PEDEVCO CORP
10-Ks and 10-Qs
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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
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☑
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934
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For the fiscal year ended December 31, 2020
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☐
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
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For the transition period from ________________ to
____________
Commission file number: 001-35922
PEDEVCO Corp.
(Exact Name of Registrant as Specified in Its Charter)
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Texas
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22-3755993
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(State or other jurisdiction of incorporation or
organization)
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(IRS Employer Identification No.)
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575 N. Dairy Ashford, Suite 210
,
Houston, Texas 77079
(Address
of Principal Executive Offices)
(713) 221-1768
(Registrant’s
Telephone Number, Including Area Code)
Securities
registered pursuant to Section 12(b) of the Act:
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Title of each class
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Trading Symbols(s)
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Name of each exchange on which registered
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Common
Stock,
$0.001
Par Value Per Share
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PED
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NYSE
American
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Securities
registered pursuant to Section 12(g) of the Act:
None.
Indicate
by check mark if the registrant is a well-known seasoned issuer, as
defined in Rule 405 of the Securities Act.
Yes
☐
No
☑
Indicate
by check mark if the registrant is not required to file reports
pursuant to Section 13 or Section 15(d) of the
Act.
Yes
☐
No
☑
Indicate
by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities
Exchange Act of 1934 during the preceding 12 months (or for such
shorter period that the registrant was required to file such
reports), and (2) has been subject to such filing requirements
for the past 90 days. Yes
☑
No
☐
Indicate
by check mark whether the registrant has submitted electronically
every Interactive Data File required to be submitted pursuant to
Rule 405 of Regulation S-T (§232.405 of this
chapter) during the preceding 12 months (or for such shorter
period that the registrant was required to submit such files).
Yes
☑
No
☐
Indicate by check mark whether the registrant is a large
accelerated filer, an accelerated filer, a non-accelerated filer, a
smaller reporting company, or an emerging growth
company. See the definitions of
“
large accelerated
filer,
”
“
accelerated
filer
”,
“
smaller reporting
company
” and
"
emerging growth
company
" in Rule 12b-2 of the
Exchange Act.
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Large
accelerated filer
☐
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Accelerated
filer
☐
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Non-accelerated
filer
☑
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Smaller
reporting company
☑
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Emerging
growth company
☐
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If an emerging growth company, indicate by check mark if the
registrant has elected not to use the extended transition period
for complying with any new or revised financial accounting
standards provided pursuant to Section 13(a) of the Exchange
Act.
☐
Indicate
by check mark whether the registrant has filed a report on and
attestation to its management’s assessment of the
effectiveness of its internal control over financial reporting
under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b))
by the registered public accounting firm that prepared or issued
its audit report.
☐
Indicate
by check mark whether the registrant is a shell company (as defined
in Rule 12b-2 of the Exchange Act).
Yes
☐
No
☑
The
aggregate market value of the voting and non-voting common equity
held by non-affiliates of the registrant as of June 30, 2020
(the last trading day of the registrant’s most recently
completed second fiscal quarter), based upon the closing price
reported on such date was approximately $7,001,681. For purposes of
calculating the aggregate market value of shares held by
non-affiliates, we have assumed that all outstanding shares are
held by non-affiliates, except for shares held by each of our
executive officers, directors and 5% or greater stockholders. In
the case of 5% or greater stockholders, we have not deemed such
stockholders to be affiliates unless there are facts and
circumstances which would indicate that such stockholders exercise
any control over our company, or unless they hold 10% or more of
our outstanding common stock. These assumptions should not be
deemed to constitute an admission that all executive officers,
directors and 5% or greater stockholders are, in fact, affiliates
of our company, or that there are not other persons who may be
deemed to be affiliates of our company.
As of
March 19, 2021, 79,441,603 shares of the registrant’s common
stock, $0.001 par value per share, were outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
None.
Table of Contents
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Page
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PART I
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1
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4
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9
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32
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60
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60
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61
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61
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PART
II
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62
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63
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64
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72
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72
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99
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99
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100
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PART
III
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102
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109
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121
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122
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126
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PART
IV
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127
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132
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F
ORWARD-LOOKING STATEMENTS
ALL STATEMENTS IN THIS DISCUSSION THAT ARE NOT HISTORICAL ARE
FORWARD-LOOKING STATEMENTS WITHIN THE MEANING OF THE PRIVATE
SECURITIES LITIGATION REFORM ACT OF 1995. STATEMENTS PRECEDED BY,
FOLLOWED BY OR THAT OTHERWISE INCLUDE THE WORDS “
BELIEVES,
”
“
EXPECTS,
”
“
ANTICIPATES,
”
“
INTENDS,
”
“
PROJECTS,
”
“
ESTIMATES,
”
“
PLANS,
”
“
MAY
INCREASE,
” “
MAY FLUCTUATE
” AND
SIMILAR EXPRESSIONS OR FUTURE OR CONDITIONAL VERBS SUCH AS
“
SHOULD
”,
“
WOULD
”,
“
MAY
”
AND “
COULD
” ARE GENERALLY
FORWARD-LOOKING IN NATURE AND NOT HISTORICAL FACTS. THESE
FORWARD-LOOKING STATEMENTS WERE BASED ON VARIOUS FACTORS AND WERE
DERIVED UTILIZING NUMEROUS IMPORTANT ASSUMPTIONS AND OTHER
IMPORTANT FACTORS THAT COULD CAUSE ACTUAL RESULTS TO DIFFER
MATERIALLY FROM THOSE IN THE FORWARD-LOOKING STATEMENTS.
FORWARD-LOOKING STATEMENTS INCLUDE THE INFORMATION CONCERNING OUR
FUTURE FINANCIAL PERFORMANCE, BUSINESS STRATEGY, PROJECTED PLANS
AND OBJECTIVES. THESE FACTORS INCLUDE, AMONG OTHERS, THE FACTORS
SET FORTH BELOW UNDER THE HEADING “
RISK
FACTORS
.
” ALTHOUGH WE BELIEVE
THAT THE EXPECTATIONS REFLECTED IN THE FORWARD-LOOKING STATEMENTS
ARE REASONABLE, WE CANNOT GUARANTEE FUTURE RESULTS, LEVELS OF
ACTIVITY, PERFORMANCE OR ACHIEVEMENTS. MOST OF THESE FACTORS ARE
DIFFICULT TO PREDICT ACCURATELY AND ARE GENERALLY BEYOND OUR
CONTROL. WE ARE UNDER NO OBLIGATION TO PUBLICLY UPDATE ANY OF THE
FORWARD-LOOKING STATEMENTS TO REFLECT EVENTS OR CIRCUMSTANCES AFTER
THE DATE HEREOF OR TO REFLECT THE OCCURRENCE OF UNANTICIPATED
EVENTS. READERS ARE CAUTIONED NOT TO PLACE UNDUE RELIANCE ON THESE
FORWARD-LOOKING STATEMENTS. REFERENCES IN THIS FORM 10-K, UNLESS
ANOTHER DATE IS STATED, ARE TO DECEMBER 31, 2020. AS USED HEREIN,
THE “
COMPANY,
”
“
WE,
”
“
US,
”
“
OUR
”
AND WORDS OF SIMILAR MEANING REFER TO PEDEVCO CORP., WHICH WAS
KNOWN AS BLAST ENERGY SERVICES, INC. UNTIL JULY 30, 2012, AND ITS
WHOLLY-OWNED SUBSIDIARIES, BLAST AFJ, INC., PACIFIC ENERGY
DEVELOPMENT CORP., RED HAWK PETROLEUM, LLC, RIDGEWAY ARIZONA OIL
CORP, EOR OPERATING COMPANY, AND SRPT ACQUISITION, LLC (FORMED ON
OCTOBER 16, 2020), UNLESS OTHERWISE STATED.
This
Annual Report on Form 10-K (this “
Annual Report
”) may
contain forward-looking statements which are subject to a number of
risks and uncertainties, many of which are beyond our control. All
statements, other than statements of historical fact included in
this Annual Report, regarding our strategy, future operations,
financial position, estimated revenues and losses, projected costs
and cash flows, prospects, plans and objectives of management are
forward-looking statements. When used in this Annual Report, the
words “
could,
”
“
believe,
”
“
anticipate,
”
“
intend,
”
“
estimate,
”
“
expect,
”
“
may,
”
“
should,
”
“
continue,
”
“
predict,
”
“
potential,
”
“
project
” and similar
expressions are intended to identify forward-looking statements,
although not all forward-looking statements contain such
identifying words.
Forward-looking
statements may include statements about our:
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business
strategy;
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reserves;
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technology;
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cash
flows and liquidity;
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financial
strategy, budget, projections and operating results;
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oil and
natural gas realized prices;
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timing
and amount of future production of oil and natural
gas;
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availability
of oil field labor;
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the
amount, nature and timing of capital expenditures, including future
exploration and development costs;
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drilling
of wells;
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government
regulation and taxation of the oil and natural gas
industry;
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marketing
of oil and natural gas;
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exploitation
projects or property acquisitions;
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costs
of exploiting and developing our properties and conducting other
operations;
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general
economic conditions in the United States and around the world,
including the effect of regional or global health pandemics (such
as, for example, COVID-19);
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the
effect of COVID-19 on the U.S. and global economy, the effect of
U.S. and global efforts to reduce the spread of the virus,
including ‘stay-at-home’ and other orders, and the
resulting effect of such pandemic and governmental responses
thereto on the market for oil and gas and the U.S. and global
economy in general;
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competition
in the oil and natural gas industry;
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1
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effectiveness
of our risk management activities;
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environmental
liabilities;
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counterparty
credit risk;
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developments
in oil-producing and natural gas-producing countries;
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future
operating results;
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future
acquisition transactions;
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estimated
future reserves and the present value of such reserves;
and
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●
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plans,
objectives, expectations and intentions contained in this Annual
Report that are not historical.
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All
forward-looking statements speak only at the date of the filing of
this Annual Report. The reader should not place undue reliance on
these forward-looking statements. Although we believe that our
plans, intentions and expectations reflected in or suggested by the
forward-looking statements we make in this Annual Report are
reasonable, we can give no assurance that these plans, intentions
or expectations will be achieved. We disclose important factors
that could cause our actual results to differ materially from our
expectations under “
Risk
Factors
” and “
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
” and elsewhere in this Annual Report. These
cautionary statements qualify all forward-looking statements
attributable to us or persons acting on our behalf. We do not
undertake any obligation to update or revise publicly any
forward-looking statements except as required by law, including the
securities laws of the United States and the rules and regulations
of the SEC.
Certain
abbreviations and oil and gas industry terms used throughout this
Annual Report are described and defined in greater detail under
“
Glossary of Oil and
Natural Gas Terms
” above, and readers are
encouraged to review that section.
Unless
the context otherwise requires and for the purposes of this report
only:
●
“
Exchange
Act
” refers to the
Securities Exchange Act of 1934, as amended;
●
“
SEC
” or the “
Commission
”
refers to the United States Securities and Exchange Commission;
and
●
“
Securities
Act
” refers to the
Securities Act of 1933, as amended.
Available Information
We are
subject to the information and reporting requirements of the
Exchange Act, under which we file periodic reports, proxy and
information statements and other information with the United States
Securities and Exchange Commission, or SEC.
Financial and other
information about PEDEVCO Corp. is available on our website
(
www.pedevco.com
).
Information on our website is not incorporated by reference into
this report. We make available on our website, free of charge,
copies of our annual report on Form 10-K, quarterly reports on Form
10-Q, current reports on Form 8-K, and amendments to those reports
filed or furnished pursuant to Section 13(a) or 15(d) of
the Exchange Act as soon as reasonably practicable after filing
such material electronically or otherwise furnishing it to the
SEC.
Summary Risk Factors
We face
risks and uncertainties related to our business, many of which are
beyond our control. In particular, risks associated with our
business include:
●
The future price of
oil, natural gas and NGL;
●
The effect of
COVID-19 on the Company’s operations, future prospects, the
value of its properties, and the economy in general, including the
related effect on the supply and demand, and ultimate price of oil
and natural gas;
●
Current and future
declines in economic activity and rescessions, and their effect on
the Company, its property, prospects and the supply and demand, and
ultimate price of oil and natural gas;
●
The status and
availability of oil and natural gas gathering, transportation, and
storage facilities owned and operated by third
parties;
2
●
An increase in the
differential between the NYMEX or other benchmark prices of oil and
natural gas and the wellhead price we receive for our production
may adversely affect our business, financial condition, and results
of operations;
●
New or amended
environmental legislation or regulatory initiatives which could
result in increased costs, additional operating restrictions, or
delays, or have other adverse effects on us;
●
The effect of
future shut-ins of our operated production, should market
conditions significantly deteriorate;
●
Anticipated
significant write-downs of a material portion of our assets due to
the recent economic downturn resulting from COVID-19;
●
Our need for
additional capital to complete future acquisitions, conduct our
operations and fund our business, and our ability to obtain such
necessary funding on favorable terms, if at all;
●
Our ability to
generate sufficient cash flow to meet any future debt service and
other obligations due to events beyond our control;
●
The fact that all
our assets and operations are located in the Permian Basin and the
D-J Basin, making us vulnerable to risks associated with operating
in only two geographic areas;
●
The speculative
nature of our oil and gas operations, and general risks associated
with the exploration for, and production of oil and gas; including
accidents, equipment failures or mechanical problems which may
occur while drilling or completing wells or in production
activities; operational hazards and unforeseen interruptions for
which we may not be adequately insured; the threat and impact of
terrorist attacks, cyber-attacks or similar hostilities; declining
reserves and production; and losses or costs we may incur as a
result of title deficiencies or environmental issues in the
properties in which we invest, any one of which may adversely
impact our operations;
●
Potential conflicts
of interest that could arise for certain members of our management
team and board of directors that hold management positions with
other entities and our largest stockholder;
●
The limited control
we have over activities on properties we do not
operate;
●
The estimates of
the value of our oil and gas properties and accounting in
connection therewith;
●
Intense competition
in the oil and natural gas industry;
●
Our competitors use
of superior technology and data resources that we may be unable to
afford or obtain the use of;
●
Changes in the
legal and regulatory environment governing the oil and natural gas
industry, including new or amended environmental legislation or
regulatory initiatives which could result in increased costs,
additional operating restrictions, or delays, or have other adverse
effects on us;
●
Uncertainties
associated with enhanced recovery methods which may result in us
not realizing an acceptable return on our investments in such
projects or suffering losses;
●
Requirements that
we must drill on certain of acreage in order to hold such acreage
by production;
●
Improvements in or
new discoveries of alternative energy technologies that could have
a material adverse effect on our financial condition and results of
operations;
●
Future litigation
or governmental proceedings which could result in material adverse
consequences, including judgments or settlements;
●
The currently
illiquid and volatile market for our common stock;
●
Our dependence on
the continued involvement of our present management;
3
●
The fact that Mr.
Simon Kukes, our Chief Executive Officer and a member of board of
directors, beneficially owns a majority of our common stock and
that his interests may be different from other
shareholders;
●
Our ability to
maintain the listing of our common stock on the NYSE American;
and
●
Future material
impairments of our oil and gas assets; and
●
Other risks
described under “
Risk
Factors
” below.
G
LOSSARY OF OIL AND
NATURAL GAS TERMS
The
following is a description of the meanings of some of the oil and
natural gas terms used in this Annual Report.
2-D
seismic
. The method by which a
cross-section of the earth’s subsurface is created through
the interpretation of reflecting seismic data collected along a
single source profile.
3-D
seismic
. The method by which a
three-dimensional image of the earth’s subsurface is created
through the interpretation of reflection seismic data collected
over a surface grid. 3-D seismic surveys allow for a more detailed
understanding of the subsurface than do 2-D seismic surveys and
contribute significantly to field appraisal, exploitation and
production.
AFE
or
Authorization for Expenditures
.
A document that lays out proposed expenses for a particular project
and authorizes an individual or group to spend a certain amount of
money for that project.
ARO
. Asset retirement
obligation, which is a legal obligation associated with the
retirement of an oil or gas well, where the owner is responsible
for removing equipment, plugging the well and/or cleaning up
hazardous materials at some future date.
Bbl
. One stock tank barrel, or
42 U.S. gallons liquid volume, used in this Annual Report in
reference to crude oil or other liquid hydrocarbons.
Bcf.
An abbreviation for
billion cubic feet. Unit used to measure large quantities of gas,
approximately equal to 1 trillion Btu.
Boe
. Barrels of oil equivalent,
determined using the ratio of one Bbl of crude oil, condensate or
natural gas liquids, to six Mcf of natural gas.
Boepd
. Barrels of oil
equivalent per day.
Bopd
. Barrels of oil per
day.
Btu or British thermal unit
.
The quantity of heat required to raise the temperature of one pound
of water by one degree Fahrenheit.
Completion
. The operations
required to establish production of oil or natural gas from a
wellbore, usually involving perforations, stimulation and/or
installation of permanent equipment in the well or, in the case of
a dry hole, the reporting of abandonment to the appropriate
agency.
Condensate
. Liquid hydrocarbons
associated with the production of a primarily natural gas
reserve.
Conventional resources
. Natural
gas or oil that is produced by a well drilled into a geologic
formation in which the reservoir and fluid characteristics permit
the natural gas or oil to readily flow to the
wellbore.
Cushing/WTI
. Means the price of
West Texas Intermediate oil at the hub located in Cushing,
Oklahoma.
Developed acreage
. The number
of acres that are allocated or assignable to productive
wells.
4
Developed oil and
natural gas reserves
. Reserves
of any category that can be expected to be recovered (i) through
existing wells with existing equipment and operating methods or in
which the cost of the required equipment is relatively minor
compared to the cost of a new well and (ii) through installed
extraction equipment and infrastructure operational at the time of
the reserves estimate if the extraction is by means not involving a
well.
Development well
. A well
drilled into a proved oil or natural gas reservoir to the depth of
a stratigraphic horizon known to be productive.
Estimated ultimate recovery or
EUR
. Estimated ultimate recovery is the sum of reserves
remaining as of a given date and cumulative production as of that
date.
Exploratory well
. A well
drilled to find and produce oil or natural gas reserves not
classified as proved, to find a new reservoir in a field previously
found to be productive of oil or natural gas in another reservoir
or to extend a known reservoir.
Frac
or
fracking.
A short name for
hydraulic fracturing, a method for extracting oil and natural
gas.
Farmin
or
farmout
. An agreement under
which the owner of a working interest in an oil or natural gas
lease assigns the working interest or a portion of the working
interest to another party who desires to drill on the leased
acreage. Generally, the assignee is required to drill one or more
wells in order to earn its interest in the acreage. The assignor
usually retains a royalty or reversionary interest in the lease.
The interest received by an assignee is a “
farmin
” while the
interest transferred by the assignor is a “
farmout.
”
FERC
. Federal Energy Regulatory
Commission.
Field
. An area consisting of a
single reservoir or multiple reservoirs all grouped on or related
to the same individual geological structural feature and/or
stratigraphic condition.
Gross acres or gross wells
. The
total acres or wells in which a working interest is
owned.
Henry Hub
. A natural gas
pipeline located in Erath, Louisiana that serves as the official
delivery location for futures contracts on the NYMEX. The
settlement prices at the Henry Hub are used as benchmarks for the
entire North American natural gas market.
Held by production
. An oil and
natural gas property under lease in which the lease continues to be
in force after the primary term of the lease in accordance with its
terms as a result of production from the property.
Horizontal drilling or well
. A
drilling operation in which a portion of the well is drilled
horizontally within a productive or potentially productive
formation. This operation typically yields a horizontal well that
has the ability to produce higher volumes than a vertical well
drilled in the same formation. A horizontal well is designed to
replace multiple vertical wells, resulting in lower capital
expenditures for draining like acreage and limiting surface
disruption.
Hydraulic Fracturing
.
Means
the forcing open of
fissures in subterranean rocks by introducing liquid at high
pressure, especially to extract oil or gas.
IP30
. Means the production of a
well for the first full calendar month of production.
Liquids
. Liquids, or natural
gas liquids, are marketable liquid products including ethane,
propane, butane and pentane resulting from the further processing
of liquefiable hydrocarbons separated from raw natural gas by a
natural gas processing facility.
LOE
or
Lease operating expenses
. The
costs of maintaining and operating property and equipment on a
producing oil and gas lease.
MBbl or MBbls
. One thousand
barrels of crude oil or other liquid hydrocarbons.
MBbl/d
. One thousand barrels of
crude oil or other liquid hydrocarbons per day.
MBoe
.
Thousand barrels of oil equivalent.
5
MBoe/d
.
Thousand barrels of oil equivalent per day.
Mcf
. One thousand cubic feet of
natural gas.
Mcfgpd
. Thousands of cubic feet
of natural gas per day.
MMcf
. One million cubic feet of
natural gas.
MMBtu
. One million British
thermal units.
MMBoe.
Million barrels of oil
equivalent.
Net acres or net wells
. The sum
of the fractional working interest owned in gross acres or
wells.
Net revenue interest
. The
interest that defines the percentage of revenue that an owner of a
well receives from the sale of oil, natural gas and/or natural gas
liquids that are produced from the well.
NGL
. Natural gas
liquids.
NYMEX
. New York Mercantile
Exchange.
Permeability
. A reference to
the ability of oil and/or natural gas to flow through a
reservoir.
Petrophysical analysis
. The
interpretation of well log measurements, obtained from a string of
electronic tools inserted into the borehole, and from core
measurements, in which rock samples are retrieved from the
subsurface, then combining these measurements with other relevant
geological and geophysical information to describe the reservoir
rock properties.
Play
. A set of known or
postulated oil and/or natural gas accumulations sharing similar
geologic, geographic and temporal properties, such as source rock,
migration pathways, timing, trapping mechanism and hydrocarbon
type.
Plugging and
abandonment
. Refers to the
sealing off of fluids in the strata penetrated by a well so that
the fluids from one stratum will not escape into another or to the
surface. State regulations require generally plugging of abandoned
wells.
Possible reserves
. Additional
reserves that are less certain to be recognized than probable
reserves.
Present value of
future net revenues (“PV-10”)
. The present value of estimated future revenues
to be generated from the production of proved reserves, before
income taxes, calculated in accordance with SEC guidelines, net of
estimated production and future development costs, using prices and
costs as of the date of estimation without future escalation and
without giving effect to hedging activities, non-property related
expenses such as general and administrative expenses, debt service
and depreciation, depletion and amortization. PV-10 is calculated
using an annual discount rate of 10%.
Probable reserves
. Additional
reserves that are less certain to be recognized than proved
reserves but which, in sum with proved reserves, are as likely as
not to be recovered.
