Overview
Unless the context otherwise requires, all
references in this report to the “Company,”
“Yuma,” “our,” “us,” and
“we” refer to Yuma Energy, Inc., a Delaware
corporation, and its subsidiaries, as a common entity, and
“Yuma California” prior to our reincorporation from
California to Delaware in October 2016. Unless otherwise noted, all
information in this report relating to oil, natural gas and natural
gas liquids reserves and the estimated future net cash flows
attributable to those reserves are based on estimates prepared by
independent reserve engineers and are net to our
interest.
We have referenced certain technical terms
important to an understanding of our business under the
Glossary of Selected Oil and Natural Gas Terms section above.
Throughout this report we make statements that may be classified as
“forward-looking.” Please refer to the Cautionary
Statement Regarding Forward-Looking Statements section above
for an explanation of these types of
statements.
Yuma
Energy, Inc., a Delaware corporation, is an independent
Houston-based exploration and production company focused on
acquiring, developing and exploring for conventional and
unconventional oil and natural gas resources. Historically, our
operations have focused on onshore properties located in central
and southern Louisiana and southeastern Texas where we have a long
history of drilling, developing and producing both oil and natural
gas assets. More recently, we have begun acquiring acreage in an
extension of the San Andres formation in Yoakum County, Texas, with
plans to explore and develop additional oil and natural gas assets
in the Permian Basin of West Texas. Finally, we have operated
positions in Kern County, California, and non-operated positions in
the East Texas Woodbine and the Bakken Shale in North Dakota. Our
common stock is listed on the NYSE American under the trading
symbol “YUMA.”
Recent Developments
Common Stock Offering
In
September and October 2017, we completed a public offering of
10,100,000 shares of common stock (including 500,000 shares
purchased pursuant to the underwriter’s overallotment
option), at a public offering price of $1.00 per share. We received
net proceeds from this offering of approximately $8.7 million,
after deducting underwriters’ fees and offering expenses of
$1.4 million.
Entry into the Permian Basin
In
2017, we entered the Permian Basin through a joint venture with two
privately held energy companies and established an Area of Mutual
Interest (“AMI”) covering approximately 33,280 acres in
Yoakum County, Texas, located in the Northwest Shelf of the Permian
Basin. The primary target within the AMI is the San Andres
formation, which has been one of the largest producing formations
in Texas to date. As of March 1, 2018, we held a 62.5% working
interest in approximately 4,558 gross acres (2,849 net acres)
within the AMI and intend to apply horizontal drilling technology
to the San Andres formation. This activity is commonly referred to
as the San Andres Horizontal Oil Play, and in certain areas,
referred to as a Residual Oil Zone (“ROZ”) Play due to
the presence of residual oil zone fairways with substantial
recoverable hydrocarbon resources in place. We are the operator of
the joint venture and intend to acquire additional leases
offsetting existing acreage. In December 2017, we sold a 12.5%
working interest in ten sections of the project on a promoted basis
and sold an additional 12.5% working interest in the same ten
sections under the same terms in January 2018. On November 8, 2017,
we spudded a salt water disposal well, the Jameson SWD #1, and
completed the well on December 8, 2017. The rig was then moved to
our State 320 #1H horizontal San Andres well, which we spudded on
December 13, 2017. The State 320 #1H well reached total depth on
January 2, 2018, and was subsequently completed and fraced, with
the last stage being completed on February 15, 2018. After the frac
was completed, we installed an electrical submersible pump
(“ESP”) and placed the well on production on March 1,
2018. The well is currently in the early stages of recovering
stimulation fluids and dewatering the near wellbore
area.
Sale of Certain Non-Core Oil and Gas Properties
On May
22, 2017 and effective as of January 1, 2017, we sold certain oil
and natural gas properties for $5.5 million located in Brazos
County, Texas known as the El Halcón property. Our El
Halcón property consisted of an average working interest of
approximately 8.5% (1,557 net acres) producing approximately 140
Boe/d net from 50 Eagle Ford wells and one Austin Chalk
well.
Reincorporation Merger and Davis Merger
On
October 26, 2016, Yuma Energy, Inc., a California corporation
(“Yuma California”), merged with and into the Company
resulting in our reincorporation from California to Delaware (the
“Reincorporation Merger”). In connection with the
Reincorporation Merger, Yuma California converted each outstanding
share of its 9.25% Series A Cumulative Redeemable Preferred Stock
(the “Yuma California Series A Preferred Stock”), into
35 shares of its common stock (the “Yuma California Common
Stock”), and then each share of Yuma California Common Stock
was exchanged for one-twentieth of one share of common stock of the
Company (the “common stock”). Immediately after
the Reincorporation Merger on October 26, 2016, a wholly owned
subsidiary of the Company merged (the “Davis Merger”)
with and into Davis Petroleum Acquisition Corp., a Delaware
corporation (“Davis”), in exchange for approximately
7,455,000 shares of common stock and 1,754,179 shares of Series D
Convertible preferred stock (the “Series D preferred
stock”). The Series D preferred stock had an aggregate
liquidation preference of approximately $19.4 million and a
conversion rate of $11.0741176 per share at the closing of the
Davis Merger, and will be paid dividends in the form of additional
shares of Series D preferred stock at a rate of 7% per annum. As a
result of the Davis Merger, the former holders of Davis common
stock received approximately 61.1% of the then outstanding common
stock of the Company and thus acquired voting control.
The
Davis Merger was accounted for as a business combination in
accordance with ASC 805 Business Combinations (“ASC
805”). ASC 805, among other things, requires assets acquired
and liabilities assumed to be measured at their acquisition date
fair value. Although the Company was the legal acquirer, Davis was
the accounting acquirer. The historical financial statements are
therefore those of Davis. Hence, the financial statements included
in this report reflect (i) the historical results of Davis prior to
the Davis Merger; (ii) the combined results of the Company
following the Davis Merger; (iii) the acquired assets and
liabilities of Davis at their historical cost; and (iv) the fair
value of the Company’s assets and liabilities as of the
closing of the Davis Merger.
Senior Credit Agreement
In
connection with the closing of the Davis Merger on October 26,
2016, the Company and three of its subsidiaries, as the
co-borrowers, entered into a credit agreement providing for a $75.0
million three-year senior secured revolving credit facility (the
“Credit Agreement”) with Société
Générale (“SocGen”), as administrative agent,
SG Americas Securities, LLC, as lead arranger and bookrunner, and
the Lenders signatory thereto (collectively with SocGen, the
“Lender”).
The
borrowing base of the credit facility was reaffirmed on September
8, 2017 at $40.5 million. The borrowing base is generally subject
to redetermination on April 1st and October 1st of each year, as
well as special redeterminations described in the Credit Agreement.
The amounts borrowed under the Credit Agreement bear annual
interest rates at either (a) the London Interbank Offered Rate
(“LIBOR”) plus 3.00% to 4.00% or (b) the prime lending
rate of SocGen plus 2.00% to 3.00%, depending on the amount
borrowed under the credit facility and whether the loan is drawn in
U.S. dollars or Euro dollars. The interest rate for the credit
facility at December 31, 2017 was 5.07% for LIBOR-based debt and
7.00% for prime-based debt. Principal amounts outstanding under the
credit facility are due and payable in full at maturity on October
26, 2019. All of the obligations under the Credit Agreement, and
the guarantees of those obligations, are secured by substantially
all of our assets. Additional payments due under the Credit
Agreement include paying a commitment fee to the Lender in respect
of the unutilized commitments thereunder. The commitment rate is
0.50% per year of the unutilized portion of the borrowing base in
effect from time to time. We are also required to pay customary
letter of credit fees.
The
Credit Agreement contains a number of covenants that, among other
things, restrict, subject to certain exceptions, our ability to
incur additional indebtedness, create liens on assets, make
investments, enter into sale and leaseback transactions, pay
dividends and distributions or repurchase our capital stock, engage
in mergers or consolidations, sell certain assets, sell or discount
any notes receivable or accounts receivable, and engage in certain
transactions with affiliates.
In
addition, the Credit Agreement requires us to maintain the
following financial covenants: a current ratio of not less than 1.0
to 1.0 on the last day of each quarter, a ratio of total debt to
earnings before interest, taxes, depreciation, depletion,
amortization and exploration expenses (“EBITDAX”) ratio
of not greater than 3.5 to 1.0 for the four fiscal quarters ending
on the last day of the fiscal quarter immediately preceding such
date of determination, and a ratio of EBITDAX to interest expense
of not less than 2.75 to 1.0 for the four fiscal quarters ending on
the last day of the fiscal quarter immediately preceding such date
of determination, and cash and cash equivalent investments together
with borrowing availability under the Credit Agreement of at least
$4.0 million. The Credit Agreement contains customary affirmative
covenants and defines events of default for credit facilities of
this type, including failure to pay principal or interest, breach
of covenants, breach of representations and warranties, insolvency,
judgment default, and a change of control. Upon the occurrence and
continuance of an event of default, the Lender has the right to
accelerate repayment of the loans and exercise its remedies with
respect to the collateral. As of December 31, 2017, we were in
compliance with the covenants under the Credit
Agreement.
Preferred Stock
As of
December 31, 2017, we had 1,904,391 shares of our Series D
preferred stock outstanding with an aggregate liquidation
preference of approximately $21.1 million and a conversion price of
$6.5838109 per share. The conversion price was adjusted from
$11.0741176 per share to $6.5838109 per share as a result of our
common stock offering that closed in October 2017. As a result, if
all of our outstanding shares of Series D preferred stock were
converted into common stock, we would need to issue approximately
3.2 million shares of common stock. The Series D preferred stock is
paid dividends in the form of additional shares of Series D
preferred stock at a rate of 7% per annum.
Operating Outlook
Recognizing the
volatility in oil and natural gas prices, we plan to continue a
disciplined approach in 2018 by emphasizing liquidity and value,
enhancing operational efficiencies, and managing capital expenses.
We will continue to evaluate the oil and natural gas price
environments and may adjust our capital spending plans, capital
raising activities, and strategic alternatives (including possible
asset sales) to maintain appropriate liquidity and financial
flexibility.
Business Strategy
Due to
the continued volatile commodity price environment and our belief
that uncertainty remains with respect to commodity prices in 2018,
we expect our capital spending plans to be limited primarily to
within our cash flow. In addition, we may slow or accelerate the
development of our properties to more closely match our projected
cash flows. We will be focused on lower risk and lower cost
opportunities that are expected to have higher returns to maintain
our production and cash flow. In addition, we intend to capture new
opportunities in the Permian Basin that will build on existing
inventory, as well as the Gulf Coast basins where we have
considerable history and experience.
The key
elements of our business strategy are:
➢
seek merger,
acquisition, and joint venture opportunities to increase our
liquidity, as well as reduce our G&A on a per Boe
basis;
➢
transition existing
inventory of non-producing and undeveloped reserves into oil and
natural gas production;
➢
add selectively to
project inventory through ongoing prospect generation, exploration
and strategic acquisitions; and
➢
retain a greater
percentage working interest in, and operatorship of, our projects
going forward.
Our
core competencies include oil and natural gas operating activities
and expertise in generating and developing:
➢
unconventional oil
and natural gas resource plays;
➢
onshore
liquids-rich prospects through the use of 3-D seismic surveys;
and
➢
identification of
high impact deep onshore prospects located beneath known producing
trends through the use of 3-D seismic surveys.
Our Key Strengths and Competitive Advantages
We
believe the following are our key strengths and competitive
advantages:
➢
Extensive technical knowledge and history of
operations in the Permian Basin and Gulf Coast regions
. We
believe our extensive understanding of the geology and experience
in interpreting well control, core and 3-D seismic data in these
areas provides us with a competitive advantage in exploring and
developing projects in the Permian Basin and Gulf Coast regions. We
have cultivated amicable and mutually beneficial relationships with
acreage owners in these regions and adjacent oil and natural gas
operators, which generally provides for effective leasing and
development activities.
➢
In-house technical expertise in 3-D seismic
programs
. We design and generate in-house 3-D seismic survey
programs on many of our projects. By controlling the 3-D seismic
program from field acquisition through seismic processing and
interpretation, we gain a competitive advantage through proprietary
knowledge of the project.
➢
Liquids-rich, quality assets with attractive
economics
. Our assets and potential future drilling
locations are primarily in oil plays with associated liquids-rich
natural gas.
➢
Diversified portfolio of producing and
non-producing assets
. Our current portfolio of producing and
non-producing assets covers an area within the Permian Basin of
west Texas, the Gulf Coast, southeastern Texas, the Bakken/Three
Forks shale in North Dakota, along with shallow oil fields in
central California.
➢
Company operated assets
. In order to
maintain better control over our assets, we have established a
leasehold position comprised primarily of assets where we are the
operator. By controlling operations, we are able to dictate the
pace of development and better manage the cost, type, and timing of
exploration and development activities.
➢
Experienced management team
. We have a
highly qualified management team with many years of industry
experience, including extensive experience in the Louisiana and
Texas Gulf Coast, the Permian Basin and southeast Texas, and most
of the other oil and natural gas producing regions of the United
States. Our exploration team has substantial expertise in the
design, acquisition, processing and interpretation of 3-D seismic
surveys, our experienced operations team allows for efficient
turnaround from project identification, to drilling, to production,
and our engineering and geoscience teams have considerable
experience evaluating both conventional and unconventional
opportunities in existing and prospective trends.
➢
Experienced board of directors
. Our
directors have substantial experience managing successful public
companies and realizing value for investors through the
development, acquisition and monetization of both conventional and
unconventional oil and natural gas assets.
Description of Major Properties
We are
the operator of properties containing approximately 63.5% of our
proved oil and natural gas reserves as of December 31, 2017. As
operator, we are able to directly influence exploration,
development and production operations. Our producing properties
have reasonably predictable production profiles and cash flows,
subject to commodity price fluctuations, and have provided a
foundation for our technical staff to pursue the development of our
undeveloped acreage, further develop our existing properties and
also generate new projects that we believe have the potential to
increase shareholder value.
As is
common in the industry, we participate in non-operated properties
and investments on a selective basis; our non-operating
participation decisions are dependent on the technical and economic
nature of the projects and the operating expertise and financial
standing of the operators. The following is a description of our
significant oil and natural gas properties.
Permian Basin
In
2017, we entered the Permian Basin through a joint venture with two
privately held energy companies and established an AMI covering
approximately 33,280 acres in Yoakum County, Texas, located in the
Northwest Shelf of the Permian Basin. The primary target within the
AMI is the San Andres formation, which has been one of the largest
producing formations in Texas to date. As of March 1, 2018, we held
a 62.5% working interest in approximately 4,558 gross acres (2,849
net acres) within the AMI and intend to apply horizontal drilling
technology to the San Andres formation. This activity is commonly
referred to as the San Andres Horizontal Oil Play, and in certain
areas, referred to as a Residual Oil Zone (“ROZ”) Play
due to the presence of residual oil zone fairways with substantial
recoverable hydrocarbon resources in place. We are the operator of
the joint venture and intend to acquire additional leases
offsetting existing acreage. In December 2017, we sold a 12.5%
working interest in ten sections of the project on a promoted basis
and sold an additional 12.5% working interest in the same ten
sections under the same terms in January 2018. On November 8, 2017,
we spudded a salt water disposal well, the Jameson SWD #1, and
completed the well on December 8, 2017. The rig was then moved to
our State 320 #1H horizontal San Andres well, which we spudded on
December 13, 2017. The State 320 #1H well reached total depth on
January 2, 2018, and was subsequently completed and fraced, with
the last stage being completed on February 15, 2018. After the frac
was completed, we installed an ESP and placed the well on
production on March 1, 2018. The well is currently in the early
stages of recovering the stimulation fluids and dewatering the near
wellbore area.
South Louisiana
We have
operated and non-operated assets in many of the prolific oil and
natural gas producing parishes of south Louisiana including
Cameron, LaFourche, Livingston, St. Helena, St. Bernard, and
Vermilion parishes. As of December 31, 2017, we had working
interests in nine fields in south Louisiana, of which we operate
eight with an average operated working interest of 62.7%. The
acreage associated with these leasehold positions is comprised of
19,668 gross acres and 3,862 net acres. The associated assets
produce from a variety of conventional formations with oil, natural
gas, and natural gas liquids from depths of approximately 5,500
feet to almost 19,000 feet. The formations include the Lower
Miocene, CibCarst, Dibert, Wilcox, Marg Tex, Het 1A, Tuscaloosa,
Miocene Siphonina, and Lower Planulina Cris R sands. The collective
net production from this area averaged approximately 489 Bbl/d of
oil, 8.0 MMcf/d of natural gas and 229 Bbl/d of natural gas liquids
during the year ended December 31, 2017. Our inventory of future
development opportunities includes proved, probable and possible
reserves and prospective resources consisting of behind pipe
recompletions, artificial lift installations, workovers, sidetracks
of existing wells and new well drilling opportunities.
Our two
largest fields in south Louisiana, based on estimated proved
reserve value, are described below.
Lac Blanc Field, Vermilion Parish,
Louisiana
– We are the operator of the Lac Blanc Field
where we have an average working interest of 81.3%. The field is
comprised of 1,744 gross acres and 1,090 net acres where two wells,
the SL 18090 #1 and #2, are producing from the Miocene Siphonina
D-1 sand (18,700 feet sand). The net production from the field
averaged approximately 69 Bbl/d of oil, 3.0 MMcf/d of natural gas
and 175 Bbl/d of natural gas liquids during the year ended December
31, 2017.
Bayou Hebert Field, Vermilion Parish,
Louisiana
– We have a 12.5% non-operated working
interest in the Bayou Hebert Field, which is comprised of
approximately 1,600 gross acres and 200 net acres with three wells
completed in the Lower Planulina Cris R sands. One of the
three wells is currently shut-in. The net production from the field
averaged approximately 70 Bbl/d of oil, 3.4 MMcf/d of natural gas
and 118 Bbl/d of natural gas liquids during the year ended December
31, 2017. Future development opportunities include behind pipe
recompletions and sidetracking an existing wellbore for proved and
non-proved reserves.
