Yuma Energy, Inc. (NYSEMKT:PDO) Files An 8-K Completion of Acquisition or Disposition of Assets
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 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.
First Amendment), Yuma California, the Company, Merger
Subsidiary, and Davis entered into the Merger Agreement 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.
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 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 to the Yuma California 2011 Stock Option Plan
(the 2011 Plan) or Yuma Californias 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 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.
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 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 to the Yuma California 2011 Stock Option Plan
(the 2011 Plan) or Yuma Californias 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 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
Companys 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.
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
Companys 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.
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.
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.
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. 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.
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. 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.
MANAGEMENTS 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 Californias and Davis definitive proxy
statement/prospectus (the Proxy Statement/Prospectus), included
in the Companys 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.
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 Californias and Davis definitive proxy
statement/prospectus (the Proxy Statement/Prospectus), included
in the Companys 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.
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.
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.
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.
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.
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 DDA and the full cost ceiling limitation.
reserves directly impact financial accounting estimates,
including DDA 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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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-partys 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.
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-partys 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
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.
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.
|
Three Months Ended September 30,
|
Nine Months Ended September 30,
|
|||
|
Production
|
||||
|
Oil – Bbls
|
32,242
|
47,452
|
106,257
|
178,470
|
|
NGL – Bbls
|
23,903
|
35,894
|
74,282
|
101,951
|
|
Natural Gas – Mcf
|
507,521
|
635,996
|
1,553,906
|
2,053,827
|
|
Total BOE
|
140,732
|
189,345
|
439,523
|
622,726
|
|
Total – Mcfe
|
844,391
|
1,136,072
|
2,637,140
|
3,736,353
|
|
Revenue
|
||||
|
Oil
|
$1,400,837
|
$2,233,659
|
$4,172,477
|
$8,875,276
|
|
NGL
|
398,264
|
386,811
|
1,111,402
|
1,907,523
|
|
Natural Gas
|
1,249,148
|
1,705,874
|
3,295,258
|
5,744,057
|
|
Total
|
$3,048,249
|
$4,326,344
|
$8,579,137
|
$16,526,856
|
|
Average Sales Price
|
||||
|
Oil per Bbl
|
$43.45
|
$47.07
|
$39.27
|
$49.73
|
|
NGL per Bbl
|
$16.66
|
$10.78
|
$14.96
|
$18.71
|
|
Natural Gas per Mcf
|
$2.46
|
$2.68
|
$2.12
|
$2.80
|
|
Total per BOE
|
$21.66
|
$22.85
|
$19.52
|
$26.54
|
|
Total per Mcfe
|
$3.61
|
$3.81
|
$3.25
|
$4.42
|
(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.
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.
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
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.
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.
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.
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.
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.
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.
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.
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 $18.71 for the
same period of 2015. Stated on a Boe basis, unit prices
received during 2016 were 26.5% lower than the prices
received during 2015.
Lease Operating Expenses
|
Three Months Ended September 30,
|
Nine Months Ended September 30,
|
|||
|
($ in thousands, except per Boe amounts)
|
||||
|
Lease operating expenses
|
$1,034
|
$1,330
|
$2,682
|
$4,822
|
|
Production taxes
|
||||
|
Total LOE
|
$1,223
|
$1,590
|
$3,270
|
$5,792
|
|
LOE per BOE
|
$8.69
|
$8.40
|
$7.44
|
$9.30
|
|
LOE per BOE without production taxes
|
$7.35
|
$7.02
|
$6.10
|
$7.74
|
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.
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.
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 ($358 thousand). The decrease in total
production taxes was primarily due to lower commodity
prices. The majority of Davis properties that are
subject to severance taxes are assessed on the oil and
gas sales value.
General and Administrative Expenses
|
Three Months Ended September 30,
|
Nine Months Ended September 30,
|
|||
|
($ in thousands)
|
||||
|
General and administrative:
|
||||
|
Stock-based compensation
|
$380
|
$188
|
$3,381
|
$745
|
|
Capitalized
|
–
|
–
|
(1,716)
|
–
|
|
Net stock-based compensation
|
1,665
|
|||
|
Other
|
2,218
|
1,694
|
10,090
|
7,197
|
|
Capitalized
|
(480)
|
(426)
|
(1,795)
|
(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
|
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.