Producing well, production well or
productive well
. A well that is found to be capable of
producing hydrocarbons in sufficient quantities such that proceeds
from the sale of the well’s production exceed
production-related expenses and taxes.
Production
costs
. Costs incurred to
operate and maintain wells and related equipment and facilities,
including depreciation and applicable operating costs of support
equipment and facilities and other costs of operating and
maintaining those wells and related equipment and facilities that
become part of the cost of oil, natural gas and NGL
produced.
Properties
. Natural gas and oil
wells, production and related equipment and facilities and natural
gas, oil or other mineral fee, leasehold and related
interests.
6
Prospect
. A specific geographic
area which, based on supporting geological, geophysical or other
data and also preliminary economic analysis using reasonably
anticipated prices and costs, is considered to have potential for
the discovery of commercial hydrocarbons.
Proved developed
reserves
. Proved reserves that
can be expected to be recovered through existing wells and
facilities and by existing operating methods.
Proved
reserves
. Reserves of oil and
natural gas that have been proved to a high degree of certainty by
analysis of the producing history of a reservoir and/or by
volumetric analysis of adequate geological and engineering
data.
Proved undeveloped
reserves or PUDs
. Proved
reserves that are expected to be recovered from new wells on
undrilled acreage or from existing wells where a relatively major
expenditure is required for recompletion.
Repeatability
. The potential
ability to drill multiple wells within a prospect or
trend.
Reserves
.
Estimated remaining quantities of oil, natural gas and NGL and
related substances anticipated to be economically producible by
application of development projects to known accumulations. In
addition, there must exist, or there must be a reasonable
expectation that there will exist, the legal right to produce or a
revenue interest in the production, installed means of delivering
oil, natural gas and NGL or related substances to market, and all
permits and financing required to implement the project. Reserves
should not be assigned to adjacent reservoirs isolated by major,
potentially sealing, faults until those reservoirs are penetrated
and evaluated as economically producible. Reserves should not be
assigned to areas that are clearly separated from a known
accumulation by a non-productive reservoir (i.e., absence of
reservoir, structurally low reservoir, or negative test results).
Such areas may contain prospective resources (i.e., potentially
recoverable resources from undiscovered
accumulations).
Reservoir
. A porous and
permeable underground formation containing a natural accumulation
of producible oil and/or natural gas that is confined by
impermeable rock or water barriers and is individual and separate
from other reservoirs.
Royalty interest
. An interest
in an oil and natural gas lease that gives the owner of the
interest the right to receive a portion of the production from the
leased acreage (or of the proceeds of the sale thereof), but
generally does not require the owner to pay any portion of the
costs of drilling or operating the wells on the leased acreage.
Royalties may be either landowner’s royalties, which are
reserved by the owner of the leased acreage at the time the lease
is granted, or overriding royalties, which are usually reserved by
an owner of the leasehold in connection with a transfer to a
subsequent owner.
Standardized
measure
or
standardized measure
of discounted future net cash flows
. The present value of estimated future cash
inflows from proved oil, natural gas and NGL reserves, less future
development and production costs and future income tax expenses,
discounted at 10% per annum to reflect timing of future cash flows
and using the same pricing assumptions as were used to calculate
PV-10. Standardized Measure differs from PV-10 because standardized
measure includes the effect of future income taxes on future net
revenues.
Transition Zone
. The Transition
Zone usually produces both oil and water at different ratios
depending on the height above the Free Water Level
(“FWL”). In normal conditions wells that are drilled in
the Transition Zone will produce at some water cut.
Trend
. A region of oil and/or
natural gas production, the geographic limits of which have not
been fully defined, having geological characteristics that have
been ascertained through supporting geological, geophysical or
other data to contain the potential for oil and/or natural gas
reserves in a particular formation or series of
formations.
Unconventional resource play
. A
set of known or postulated oil and or natural gas resources or
reserves warranting further exploration which are extracted from
(a) low-permeability sandstone and shale formations and
(b) coalbed methane. These plays require the application of
advanced technology to extract the oil and natural gas
resources.
Undeveloped
acreage
. Lease 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.
Undeveloped acreage is usually considered to be all acreage that is
not allocated or assignable to productive
wells.
Unproved and unevaluated
properties
. Refers to properties where no drilling or other
actions have been undertaken that permit such property to be
classified as proved.
7
USACE
. United States Army Corps
of Engineers.
Vertical well
. A hole drilled
vertically into the earth from which oil, natural gas or water
flows is pumped.
Volumetric reserve analysis
. A
technique used to estimate the amount of recoverable oil and
natural gas. It involves calculating the volume of reservoir rock
and adjusting that volume for the rock porosity, hydrocarbon
saturation, formation volume factor and recovery
factor.
Wellbore
. The hole made by a
well.
WTI
or
West Texas Intermediate
. A
grade of crude oil used as a benchmark in oil pricing. This grade
is described as light because of its relatively low density, and
sweet because of its low sulfur content.
Working interest
. The operating
interest that gives the owner the right to drill, produce and
conduct operating activities on the property and receive a share of
production.
8
PART I
ITEM 1.
B
USINESS.
History
We were
originally incorporated in September 2000 as Rocker & Spike
Entertainment, Inc. In January 2001 we changed our name to
Reconstruction Data Group, Inc., and in April 2003 we changed our
name to Verdisys, Inc. and were engaged in the business of
providing satellite services to agribusiness. In June 2005, we
changed our name to Blast Energy Services, Inc.
(“
Blast
”) to
reflect our new focus on the energy services business, and in 2010
we changed the direction of the Company to focus on the acquisition
of oil and gas producing properties.
On July
27, 2012, we acquired, through a reverse acquisition, Pacific
Energy Development Corp., a privately held Nevada corporation,
which we refer to as Pacific Energy Development. As described
below, pursuant to the acquisition, the stockholders of Pacific
Energy Development gained control of approximately 95% of the then
voting securities of our company. Since the transaction resulted in
a change of control, Pacific Energy Development was the acquirer
for accounting purposes. In connection with the merger, which we
refer to as the Pacific Energy Development merger, Pacific Energy
Development became our wholly-owned subsidiary and we changed our
name from Blast Energy Services, Inc. to PEDEVCO Corp. Following
the merger, we refocused our business plan on the acquisition,
exploration, development and production of oil and natural gas
resources in the United States.
Our
corporate headquarters are located in approximately 5,200 square
feet of office space at 575 N. Dairy Ashford, Suite 210, Houston,
Texas 77079. We lease that space pursuant to a lease that expires
in August 2023.
Business Operations
Overview
We are an oil and gas company focused on the
acquisition and development of oil and natural gas
assets
where the latest in modern drilling and completion techniques and
technologies have yet to be applied. In particular, we focus on
legacy proven properties where there is a long production history,
well defined geology and existing infrastructure that can be
leveraged when applying modern field management technologies. Our
current properties are located in the San Andres formation of the
Permian Basin situated in West Texas and eastern New Mexico (the
“
Permian
Basin
”) and in the
Denver-Julesberg Basin (“
D-J
Basin
”) in
Colorado.
As of
December 31, 2020, we held approximately 37,068 net Permian Basin
acres located in Chaves and Roosevelt Counties, New Mexico, through
our wholly-owned operating subsidiary, Pacific Energy Development
Corp. (“
PEDCO
”),
which we refer to as our “
Permian Basin
Asset,
” and approximately
11,948 net D-J Basin acres located in Weld and Morgan Counties,
Colorado, through our wholly-owned operating subsidiary, Red Hawk
Petroleum, LLC (“
Red
Hawk
”), which asset we
refer to as our “
D-J Basin
Asset.
” As of
December 31, 2020, we held interests in 379 gross (302
net) wells in our Permian Basin Asset, of which 26 are active
producers, 15 are active injectors and two are active Saltwater
Disposal Wells (“
SWD
”s), all of which are held by PEDCO and
operated by its wholly-owned operating subsidiaries, and
interests in 77 gross (22.0
net) wells in our D-J Basin Asset, of which 18 gross (16.2
net) wells are operated by Red Hawk and currently producing,
38 gross (5.8 net) wells are non-operated, and 21 wells have
an after-payout interest.
As a result of the COVID-19 outbreak in early
2020, and the sharp decline in oil prices which occurred partially
as a result of the decreased demand for oil caused by such outbreak
and the actions taken globally to stop the spread of such virus, in
mid-April 2020, we temporarily shut-in all of our operated
producing wells in our Permian Basin Asset and D-J Basin Asset to
preserve our oil and gas reserves for production during a more
favorable oil price environment, noting that most of our acreage is
held by production with no drilling obligations, which provides us
with flexibility to hold back on production and development during
periods of low oil and gas prices. Following the partial recovery
in oil prices, commencing in early June 2020, we resumed full
production from our operated wells in the Permian Basin and the D-J
Basin that we shut-in in mid-April 2020. In September of 2020 we
completed a salt water disposal well (“
SWD
well
”) on our Permian
Basin Asset which allowed us to commence production on three wells
that were shut in due to salt water disposal constraints. We
brought one of the three wells online in September 2020 and the
other two were brought online in late January 2021, all producing
from the San Andres formation. The Company has deferred into 2021
several minor projects from the 2019 carryover projects, and all
previously planned 2020 development plan projects, pending a more
favorable oil price environment.
9
Business Strategy
We
believe that horizontal development and exploitation of
conventional assets in the Permian Basin and development of the
Wattenberg and Wattenberg Extension in the D-J Basin, represent
among the most economic oil and natural gas plays in the
U.S. We plan to optimize our existing assets and
opportunistically seek additional acreage proximate to our
currently held core acreage, as well as other attractive onshore
U.S. oil and gas assets that fit our acquisition criteria, that
Company management believes can be developed using our technical
and operating expertise and be accretive to stockholder value,
provided that, as discussed above, the price of oil
recovers.
Specifically, we
seek to increase stockholder value through the following
strategies:
●
Grow production, cash flow and reserves by
developing our operated drilling inventory and participating
opportunistically in non-operated projects.
We believe our
extensive inventory of drilling locations in the Permian Basin and
the D-J Basin, combined with our operating expertise, will enable
us to continue to deliver accretive production, cash flow and
reserves growth. We have identified approximately 150 gross
drilling locations across our Permian Basin acreage based on
20-acre spacing. We believe the location, concentration and scale
of our core leasehold positions, coupled with our technical
understanding of the reservoirs will allow us to efficiently
develop our core areas and to allocate capital to maximize the
value of our resource base.
●
Apply modern drilling and completion techniques
and technologies.
We own and intend to own additional
properties that have been historically underdeveloped and
underexploited. We believe our attention to detail and application
of the latest industry advances in horizontal drilling, completions
design, frac intensity and locally optimal frac fluids will allow
us to successfully develop our properties.
●
Optimization of well density and
configuration.
We own properties that are legacy
conventional oil fields characterized by widespread vertical
development and geological well control. We utilize the extensive
petrophysical and production data of such legacy properties to
confirm optimal well spacing and configuration using modern
reservoir evaluation methodologies.
●
Maintain a high degree of operational
control.
We believe that by retaining high operational
control, we can efficiently manage the timing and amount of our
capital expenditures and operating costs, and thus key in on the
optimal drilling and completions strategies, which we believe will
generate higher recoveries and greater rates of return per
well.
●
Leverage extensive deal flow, technical and
operational experience to evaluate and execute accretive
acquisition opportunities.
Our management and technical
teams have an extensive track record of forming and building oil
and gas businesses. We also have significant expertise in
successfully sourcing, evaluating and executing acquisition
opportunities. We believe our understanding of the geology,
geophysics and reservoir properties of potential acquisition
targets will allow us to identify and acquire highly prospective
acreage in order to grow our reserve base and maximize stockholder
value.
●
Preserve financial flexibility to pursue
organic and external growth opportunities.
We intend to
maintain a disciplined financial profile that will provide us
flexibility across various commodity and market cycles. We intend
to utilize our strategic partners and public currency to
continuously fund development and operations.
Our
strategy is to be the operator and/or a significant working
interest owner, directly or through our subsidiaries and joint
ventures, in the majority of our acreage so that we can dictate the
pace of development in order to execute our business plan. Our 2021
development plan includes several projects delayed from our 2019
Phase II Permian Basin Asset development program, which were put on
hold through 2020 due to the COVID-19 outbreak and related low oil
price environment through most of 2020. In late 2020 we resumed
work on these carryover projects, including the completion of a SWD
well in the Chaveroo field (Chaves and Roosevelt Counties, New
Mexico) which was brought online in September 2020. In September of
2020 we brought online one horizontal San Andres well from our 2019
Phase I Permian Basin Asset development program that was shut in
due to salt water disposal capacity constraints. In January 2021,
we initiated production hookup and commencement of two horizontal
San Andres wells drilled in our 2019/2020 Phase II Permian Basin
Asset development program. Over the remainder of 2021, we plan to
drill and complete up to nine horizontal San Andres wells on our
Permian Basin Asset, complete several potential well reactivation
projects, and complete several enhancement and facilities projects
across our operated Permian Basin Asset for a total estimated
capital deployment of $27.3 million through year-end (of which we
have deployed pproximately $700,000 to date) and plan to fund the
remaining amount with $17.7 million in current cash on hand and
through operating cash flow. However, we may need to raise
additional capital to fund our development program if market
conditions significantly deteriorate. Additionally, we plan to
spend approximately $1 million to participate in non-operated well
projects on our D-J Basin Asset pursuant to well proposals
received, and anticipated to be received, from third party
operators on lands in which we share a leasehold interest. This
2021 development program is based upon our current outlook for the
remainder of the year and is subject to revision, if and as
necessary to react to market conditions, product pricing,
contractor availability, requisite permitting and capital
availability, capital allocation changes between assets,
acquisitions, divestitures and other adjustments determined by the
Company in the best interest of its shareholders while prioritizing
our financial strength and liquidity.
10
We expect that we will have sufficient cash
available to meet our needs over the foreseeable future, which cash
we anticipate being available from (i) projected cash flow from our
operations, (ii) existing cash on hand, (iii) equity infusions or
loans (which may be convertible) made available from SK Energy
LLC
(“
SK
Energy
”)
, which is 100%
owned and controlled by Simon Kukes, our Chief Executive Officer
and director, which funding SK Energy is under no obligation to
provide, (iv) public or private debt or equity financings (similar
to our recently completed February 2021 underwritten offering, as
discussed below), and (v) funding through credit or loan
facilities. In addition, we may seek additional funding through
asset sales, farm-out arrangements, and credit facilities to fund
potential acquisitions in 2021.
The
following chart reflects our current organizational
structure:
*Represents
percentage of total voting power based on 79,441,603
shares of common stock outstanding as of March 19, 2021, with
beneficial ownership calculated in accordance with Rule 13d-3 of
the Exchange Act. Holdings of SK Energy LLC are also included in
holdings of Senior Management and the Board – See
“
Part
III
” — “
Item 12. Security
Ownership of Certain Beneficial Owners and Management and Related
Stockholder Matters
.” Ownership of Mr. Tkachev is
based solely on his filings with the Securities and Exchange
Commission.
Competition
The oil
and natural gas industry is highly competitive. We compete, and
will continue to compete, with major and independent oil and
natural gas companies for exploration and exploitation
opportunities, acreage and property acquisitions. We also compete
for drilling rig contracts and other equipment and labor required
to drill, operate and develop our properties. Many of our
competitors have substantially greater financial resources, staffs,
facilities and other resources than we have. In addition, larger
competitors may be able to absorb the burden of any changes in
federal, state and local laws and regulations more easily than we
can, which would adversely affect our competitive position. These
competitors may be able to pay more for drilling rigs or
exploratory prospects and productive oil and natural gas properties
and may be able to define, evaluate, bid for and purchase a greater
number of properties and prospects than we can. Our competitors may
also be able to afford to purchase and operate their own drilling
rigs.
11
Our
ability to exploit, drill and explore for oil and natural gas and
to acquire properties will depend upon our ability to conduct
operations, to evaluate and select suitable properties and to
consummate transactions in this highly competitive environment.
Many of our competitors have a longer history of operations than we
have, and many of them have also demonstrated the ability to
operate through industry cycles.
Competitive Strengths
We
believe we are well positioned to successfully execute our business
strategies and achieve our business objectives because of the
following competitive strengths:
Legacy Conventional Focus
.
Legacy conventional oil fields that have seen large-scale vertical
development. Vertical production confirms moveable hydrocarbons
ideal for horizontal development that may have been technologically
or economically limited or missed.
Technical Engineering & Operations
Expertise
. Lateral landing decisions incorporate log
analysis, fracture-geometry modeling and an understanding of local
porosity and saturation distributions. Our team are creative
problem solvers with expertise in wellbore mechanics, completion
design, production enhancement, artificial lift design, water
handling, facilities optimization, and production down-time
reduction.
Low Cost Development
. Shallow
conventional reservoirs (<8,000 feet) and short to
mid-range laterals (1.0 mile and 1.5 mile, respectively) allow
for efficient full-scale development without the requirement for
extended reach laterals and large fracs to meet economic
thresholds.
Management
. We have assembled a
management team at our Company with extensive experience in the
fields of business development, petroleum engineering, geology,
field development and production, operations, planning and
corporate finance. Our management team is headed by our Chief
Executive Officer, Simon Kukes, who was formerly the CEO at
Samara-Nafta, a Russian oil company partnering with Hess
Corporation, President and CEO of Tyumen Oil Company, and Chairman
of Yukos Oil. Our President, J. Douglas Schick, has over 20 years
of experience in the oil and gas industry, having co-founded
American Resources, Inc., and formerly serving in executive,
management and operational planning, strategy and finance roles at
Highland Oil and Gas, Mariner Energy, Inc., The Houston Exploration
Co., ConocoPhillips and Shell Oil Company. In addition, our
Executive Vice President and General Counsel, Clark R. Moore, has
over 15 years of energy industry experience, and formerly served as
acting general counsel of Erin Energy Corp. Several other members
of the management team have also successfully helped develop
similar companies with like kind asset profiles and technical
operations at Sheridan Production Company, Trinity Operating LLC,
Baker Hughes and Halliburton. We believe that our management team
is highly qualified to identify, acquire and exploit energy
resources in the U.S.
Our
operations team has extensive experience in horizontal development
of conventional assets in the Permian Basin at Sheridan Production
Company and experience drilling and completing unconventional wells
in the D-J Basin at Baker Hughes and Halliburton.
Our
board of directors also brings extensive oil and gas industry
experience, headed by our Chairman, John J. Scelfo, who brings over
40 years of experience in oil and gas management, finance and
accounting, and who served in numerous executive-level capacities
at Hess Corporation, including as Senior Vice President, Finance
and Corporate Development, Chief Financial Officer, Worldwide
Exploration & Producing, and as a member of Hess’
Executive Committee. In addition, our Board includes Ivar Siem, who
brings over 50 years of broad experience from both the upstream and
the service segments of the oil and gas industry, including serving
as Chairman of Blue Dolphin Energy Company (OTCQX: BDCO), as
Chairman and interim CEO of DI Industries/Grey Wolf Drilling, as
Chairman and CEO of Seateam Technology ASA, and in various
executive roles at multiple oil and gas exploration and production
(E&P) and oil field service companies. Furthermore, our Board
includes H. Douglas Evans, who brings over
50
years of experience in executive management positions with Gulf
Interstate Engineering Company, one of the world's top pipeline
design and engineering firms, including as its Honorary Chairman
and previously its Chairman and President and Chief Executive
Officer, and who is a past President and current Board member of
the International Pipe Line and Offshore Contractors Association,
current Chairman of its Strategy Committee, and an active member of
the Pipeline Contractors Association.
12
Significant acreage positions and
drilling potential
. As of December 31, 2020, we have
accumulated interests in a total of 37,068 net acres in our core
Permian Basin Asset operating area, and 11,948 net acres in our
core D-J Basin Asset operating area, both of which we believe
represent significant upside potential. The majority of our
interests are in or near areas of considerable activity by both
major and independent operators, although such activity may not be
indicative of our future operations. Based on our current acreage
position, we believe our Permian Basin Asset could contain up to
185 potential net wells, comprised of 170 net 1.0-mile lateral
wells and 15 net 1.5-mile lateral wells, on 160-acre spacing and
240-acre spacing, respectively. We believe our D-J Basin Asset
could contain up to 90 potential net wells, comprised of 49 net
1.0-mile lateral wells, 40 net 2.0-mile lateral wells, and 1 net
1.5-mile lateral well, on 80-acre spacing, 160-acre spacing, and
120-acre spacing, respectively, providing us with a substantial
drilling inventory for future years. Not all of these potential
well locations in our Permian Basin Asset and D-J Basin Asset are
included in our reserve report due to SEC guidelines related to
development timing.
Marketing
We
generally sell a significant portion of our oil and gas production
to a relatively small number of customers, and during the year
ended December 31, 2020, sales to two customers comprised
63% and 11%, respectively, of the Company’s total oil
and gas revenues. No other customer accounted for more than 10% of
our revenue during these periods. The Company is not dependent upon
any one purchaser and believes that, if its primary customers are
unable or unwilling to continue to purchase the Company’s
production, there are a substantial number of alternative buyers
for its production at comparable prices.
Oil
. Our
crude oil is generally sold under short-term, extendable and
cancellable agreements with unaffiliated purchasers. Crude oil
prices realized from production sales are indexed to published
posted refinery prices, and to published crude indexes with
adjustments on a contract basis. Transportation costs related to
moving crude oil are also deducted from the price received for
crude oil.
Natural
Gas
.
Our
natural gas is sold under both long-term and short-term natural gas
purchase agreements, which includes two gas purchase agreements for
our DJ Basin Asset that are in effect until December 1, 2021 and
April 1, 2032, respectively. However, natural gas sales related to
these agreements only represent a nominal 1% of our total
revenues as of December 31, 2020, and the Company believes that
this trend will continue in the DJ Basin Asset. Natural gas
produced by us is sold at various delivery points at or near
producing wells to both unaffiliated independent marketing
companies and unaffiliated mid-stream companies. We receive
proceeds from prices that are based on various pipeline indices
less any associated fees for processing, location or transportation
differentials.
Oil and Gas Properties
We
believe that our Permian Basin and D-J Basin assets represent among
the most economic oil and natural gas plays in the U.S. We plan to
opportunistically seek additional acreage proximate to our
currently held core acreage located in the Northwest Shelf of the
Permian Basin in Chaves and Roosevelt Counties, New Mexico, and the
Wattenberg and Wattenberg Extension areas of Weld County, Colorado
in the D-J Basin. Our strategy is to be the operator and/or a
significant working interest owner, directly or through our
subsidiaries and joint ventures, in the majority of our acreage so
we can dictate the pace of development in order to execute our
business plan. The majority of our capital expenditure budget
for 2020 will be focused on the development of our Permian Basin
Asset, and secondarily on development of our D-J Basin
Asset.
