
represent projections based on geologic and engineering data.
Reserve engineering is a subjective process of estimating
underground accumulations of oil and gas that are difficult to
measure. The accuracy of any reserve estimate is a function of the
quantity and quality of available data, engineering and geological
interpretation and professional judgment. Estimates of economically
recoverable oil and gas reserves and future net cash flows
necessarily depend upon a number of variable factors and
assumptions, such as historical production from the area compared
with production from other producing areas, the assumed effect of
regulations by governmental agencies, and assumptions governing
future oil and gas prices, future operating costs, severance taxes,
development costs and workover costs. The future drilling costs
associated with reserves assigned to proved undeveloped locations
may ultimately increase to the extent that these reserves may be
later determined to be uneconomical.
Davis
reports the value of its proved
oil and natural gas reserves under both the standardized measure of
discounted future net cash flows and under a non-GAAP financial
measure known as PV-10 which reflect the estimated value of future
net cash flows from such reserves under certain oil and gas
commodities prices. Davis accounts for its oil and gas producing
activities using the full cost method of accounting. Accordingly,
the value of Davis’ oil and gas properties on its financial
statements reflects the historical cost of finding and developing
proved reserves, net of accumulated depreciation, depletion and
amortization and related deferred taxes, not the value of such
reserves or their associated net cash flows. The carrying value of
Davis’ oil and gas properties on its consolidated financial
statements is limited, however, to the full cost ceiling (described
below), which is the deemed value of such properties based on
estimated future net cash flows assuming certain future oil and gas
commodities prices. Any significant inaccuracy in the assumptions
affecting the estimated quantity and value of the reserves and/or
the rate of depletion of such oil and gas properties could affect
the carrying value of Davis’ oil and gas
properties.
Oil and Gas Properties
Davis
accounts for its oil and gas producing activities using the full
cost method of accounting as prescribed by the SEC.
Accordingly, all costs incurred in the acquisition, exploration,
and development of proved oil and gas properties, including the
costs of abandoned properties, dry holes, geophysical costs, and
annual lease rentals, are capitalized. Internal costs that
are directly related to finding and developing oil and gas
properties are also capitalized. All general corporate costs
are expensed as incurred. Sales or other dispositions of oil
and gas properties are accounted for as adjustments to capitalized
costs with no gain or loss recorded unless the relationship of cost
to proved reserves would significantly change. Depletion of
evaluated oil and gas properties is computed on the
units-of-production method based on proved reserves. The net
capitalized costs of proved oil and gas properties are subject to a
quarterly full cost ceiling limitation in which the costs are not
allowed to exceed their related estimated future net revenues using
the twelve-month average of the first-day-of-the-month reference
prices as adjusted for location and quality differentials and
discounted at 10%, net of tax considerations. Costs
associated with unevaluated properties are excluded from the full
cost pool until a determination is made as to whether proved
reserves can be attributed to the related properties.
Unevaluated properties are evaluated periodically to determine
whether the costs incurred should be reclassified to the full cost
pool and thereby subject to amortization.
Capitalized costs
of oil and gas properties, net of accumulated depreciation,
depletion and amortization and related deferred taxes, are limited
to the estimated future net cash flows from proved oil and gas
reserves, discounted at 10%, plus the lower of cost or fair value
of unproved properties, as adjusted for related income tax effects
(the full cost ceiling). If capitalized costs exceed the full cost
ceiling, the excess is charged to write-down of oil and gas
properties in the quarter in which the excess occurs.
4
Given
the volatility of oil and gas prices, it is probable that
Davis’ estimate of discounted future net cash flows from
estimated proved oil and gas reserves will change in the near term.
If oil or gas prices decline further, even for only a short period
of time, or if Davis has downward revisions to its estimated
volumes of proved reserves, it is possible that further write-downs
of oil and gas properties could occur.