Southeast Texas
We have
operated and non-operated assets in southeast Texas containing both
conventional and unconventional properties located in Jefferson and
Madison counties. As of December 31, 2017, we had working interests
in two fields, one of which we are the operator, with a working
interest of 47.4%. The average working interest in the non-operated
field was approximately 23.0%. The acreage associated with these
leasehold positions consist of 25,724 gross acres and 1,248 net
acres. The unconventional assets are developed primarily with
horizontal wells in the Eagle Ford and tight Woodbine sands
producing oil, natural gas, and natural gas liquids from depths of
approximately 8,000 feet to 9,000 feet. Typical development wells
are drilled horizontally with lateral sections ranging from
approximately 4,500 feet to 7,500 feet in length where multi-stage
fracturing technology is employed. The collective net production
from this area averaged approximately 85 Bbl/d of oil, 372 Mcf/d of
natural gas and 60 Bbl/d of natural gas liquids during the year
ended December 31, 2017, which includes production from our El
Halcón property prior to its sale in May 2017. Future
development opportunities include the drilling of proved and
non-proved reserves, the development of which will be influenced
largely by future oil and natural gas commodities
prices.
California
We have
assets in Kern County, California. As of December 31, 2017, we have
a 100% working interest in five conventional fields with a
leasehold position comprised of 1,192 gross acres inclusive of 263
fee or minerals only acres. These properties produce oil from a
variety of conventional formations including the Pliocene, Miocene,
Oligocene, and Eocene from depths ranging from approximately 800
feet to 6,300 feet and are characterized by long-life shallow
decline production profiles. For the year ended December 31, 2017,
net production from our California assets averaged approximately 95
Bbls/d of oil. Future development opportunities include behind pipe
recompletions, artificial lift installations, and new well drilling
opportunities of proved and non-proved reserves.
North Dakota
We have
non-operated working interests in the Bakken Play in McKenzie
County, North Dakota. As of December 31, 2017, we had an
approximate 4.7% average working interest in two fields that
together include 7,680 gross acres and 362 net acres. Oil, natural
gas, and natural gas liquids are produced from depths of
approximately 8,000 feet from wells drilled horizontally with
lateral lengths ranging from approximately 5,000 feet to 10,000
feet and completed with multi-stage fracturing technology. For the
year ended December 31, 2017, net production from these assets
averaged 16 Bbl/d of oil, 9 Mcf/d of natural gas and 2 Bbl/d of
natural gas liquids. Future development opportunities include the
drilling of non-proved reserves, the development of which will be
influenced largely by future oil and natural gas commodities
prices.
Oil and Natural Gas Reserves
All of
our oil and natural gas reserves are located in the United States.
Unaudited information concerning the estimated net quantities of
all of our proved reserves and the standardized measure of future
net cash flows from the reserves is presented in Note 23 –
Supplementary Information on Oil and Natural Gas Exploration,
Development and Production Activities (Unaudited) in the Notes to
the Consolidated Financial Statements in Part II, Item 8 in this
report. The reserve estimates have been prepared by Netherland,
Sewell & Associates, Inc. (“NSAI”), an independent
petroleum engineering firm. We have no long-term supply or similar
agreements with foreign governments or authorities. We did not
provide any reserve information to any federal agencies in 2017
other than to the SEC and the Department of Energy.
Estimated Proved Reserves
The
table below summarizes our estimated proved reserves at December
31, 2017 based on reports prepared by NSAI. In preparing these
reports, NSAI evaluated 100% of our properties at December 31,
2017. For more information regarding our independent reserve
engineers, please see Independent Reserve Engineers below. The
information in the following table does not give any effect to or
reflect our commodity derivatives.
|
|
Natural Gas Liquids (MBbls)
|
|
|
Present Value Discounted at 10% ($ in
thousands)
(2)
|
Proved developed
(3)
|
|
|
|
|
|
Lac Blanc Field
(4)
|
330
|
712
|
12,132
|
3,065
|
$
23,895
|
Bayou Hebert Field
(4)
|
142
|
239
|
6,871
|
1,526
|
19,490
|
Other
|
1,291
|
58
|
2,128
|
1,704
|
20,643
|
Total
proved developed
|
1,763
|
1,009
|
21,131
|
6,295
|
64,028
|
Proved
undeveloped
(3)
|
|
|
|
|
|
Lac Blanc Field
(4)
|
-
|
-
|
-
|
-
|
-
|
Bayou Hebert Field
(4)
|
-
|
-
|
-
|
-
|
-
|
Other
|
599
|
285
|
2,465
|
1,295
|
8,875
|
Total
proved undeveloped
|
599
|
285
|
2,465
|
1,295
|
8,875
|
Total proved
(3)
|
2,362
|
1,294
|
23,596
|
7,590
|
$
72,903
|
(1)
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
(Boe).
(2)
Present Value
Discounted at 10% (“PV10”) is a Non-GAAP measure that
differs from the GAAP measure “standardized measure of
discounted future net cash flows” in that PV10 is calculated
without regard to future income taxes. Management believes that the
presentation of the PV10 value is relevant and useful to investors
because it presents the estimated discounted future net cash flows
attributable to our estimated proved reserves independent of our
income tax attributes, thereby isolating the intrinsic value of the
estimated future cash flows attributable to our reserves. Because
many factors that are unique to each individual company impact the
amount of future income taxes to be paid, we believe the use of a
pre-tax measure provides greater comparability of assets when
evaluating companies. For these reasons, management uses, and
believes the industry generally uses, the PV10 measure in
evaluating and comparing acquisition candidates and assessing the
potential return on investment related to investments in oil and
natural gas properties. PV10 includes estimated abandonment costs
less salvage. PV10 does not necessarily represent the fair market
value of oil and natural gas properties.
PV10 is
not a measure of financial or operational performance under GAAP,
nor should it be considered in isolation or as a substitute for the
standardized measure of discounted future net cash flows as defined
under GAAP. For a presentation of the standardized measure of
discounted future net cash flows, see Note 23 – Supplementary
Information on Oil and Natural Gas Exploration, Development and
Production Activities (Unaudited) in the Notes to the Consolidated
Financial Statements in Part II, Item 8 in this report. The table
below titled “Non-GAAP Reconciliation” provides a
reconciliation of PV10 to the standardized measure of discounted
future net cash flows.
Non-GAAP
Reconciliation
($ in thousands)
The
following table reconciles our direct interest in oil, natural gas
and natural gas liquids reserves as of December 31,
2017:
Present
value of estimated future net revenues (PV10)
|
$
72,903
|
Future
income taxes discounted at 10%
|
-
|
Standardized
measure of discounted future net cash flows
|
$
72,903
|
(3)
Proved reserves
were calculated using prices equal to the twelve-month unweighted
arithmetic average of the first-day-of-the-month prices for each of
the preceding twelve months, which were $51.34 per Bbl (WTI) and
$2.98 per MMBtu (HH), for the year ended December 31, 2017.
Adjustments were made for location and grade.
(4)
Our Lac Blanc Field
and Bayou Hebert Field were our only fields that each contained 15%
or more of our estimated proved reserves as of December 31,
2017.
Proved Undeveloped Reserves
At
December 31, 2017, our estimated proved undeveloped
(“PUD”) reserves were approximately 1,295 MBoe. The
following table details the changes in PUD reserves for the year
ended December 31, 2017 (in MBoe):
Beginning
proved undeveloped reserves at January 1, 2017
|
1,404
|
Undeveloped
reserves transferred to developed
|
-
|
Purchases
of minerals-in-place
|
-
|
Sales
of minerals-in-place
|
(408
)
|
Extensions
and discoveries
|
176
|
Production
|
-
|
Revisions
|
123
|
Proved
undeveloped reserves at December 31, 2017
|
1,295
|
From
January 1, 2017 to December 31, 2017, our PUD reserves decreased
109 MBoe, or 8%, from 1,404 MBoe to 1,295 MBoe, primarily due to
the sale of minerals-in-place in Santa Barbara County, California
of 408 MBoe. This decrease was partially offset by 176 MBoe added
through extensions of existing discoveries in Kern County,
California and upward revisions of 123 MBoe due to increased
prices. As of December 31, 2017, we plan to drill all of our PUD
drilling locations within five years from the date they were
initially recorded
.
Uncertainties are
inherent in estimating quantities of proved reserves, including
many risk factors beyond our control. Reserve engineering is a
subjective process of estimating subsurface accumulations of oil
and natural gas that cannot be measured in an exact manner, and the
accuracy of any reserve estimate is a function of the quality of
available data and the interpretation thereof. As a result,
estimates by different engineers often vary, sometimes
significantly. In addition, physical factors such as the results of
drilling, testing and production subsequent to the date of the
estimates, as well as economic factors such as change in product
prices, may require revision of such estimates. Accordingly, oil
and natural gas quantities ultimately recovered will vary from
reserve estimates.
Technology Used to Establish Reserves
Under
SEC rules, proved reserves are those quantities of oil and natural
gas that 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, under existing
economic conditions, operating methods and government regulations.
The term “reasonable certainty” implies a high degree
of confidence that the quantities of oil and natural gas actually
recovered will equal or exceed the estimate. Reasonable certainty
can be established using techniques that have been proven effective
by actual production from projects in the same reservoir or an
analogous reservoir or by other evidence using reliable technology
that establishes reasonable certainty. Reliable technology is a
grouping of one or more technologies (including computational
methods) that has been field tested and has been demonstrated to
provide reasonably certain results with consistency and
repeatability in the formation being evaluated or in an analogous
formation.
To
establish reasonable certainty with respect to our estimated proved
reserves, NSAI employed technologies that have been demonstrated to
yield results with consistency and repeatability. The technologies
and economic data used in the estimation of our reserves include,
but are not limited to, electrical logs, radioactivity logs, core
analyses, geologic maps and available downhole and production data,
seismic data and well test data. Reserves attributable to producing
wells with sufficient production history were estimated using
appropriate decline curves or other performance relationships.
Reserves attributable to producing wells with limited production
history and for undeveloped locations were estimated using both
volumetric estimates and performance from analogous wells in the
surrounding area. These wells were considered to be analogous based
on production performance from the same formation and completion
using similar techniques.
Independent Reserve Engineers
We
engaged NSAI to prepare our annual reserve estimates and have
relied on NSAI’s expertise to ensure that our reserve
estimates are prepared in compliance with SEC guidelines. NSAI was
founded in 1961 and performs consulting petroleum engineering
services under Texas Board of Professional Engineers Registration
No. F-2699. Within NSAI, the technical persons primarily
responsible for preparing the estimates set forth in the NSAI
reserves report incorporated herein are G. Lance Binder and Philip
R. Hodgson. Mr. Binder has been practicing consulting petroleum
engineering at NSAI since 1983. Mr. Binder is a Registered
Professional Engineer in the State of Texas (No. 61794) and has
over 30 years of practical experience in petroleum engineering,
with over 30 years of experience in the estimation and evaluation
of reserves. He graduated from Purdue University in 1978 with a
Bachelor of Science degree in Chemical Engineering. Mr. Hodgson has
been practicing consulting petroleum geology at NSAI since 1998.
Mr. Hodgson is a Licensed Professional Geoscientist in the State of
Texas, Geology (No. 1314) and has over 30 years of practical
experience in petroleum geosciences. He graduated from University
of Illinois in 1982 with a Bachelor of Science Degree in Geology
and from Purdue University in 1984 with a Master of Science Degree
in Geophysics. Both technical principals meet or exceed the
education, training, and experience requirements set forth in the
Standards Pertaining to the Estimating and Auditing of Oil and Gas
Reserves Information promulgated by the Society of Petroleum
Engineers; both are proficient in judiciously applying industry
standard practices to engineering and geoscience evaluations as
well as applying SEC and other industry reserves definitions and
guidelines.
Our
President and Chief Operating Officer is the person primarily
responsible for overseeing the preparation of our internal reserve
estimates and for overseeing the independent petroleum engineering
firm during the preparation of our reserve report. He has a
Bachelor of Science degree in Petroleum Engineering and over 31
years of industry experience, with 21 years or more of experience
working as a reservoir engineer, reservoir engineering manager, or
reservoir engineering executive. His professional qualifications
meet or exceed the qualifications of reserve estimators and
auditors set forth in the “Standards Pertaining to Estimation
and Auditing of Oil and Gas Reserves Information” promulgated
by the Society of Petroleum Engineers. The President and Chief
Operating Officer reports directly to our Chief Executive
Officer.
Internal Control over Preparation of Reserve Estimates
We
maintain adequate and effective internal controls over our reserve
estimation process as well as the underlying data upon which
reserve estimates are based. The primary inputs to the reserve
estimation process are technical information, financial data,
ownership interest and production data. The relevant field and
reservoir technical information, which is updated annually, is
assessed for validity when our independent petroleum engineering
firm has technical meetings with our engineers, geologists, and
operations and land personnel. Current revenue and expense
information is obtained from our accounting records, which are
subject to external quarterly reviews, annual audits and our own
set of internal controls over financial reporting. All current
financial data such as commodity prices, lease operating expenses,
production taxes and field-level commodity price differentials are
updated in the reserve database and then analyzed to ensure that
they have been entered accurately and that all updates are
complete. Our current ownership in mineral interests and well
production data are also subject to our internal controls over
financial reporting, and they are incorporated in our reserve
database as well and verified internally by us to ensure their
accuracy and completeness. Once the reserve database has been
updated with current information, and the relevant technical
support material has been assembled, our independent engineering
firm meets with our technical personnel to review field performance
and future development plans in order to further verify the
validity of estimates. Following these reviews, the reserve
database is furnished to NSAI so that it can prepare its
independent reserve estimates and final report. The reserve
estimates prepared by NSAI are reviewed and compared to our
internal estimates by our President and Chief Operating Officer and
our reservoir engineering staff. Material reserve estimation
differences are reviewed between NSAI’s reserve estimates and
our internally prepared reserves on a case-by-case basis. An
iterative process is performed between NSAI and us, and additional
data is provided to address any differences. If the supporting
documentation will not justify additional changes, the NSAI
reserves are accepted. In the event that additional data supports a
reserve estimation adjustment, NSAI will analyze the additional
data, and may make changes it deems necessary. Additional data is
usually comprised of updated production information on new wells.
Once the review is completed and all material differences are
reconciled, the reserve report is finalized and our reserve
database is updated with the final estimates provided by NSAI.
Access to our reserve database is restricted to specific members of
our reservoir engineering department and management.
Production, Average Price and Average Production Cost
The net
quantities of oil, natural gas and natural gas liquids produced and
sold by us for each of the years ended December 31, 2017 and 2016,
the average sales price per unit sold and the average production
cost per unit are presented below.
|
|
|
|
|
Production
volumes:
|
|
|
Crude
oil and condensate (Bbls)
|
250,343
|
172,003
|
Natural
gas (Mcf)
|
3,085,613
|
2,326,400
|
Natural
gas liquids (Bbls)
|
131,155
|
104,689
|
Total (Boe)
(1)
|
895,767
|
664,425
|
Average
prices realized:
|
|
|
Crude
oil and condensate (per Bbl)
|
$
50.32
|
$
42.21
|
Natural
gas (per Mcf)
|
$
3.05
|
$
2.45
|
Natural
gas liquids (per Bbl)
|
$
26.08
|
$
17.33
|
Production cost per Boe
(2)
|
$
9.80
|
$
5.98
|
(1)
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
(Boe).
(2)
Excludes ad valorem
taxes (which are included in lease operating expenses on our
Consolidated Statements of Operations in the Consolidated Financial
Statements in Part II, Item 8 in this report) and severance taxes,
totaling $2,262,702 and $1,588,798 in fiscal years 2017 and 2016,
respectively.
Our
interests in Lac Blanc Field and Bayou Hebert Field represented
40.0% and 20.1%, respectively, of our total proved reserves as of
December 31, 2017. Our interests in Lac Blanc Field and Bayou
Hebert Field represented 31.1% and 21.7%, respectively, of our
total proved reserves as of December 31, 2016. No other single
field accounted for 15% or more of our proved reserves as of
December 31, 2017 and 2016.
The net
quantities of oil, natural gas and natural gas liquids produced and
sold by us for the years ended December 31, 2017 and 2016, the
average sales price per unit sold and the average production cost
per unit for our Lac Blanc Field are presented below.
|
|
Lac Blanc Field
|
|
|
Production
volumes:
|
|
|
Crude
oil and condensate (Bbls)
|
25,070
|
22,111
|
Natural
gas (Mcf)
|
1,101,824
|
1,069,325
|
Natural
gas liquids (Bbls)
|
63,841
|
56,005
|
Total (Boe)
(1)
|
272,548
|
256,337
|
Average
prices realized:
|
|
|
Crude
oil and condensate (per Bbl)
|
$
50.86
|
$
41.46
|
Natural
gas (per Mcf)
|
$
3.22
|
$
2.43
|
Natural
gas liquids (per Bbl)
|
$
27.76
|
$
18.75
|
Production cost per Boe
(2)
|
$
6.63
|
$
6.37
|
(1)
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
(Boe).
(2)
Excludes ad valorem
taxes (which are included in lease operating expenses on our
Consolidated Statements of Operations in the Consolidated Financial
Statements in Part II, Item 8 in this report) and severance taxes,
totaling $326,526 and $412,372 in fiscal years 2017 and 2016,
respectively.
The net
quantities of oil, natural gas and natural gas liquids produced and
sold by us for the years ended December 31, 2017 and 2016, the
average sales price per unit sold and the average production cost
per unit for our Bayou Hebert Field are presented
below.
|
|
Bayou Hebert Field
|
|
|
Production
volumes:
|
|
|
Crude
oil and condensate (Bbls)
|
25,479
|
4,401
|
Natural
gas (Mcf)
|
1,236,615
|
177,756
|
Natural
gas liquids (Bbls)
|
43,196
|
5,553
|
Total (Boe)
(1)
|
274,778
|
39,580
|
Average
prices realized:
|
|
|
Crude
oil and condensate (per Bbl)
|
$
52.80
|
$
47.41
|
Natural
gas (per Mcf)
|
$
3.10
|
$
3.01
|
Natural
gas liquids (per Bbl)
|
$
27.85
|
$
22.72
|
Production cost per Boe
(2)
|
$
4.51
|
$
6.48
|
(1)
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
(Boe).