Unless otherwise noted,
the following table presents summary data for our leasehold acreage
in our core Permian Basin Asset and D-J Basin Asset as of December
31, 2020 and our drilling capital budget with respect to this
acreage from January 1, 2021 to December 31, 2021. This 2021
development plan is based upon our current outlook for the
remainder 2021 and is subject to further revision due to the
significant volatility in market conditions and historically high
levels of uncertainty affecting the oil and gas exploration sector,
with the ultimate amount of capital
we
will expend subject to
material fluctuations based on, among other things, market
conditions, commodity prices, asset monetizations, acquisitions,
permitting and regulatory matters, non-operated project proposals,
and availability of capital. We will further revise our development
plans as necessary to react to market conditions in the best
interest of our shareholders, while prioritizing its financial
strength and liquidity
(see “
Part I
” –
“
Item 1A. Risk
Factors
”.)
13
|
|
|
Drilling Capital
Budget
January 1, 2021 -
December 31, 2021
|
||
|
Current Core
Assets:
|
Net
Acres
|
Gross Wells
(1)
|
Gross
Costs
per
Well
|
Capital Cost to the
Company
|
|
Permian Basin
Asset
|
37,068
|
9.0
|
$
2,500,000
|
$
22,500,000
|
|
D-J Basin Asset
(2)
|
11,948
|
|
|
1,000,000
|
|
Enhancements
(3)
|
|
|
|
2,400,000
|
|
Facilities and
Infrastructure (4)
|
|
|
|
2,400,000
|
|
Total
|
49,106
|
9.0
|
|
$
28,300,000
|
|
(1)
|
Includes planned drilling and completion of nine 1.0-mile lateral
wells in the Chaveroo Field in the Permian Basin
Asset.
|
(2)
Estimated capital expenditures for outside operated projects in the
D-J Basin. Well cost estimates are unavailable until the Company
receives authorities for expenditure (“
AFEs
”) from the operator
with respect to specific well projects in which the Company may
elect to participate.
(3)
Estimated capital expenditures for electric submersible pump
(“
ESP
”)
purchases, rod pump conversions, recompletions, well cleanouts,
conversion of proved, developed, non-producing (“
PDNP
”) reserves to proved
developed (“
PDP
”) reserves. Includes
two wells brought online in the Permian Basin Asset in January
2021, following completion of a saltwater disposal
well.
(4)
Facility upgrades and buildout related to the Permian Basin Asset
Chaveroo Field drilling program.
Our Core Areas
Permian Basin Asset
We
hold our Permian Basin Assets through our wholly-owned subsidiary,
PEDCO, with operations conducted through PEDCO’s wholly-owned
operating subsidiaries, EOR Operating Company and Ridgeway Arizona
Oil Corp. Our Permian Basin Asset was assembled through three
acquisitions completed between 2018 and 2019. In the first
acquisition, we acquired 100% of the assets of Hunter Oil Company,
with an effective date of September 1, 2018, which created our core
Permian position. In 2019, we acquired additional assets in two
bolt-on acquisitions from private operators. These interests are
all located in Chaves and Roosevelt Counties, New Mexico, where we
currently operate 379 gross (302 net) wells, of which 26 wells
are active producers, 15 wells are active injectors, and two are
active SWDs. As of December 31, 2020, our Permian Basin Asset
acreage is located where indicated in the below map of the State of
New Mexico and more specifically in the areas shaded in yellow in
the subsequent sectional map.
14
State of New Mexico
15
It is
estimated that there are approximately 110 billion barrels of
oil-in-place in San Andres reservoirs across the Permian Basin
(Research Partnership to Secure Energy for America
(“
RPSEA
”) report dated
December 21, 2015). The San Andres oilfields of the Northwest
Shelf, Central Basin Platform and the Eastern Shelf are some of the
largest oilfields within the Permian Basin. According to the U.S.
Energy Information Administration (“
EIA
”), as of December 31,
2013, three oil fields that have produced from the San Andres
formation were amongst the top 50 largest oilfields by reserves in
the United States. The San Andres has been historically
under-developed due to technological and economic limitations
during early development. The San Andres is a dolomitic carbonate
reservoir characterized as being highly-heterogenous with a
multi-porosity system that typically shows significant oil
saturation, but primary production often yields higher than normal
water cut. While existing San Andres operators may ascribe
different drivers for the water cut, San Andres production requires
sufficient fluid removal, transportation and disposal, in order to
achieve higher oil cuts, through a network of on-site fluid storage
and saltwater disposal systems.
Oil was
originally trapped in the San Andres by three types of pre-Tertiary
traps: Structural, Stratigraphic and Structurally enhanced
Stratigraphic. Legacy fields exist where oil accumulated in these
traps to form thick oil columns, referred to as Main Pay Zones
(“
MPZ
”). Legacy San Andres
fields lack sharp oil-water contacts creating secondary zones of
increasing water saturation beneath the MPZ known as Transitional
Oil Zones (“
TOZ
”) and Residual
Oil Zones (“
ROZ
”). TOZs and ROZs also
extend outside the historical boundaries of the legacy fields
downdip to their structural limits. The vast majority of horizontal
San Andres wells have been drilled in these TOZ and ROZ areas where
vertical development is uneconomic.
16
The
Company’s 37,068 net acres within the Chaveroo and Milnesand
fields of Chaves and Roosevelt Counties, New Mexico offer a unique
opportunity to drill infill horizontal wells targeting the higher
oil-saturations of the MPZs. The Chaveroo NE field is an extension
of the Chaveroo field that was not originally developed vertically.
There are currently 379 wellbores within the leasehold, of which 26
are active producers and 15 are active injectors, and one is an
active SWD. The remainder are shut-in wellbores with future
potential utility for additional water injection, production
reactivations, and behind-pipe recompletions. We currently own and
operate three water handling facilities, one in each field, that
have a current combined capacity of approximately 60,000 barrels of
water per day (bbl/d).
D-J Basin Asset
We have
grown our legacy D-J Basin Asset position to 11,948 net acres in
Weld and Morgan Counties, Colorado.
We
directly hold all of our interests in the D-J Basin Asset through
our wholly-owned subsidiary, Red Hawk. These interests are all
located in Weld and Morgan Counties, Colorado. Red Hawk has an
interest in 77 gross (22.0 net) wells and is currently the
operator of 18 gross (16.2 net) wells located in our D-J Basin
Asset. Our D-J Basin Asset acreage is located in the areas shown in
the map below
. The D-J Basin had seen a tremendous amount of
growth in drilling activity until the COVID-19 pandemic and related
oil market crash in early 2020. D-J Basin operators are now
drilling 16 to 24 horizontal wells per section in the Niobrara and
Codell formations, utilizing the latest advances in completion
design, frac stages, and frac intensity to obtain favorable well
results. Notable non-operated partners leading the Niobrara revival
are Noble Energy (recently bought by Chevron Corporation), Bonanza
Creek Energy, and several private equity-backed independent E&P
companies. Other active operators in the area include Whiting
Petroleum, Anakarko Petroleum (recently bought by Occidental
Petroleum), SRC Energy, and Extraction Oil and Gas.
Weld and Morgan Counties, Colorado
17
Production, Sales Price and Production Costs
We have
listed below the total production volumes and total
revenue net to the Company for the years ended December 31,
2020, 2019, and 2018:
|
|
2020
|
2019
|
2018
|
|
|
|
|
|
|
Total
Revenues
|
$
8,059,000
|
$
12,972,000
|
$
4,523,000
|
|
|
|
|
|
|
Oil:
|
|
|
|
|
Total Production
(Bbls)
|
204,983
|
234,378
|
70,395
|
|
Average sales price
(per Bbl)
|
$
36.84
|
$
53.41
|
$
59.00
|
|
Natural
Gas:
|
|
|
|
|
Total Production
(Mcf)
|
191,337
|
153,251
|
89,769
|
|
Average sales price
(per Mcf)
|
$
1.72
|
$
2.43
|
$
2.56
|
|
NGL:
|
|
|
|
|
Total Production
(Bbls)
|
15,934
|
6,150
|
7,629
|
|
Average sales price
(per Bbl)
|
$
11.20
|
$
13.28
|
$
18.32
|
|
Oil
Equivalents:
|
|
|
|
|
Total Production
(Boe)
(1)
|
252,807
|
266,070
|
92,985
|
|
Average Daily
Production (Boe/d)
|
691
|
729
|
255
|
|
Average Production Costs (per
Boe)
(2)
|
$
13.09
|
$
15.32
|
$
19.77
|
_________________________
|
(1)
|
Assumes
6 Mcf of natural gas equivalents to 1 barrel of oil.
|
|
(2)
|
Excludes
workover costs, marketing, ad valorem and severance
taxes.
|
As of
December 31, 2020, and 2019, the Chaveroo and Milnesand fields are
the fields that each comprise 15% or more of our total proved
reserves. The applicable production volumes from these fields for
the years ended December 31, 2020, 2019, and 2018, are
represented in the table below in total barrels
(Bbls):
|
|
2020
|
2019
|
2018*
|
|
Chaveroo
|
129,332
|
120,765
|
3,631
|
|
Milnesand
|
7,868
|
11,295
|
2,917
|
*
In 2018,
production from our
acquisition of the Chaveroo and Milnesand fields in the third
quarter 2018 are the fields that each comprised 15% or more of our
total proved reserves at December 31, 2018. The data above only
includes production for these fields since the acquisition in the
third quarter of 2018.
The
following table summarizes our gross and net developed and
undeveloped leasehold and mineral fee acreage at December 31,
2020:
|
|
Total
|
Developed
(1)
|
Undeveloped
(2)
|
|||
|
|
Gross
|
Net
|
Gross
|
Net
|
Gross
|
Net
|
|
D-J
Basin
|
205,994
|
11,948
|
183,370
|
9,388
|
22,624
|
2,560
|
|
Permian
Basin
|
39,458
|
37,068
|
31,813
|
31,036
|
7,645
|
6,032
|
|
Total
|
245,452
|
49,016
|
215,183
|
40,424
|
30,269
|
8,592
|
(1) Developed
acreage is the number of acres that are allocated or assignable to
producing wells or wells capable of production.
(2) Undeveloped
acreage is lease 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 includes proved reserves.
We
believe we have satisfactory title, in all material respects, to
substantially all of our producing properties in accordance with
standards generally accepted in the oil and natural gas
industry.
18
Total Net Undeveloped Acreage Expiration
In the event that production is not established or
we take no action to extend or renew the terms of our leases, our
net undeveloped acreage that will expire over the next three years
as of December 31, 2020, is
3,865, 1,395 and 80, for the years ending
December 31, 2021, 2022 and 2023, respectively. We expect to
retain substantially all of our expiring acreage either through
drilling activities, renewal of the expiring leases or through the
exercise of extension options.
Well Summary
The
following table presents our ownership in productive crude oil and
natural gas wells at December 31, 2020. This summary includes crude
oil wells in which we have a working interest:
|
|
Gross
|
Net
|
|
Crude
oil
|
125.0
|
91.1
|
|
Natural
gas
|
-
|
-
|
|
Total*
|
125.0
|
91.1
|
*
Total percentage
of gross operated wells is 70.4%.
Drilling Activity
We
drilled wells or participated in the drilling of wells as indicated
in the table below:
|
|
2020
|
2019
|
2018
|
|||
|
|
Gross
|
Net
|
Gross
|
Net
|
Gross
|
Net
|
|
Development
|
|
|
|
|
|
|
|
Productive
|
-
|
-
|
20
|
9.6
|
-
|
-
|
|
Dry
|
-
|
-
|
-
|
-
|
-
|
-
|
|
Exploratory
|
|
|
|
|
|
|
|
Productive
|
-
|
-
|
-
|
-
|
-
|
-
|
|
Dry
|
-
|
-
|
-
|
-
|
-
|
-
|
Oil and Natural Gas Reserves
Reserve Information.
For estimates of the Company’s
net proved producing reserves of crude oil and natural gas, as well
as discussion of the Company’s proved and probable
undeveloped reserves, see
“
Part II
” -
“
Item 8 Financial
Statements and Supplementary Data
” – “
Supplemental Oil and
Gas Disclosures (Unaudited)
”. At December 31,
2020, the Company’s total estimated proved reserves were 14.1
million Boe, of which 12.1 million Bbls were crude oil and NGL
reserves, and 11.9 million Mcf were natural gas
reserves.
Internal Controls.
Boris Litvak, Senior
Reserve Engineering Consultant, is the technical person primarily
responsible for our internal reserves estimation process (which are
based upon the best available production, engineering and geologic
data) and provides oversight of the annual audit of our year end
reserves by our independent third party engineers. He has a PhD
degree in Petroleum Engineering, and in excess of twenty years as a
reserves estimator and former Manager of Reservoir Engineering
Department for Texaco, and was an invited speaker for the Society
of Petroleum Engineers.
The
preparation of our reserve estimates is in accordance with our
prescribed procedures that include verification of input data into
a reserve forecasting and economic software, as well as management
review. Our reserve analysis includes, but is not limited to, the
following:
●
Research of
operators near our lease acreage. Review operating and
technological techniques, as well as reserve projections of such
wells.
●
The review of
internal reserve estimates by well and by area by a qualified
petroleum engineer. A variance by well to the previous year-end
reserve report is used as a tool in this process.
●
SEC-compliant
internal policies to determine and report proved
reserves.
●
The discussion of
any material reserve variances among management to ensure the best
estimate of remaining reserves.
19
Qualifications of Third-Party
Engineers.
The technical person
primarily responsible for the audit of our reserves estimates
at
Cawley, Gillespie & Associates, Inc.
is W. Todd Brooker, who meets the requirements
regarding qualifications, independence, objectivity, and
confidentiality set forth in the Standards Pertaining to the
Estimating and Auditing of Oil and Gas Reserves Information
promulgated by the Society of Petroleum Engineers.
Cawley,
Gillespie & Associates, Inc. is an independent firm and does
not own an interest in our properties and is not employed on a
contingent fee basis. Reserve estimates are imprecise and
subjective and may change at any time as additional information
becomes available. Furthermore, estimates of oil and gas reserves
are projections based on engineering data. There are uncertainties
inherent in the interpretation of this data as well as the
projection of future rates of production. The accuracy of any
reserve estimate is a function of the quality of available data and
of engineering and geological interpretation and judgment. A copy
of the report issued by Cawley, Gillespie & Associates, Inc. is
attached to this report as Exhibit 99.1.
For
more information regarding our oil and gas reserves, please refer
to “
Item 8 Financial
Statements and Supplementary Data
” – “
Supplemental Oil and
Gas Disclosures (Unaudited)
”.
PPP Loan
On June
2, 2020, the Company received loan proceeds of $370,000 under the
U. S. Small Business Administration’s Paycheck Protection
Program established as part of the Coronavirus Aid, Relief and
Economic Security Act described in further detail in “Part
II” - “Item 8. Financial Statements and Supplementary
Data” – “
Note 7 – PPP
Loan
”. Forgiveness of this loan has been applied for
and is currently pending approval.
Drilling and Completion Activities
In
2019, we commenced drilling four San Andres horizontal wells in our
Permian Basin Asset, for which drilling operations were completed
in September 2019, and for which completion operations commenced in
November and December of 2019. Three of these wells had their
completion operations finalized in the first quarter of 2020 and
then were brought online for production but were shut-in
temporarily starting in April 2020 due to the
COVID-19 outbreak in early 2020 and the sharp
decline in oil prices that followed
. In September 2020, an
additional SWD well was completed to support our Permian Basin
Assets, providing an additional 20,000 barrels of water per day of
disposal capacity and activation of the fourth San Andres
horizontal well. This SWD well will also provide the future ability
to produce multiple additional development wells, without the need
for further significant infrastructure enhancements.
SandRidge Permian Trust Offer to Exchange
On
October 13, 2020 we commenced an exchange offer (the
“
Exchange
Offer
”), wherein we offered to exchange each issued
and outstanding common unit of beneficial interest of SandRidge
Permian Trust (OTC Pink Sheets: PERS) (the “
Trust
’) for 4/10ths of
one share of our common stock. On November 17, 2020, we terminated
the Exchange Offer following our evaluation of the Trust’s
Quarterly Report on Form 10-Q for the quarter ended September 30,
2020, wherein the Trust provided further details regarding the
divestiture of certain of its assets first announced on October 14,
2020. As a result of our evaluation of the details regarding the
Trust’s asset divestiture, we determined that the Trust had
been materially and adversely stripped of significant value for
which it was not fairly compensated, and we therefore elected to
terminate our Exchange Offer. We incurred approximately $501,000 in
expenses related to the Exchange Offer.
Recent Event
Common Stock Offering
On
February 5, 2021, the Company closed
an underwritten public offering of 5,968,500
shares of common stock at a public offering price of $1.50 per
share, which included the full exercise of the underwriter’s
over-allotment option, for
net proceeds (after deducting the
underwriters’ discount equal to 6% of the public offering
price and expenses associated with the offering) of approximately
$8.3 million.
The Company intends to
use the majority of the net proceeds from the offering (i) to fund
the Company’s 2021 Permian Basin and D-J Basin asset
development programs, (ii) to fund potential acquisition and
business combination opportunities, and (iii) for general corporate
purposes and working capital or for other purposes that the Board
of Directors, in their good faith, deems to be in the best interest
of the Company.
20
Regulation of the Oil and Gas Industry
All of
our oil and gas operations are substantially affected by federal,
state and local laws and regulations. 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. Historically, our
compliance costs have not had a material adverse effect on our
results of operations; however, we are unable to predict the future
costs or impact of compliance.
Additional proposals and proceedings that affect
the oil and natural gas industry are regularly considered by
Congress, the states, the Federal Energy Regulatory Commission (the
“
FERC
”) and
the courts. We cannot predict when or whether any such proposals
may become effective. We do not believe that we would be affected
by any such action materially differently than similarly situated
competitors.
At the
state level, our operations in Colorado are regulated by the
Colorado Oil & Gas Conservation Commission (“
COGCC
”) and our New
Mexico operations are regulated by the Conservation Division of the
New Mexico Energy, Minerals, and Natural Resources Department
(regulates oil and gas operations), New Mexico Environment
Department (administers environmental protection laws), and the New
Mexico State Land Office (oversees surface and mineral acres and
development). The Oil Conservation Division of the New Mexico
Energy, Minerals, Natural Resources Department, and New Mexico
State Land Office require the posting of financial assurance for
owners and operators on privately owned or state land within New
Mexico in order to provide for abandonment restoration and
remediation of wells, and for the drilling of salt water disposal
wells.
The COGCC regulates oil and gas operators through
rules, policies, written guidance, orders, permits, and
inspections. Among other things, the COGCC enforces specifications
regarding drilling, development, production, reclamation, enhanced
recovery, safety, aesthetics, noise, waste, flowlines, and
wildlife. In recent years, the COGCC has amended its existing
regulatory requirements and adopted new requirements with increased
frequency. For example, in January 2016, the COGCC approved new
rules that require local government consultation and certain best
management practices for large-scale oil and natural gas facilities
in certain urban mitigation areas. These rules also require
operator registration and/or notifications to local governments
with respect to future oil and natural gas drilling and production
facility locations. In February 2018, the COGCC comprehensively
amended its regulations for oil, gas, and water flowlines to expand
requirements addressing flowline registration and safety, integrity
management, leak detection, and other matters. The COGCC has also
adopted or amended numerous other rules in recent years, including
rules relating to safety, flood protection, and spill reporting. In
December 2018, the COGCC approved new rules that require new oil
and gas sites to be situated at least 1,000 feet away from school
properties such as playgrounds and athletic fields.
Most recently, in 2019, Colorado
enacted Senate Bill 19-181 (“
SB
19-181
”), which changes
the mission of the COGCC from fostering responsible and balanced
development to regulating development to protect public health and
the environment and directs the COGCC to undertake rulemaking on
various operational matters including environmental protection,
facility siting and wellbore integrity. Pursuant to this directive,
in December 2019, the COGCC proposed new regulatory requirements to
enhance safety and environmental protection during hydraulic
fracturing and to enhance wellbore integrity.
We anticipate that the COGCC,
the
Conservation Division of the New Mexico Energy, Minerals, Natural
Resources Department, the New Mexico State Land Office, the New
Mexico Environment Department and other federal, state and local
authorities will continue to adopt new rules and regulations moving
forward which will likely affect our oil and gas operations and
could make it more costly for our operations or limit our
activities. We routinely monitor our operations and new rules and
regulations which may affect our operations, to ensure that we
maintain compliance.
Regulation Affecting Production
The
production of oil and natural gas is subject to United States
federal and state laws and regulations, and orders of regulatory
bodies under those laws and regulations, governing a wide variety
of matters. All of the jurisdictions in which we own or operate
producing oil and natural gas properties have statutory provisions
regulating the exploration for and production of oil and natural
gas, 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 abandonment of wells. Our operations are also
subject to various conservation laws and regulations. These include
the regulation of the size of drilling and spacing units or
proration units, the number of wells which may be drilled in an
area, and the unitization or pooling of oil or natural gas wells,
as well as regulations that generally prohibit the venting or
flaring of natural gas, and impose certain requirements regarding
the ratability or fair apportionment of production from fields and
individual wells. These laws and regulations may limit the amount
of oil and gas wells we can drill. Moreover, each state generally
imposes a production or severance tax with respect to the
production and sale of oil, NGL and gas within its
jurisdiction.
21
States
do not regulate wellhead prices or engage in other similar direct
regulation, but there can be no assurance that they will not do so
in the future. The effect of such future regulations may be to
limit the amounts of oil and gas that may be produced from our
wells, negatively affect the economics of production from these
wells or limit the number of locations we can drill.
The
failure to comply with the rules and regulations of oil and natural
gas production and related operations can result in substantial
penalties. Our competitors in the oil and natural gas industry are
subject to the same regulatory requirements and restrictions that
affect our operations.
Regulation Affecting Sales and Transportation of
Commodities
Sales
prices of gas, oil, condensate and NGL are not currently regulated
and are made at market prices. Although prices of these energy
commodities are currently unregulated, the United States Congress
historically has been active in their regulation. We cannot predict
whether new legislation to regulate oil and gas, or the prices
charged for these commodities might be proposed, what proposals, if
any, might actually be enacted by the United States Congress or the
various state legislatures and what effect, if any, the
proposals might have on our operations. Sales of oil and natural
gas may be subject to certain state and federal reporting
requirements.