Asset Retirement Obligations
Davis
records a liability equal to the fair value of the estimated cost
to retire an asset. The asset retirement obligation
(“ARO”)
liability is recorded in the period in which the obligation meets
the definition of a liability. When an ARO liability is
recorded, Davis increases the carrying amount of the related
long-lived asset by an amount equal to the original
liability. The liability is then accreted to its expected
value each period, and the capitalized cost is depreciated over the
useful life of the long-lived asset. Any difference between
costs incurred upon settlement of an asset retirement obligation
and the recorded liability is recognized as an increase or decrease
to proved properties, similar to how Davis recognizes gains and
losses on divested oil and gas properties. The ARO is based
on a number of assumptions requiring judgment. Davis cannot
predict the type of revisions to these assumptions that will be
required in future periods or the availability of additional
information, including prices for oil field services, technological
changes, governmental requirements, and other factors.
Deferred Taxes
Deferred income
taxes are provided to reflect the tax consequences in future years
of differences between the financial statement and tax bases of
assets and liabilities. A valuation allowance is established to
reduce deferred tax assets if it is more likely-than-not that the
related tax benefits will not be realized.
Commodity Hedging Contracts and Other Derivatives
Davis
periodically enters into derivative contracts to hedge future crude
oil and natural gas production in order to mitigate the risk of
market price fluctuations. All derivatives are recognized on
the balance sheet and measured at fair value. Davis does not
designate its derivative contracts as hedges, as defined in ASC
815, Derivatives and
Hedging, and accordingly, recognizes changes in fair value,
both realized and unrealized, as (gains) loss on derivative
instruments in its income statement. Cash flows are only impacted
to the extent the actual settlements under the contracts result in
Davis making a payment to or receiving a payment from the
counterparty.
Davis
uses a variety of derivative instruments, such as swaps, collars,
puts, calls and various combinations of these instruments, which
may be utilized to manage exposure to the volatility of oil and gas
commodity prices. Currently, Davis does not use derivatives to
manage its exposure to fluctuations in interest rates.
The
derivatives instruments Davis has in place are not classified as
hedges for accounting purposes. These derivative contracts are
reflected at fair value on Davis’ balance sheet and are
marked-to-market each quarter with fair value gains and losses,
both realized and unrealized, recognized currently as a gain or
loss on mark-to-market derivative contracts on the income
statement. Consequently, Davis expects continued volatility in its
reported earnings as changes occur in the NYMEX index. Cash flow is
only impacted to the extent the actual settlements under the
contracts result in making or receiving a payment from the
counterparty.
The
estimation of fair values of derivative instruments requires
substantial judgment. Valuation calculations incorporate estimates
of future NYMEX prices, discount rates and price movements. As a
result, Davis calculates the fair value of its commodity
derivatives using an independent third-party’s valuation
model that utilizes market-corroborated inputs that are observable
over the term of the derivative contract. Davis’ fair value
calculations also incorporate an estimate of the
counterparties’ default risk for derivative assets and an
estimate of its default risk for derivative liabilities. Davis also
uses third-party valuations to determine the fair values of the
contracts that are reflected on its consolidated balance sheets.
Realized and unrealized gains and losses are also included in
income (expense) on its consolidated statements of
operations.
Results of Operations for the Three and Nine Months Ended September
30, 2016 and 2015
Davis’
results of operations are significantly affected by fluctuations in
oil and gas prices. The following table reflects Davis’
production and average prices for crude oil, natural gas and
natural gas liquids. These historical results are not necessarily
indicative of results to be expected in future
periods.
5
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Three Months
Ended September 30,
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Nine Months
Ended September 30,
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2016
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2015
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2016
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2015
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Production
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Oil -
Bbls
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32,242
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47,452
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106,257
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178,470
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NGL -
Bbls
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23,903
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35,894
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74,282
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101,951
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Natural Gas -
Mcf
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507,521
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635,996
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1,553,906
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2,053,827
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Total
BOE
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140,732
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189,345
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439,523
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622,726
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Total -
Mcfe
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844,391
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1,136,072
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2,637,140
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3,736,353
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Revenue
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Oil
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$1,400,837
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$2,233,659
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$4,172,477
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$8,875,276
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NGL
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398,264
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386,811
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1,111,402
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1,907,523
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Natural
Gas
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1,249,148
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1,705,874
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3,295,258
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5,744,057
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Total
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$3,048,249
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$4,326,344
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$8,579,137
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$16,526,856
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Average Sales
Price
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Oil – per
Bbl
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$43.45
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$47.07
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$39.27
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$49.73
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NGL – per
Bbl
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$16.66
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$10.78
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$14.96
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$18.71
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Natural Gas –
per Mcf
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$2.46
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$2.68
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$2.12
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$2.80
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Total – per
BOE
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$21.66
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$22.85
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$19.52
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$26.54
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Total – per
Mcfe
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$3.61
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$3.81
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$3.25
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$4.42
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(1)
Thousand cubic feet
equivalent on the basis of one barrel of oil or natural gas liquids
equal to six thousand cubic feet (Mcf) of natural gas.