(2)
Excludes ad valorem
taxes (which are included in lease operating expenses on our
Consolidated Statements of Operations in the Consolidated Financial
Statements in Part II, Item 8 in this report) and severance taxes,
totaling $289,857 and $308,338 in fiscal years 2017 and 2016,
respectively.
Gross and Net Productive Wells
As of
December 31, 2017, our total gross and net productive wells
were as follows:
(1)
A gross well is a
well in which a working interest is owned. The number of net wells
represents the sum of fractions of working interests we own in
gross wells. Productive wells are producing wells plus shut-in
wells we deem capable of production. Horizontal re-entries of
existing wells do not increase a well total above one gross well.
We have working interests in 8 gross wells with completions into
more than one productive zone; in the table above, these wells with
multiple completions are only counted as one gross
well.
Gross and Net Developed and Undeveloped Acres
As of
December 31, 2017, we had total gross and net developed and
undeveloped leasehold acres as set forth below. The developed
acreage is stated on the basis of spacing units designated or
permitted by state regulatory authorities.
Gross acres are those acres in which
a working interest is owned. The number of net acres represents the
sum of fractional working interests we own in gross
acres.
|
|
Undeveloped
|
|
State
|
|
|
|
|
|
|
Louisiana
|
19,028
|
3,344
|
640
|
518
|
19,668
|
3,862
|
North
Dakota
|
7,680
|
362
|
-
|
-
|
7,680
|
362
|
Texas
|
26,584
|
1,225
|
8,237
|
3,262
|
34,821
|
4,487
|
Oklahoma
|
2,000
|
79
|
-
|
-
|
2,000
|
79
|
California
|
1,192
|
1,192
|
-
|
-
|
1,192
|
1,192
|
Total
|
56,484
|
6,202
|
8,877
|
3,780
|
65,361
|
9,982
|
As of
December 31, 2017, we had leases representing 1,996 net acres (none
of which were in the Lac Blanc or Bayou Herbert Fields) expiring in
2018; 607 net acres (none of which were in the Lac Blanc or Bayou
Herbert Fields) expiring in 2019; and 1,083 net acres expiring in
2020 and beyond. We believe that our current and future drilling
plans, along with selected lease extensions, can address the
majority of the leases expiring in 2018 and beyond.
Exploratory Wells and Development Wells
Set
forth below for the years ended December 31, 2017 and 2016 is
information concerning our drilling activity during the years
indicated.
|
|
|
|
|
|
|
|
Year
|
|
|
|
|
|
2017
|
-
|
0.5
|
-
|
-
|
0.5
|
2016
|
-
|
-
|
1.0
|
-
|
1.0
|
Present Activities
At
April 2, 2018, we had -0- gross (-0- net) wells in the process of
drilling or completing.
Supply Contracts or Agreements
Crude
oil and condensate are sold through month-to-month evergreen
contracts. The price is tied to an index or a weighted monthly
average of posted prices with certain adjustments for gravity,
Basic Sediment and Water (“BS&W”) and
transportation. Generally, the index or posting is based on WTI and
adjusted to LLS or HLS. Pricing for our California properties is
based on an average of specified posted prices, adjusted for
gravity, transportation, and for one field, a market
differential.
Our
natural gas is sold under multi-year contracts with pricing tied to
either first of the month index or a monthly weighted average of
purchaser prices received. Natural gas liquids are also sold under
multi-year contacts usually tied to the related natural gas
contract. Pricing is based on published prices for each product or
a monthly weighted average of purchaser prices
received.
We also
engage in commodity derivative activities as discussed below in
“Management’s Discussion and Analysis of Financial
Condition and Results of Operations – Commodity derivative
Activities.”
Competition
The
domestic oil and natural gas business is intensely competitive in
the exploration for and acquisition of leasehold interests,
reserves and in the producing and marketing of oil and natural gas
production. Our competitors include national oil companies, major
oil and natural gas companies, independent oil and natural gas
companies, drilling partnership programs, individual producers,
natural gas marketers, and major pipeline companies, as well as
participants in other industries supplying energy and fuel to
consumers. Many of our competitors are large, well-established
companies. They likely are able to pay more for seismic information
and lease rights on oil and natural gas properties and exploratory
prospects and to define, evaluate, bid for and purchase a greater
number of properties and prospects than our financial or human
resources permit. Our ability to acquire additional properties and
to discover reserves in the future will be dependent upon our
ability to evaluate and select suitable properties and to
consummate oil and gas related transactions in a highly competitive
environment.
Other Business Matters
Major Customers
During
the years ended December 31, 2017 and 2016, sales to five customers
accounted for approximately 79% and sales to five customers
accounted for approximately 78%, respectively, of the
Company’s total revenues.
We
believe there are adequate alternate purchasers of our production
such that the loss of one or more of the above purchasers would not
have a material adverse effect on our results of operations or cash
flows.
Seasonality of Business
Weather
conditions affect the demand for, and prices of, natural gas and
can also delay oil and natural gas drilling activities, disrupting
our overall business plans. Demand for natural gas is typically
higher during the winter, resulting in higher natural gas prices
for our natural gas production during our first and fourth fiscal
quarters. Due to these seasonal fluctuations, our results of
operations for individual quarterly periods may not be indicative
of the results that we may realize on an annual basis.
Operational Risks
Oil and
natural gas exploration, development and production involve a high
degree of risk, which even a combination of experience, knowledge
and careful evaluation may not be able to overcome. There is no
assurance that we will discover, acquire or produce additional oil
and natural gas in commercial quantities. Oil and natural gas
operations also involve the risk that well fires, blowouts,
equipment failure, human error and other events may cause
accidental leakage or spills of toxic or hazardous materials, such
as petroleum liquids or drilling fluids into the environment, or
cause significant injury to persons or property. In such event,
substantial liabilities to third parties or governmental entities
may be incurred, the satisfaction of which could substantially
reduce our available cash and possibly result in loss of oil and
natural gas properties. Such hazards may also cause damage to or
destruction of wells, producing formations, production facilities
and pipeline or other processing facilities.
As is
common in the oil and natural gas industry, we do not insure fully
against all risks associated with our business either because such
insurance is not available or because we believe the premium costs
are prohibitive. A loss not fully covered by insurance could have a
material effect on our operating results, financial position and
cash flows. For further discussion of these risks see Item 1A.
“Risk Factors” of this report.
Title to Properties
We
believe that the title to our oil and natural gas properties is
good and defensible in accordance with standards generally accepted
in the oil and natural gas industry, subject to such exceptions
which, in our opinion, are not so material as to detract
substantially from the use or value of our oil and natural gas
properties. Our oil and natural gas properties are typically
subject, in one degree or another, one or more of the
following:
●
royalties and other
burdens and obligations, express or implied, under oil and natural
gas leases;
●
overriding
royalties and other burdens created by us or our predecessors in
title;
●
a variety of
contractual obligations (including, in some cases, development
obligations) arising under operating agreements, joint development
agreements, farmout agreements, participation agreements,
production sales contracts and other agreements that may affect the
properties or their titles;
●
back-ins and
reversionary interests existing under various agreements and
leasehold assignments;
●
liens that arise in
the normal course of operations, such as those for unpaid taxes,
statutory liens securing obligations to unpaid suppliers and
contractors and contractual liens under operating
agreements;
●
pooling,
unitization and other agreements, declarations and orders;
and
●
easements,
restrictions, rights-of-way and other matters that commonly affect
property.
To the
extent that such burdens and obligations affect our rights to
production revenues, they have been taken into account in
calculating our net revenue interests and in estimating the
quantity and value of our reserves. We believe that the burdens and
obligations affecting our oil and natural gas properties are common
in our industry with respect to the types of properties we
own.
Operational Regulations
All of
the jurisdictions in which we own or operate producing oil and
natural gas properties have statutory and regulatory provisions
affecting drilling, completion, and production activities,
including provisions related to permits for the drilling of wells,
bonding requirements to drill or operate wells, the location of
wells, the method of drilling and casing wells, the surface use and
restoration of properties upon which wells are drilled, sourcing
and disposal of water used in the drilling and completion process,
and the plugging and abandonment of wells. Our operations are also
subject to various conservation laws and regulations. These laws
and regulations govern the size of drilling and spacing units, the
density of wells that may be drilled in oil and natural gas
properties and the unitization or pooling of oil and natural gas
properties. In this regard, while some states allow the forced
pooling or integration of land and leases to facilitate
development, other states including Texas, where we operate, rely
primarily or exclusively on voluntary pooling of land and leases.
Accordingly, it may be difficult for us to form spacing units and
therefore difficult to develop a project if we own or control less
than 100% of the leasehold. In addition, state conservation laws
establish maximum rates of production from oil and natural gas
wells, generally prohibit the venting or flaring of natural gas,
and impose specified requirements regarding the ratability of
production. On some occasions, local authorities have imposed
moratoria or other restrictions on exploration, development and
production activities pending investigations and studies addressing
potential local impacts of these activities before allowing oil and
natural gas exploration, development and production to
proceed.
The
effect of these regulations is to limit the amount of oil and
natural gas that we can produce from our wells and to limit the
number of wells or the locations at which we can drill, although we
can apply for exceptions to such regulations or to have reductions
in well spacing. Failure to comply with applicable laws and
regulations can result in substantial penalties. The regulatory
burden on the industry increases the cost of doing business and
affects profitability. Moreover, each state generally imposes a
production or severance tax with respect to the production and sale
of oil, natural gas and natural gas liquids within its
jurisdiction.
Regulation of Transportation of Natural Gas
The
transportation and sale, or resale, of natural gas in interstate
commerce are regulated by the Federal Energy Regulatory Commission
(“FERC”) under the Natural Gas Act of 1938
(“NGA”), the Natural Gas Policy Act of 1978
(“NGPA”) and regulations issued under those statutes.
FERC regulates interstate natural gas transportation rates and
service conditions, which affects the marketing of natural gas that
we produce, as well as the revenues we receive for sales of our
natural gas.
Intrastate natural
gas transportation is also subject to regulation by state
regulatory agencies. The basis for intrastate regulation of natural
gas transportation and the degree of regulatory oversight and
scrutiny given to intrastate natural gas pipeline rates and
services varies from state to state. Insofar as such regulation
within a particular state will generally affect all intrastate
natural gas shippers within the state on a comparable basis, we
believe that the regulation of similarly situated intrastate
natural gas transportation in any states in which we operate and
ship natural gas on an intrastate basis will not affect our
operations in any way that is of material difference from those of
our competitors. Like the regulation of interstate transportation
rates, the regulation of intrastate transportation rates affects
the marketing of natural gas that we produce, as well as the
revenues we receive for sales of our natural gas.
Regulation of Sales of Oil, Natural Gas and Natural Gas
Liquids
The
prices at which we sell oil, natural gas and natural gas liquids
are not currently subject to federal regulation and, for the most
part, are not subject to state regulation. FERC, however, regulates
interstate natural gas transportation rates, and terms and
conditions of transportation service, which affects the marketing
of the natural gas we produce, as well as the prices we receive for
sales of our natural gas. Similarly, the price we receive from the
sale of oil and natural gas liquids is affected by the cost of
transporting those products to market. FERC regulates
the transportation of oil and liquids on interstate pipelines under
the provision of the Interstate Commerce Act, the Energy Policy Act
of 1992 and regulations issued under those
statutes. Intrastate transportation of oil, natural gas
liquids, and other products, is dependent on pipelines whose rates,
terms and conditions of service are subject to regulation by state
regulatory bodies under state statutes. In addition, while sales by
producers of natural gas and all sales of crude oil, condensate,
and natural gas liquids can currently be made at uncontrolled
market prices, Congress could reenact price controls in the
future.
Changes
in law and to FERC policies and regulations may adversely affect
the availability and reliability of firm and/or interruptible
transportation service on interstate pipelines, and we cannot
predict what future action FERC will take. We do not believe,
however, that any regulatory changes will affect us in a way that
materially differs from the way they will affect other natural gas
producers, gatherers and marketers with which we
compete.
Environmental Regulations
Our
operations are also subject to stringent federal, state and local
laws regulating the discharge of materials into the environment or
otherwise relating to health and safety or the protection of the
environment. Numerous governmental agencies, such as the U. S.
Environmental Protection Agency (the “EPA”), issue
regulations to implement and enforce these laws, which often
require difficult and costly compliance measures. Among other
things, environmental regulatory programs typically govern the
permitting, construction and operation of a well or production
related facility. Many factors, including public perception, can
materially impact the ability to secure an environmental
construction or operation permit. Failure to comply with
environmental laws and regulations may result in the assessment of
substantial administrative, civil and criminal penalties, as well
as the issuance of injunctions limiting or prohibiting our
activities. In addition, some laws and regulations relating to
protection of the environment may, in certain circumstances, impose
strict liability for environmental contamination, which could
result in liability for environmental damages and cleanup costs
without regard to negligence or fault on our part.
Beyond
existing requirements, new programs and changes in existing
programs may affect our business, including oil and natural gas
exploration and production, air emissions, waste management, and
underground injection of waste material. Environmental laws and
regulations have been subject to frequent changes over the years,
and the imposition of more stringent requirements could have a
material adverse effect on our financial condition and results of
operations. The following is a summary of the more significant
existing environmental, health and safety laws and regulations to
which our business operations are subject and for which compliance
in the future may have a material adverse impact on our capital
expenditures, earnings and competitive position.
Hazardous Substances and Wastes
The
federal Comprehensive Environmental Response, Compensation, and
Liability Act of 1980 (“CERCLA”), also known as the
Superfund law, and comparable state laws impose liability, without
regard to fault or the legality of the original conduct on certain
categories of persons that are considered to be responsible for the
release of a hazardous substance into the environment. These
persons may include the current or former owner or operator of the
site or sites where the release occurred and companies that
disposed or arranged for the disposal of hazardous substances found
at the site. Under CERCLA, these potentially responsible persons
may be subject to strict, joint and several liability for the costs
of investigating and cleaning up hazardous substances that have
been released into the environment, for damages to natural
resources and for the costs of certain health studies. In addition,
it is not uncommon for neighboring landowners and other third
parties to file claims for personal injury and property damage
allegedly caused by hazardous substances or other pollutants
released into the environment. We are able to control directly the
operation of only those wells with respect to which we act as
operator. Notwithstanding our lack of direct control over wells
operated by others, the failure of an operator other than us to
comply with applicable environmental regulations may, in certain
circumstances, be attributed to us. We generate materials in the
course of our operations that may be regulated as hazardous
substances but we are not presently aware of any liabilities for
which we may be held responsible that would materially or adversely
affect us.
The
Resource Conservation and Recovery Act of 1976
(“RCRA”), and comparable state statutes, regulate the
generation, treatment, storage, transportation, disposal and
clean-up of hazardous and solid (non-hazardous) wastes. With the
approval of the EPA, the individual states can administer some or
all of the provisions of RCRA, and some states have adopted their
own, more stringent requirements. Drilling fluids, produced waters
and most of the other wastes associated with the exploration,
development and production of oil and natural gas are currently
regulated under RCRA’s solid (non-hazardous) waste
provisions. However, legislation has been proposed from time to
time and various environmental groups have filed lawsuits that, if
successful, could result in the reclassification of certain oil and
natural gas exploration and production wastes as “hazardous
wastes,” which would make such wastes subject to much more
stringent handling, disposal and clean-up requirements.
For example, in response to a lawsuit filed in the U.S. District
Court for the District of Columbia by several non-governmental
environmental groups against the EPA for the agency’s failure
to timely assess its RCRA Subtitle D criteria regulations for oil
and natural gas wastes, the EPA and the environmental groups
entered into an agreement that was finalized in a consent decree
issued by the District Court on December 28, 2016. Under the
decree, the EPA is required to propose no later than March 15,
2019, a rulemaking for revision of certain Subtitle D criteria
regulations pertaining to oil and natural gas wastes or sign a
determination that revision of the regulations is not necessary. If
the EPA proposes a rulemaking for revised oil and natural gas waste
regulations, the consent decree requires that the EPA take final
action following notice and comment rulemaking no later than
July 15, 2021. A loss of the RCRA exclusion for drilling
fluids, produced waters and related wastes could result in an
increase in our, as well as the oil and natural gas E&P
industry’s, costs to manage and dispose of generated wastes,
which could have a material adverse effect on the industry as well
as on our business.
From
time to time, releases of materials or wastes have occurred at
locations we own or at which we have operations. These properties
and the materials or wastes released thereon may be subject to
CERCLA, RCRA and analogous state laws. Under these laws, we have
been and may be required to remove or remediate such materials or
wastes.
Water Discharges
The
federal Clean Water Act and analogous state laws impose
restrictions and strict controls with respect to the discharge of
pollutants, including spills and leaks of oil and other substances,
into waters of the United States. The discharge of pollutants into
regulated waters, including jurisdictional wetlands, is prohibited,
except in accordance with the terms of a permit issued by the EPA
or an analogous state agency. In September 2015, a new EPA and U.S.
Army Corps of Engineers rule defining the scope of federal
jurisdiction over wetlands and other waters became effective. To
the extent the rule expands the range of properties subject to the
Clean Water Act’s jurisdiction, certain energy companies
could face increased costs and delays with respect to obtaining
permits for dredge and fill activities in wetland areas. The rule
has been challenged in court on the grounds that it unlawfully
expands the reach of Clean Water Act programs, and implementation
of the rule has been stayed pending resolution of the court
challenge. In addition, following the issuance of a presidential
executive order to review the rule, on July 27, 2017, the EPA
proposed to repeal the rule and also separately announced its
intent to conduct a substantive re-evaluation of the definition of
“waters of the United States” in a future rulemaking.
As a result, future implementation of the rule is uncertain at this
time.
The
process for obtaining permits has the potential to delay our
operations. Spill prevention, control and countermeasure
requirements of federal laws require appropriate containment berms
and similar structures to help prevent the contamination of
navigable waters by a petroleum hydrocarbon tank spill, rupture or
leak. In addition, the Clean Water Act and analogous state laws
require individual permits or coverage under general permits for
discharges of storm water runoff from certain types of facilities.