The
price and terms of service of transportation of the commodities,
including access to pipeline transportation capacity, are subject
to extensive federal and state regulation. Such regulation may
affect the marketing of oil and natural gas produced by the
Company, as well as the revenues received for sales of such
production. Gathering systems may be subject to state ratable take
and common purchaser statutes. Ratable take statutes generally
require gatherers to take, without undue discrimination, oil and
natural gas production that may be tendered to the gatherer for
handling. Similarly, common purchaser statutes generally require
gatherers to purchase, or accept for gathering, without undue
discrimination as to source of supply or producer. These statutes
are designed to prohibit discrimination in favor of one producer
over another producer or one source of supply over another source
of supply. These statutes may affect whether and to what extent
gathering capacity is available for oil and natural gas production,
if any, of the drilling program and the cost of such capacity.
Further state laws and regulations govern rates and terms of access
to intrastate pipeline systems, which may similarly affect market
access and cost.
The
FERC regulates interstate natural gas pipeline transportation rates
and service conditions. The FERC is continually proposing and
implementing new rules and regulations affecting interstate
transportation. The stated purpose of many of these regulatory
changes is to ensure terms and conditions of interstate
transportation service are not unduly discriminatory or unduly
preferential, to promote competition among the various sectors of
the natural gas industry and to promote market transparency. We do
not believe that our drilling program will be affected by any such
FERC action in a manner materially differently than other similarly
situated natural gas producers.
In addition to the regulation of natural gas
pipeline transportation, the FERC has additional, jurisdiction over
the purchase or sale of gas or the purchase or sale of
transportation services subject to the FERC’s jurisdiction
pursuant to the Energy Policy Act of 2005
(“
EPAct
2005
”). Under the EPAct
2005, it is unlawful for “
any
entity,
” including
producers such as us, that are otherwise not subject to
FERC’s jurisdiction under the Natural Gas Act of 1938
(“
NGA
”) to use any deceptive or manipulative
device or contrivance in connection with the purchase or sale of
gas or the purchase or sale of transportation services subject to
regulation by FERC, in contravention of rules prescribed by the
FERC. The FERC’s rules implementing this provision make it
unlawful, in connection with the purchase or sale of gas subject to
the jurisdiction of the FERC, or the purchase or sale of
transportation services subject to the jurisdiction of the FERC,
for any entity, directly or indirectly, to use or employ any
device, scheme or artifice to defraud; to make any untrue statement
of material fact or omit to make any such statement necessary to
make the statements made not misleading; or to engage in any act or
practice that operates as a fraud or deceit upon any person. EPAct
2005 also gives the FERC authority to impose civil penalties for
violations of the NGA and the Natural Gas Policy Act of 1978 up to
$1.2 million per day, per violation. The anti-manipulation
rule applies to activities of otherwise non-jurisdictional entities
to the extent the activities are conducted
“
in connection
with
” gas sales,
purchases or transportation subject to FERC jurisdiction, which
includes the annual reporting requirements under FERC Order
No. 704 (defined below).
In December 2007, the FERC issued a final rule on
the annual natural gas transaction reporting requirements, as
amended by subsequent orders on rehearing
(“
Order
No. 704
”). Under
Order No. 704, any market participant, including a producer
that engages in certain wholesale sales or purchases of gas that
equal or exceed 2.2 trillion BTUs of physical natural gas in
the previous calendar year, must annually report such sales and
purchases to the FERC on Form No. 552 on May 1 of each
year. Form No. 552 contains aggregate volumes of natural gas
purchased or sold at wholesale in the prior calendar year to the
extent such transactions utilize, contribute to the formation of
price indices. Not all types of natural gas sales are required to
be reported on Form No. 552. It is the responsibility of the
reporting entity to determine which individual transactions should
be reported based on the guidance of Order No. 704. Order
No. 704 is intended to increase the transparency of
the wholesale gas markets and to assist the FERC in monitoring
those markets and in detecting market manipulation. We are not
currently subject to the requirement to report on Form No. 552, as
our sales of oil and natural gas do not rise to the minimum level
required for reporting by Order No. 704.
22
The FERC also regulates rates and terms and
conditions of service on interstate transportation of liquids,
including oil and NGL, under the Interstate Commerce Act, as it
existed on October 1, 1977 (“
ICA
”). Prices received from the sale of liquids
may be affected by the cost of transporting those products to
market. The ICA requires that certain interstate liquids pipelines
maintain a tariff on file with the FERC. The tariff sets forth the
established rates as well as the rules and regulations governing
the service. The ICA requires, among other things, that rates and
terms and conditions of service on interstate common carrier
pipelines be “
just and
reasonable.
” Such
pipelines must also provide jurisdictional service in a manner that
is not unduly discriminatory or unduly preferential. Shippers have
the power to challenge new and existing rates and terms and
conditions of service before the FERC.
The
rates charged by many interstate liquids pipelines are currently
adjusted pursuant to an annual indexing methodology established and
regulated by the FERC, under which pipelines increase or decrease
their rates in accordance with an index adjustment specified by the
FERC. For the five-year period beginning July 1, 2016, the
FERC established an annual index adjustment equal to the change in
the producer price index for finished goods plus 1.23%. This
adjustment is subject to review every five years. Under the
FERC’s regulations, a liquids pipeline can request a rate
increase that exceeds the rate obtained through application of the
indexing methodology by obtaining market-based rate authority
(demonstrating the pipeline lacks market power), establishing rates
by settlement with all existing shippers, or through a
cost-of-service approach (if the pipeline establishes that a
substantial divergence exists between the actual costs experienced
by the pipeline and the rates resulting from application of the
indexing methodology). Increases in liquids transportation rates
may result in lower revenue and cash flows for the
Company.
In
addition, due to common carrier regulatory obligations of liquids
pipelines, capacity must be prorated among shippers in an equitable
manner in the event there are nominations in excess of capacity or
new shippers. Therefore, new shippers or increased volume by
existing shippers may reduce the capacity available to us. Any
prolonged interruption in the operation or curtailment of available
capacity of the pipelines that we rely upon for liquids
transportation could have a material adverse effect on our
business, financial condition, results of operations and cash
flows. However, we believe that access to liquids pipeline
transportation services generally will be available to us to the
same extent as to our similarly situated competitors.
Rates
for intrastate pipeline transportation of liquids are subject to
regulation by state regulatory commissions. The basis for
intrastate liquids pipeline regulation, and the degree of
regulatory oversight and scrutiny given to intrastate liquids
pipeline rates, varies from state to state. We believe that the
regulation of liquids pipeline transportation rates will not affect
our operations in any way that is materially different from the
effects on our similarly situated competitors.
In addition to the FERC’s regulations, we
are required to observe anti-market manipulation laws with regard
to our physical sales of energy commodities. In November 2009, the
Federal Trade Commission (“
FTC
”) issued regulations pursuant to the
Energy Independence and Security Act of 2007, intended to prohibit
market manipulation in the petroleum industry. Violators of the
regulations face civil penalties of up to $1 million per
violation per day. In July 2010, Congress passed the Dodd-Frank
Act, which incorporated an expansion of the authority of the
Commodity Futures Trading Commission (“
CFTC
”) to
prohibit market manipulation in the markets regulated by the CFTC.
This authority, with respect to oil swaps and futures contracts, is
similar to the anti-manipulation authority granted to the FTC with
respect to oil purchases and sales. In July 2011, the CFTC issued
final rules to implement their new anti-manipulation authority. The
rules subject violators to a civil penalty of up to the greater of
$1.1 million or triple the monetary gain to the person for
each violation.
Our operations are subject to stringent federal,
state and local laws and regulations governing occupational safety
and health aspects of our operations, the discharge of materials
into the environment and environmental protection. Numerous
governmental entities, including the U.S. Environmental Protection
Agency (“
EPA
”) and analogous state agencies have
the power to enforce compliance with these laws and regulations and
the permits issued under them, often requiring difficult and costly
actions. These laws and regulations may, among other things
(i) require the acquisition of permits to conduct drilling and
other regulated activities; (ii) restrict the types,
quantities and concentration of various substances that can be
released into the environment or injected into formations in
connection with oil and natural gas drilling and production
activities; (iii) limit or prohibit drilling activities on
certain lands lying within wilderness, wetlands and other protected
areas; (iv) require remedial measures to mitigate pollution
from former and ongoing operations, such as requirements to close
pits and plug abandoned wells; (v) apply specific health and
safety criteria addressing worker protection; and (vi) impose
substantial liabilities for pollution resulting from drilling and
production operations. Any failure to comply with these laws and
regulations may result in the assessment of administrative, civil
and criminal penalties, the imposition of corrective or remedial
obligations, the occurrence of delays or restrictions in permitting
or performance of projects, and the issuance of orders enjoining
performance of some or all of our operations.
23
These
laws and regulations may also restrict the rate of oil and natural
gas production below the rate that would otherwise be possible. The
regulatory burden on the oil and natural gas industry increases the
cost of doing business in the industry and consequently affects
profitability. The trend in environmental regulation is to place
more restrictions and limitations on activities that may affect the
environment, and thus any changes in environmental laws and
regulations or re-interpretation of enforcement policies that
result in more stringent and costly well drilling, construction,
completion or water management activities, or waste handling,
storage transport, disposal, or remediation requirements could have
a material adverse effect on our financial position and results of
operations. We may be unable to pass on such increased compliance
costs to our customers. Moreover, accidental releases or spills may
occur in the course of our operations, and we cannot assure you
that we will not incur significant costs and liabilities as a
result of such releases or spills, including any third-party claims
for damage to property, natural resources or persons. Continued
compliance with existing requirements is not expected to materially
affect us. However, there is no assurance that we will be able to
remain in compliance in the future with such existing or any new
laws and regulations or that such future compliance will not have a
material adverse effect on our business and operating
results.
Additionally, on January 14, 2019, in
Martinez v.
Colorado Oil and Gas Conservation Commission
, the Colorado Supreme Court overturned a ruling
by the Colorado Court of Appeals that held that the Colorado Oil
& Gas Conservation Commission (“
COGCC
”) had
held that the COGCC concluded that it lacked statutory authority to
undertake a proposed rulemaking “to suspend the issuance of
permits that allow hydraulic fracturing until it can be done
without adversely impacting human health and safety and without
impairing Colorado’s atmospheric resource and climate system,
water, soil, wildlife, or other biological resources.” The
Colorado Court of Appeals concluded that Colorado’s Oil and
Gas Conservation Act mandated that oil and gas development
“be regulated subject to the protection of public health,
safety, and welfare, including protection of the environment and
wildlife resources.”
In the
Colorado Supreme Court’s majority opinion, Justice Richard L.
Gabriel wrote the COGCC is required first to “foster the
development of oil and gas resources” and second “to
prevent and mitigate significant environmental impacts to the
extent necessary to protect public health, safety and welfare, but
only after taking into consideration cost-effectiveness and
technical feasibility.”
The
following is a summary of the more significant existing and
proposed environmental and occupational safety and health laws, as
amended from time to time, to which our business operations are or
may be subject and for which compliance may have a material adverse
impact on our capital expenditures, results of operations or
financial position.
Hazardous Substances and Wastes
The Resource Conservation and Recovery Act
(“
RCRA
”),
and comparable state statutes, regulate the generation,
transportation, treatment, storage, disposal and cleanup of
hazardous and non-hazardous wastes. Pursuant to rules issued by the
EPA, the individual states administer some or all of the provisions
of RCRA, sometimes in conjunction with their own, more stringent
requirements. Drilling fluids, produced waters, and most of the
other wastes associated with the exploration, development, and
production of oil or natural gas, if properly handled, are
currently exempt from regulation as hazardous waste under RCRA and,
instead, are regulated under RCRA’s less stringent
non-hazardous waste provisions, state laws or other federal laws.
However, it is possible that certain oil and natural gas drilling
and production wastes now classified as non-hazardous could be
classified as hazardous wastes in the future.
Stricter regulation of wastes generated during our
operations could result in an increase in our, as well as the oil
and natural gas exploration and production industry’s, costs
to manage and dispose of wastes, which could have a material
adverse effect on our results of operations and financial
position.
In
December 2016, the U.S. District Court for the District of Columbia
approved a consent decree between the EPA and a coalition of
environmental groups. The consent decree requires the EPA to review
and determine whether it will revise the RCRA regulations for
exploration and production waste to treat such waste as hazardous
waste. In April 2019, the EPA, pursuant to the consent decree,
determined that revision of the regulations is not necessary.
Information comprising the EPA’s review and decision is
contained in a document entitled “Management of Exploration,
Development and Production Wastes: Factors Informing a Decision on
the Need for Regulatory Action”. The EPA indicated that it
will continue to work with states and other organizations to
identify areas for continued improvement and to address emerging
issues to ensure that exploration, development and production
wastes continue to be managed in a manner that is protective of
human health and the environment. Environmental groups, however,
expressed dissatisfaction with the EPA’s decision and will
likely continue to press the issue at the federal and state
levels.
24
The Comprehensive Environmental Response,
Compensation and Liability Act (“
CERCLA
”),
also known as the Superfund law, and comparable state laws impose
joint and several liability, without regard to fault or legality of
conduct, on classes of persons who are considered to be responsible
for the release of a hazardous substance into the environment.
These persons include the current and former owners and operators
of the site where the release occurred and anyone who disposed or
arranged for the disposal of a hazardous substance released at the
site. Under CERCLA, such persons may be subject to joint and
several liability for the costs of cleaning up the hazardous
substances that have been released into the environment, for
damages to natural resources and for the costs of certain health
studies. CERCLA also authorizes the EPA and, in some instances,
third parties to act in response to threats to the public health or
the environment and to seek to recover from the responsible classes
of persons the costs they incur. 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 the
hazardous substances released into the environment. We generate
materials in the course of our operations that may be regulated as
hazardous substances.
We
currently lease or operate numerous properties that have been used
for oil and natural gas exploration, production and processing for
many years. Although we believe that we have utilized operating and
waste disposal practices that were standard in the industry at the
time, hazardous substances, wastes, or petroleum hydrocarbons may
have been released on, under or from the properties owned or leased
by us, or on, under or from other locations, including off-site
locations, where such substances have been taken for treatment or
disposal. In addition, some of our properties have been operated by
third parties or by previous owners or operators whose treatment
and disposal of hazardous substances, wastes, or petroleum
hydrocarbons was not under our control. These properties and the
substances disposed or released on, under or from them may be
subject to CERCLA, RCRA and analogous state laws. Under such laws,
we could be required to undertake response or corrective measures,
which could include removal of previously disposed substances and
wastes, cleanup of contaminated property or performance of remedial
plugging or pit closure operations to prevent future contamination,
the costs of which could be substantial.
Water Discharges
The federal Clean Water Act
(“
CWA
”) and analogous state laws impose
strict controls concerning the discharge of pollutants and fill
material, including spills and leaks of crude oil and other
substances. The CWA also requires approval and/or permits prior to
construction, where construction will disturb certain wetlands or
other waters of the U.S. In February 2019, the EPA and the USACE
published a proposed new rule that would differently revise the
definition of “waters of the United States” and
essentially replace both a prior rule from 1986 and the EPA rule
adopted in June 2015, that attempted to clarify the CWA’s
jurisdictional reach over “waters of the United States”
(the “
2015 Clean Water
Rule
”). On January 23,
2020, the EPA and USACE announced the final new rule, titled the
Navigable Waters Protection Rule (“
2020
Rule
”). The 2020 Rule
became effective on June 22, 2020. The 2020 Rule generally
regulates four categories of “jurisdictional” waters:
(i) territorial seas and traditional navigable waters (i.e.,
large rivers); (ii) perennial and intermittent tributaries of
these waters; (iii) certain lakes, ponds and impoundments; and
(iv) wetlands to jurisdictional waters. The 2020 Rule also
includes 12 categories of exclusions, or
“non-jurisdictional” waters, including groundwater,
ephemeral features and diffuse stormwater run-off over upland
areas. The 2020 Rule likely regulates fewer wetlands areas than
were regulated under the 1986 rule and the 2015 Clean Water Rule
because it does not regulate wetlands that are not adjacent to
jurisdictional waters. This new definition of “waters of the
United States” has been challenged and sought to be enjoined
in federal court.
On June
19
,
2020 the U.S. District Court for the District of
Colorado issued an administrative stay that enjoined the
effectiveness of the 2020 Rule within Colorado.
State of Colorado v. U.S.
Environmental Protection Agency, et al.,
Civil Action No. 20-cv-1461-WJM-NRN. (D.C. Colo.
Jun. 19, 2020). With this stay in place, EPA and USACE jurisdiction
is pursuant to the 1986 rule and subsequent guidance. The 2020 Rule
changes the scope of the CWA’s
jurisdiction
, in every state
except Colorado, which could result in increased costs and delays
with respect to obtaining permits for discharges of pollutants or
dredge and fill activities in waters of the U.S., including
regulated wetland areas.
In
January 2017, the Army Corps of Engineers issued revised and
renewed streamlined general nationwide permits that are available
to satisfy permitting requirements for certain work in streams,
wetlands and other waters of the U.S. under Section 404 of the CWA
and the Rivers and Harbors Act. The new nationwide permits
took effect in March 2017, or when certified by each state,
whichever was later. The oil and gas industry broadly utilizes
nationwide permits 12, 14 and 39 for the construction, maintenance
and repair of pipelines, roads and drill pads, respectively, and
related structures in waters of the U.S. that impact less than a
half-acre of waters of the U.S. and meet the other criteria of each
nationwide permit.
25
In May 2020, a federal
court in Montana enjoined the use of Nationwide Permit 12 to
construct new oil and gas-related pipelines, on the basis that
the
Army Corps of
Engineers
had not properly
consulted with the U.S. Fish and Wildlife Service when that permit
was renewed in 2017. The U.S. Supreme Court in July 2020
significantly narrowed the Montana court’s injunction to
cover only the challenged XL Pipeline. The Montana court’s
substantive decision is now on appeal to the Ninth Circuit, whose
ultimate ruling could affect the oil and gas industry’s
ability to use this streamlined permit. In the meantime, in
September 2020, the
Army Corps
of Engineers
issued a proposal to
revise and reissue all 52 current nationwide permits, including No.
12, to lessen the burden on the energy industry and address the
flaws alleged in the Montana lawsuit. Among other things, under
that proposal existing Nationwide Permit 12 would be broken up into
three new separate nationwide permits, with the proposed new
Nationwide Permit 12 being limited solely to construction and
maintenance of oil and gas pipelines, with other utility-related
structures covered by the two new nationwide permits. The proposed
new No. 12 would also have decreased requirements for
pre-construction notification to the
Army Corps of Engineers
. It is unknown at this
time whether that proposed rule will be finalized by the end of the
current administration or, if not, whether it will be abandoned or
revised by the incoming administration. If the current or revised
version of Nationwide Permit 12 is invalidated or stayed by the
courts, it would increase the costs and delays for oil and gas
operators to construct or maintain pipelines that cross
jurisdictional waters of the U.S.
The CWA also regulates storm water run-off from
crude oil and natural gas facilities and requires storm water
discharge permits for certain activities. Spill Prevention, Control
and Countermeasure (“
SPCC
”) requirements
of the CWA require appropriate secondary containment, load out
controls, piping controls, berms and other measures to help prevent
the contamination of navigable waters in the event of a petroleum
hydrocarbon spill, rupture or leak.
Subsurface Injections
In the course of our operations, we produce water
in addition to oil and natural gas. Water that is not recycled may
be disposed of in disposal wells, which inject the produced water
into non-producing subsurface formations. Underground injection
operations are regulated pursuant to the Underground Injection
Control (“
UIC
”) program established under the
federal Safe Drinking Water Act (“
SDWA
”) and
analogous state laws. The UIC program requires permits from the EPA
or an analogous state agency for the construction and operation of
disposal wells, establishes minimum standards for disposal well
operations, and restricts the types and quantities of fluids that
may be disposed. A change in UIC disposal well regulations or the
inability to obtain permits for new disposal wells in the future
may affect our ability to dispose of produced water and ultimately
increase the cost of our operations.
For example, in response to recent seismic events
near belowground disposal wells used for the injection of oil and
natural gas-related wastewaters, regulators in some states,
including Colorado, have imposed more stringent permitting and
operating requirements for produced water disposal wells. In
Colorado, permit applications are reviewed specifically to evaluate
seismic activity and, since 2011, the state has required operators
to identify potential faults near proposed wells, if earthquakes
historically occurred in the area, and to accept maximum injection
pressures and volumes based on fracture gradient as conditions to
permit approval. Additionally, legal disputes may arise based on
allegations that disposal well operations have caused damage to
neighboring properties or otherwise violated state or federal rules
regulating waste disposal. These developments could result in
additional regulation, restriction on the use of injection wells by
us or by commercial disposal well vendors whom we may use from time
to time to dispose of wastewater, and increased costs of
compliance, which could have a material adverse effect on our
capital expenditures and operating costs, financial condition, and
results of operations.
Air Emissions
Our operations are subject to the Clean Air Act
(the “
CAA
”) and comparable state and local
requirements. The CAA contains provisions that may result in the
gradual imposition of certain pollution control requirements with
respect to air emissions from our operations. The EPA and state
governments continue to develop regulations to implement these
requirements. We may be required to make certain capital
investments in the next several years for air pollution control
equipment in connection with maintaining or obtaining operating
permits and approvals addressing other air emission-related
issues.
In
June 2016, the EPA implemented new requirements focused on
achieving additional methane and volatile organic compound
reductions from the oil and natural gas industry. The rules
imposed, among other things, new requirements for leak detection
and repair, control requirements for oil well completions,
replacement of certain pneumatic pumps and controllers and
additional control requirements for gathering, boosting and
compressor stations. In September 2018, the EPA proposed revisions
to the 2016 rules. The proposed amendments address certain
technical issues raised in administrative petitions and include
proposed changes to, among other things, the frequency of
monitoring for fugitive emissions at well sites and compressor
stations. In September 2020, the EPA issued a new rule which
amended the 2016 requirements. In this rule, the EPA removed all
sources in the transmission and storage segment of the oil and
natural gas industry from regulation. The rule also rescinded the
methane requirements in the 2016 regulations and loosened
monitoring and repair regulations aimed at preventing methane
leaks. The new rule was challenged in the U.S. Court of Appeals for
the D.C. Circuit, but in October 2020 the Court declined to issue a
permanent stay of the new rule while it considered the merits of
the challenge. The new rule therefore is currently in effect.
However, the future of the new rule is in flux as the Court could
vacate the rule such that the original 2016 regulations would go
back into effect.