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.
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 $1.0
million in 2015. Davis expects ongoing general and
administrative expenses to decrease further in 2016
as a result of termination of employment of all
non-essential personnel in anticipation of the
merger.
Depreciation, Depletion and Amortization
|
Three Months Ended September 30,
|
Nine Months Ended September 30,
|
|||
|
($ in thousands, except DDA per BOE)
|
||||
|
Production – BOE
|
140,732
|
189,345
|
439,523
|
622,726
|
|
Depreciation, depletion, and amortization
|
$1,525
|
$4,051
|
$5,356
|
$14,386
|
|
DDA per BOE
|
$10.84
|
$21.39
|
$12.19
|
$23.10
|
Depreciation, depletion and amortization (DDA)
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. DDA 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 DDA 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).
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. DDA 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 DDA 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.
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.
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.
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.
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.
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 $7
thousand is related to Texas deferred taxes.
Liquidity and Capital Resources
Davis principal requirements for cash, other than
working capital needs for existing operations, are
costs of development of oil and gas properties,
retirement of debt and the acquisition of oil and
gas properties. Davis has historically funded its
development program, debt repayments and
acquisitions with cash flow from operations, bank
financing, property divestitures and joint ventures
with industry partners. Davis believes its
liquidity and capital resources are sufficient to
meet its obligations.
working capital needs for existing operations, are
costs of development of oil and gas properties,
retirement of debt and the acquisition of oil and
gas properties. Davis has historically funded its
development program, debt repayments and
acquisitions with cash flow from operations, bank
financing, property divestitures and joint ventures
with industry partners. Davis believes its
liquidity and capital resources are sufficient to
meet its obligations.
Cash Flow
|
Nine Months Ended September 30,
|
||
|
($ in thousands)
|
||
|
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
September30, 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.
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
September30, 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
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.
$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.
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.
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.
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.
Derivative Instruments
Davis periodically seeks to reduce its exposure
to commodity price volatility by hedging a
portion of production through commodity
derivative instruments.
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.
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.
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:
the following contracts:
|
Production Period
|
Instrument Type
|
Daily Volumes
|
Weighted Average Price
|
|
Natural Gas:
|
|||
|
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.
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.
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 thenine monthsended
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.
of Davis as of and for thenine monthsended
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 thethree and
nine monthsended 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.
of Yuma California as of and for thethree and
nine monthsended 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.
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:
Amendment No. 2 to the Current Report on Form
8-K/A:
|
Exhibit No.
|
Description
|
||
|
99.3
|
Unaudited consolidated financial
statements of Davis Petroleum Acquisition Corp. as of and for the nine monthsended 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 Registrants 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 thethree and nine monthsended 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 Registrants Registration Statement on Form S-4 (Commission File No. 333-212103) declared effective on September 22, 2016). |
||
|
99.7
|
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. |
||
About Yuma Energy, Inc. (NYSEMKT:PDO)
Yuma Energy, Inc. is an independent exploration and production company. The Company is oil and gas company focused on the acquisition, development and exploration for conventional and unconventional oil and natural gas resources in the United States Gulf Coast and California. It has approximately 13.3 million barrel of oil equivalent (Boe) of proved reserves. Its operations are focused on onshore assets located in central and southern Louisiana, where it is targeting the Austin Chalk, Tuscaloosa, Wilcox, Frio, Marg Tex and Hackberry formations. In addition, it has a non-operated position in the Bakken Shale in North Dakota and operated positions in Kern and Santa Barbara Counties in California. Its Greater Masters Creek Field properties are located in the Austin Chalk Trend in west central Louisiana. It also has interests in La Posada, Livingston, Lake Fortuna Field, Gardner Island and Branville Bay, Kern County Field Area, Livingston 3-D Project and Amazon 3-D Project in Louisiana. Yuma Energy, Inc. (NYSEMKT:PDO) Recent Trading Information
Yuma Energy, Inc. (NYSEMKT:PDO) closed its last trading session down -4.157 at 0.963 with shares trading hands.