Federal and state regulatory agencies can impose administrative,
civil and criminal penalties as well as other enforcement
mechanisms for non-compliance with discharge permits or other
requirements of the Clean Water Act and analogous state laws and
regulations. The Clean Water Act and analogous state laws provide
for administrative, civil and criminal penalties for unauthorized
discharges and, together with the Oil Pollution Act of 1990
(“OPA”), impose rigorous requirements for spill
prevention and response planning, as well as substantial potential
liability for the costs of removal, remediation, and damages in
connection with any unauthorized discharges.
Our oil
and natural gas production also generates salt water, which we
dispose of by underground injection. The federal Safe Drinking
Water Act (“SDWA”) regulates the underground injection
of substances through the Underground Injection Control
(“UIC”) program, and related state programs regulate
the drilling and operation of salt water disposal wells. The EPA
directly administers the UIC program in some states, and in others
it is delegated to the state for administering. Permits must be
obtained before drilling salt water disposal wells, and casing
integrity monitoring must be conducted periodically to ensure the
casing is not leaking salt water to groundwater. Contamination of
groundwater by oil and natural gas drilling, production, and
related operations may result in fines, penalties, and remediation
costs, among other sanctions and liabilities under the SDWA and
state laws. In addition, third party claims may be filed by
landowners and other parties claiming damages for alternative water
supplies, property damages, and bodily injury.
Hydraulic Fracturing
Our
completion operations are subject to regulation, which may increase
in the short- or long-term. In particular, the well completion
technique known as hydraulic fracturing, which is used to stimulate
production of oil and natural gas, has come under increased
scrutiny by the environmental community, and many local, state and
federal regulators. Hydraulic fracturing involves the injection of
water, sand and additives under pressure, usually down casing that
is cemented in the wellbore, into prospective rock formations at
depths to stimulate oil and natural gas production. We engage third
parties to provide hydraulic fracturing or other well stimulation
services to us in connection with substantially all of the wells
for which we are the operator.
The
SDWA regulates the underground injection of substances through the
UIC program. Hydraulic fracturing is generally exempt from
regulation under the UIC program, and the hydraulic fracturing
process is typically regulated by state oil and gas commissions.
However, legislation has been proposed in recent sessions of
Congress to amend the SDWA to repeal the exemption for hydraulic
fracturing from the definition of “underground
injection,” to require federal permitting and regulatory
control of hydraulic fracturing, and to require disclosure of the
chemical constituents of the fluids used in the fracturing
process.
Furthermore,
several federal agencies have asserted regulatory authority over
certain aspects of the fracturing process. For example, the EPA has
taken the position that hydraulic fracturing with fluids containing
diesel fuel is subject to regulation under the UIC program,
specifically as “Class II” UIC wells.
In
addition, the EPA previously announced plans to develop a Notice of
Proposed Rulemaking by June 2018, which would describe a proposed
mechanism, regulatory, voluntary, or a combination of both, to
collect data on hydraulic fracturing chemical substances and
mixtures. Also, on June 28, 2016, the EPA published a final rule
prohibiting the discharge of wastewater from onshore unconventional
oil and natural gas extraction facilities to publicly owned
wastewater treatment plants. The EPA is also conducting a study of
private wastewater treatment facilities (also known as centralized
waste treatment (“CWT”) facilities) accepting oil and
natural gas extraction wastewater. The EPA is collecting data and
information related to the extent to which CWT facilities accept
such wastewater, available treatment technologies (and their
associated costs), discharge characteristics, financial
characteristics of CWT facilities, and the environmental impacts of
discharges from CWT facilities.
In
addition, on March 26, 2015, the Bureau of Land Management (the
“BLM”) published a final rule governing hydraulic
fracturing on federal and Indian lands. Also, on November 15, 2016,
the BLM finalized a rule to reduce the flaring, venting and leaking
of methane from oil and natural gas operations on federal and
Indian lands. On March 28, 2017, President Trump signed an
executive order directing the BLM to review the above rules and, if
appropriate, to initiate a rulemaking to rescind or revise them.
Accordingly, on December 29, 2017, the BLM published a final rule
to rescind the 2015 hydraulic fracturing rule. Also, on December 8,
2017, the BLM published a final rule to suspend or delay certain
requirements of the 2016 methane rule until January 17, 2019.
Further legal challenges are expected. At this time, it is
uncertain when, or if, the rules will be implemented or modified,
and what impact they would have on our operations.
Furthermore, there
are certain governmental reviews either underway or being proposed
that focus on environmental aspects of hydraulic fracturing
practices. On December 13, 2016, the EPA released a study examining
the potential for hydraulic fracturing activities to impact
drinking water resources, finding that, under some circumstances,
the use of water in hydraulic fracturing activities can impact
drinking water resources. Also, on February 6, 2015, the EPA
released a report with findings and recommendations related to
public concern about induced seismic activity from disposal wells.
The report recommends strategies for managing and minimizing the
potential for significant injection-induced seismic events. Other
governmental agencies, including the U.S. Department of Energy, the
U.S. Geological Survey, and the U.S. Government Accountability
Office, have evaluated or are evaluating various other aspects of
hydraulic fracturing. These ongoing or proposed studies could spur
initiatives to further regulate hydraulic fracturing and could
ultimately make it more difficult or costly for us to perform
fracturing and increase our costs of compliance and doing
business.
Some
states and local jurisdictions in which we operate or hold oil and
natural gas interests have adopted or are considering adopting
regulations that could restrict or prohibit hydraulic fracturing in
certain circumstances, impose more stringent operating standards
and/or require the disclosure of the composition of hydraulic
fracturing fluids. If new or more stringent state or local legal
restrictions relating to the hydraulic fracturing process are
adopted in areas where we operate, we could incur potentially
significant added costs to comply with such requirements,
experience delays or curtailment in the pursuit of exploration,
development or production activities, and perhaps even be precluded
from drilling wells.
There
has been increasing public controversy regarding hydraulic
fracturing with regard to the use of fracturing fluids, induced
seismic activity, impacts on drinking water supplies, use of water
and the potential for impacts to surface water, groundwater and the
environment generally. A number of lawsuits and enforcement actions
have been initiated across the country implicating hydraulic
fracturing practices. If new laws or regulations that significantly
restrict hydraulic fracturing are adopted, such laws could make it
more difficult or costly for us to perform fracturing to stimulate
production from tight formations as well as make it easier for
third parties opposing the hydraulic fracturing process to initiate
legal proceedings based on allegations that specific chemicals used
in the fracturing process could adversely affect groundwater. In
addition, if hydraulic fracturing is further regulated at the
federal, state or local level, our fracturing activities could
become subject to additional permitting and financial assurance
requirements, more stringent construction specifications, increased
monitoring, reporting and recordkeeping obligations, plugging and
abandonment requirements and also to attendant permitting delays
and potential increases in costs. Such legislative changes could
cause us to incur substantial compliance costs, and compliance or
the consequences of any failure to comply by us could have a
material adverse effect on our financial condition and results of
operations. At this time, it is not possible to estimate the impact
on our business of newly enacted or potential federal, state or
local laws governing hydraulic fracturing.
Air Emissions
The
federal Clean Air Act and comparable state laws restrict emissions
of various air pollutants through permitting programs and the
imposition of other requirements. In addition, the EPA has
developed and continues to develop stringent regulations governing
emissions of toxic air pollutants at specified sources, including
oil and natural gas production. Federal and state regulatory
agencies can impose administrative, civil and criminal penalties
for non-compliance with air permits or other requirements of the
Clean Air Act and associated state laws and regulations. Our
operations, or the operations of service companies engaged by us,
may in certain circumstances and locations be subject to permits
and restrictions under these statutes for emissions of air
pollutants.
In 2012
and 2016, the EPA issued New Source Performance Standards to
regulate emissions of sources of volatile organic compounds
(“VOCs”), sulfur dioxide, air toxics and methane from
various oil and natural gas exploration, production, processing and
transportation facilities. In particular, on May 12, 2016, the EPA
amended its regulations to impose new standards for methane and VOC
emissions for certain new, modified, and reconstructed equipment,
processes, and activities across the oil and natural gas
sector. However, in a March 28, 2017 executive order,
President Trump directed the EPA to review the 2016 regulations
and, if appropriate, to initiate a rulemaking to rescind or revise
them consistent with the stated policy of promoting clean and safe
development of the nation’s energy resources, while at the
same time avoiding regulatory burdens that unnecessarily encumber
energy production. On June 16, 2017, the EPA published a proposed
rule to stay for two years certain requirements of the 2016
regulations, including fugitive emission requirements. These
standards, as well as any future laws and their implementing
regulations, may require us to obtain pre-approval for the
expansion or modification of existing facilities or the
construction of new facilities expected to produce air emissions,
impose stringent air permit requirements, or mandate the use of
specific equipment or technologies to control emissions. We
cannot predict the final regulatory requirements or the cost to
comply with such requirements with any certainty.
In
October 2015, the EPA announced that it was lowering the primary
national ambient air quality standards (“NAAQS”) for
ozone from 75 parts per billion to 70 parts per billion. The EPA
did not meet an October 2017 deadline for designating
non-attainment areas but has indicated that it continues to work
with states to make the required designations. If implemented in
the future, the changes will take place over several years;
however, the new standard could result in a significant expansion
of ozone non-attainment areas across the United States, including
areas in which we operate. Oil and natural gas operations in ozone
non-attainment areas would likely be subject to increased
regulatory burdens in the form of more stringent emission controls,
emission offset requirements, and increased permitting delays and
costs.
Climate Change
In
December 2009, the EPA issued an Endangerment Finding that
determined that emissions of carbon dioxide, methane and other
greenhouse gases (“GHGs”), present an endangerment to
public health and the environment because, according to the EPA,
emissions of such gases contribute to warming of the earth’s
atmosphere and other climatic changes. In May 2010, the EPA adopted
regulations establishing new GHG emissions thresholds that
determine when stationary sources must obtain permits under the
Prevention of Significant Deterioration, or PSD, and Title V
programs of the Clean Air Act. On June 23, 2014,
in
Utility Air Regulatory
Group v. EPA
, the Supreme Court held that stationary sources
could not become subject to PSD or Title V permitting solely by
reason of their GHG emissions. The Court ruled, however, that the
EPA may require installation of best available control technology
for GHG emissions at sources otherwise subject to the PSD and Title
V programs. On August 26, 2016, the EPA proposed changes needed to
bring EPA’s air permitting regulations in line with the
Supreme Court’s decision on GHG permitting. The proposed rule
was published in the Federal Register on October 3, 2016 and the
public comment period closed on December 2, 2016.
In
addition, the U.S. Congress has from time to time considered
adopting legislation to reduce emissions of greenhouse gases and
almost one-half of the states have already taken legal measures to
reduce emissions of greenhouse gases primarily through the planned
development of greenhouse gas emission inventories and/or regional
greenhouse gas cap and trade programs. Although the U.S. Congress
has not adopted such legislation at this time, it may do so in the
future and many states continue to pursue regulations to reduce
greenhouse gas emissions.
In
December 2015, the United States participated in the 21st
Conference of the Parties of the United Nations Framework
Convention on Climate Change in Paris, France. The resulting Paris
Agreement calls for the parties to undertake “ambitious
efforts” to limit the average global temperature, and to
conserve and enhance sinks and reservoirs of GHGs. The Agreement
went into effect on November 4, 2016. The Agreement establishes a
framework for the parties to cooperate and report actions to reduce
GHG emissions. However, on June 1, 2017, President Trump announced
that the United States would withdraw from the Paris Agreement, and
begin negotiations to either re-enter or negotiate an entirely new
agreement with more favorable terms for the United States. The
Paris Agreement sets forth a specific exit process, whereby a party
may not provide notice of its withdrawal until three years from the
effective date, with such withdrawal taking effect one year from
such notice. It is not clear what steps the Trump Administration
plans to take to withdraw from the Paris Agreement, whether a new
agreement can be negotiated, or what terms would be included in
such an agreement. Furthermore, in response to the announcement,
many state and local leaders have stated their intent to intensify
efforts to uphold the commitments set forth in the international
accord.
Restrictions on
emissions of methane or carbon dioxide that may be imposed could
adversely impact the demand for, price of and value of our products
and reserves. As our operations also emit greenhouse gases
directly, current and future laws or regulations limiting such
emissions could increase our own costs. Currently, our operations
are not adversely impacted by existing federal, state and local
climate change initiatives and, at this time, it is not possible to
accurately estimate how potential future laws or regulations
addressing greenhouse gas emissions would impact our
business.
The National Environmental Policy Act
Oil and
natural gas exploration, development and production activities on
federal lands are subject to the National Environmental Policy Act
(“NEPA”). NEPA requires federal agencies, including the
Department of the Interior, to evaluate major agency actions that
have the potential to significantly impact the environment. The
process involves the preparation of either an environmental
assessment or environmental impact statement depending on whether
the specific circumstances surrounding the proposed federal action
will have a significant impact on the human environment. The NEPA
process involves public input through comments which can alter the
nature of a proposed project either by limiting the scope of the
project or requiring resource-specific mitigation. NEPA decisions
can be appealed through the court system by process participants.
This process may result in delaying the permitting and development
of projects, increase the costs of permitting and developing some
facilities and could result in certain instances in the
cancellation of existing leases.
Threatened and endangered species, migratory birds and natural
resources
Various
federal and state statutes prohibit certain actions that adversely
affect endangered or threatened species and their habitat,
migratory birds, wetlands, and natural resources. These statutes
include the Endangered Species Act (“ESA”), the
Migratory Bird Treaty Act and the Clean Water Act. The U.S. Fish
and Wildlife Service may designate critical habitat areas that it
believes are necessary for survival of threatened or endangered
species. On February 11, 2016, the
U.S. Fish and Wildlife Service published a
final policy which alters how it identifies critical habitat
for endangered and threatened species. A critical
habitat designation could result in further material restrictions
on federal land use or on private land use and could delay or
prohibit land access or development. Where takings of or harm to
species or damages to wetlands, habitat, or natural resources occur
or may occur, government entities or at times private parties may
act to prevent or restrict oil and natural gas exploration
activities or seek damages for any injury, whether resulting from
drilling or construction or releases of oil, wastes, hazardous
substances or other regulated materials, and in some cases,
criminal penalties may result. Similar protections are offered to
migratory birds under the Migratory Bird Treaty Act. While some of
our operations may be located in areas that are designated as
habitats for endangered or
threatened species or that may attract migratory birds,
we believe that we are in substantial compliance with the ESA and
the Migratory Bird Treaty Act, and we are not aware of any proposed
ESA listings that will materially affect our operations. The
federal government in the past has issued indictments under the
Migratory Bird Treaty Act to several oil and natural gas companies
after dead migratory birds were found near reserve pits associated
with drilling activities. The identification or designation of
previously unprotected species as threatened or endangered in areas
where underlying property operations are conducted could cause us
to incur increased costs arising from species protection measures
or could result in limitations on our development activities that
could have an adverse impact on our ability to develop and produce
our oil and natural gas reserves. If we were to have a portion of
our leases designated as critical or suitable habitat, it could
adversely impact the value of our leases.
Hazard communications and community right to know
We are
subject to federal and state hazard communication and community
right to know statutes and regulations. These regulations,
including, but not limited to, the federal Emergency Planning &
Community Right-to-Know Act, govern record keeping and reporting of
the use and release of hazardous substances and may require that
information be provided to state and local government authorities,
as well as the public.
Occupational Safety and Health Act
We are
subject to the requirements of the federal Occupational Safety and
Health Act, as amended (“OSHA”), and comparable state
statutes that regulate the protection of the health and safety of
workers. In addition, OSHA hazard communication standard requires
that information be maintained about hazardous materials used or
produced in operations and that this information be provided to
employees, state and local government authorities and
citizens.
State Regulation
Texas
regulates the drilling for, and the production, gathering and sale
of, oil and natural gas, including imposing severance taxes and
requirements for obtaining drilling permits. Texas currently
imposes a 4.6% severance tax on oil production and a 7.5% severance
tax on natural gas production. States also regulate the method of
developing new fields, the spacing and operation of wells and the
prevention of waste of oil and natural gas resources. States may
regulate rates of production and may establish maximum daily
production allowables from oil and natural gas wells based on
market demand or resource conservation, or both. States do not
regulate wellhead prices or engage in other similar direct economic
regulation, but we cannot assure our stockholders that
they will not do so in the future. The effect of these regulations
may be to limit the amount of oil and natural gas that may be
produced from our wells and to limit the number of wells or
locations we can drill.
The
petroleum industry is also subject to compliance with various other
federal, state and local regulations and laws. Some of those laws
relate to resource conservation and equal employment opportunity.
We do not believe that compliance with these laws will have a
material adverse effect on us.
Related Insurance
We
maintain insurance against some risks associated with above or
underground contamination that may occur as a result of our
exploration and production activities. However, this insurance is
limited to activities at the well site, and there can be no
assurance that this insurance will continue to be commercially
available or that this insurance will be available at premium
levels that justify its purchase by us. The occurrence of a
significant event that is not fully insured or indemnified against
could have a materially adverse effect on our financial condition
and operations.
Although we have
not experienced any material adverse effect from compliance with
environmental requirements, there is no assurance that this will
continue. We did not have any material capital or other
non-recurring expenditures in connection with complying with
environmental laws or environmental remediation matters in 2017,
nor do we anticipate that such expenditures will be material in
2018.
Employees and Principal Office
As of
December 31, 2017, we had 31 full-time employees. We hire
independent contractors on an as-needed basis. We have no
collective bargaining agreements with our employees. We believe
that our employee relationships are satisfactory.
Our
principal executive office is located at 1177 West Loop South,
Suite 1825, Houston, Texas 77027, where we occupy approximately
15,180 square feet of office space. Our Bakersfield office,
consisting of approximately 4,200 square feet, is located at 2008
Twenty-First Street, Bakersfield, California 93301.
Executive Officers of the Company
The
following table sets forth the names and ages of all of our
executive officers, the positions and offices held by such persons,
and the months and years in which continuous service as executive
officers began:
|
|
Executive
|
|
|
|
|
Name
|
|
Officer Since
|
|
Age
|
|
Position
|
Sam L. Banks
|
|
October 2016
|
|
68
|
|
Director and Chief Executive Officer
|
James J. Jacobs
|
|
October 2016
|
|
40
|
|
Chief Financial Officer, Treasurer and Corporate
Secretary
|
Paul D. McKinney
|
|
October 2016
|
|
59
|
|
President and Chief Operating Officer
|
The
following paragraphs contain certain information about each of our
executive officers.