26
In
November 2016, the BLM finalized rules to further regulate venting,
flaring and leaks during oil and natural gas production activities
on onshore federal and Indian leases. The rules require additional
controls and impose new emissions and other standards on certain
operations on applicable leases, including committed state or
private tracts in a federally approved unit or communitized
agreement that drains federal minerals. In September 2018, the BLM
published a final rule that revises the 2016 rules. The new rule,
among other things, rescinds the 2016 rule requirements related to
waste-minimization plans, gas-capture percentages, well drilling,
well completion and related operations, pneumatic controllers,
pneumatic diaphragm pumps, storage vessels and leak detection and
repair. The new rule also revised provisions related to venting and
flaring. Environmental groups and the States of California and New
Mexico have filed challenges to the 2018 rule in the United States
District Court for the Northern District of
California.
In 2016, the EPA increased the state of
Colorado’s non-attainment ozone classification for the Denver
Metro North Front Range Ozone Eight-Hour Non-Attainment
(“
Denver Metro/North
Front Range NAA
”) area from “marginal” to
“moderate” under the 2008 national ambient air quality
standard (“
NAAQS
”).
This
increase in non-attainment status to "serious" triggered
significant additional obligations for the state under the CAA and
resulted in Colorado adopting new and more stringent air quality
control requirements in December 2020 that are applicable to our
operations. Based on current air quality monitoring data, it is
expected that the Denver Metro/North Front Range NAA will be
further "bumped-up" to "severe" status in 2021 or 2022. This will
trigger additional obligations for the state under the CAA and will
result in new and more stringent air quality permitting and control
requirements, which may in turn result in significant costs and
delays in obtaining necessary permits applicable to our
operations
.
SB 19-181 also requires, among other things, that
the Air Quality Control Commission (“
AQCC
”) adopt
additional rules to minimize emissions of methane and other
hydrocarbons and nitrogen oxides from the entire oil and gas fuel
cycle. The AQCC anticipates holding several rulemakings over the
next several years to implement the requirements of SB 19-181,
including a rulemaking to require continuous emission monitoring
equipment at oil and gas facilities. In December 2019, the AQCC
held the first of several rulemakings that are anticipated as a
result of SB 19-181. As part of that rulemaking, the AQCC adopted
significant additional and new emission control requirements
applicable to oil and gas operations, including, for example,
hydrocarbon liquids unloading control requirements and increased
LDAR frequencies for facilities in certain proximity to occupied
areas.
State-level rules applicable to our operations
include regulations imposed by the Colorado Department of Public
Health and Environment’s (“
CDPHE
”) Air
Quality Control Commission, including stringent requirements
relating to monitoring, recordkeeping and reporting matters. In
October 2019, the CDPHE published a human health risk assessment
for oil and gas operations in Colorado, which used oil and gas
emission data to model possible human exposure and found a
possibility of negative health impacts at distances up to 2,000
feet away under worst case conditions. In response, the COGCC
announced that it will more rigorously scrutinize permit
applications for wells within 2,000 feet of a building unit, work
with CDPHE to obtain better site-specific data on oil and gas
emissions, and consider the resulting data for possible future
rulemaking.
Regulation of GHG Emissions
The EPA has published findings that emissions of
carbon dioxide, methane and other greenhouse gases
(“
GHGs
”) present
an endangerment to public health and the environment because such
emissions are, according to the EPA, contributing to warming of the
earth’s atmosphere and other climatic changes. These findings
provide the basis for the EPA to adopt and implement regulations
that would restrict emissions of GHGs under existing provisions of
the CAA. In June 2010, the EPA began regulating GHG emissions from
stationary sources.
In
the past, Congress has considered proposed legislation to reduce
emissions of GHGs. To date, Congress has not adopted any such
significant legislation, but could do so in the future. In
addition, many states and regions have taken legal measures to
reduce emissions of GHGs, primarily through the planned development
of GHG emission inventories and/or regional GHG cap and trade
programs. In February 2014, November 2017 and December 2019,
Colorado adopted rules regulating methane emissions from the oil
and gas sector.
The Obama administration reached an agreement
during the December 2015 United Nations climate change conference
in Paris pursuant to which the U.S. initially pledged to make a 26
percent to 28 percent reduction in its GHG emissions by 2025,
against a 2005 baseline, and committed to periodically update this
pledge every five years starting in 2020 (the
“
Paris
Agreement
”). In June
2017, President Trump announced that the U.S. would initiate the
formal process to withdraw from the Paris Agreement. In November
2019, the U.S. formally notified the United Nations of its
intentions to withdraw from the Paris Agreement. The notification
begins a one-year process to complete the withdrawal. Effective
February 19, 2021, President Joe Biden reentered the U.S. in the
Paris Agreement.
27
Regulation
of methane and other GHG emissions associated with oil and natural
gas production could impose significant requirements and costs on
our operations.
Regulation of Flowlines
In
February 2018, the COGCC comprehensively amended its regulations
for oil, gas and water flowlines in Colorado to expand requirements
addressing flowline registration and safety, integrity management,
leak detection and other matters. In November 2019, the COGCC
further amended its flowline regulations pursuant to SB 19-181 to
impose additional requirements regarding flowline mapping,
operational status, certification and abandonment, among other
things. The COGCC has also adopted or amended numerous other rules
in recent years, including rules relating to safety, flood
protection and spill reporting.
Hydraulic Fracturing Activities
Hydraulic fracturing is an important and common
practice that is used to stimulate production of natural gas and/or
oil from dense subsurface rock formations. We regularly use
hydraulic fracturing as part of our operations. Hydraulic
fracturing involves the injection of water, sand or alternative
proppant and chemicals under pressure into targeted geological
formations to fracture the surrounding rock and stimulate
production. Hydraulic fracturing is typically regulated by
state oil and natural gas commissions. However, several federal
agencies have asserted regulatory authority over certain aspects of
the process.
For example, in
December 2016, the EPA released its final report on 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. Additionally, the EPA published in June 2016
an effluent limitations guideline final rule pursuant to its
authority under the SDWA prohibiting the discharge of wastewater
from onshore unconventional oil and natural gas extraction
facilities to publicly owned wastewater treatment plants; asserted
regulatory authority in 2014 under the SDWA over hydraulic
fracturing activities involving the use of diesel and issued
guidance covering such activities; and issued in 2014 a
prepublication of its Advance Notice of Proposed Rulemaking
regarding Toxic Substances Control Act reporting of the chemical
substances and mixtures used in hydraulic fracturing. Also, the BLM
published a final rule in March 2015 establishing new or more
stringent standards for performing hydraulic fracturing on federal
and American Indian lands including well casing and wastewater
storage requirements and an obligation for exploration and
production operators to disclose what chemicals they are using in
fracturing activities. However, following years of litigation, the
BLM rescinded the rule in December 2017. Additionally, from time to
time, legislation has been introduced, but not enacted, in Congress
to provide for federal regulation of hydraulic fracturing and to
require disclosure of the chemicals used in the fracturing process.
In the event that a new, federal level of legal restrictions
relating to the hydraulic fracturing process is adopted in areas
where we operate, we may incur additional costs to comply with such
federal requirements that may be significant in nature, and also
could become subject to additional permitting requirements and
experience added delays or curtailment in the pursuit of
exploration, development, or production
activities.
At
the state level, Colorado, where we conduct significant operations,
is among the states that has adopted, and other states are
considering adopting, regulations that could impose new or more
stringent permitting, disclosure or well-construction requirements
on hydraulic fracturing operations. Moreover, states could elect to
prohibit high volume hydraulic fracturing altogether, following the
approach taken by the State of New York in 2015. Also, certain
interest groups in Colorado opposed to oil and natural gas
development generally, and hydraulic fracturing in particular, have
from time-to-time advanced various options for ballot initiatives
that, if approved, would allow revisions to the state constitution
in a manner that would make such exploration and production
activities in the state more difficult in the future. However,
during the November 2016 voting process, one proposed amendment
placed on the Colorado state ballot making it relatively more
difficult to place an initiative on the state ballot was passed by
the voters. As a result, there are more stringent procedures now in
place for placing an initiative on a state ballot. In addition to
state laws, local land use restrictions may restrict drilling or
the hydraulic fracturing process and cities may adopt local
ordinances allowing hydraulic fracturing activities within their
jurisdictions but regulating the time, place and manner of those
activities.
For example, on November 6, 2018, registered
voters in the State of Colorado cast their ballots and rejected
Proposition 112 (“
Prop.
112
”), with 55% of
ballots cast against the measure. Prop. 112 would have created a
rigid 2,500-foot setback from oil and gas facilities to the nearest
occupied structure and other “vulnerable areas,” which
included parks, ball fields, open space, streams, lakes and
intermittent streams. It would have dramatically increased the
amount of surface area off-limits to new energy development by 26
times and put 94% of private land in the top five oil and
gas producing counties in the State of Colorado off-limits to new
development.
See further discussion in “
Part I
” –
“
Item 1A. Risk
Factors
.”
28
Passed
in Colorado in 2019, SB 19-181 gives local governmental authorities
increased authority to regulate oil and gas development. The
authors of the legislation were clear that SB 19-181 was not
intended to allow an outright ban on oil and gas development.
However, anti-industry activists in Longmont, Colorado, have argued
in court that SB 19-181 permits a local governmental authority to
impose such a ban. We primarily operate in the rural areas of the
Wattenberg Field in Weld and Morgan Counties, jurisdictions in
which there has historically been significant support for the oil
and gas industry.
In addition, on September 28, 2020, the COGCC voted in favor of a
preliminary approval establishing a new 2,000-foot setback rule
from buildings for drilling and fracturing operations statewide,
increasing the previous 500-foot setback rule, which new rule
became effective January 1, 2021, and could likewise make it more
difficult for us to undertake oil and gas development activities in
Colorado.
If
new or more stringent federal, state or local legal restrictions
relating to the hydraulic fracturing process are adopted in areas
where we operate, including, for example, on federal and American
Indian lands, 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.
In
the event that local or state restrictions or prohibitions are
adopted in areas where we conduct operations, that impose more
stringent limitations on the production and development of oil and
natural gas, including, among other things, the development of
increased setback distances, we and similarly situated oil and
natural exploration and production operators in the state may incur
significant costs to comply with such requirements or may
experience delays or curtailment in the pursuit of exploration,
development, or production activities, and possibly be limited or
precluded in the drilling of wells or in the amounts that we and
similarly situated operates are ultimately able to produce from our
reserves. Any such increased costs, delays, cessations,
restrictions or prohibitions could have a material adverse effect
on our business, prospects, results of operations, financial
condition, and liquidity. If new or more stringent federal, state
or local legal restrictions relating to the hydraulic fracturing
process are adopted in areas where we operate, including, for
example, on federal and American Indian lands, we could incur
potentially significant added cost 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.
Moreover,
because most of our operations are conducted in two particular
areas, the Permian Basin in New Mexico and the D-J Basin in
Colorado, legal restrictions imposed in that area will have a
significantly greater adverse effect than if we had our operations
spread out amongst several diverse geographic areas. Consequently,
in the event that local or state restrictions or prohibitions are
adopted in the Permian Basin in New Mexico and/or the D-J Basin in
Colorado that impose more stringent limitations on the production
and development of oil and natural gas, we may incur significant
costs to comply with such requirements or may experience delays or
curtailment in the pursuit of exploration, development, or
production activities, and possibly be limited or precluded in the
drilling of wells or in the amounts that we are ultimately able to
produce from our reserves. Any such increased costs, delays,
cessations, restrictions or prohibitions could have a material
adverse effect on our business, prospects, results of operations,
financial condition, and liquidity.
Activities on Federal Lands
Oil and natural gas exploration, development and
production activities on federal lands, including American Indian
lands and lands administered by the BLM, are subject to the
National Environmental Policy Act (“
NEPA
”).
NEPA requires federal agencies, including the BLM, to evaluate
major agency actions having the potential to significantly impact
the environment. In the course of such evaluations, an agency will
prepare an Environmental Assessment that assesses the potential
direct, indirect and cumulative impacts of a proposed project and,
if necessary, will prepare a more detailed Environmental Impact
Statement that may be made available for public review and comment.
While we currently have no exploration, development and production
activities on federal lands, our future exploration, development
and production activities may include leasing of federal mineral
interests, which will require the acquisition of governmental
permits or authorizations that are subject to the requirements of
NEPA. This process has the potential to delay or limit, or increase
the cost of, the development of oil and natural gas projects.
Authorizations under NEPA are also subject to protest, appeal or
litigation, any or all of which may delay or halt projects.
Moreover, depending on the mitigation strategies recommended in
Environmental Assessments or Environmental Impact Statements, we
could incur added costs, which may be
substantial.
29
On
January 20, 2021, the Acting U.S. Interior Secretary, instituted a
60-day moratorium on new oil and gas leases and permits on federal
onshore and offshore lands. A total of approximately 26% of the
Company’s acreage in New Mexico and 1% of the Company’s
acreage in Colorado are located on federal lands. It is currently
unclear whether the moratorium will be extended when it expires on
March 21, 2021, or whether such moratorium is the start of a change
in federal policies regarding the grant of oil and gas permits on
federal lands.
Endangered Species and Migratory Birds Considerations
The federal Endangered Species Act
(“
ESA
”), and comparable state laws were
established to protect endangered and threatened species. Pursuant
to the ESA, if a species is listed as threatened or endangered,
restrictions may be imposed on activities adversely affecting that
species or that species’ habitat. Similar protections are
offered to migrating birds under the Migratory Bird Treaty Act. We
may conduct operations on oil and natural gas leases in areas where
certain species that are listed as threatened or endangered are
known to exist and where other species, such as the sage grouse,
that potentially could be listed as threatened or endangered under
the ESA may exist. Moreover, as a result of one or more agreements
entered into by the U.S. Fish and Wildlife Service, the agency is
required to make a determination on listing of numerous species as
endangered or threatened under the ESA pursuant to specific
timelines. 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,
time delays or limitations on our exploration and production
activities that could have an adverse impact on our ability to
develop and produce 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.
OSHA
We are subject to the requirements of the
Occupational Safety and Health Administration
(“
OSHA
”) and
comparable state statutes whose purpose is to protect the health
and safety of workers. In addition, the OSHA hazard communication
standard, the Emergency Planning and Community Right-to-Know Act
and comparable state statutes and any implementing regulations
require that we organize and/or disclose information about
hazardous materials used or produced in our operations and that
this information be provided to employees, state and local
governmental authorities and citizens.
Private Lawsuits
Lawsuits
have been filed against other operators in several states,
including Colorado, alleging contamination of drinking water as a
result of hydraulic fracturing activities.
Related Permits and Authorizations
Many
environmental laws require us to obtain permits or other
authorizations from state and/or federal agencies before initiating
certain drilling, construction, production, operation, or other oil
and natural gas activities, and to maintain these permits and
compliance with their requirements for on-going operations. These
permits are generally subject to protest, appeal, or litigation,
which can in certain cases delay or halt projects and cease
production or operation of wells, pipelines, and other
operations.
We are
not able to predict the timing, scope and effect of any currently
proposed or future laws or regulations regarding hydraulic
fracturing, but the direct and indirect costs of such laws and
regulations (if enacted) could materially and adversely affect
our business, financial conditions and results of operations. See
further discussion in “
Part I
” –
“
Item 1A. Risk
Factors
.”
Insurance
Our oil
and gas properties are subject to hazards inherent in the oil and
gas industry, such as accidents, blowouts, explosions, implosions,
fires and oil spills. These conditions can cause:
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damage
to or destruction of property, equipment and the
environment;
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personal
injury or loss of life; and
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suspension
of operations.
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30
We
maintain insurance coverage that we believe to be customary in the
industry against these types of hazards. However, we may not be
able to maintain adequate insurance in the future at rates we
consider reasonable. In addition, our insurance is subject to
coverage limits and some policies exclude coverage for damages
resulting from environmental contamination. The occurrence of a
significant event or adverse claim in excess of the insurance
coverage that we maintain or that is not covered by insurance could
have a material adverse effect on our financial condition and
results of operations.
Employees
At
December 31, 2020, we employed 15 people and also utilize the
services of independent contractors to perform various field and
other services. Our future success will depend partially on our
ability to attract, retain and motivate qualified personnel. We are
not a party to any collective bargaining agreements and have not
experienced any strikes or work stoppages. We consider our
relations with our employees to be satisfactory.
The
health and safety of our employees is our highest priority, and
this is consistent with our operating philosophy. Our safety focus
is also evident in our response to the COVID-19 pandemic around the
globe:
●
Adding work from
home flexibility;
●
Adjusting
attendance policies to encourage those who are sick to stay
home;
●
Increasing cleaning
protocols across all locations;
●
Initiating regular
communication regarding impacts of the COVID-19 pandemic, including
health and safety protocols and procedures;
●
Establishing new
physical distancing procedures for employees who need to be
onsite;
●
Providing
additional personal protective equipment and cleaning
supplies;
●
Implementing
protocols to address actual and suspected COVID-19 cases and
potential exposure;
●
Limiting all
non-essential travel for all employees; and
●
Encouraging masks
to be worn in all locations where allowed by local
law.
The
development, attraction and retention of employees is a critical
success factor for the Company. To support the advancement and
education of our employees, we offer training and development
programs to our employees, including training on compliance,
general business, management, harassment prevention, leadership,
and workplace safety-related topics to further their personal and
professional development. We also require annual anti-harassment
training of all employees and supervisors.
We also
offer our employees competitive pay and benefits. The
Company’s compensation programs are designed to align the
compensation of our employees with the Company’s performance
and to provide the proper incentives to attract, retain and
motivate employees to achieve superior results. The structure of
our compensation programs balances incentive earnings for both
short-term and long-term performance. Specifically:
●
We provide employee
wages that are competitive and consistent with employee positions,
skill levels, experience, knowledge and geographic
location.
●
Annual increases
and incentive compensation are based on merit, which is
communicated to employees at the time of hiring and documented
through our annual review procedures and upon internal transfer
and/or promotion.
●
All employees are
eligible for health insurance, paid and unpaid leaves, a retirement
plan and life and disability/accident coverage. We also offer a
variety of voluntary benefits that allow employees to select the
options that meet their needs, including flexible spending
accounts, flexible time-off, telemedicine, wellness resources,
legal resources and identity protection plans, family leave, and
adoption assistance, among others.
31
ITEM 1A.
R
ISK FACTORS.
An investment in our common stock involves a high degree of risk.
You should carefully consider the risks described below as well as
the other information in this filing before deciding to invest in
our company. Any of the risk factors described below could
significantly and adversely affect our business, prospects,
financial condition and results of operations. Additional risks and
uncertainties not currently known or that are currently considered
to be immaterial may also materially and adversely affect our
business, prospects, financial condition and results of operations.
As a result, the trading price or value of our common stock could
be materially adversely affected and you may lose all or part of
your investment.
Risks Related to the Oil, NGL and Natural Gas Industry and Our
Business
Declines in oil and, to a lesser extent, NGL and natural gas
prices, have in the past, and will continue in the future, to
adversely affect our business, financial condition or results of
operations and our ability to meet our capital expenditure
obligations or targets and financial commitments.
The price we receive for our oil and, to a lesser
extent, natural gas and NGLs, heavily influences our revenue,
profitability, cash flows, liquidity, access to capital, present
value and quality of our reserves, the nature and scale of our
operations and future rate of growth. Oil, NGL and natural gas are
commodities and, therefore, their prices are subject to wide
fluctuations in response to relatively minor changes in supply and
demand. In recent years, the markets for oil and natural gas have
been volatile. These markets will likely continue to be volatile in
the future. Further, oil prices and natural gas prices do not
necessarily fluctuate in direct relation to each other.
Because approximately 84% of our estimated proved reserves as of
December 31, 2020, were oil, our financial results are more
sensitive to movements in oil prices
.
The price of crude oil has experienced significant volatility over
the last five years, with the price per barrel of West Texas
Intermediate (“
WTI
”) crude rising from a low of $27 in
February 2016 to a high of $76 in October 2018, then, in 2020,
dropping below $20 per barrel due in part to reduced global demand
stemming from the recent global COVID-19 outbreak, and most
recently climbing back around $55 to $65 a barrel. A prolonged
period of low market prices for oil and natural gas, or further
declines in the market prices for oil and natural gas, will likely
result in capital expenditures being further curtailed and will
adversely affect our business, financial condition and liquidity
and our ability to meet obligations, targets or financial
commitments and could ultimately lead to restructuring or filing
for bankruptcy, which would have a material adverse effect on our
stock price and indebtedness. Additionally, lower oil and natural
gas prices have, and may in the future, cause, a decline in our
stock price. During the year ended December 31, 2019, the
daily NYMEX WTI oil spot price ranged from a high of $66.24 per Bbl
to a low of $46.31 per Bbl and the NYMEX natural gas Henry Hub spot
price ranged from a high of $4.25 per MMBtu to a low of $1.75 per
MMBtu.
During
the year ended December 31, 2020, the daily NYMEX WTI oil spot
price ranged from a high of $63.27 per Bbl to a low of ($36.98) per
Bbl and the NYMEX natural gas Henry Hub spot price ranged from a
high of $3.14 per MMBtu to a low of $1.33 per
MMBtu.
Our business and
operations have been adversely affected by, and are expected to
continue to be adversely affected by, the COVID-19 outbreak, and
may be adversely affected by other similar
outbreaks
.
As
a result of the ongoing COVID-19 outbreak or other adverse
public health developments, including voluntary and mandatory
quarantines, travel restrictions and other restrictions relating
thereto, our operations, and those of our subcontractors, customers
and suppliers, have and are anticipated to continue to experience
delays or disruptions and temporary suspensions of operations. In
addition, our financial condition and results of operations have
been and are likely to continue to be adversely affected by
the COVID-19 outbreak.
The
timeline and potential magnitude of the COVID-19 outbreak are
currently unknown. The continuation or amplification of this
virus could continue to more broadly affect the United States and
global economy, including our business and operations, and the
demand for oil and gas. For example, the outbreak of
coronavirus has resulted in a widespread health crisis that will
adversely affect the economies and financial markets of many
countries, resulting in an economic downturn that will affect our
operating results. Other contagious diseases in the human
population could have similar adverse effects. In addition, the
effects of COVID-19 and concerns regarding its global spread have
previously negatively impacted the domestic and international
demand for crude oil and natural gas, which has contributed to
price volatility, impacted the price we receive for oil and natural
gas and materially and has materially and adversely affected the
demand for and marketability of our production, which production we
temporarily shut-in from mid-April 2020 through early June 2020,
and is anticipated to continue to adversely affect the same for the
foreseeable future. As the potential impact from COVID-19 is
difficult to predict, the extent to which it will negatively affect
out operating results, or the duration of any potential business
disruption is uncertain. The magnitude and duration of any impact
will depend on future developments and new information that may
emerge regarding the severity and duration of COVID-19 and the
actions taken by authorities to contain it or treat its impact,
including the efficiency of recent vaccines, the ability of the
government to roll such vaccines out to the general public, and the
willingness of individuals to obtain such vaccines, all of which
are beyond our control. These potential impacts, while uncertain,
have already negatively affected our fiscal 2020 results of
operations, and are anticipated to have a negative impact on
multiple future quarters’ results as well.