(2)
Barrels of oil
equivalent have been calculated on the basis of six thousand cubic
feet (Mcf) of natural gas equal to one barrel of oil
equivalent.
Comparison of Results of Operations for the Three and Nine Months
Ended September 30, 2016 and 2015
For the
three months ended September 30, 2016, Davis had a net loss of
$(1.9 million), or $(0.01) per diluted share compared to a net loss
of $(0.5 million), or $(0.00) per diluted share in the same period
of 2015.
Davis
had a net loss of $(28.0 million), or $(0.19) per diluted share for
the nine months ended September 30, 2016 compared to a net loss of
$(7.9 million), or $(0.05) per diluted share for the same period in
2015. The 2016 net loss was impacted by impairments of oil and gas
properties (ceiling test write-downs) in the amount of $17.6
million in the first nine months of 2016 compared with write-downs
of $3.7 million for the same period in 2015.
Revenue
Oil and
gas revenue for the three months ended September 30, 2016 was $3.0
million compared to $4.3 million for the same period in
2015. Davis’ realized oil price of $43.45 per Bbl
for the three months ended September 30, 2016 was a 7.7% decrease
from the $47.07 per Bbl realized for the three months ended
September 30, 2015. Production was 140,732 Boe for the
three months ended September 30, 2016 compared to 189,345 Boe for
the same period in 2015. Total production decreased
primarily as a result of normal production declines (45,251 Boe),
sold and abandoned wells (2,439 Boe) and a well shut-in for
recompletion (28,289 Boe) and was partially offset by 27,366 Boe of
production from the recently completed E.E. Broussard #1 ST2 well
in the Cameron Canal field.
Oil and
gas revenue for the nine months ended September 30, 2016 was $8.6
million compared to $16.5 million for the same period in
2015. Davis’ realized oil price of $39.27 per Bbl
for the nine months ended September 30, 2016 was a 21.0% decrease
from $49.73 per Bbl realized for the nine months ended September
30, 2015. Production of 439,523 Boe for the nine months
ended September 30, 2016 compared to 622,726 Boe for the nine
months ended September 30, 2015. Total production
decreased primarily as a result of normal production declines
(126,485 Boe), sold and abandoned wells (38,358 Boe) and a well
shut-in for recompletion (95,243 Boe) and was partially offset by
76,883 Boe of production from the recently completed E.E. Broussard
#1 ST2 well in the Cameron Canal field.
6
Prices
The
average realized natural gas price per Mcf for the three months
ended September 30, 2016 was $2.46 compared to $2.68 for the same
period of 2015. Average realized oil price per Bbl for the three
months ended September 30, 2016 was $43.45 compared to $47.07 for
the same period of 2015, and the average realized natural gas
liquids price per Bbl was $16.66 for the three months ended
September 30, 2016 compared to $10.78 for the same period of 2015.
Stated on a Boe basis, unit prices received during 2016 were 5.2%
lower than the prices received during 2015.
The
average realized natural gas price per Mcf for the nine months
ended September 30, 2016 was $2.12 compared to $2.80 for the same
period of 2015. Average realized oil price per Bbl for the nine
months ended September 30, 2016 was $39.27 compared to $49.73 for
the same period of 2015, and the average realized natural gas
liquids price per Bbl was $14.96 for the nine months ended
September 30, 2016 compared to $18.71 for the same period of 2015.
Stated on a Boe basis, unit prices received during 2016 were 26.5%
lower than the prices received during 2015.