Sam L. Banks
has been our Chief
Executive Officer and a member of the Board of Directors since the
closing of the Davis Merger on October 26, 2016. He was the Chief
Executive Officer and Chairman of the Board of Directors of Yuma
California from September 10, 2014 and also our President since
October 10, 2014 through October 26, 2016. He was the Chief
Executive Officer and Chairman of the Board of Directors of The
Yuma Companies, Inc. (“Yuma Co.”) and its predecessor
since 1983. He was also the founder of Yuma Co. He has 40 years of
experience in the oil and natural gas industry, the majority of
which he has been leading Yuma Co. Prior to founding Yuma Co., he
held the position of Assistant to the President of Tomlinson
Interests, a private independent oil and gas company. Mr. Banks
graduated with a Bachelor of Arts from Tulane University in New
Orleans, Louisiana, in 1972, and in 1976 he served as Republican
Assistant Finance Chairman for the re-election of President Gerald
Ford, under former Secretary of State, Robert
Mosbacher.
James J. Jacobs
has been our Chief
Financial Officer, Treasurer and Corporate Secretary since the
closing of the Davis Merger on October 26, 2016. He was the Chief
Financial Officer, Treasurer and Corporate Secretary of Yuma
California from December 2015 through October 26, 2016. He served
as Vice President – Corporate and Business Development of
Yuma California immediately prior to his appointment as Chief
Financial Officer in December 2015 and has been with us since 2013.
He has 16 years of experience in the financial services and energy
sector. In 2001, Mr. Jacobs worked as an Energy Analyst at Duke
Capital Partners. In 2003, Mr. Jacobs worked as a Vice President of
Energy Investment Banking at Sanders Morris Harris where he
participated in capital markets financing, mergers and
acquisitions, corporate restructuring and private equity
transactions for various sized energy companies. From 2006 through
2013, Mr. Jacobs was the Chief Financial Officer, Treasurer and
Secretary at Houston America Energy Corp., where he was responsible
for financial accounting and reporting for U.S. and Colombian
operations, as well as capital raising activities. Mr. Jacobs
graduated with a Master’s Degree in Professional Accounting
and a Bachelor of Business Administration from the University of
Texas in 2001.
Paul D. McKinney
has been our Executive
Vice President and Chief Operating Officer since the closing of the
Davis Merger on October 26, 2016. He was the Executive Vice
President and Chief Operating Officer of Yuma California from
October 2014 through October 26, 2016. Mr. McKinney served as a
petroleum engineering consultant for Yuma California’s
predecessor from June 2014 to September 2014 and for Yuma
California from September 2014 to October 2014. Mr. McKinney served
as Region Vice President, Gulf Coast Onshore, for Apache
Corporation from 2010 through 2013, where he was responsible for
the development and all operational aspects of the Gulf Coast
region for Apache. Prior to his role as Region Vice President, Mr.
McKinney was Manager, Corporate Reservoir Engineering, for Apache
from 2007 through 2010. From 2006 through 2007, Mr. McKinney was
Vice President and Director, Acquisitions & Divestitures for
Tristone Capital, Inc. Mr. McKinney commenced his career with
Anadarko Petroleum Corporation and held various positions with
Anadarko over a 23 year period from 1983 to 2006, including his
last title as Vice President of Reservoir Engineering, Anadarko
Canada Corporation. Mr. McKinney currently serves on the Board of
Directors for Pro-Ject Holdings, LLC, a private oil field chemical
services company. Mr. McKinney has a Bachelor of Science degree in
Petroleum Engineering from Louisiana Tech University.
Available Information
Our
principal executive offices are located at 1177 West Loop South,
Suite 1825, Houston, Texas 77027. Our telephone number is (713)
768-7000. You can find more information about us at our website
located at www.yumaenergyinc.com. Our Annual Report on Form 10-K,
our Quarterly Reports on Form 10-Q, our Current Reports on Form 8-K
and any amendments to those reports are available free of charge on
or through our website, which is not part of this report. These
reports are available as soon as reasonably practicable after we
electronically file these materials with, or furnish them to, the
SEC. Information filed with the SEC may be read or copied at the
SEC’s Public Reference Room at 100 F Street, N.E.,
Washington, D.C. 20549. Information on operation of the Public
Reference Room may be obtained by calling the SEC at
1-800-SEC-0330. The SEC also maintains a website at www.sec.gov
that contains reports, proxy and information statements, and other
information regarding issuers that file electronically with the
SEC, including us.
We are
subject to various risks and uncertainties in the course of our
business. The following summarizes significant risks and
uncertainties that may adversely affect our business, financial
condition or results of operations. We cannot assure you that any
of the events discussed in the risk factors below will not occur.
Further, the risks and uncertainties described below are not the
only ones we face. Additional risks not presently known to us or
that we currently deem immaterial may also materially affect our
business. When considering an investment in our securities, you
should carefully consider the risk factors included below as well
as those matters referenced in this report under “Cautionary
Statement Regarding Forward-Looking Statements” and other
information included and incorporated by reference into this Annual
Report on Form 10-K.
If we are not able to access additional capital in significant
amounts, we may not be able to continue to develop our current
prospects and properties, or we may forfeit our interest in certain
prospects and we may not be able to continue to operate our
business.
We need
significant capital to continue to operate our properties and
continue operations. In the near term, we intend to finance our
capital expenditures with cash flow from operations, borrowings
under our revolving credit facility, and future issuance of debt
and/or equity securities. Our cash flow from operations and access
to capital is subject to a number of variables, including, among
others:
●
our estimated
proved oil and natural gas reserves;
●
the amount of oil
and natural gas we produce from existing wells;
●
the prices at which
we sell our production;
●
the costs of
developing and producing our oil and natural gas
reserves;
●
our ability to
acquire, locate and produce new reserves;
●
our borrowing base
and willingness of banks to lend to us; and
●
our ability to
access the equity and debt capital markets.
Our
operations and other capital resources may not provide cash in
sufficient amounts to maintain planned or future levels of capital
expenditures. Further, our actual capital expenditures in 2018
could exceed our capital expenditure budget. In the event our
capital expenditure requirements at any time are greater than the
amount of capital we have available, we could be required to seek
additional sources of capital, which may include refinancing
existing debt, joint venture partnerships, production payment
financings, sales of non-core property assets, or offerings of debt
or equity securities. We may not be able to obtain any form of
financing on terms favorable, or at all.
If we
are unable to fund our capital requirements, we may be required to
curtail our operations relating to the exploration and development
of our prospects, which in turn could lead to a possible loss of
properties and a decline in our oil and natural gas reserves, or we
may be otherwise unable to implement our development plan, complete
acquisitions or otherwise take advantage of business opportunities
or respond to competitive pressures, any of which could have a
material adverse effect on our production, revenues and results of
operations. In addition, a delay in or the failure to complete
proposed or future infrastructure projects could delay or eliminate
potential efficiencies and related cost savings. The occurrence of
such events may prevent us from continuing to operate our business
and our common stock and preferred stock may not have any
value.
Our business is highly competitive.
The oil
and natural gas industry is highly competitive in many respects,
including identification of attractive oil and natural gas
properties for acquisition, drilling and development, securing
financing for such activities and obtaining the necessary equipment
and personnel to conduct such operations and activities. In seeking
suitable opportunities, we compete with a number of other
companies, including large oil and natural gas companies and other
independent operators with greater financial resources, larger
numbers of personnel and facilities, and, in some cases, with more
expertise. There can be no assurance that we will be able to
compete effectively with these entities.
Our short-term liquidity is significantly constrained, and could
severely impact our cash flow and our development of our
properties.
Currently, our
principal sources of liquidity are cash flow from our operations
and borrowing under our credit facility. For the year ended
December 31, 2017, we had outstanding borrowing of $27.7 million
under our credit facility. As of December 31, 2017, our total
borrowing base was $40.5 million with $12.8 million of undrawn
borrowing base. Since significant amounts of capital are required
for companies to participate in the business of exploration for and
development of oil and natural gas resources, we are dependent on
improving our cash flow and revenue, as well as receipt of
additional working capital, to fund continued development and
implementation of our business plan. Adverse developments in our
business or general economic conditions may require us to raise
additional financing at prices or on terms that are disadvantageous
to existing stockholders. We may not be able to obtain additional
capital at all and may be forced to curtail or cease our
operations. We will continue to rely on equity or debt financing
and the sale of working interests to finance operations until such
time, if ever, that we generate sustained positive cash flow. The
inability to obtain necessary financing will likely adversely
impact our ability to develop our properties and to expand our
business operations.
Our credit facility has substantial restrictions and financial
covenants and our ability to comply with those restrictions and
covenants is uncertain. Our lenders can unilaterally reduce our
borrowing availability based on anticipated commodity
prices.
The
terms of our Credit Agreement require us to comply with certain
financial covenants and ratios. Our ability to comply with these
restrictions and covenants in the future is uncertain and will be
affected by the levels of cash flows from operations and events or
circumstances beyond our control. Our failure to comply with any of
the restrictions and covenants under the credit facility or other
debt agreements could result in a default under those agreements,
which could cause all of our existing indebtedness to be
immediately due and payable. Reductions in our borrowing base under
our credit facility could also arise from several factors,
including but not limited to:
●
lower commodity
prices or production;
●
increased leverage
ratios;
●
inability to drill
or unfavorable drilling results;
●
changes in oil,
natural gas and natural gas liquid reserves due to engineering
updates, or changes in engineering applications;
●
increased operating
and/or capital costs;
●
the lenders’
inability to agree to an adequate borrowing base; or
●
adverse changes in
the lenders’ practices (including required regulatory
changes) regarding estimation of reserves.
The
credit facility limits the amounts we can borrow to a borrowing
base amount, determined by the lenders in their sole discretion
based upon projected revenues from the properties securing their
loan. For example, our lenders have set our current borrowing base
at $40.5 million. Prices of crude oil below $50.00 per Bbl are
likely to have an adverse effect on our borrowing base. The lenders
can unilaterally adjust the borrowing base and the borrowings
permitted to be outstanding under the credit facility. Outstanding
borrowings in excess of the borrowing base must be repaid
immediately, or we must pledge other oil and natural gas properties
as additional collateral. We do not currently have any substantial
unpledged properties, and we may not have the financial resources
in the future to make any mandatory principal prepayments required
under the credit facility. Any inability to borrow additional funds
under our credit facility could adversely affect our operations and
our financial results, and possibly force us into bankruptcy or
liquidation.
If we are unable to comply with the restrictions and covenants in
the agreements governing our indebtedness, there would be a default
under the terms of these agreements, which could result in an
acceleration of payment of funds that we have borrowed and would
impact our ability to make principal and interest payments on our
indebtedness and satisfy our other obligations.
Any
default under the agreements governing our indebtedness, including
a default under our credit facility that is not waived by the
required lenders, and the remedies sought by the holders of any
such indebtedness, could make us unable to pay principal and
interest on our indebtedness and satisfy our other obligations. If
we are unable to generate sufficient cash flows and are otherwise
unable to obtain the funds necessary to meet required payments of
principal and interest on our indebtedness, or if we otherwise fail
to comply with the various covenants, including financial and
operating covenants, in the instruments governing our indebtedness,
we could be in default under the terms of the agreements governing
such indebtedness. In the event of such default, the holders of
such indebtedness could elect to declare all the funds borrowed
thereunder to be due and payable, together with accrued and unpaid
interest, the lenders under our credit facility could elect to
terminate their commitments, cease making further loans and
institute foreclosure proceedings against our assets, and we could
be forced into bankruptcy or liquidation. If our operating
performance declines, we may in the future need to seek to obtain
waivers from the required lenders under our credit facility to
avoid being in default and we may not be able to obtain such a
waiver. If this occurs, we would be in default under our credit
facility, the lenders could exercise their rights as described
above, and we could be forced into bankruptcy or liquidation. We
cannot assure you that we will be granted waivers or amendments to
our debt agreements if for any reason we are unable to comply with
these agreements, or that we will be able to refinance our debt on
terms acceptable to us, or at all.
Our variable rate indebtedness subjects us to interest rate risk,
which could cause our debt service obligations to increase
significantly.
Borrowings under
our credit facility bear interest at variable rates and expose us
to interest rate risk. If interest rates increase, our debt service
obligations on the variable rate indebtedness would increase
although the amount borrowed remains the same, and our net income
and cash available for servicing our indebtedness and for other
purposes would decrease.
Oil and natural gas prices are volatile. A substantial or extended
decline in commodity prices will likely adversely affect our
business, financial condition and results of operations and our
ability to meet our debt commitments, or capital expenditure
obligations and other financial commitments.
Prices
for oil, natural gas, and natural gas liquids can fluctuate widely.
For example, during the period from January 1, 2014 through
December 31, 2017, the WTI futures price for oil declined from a
high of $107.26 per Bbl on June 20, 2014 to $26.21 per Bbl on
February 11, 2016, and subsequently increased to reach a high
of $60.01 per Bbl in December 2017; and the Henry Hub futures price
for natural gas has declined from a high of $6.15 per MMBtu on
February 19, 2014 to a low of $1.64 per MMBtu on March 3,
2016, and subsequently increased to reach a high of $3.69 per MMBtu
in December 2017. Our revenues, profitability and our future growth
and the carrying value of our properties depend substantially on
prevailing oil and natural gas prices. Prices also affect the
amount of cash flow available for capital expenditures and our
ability to borrow and raise additional capital. The amount we will
be able to borrow under our Credit Agreement is subject to periodic
redetermination based in part on current oil and natural gas prices
and on changing expectations of future prices. Lower prices may
also reduce the amount of oil and natural gas that we can
economically produce and have an adverse effect on the value of our
properties.
Historically, the
markets for oil and natural gas have been volatile, and they are
likely to continue to be volatile in the future. Among the factors
that can cause volatility are:
●
the domestic and
foreign supply of, and demand for, oil and natural
gas;
●
volatility and
trading patterns in the commodity-futures markets;
●
the ability of
members of OPEC and other oil and natural gas producing countries
to agree upon and determine prices and production
levels;
●
social unrest and
political instability, particularly in major oil and natural gas
producing regions outside the United States, such as Africa and the
Middle East, and armed conflict or terrorist attacks, whether or
not in oil or natural gas producing regions;
●
the level of
overall product demand;
●
the growth of
consumer product demand in emerging markets, such as China and
India;
●
labor unrest in oil
and natural gas producing regions;
●
weather conditions,
including hurricanes and other natural occurrences that affect the
supply and/or demand of oil and natural gas;
●
the price and
availability of alternative fuels;
●
the price of
foreign imports;
●
worldwide economic
conditions; and
●
the availability of
liquid natural gas imports.
These
external factors and the resultant volatile nature of the energy
markets make it difficult to estimate future prices of oil and
natural gas.
The
long-term effect of these and other factors on the prices of oil
and natural gas is uncertain. Prolonged or significant declines in
these commodity prices may have the following effects on our
business:
●
adversely affecting
our financial condition, liquidity, ability to finance planned
capital expenditures, and results of operations;
●
reducing the amount
of oil and natural gas that we can produce
economically;
●
causing us to delay
or postpone a significant portion of our capital
projects;
●
materially reducing
our revenues, operating income, or cash flows;
●
reducing the
amounts of our estimated proved oil and natural gas
reserves;
●
forcing reductions
in the financial carrying value of our oil and natural gas
properties due to recognizing impairments of proved properties,
unproved properties and exploration assets;
●
reducing the
standardized measure of discounted future net cash flows relating
to our oil and natural gas reserves; and
●
limiting our access
to, or increasing the cost of, sources of capital such as equity
and long-term debt.
As a result of low prices for oil, natural gas and natural gas
liquids, we have taken and may be required to take significant
future write-downs of the financial carrying values of our
properties.
Accounting rules
require that we periodically review the carrying value of our
properties for possible impairment. Based on prevailing commodity
prices and specific market factors and circumstances at the time of
prospective impairment reviews, and the continuing evaluation of
development plans, production data, economics and other factors, we
have been required to, and may be required to significantly
write-down the financial carrying value of our oil and natural gas
properties, which constitutes a non-cash charge to earnings. We may
incur impairment charges in the future, which could have a material
adverse effect on our results of operations for the periods in
which such charges are recorded.
A
write-down could occur when oil and natural gas prices are low or
if we have substantial downward adjustments to our estimated proved
oil and natural gas reserves, if operating costs or development
costs increase over prior estimates, or if our drilling and
workover program is unsuccessful.
The
capitalized costs of our oil and natural gas properties subject to
amortization, net of accumulated DD&A and related deferred
taxes, are limited to the estimated future net cash flows from
proved oil and natural gas reserves, discounted at 10 percent, plus
unproved properties not subject to amortization. If the capitalized
cost of these proved properties subject to amortization exceeds
these estimated future net cash flows, we would be required to
record impairment charges to reduce the capitalized costs of our
oil and natural gas properties. These types of charges will reduce
our earnings and stockholders’ equity and could adversely
affect our stock price. Unproved properties not subject to
amortization are evaluated quarterly, and this review may result in
these properties being moved into our oil and gas properties
subject to amortization.
We
periodically assess our properties for impairment based on future
estimates of proved and non-proved reserves, oil and natural gas
prices, production rates and operating, development and reclamation
costs based on operating budget forecasts. Once incurred, an
impairment charge cannot be reversed at a later date even if price
increases of oil and/or natural gas occur and in the event of
increases in the quantity of our estimated proved
reserves.
If oil,
natural gas and natural gas liquids prices fall below current
levels for an extended period of time and all other factors remain
equal, we may incur impairment charges in the future. Such charges
could have a material adverse effect on our results of operations
for the periods in which they are recorded. See Note 5. Asset
Impairments and Note 6. Property, Plant, and Equipment, Net in the
Notes to the Consolidated Financial Statements included in this
report for additional information.
We have historically incurred losses and may not achieve
profitability in the future.