32
We have a limited operating history and expect to continue to incur
losses for an indeterminable period of time.
We have a limited operating history and are
engaged in the initial stages of exploration, development and
exploitation of our leasehold acreage and will continue to be so
until commencement of substantial production from our oil and
natural gas properties, which will depend upon successful drilling
results, additional and timely capital funding, and access to
suitable infrastructure. Companies in their initial stages of
development face substantial business risks and may suffer
significant losses. We have generated substantial net losses and
negative cash flows from operating activities in the past and
expect to continue to incur substantial net losses as we continue
our drilling program. In considering an investment in our common
stock, you should consider that there is only limited historical
and financial operating information available upon which to base
your evaluation of our performance.
We have incurred net losses
of $128,286,000 from the date of inception (February 9,
2011) through December 31, 2020. Additionally, we are
dependent on obtaining additional debt and/or equity financing to
roll-out and scale our planned principal business operations.
Management’s plans in regard to these matters consist
principally of seeking additional debt and/or equity financing
combined with expected cash flows from current oil and gas assets
held and additional oil and gas assets that we may acquire. Our
efforts may not be successful, and funds may not be available on
favorable terms, if at all.
We
face challenges and uncertainties in financial planning as a result
of the unavailability of historical data and uncertainties
regarding the nature, scope and results of our future activities.
New companies must develop successful business relationships,
establish operating procedures, hire staff, install management
information and other systems, establish facilities and obtain
licenses, as well as take other measures necessary to conduct their
intended business activities. We may not be successful in
implementing our business strategies or in completing the
development of the infrastructure necessary to conduct our business
as planned. In the event that one or more of our drilling programs
is not completed or is delayed or terminated, our operating results
will be adversely affected and our operations will differ
materially from the activities described in this Annual Report and
our subsequent periodic reports. As a result of industry factors or
factors relating specifically to us, we may have to change our
methods of conducting business, which may cause a material adverse
effect on our results of operations and financial condition. The
uncertainty and risks described in this Annual Report may impede
our ability to economically find, develop, exploit, and acquire oil
and natural gas reserves. As a result, we may not be able to
achieve or sustain profitability or positive cash flows provided by
our operating activities in the future.
We will need additional capital to complete future acquisitions,
conduct our operations and fund our business beyond 2021, and our
ability to obtain the necessary funding is uncertain.
We
will need to raise additional funding to complete future potential
acquisitions and will be required to raise additional funds through
public or private debt or equity financing or other various means
to fund our operations and complete exploration and drilling
operations beyond 2021 and acquire assets. In such a case, adequate
funds may not be available when needed or may not be available on
favorable terms. If we need to raise additional funds in the future
by issuing equity securities, dilution to existing stockholders
will result, and such securities may have rights, preferences and
privileges senior to those of our common stock. If funding is
insufficient at any time in the future and we are unable to
generate sufficient revenue from new business arrangements, to
complete planned acquisitions or operations, our results of
operations and the value of our securities could be adversely
affected.
Additionally,
due to the nature of oil and gas interests, i.e., that rates of
production generally decline over time as oil and gas reserves are
depleted, if we are unable to drill additional wells and develop
our reserves, either because we are unable to raise sufficient
funding for such development activities, or otherwise, or in the
event we are unable to acquire additional operating properties, we
believe that our revenues will continue to decline over time.
Furthermore, in the event we are unable to raise additional
required funding in the future, we will not be able to participate
in the drilling of additional wells, will not be able to complete
other drilling and/or workover activities, and may not be able to
make required payments on our outstanding liabilities.
If
this were to happen, we may be forced to scale back our business
plan, sell or liquidate assets to satisfy outstanding debts, all of
which could result in the value of our outstanding securities
declining in value.
33
We may not be able to generate sufficient cash flow to meet any
future debt service and other obligations due to events beyond our
control.
Our
ability to generate cash flows from operations, to make payments on
or refinance potential future indebtedness and to fund working
capital needs and planned capital expenditures will depend on our
future financial performance and our ability to generate cash in
the future. Our future financial performance will be affected by a
range of economic, financial, competitive, business and other
factors that we cannot control, such as general economic,
legislative, regulatory and financial conditions in our industry,
the economy generally, the price of oil and other risks described
below. A significant reduction in operating cash flows resulting
from changes in economic, legislative or regulatory conditions,
increased competition or other events beyond our control could
increase the need for additional or alternative sources of
liquidity and could have a material adverse effect on our business,
financial condition, results of operations, prospects and our
ability to service future potential debt and other obligations. If
we are unable to service future potential indebtedness or to fund
our other liquidity needs, we may be forced to adopt an alternative
strategy that may include actions such as reducing or delaying
capital expenditures, selling assets, restructuring or refinancing
such indebtedness, seeking additional capital, or any combination
of the foregoing. If we raise debt, it would increase our interest
expense, leverage and our operating and financial costs. We cannot
assure you that any of these alternative strategies could be
affected on satisfactory terms, if at all, or that they would yield
sufficient funds to make required payments on future potential
indebtedness or to fund our other liquidity needs. Reducing or
delaying capital expenditures or selling assets could delay future
cash flows. In addition, the terms of future debt agreements may
restrict us from adopting any of these alternatives. We cannot
assure you that our business will generate sufficient cash flows
from operations or that future borrowings will be available in an
amount sufficient to enable us to pay such future potential
indebtedness or to fund our other liquidity needs.
If
for any reason we are unable to meet our future potential debt
service and repayment obligations, we may be in default under the
terms of the agreements governing such indebtedness, which could
allow our creditors at that time to declare such outstanding
indebtedness to be due and payable. Under these circumstances, our
lenders could compel us to apply all of our available cash to repay
our borrowings. In addition, the lenders under our credit
facilities or other secured indebtedness could seek to foreclose on
any of our assets that are their collateral. If the amounts
outstanding under such indebtedness were to be accelerated, or were
the subject of foreclosure actions, our assets may not be
sufficient to repay in full the money owed to the lenders or to our
other debt holders.
All of our crude oil, natural gas and NGLs production is located in
the Permian Basin and the D-J Basin, making us vulnerable to risks
associated with operating in only two geographic areas. In
addition, we have a large amount of proved reserves attributable to
a small number of producing formations.
Our
operations are focused solely in the Permian Basin located in
Chaves and Roosevelt Counties, New Mexico, and the D-J Basin of
Weld and Morgan Counties, Colorado, which means our current
producing properties and new drilling opportunities are
geographically concentrated in those two areas. Because our
operations are not as diversified geographically as many of our
competitors, the success of our operations and our profitability
may be disproportionately exposed to the effect of any regional
events, including:
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fluctuations
in prices of crude oil, natural gas and NGLs produced from the
wells in these areas;
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natural
disasters such as the flooding that occurred in the D-J Basin area
in September 2013;
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the
effects of local quarantines;
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restrictive
governmental regulations; and
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curtailment
of production or interruption in the availability of gathering,
processing or transportation infrastructure and services, and any
resulting delays or interruptions of production from existing or
planned new wells.
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For
example, bottlenecks in processing and transportation that have
occurred in some recent periods in the Permian Basin and D-J Basin
may negatively affect our results of operations, and these adverse
effects may be disproportionately severe to us compared to our more
geographically diverse competitors. Similarly, the concentration of
our assets within a small number of producing formations exposes us
to risks, such as changes in field-wide rules that could adversely
affect development activities or production relating to those
formations. Such an event could have a material adverse effect on
our results of operations and financial condition. In addition, in
areas where exploration and production activities are increasing,
as has been the case in recent years in the Permian Basin and D-J
Basin, the demand for, and cost of, drilling rigs, equipment,
supplies, personnel and oilfield services increase. Shortages or
the high cost of drilling rigs, equipment, supplies, personnel or
oilfield services could delay or adversely affect our development
and exploration operations or cause us to incur significant
expenditures that are not provided for in our capital forecast,
which could have a material adverse effect on our business,
financial condition or results of operations. Finally, our
operations in New Mexico or Colorado may be negatively affected by
quarantines put in place in New Mexico or Colorado in an effort to
slow the spread of COVID-19 or other viruses or diseases, with the
quarantines effected in 2020 to slow the spread of COVID-19
negatively affecting our operations in both New Mexico and Colorado
in 2020.
34
Drilling for and producing oil and natural gas are highly
speculative and involve a high degree of risk, with many
uncertainties that could adversely affect our business. We have not
recorded significant proved reserves, and areas that we decide to
drill may not yield oil or natural gas in commercial quantities or
at all.
Exploring
for and developing hydrocarbon reserves involves a high degree of
operational and financial risk, which precludes us from
definitively predicting the costs involved and time required to
reach certain objectives. Our potential drilling locations are in
various stages of evaluation, ranging from locations that are ready
to drill, to locations that will require substantial additional
interpretation before they can be drilled. The budgeted costs of
planning, drilling, completing and operating wells are often
exceeded, and such costs can increase significantly due to various
complications that may arise during the drilling and operating
processes. Before a well is spudded, we may incur significant
geological and geophysical (seismic) costs, which are incurred
whether a well eventually produces commercial quantities of
hydrocarbons or is drilled at all. Exploration wells bear a much
greater risk of loss than development wells. The analogies we draw
from available data from other wells, more fully explored locations
or producing fields may not be applicable to our drilling
locations. If our actual drilling and development costs are
significantly more than our estimated costs, we may not be able to
continue our operations as proposed and could be forced to modify
our drilling plans accordingly.
If
we decide to drill a certain location, there is a risk that no
commercially productive oil or natural gas reservoirs will be found
or produced. We may drill or participate in new wells that are not
productive. We may drill wells that are productive, but that do not
produce sufficient net revenues to return a profit after drilling,
operating and other costs. There is no way to predict in advance of
drilling and testing whether any particular location will yield oil
or natural gas in sufficient quantities to recover exploration,
drilling or completion costs or to be economically viable. Even if
sufficient amounts of oil or natural gas exist, we may damage the
potentially productive hydrocarbon-bearing formation or experience
mechanical difficulties while drilling or completing the well,
resulting in a reduction in production and reserves from the well
or abandonment of the well. Whether a well is ultimately productive
and profitable depends on a number of additional factors, including
the following:
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general
economic and industry conditions, including the prices received for
oil and natural gas;
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shortages
of, or delays in, obtaining equipment, including hydraulic
fracturing equipment, and qualified personnel;
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potential
significant water production which could make a producing well
uneconomic, particularly in the Permian Basin Asset, where abundant
water production is a known risk;
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potential
drainage by operators on adjacent properties;
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loss
of, or damage to, oilfield development and service
tools;
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problems
with title to the underlying properties;
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increases
in severance taxes;
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adverse
weather conditions that delay drilling activities or cause
producing wells to be shut down;
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domestic
and foreign governmental regulations; and
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proximity
to and capacity of transportation facilities.
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If
we do not drill productive and profitable wells in the future, our
business, financial condition and results of operations could be
materially and adversely affected.
35
Our success is dependent on the prices of oil, NGLs and natural
gas. Low oil or natural gas prices and the substantial volatility
in these prices have adversely affected, and are expected to
continue to adversely affect, our business, financial condition and
results of operations and our ability to meet our capital
expenditure requirements and financial obligations.
The
prices we receive for our oil, NGLs and natural gas heavily
influence our revenue, profitability, cash flow available for
capital expenditures, access to capital and future rate of growth.
Oil, NGLs and natural gas are commodities and, therefore,
their prices are subject to wide fluctuations in response to
relatively minor changes in supply and demand. Historically, the
commodities market has been volatile. For example, the price of
crude oil has experienced significant volatility over the last five
years, with the price per barrel of WTI crude rising from a low of
$27 in February 2016 to a high of $76 in October 2018, then
dropping below $20 per barrel in April 2020, due in part to reduced
global demand stemming from the recent global COVID-19 outbreak,
before recovering to between $55 and $65 per barrel more recently.
Prices for natural gas and NGLs experienced declines of similar
magnitude. An extended period of continued lower oil prices, or
additional price declines, will have further adverse effects on us.
The prices we receive for our production, and the levels of our
production, will continue to depend on numerous factors, including
the following:
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the
domestic and foreign supply of oil, NGLs and natural
gas;
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the
domestic and foreign demand for oil, NGLs and natural
gas;
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the
prices and availability of competitors’ supplies of oil,
NGLs and natural gas;
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the
actions of the Organization of Petroleum Exporting Countries, or
OPEC, and state-controlled oil companies relating to oil price and
production controls;
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the
price and quantity of foreign imports of oil, NGLs and natural
gas;
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the
impact of U.S. dollar exchange rates on oil, NGLs and natural
gas prices;
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domestic
and foreign governmental regulations and taxes;
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speculative
trading of oil, NGLs and natural gas futures
contracts;
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localized
supply and demand fundamentals, including the availability,
proximity and capacity of gathering and transportation systems for
natural gas;
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the
availability of refining capacity;
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the
prices and availability of alternative fuel sources;
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the
threat, or perceived threat, or results, of viral pandemics, for
example, as experienced with the COVID-19 pandemic in 2020 and
2021;
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weather
conditions and natural disasters;
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political
conditions in or affecting oil, NGLs and natural gas producing
regions, including the Middle East and South America;
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the
continued threat of terrorism and the impact of military action and
civil unrest;
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public
pressure on, and legislative and regulatory interest within,
federal, state and local governments to stop, significantly limit
or regulate hydraulic fracturing activities;
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the
level of global oil, NGL and natural gas inventories and
exploration and production activity;
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authorization
of exports from the Unites States of liquefied natural
gas;
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the
impact of energy conservation efforts;
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technological
advances affecting energy consumption; and
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overall
worldwide economic conditions.
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36
Declines
in oil, NGL or natural gas prices have not, and will not, only
reduce our revenue, but have and will reduce the amount of oil,
NGL and natural gas that we can produce economically. Should
natural gas, NGL or oil prices decline from current levels and
remain there for an extended period of time, we may choose to
shut-in our operated wells, (similar to our shut-in of our operated
wells in 2020), delay some or all of our exploration and
development plans for our prospects, or to cease exploration or
development activities on certain prospects due to the anticipated
unfavorable economics from such activities, and, as a result, we
may have to make substantial downward adjustments to our estimated
proved reserves, each of which would have a material adverse effect
on our business, financial condition and results of
operations.
Future conditions might require us to incur impairments or make
write-downs in our assets, which would adversely affect our balance
sheet and results of operations.
We
review our long-lived tangible and intangible assets for impairment
whenever events or changes in circumstances indicate that the
carrying value of an asset may not be recoverable. For the year
ended December 31, 2020, due to falling oil and gas prices, we
incurred a $19.3 million impairment of our oil and gas properties
located in our D-J Basin Asset. If conditions in any of the
businesses in which we compete were to deteriorate (or deteriorate
further), we could determine that certain of our assets were
further impaired and we would then be required to write-off all or
a portion of our costs for such assets. Any such significant
write-offs would adversely affect our balance sheet and results of
operations, similar to the effect of the December 31, 2020
impairment.
Declining general economic, business or industry conditions have,
and will continue to have, a material adverse effect on our results
of operations, liquidity and financial condition, and are expected
to continue having a material adverse effect for the foreseeable
future.
Concerns
over global economic conditions, the duration and effects of
COVID-19 and the results thereof, energy costs, geopolitical
issues, inflation, and the availability and cost of credit have
contributed to increased economic uncertainty and diminished
expectations for the global economy. These factors, combined with
volatile prices of oil and natural gas, declining business and
consumer confidence and increased unemployment, have precipitated
an economic slowdown and a recession, which could expand to a
global depression. Concerns about global economic growth have had a
significant adverse impact on global financial markets and
commodity prices and are expected to continuing having a material
adverse effect for the foreseeable future. If the economic climate
in the United States or abroad continues to deteriorate, demand for
petroleum products could diminish, which could further impact the
price at which we can sell our oil, natural gas and natural gas
liquids, affect the ability of our vendors, suppliers and customers
to continue operations, and ultimately adversely impact our results
of operations, liquidity and financial condition to a greater
extent that it has already.
Our exploration, development and exploitation projects require
substantial capital expenditures that may exceed cash on hand, cash
flows from operations and potential borrowings, and we may be
unable to obtain needed capital on satisfactory terms, which could
adversely affect our future growth.
Our
exploration and development activities are capital intensive. We
make and expect to continue to make substantial capital
expenditures in our business for the development, exploitation,
production and acquisition of oil and natural gas reserves. Our
cash on hand, our operating cash flows and future potential
borrowings may not be adequate to fund our future acquisitions or
future capital expenditure requirements. The rate of our future
growth may be dependent, at least in part, on our ability to access
capital at rates and on terms we determine to be
acceptable.
Our
cash flows from operations and access to capital are subject to a
number of variables, including:
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our
estimated proved oil and natural gas reserves;
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the
amount of oil and natural gas we produce from existing
wells;
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the
prices at which we sell our production;
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the
costs of developing and producing our oil and natural gas
reserves;
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our
ability to acquire, locate and produce new reserves;
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the
general state of the economy;
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the
ability and willingness of banks to lend to us; and
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our
ability to access the equity and debt capital markets.
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37
In
addition, future events, such as terrorist attacks, wars or combat
peace-keeping missions, financial market disruptions, general
economic recessions, oil and natural gas industry recessions, large
company bankruptcies, accounting scandals, pandemic diseases,
overstated reserves estimates by major public oil companies and
disruptions in the financial and capital markets have caused
financial institutions, credit rating agencies and the public to
more closely review the financial statements, capital structures
and earnings of public companies, including energy companies. Such
events have constrained the capital available to the energy
industry in the past, and such events or similar events could
adversely affect our access to funding for our operations in the
future.
If
our revenues decrease as a result of lower oil and natural gas
prices, operating difficulties, declines in reserves or for any
other reason, we may have limited ability to obtain the capital
necessary to sustain our operations at current levels, further
develop and exploit our current properties or invest in additional
exploration opportunities. Alternatively, a significant improvement
in oil and natural gas prices or other factors could result in an
increase in our capital expenditures and we may be required to
alter or increase our capitalization substantially through the
issuance of debt or equity securities, the sale of production
payments, the sale or farm out of interests in our assets, the
borrowing of funds or otherwise to meet any increase in capital
needs. If we are unable to raise additional capital from available
sources at acceptable terms, our business, financial condition and
results of operations could be adversely affected. Further, future
debt financings may require that a portion of our cash flows
provided by operating activities be used for the payment of
principal and interest on our debt, thereby reducing our ability to
use cash flows to fund working capital, capital expenditures and
acquisitions. Debt financing may involve covenants that restrict
our business activities. If we succeed in selling additional equity
securities to raise funds, at such time the ownership percentage of
our existing stockholders would be diluted, and new investors may
demand rights, preferences or privileges senior to those of
existing stockholders. If we choose to farm-out interests in our
prospects, we may lose operating control over such
prospects.
Our oil and natural gas reserves are estimated and may not reflect
the actual volumes of oil and natural gas we will receive, and
significant inaccuracies in these reserve estimates or underlying
assumptions will materially affect the quantities and present value
of our reserves.
The
process of estimating accumulations of oil and natural gas is
complex and is not exact, due to numerous inherent uncertainties.
The process relies on interpretations of available geological,
geophysical, engineering and production data. The extent, quality
and reliability of this technical data can vary. The process also
requires certain economic assumptions related to, among other
things, oil and natural gas prices, drilling and operating
expenses, capital expenditures, taxes and availability of funds.
The accuracy of a reserves estimate is a function of:
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the
quality and quantity of available data;
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the
interpretation of that data;
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the
judgment of the persons preparing the estimate; and
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the
accuracy of the assumptions.
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The
accuracy of any estimates of proved reserves generally increases
with the length of the production history. Due to the limited
production history of our properties, the estimates of future
production associated with these properties may be subject to
greater variance to actual production than would be the case with
properties having a longer production history. As our wells produce
over time and more data is available, the estimated proved reserves
will be re-determined on at least an annual basis and may be
adjusted to reflect new information based upon our actual
production history, results of exploration and development,
prevailing oil and natural gas prices and other
factors.
Actual
future production, oil and natural gas prices, revenues, taxes,
development expenditures, operating expenses and quantities of
recoverable oil and natural gas most likely will vary from our
estimates. It is possible that future production declines in our
wells may be greater than we have estimated. Any significant
variance to our estimates could materially affect the quantities
and present value of our reserves.
38
We have written down, and may in the future be forced to further
write-down, material portions of our assets due to low oil
prices.
The
successful efforts method of accounting is used for oil and gas
exploration and production activities. Under this method, all costs
for development wells, support equipment and facilities, and proved
mineral interests in oil and gas properties are capitalized. We
review the carrying value of our long-lived assets annually or
whenever events or changes in circumstances indicate that the
historical cost-carrying value of an asset may no longer be
appropriate. We assess the recoverability of the carrying value of
the asset by estimating the future net undiscounted cash flows
expected to result from the asset, including eventual disposition.
If the future net undiscounted cash flows are less than the
carrying value of the asset, an impairment loss is recorded equal
to the difference between the asset’s carrying value and
estimated fair value. This impairment does not impact cash flows
from operating activities but does reduce earnings and our
shareholders’ equity.
Additionally,
the recent COVID-19 outbreak has led to an economic downturn
resulting in lower oil prices, which has in turn required us to
shut-in all of our production from mid-April through early June
2020, as it was uneconomical for us to operate our producing wells
during such time, and we could be required to again shut-in some or
all of our production in the future should market conditions
deteriorate. For example, for the year ended December 31, 2020, due
to falling oil and gas prices, we incurred a $19.3 million
impairment of our oil and gas properties located in our D-J Basin
Asset.
A
continued period of low prices may force us to incur further
material write-downs of our oil and natural gas properties, which
could have a material effect on the value of our properties and
cause the value of our securities to decline in value.
Additionally, impairments would occur if we were to experience
sufficient downward adjustments to our estimated proved reserves or
the present value of estimated future net revenues. An impairment
recognized in one period may not be reversed in a subsequent period
even if higher oil and gas prices increase the cost center ceiling
applicable to the subsequent period. We have in the past and could
in the future incur additional impairments of oil and gas
properties which may be material.