Lease Operating Expenses
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Three Months
Ended September 30,
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Nine Months
Ended September 30,
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($ in thousands, except per Boe
amounts)
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2016
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2015
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2016
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2015
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Lease operating
expenses
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$1,034
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$1,330
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$2,682
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$4,822
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Production
taxes
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189
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260
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588
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970
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Total
LOE
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$1,223
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$1,590
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$3,270
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$5,792
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LOE per
BOE
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$8.69
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$8.40
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$7.44
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$9.30
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LOE per BOE without
production taxes
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$7.35
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$7.02
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$6.10
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$7.74
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Lease
operating expenses and production taxes decreased 23.1% to $1,223
thousand in the three months ended September 2016 from $1,590
thousand in the same period of 2015 primarily due to the cost
savings associated with de-manning the Lac Blanc platform ($95
thousand), sold and abandoned wells ($31 thousand), as well as
normal production declines ($170 thousand). The decrease in total
production taxes was primarily due to lower commodity
prices.
For the
nine months ended September 30, 2016, lease operating expenses and
production taxes decreased 44% from the same period in 2015
primarily due to the cost savings associated with de-manning the
Lac Blanc platform ($498 thousand), sold and abandoned wells
($1,284 thousand), as well as normal production declines ($358
thousand). The decrease in total production taxes was primarily due
to lower commodity prices. The majority of Davis’ properties
that are subject to severance taxes are assessed on the oil and gas
sales value.
General and Administrative Expenses
|
Three Months
Ended September 30,
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Nine Months
Ended September 30,
|
||
($ in thousands)
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2016
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2015
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2016
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2015
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General and
administrative:
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Stock-based
compensation
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$380
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$188
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$3,381
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$745
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Capitalized
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-
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-
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(1,716)
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-
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Net stock-based
compensation
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380
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188
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1,665
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745
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|
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Other
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2,218
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1,694
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10,090
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7,197
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Capitalized
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(480)
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(426)
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(1,795)
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(1,416)
|
Net
other
|
1,738
|
1,268
|
8,295
|
5,781
|
Net general and
administrative expenses
|
$2,118
|
$1,456
|
$9,960
|
$6,526
|
7
General
and administrative expenses were $2.1 million for the three months
ended September 30, 2016 compared to $1.5 million for the same
period of 2015. Included in general and administrative expenses for
2016 were severance expenses of $0.4 million, merger-related costs
of $0.5 million, and share-based compensation costs, net of amounts
capitalized, of $0.4 million, compared to $0.2 million in
2015.
General
and administrative expenses were $10.0 million for the nine months
ended September 30, 2016 compared to $6.5 million in the same
period of 2015. Included in general and administrative expenses for
2016 were severance expenses of $3.9 million, merger-related costs
of $1.5 million, share-based compensation costs, net of amounts
capitalized of $1.7 million, compared to $0.8 million in 2015.
Davis capitalized $3.3 million of its general and administrative
costs during 2016 compared to $1.0 million in 2015. Davis expects
ongoing general and administrative expenses to decrease further in
2016 as a result of termination of employment of all non-essential
personnel in anticipation of the merger.
Depreciation, Depletion and Amortization
|
Three Months
Ended September 30,
|
Nine Months
Ended September 30,
|
||
|
2016
|
2015
|
2016
|
2015
|
($ in
thousands, except DD&A per BOE)
|
|
|
|
|
Production -
BOE
|
140,732
|
189,345
|
439,523
|
622,726
|
Depreciation,
depletion, and amortization
|
$1,525
|
$4,051
|
$5,356
|
$14,386
|
DD&A per
BOE
|
$10.84
|
$21.39
|
$12.19
|
$23.10
|
Depreciation,
depletion and amortization (“DD&A”) expenses for the three
months ended September 30, 2016 totaled $1.5 million, or $10.84 per
Boe compared to $4.1 million, or $21.39 per Boe, during the same
period of 2015. DD&A expenses for the nine months ended
September 30, 2016 totaled $5.4 million, or $12.19 per Boe compared
to $14.4 million, or $23.10 per Boe, during the same period
for the
nine months ended September 30 for both2015. The decrease
in the per unit DD&A rate was primarily the result of ceiling
test write-downs for the nine months ended September 30 in both
2015 ($3.7 million) and 2016 ($17.6 million).