We have
incurred losses from operations during our history in the oil and
natural gas business. We had an accumulated deficit of
approximately $19.2 million as of December 31, 2017. Our ability to
be profitable in the future will depend on successfully addressing
our near-term capital needs and implementing our acquisition,
development and production activities, all of which are subject to
many risks beyond our control. Even if we become profitable on an
annual basis, our profitability may not be sustainable or increase
on a periodic basis.
Our ability to sell our production and/or receive market prices for
our production may be adversely affected by transportation capacity
constraints and interruptions.
If the
amount of oil, natural gas or natural gas liquids being produced by
us and others exceeds the capacity of the various transportation
pipelines and gathering systems available in our operating areas,
it will be necessary for new transportation pipelines and gathering
systems to be built. Or, in the case of oil and natural gas
liquids, it will be necessary for us to rely more heavily on trucks
to transport our production, which is more expensive and less
efficient than transportation via pipeline. The construction of new
pipelines and gathering systems is capital intensive and
construction may be postponed, interrupted or cancelled in response
to changing economic conditions and the availability and cost of
capital. In addition, capital constraints could limit our ability
to build gathering systems to transport our production to
transportation pipelines. In such event, costs to transport our
production may increase materially or we might have to shut in our
wells awaiting a pipeline connection or capacity and/or sell our
production at much lower prices than market or than we currently
project, which would adversely affect our results of
operations.
A
portion of our production may also be interrupted, or shut in, from
time to time for numerous other reasons, including as a result of
operational issues, mechanical breakdowns, weather conditions,
accidents, loss of pipeline or gathering system access, field labor
issues or strikes, or we might voluntarily curtail production in
response to market conditions. If a substantial amount of our
production is interrupted at the same time, it would likely
adversely affect our cash flow.
Our oil, natural gas and natural gas liquids are sold in a limited
number of geographic markets so an oversupply in any of those areas
could have a material negative effect on the price we
receive.
Our
oil, natural gas and natural gas liquids are sold in a limited
number of geographic markets and each has a fixed amount of storage
and processing capacity. As a result, if such markets become
oversupplied with oil, natural gas and/or natural gas liquids, it
could have a material negative effect on the prices we receive for
our products and therefore an adverse effect on our financial
condition and results of operations. There is a risk that refining
capacity in the U.S. Gulf Coast may be insufficient to refine all
of the light sweet crude oil being produced in the United States.
If light sweet crude oil production remains at current levels or
continues to increase, demand for our light crude oil production
could result in widening price discounts to the world crude prices
and potential shut-in or reduction of production due to a lack of
sufficient markets despite the lift on prior restrictions on the
exporting of oil and natural gas from the United
States.
Commodity derivative transactions may limit our potential gains and
increase our potential losses.
In
order to manage our exposure to price risks in the marketing of our
oil and natural gas production, we have entered into oil and
natural gas price commodity derivative arrangements with respect to
a portion of our anticipated production and we may enter into
additional commodity derivative transactions in the future. While
intended to reduce the effects of volatile commodity prices, such
transactions may limit our potential gains and increase our
potential losses if commodity prices were to rise substantially
over the price established by the commodity derivative. In
addition, such transactions may expose us to the risk of loss in
certain circumstances, including instances in which:
●
our production is
less than expected;
●
there is a widening
of price differentials between delivery points for our production;
or
●
the counterparties
to our commodity derivative agreements fail to perform under the
contracts.
Derivatives reform legislation and related regulations could have
an adverse effect on our ability to hedge risks associated with our
business.
The
Dodd-Frank Wall Street Reform and Consumer Protection Act (the
“Dodd-Frank Act”) provides for federal oversight of the
over-the-counter derivatives market and entities that participate
in that market and mandates that the Commodity Futures Trading
Commission (the “CFTC”), the SEC, and federal
regulators of financial institutions adopt rules or regulations
implementing the Dodd-Frank Act and providing definitions of terms
used in the Dodd-Frank Act.
The
CFTC has finalized other regulations implementing the Dodd-Frank
Act’s provisions regarding trade reporting, margin, clearing
and trade execution; however, some regulations remain to be
finalized and it is not possible at this time to predict when the
CFTC will adopt final rules. For example, the CFTC has re-proposed
regulations setting position limits for certain futures and option
contracts in the major energy markets and for swaps that are their
economic equivalents. Certain bona fide commodity derivative
transactions are expected to be made exempt from these limits.
Also, it is possible that under recently adopted margin rules, some
registered swap dealers may require us to post initial and
variation margins in connection with certain swaps not subject to
central clearing.
The
Dodd-Frank Act and any additional implementing regulations could
significantly increase the cost of some commodity derivative
contracts (including through requirements to post collateral, which
could adversely affect our available liquidity), materially alter
the terms of some commodity derivative contracts, limit our ability
to trade some derivatives to hedge risks, reduce the availability
of some derivatives to protect against risks we encounter, and
reduce our ability to monetize or restructure our existing
commodity derivative contracts. If we reduce our use of derivatives
as a consequence, our results of operations may become more
volatile and our cash flows may be less predictable, which could
adversely affect our ability to plan for and fund capital
expenditures. Increased volatility may make us less attractive to
certain types of investors. Finally, the Dodd-Frank Act was
intended, in part, to reduce the volatility of oil and natural gas
prices, which some legislators attributed to speculative trading in
derivatives and commodity instruments related to oil and natural
gas. If the implementing regulations result in lower commodity
prices, our revenues could be adversely affected. Any of these
consequences could adversely affect our business, financial
condition and results of operations.
We may not be able to drill wells on a substantial portion of our
leasehold acreage.
We may
not be able to drill on a substantial portion of our acreage for
various reasons. We may not generate or be able to raise sufficient
capital to do so. Deterioration in commodities prices may also make
drilling certain acreage uneconomic. Our actual drilling activities
and future drilling budget will depend on prior drilling results,
oil and natural gas prices, the availability and cost of capital,
drilling and production costs, availability of drilling services
and equipment, lease expirations, gathering system and pipeline
transportation constraints, regulatory approvals and other factors.
In addition, any drilling activities we are able to conduct may not
be successful or add additional proved reserves to our overall
proved reserves, which could have a material adverse effect on our
business, financial condition and results of
operations.
Approximately 37.8% of our net leasehold acreage is undeveloped and
that acreage may not ultimately be developed or become commercially
productive, which could cause us to lose rights under our leases as
well as have a material adverse effect on our oil and natural gas
reserves and future production and, therefore, our future cash flow
and income.
As of
December 31, 2017, approximately 37.8% of our net leasehold acreage
was undeveloped, or acreage on which wells have not been drilled or
completed to a point that would permit the production of commercial
quantities of oil and natural gas regardless of whether such
acreage contains proved reserves. Unless production is established
on the undeveloped acreage covered by our leases, such
leases will expire. Our future oil and natural gas reserves
and production and, therefore, our future cash flow and income, are
highly dependent on successfully developing our undeveloped
leasehold acreage. We may also lose the right to claim certain
proved undeveloped reserves in our engineering and financial
reports if we cannot demonstrate the probability of developing
those reserves within prescribed time frames, usually within five
years.
Further,
to the extent we determine that it is not economic to develop
particular undeveloped acreage; we may intentionally
allow leases to expire.
Unless we replace our reserves with new reserves and develop those
reserves, our production and estimated reserves will decline, which
may adversely affect our financial condition, results of operations
and/or future cash flows.
Producing oil and
natural gas reservoirs are generally characterized by declining
production rates that may vary depending upon reservoir
characteristics and other factors. Decline rates are typically
greatest early in the productive life of a well, particularly
horizontal wells. Estimates of the decline rate of an oil or
natural gas well are inherently imprecise and may be less precise
with respect to new or emerging oil and natural gas formations with
limited production histories than for more developed formations
with established production histories. Our production levels and
the reserves that we currently expect to recover from our wells
will change if production from our existing wells declines in a
different manner than we have estimated and can change under other
circumstances. Unless we conduct successful ongoing acquisition and
development activities or continually acquire properties containing
proved reserves, our proved reserves will decline as those reserves
are produced. Thus, our estimated future oil and natural gas
reserves and production and, therefore, our cash flows and results
of operations are highly dependent upon our success in efficiently
developing and exploiting our current reserves and economically
finding or acquiring additional recoverable reserves. We may not be
able to develop, find or acquire additional reserves to replace our
current and future production at acceptable costs. If we are unable
to replace our current and future production, our cash flows and
the value of our reserves will decrease, adversely affecting our
business, financial condition and results of
operations.
Estimates of proved oil and natural gas reserves involve
assumptions and any material inaccuracies in these assumptions will
materially affect the quantities and the value of those
reserves.
This
report contains estimates of our proved oil and natural gas
reserves. These estimates are based upon various assumptions,
including assumptions required by SEC regulations relating to oil
and natural gas prices, drilling and operating expenses, capital
expenditures, taxes and availability of funds. The process of
estimating oil and natural gas reserves is complex and requires
significant decisions, complex analyses and assumptions in
evaluating available geological, geophysical, engineering and
economic data for each reservoir. Therefore, these estimates are
inherently imprecise.
Our
actual future production, oil and natural gas prices, revenues,
taxes, development expenditures, operating expenses and quantities
of recoverable oil and natural gas reserves will vary from those
estimated. Any significant variance will likely materially affect
the estimated quantities and the estimated value of our reserves.
In addition, we may later adjust estimates of proved reserves to
reflect production history, results of exploration and development
activities, prevailing oil and natural gas prices and other
factors, many of which are beyond our control.
Quantities of
estimated proved reserves are based on economic conditions in
existence during the period of assessment. Changes to oil, natural
gas and natural gas liquids prices in the markets for these
commodities may shorten the economic lives of certain fields
because it may become uneconomical to produce all recoverable
reserves in such fields, which may reduce proved reserves
estimates.
Negative revisions
in the estimated quantities of proved reserves have the effect of
increasing the rates of depletion on the affected properties, which
decrease earnings or result in losses through higher depletion
expense. These revisions, as well as revisions in the assumptions
of future estimated cash flows of those reserves, may also trigger
impairment losses on certain properties, which may result in
non-cash charges to earnings. See Note 6 – Property, Plant,
and Equipment, Net in the Notes to the Consolidated Financial
Statements included in this report.
At
December 31, 2017, approximately 17.1% of our estimated reserves
were classified as proved undeveloped. Recovery of proved
undeveloped reserves requires significant capital expenditures and
successful drilling operations. The reserve data assumes that we
will make significant capital expenditures to develop our reserves.
The estimates of these oil, natural gas and natural gas liquids
reserves and the costs associated with development of these
reserves have been prepared in accordance with SEC regulations;
however, actual capital expenditures will likely vary from
estimated capital expenditures, development may not occur as
scheduled and actual results may not be as estimated.
The standardized measure of discounted future net cash flows from
our estimated proved reserves may not be the same as the current
market value of our estimated oil and natural gas
reserves.
You
should not assume that the standardized measure of discounted
future net cash flows from our estimated proved reserves set forth
in this report is the current market value of our estimated oil and
natural gas reserves. In accordance with SEC requirements in effect
at December 31, 2017 and 2016, we based the discounted future net
cash flows from our proved reserves on the 12-month
first-day-of-the-month oil and natural gas arithmetic average
prices without giving effect to derivative transactions. Actual
future net cash flows from our oil and natural gas properties will
be affected by factors such as:
●
actual prices we
receive for oil and natural gas;
●
actual cost of
development and production expenditures;
●
the amount and
timing of actual production; and
●
changes in
governmental regulations or taxation.
The
timing of both our production and incurring expenses related to
developing and producing oil and natural gas properties will affect
the timing and amount of actual future net revenues from proved
reserves, and thus their actual present value. In addition, the 10%
discount factor we use when calculating standardized measure may
not be the most appropriate discount factor based on interest rates
in effect from time to time and risks associated with our business
or the oil and natural gas industry in general. As a corporation,
we are treated as a taxable entity for statutory income tax
purposes and our future income taxes will be dependent on our
future taxable income. Actual future prices and costs may differ
materially from those used in the estimates included in this report
which could have a material effect on the value of our estimated
reserves.
Our oil and natural gas activities are subject to various risks
which are beyond our control.
Our
operations are subject to many risks and hazards incident to
exploring and drilling for, producing, transporting, marketing and
selling oil and natural gas. Although we may take precautionary
measures, many of these risks and hazards are beyond our control
and unavoidable under the circumstances. Many of these risks or
hazards could materially and adversely affect our revenues and
expenses, the ability of certain of our wells to produce oil and
natural gas in commercial and economic quantities, the rate of
production and the economics of the development of, and our
investment in the prospects in which we have or will acquire an
interest. Any of these risks and hazards could materially and
adversely affect our financial condition, results of operations and
cash flows. Such risks and hazards include:
●
human error,
accidents, labor force issues and other factors beyond our control
that may cause personal injuries or death to persons and
destruction or damage to equipment and facilities;
●
blowouts, fires,
hurricanes, pollution and equipment failures that may result in
damage to or destruction of wells, producing formations, production
facilities and equipment and increased drilling and production
costs;
●
unavailability of
materials and equipment;
●
engineering and
construction delays;
●
unanticipated
transportation costs and infrastructure delays;
●
unfavorable weather
conditions;
●
hazards resulting
from unusual or unexpected geological or environmental
conditions;
●
environmental
regulations and requirements;
●
accidental leakage
of toxic or hazardous materials, such as petroleum liquids,
drilling fluids or salt water, into the environment;
●
hazards resulting
from the presence of hydrogen sulfide or other contaminants in
natural gas we produce;
●
changes in laws and
regulations, including laws and regulations applicable to oil and
natural gas activities or markets for the oil and natural gas
produced;
●
fluctuations in
supply and demand for oil and natural gas causing variations of the
prices we receive for our oil and natural gas production;
and
●
the availability of
alternative fuels and the price at which they become
available.
As a
result of these risks, expenditures, quantities and rates of
production, revenues and operating costs may be materially affected
and may differ materially from those anticipated by
us.
The unavailability or high cost of drilling rigs, pressure pumping
equipment and crews, other equipment, supplies, water, personnel
and oilfield services could adversely affect our ability to execute
our exploration and development plans on a timely basis and within
our budget.
The oil
and natural gas industry is cyclical and, from time to time, there
have been shortages of drilling rigs, equipment, supplies, water or
qualified personnel. During these periods, the costs and delivery
times of rigs, equipment and supplies are substantially greater. In
addition, the demand for, and wage rates of, qualified drilling rig
crews rise as the number of active rigs in service increases.
Increasing levels of exploration and production may increase the
demand for oilfield services and equipment, and the costs of these
services and equipment may increase, while the quality of these
services and equipment may suffer. The unavailability or high cost
of drilling rigs, pressure pumping equipment, supplies or qualified
personnel can materially and adversely affect our operations and
profitability.
Our exploration and development drilling efforts and the operation
of our wells may not be profitable or achieve our targeted
returns.
We have
acquired significant amounts of unproved property in order to
further our development efforts and expect to continue to undertake
acquisitions in the future. Development and exploratory drilling
and production activities are subject to many risks, including the
risk that no commercially productive reservoirs will be discovered.
We acquire unproved properties and lease undeveloped acreage that
we believe will enhance our growth potential and increase our
results of operations over time. However, we cannot assure you that
all prospects will be economically viable or that we will not
abandon our leaseholds. Additionally, we cannot assure you that
unproved property acquired by us or undeveloped acreage leased by
us will be profitably developed, that wells drilled by us in
prospects that we pursue will be productive or that we will recover
all or any portion of our investment in such unproved property or
wells.
In
addition, we may not be successful in controlling our drilling and
production costs to improve our overall return. The cost of
drilling, completing and operating a well is often uncertain and
cost factors can adversely affect the economics of a project. We
cannot predict the cost of drilling and completing a well, and we
may be forced to limit, delay or cancel drilling operations as a
result of a variety of factors, including:
●
unexpected drilling
conditions;
●
downhole and well
completion difficulties;
●
pressure or
irregularities in formations;
●
equipment failures
or breakdowns, or accidents and shortages or delays in the
availability of drilling and completion equipment and
services;
●
fires, explosions,
blowouts and surface cratering;
●
adverse weather
conditions, including hurricanes; and
●
compliance with
governmental requirements.
We participate in oil and natural gas leases with third parties who
may not be able to fulfill their commitments to our
projects.
In some
cases, we operate but own less than 100% of the working interest in
the oil and natural gas leases on which we conduct operations, and
other parties own the remaining portion of the working interest.
Financial risks are inherent in any operation where the cost of
drilling, equipping, completing and operating wells is shared by
more than one person. We could be held liable for joint activity
obligations of other working interest owners, such as nonpayment of
costs and liabilities arising from the actions of other working
interest owners. In addition, declines in oil and natural gas
prices may increase the likelihood that some of these working
interest owners, particularly those that are smaller and less
established, are not able to fulfill their joint activity
obligations. A partner may be unable or unwilling to pay its share
of project costs, and, in some cases, a partner may declare
bankruptcy. In the event any of our project partners do not pay
their share of such costs, we would likely have to pay those costs,
and we may be unsuccessful in any efforts to recover these costs
from our partners, which could materially adversely affect our
financial position.
We depend on the skill, ability and decisions of third-party
operators of the oil and natural gas properties in which we have a
non-operated working interest.
The
success of the drilling, development and production of the oil and
natural gas properties in which we have or expect to have a
non-operating working interest is substantially dependent upon the
decisions of such third-party operators and their diligence to
comply with various laws, rules and regulations affecting such
properties. The success and timing of our drilling, development and
production activities on such properties operated by third-parties
therefore depends upon a number of factors, including:
●
timing and amount
of capital expenditures;
●
the
operator’s expertise and financial
resources;
●
the rate of
production of reserves, if any;
●
approval of other
participants in drilling wells; and
●
selection of
technology.
The
failure of third-party operators to make decisions, perform their
services, discharge their obligations, deal with regulatory
agencies, and comply with laws, rules and regulations, including
environmental laws and regulations in a proper manner with respect
to properties in which we have an interest could result in material
adverse consequences to our interest in such properties, including
substantial penalties and compliance costs. Such adverse
consequences could result in substantial liabilities to us or
reduce the value of our properties, which could materially affect
our results of operations. As a result, our ability to
exercise influence over the operations of some of our current or
future properties is and may be limited.