We may have accidents, equipment failures or mechanical problems
while drilling or completing wells or in production activities,
which could adversely affect our business.
While
we are drilling and completing wells or involved in production
activities, we may have accidents or experience equipment failures
or mechanical problems in a well that cause us to be unable to
drill and complete the well or to continue to produce the well
according to our plans. We may also damage a potentially
hydrocarbon-bearing formation during drilling and completion
operations. Such incidents may result in a reduction of our
production and reserves from the well or in abandonment of the
well.
Our operations are subject to operational hazards and unforeseen
interruptions for which we may not be adequately
insured.
There
are numerous operational hazards inherent in oil and natural gas
exploration, development, production and gathering,
including:
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unusual
or unexpected geologic formations;
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natural
disasters;
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adverse
weather conditions;
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unanticipated
pressures;
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loss of
drilling fluid circulation;
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blowouts
where oil or natural gas flows uncontrolled at a
wellhead;
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cratering
or collapse of the formation;
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39
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pipe or
cement leaks, failures or casing collapses;
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fires
or explosions;
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releases
of hazardous substances or other waste materials that cause
environmental damage;
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pressures
or irregularities in formations; and
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equipment
failures or accidents.
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In
addition, there is an inherent risk of incurring significant
environmental costs and liabilities in the performance of our
operations, some of which may be material, due to our handling of
petroleum hydrocarbons and wastes, our emissions to air and water,
the underground injection or other disposal of our wastes, the use
of hydraulic fracturing fluids and historical industry operations
and waste disposal practices.
Any
of these or other similar occurrences could result in the
disruption or impairment of our operations, substantial repair
costs, personal injury or loss of human life, significant damage to
property, environmental pollution and substantial revenue losses.
The location of our wells, gathering systems, pipelines and other
facilities near populated areas, including residential areas,
commercial business centers and industrial sites, could
significantly increase the level of damages resulting from these
risks. Insurance against all operational risks is not available to
us. We are not fully insured against all risks, including
development and completion risks that are generally not recoverable
from third parties or insurance. In addition, pollution and
environmental risks generally are not fully insurable. We maintain
$2 million in general liability coverage and $10 million umbrella
coverage that covers our and our subsidiaries’ business and
operations. With respect to our other non-operated assets, we may
elect not to obtain insurance if we believe that the cost of
available insurance is excessive relative to the perceived risks
presented. Losses could, therefore, occur for uninsurable or
uninsured risks or in amounts in excess of existing insurance
coverage. Moreover, insurance may not be available in the future at
commercially reasonable prices or on commercially reasonable terms.
Changes in the insurance markets due to various factors may make it
more difficult for us to obtain certain types of coverage in the
future. As a result, we may not be able to obtain the levels or
types of insurance we would otherwise have obtained prior to these
market changes, and the insurance coverage we do obtain may not
cover certain hazards or all potential losses that are currently
covered and may be subject to large deductibles. Losses and
liabilities from uninsured and underinsured events and delay in the
payment of insurance proceeds could have a material adverse effect
on our business, financial condition and results of
operations.
Our strategy as an onshore resource player may result in operations
concentrated in certain geographic areas and may increase our
exposure to many of the risks described in this Annual
Report.
Our
current operations are concentrated in the states of New
Mexico and Colorado. This concentration may increase the potential
impact of many of the risks described in this Annual Report. For
example, we may have greater exposure to regulatory actions
impacting New Mexico and/or Colorado, adverse weather and natural
disasters in New Mexico and/or Colorado, competition for equipment,
services and materials available in, and access to infrastructure
and markets in, these states.
Unless we replace our oil and natural gas reserves, our reserves
and production will decline, which will adversely affect our
business, financial condition and results of
operations.
The
rate of production from our oil and natural gas properties will
decline as our reserves are depleted. Our future oil and natural
gas reserves and production and, therefore, our income and cash
flow, are highly dependent on our success in (a) efficiently
developing and exploiting our current reserves on properties owned
by us or by other persons or entities and (b) economically
finding or acquiring additional oil and natural gas producing
properties. In the future, we may have difficulty acquiring new
properties. During periods of low oil and/or natural gas prices, it
will become more difficult to raise the capital necessary to
finance expansion activities. If we are unable to replace our
production, our reserves will decrease, and our business, financial
condition and results of operations would be adversely
affected.
40
Our strategy includes acquisitions of oil and natural gas
properties, and our failure to identify or complete future
acquisitions successfully, or not produce projected revenues
associated with the future acquisitions could reduce our earnings
and hamper our growth.
We
may be unable to identify properties for acquisition or to make
acquisitions on terms that we consider economically acceptable.
There is intense competition for acquisition opportunities in our
industry. Competition for acquisitions may increase the cost of, or
cause us to refrain from, completing acquisitions. The completion
and pursuit of acquisitions may be dependent upon, among other
things, our ability to obtain debt and equity financing and, in
some cases, regulatory approvals. Our ability to grow through
acquisitions will require us to continue to invest in operations,
financial and management information systems and to attract,
retain, motivate and effectively manage our employees. The
inability to manage the integration of acquisitions effectively
could reduce our focus on subsequent acquisitions and current
operations and could negatively impact our results of operations
and growth potential. Our financial position and results of
operations may fluctuate significantly from period to period as a
result of the completion of significant acquisitions during
particular periods. If we are not successful in identifying or
acquiring any material property interests, our earnings could be
reduced and our growth could be restricted.
We
may engage in bidding and negotiating to complete successful
acquisitions. We may be required to alter or increase substantially
our capitalization to finance these acquisitions through the use of
cash on hand, the issuance of debt or equity securities, the sale
of production payments, the sale of non-strategic assets, the
borrowing of funds or otherwise. If we were to proceed with one or
more acquisitions involving the issuance of our common stock, our
stockholders would suffer dilution of their interests. Furthermore,
our decision to acquire properties that are substantially different
in operating or geologic characteristics or geographic locations
from areas with which our staff is familiar may impact our
productivity in such areas.
We
may not be able to produce the projected revenues related to future
acquisitions. There are many assumptions related to the projection
of the revenues of future acquisitions including, but not limited
to, drilling success, oil and natural gas prices, production
decline curves and other data. If revenues from future acquisitions
do not meet projections, this could adversely affect our business
and financial condition.
If we complete acquisitions or enter into business combinations in
the future, they may disrupt or have a negative impact on our
business.
If
we complete acquisitions or enter into business combinations in the
future, funding permitting, we could have difficulty integrating
the acquired companies’ assets, personnel and operations with
our own. Additionally, acquisitions, mergers or business
combinations we may enter into in the future could result in a
change of control of the Company, and a change in the board of
directors or officers of the Company. In addition, the key
personnel of the acquired business may not be willing to work for
us. We cannot predict the effect expansion may have on our core
business. Regardless of whether we are successful in making an
acquisition or completing a business combination, the negotiations
could disrupt our ongoing business, distract our management and
employees and increase our expenses. In addition to the risks
described above, acquisitions and business combinations are
accompanied by a number of inherent risks, including, without
limitation, the following:
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the
difficulty of integrating acquired companies, concepts and
operations;
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the
potential disruption of the ongoing businesses and distraction of
our management and the management of acquired
companies;
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change
in our business focus and/or management;
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difficulties
in maintaining uniform standards, controls, procedures and
policies;
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the
potential impairment of relationships with employees and partners
as a result of any integration of new management
personnel;
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the
potential inability to manage an increased number of locations and
employees;
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our
ability to successfully manage the companies and/or concepts
acquired;
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the
failure to realize efficiencies, synergies and cost savings;
or
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the
effect of any government regulations which relate to the business
acquired.
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41
Our
business could be severely impaired if and to the extent that we
are unable to succeed in addressing any of these risks or other
problems encountered in connection with an acquisition or business
combination, many of which cannot be presently identified. These
risks and problems could disrupt our ongoing business, distract our
management and employees, increase our expenses and adversely
affect our results of operations.
Any
acquisition or business combination transaction we enter into in
the future could cause substantial dilution to existing
stockholders, result in one party having majority or significant
control over the Company or result in a change in business focus of
the Company.
We may incur indebtedness which could reduce our financial
flexibility, increase interest expense and adversely impact our
operations and our unit costs.
We
currently have no outstanding indebtedness, but we may incur
significant amounts of indebtedness in the future in order to make
acquisitions or to develop our properties. Our level of
indebtedness could affect our operations in several ways, including
the following:
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a
significant portion of our cash flows could be used to service our
indebtedness;
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a high
level of debt would increase our vulnerability to general adverse
economic and industry conditions;
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any
covenants contained in the agreements governing our outstanding
indebtedness could limit our ability to borrow additional
funds;
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dispose
of assets, pay dividends and make certain investments;
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a high
level of debt may place us at a competitive disadvantage compared
to our competitors that are less leveraged and, therefore, may be
able to take advantage of opportunities that our indebtedness may
prevent us from pursuing; and
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debt
covenants to which we may agree may affect our flexibility in
planning for, and reacting to, changes in the economy and in our
industry.
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A
high level of indebtedness increases the risk that we may default
on our debt obligations. We may not be able to generate sufficient
cash flows to pay the principal or interest on our debt, and future
working capital, borrowings or equity financing may not be
available to pay or refinance such debt. If we do not have
sufficient funds and are otherwise unable to arrange financing, we
may have to sell significant assets or have a portion of our assets
foreclosed upon which could have a material adverse effect on our
business, financial condition and results of
operations.
We may purchase oil and natural gas properties with liabilities or
risks that we did not know about or that we did not assess
correctly, and, as a result, we could be subject to liabilities
that could adversely affect our results of operations.
Before
acquiring oil and natural gas properties, we estimate the reserves,
future oil and natural gas prices, operating costs, potential
environmental liabilities and other factors relating to the
properties. However, our review involves many assumptions and
estimates, and their accuracy is inherently uncertain. As a result,
we may not discover all existing or potential problems associated
with the properties we buy. We may not become sufficiently familiar
with the properties to assess fully their deficiencies and
capabilities. We do not generally perform inspections on every well
or property, and we may not be able to observe mechanical and
environmental problems even when we conduct an inspection. The
seller may not be willing or financially able to give us
contractual protection against any identified problems, and we may
decide to assume environmental and other liabilities in connection
with properties we acquire. If we acquire properties with risks or
liabilities we did not know about or that we did not assess
correctly, our business, financial condition and results of
operations could be adversely affected as we settle claims and
incur cleanup costs related to these liabilities.
42
We may incur losses or costs as a result of title deficiencies in
the properties in which we invest.
If
an examination of the title history of a property that we have
purchased reveals an oil and natural gas lease has been purchased
in error from a person who is not the owner of the property, our
interest would be worthless. In such an instance, the amount paid
for such oil and natural gas lease as well as any royalties paid
pursuant to the terms of the lease prior to the discovery of the
title defect would be lost.
Prior
to the drilling of an oil and natural gas well, it is the normal
practice in the oil and natural gas industry for the person or
company acting as the operator of the well to obtain a preliminary
title review of the spacing unit within which the proposed oil and
natural gas well is to be drilled to ensure there are no obvious
deficiencies in title to the well. Frequently, as a result of such
examinations, certain curative work must be done to correct
deficiencies in the marketability of the title, and such curative
work entails expense. Our failure to cure any title defects may
adversely impact our ability in the future to increase production
and reserves. In the future, we may suffer a monetary loss from
title defects or title failure. Additionally, unproved and
unevaluated acreage has greater risk of title defects than
developed acreage. 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 which could adversely
affect our business, financial condition and results of
operations.
Our identified drilling locations are scheduled over several years,
making them susceptible to uncertainties that could materially
alter the occurrence or timing of their drilling.
Our
management team has identified and scheduled drilling locations in
our operating areas over a multi-year period. Our ability to drill
and develop these locations depends on a number of factors,
including the availability of equipment and capital, approval by
regulators, seasonal conditions, oil and natural gas prices,
assessment of risks, costs and drilling results. The final
determination on whether to drill any of these locations will be
dependent upon the factors described elsewhere in this Annual
Report and the documents incorporated by reference herein, as well
as, to some degree, the results of our drilling activities with
respect to our established drilling locations. Because of these
uncertainties, we do not know if the drilling locations we have
identified will be drilled within our expected timeframe or at all
or if we will be able to economically produce hydrocarbons from
these or any other potential drilling locations. Our actual
drilling activities may be materially different from our current
expectations, which could adversely affect our business, financial
condition and results of operations.
Potential conflicts of interest could arise for certain members of
our management team and board of directors that hold management
positions with other entities and our largest
stockholder.
Simon Kukes, our Chief Executive Officer and
member of our board of directors, J. Douglas Schick, our President,
and Clark R. Moore, our Executive Vice President, General Counsel
and Secretary, hold various other management positions with
privately-held companies, some of which are involved in the oil and
gas industry, and Simon Kukes is the principal of SK Energy LLC,
the Company’s largest stockholder. Simon Kukes also
beneficially owns 68.1% of our voting securities. We believe these
positions require only an immaterial amount of each officers’
time and will not conflict with their roles or responsibilities
with our company. If any of these companies enter into one or
more transactions with our company, or if the officers’
position with any such company requires significantly more time
than currently
anticipated, potential conflicts of
interests could arise from the officers performing services for us
and these other entities.
We currently license only a limited amount of seismic and other
geological data and may have difficulty obtaining additional data
at a reasonable cost, which could adversely affect our
future results of operations.
We
currently license only a limited amount of seismic and other
geological data to assist us in exploration and development
activities. We may obtain access to additional data in our areas of
interest through licensing arrangements with companies that own or
have access to that data or by paying to obtain that data directly.
Seismic and geological data can be expensive to license or obtain.
We may not be able to license or obtain such data at an acceptable
cost. In addition, even when properly interpreted, seismic
data and visualization techniques are not conclusive in determining
if hydrocarbons are present in economically producible amounts and
seismic indications of hydrocarbon saturation are generally not
reliable indicators of productive reservoir rock.
43
The unavailability or high cost of drilling rigs, completion
equipment and services, supplies and personnel, including hydraulic
fracturing equipment and personnel, could adversely affect our
ability to establish and execute exploration and development plans
within budget and on a timely basis, which could have a material
adverse effect on our business, financial condition and results of
operations.
Shortages
or the high cost of drilling rigs, completion equipment and
services, supplies or personnel could delay or adversely affect our
operations. When drilling activity in the United States increases,
associated costs typically also increase, including those costs
related to drilling rigs, equipment, supplies and personnel and the
services and products of other vendors to the industry. These costs
may increase, and necessary equipment and services may become
unavailable to us at economical prices. Should this increase in
costs occur, we may delay drilling activities, which may limit our
ability to establish and replace reserves, or we may incur these
higher costs, which may negatively affect our business, financial
condition and results of operations.
In
addition, in the past, the demand for hydraulic fracturing services
has exceeded the availability of fracturing equipment and crews
across the industry and in our operating areas in particular. The
accelerated wear and tear of hydraulic fracturing equipment due to
its deployment in unconventional oil and natural gas fields
characterized by longer lateral lengths and larger numbers of
fracturing stages may further amplify this equipment and crew
shortage. Although we believe there is currently sufficient supply
of hydraulic fracturing services, if demand for fracturing services
increases or the supply of fracturing equipment and crews
decreases, then higher costs could result and could adversely
affect our business, financial condition and results of
operations.
We have limited control over activities on properties we do not
operate.
We
are not the operator on some of our properties located in our D-J
Basin Asset, and, as a result, our ability to exercise influence
over the operations of these properties or their associated costs
is limited. Our dependence on the operators and other working
interest owners of these projects and our limited ability to
influence operations and associated costs or control the risks
could materially and adversely affect the realization of our
targeted returns on capital in drilling or acquisition activities.
The success and timing of our drilling and development activities
on properties operated by others therefore depends upon a number of
factors, including:
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and amount of capital expenditures;
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operator’s expertise and financial resources;
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the
rate of production of reserves, if any;
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approval
of other participants in drilling wells; and
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selection
of technology.
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The marketability of our production is dependent upon oil and
natural gas gathering and transportation and storage facilities
owned and operated by third parties, and the unavailability of
satisfactory oil and natural gas transportation arrangements have
had a material adverse effect on our revenue.
The
unavailability of satisfactory oil and natural gas transportation
arrangements has hindered our access to oil and natural gas markets
and has delayed production from our wells. The availability of a
ready market for our oil and natural gas production depends on a
number of factors, including the demand for, and supply of, oil and
natural gas and the proximity of reserves to pipelines, terminal
facilities and storage facilities. Our ability to market our
production depends in substantial part on the availability and
capacity of gathering systems, pipelines and processing facilities
owned and operated by third parties. Our failure to obtain these
services on acceptable terms could materially harm our business. In
the past we have, and in the future, we may be required to, shut-in
wells for lack of a market or because of inadequacy or
unavailability of pipeline or gathering system capacity. When this
occurs, we are unable to realize revenue from those wells until the
market for oil and gas increases and/or until production
arrangements are made to deliver our production to market.
Furthermore, we are obligated to pay shut-in royalties to certain
mineral interest owners in order to maintain our leases with
respect to certain shut-in wells. We do not expect to purchase firm
transportation capacity on third-party facilities. Therefore, we
expect the transportation of our production to be generally
interruptible in nature and lower in priority to those having firm
transportation arrangements.
44
The
disruption of third-party facilities due to maintenance and/or
weather could negatively impact our ability to market and deliver
our products. The third parties' control when or if such facilities
are restored after disruption, and what prices will be charged for
products. Federal and state regulation of oil and natural gas
production and transportation, tax and energy policies, changes in
supply and demand, pipeline pressures, damage to or destruction of
pipelines and general economic conditions could adversely affect
our ability to produce, gather and transport oil and natural
gas.
An increase in the differential between the NYMEX or other
benchmark prices of oil and natural gas and the wellhead price we
receive for our production has adversely affected our business,
financial condition and results of operations.
The
prices that we will receive for our oil and natural gas production
sometimes may reflect a discount to the relevant benchmark prices,
such as the New York Mercantile Exchange (NYMEX), that are used for
calculating hedge positions. The difference between the benchmark
price and the prices we receive is called a differential. Increases
in the differential between the benchmark prices for oil and
natural gas and the wellhead price we receive has recently
adversely affected, and is anticipated to continue to adversely
affect our business, financial condition and results of operations.
We do not have, and may not have in the future, any derivative
contracts or hedging covering the amount of the basis differentials
we experience in respect of our production. As such, we will be
exposed to any increase in such differentials.
Financial difficulties encountered by our oil and natural gas
purchasers, third-party operators or other third parties could
decrease our cash flow from operations and adversely affect the
exploration and development of our prospects and
assets.
We
derive and will derive in the future, substantially all of our
revenues from the sale of our oil and natural gas to unaffiliated
third-party purchasers, independent marketing companies and
mid-stream companies. Any delays in payments from our purchasers
caused by financial problems encountered by them will have an
immediate negative effect on our results of
operations.
Liquidity
and cash flow problems encountered by our working interest
co-owners or the third-party operators of our non-operated
properties may prevent or delay the drilling of a well or the
development of a project. Our working interest co-owners may be
unwilling or unable to pay their share of the costs of projects as
they become due. In the case of a farmout party, we would have to
find a new farmout party or obtain alternative funding in order to
complete the exploration and development of the prospects subject
to a farmout agreement. In the case of a working interest owner, we
could be required to pay the working interest owner’s share
of the project costs. We cannot assure you that we would be able to
obtain the capital necessary to fund either of these contingencies
or that we would be able to find a new farmout party.
The calculated present value of future net revenues from our proved
reserves will not necessarily be the same as the current market
value of our estimated oil and natural gas reserves.
You
should not assume that the present value of future net cash flows
as included in our public filings is the current market value of
our estimated proved oil and natural gas reserves. We generally
base the estimated discounted future net cash flows from proved
reserves on current costs held constant over time without
escalation and on commodity prices using an unweighted arithmetic
average of first-day-of-the-month index prices, appropriately
adjusted, for the 12-month period immediately preceding the date of
the estimate. Actual future prices and costs may be materially
higher or lower than the prices and costs used for these estimates
and will be affected by factors such as:
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prices we receive for oil and natural gas;
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actual
cost and timing of development and production
expenditures;
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the
amount and timing of actual production; and
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changes
in governmental regulations or taxation.
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In addition, the 10% discount factor that is
required to be used to calculate discounted future net revenues for
reporting purposes under Generally Accepted Accounting Principles
(“
GAAP
”) is
not necessarily the most appropriate discount factor based on the
cost of capital in effect from time to time and risks associated
with our business and the oil and natural gas industry in
general.
45
Competition in the oil and natural gas industry is intense, making
it difficult for us to acquire properties, market oil and natural
gas and secure trained personnel.
Our
ability to acquire additional prospects and to find and develop
reserves in the future will depend on our ability to evaluate and
select suitable properties and to consummate transactions in a
highly competitive environment for acquiring properties, marketing
oil and natural gas and securing trained personnel. Also, there is
substantial competition for capital available for investment in the
oil and natural gas industry. Many of our competitors possess and
employ financial, technical and personnel resources substantially
greater than ours, and many of our competitors have more
established presences in the United States than we have. Those
companies may be able to pay more for productive oil and natural
gas properties and exploratory prospects and to evaluate, bid for
and purchase a greater number of properties and prospects than our
financial or personnel resources permit. In addition, other
companies may be able to offer better compensation packages to
attract and retain qualified personnel than we are able to offer.
The cost to attract and retain qualified personnel has increased in
recent years due to competition and may increase substantially in
the future. We may not be able to compete successfully in the
future in acquiring prospective reserves, developing reserves,
marketing hydrocarbons, attracting and retaining quality personnel
and raising additional capital, which could have a material adverse
effect on our business, financial condition and results of
operations.
Our competitors may use superior technology and data resources that
we may be unable to afford or that would require a costly
investment by us in order to compete with them more
effectively.
Our
industry is subject to rapid and significant advancements in
technology, including the introduction of new products and services
using new technologies and databases. As our competitors use or
develop new technologies, we may be placed at a competitive
disadvantage, and competitive pressures may force us to implement
new technologies at a substantial cost. In addition, many of our
competitors will 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
can. We cannot be certain that we will be able to implement
technologies on a timely basis or at a cost that is acceptable to
us. One or more of the technologies that we will use or that we may
implement in the future may become obsolete, and we may be
adversely affected.
If we do not hedge our exposure to reductions in oil and natural
gas prices, we may be subject to significant reductions in prices.
Alternatively, we may use oil and natural gas price hedging
contracts, which involve credit risk and may limit future revenues
from price increases and result in significant fluctuations in our
profitability.