At
September 30, 2016, the prices used in computing the estimated
future net cash flows from Davis’ estimated proved reserves
averaged $2.31 per Mcf of natural gas with respect to Louisiana and
Gulf of Mexico properties, $2.30 per Mcf of natural gas with
respect to with respect to Texas properties and $41.97 per barrel
of oil and natural gas liquids, in each case adjusted by field for
quality, transportation fees and market differentials. As a result
of lower average commodity prices and their negative impact on
Davis’ estimated proved reserves and estimated future net
cash flows, Davis recognized a ceiling test write-down of
approximately $17.6 million in the nine-month period of 2016 and
$3.7 million in the same period of 2015.
Interest Expense
Interest expense
decreased 53% to $81 thousand during the three months ended
September 30, 2016 from $172 thousand during the same period of
2015. Interest expense totaled $195 thousand during the nine months
ended September 30, 2016 compared to $478 thousand in the same
period of 2015. The decrease in 2016 was due to lower amounts
outstanding under Davis’ senior bank credit
facility.
Income Tax Expense
Income
tax expense during the nine months ended September 30, 2016,
totaled $7 thousand compared to an income tax benefit of $4.2
million during 2015. Davis typically provides for income taxes at a
statutory rate of 35% adjusted for permanent differences expected
to be realized, primarily statutory depletion, non-deductible stock
compensation expenses and state income taxes.
8
At
September 30, 2016, the effective tax rate of 0.02% is less than
the statutory tax rate of 35% because Davis has recorded a full
valuation allowance against its federal and Louisiana net deferred
tax assets. The income tax expense of $7 thousand is related to
Texas deferred taxes.
Liquidity and Capital Resources
Davis’
principal requirements for cash, other than working capital needs
for existing operations, are costs of development of oil and gas
properties, retirement of debt and the acquisition of oil and gas
properties. Davis has historically funded its development program,
debt repayments and acquisitions with cash flow from operations,
bank financing, property divestitures and joint ventures with
industry partners. Davis believes its liquidity and capital
resources are sufficient to meet its obligations.
Cash Flow
|
Nine Months
Ended September 30,
|
|
($ in thousands)
|
2016
|
2015
|
Net cash provided
by (used in) operating activities
|
$(908)
|
$10,360
|
Net cash used in
investing activities
|
$(8,578)
|
$(15,431)
|
Net cash provided
by (used in) financing activities
|
$8,591
|
$(1,210)
|
Credit Facility
Davis’ senior
bank credit facility provides for secured senior revolving credit
availability of up to $9.0 million as of July 1, 2016 from a bank
group led by Bank of America, N.A., subject to compliance with
financial and other covenants. In January 2013, the
termination date of the senior bank credit facility was extended to
January 4, 2016, in July 2015, the termination date of the senior
bank credit facility was extended to July 6, 2016, and on July 1,
2016, the termination date of the senior bank credit facility was
extended to September 30, 2016. On September 26, 2016, Davis
completed the Sixth Amendment, which extended the maturity date to
November 15, 2016. Davis’ obligations under its senior
bank credit facility are secured by a security interest in
substantially all of its oil and gas properties. At September 30,
2016, Davis had $9.0 million of borrowings under its senior bank
credit facility.
Nine Months Ended September 30, 2016 Compared to the Nine Months
Ended September 30, 2015
In
2016, cash used in investing activities included $9.9 million of
capital expenditures, a majority of which were related to the
drilling of the E.E. Broussard #1 ST2 in the Cameron Canal field
which began production in April 2016. These expenditures were
partially offset by Davis’ receipt of $1.3 million of
derivative settlements. In 2015, cash used in investing activities
included $23.0 million of capital expenditures partially offset by
Davis’ receipt of $7.3 million of derivative
settlements.
Net
cash provided by financing activities in 2016 consisted of
borrowings under the revolving credit facility of $9.0 million. Net
cash used in financing activities in 2015 consisted of borrowings
under the revolving credit facility of $10.0 million offset by
repayments under the revolving credit facility of $11.0
million.