Our use of seismic data is subject to interpretation and may not
accurately identify the presence of oil and natural gas, which
could adversely affect the results of our drilling
operations.
We
design and generate in-house 3-D seismic survey programs on many of
our projects. We may use seismic studies to assist with assessing
prospective drilling opportunities on current properties, as well
as on properties that we may acquire. Such seismic studies are
merely an interpretive tool and do not necessarily guarantee that
hydrocarbons are present or if present will produce in economic
quantities. In addition, the use of 3-D seismic and other advanced
technologies requires greater pre-drilling expenditures than
traditional drilling strategies and we could incur losses as a
result of such expenditures. As a result, our drilling activities
may not be successful or economical.
A component of our growth may come through acquisitions, and our
failure to identify or complete future acquisitions successfully
could reduce our earnings and slow our growth.
In
assessing potential acquisitions, we consider information available
in the public domain and information provided by the seller. In the
event publicly available data is limited, then, by necessity, we
may rely to a large extent on information that may only be
available from the seller, particularly with respect to drilling
and completion costs and practices, geological, geophysical and
petrophysical data, detailed production data on existing wells, and
other technical and cost data not available in the public domain.
Accordingly, the review and evaluation of businesses or properties
to be acquired may not uncover all existing or relevant data,
obligations or actual or contingent liabilities that could
adversely impact any business or property to be acquired and,
hence, could adversely affect us as a result of the acquisition.
These issues may be material and could include, among other things,
unexpected environmental liabilities, title defects, unpaid
royalties, taxes or other liabilities. If we acquire properties on
an “as-is” basis, we may have limited or no remedies
against the seller with respect to these types of
problems.
The
success of any acquisition that we complete will depend on a
variety of factors, including our ability to accurately assess the
reserves associated with the acquired properties, assumptions
related to future oil and natural gas prices and operating costs,
potential environmental and other liabilities and other factors.
These assessments are often inexact and subjective. As a result, we
may not recover the purchase price of a property from the sale of
production from the property or recognize an acceptable return from
such sales or operations.
Our
ability to achieve the benefits that we expect from an acquisition
will also depend on our ability to efficiently integrate the
acquired operations. Management may be required to dedicate
significant time and effort to the integration process, which could
divert its attention from other business opportunities and
concerns. The challenges involved in the integration process may
include retaining key employees and maintaining employee morale,
addressing differences in business cultures, processes and systems
and developing internal expertise regarding acquired
properties.
We are subject to complex federal, state, local and other laws and
regulations that from time to time are amended to impose more
stringent requirements that could adversely affect the cost, manner
or feasibility of doing business.
Companies that
explore for and develop, produce, sell and transport oil and
natural gas in the United States are subject to extensive federal,
state and local laws and regulations, including complex tax and
environmental, health and safety laws and the corresponding
regulations, and are required to obtain various permits and
approvals from federal, state and local agencies. If these permits
are not issued or unfavorable restrictions or conditions are
imposed on our drilling activities, we may not be able to conduct
our operations as planned. We may be required to make large
expenditures to comply with governmental regulations. Matters
subject to regulation include:
●
water discharge and
disposal permits for drilling operations;
●
reports concerning
operations;
●
air quality, air
emissions, noise levels and related permits;
●
rights-of-way and
easements;
●
unitization and
pooling of properties;
●
gathering,
transportation and marketing of oil and natural gas;
●
waste and water
transport and disposal permits and requirements.
Failure
to comply with applicable laws may result in the suspension or
termination of operations and subject us to liabilities, including
administrative, civil and criminal penalties. Compliance costs can
be significant. Moreover, the laws governing our operations or the
enforcement thereof could change in ways that substantially
increase the costs of doing business. Any such liabilities,
penalties, suspensions, terminations or regulatory changes could
materially and adversely affect our business, financial condition
and results of operations.
Under
environmental, health and safety laws and regulations, we also
could be held liable for personal injuries, property damage
(including site clean-up and restoration costs) and other damages
including the assessment of natural resource damages. Such laws may
impose strict as well as joint and several liability for
environmental contamination, which could subject us to liability
for the conduct of others or for our own actions that were in
compliance with all applicable laws at the time such actions were
taken. Environmental and other governmental laws and regulations
also increase the costs to plan, design, drill, install, operate
and abandon oil and natural gas wells. Moreover, public interest in
environmental protection has increased in recent years, and
environmental organizations have opposed, with some success,
certain drilling projects. Part of the regulatory environment in
which we operate includes, in some cases, federal requirements for
performing or preparing environmental assessments, environmental
impact studies and/or plans of development before commencing
exploration and production activities.
In
addition, our activities are subject to regulation by oil and
natural gas-producing states relating to conservation practices and
protection of correlative rights. These regulations affect our
operations and limit the quantity of oil and natural gas we may
produce and sell. Delays in obtaining regulatory approvals or
necessary permits, the failure to obtain a permit or the receipt of
a permit with excessive conditions or costs could have a material
adverse effect on our ability to explore on, develop or produce our
properties. The oil and natural gas regulatory environment could
change in ways that might substantially increase the financial and
managerial costs to comply with the requirements of these laws and
regulations and, consequently, adversely affect our results of
operations and financial condition.
Federal, state and local legislation and regulatory initiatives
relating to hydraulic fracturing could result in increased costs
and additional operating restrictions or delays.
We
engage third parties to provide hydraulic fracturing or other well
stimulation services to us in connection with many of the wells for
which we are the operator. Federal, state and local governments
have been adopting or considering restrictions on or prohibitions
of fracturing in areas where we currently conduct operations, or in
the future plan to conduct operations. Consequently, we could be
subject to additional levels of regulation, operational delays or
increased operating costs and could have additional regulatory
burdens imposed upon us that could make it more difficult to
perform hydraulic fracturing and increase our costs of compliance
and doing business.
From
time to time, for example, legislation has been proposed in
Congress to amend the federal Safe Drinking Water Act
(“SDWA”) to require federal permitting of hydraulic
fracturing and the disclosure of chemicals used in the hydraulic
fracturing process. Further, the EPA completed a study finding that
hydraulic fracturing could potentially harm drinking water
resources under adverse circumstances such as injection directly
into groundwater or into production wells lacking mechanical
integrity. Other governmental reviews have also been recently
conducted or are under way that focus on environmental aspects of
hydraulic fracturing. For example, a BLM rulemaking for hydraulic
fracturing practices on federal and Indian lands resulted in a
March 2015 final rule that requires public disclosure of chemicals
used in hydraulic fracturing, confirmation that the wells used in
fracturing operations meet proper construction standards and
development of plans for managing related flowback water. In June
2016, a federal district court judge in Wyoming struck down the
final rule, finding that the BLM lacked congressional authority to
promulgate the rule. The BLM appealed that ruling. However, in July
2017, the BLM initiated a rulemaking to rescind the final rule and
reinstate the regulations that existed immediately before the
published effective date of the rule. In light of the BLM’s
proposed rulemaking, in September 2017, the U.S. Court of Appeals
for the Tenth Circuit dismissed the appeal and remanded with
directions to vacate the lower court’s opinion, leaving the
final rule in place. On December 29, 2017, the BLM published a
final rule rescinding the March 2015 final rule. Further,
legislation to amend the SDWA to repeal the exemption for hydraulic
fracturing (except when diesel fuels are used) from the definition
of “underground injection” and require federal
permitting and regulatory control of hydraulic fracturing, as well
as legislative proposals to require disclosure of the chemical
constituents of the fluids used in the fracturing process, have
been proposed in recent sessions of Congress. Several states and
local jurisdictions in which we operate also have adopted or are
considering adopting regulations that could restrict or prohibit
hydraulic fracturing in certain circumstances, impose more
stringent operating standards and/or require the disclosure of the
composition of hydraulic fracturing fluids.
More
recently, federal and state governments have begun investigating
whether the disposal of produced water into underground injection
wells has caused increased seismic activity in certain areas. For
example, in December 2016, the EPA released its final report
regarding the potential impacts of hydraulic fracturing on drinking
water resources, concluding that “water cycle”
activities associated with hydraulic fracturing may impact drinking
water resources under certain circumstances such as water
withdrawals for fracturing in times or areas of low water
availability, surface spills during the management of fracturing
fluids, chemicals or produced water, injection of fracturing fluids
into wells with inadequate mechanical integrity, injection of
fracturing fluids directly into groundwater resources, discharge of
inadequately treated fracturing wastewater to surface waters, and
disposal or storage of fracturing wastewater in unlined pits. The
results of these studies could lead federal and state governments
and agencies to develop and implement additional
regulations.
The
proliferation of regulations may limit our ability to operate. If
the use of hydraulic fracturing is limited, prohibited or subjected
to further regulation, these requirements could delay or
effectively prevent the extraction of oil and natural gas from
formations which would not be economically viable without the use
of hydraulic fracturing. This could have a material adverse effect
on our business, financial condition, results of operations and
cash flows.
Climate change legislation or regulations restricting emissions of
“greenhouse gases” could result in increased operating
costs and reduced demand for the oil, natural gas and natural gas
liquids we produce.
Studies
over recent years have indicated that emissions of certain gases
may be contributing to warming of the Earth’s atmosphere. In
response, increasingly governments have been adopting domestic and
international climate change regulations that require reporting and
reductions of the emission of such greenhouse gases. Methane, a
primary component of natural gas, and carbon dioxide, a byproduct
of burning oil, natural gas and refined petroleum products, are
considered greenhouse gases. Internationally, the United Nations
Framework Convention on Climate Change, the Kyoto Protocol and the
Paris Agreement address greenhouse gas emissions, and international
negotiations over climate change and greenhouse gases are
continuing. Meanwhile, several countries, including those
comprising the European Union, have established greenhouse gas
regulatory systems.
In the
United States, many states, either individually or through
multi-state regional initiatives, have begun implementing legal
measures to reduce emissions of greenhouse gases, primarily through
emission inventories, emission targets, greenhouse gas cap and
trade programs or incentives for renewable energy generation, while
others have considered adopting such greenhouse gas
programs.
At the
federal level, the Obama Administration pledged for the Paris
Agreement to meet an economy-wide target in 2025 of reducing
greenhouse gas emissions by 26-28% below the 2005 level. To help
achieve these reductions, federal agencies have been addressing
climate change through a variety of administrative actions. The
EPA thus issued greenhouse gas monitoring and reporting
regulations that cover oil and natural gas facilities, among other
industries. Beyond measuring and reporting, the EPA issued an
“Endangerment Finding” under Section 202(a) of the
Clean Air Act, concluding certain greenhouse gas pollution
threatens the public health and welfare of current and future
generations. The finding served as the first step to issuing
regulations that require permits for and reductions in greenhouse
gas emissions for certain facilities. In March 2014, moreover, then
President Obama released a Strategy to Reduce Methane Emissions
that included consideration of both voluntary programs and targeted
regulations for the oil and natural gas sector. Consistent with
that strategy, the EPA issued final rules in 2016 for new and
modified oil and natural gas production sources (including
hydraulically fractured oil wells, natural gas well sites, natural
gas processing plants, natural gas gathering and boosting stations
and natural gas transmission sources) to reduce emissions of
methane as well as volatile organic compound and toxic pollutants.
However, in May 2017 the EPA temporarily stayed implementing
portions of the new rule and in June 2017 proposed a two year stay
of new requirements, and more recently the head of the EPA has
announced the current administration's intent to roll back or
repeal most, if not all, of the Obama administration's regulations
restricting future greenhouse gas emissions. In June 2017,
President Trump announced that the United States intends to
withdraw from the Paris Agreement and to seek negotiations either
to reenter the Paris Agreement on different terms or a separate
agreement. In August 2017, the U.S. Department of State officially
informed the United Nations of the intent of the United States to
withdraw from the Paris Agreement. The Paris Agreement provides for
a four-year exit process beginning when it took effect in November
2016, which would result in an effective exit date of November
2020. The United States’ adherence to the exit process and/or
the terms on which the United States may re-enter the Paris
Agreement or a separately negotiated agreement are unclear at this
time.
In the
courts, several decisions have been issued that may increase the
risk of claims being filed by governments and private parties
against companies that have significant greenhouse gas emissions.
Such cases may seek to challenge air emissions permits that
greenhouse gas emitters apply for and seek to force emitters to
reduce their emissions or seek damages for alleged climate change
impacts to the environment, people, and property.
The
direction of future U.S. climate change regulation is difficult to
predict given the current uncertainties surrounding the policies of
the Trump Administration. The EPA may or may not continue
developing regulations to reduce greenhouse gas emissions from the
oil and natural gas industry. Even if federal efforts in this area
slow, states may continue pursuing climate regulations. Any laws or
regulations that may be adopted to restrict or reduce emissions of
greenhouse gases could require us to incur additional operating
costs, such as costs to purchase and operate emissions controls, to
obtain emission allowances or to pay emission taxes, and reduce
demand for our oil and natural gas.
Our operations are substantially dependent on the availability, use
and disposal of water. New legislation and regulatory initiatives
or restrictions relating to water disposal wells could have a
material adverse effect on our future business, financial
condition, operating results and prospects.
Water
is an essential component of our drilling and hydraulic fracturing
processes. If we are unable to obtain water to use in our
operations from local sources, we may be unable to economically
produce oil, natural gas and natural gas liquids, which could have
an adverse effect on our business, financial condition and results
of operations. Wastewaters from our operations typically are
disposed of via underground injection. Some studies have linked
earthquakes in certain areas to underground injection, which is
leading to greater public scrutiny of disposal wells. Any new
environmental initiatives or regulations that restrict injection of
fluids, including, but not limited to, produced water, drilling
fluids and other wastes associated with the exploration,
development or production of oil and natural gas, or that limit the
withdrawal, storage or use of surface water or ground water
necessary for hydraulic fracturing of our wells, could increase our
operating costs and cause delays, interruptions or cessation of our
operations, the extent of which cannot be predicted, and all of
which would have an adverse effect on our business, financial
condition, results of operations and cash flows.
We may incur more taxes and certain of our projects may become
uneconomic if certain federal income tax deductions currently
available with respect to oil and natural gas exploration and
development are eliminated as a result of future
legislation.
In past
years, legislation has been proposed that would, if enacted into
law, make significant changes to U.S. tax laws, including to
certain key U.S. federal income tax provisions currently available
to oil and natural gas exploration, development and production
companies. Such legislative changes have included, but not limited
to, (i) the repeal of the percentage depletion allowance for
oil and natural gas properties, (ii) the elimination of
current deductions for intangible drilling and development costs,
(iii) the elimination of the deduction for certain domestic
production activities, and (iv) an extension of the
amortization period for certain geological and geophysical
expenditures. The Tax Cuts and Jobs Act of 2017 (the
“TCJA”) did not directly affect deductions currently
available to the oil and natural gas industry but any future
changes in U.S. federal income tax laws could eliminate or postpone
certain tax deductions that currently are available with respect to
oil and natural gas development, or increase costs, and any such
changes could have an adverse effect on our financial position,
results of operations and cash flows.
The recently passed comprehensive tax reform bill could adversely
affect our business and financial condition.
On
December 22, 2017, President Trump signed into law the TCJA
that significantly changes the federal income taxation of business
entities. The TCJA, among other things, reduces the corporate
income tax rate to 21%, partially limits the deductibility of
business interest expense and net operating losses, imposes a
one-time tax on unrepatriated earnings from certain foreign
subsidiaries, taxes offshore earnings at reduced rates regardless
of whether they are repatriated and allows the immediate deduction
of certain capital expenditures instead of deductions for
depreciation expense over time. We are still evaluating the overall
impact of the TCJA to us. Notwithstanding the reduction in the
corporate income tax rate, we cannot yet conclude that the overall
impact of the TCJA to us is positive.
Title to the properties in which we have an interest may be
impaired by title defects.
We
generally obtain title opinions on significant properties that we
drill or acquire. However, there is no assurance that we will not
suffer a monetary loss from title defects or title failure.
Additionally, undeveloped acreage has greater risk of title defects
than developed acreage. Generally, under the terms of the operating
agreements affecting our properties, any monetary loss is to be
borne by all parties to any such agreement in proportion to their
interests in such property. If there are any title defects or
defects in assignment of leasehold rights in properties in which we
hold an interest, we will suffer a financial loss.
We cannot be certain that the insurance coverage maintained by us
will be adequate to cover all losses that may be sustained in
connection with all oil and natural gas activities.
We
maintain general and excess liability policies, which we consider
to be reasonable and consistent with industry standards. These
policies generally cover:
●
third party
property damage;
●
pollution in some
cases;
●
well blowouts in
some cases; and
As is
common in the oil and natural gas industry, we will not insure
fully against all risks associated with our business either because
such insurance is not available or because we believe the premium
costs are prohibitive. A loss not fully covered by insurance could
have a material effect on our financial position, results of
operations and cash flows. There can be no assurance that the
insurance coverage that we maintain will be sufficient to cover
claims made against us in the future.
Red Mountain Capital Partners LLC and its affiliates (“Red
Mountain”) hold 22% of the voting power of our outstanding
shares which gives Red Mountain a significant interest in the
Company.
Red
Mountain holds approximately 22% of our outstanding shares of
common stock on an as-converted basis. Accordingly, Red Mountain
has the ability to exert a significant degree of influence over our
management and affairs and, as a practical matter, will
significantly influence corporate actions requiring stockholder
approval, irrespective of how our other stockholders may vote,
including the election of directors, amendments to our certificate
of incorporation and bylaws, and the approval of mergers and other
significant corporate transactions, including a sale of
substantially all of our assets, and Red Mountain may vote its
shares in a manner that is adverse to the interests of our minority
stockholders. For example, Red Mountain may be able to prevent a
merger or similar transaction, including a transaction in which
stockholders will receive a premium for their shares, even if our
other stockholders are in favor of such transaction. Further, Red
Mountain’s position might adversely affect the market price
of our common stock to the extent investors perceive disadvantages
in owning shares of a company with a significant
stockholder.
A cyber incident could result in information theft, data
corruption, operational disruption and/or financial
loss.
The oil
and natural gas industry has become increasingly dependent on
digital technologies to conduct day-to-day operations including
certain exploration, development and production activities. For
example, software programs are used to interpret seismic data,
manage drilling rigs, production equipment and gathering and
transportation systems, as well as conduct reservoir modeling and
reserve estimation for compliance reporting.