Davis
has financed its acquisition, exploration and development
activities to date principally through cash flow from operations,
bank borrowings and sales of assets. As of September 30, 2016,
Davis had approximately $3.2 million of cash on hand and had $9.0
million outstanding under its senior bank credit facility. At such
date, Davis had no availability under its senior bank credit
facility, subject to compliance with the financial covenants
thereunder.
Prices
for oil and natural gas are subject to many factors beyond
Davis’ control, such as weather, the overall condition of the
global financial markets and economies, relatively minor changes in
the outlook of supply and demand, and the actions of OPEC. Oil and
natural gas prices have a significant impact on Davis’ cash
flows available for capital expenditures and its ability to borrow
and raise additional capital. The amount Davis can borrow under its
senior bank credit facility is subject to periodic re-determination
based in part on changing expectations of future prices. Lower
prices may also reduce the amount of oil and natural gas that Davis
can economically produce. Lower prices and/or lower production may
decrease revenues, cash flows and the borrowing base under the
senior bank credit facility, thus reducing the amount of financial
resources available to meet Davis’ capital requirements.
Davis’ ability to comply with the covenants in its debt
agreements is dependent upon the success of its exploration and
development program and upon factors beyond its control, such as
oil and natural gas prices.
9
Davis
periodically seeks to reduce its exposure to commodity price
volatility by hedging a portion of production through commodity
derivative instruments.
The
level of derivative activity Davis engages in depends on its view
of market conditions, available derivative prices and operating
strategy. A variety of derivative instruments, such as swaps,
collars, puts, calls and various combinations of these instruments,
may be utilized to manage exposure to the volatility of oil and gas
commodity prices.
When
engaging in oil and gas commodities swaps, Davis is required to pay
the difference between the floating price and the fixed price (when
the floating price exceeds the fixed price) regardless of whether
Davis has sufficient production to cover the quantities specified
in the hedge. Significant reductions in production at times when
the floating price exceeds the fixed price could require Davis to
make payments under certain hedge agreements even though such
payments are not offset by sales of production. Hedging may also
prevent Davis from receiving the full advantage of increases in oil
or gas prices above the fixed amount specified in the
hedge.
As of
September 30, 2016, Davis had entered into the following
contracts:
Production
Period
|
Instrument
Type
|
Daily
Volumes
|
Weighted Average
Price
|
Natural
Gas:
|
|
|
|
2016
|
Natural Gas
Swap
|
3,000
MMBtu
|
$4.05
|
|
|
||
Crude
Oil:
|
|
|
|
October 2016
– December 2016
|
Three-Way
Collar
|
400
Bbls
|
$30.00 – 40.00 –
50.00
|
A
“Three-Way Collar” combines a sold put, a purchased put
and a sold call. The purchased put and sold put establish a
floating minimum price and the sold call establishes a maximum
price Davis will receive for the volumes under
contract.
The
fair market value of Davis’ commodity derivative contracts in
place at September 30, 2016 and 2015, were $0.2 million and $3.6
million, respectively.
Item
9.01.
Financial
Statements and Exhibits
(a)
Financial Statements of Business
Acquired.
The
unaudited consolidated financial statements of Davis as of and for
the nine months ended September 30, 2016 and 2015 are
attached hereto as Exhibit 99.3 and incorporated herein by
reference. The audited consolidated financial statements of Davis
for the years ended December 31, 2015 and 2014 are attached hereto
as Exhibit 99.4 and incorporated herein by reference.
The
unaudited consolidated financial statements of Yuma California as
of and for the three and nine months ended September 30,
2016 and 2015 are attached hereto as Exhibit 99.5 and incorporated
herein by reference. The audited consolidated financial statements
of Yuma California for the years ended December 31, 2015, 2014 and
2013 are attached hereto as Exhibit 99.6 and incorporated herein by
reference.
(b)
Pro Forma Financial
Information.
The
unaudited pro forma condensed consolidated combined balance sheet
of the Company as of September 30, 2016 and the unaudited pro forma
condensed consolidated combined statements of operations for the
twelve months ended December 31, 2015 and the nine months ended
September 30, 2016 are attached hereto as Exhibit 99.7 and are
incorporated herein by reference. These unaudited pro forma
financial statements give effect to the Merger on October 26, 2016,
on the basis, and subject to the assumptions, set forth in
accordance with Article 11 of Regulation S-X.