We are
dependent on digital technologies including information systems and
related infrastructure, to process and record financial and
operating data, communicate with our employees, business partners,
and stockholders, analyze seismic and drilling information,
estimate quantities of oil and natural gas reserves as well as
other activities related to our business. Our business partners,
including vendors, service providers, purchasers of our production
and financial institutions are also dependent on digital
technology. The technologies needed to conduct oil and natural gas
exploration, development and production activities make certain
information the target of theft or misappropriation.
As
dependence on digital technologies has increased, cyber incidents,
including deliberate attacks or unintentional events, have also
increased. A cyber-attack could include gaining unauthorized access
to digital systems for the purposes of misappropriating assets or
sensitive information, corrupting data, causing operational
disruption, or result in denial-of-service on
websites.
Our
technologies, systems, networks, and those of our business partners
may become the target of cyber-attacks or information security
breaches that could result in the unauthorized release, gathering,
monitoring, misuse, loss or destruction of proprietary and other
information, or other disruption of our business operations. In
addition, certain cyber incidents, such as surveillance, may remain
undetected for an extended period of time. A cyber incident
involving our information systems and related infrastructure, or
that of our business partners, could disrupt our business plans and
negatively impact our operations.
We may not be able to keep pace with technological developments in
the industry.
The oil
and natural gas industry is characterized by rapid and significant
technological advancements and introductions of new products and
services using new technologies. As others use or develop new
technologies, we may be placed at a competitive disadvantage or
competitive pressures may force us to implement those new
technologies at substantial costs. In addition, other oil and
natural gas companies may have greater financial, technical, and
personnel resources that allow them to enjoy technological
advantages and may in the future allow them to implement new
technologies before we are in a position to do so. We may not be
able to respond to these competitive pressures and implement new
technologies on a timely basis or at an acceptable cost. If one or
more of the technologies used now or in the future were to become
obsolete or if we are unable to use the most advanced commercially
available technology, the business, financial condition, and
results of operations could be materially adversely
affected.
Terrorist attacks aimed at energy operations could adversely affect
our business.
The
continued threat of terrorism and the impact of military and other
government action have led and may lead to further increased
volatility in prices for oil and natural gas and could affect these
commodity markets or the financial markets used by us. In addition,
the U.S. government has issued warnings that energy assets may be a
future target of terrorist organizations. These developments have
subjected oil and natural gas operations to increased risks. Any
future terrorist attack on our facilities, the infrastructure
depended upon for transportation of products, and, in some cases,
those of other energy companies, could have a material adverse
effect on our business.
We depend substantially on our key personnel for critical
management decisions and industry contacts.
Our
success depends upon the continued contributions of our executive
officers and key employees, particularly with respect to providing
the critical management decisions and contacts necessary to manage,
maintain and expand our company in a highly competitive industry.
Competition for qualified personnel can be intense, particularly in
the oil and natural gas industry, and there are a limited number of
people with the requisite knowledge and experience. Under these
conditions, we could be unable to attract and retain these
personnel. The loss of the services of any of our executive
officers or other key employees for any reason, particularly
unexpected losses, could have a material adverse effect on our
business, operating results, financial condition and cash
flows.
Risks Related to the Ownership of our Common Stock
Our common stock price has been and is likely to continue to be
highly volatile.
The
trading price of our common stock is subject to wide fluctuations
in response to a variety of factors, including quarterly variations
in operating results, announcements of drilling and rig activity,
economic conditions in the oil and natural gas industry, general
economic conditions or other events or factors that are beyond our
control.
In
addition, the stock market in general and the market for oil and
natural gas exploration companies, in particular, have experienced
large price and volume fluctuations that have often been unrelated
or disproportionate to the operating results or asset values of
those companies. These broad market and industry factors may
seriously impact the market price and trading volume of our common
stock regardless of our actual operating performance. In the past,
following periods of volatility in the overall market and in the
market price of a company’s securities, securities class
action litigation has been instituted against certain oil and
natural gas exploration companies. If this type of litigation were
instituted against us following a period of volatility in our
common stock trading price, it could result in substantial costs
and a diversion of our management’s attention and resources,
which could have a material adverse effect on our financial
condition, future cash flows and the results of
operations.
The low trading volume of our common stock may adversely affect the
price of our shares and their liquidity.
Although our common
stock is listed on the NYSE American exchange, our common stock has
experienced low trading volume. Limited trading volume may subject
our common stock to greater price volatility and may make it
difficult for investors to sell shares at a price that is
attractive to them.
If our common stock was delisted and determined to be a
“penny stock,” a broker-dealer may find it more
difficult to trade our common stock, and an investor may find it
more difficult to acquire or dispose of our common stock in the
secondary market.
If our
common stock were removed from listing with the NYSE American, it
may be subject to the so-called “penny stock” rules.
The SEC has adopted regulations that define a penny stock to be any
equity security that has a market price per share of less than
$5.00, subject to certain exceptions, such as any securities listed
on a national securities exchange. For any transaction involving a
penny stock, unless exempt, the rules impose additional sales
practice requirements on broker-dealers, subject to certain
exceptions. If our common stock were delisted and determined to be
a penny stock, a broker-dealer may find it more difficult to trade
our common stock, and an investor may find it more difficult to
acquire or dispose of our common stock on the secondary
market.
We are able to issue shares of preferred stock with greater rights
than our common stock.
Our
Amended and Restated Certificate of Incorporation authorizes our
board of directors to issue one or more series of preferred shares
and set the terms of the preferred shares without seeking any
further approval from our stockholders. The preferred shares that
we have issued rank ahead of our common stock in terms of dividends
and liquidation rights. We may issue additional preferred shares
that rank ahead of our common stock in terms of dividends,
liquidation rights or voting rights. If we issue additional
preferred shares in the future, it may adversely affect the market
price of our common stock. We have issued in the past, and may in
the future continue to issue, in the open market at prevailing
prices or in capital markets offerings series of perpetual
preferred stock with dividend and liquidation preferences that rank
ahead of our common stock.
Our failure to fulfill all of our registration requirements may
cause us to suffer liquidated damages, which may be very
costly.
Pursuant to the
terms of the Registration Rights Agreement that
we entered into with certain of our stockholders, we filed a
registration statement with respect to securities issued and are
required to maintain the effectiveness of such registration
statement. There can be no assurance that we will be able to
maintain the effectiveness of any registration statement, and
therefore there can be no assurance that we will not incur damages
with respect to such agreement.
Because we have no plans to pay dividends on our common stock,
stockholders must look solely to a possible appreciation of our
common stock to realize a gain on their investment.
We do
not anticipate paying any dividends on our common stock in the
foreseeable future. We currently intend to retain any future
earnings to finance the expansion of our business. In addition, our
Credit Agreement contains covenants that prohibit us from paying
cash dividends on our common stock as long as such debt remains
outstanding. The payment of future dividends, if any, will be
determined by our board of directors in light of conditions then
existing, including our earnings, financial condition, capital
requirements, restrictions in financing agreements, business
conditions and other factors. Accordingly, stockholders must look
solely to appreciation of our common stock to realize a gain on
their investment, which may not occur.
Our Series D preferred stock has rights, preferences and privileges
that are not held by, and are preferential to, the rights of our
common stockholders. Such preferential rights could adversely
affect our liquidity and financial condition and may result in the
interests of the holders of the Series D preferred stock differing
from those of our common stockholders.
In the
event of any liquidation, dissolution or winding up of our company,
whether voluntary or involuntary, or any other transaction deemed a
liquidation event pursuant to the Certificate of Designation,
including a sale of our company (a “Liquidation”), each
holder of outstanding shares of our Series D preferred stock will
be entitled to be paid out of our assets available for distribution
to stockholders, before any payment may be made to the holders of
our common stock, an amount per share equal to the original issue
price, plus accrued and unpaid dividends thereon. If, upon such
Liquidation, the amount that the holders of Series D preferred
stock would have received if all outstanding shares of Series D
preferred stock had been converted into shares of our common stock
immediately prior to such Liquidation would exceed the amount they
would receive pursuant to the preceding sentence, the holders of
Series D preferred stock will receive such greater
amount.
Dividends on the
Series D preferred stock are cumulative and accrue quarterly,
whether or not declared by our board of directors, at the rate of
7.0% per annum on the sum of the original issue price plus all
unpaid accrued and unpaid dividends thereon, and payable in
additional shares of Series D preferred stock. In addition to the
dividends accruing on shares of Series D preferred stock described
above, if we declare certain dividends on our common stock, we will
be required to declare and pay a dividend on the outstanding shares
of our Series D preferred stock on a pro rata basis with the common
stock, determined on an as-converted basis. Our obligations to the
holders of Series D preferred stock could also limit our ability to
obtain additional financing or increase our borrowing costs, which
could have an adverse effect on our financial
condition.
There may be future dilution of our common stock.
We have
a significant amount of derivative securities outstanding, which
upon conversion, would result in substantial dilution. For example,
the conversion of outstanding shares of Series D preferred stock in
full could result in the issuance of approximately 3.2 million
shares of common stock. To the extent outstanding stock
appreciation rights under our long-term incentive plan are
exercised or additional shares of restricted stock are issued to
our employees, holders of our common stock will experience
dilution. Furthermore, if we sell additional equity or convertible
debt securities, such sales could result in further dilution to our
existing stockholders and cause the price of our outstanding
securities to decline.
If securities or industry analysts do not publish research or
publish inaccurate or unfavorable research about our business, our
stock price and trading volume could decline.
The
trading market for our common stock will depend in part upon the
research and reports that securities or industry analysts publish
about us and our business. We do not currently have and may never
obtain research coverage by securities and industry analysts. If no
analysts commence coverage of our company, the trading price of our
common stock might be negatively impacted. If we obtain securities
or industry analyst coverage and if one or more of the analysts who
covers us downgrades our stock or publishes inaccurate or
unfavorable research about our business, our stock price would
likely decline. If one or more of these analysts ceases coverage or
fails to report about us on a regular basis, demand for our stock
could decrease, which could cause our stock price and trading
volume to decline.
Item
1B.
Unresolved
Staff Comments.
None.
A
description of our properties is included in
Item 1. Business and is incorporated herein by
reference.
We
believe that we have satisfactory title to the properties owned and
used in our business, subject to liens for taxes not yet payable,
liens incident to minor encumbrances, liens for credit arrangements
and easements and restrictions that do not materially detract from
the value of these properties, our interests in these properties,
or the use of these properties in our business. We believe that our
properties are adequate and suitable for us to conduct business in
the future.
Item
3.
Legal
Proceedings.
From
time to time, we are party to various legal proceedings arising in
the ordinary course of business. We expense or accrue legal costs
as incurred. A summary of our legal proceedings is as
follows:
Yuma Energy, Inc. v. Cardno PPI Technology Services, LLC
Arbitration
On May
20, 2015, counsel for Cardno PPI Technology Services, LLC
(“Cardno PPI”) sent a notice of the filing of liens
totaling $304,209 on our Crosby 14 No. 1 Well and Crosby 14 SWD No.
1 Well in Vernon Parish, Louisiana. We disputed the validity of the
liens and of the underlying invoices, and notified Cardno PPI that
applicable credits had not been applied. We invoked mediation on
August 11, 2015 on the issues of the validity of the liens, the
amount due pursuant to terms of the parties’ Master Service
Agreement (“MSA”), and PPI Cardno’s breaches of
the MSA. Mediation was held on April 12, 2016; no settlement was
reached.
On May
12, 2016, Cardno filed a lawsuit in Louisiana state court to
enforce the liens; the Court entered an Order Staying Proceeding on
June 13, 2016, ordering that the lawsuit “be stayed pending
mediation/arbitration between the parties.” On June 17, 2016,
we served a Notice of Arbitration on Cardno PPI, stating claims for
breach of the MSA billing and warranty provisions. On July 15,
2016, Cardno PPI served a Counterclaim for $304,209 plus
attorneys’ fees. The parties selected an arbitrator, and the
initial arbitration hearing was held on March 29, 2018. The
arbitration has been continued, with the next hearing to be held on
April 12 and 13, 2018. Management intends to pursue our claims and
to defend the counterclaim vigorously. At this point in the legal
process, no evaluation of the likelihood of an unfavorable outcome
or associated economic loss can be made; therefore no liability has
been recorded on our consolidated financial
statements.
The Parish of St. Bernard v. Atlantic Richfield Co., et
al
On
October 13, 2016, two of our subsidiaries, Yuma Exploration and
Production Company (“Exploration”) and Yuma Petroleum
Company (“YPC”), were named as defendants, among
several other defendants, in an action by the Parish of St. Bernard
in the Thirty-Fourth Judicial District of Louisiana. The petition
alleges violations of the State and Local Coastal Resources
Management Act of 1978, as amended, in the St. Bernard
Parish. We have notified our insurance carrier of the
lawsuit. Management intends to defend the plaintiffs’
claims vigorously. At this point in the legal process, no
evaluation of the likelihood of an unfavorable outcome or
associated economic loss can be made; therefore no liability has
been recorded on our consolidated financial statements. The case
has been removed to federal district court for the Eastern District
of Louisiana. A motion to remand has been filed and the Court
officially remanded the case on July 6, 2017. Exceptions for
Exploration, YPC and the other defendants have been filed; however,
the hearing for such exceptions was continued from the original
date of October 6, 2017 to November 22, 2017. As a result of the
November 22, 2017 hearing, the case will be de-cumulated into
subcases, but the details of this are yet to be
determined.
Cameron Parish vs. BEPCO LP, et al & Cameron Parish vs. Alpine
Exploration Companies, Inc., et al.
The
Parish of Cameron, Louisiana, filed a series of lawsuits against
approximately 190 oil and gas companies alleging that the
defendants, including Davis, have failed to clear, revegetate,
detoxify, and restore the mineral and production sites and other
areas affected by their operations and activities within certain
coastal zone areas to their original condition as required by
Louisiana law, and that such defendants are liable to Cameron
Parish for damages under certain Louisiana coastal zone laws for
such failures; however, the amount of such damages has not been
specified. At this point in the legal process, no evaluation of the
likelihood of an unfavorable outcome or associated economic loss
can be made; therefore no liability has been recorded on our
consolidated financial statements. Two of these lawsuits,
originally filed February 4, 2016 in the 38th Judicial District
Court for the Parish of Cameron, State of Louisiana, name Davis as
defendant, along with more than 30 other oil and gas companies.
Both cases have been removed to federal district court for the
Western District of Louisiana. We deny these claims and intend to
vigorously defend them. Davis has become a party to the Joint
Defense and Cost Sharing Agreements for these cases. Motions to
remand have been filed and the Magistrate Judge has recommended
that the cases be remanded. We are still waiting for a new District
Judge to be assigned to these cases and to rule on the remand
recommendation.
Louisiana, et al. Escheat Tax Audits
The
States of Louisiana, Texas, Minnesota, North Dakota and Wyoming
have notified us that they will examine our books and records to
determine compliance with each of the examining state’s
escheat laws. The review is being conducted by Discovery Audit
Services, LLC. We have engaged Ryan, LLC to represent us in this
matter. The exposure related to the audits is not currently
determinable.
Louisiana Severance Tax Audit
The
State of Louisiana, Department of Revenue, notified Exploration
that it was auditing Exploration’s calculation of its
severance tax relating to Exploration’s production from
November 2012 through March 2016. The audit relates to the
Department of Revenue’s recent interpretation of
long-standing oil purchase contracts to include a disallowable
“transportation deduction,” and thus to assert that the
severance tax paid on crude oil sold during the contract term was
not properly calculated. The Department of Revenue sent a
proposed assessment in which they sought to impose $476,954 in
additional state severance tax plus associated penalties and
interest. Exploration engaged legal counsel to protest
the proposed assessment and request a hearing. Exploration
then entered a Joint Defense Group of operators challenging similar
audit results. Since the Joint Defense Group is challenging
the same legal theory, the Board of Tax Appeals proposed to hear a
motion brought by one of the taxpayers that would address the rule
for all through a test case. Exploration’s case has
been stayed pending adjudication of the test case. The hearing for
the test case was held on November 7, 2017, and on December 6,
2017, the Board of Tax Appeals rendered judgment in favor of the
taxpayer in the first of these cases. The Department of Revenue
filed an appeal to this decision on January 5, 2018. At this point
in the legal process, no evaluation of the likelihood of an
unfavorable outcome or associated economic loss can be made;
therefore no liability has been recorded on our consolidated
financial statements.
Louisiana Department of Wildlife and Fisheries
We
received notice from the Louisiana Department of Wildlife and
Fisheries (“LDWF”) in July 2017 stating that
Exploration has open Coastal Use Permits (“CUPs”)
located within the Louisiana Public Oyster Seed Grounds dating back
from as early as November 1993 and through a period ending in
November 2012. The majority of the claims relate to permits
that were filed from 2000 to 2005. Pursuant to the conditions
of each CUP, LDWF is alleging that damages were caused to the
oyster seed grounds and that compensation of an aggregate amount of
approximately $500,000 is owed by the Company. We are
currently evaluating the merits of the claim, are reviewing the
LDWF analysis, and have now requested that the LDWF revise downward
the amount of area their claims of damages pertain to. At this
point in the regulatory process, no evaluation of the likelihood of
an unfavorable outcome or associated economic loss can be made;
therefore no liability has been recorded on our consolidated
financial statements.
Miami Corporation – South Pecan Lake Field Area
P&A
We,
along with several other exploration and production companies in
the chain of title, received letters from representatives of Miami
Corporation demanding the performance of well plugging and
abandonment, facility removal and restoration obligations for wells
in the South Pecan Lake Field Area, Cameron Parish, Louisiana.
Apache is one of the other companies in the chain of title, and
after taking a field tour of the area, has sent to us, along with
BP and other companies in the chain of title, a proposed work plan
to comply with the Miami Corporation demand. We are currently
evaluating the merits of the claim and the proposed work plan. At
this point in the process, no evaluation of the likelihood of an
unfavorable outcome or associated economic loss can be made;
therefore no liability has been recorded on our consolidated
financial statements.
Item
4.
Mine
Safety Disclosures.
Not
applicable.