(d)
Exhibits.
The
following exhibits are included with this Amendment No. 2 to the
Current Report on Form 8-K/A:
10
Exhibit
No.
|
|
Description
|
|
|
|
|
|
|
Unaudited
consolidated financial statements of Davis Petroleum Acquisition
Corp. as of and for the nine months ended September 30, 2016
and 2015.
|
||
|
|
|
|
99.4
|
|
Audited
consolidated financial statements of Davis Petroleum Acquisition
Corp. for the years ended December 31, 2015 and 2014 (incorporated by reference from the
Registrant’s Registration Statement on Form S-4 (Commission
File No. 333-212103) declared effective on September 22,
2016).
|
|
|
|
|
|
99.5
|
|
Unaudited
consolidated financial statements of Yuma Energy, Inc., a
California corporation, as of and for the three and nine
months ended September 30, 2016 and 2015 (incorporated by
reference from the Quarterly Report on Form 10-Q of Yuma Energy,
Inc. (File No.: 001-32989) filed with the SEC on November 14,
2016).
|
|
|
|
|
|
99.6
|
|
Audited
consolidated financial statements of Yuma Energy, Inc., a
California corporation, for the years ended December 31, 2015, 2014
and 2013 (incorporated by reference from the Registrant’s
Registration Statement on Form S-4 (Commission File No. 333-212103)
declared effective on September 22, 2016).
|
|
|
|
|
|
|
Unaudited
pro forma condensed consolidated combined balance sheet of Yuma
Energy, Inc., a Delaware corporation, as of September 30, 2016, and
unaudited pro forma condensed consolidated combined statements of
operations of Yuma Energy, Inc. for the twelve months ended
December 31, 2015 and the nine months ended September 30,
2016.
|
11
SIGNATURE
Pursuant to the
requirements of the Securities Exchange Act of 1934, the registrant
has duly caused this report to be signed on its behalf by the
undersigned hereunto duly authorized.
|
|
|
|
|
|
|
YUMA ENERGY, INC.
|
|
|
|
|
|
|
|
|
|
By:
|
/s/ Sam
L. Banks
|
|
|
|
Name:
|
Sam L.
Banks
|
|
Date:
January 9, 2017
|
|
Title:
|
President
and Chief Executive Officer
|
|
12
EXHIBIT
INDEX
Exhibit
No.
|
|
Description
|
|
|
|
|
|
|
Unaudited
consolidated financial statements of Davis Petroleum Acquisition
Corp. as of and for the nine months ended September 30, 2016
and 2015.
|
||
|
|
|
|
99.4
|
|
Audited
consolidated financial statements of Davis Petroleum Acquisition
Corp. for the years ended December 31, 2015 and 2014 (incorporated by reference from the
Registrant’s Registration Statement on Form S-4 (Commission
File No. 333-212103) declared effective on September 22,
2016).
|
|
|
|
|
|
99.5
|
|
Unaudited
consolidated financial statements of Yuma Energy, Inc., a
California corporation, as of and for the three and nine
months ended September 30, 2016 and 2015 (incorporated by
reference from the Quarterly Report on Form 10-Q of Yuma Energy,
Inc. (File No.: 001-32989) filed with the SEC on November 14,
2016).
|
|
|
|
|
|
99.6
|
|
Audited
consolidated financial statements of Yuma Energy, Inc., a
California corporation, for the years ended December 31, 2015, 2014
and 2013 (incorporated by reference from the Registrant’s
Registration Statement on Form S-4 (Commission File No. 333-212103)
declared effective on September 22, 2016).
|
|
|
|
|
|
|
Unaudited
pro forma condensed consolidated combined balance sheet of Yuma
Energy, Inc., a Delaware corporation, as of September 30, 2016, and
unaudited pro forma condensed consolidated combined statements of
operations of Yuma Energy, Inc. for the twelve months ended
December 31, 2015 and the nine months ended September 30,
2016.
|
13