In
the event that we continue to choose not to hedge our exposure to
reductions in oil and natural gas prices by purchasing futures
and/or by using other hedging strategies, we may be subject to a
significant reduction in prices which could have a material
negative impact on our profitability. Alternatively, we may elect
to use hedging transactions with respect to a portion of our oil
and natural gas production to achieve more predictable cash flow
and to reduce our exposure to price fluctuations. While the use of
hedging transactions limits the downside risk of price declines,
their use also may limit future revenues from price increases.
Hedging transactions also involve the risk that the counterparty
may be unable to satisfy its obligations.
Part of our strategy involves using some of the latest available
horizontal drilling and completion techniques. The results of our
drilling in these plays are subject to drilling and completion
technique risks, and results may not meet our expectations for
reserves or production.
Many
of our operations involve, and are planned to utilize, the latest
drilling and completion techniques as developed by us and our
service providers in order to maximize production and ultimate
recoveries and therefore generate the highest possible returns.
Risks we face while completing our wells include, but are not
limited to, the inability to fracture stimulate the planned number
of stages, the inability to run tools and other equipment the
entire length of the well bore during completion operations, the
inability to recover such tools and other equipment, and the
inability to successfully clean out the well bore after completion
of the final fracture stimulation. Ultimately, the success of these
drilling and completion techniques can only be evaluated over time
as more wells are drilled and production profiles are established
over a sufficiently long time period. If our drilling results are
less than anticipated or we are unable to execute our drilling
program because of capital constraints, lease expirations, limited
access to gathering systems and takeaway capacity, and/or prices
for crude oil, natural gas, and NGLs decline, then the return on
our investment for a particular project may not be as attractive as
we anticipated and we could incur material write-downs of oil and
gas properties and the value of our undeveloped acreage could
decline in the future.
46
Uncertainties associated with enhanced recovery methods may result
in us not realizing an acceptable return on our investments in such
projects.
Production
and reserves, if any, attributable to the use of enhanced recovery
methods are inherently difficult to predict. If our enhanced
recovery methods do not allow for the extraction of crude oil,
natural gas, and associated liquids in a manner or to the extent
that we anticipate, we may not realize an acceptable return on our
investments in such projects. In addition, as proposed legislation
and regulatory initiatives relating to hydraulic fracturing become
law, the cost of some of these enhanced recovery methods could
increase substantially.
A significant amount of our Permian Basin Asset acreage must be
drilled pursuant to governing agreements and leases, in order to
hold the acreage by production. In the highly competitive market
for acreage, failure to drill sufficient wells in order to hold
acreage will result in a substantial lease renewal cost, or if
renewal is not feasible, loss of our lease and prospective drilling
opportunities.
Currently
31,813 acres (gross) of our Permian Basin Asset are held by
production and not subject to lease expiration, with 7,645 acres
(gross)
subject to lease or governing agreement expiration if these acres
are not developed by us prior to expiration. The loss of
substantial leases could have a material adverse effect on our
assets, operations, revenues and cash flow and could cause the
value of our securities to decline in value.
Competition for hydraulic fracturing services and water
disposal could impede our ability to develop our oil and gas
plays.
The
unavailability or high cost of high-pressure pumping services (or
hydraulic fracturing services), chemicals, proppant, water and
water disposal and related services and equipment could limit our
ability to execute our exploration and development plans on a
timely basis and within our budget. The U.S. oil and natural gas
industry is experiencing a growing emphasis on the exploitation and
development of shale natural gas and shale oil resource plays,
which are dependent on hydraulic fracturing for economically
successful development. Hydraulic fracturing in oil and gas plays
requires high pressure pumping service crews. A shortage of service
crews or proppant, chemical, water or water disposal options,
especially if this shortage occurred in eastern New Mexico or
eastern Colorado, could materially and adversely affect our
operations and the timeliness of executing our development plans
within our budget.
Our
operations are substantially dependent on the availability of
water. Restrictions on our ability to obtain water may have an
adverse effect on our financial condition, results of operations
and cash flows.
Water is an essential component of shale oil and natural gas
production during both the drilling and hydraulic fracturing
processes. Historically, we have been able to purchase water from
local land owners for use in our operations. When drought
conditions occur, governmental authorities may restrict the use of
water subject to their jurisdiction for hydraulic fracturing to
protect local water supplies. Both New Mexico and Colorado have
relatively arid climates and experience drought conditions from
time to time. If we are unable to obtain water to use in our
operations from local sources or dispose of or recycle water used
in operations, or if the price of water or water disposal increases
significantly, we may be unable to produce oil and natural gas
economically, which could have a material adverse effect on our
financial condition, results of operations, and cash
flows.
Downturns and volatility in global economies and commodity and
credit markets have, and in the future may, materially adversely
affect our business, results of operations and financial
condition.
Our
results of operations have been, and in the future may be,
materially adversely affected by the conditions of the global
economies and the credit, commodities and stock markets. Among
other things, we have recently been adversely impacted, and
anticipate to continue to be adversely impacted, due to a global
reduction in consumer demand for oil and gas. In addition, a
decline in consumer confidence or changing patterns in the
availability and use of disposable income by consumers can
negatively affect the demand for oil and gas and as a result our
results of operations.
47
Improvements in or new discoveries of alternative energy
technologies could have a material adverse effect on our financial
condition and results of operations.
Because
our operations depend on the demand for oil and used oil, any
improvement in or new discoveries of alternative energy
technologies (such as wind, solar, geothermal, fuel cells and
biofuels) that increase the use of alternative forms of energy
and reduce the demand for oil, gas and oil and gas related products
could have a material adverse impact on our business, financial
condition and results of operations.
Competition due to advances in renewable fuels may lessen the
demand for our products and negatively impact our
profitability.
Alternatives
to petroleum-based products and production methods are continually
under development. For example, a number of automotive, industrial
and power generation manufacturers are developing alternative clean
power systems using fuel cells or clean-burning gaseous fuels that
may address increasing worldwide energy costs, the long-term
availability of petroleum reserves and environmental concerns,
which if successful could lower the demand for oil and gas. If
these non-petroleum-based products and oil alternatives continue to
expand and gain broad acceptance such that the overall demand for
oil and gas is decreased it could have an adverse effect on our
operations and the value of our assets.
Future litigation or governmental proceedings could result in
material adverse consequences, including judgments or
settlements.
From
time to time, we are involved in lawsuits, regulatory inquiries and
may be involved in governmental and other legal proceedings arising
out of the ordinary course of our business. Many of these matters
raise difficult and complicated factual and legal issues and are
subject to uncertainties and complexities. The timing of the final
resolutions to these types of matters is often uncertain.
Additionally, the possible outcomes or resolutions to these matters
could include adverse judgments or settlements, either of which
could require substantial payments, adversely affecting our results
of operations and liquidity.
We may be subject in the normal course of business to judicial,
administrative or other third-party proceedings that could
interrupt or limit our operations, require expensive remediation,
result in adverse judgments, settlements or fines and create
negative publicity.
Governmental
agencies may, among other things, impose fines or penalties on us
relating to the conduct of our business, attempt to revoke or deny
renewal of our operating permits, franchises or licenses for
violations or alleged violations of environmental laws or
regulations or as a result of third-party challenges, require us to
install additional pollution control equipment or require us to
remediate potential environmental problems relating to any real
property that we or our predecessors ever owned, leased or operated
or any waste that we or our predecessors ever collected,
transported, disposed of or stored. Individuals, citizens groups,
trade associations or environmental activists may also bring
actions against us in connection with our operations that could
interrupt or limit the scope of our business. Any adverse outcome
in such proceedings could harm our operations and financial results
and create negative publicity, which could damage our reputation,
competitive position and stock price. We may also be required to
take corrective actions, including, but not limited to, installing
additional equipment, which could require us to make substantial
capital expenditures. We could also be required to indemnify our
employees in connection with any expenses or liabilities that they
may incur individually in connection with regulatory action against
us. These could result in a material adverse effect on our
prospects, business, financial condition and our results of
operations.
A substantial percentage of our New Mexico properties are
undeveloped; therefore, the risk associated with our success is
greater than would be the case if the majority of such properties
were categorized as proved developed producing.
Because
a substantial percentage of our New Mexico properties are
undeveloped, we will require significant additional capital to
develop such properties before they may become productive. Further,
because of the inherent uncertainties associated with drilling for
oil and gas, some of these properties may never be developed to the
extent that they result in positive cash flow. Even if we are
successful in our development efforts, it could take several years
for a significant portion of our undeveloped properties to be
converted to positive cash flow.
48
Part of our strategy involves using certain of the latest available
horizontal drilling and completion techniques, which involve
additional risks and uncertainties in their application if compared
to conventional drilling.
We
plan to utilize some of the latest horizontal drilling and
completion techniques as developed by us, other oil and gas
exploration and production companies and our service providers. The
additional risks that we face while drilling horizontally include,
but are not limited to, the following:
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drilling
wells that are significantly longer and/or deeper than more
conventional wells;
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landing
our wellbore in the desired drilling zone;
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staying
in the desired drilling zone while drilling horizontally through
the formation;
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running
our casing the entire length of the wellbore; and
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being
able to run tools and other equipment consistently through the
horizontal wellbore.
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Risks
that we face while completing our wells include, but are not
limited to, the following:
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the
ability to fracture stimulate the planned number of stages in a
horizontal or lateral well bore;
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the
ability to run tools the entire length of the wellbore during
completion operations; and
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the
ability to successfully clean out the wellbore after completion of
the final fracture stimulation stage.
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Prospects that we decide to drill may not yield oil or natural gas
in commercially viable quantities.
Our
prospects are in various stages of evaluation, ranging from
prospects that are currently being drilled to prospects that will
require substantial additional seismic data processing and
interpretation. There is no way to predict in advance of drilling
and testing whether any particular prospect will yield oil or
natural gas in sufficient quantities to recover drilling or
completion costs or to be economically viable. This risk may be
enhanced in our situation, due to the fact that a significant
percentage of our reserves is undeveloped. The use of seismic data
and other technologies and the study of producing fields in the
same area will not enable us to know conclusively prior to drilling
whether oil or natural gas will be present or, if present, whether
oil or natural gas will be present in commercial quantities. We
cannot assure you that the analogies we draw from available data
obtained by analyzing other wells, more fully explored prospects or
producing fields will be applicable to our drilling
prospects.
Over the past three years we have been significantly dependent on
capital provided to us by SK Energy.
Since
June 2018, SK Energy, which is owned and controlled by Simon Kukes,
the Company’s Chief Executive Officer and director, has
loaned us an aggregate of $51.7 million to support our operations
and for acquisitions, all of which loans were evidenced by
promissory notes. The promissory notes generally had terms which
were more favorable to us than we would have been able to obtain
from third parties, including, generally favorable interest rates,
no restrictions on further borrowing or financial covenants and no
security interests in our assets. All of such notes have to date
been converted into 29.5 million shares of common stock at
conversion prices which were above the then-trading prices of our
common stock. Additionally, pursuant to subscription agreements, SK
Energy purchased an additional aggregate of 15.0 million shares of
common stock from the Company in private transactions for $28.0
million, also on substantially more favorable terms to us than
could be obtained with third parties. While SK Energy has verbally
advised us that it intends to provide us additional funding as
needed, nothing has been documented to date, and such future
funding, if any, may not ultimately be provided on favorable terms,
if at all. In the event that we are forced to obtain funding from
parties other than SK Energy, such funding terms will likely not be
as favorable to the Company as the funding provided by SK Energy,
and may not be available in such amounts as previously provided by
SK Energy. In the event SK Energy fails to provide us future
funding, when and if needed, it could have a material adverse
effect on our liquidity, results of operations and could force us
to borrow funds from outside sources on less favorable terms than
our prior debt or sell equity to outside investors on less
favorable terms than the equity we issued to SK
Energy.
49
Negative public perception regarding us and/or our industry could
have an adverse effect on our operations.
Negative
public perception regarding us and/or our industry resulting from,
among other things, concerns raised by advocacy groups about
hydraulic fracturing, waste disposal, oil spills, seismic activity,
climate change, explosions of natural gas transmission lines and
the development and operation of pipelines and other midstream
facilities may lead to increased regulatory scrutiny, which may, in
turn, lead to new state and federal safety and environmental laws,
regulations, guidelines and enforcement interpretations.
Additionally, environmental groups, landowners, local groups and
other advocates may oppose our operations through organized
protests, attempts to block or sabotage our operations or those of
our midstream transportation providers, intervene in regulatory or
administrative proceedings involving our assets or those of our
midstream transportation providers, or file lawsuits or other
actions designed to prevent, disrupt or delay the development or
operation of our assets and business or those of our midstream
transportation providers. These actions may cause operational
delays or restrictions, increased operating costs, additional
regulatory burdens and increased risk of litigation. Moreover,
governmental authorities exercise considerable discretion in the
timing and scope of permit issuance and the public may engage in
the permitting process, including through intervention in the
courts. Negative public perception could cause the permits we
require to conduct our operations to be withheld, delayed or
burdened by requirements that restrict our ability to profitably
conduct our business.
Recently,
activists concerned about the potential effects of climate change
have directed their attention towards sources of funding for
fossil-fuel energy companies, which has resulted in certain
financial institutions, funds and other sources of capital
restricting or eliminating their investment in energy-related
activities. Ultimately, this could make it more difficult to secure
funding for exploration and production activities.
Weather and climate may have a significant and adverse impact on
us.
Demand
for crude oil and natural gas is, to a degree, dependent on weather
and climate, which impacts, among other things, the price we
receive for the commodities we produce and, in turn, our cash flows
and results of operations. For example, relatively warm
temperatures during a winter season generally result in relatively
lower demand for natural gas (as less natural gas is used to heat
residences and businesses) and, as a result, lower prices for
natural gas production.
In
addition, there has been public discussion that climate change may
be associated with more frequent or more extreme weather events,
changes in temperature and precipitation patterns, changes to
ground and surface water availability, and other related phenomena,
which could affect some, or all, of our operations. Our
exploration, exploitation and development activities and equipment
could be adversely affected by extreme weather events, such as
winter storms, flooding and tropical storms and hurricanes, which
may cause a loss of production from temporary cessation of activity
or damaged facilities and equipment. Such extreme weather events
could also impact other areas of our operations, including access
to our drilling and production facilities for routine operations,
maintenance and repairs, the installation and operation of
gathering, processing, compression, storage and transportation
facilities and the availability of, and our access to, necessary
third-party services, such as gathering, processing, compression,
storage and transportation services. Such extreme weather events
and changes in weather patterns may materially and adversely affect
our business and, in turn, our financial condition and results of
operations.
In 2020, we temporarily shut-in all of our operated producing
wells in our Permian Basin Asset and D-J Basin Asset to preserve
our oil and gas reserves for production during a more favorable oil
price environment, and while we have resumed full production, we
may again shut-in some or all of its operated production, should
market conditions significantly deteriorate.
As
a result of the COVID-19 outbreak, and the sharp decline in oil
prices which occurred in early 2020, partially as a result of the
decreased demand for oil caused by such outbreak and the actions
taken globally to stop the spread of such virus, in mid-April 2020,
we temporarily shut-in all of our operated producing wells in our
Permian Basin and D-J Basin to preserve our oil and gas reserves
for production during a more favorable oil price environment,
noting that most of our acreage is held by production with no
drilling obligations, which provides us with flexibility to hold
back on production and development during periods of low oil and
gas prices. Following partial recovery in oil prices, commencing in
early June 2020, we reactivated over 90% of our operated wells in
the Permian Basin and the D-J Basin that we shut-in in mid-April
2020. We subsequently resumed full production. However, we may
again shut-in some or all of our production, should market
conditions deteriorate into the mid- to low-$20 per barrel realized
well head price range in the future. While our producing wells are
shut-in, we do not generate revenues from such wells, and need to
use cash on hand and funds we receive from borrowings and the sale
of equity in order to pay our operating expenses. A continued
period of low-priced oil may make it non-economical for us to
operate our wells, which would have a material adverse effect on
our operating results and the value of our assets. We cannot
estimate the future price of oil, and as such cannot estimate, when
we may again determine to begin producing oil at its operated
wells.
50
Risks Relating to Government Regulations
Changes in the legal and regulatory environment governing the oil
and natural gas industry, particularly changes in the current
Colorado forced pooling system and drilling operation set-back
rules, salt water disposal permitting regulations in New Mexico,
and new federal orders restricting operations on federal lands,
could have a material adverse effect on our business.
Our business is subject to various forms of
government regulation, including laws, regulations and federal
orders concerning the location, spacing and permitting of the oil
and natural gas wells we drill, among other matters. In particular,
our business in the D-J Basin of Colorado utilizes a methodology
available in Colorado known as “
forced
pooling,
” which refers to
the ability of a holder of an oil and natural gas interest in a
particular prospective drilling spacing unit to apply to the
Colorado Oil and Gas Conservation Commission for an order forcing
all other holders of oil and natural gas interests in such area
into a common pool for purposes of developing that drilling spacing
unit. In addition, our Permian Basin operations require significant
salt water disposal capacity, with the permitting of necessary salt
water disposal wells being regulated by the New Mexico State Land
Office. In recent months, we have encountered significant delays in
receiving such permits, and increasing difficulty in obtaining
required permits, from the New Mexico State Land Office, which has
delayed completion operations and the bringing of new wells on to
full production. Changes in the legal and regulatory environment
governing our industry, particularly any changes to
Colorado’s forced pooling procedures that make forced pooling
more difficult to accomplish and changes in minimum set-backs
distances for drilling operations from buildings (including those
recently adopted), or increased regulation in New Mexico with
respect to salt water disposal well permitting, could result in
increased compliance costs and operational delays, and adversely
affect our business, financial condition and results of
operations.
In addition, approximately 26% of our Permian
Basin Assets and 1% of our D-J Basin Assets are located on federal
leases, which may be subject to federal laws, regulations and
orders that could limit our ability to operate. For example, on
January 20, 2021, the Acting Secretary of the Interior issued Order
Number 3395 (“
Order No.
3395
”) which contained a
directive to temporarily halt all federal permitting activity for
60 days in an effort to study environmental impacts of oil and gas
drilling and development. While Order No. 3395 has no impact on
existing or ongoing operations, potentially subsequent federal
orders could restrict our ability to develop our leases on federal
lands, which could adversely affect our business, financial
condition and results of operations.
In
the event that federal, state or local restrictions or prohibitions
are adopted in areas where we conduct operations, that restrict
operations or otherwise impose more stringent limitations on the
production and development of oil and natural gas, including, among
other things, the development of increased setback distances, we
and similarly situated oil and natural exploration and production
operators in the state may incur significant costs to comply with
such requirements or may experience delays or curtailment in the
pursuit of exploration, development, or production activities, and
possibly be limited or precluded in the drilling of wells or in the
amounts that we and similarly situated operates are ultimately able
to produce from our reserves. Any such increased costs, delays,
cessations, restrictions or prohibitions could have a material
adverse effect on our business, prospects, results of operations,
financial condition, and liquidity. If new or more stringent
federal, state or local legal restrictions relating to the
hydraulic fracturing process are adopted in areas where we operate,
including, for example, on federal and American Indian lands, we
could incur potentially significant added cost 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.
SEC rules could limit our ability to
book additional proved undeveloped reserves
(“
PUDs
”) in
the future.
SEC
rules require that, subject to limited exceptions, PUDs may only be
booked if they relate to wells scheduled to be drilled within five
years after the date of booking. This requirement has limited and
may continue to limit our ability to book additional PUDs as we
pursue our drilling program. Moreover, we may be required to write
down our PUDs if we do not drill or plan on delaying those wells
within the required five-year timeframe.
51
New or amended environmental legislation or regulatory initiatives
could result in increased costs, additional operating restrictions,
or delays, or have other adverse effects on us.
The environmental laws and regulations to which we are subject
change frequently, often to become more burdensome and/or to
increase the risk that we will be subject to significant
liabilities. New or amended federal, state, or local laws or
implementing regulations or orders imposing new environmental
obligations on, or otherwise limiting, our operations could make it
more difficult and more expensive to complete oil and natural gas
wells, increase our costs of compliance and doing business, delay
or prevent the development of resources (especially from shale
formations that are not commercial without the use of hydraulic
fracturing), or alter the demand for and consumption of our
products. Any such outcome could have a material and adverse impact
on our cash flows and results of operations.
For example, in 2014,
2016 and 2018, opponents of hydraulic fracturing sought statewide
ballot initiatives in Colorado that would have restricted oil and
gas development in Colorado and could have had materially adverse
impacts on us. One of the proposed initiatives would have made the
vast majority of the surface area of the state ineligible for
drilling, including substantially all of our planned future
drilling locations. By further example, in April 2019, Colorado
Senate Bill 19-181 (the “
Bill
”) was
passed into law, which prioritizes the protection of public safety,
health, welfare, and the environment in the regulation of the oil
and gas industry by modifying the State’s oil and gas
statutes and clarifying, reinforcing, and establishing local
governments’ regulatory authority over the surface impacts of
oil and gas development in Colorado. This Bill, among other things,
gives more power to local government entities in making land use
decisions about oil and gas development and regulation, and directs
the Colorado Oil & Gas Conservation Commission
(“
COGCC
”) to
promulgate rules to ensure, among other things, proper wellbore
integrity, allow public disclosure of flowline information, and
evaluate when inactive or shut-in wells must be inspected before
being put into production or used for injection. In addition, the
Bill requires that owners of more than 50% of the mineral interests
in lands to be pooled must have joined in the application for a
pooling order and that the application must include proof that the
applicant received approval for the facilities from the affected
local government or that the affected local government does not
regulate such facilities. In addition, the Bill provides that an
operator cannot use the surface owned by a nonconsenting owner
without permission from the nonconsenting owner, and increases
nonconsenting owners’ royalty rates during a well’s
pay-back period from 12.5% to 13.0%.
Pursuant to the Bill,
the COGCC conducted a
series of rulemaking hearings during 2020 which resulted in updated
regulatory and permitting requirements, including siting
requirements.
The
COGCC commissioners determined that locations with residential or
high occupancy building units within 2,000 feet would be subject to
additional siting requirements, but also supported “off
ramps” allowing oil and gas operators to site their drill
pads as close as 500 feet from building units in certain
circumstances. We anticipate that the Bill may make it more
difficult and more costly for us to undertake oil and gas
development activities in Colorado.
Similar to the Bill
described above, proposals are made from time to time to adopt new,
or amend existing, laws and regulations to address hydraulic
fracturing or climate change concerns through further regulation of
exploration and development activities.
Please read “
Part
I
” –
“
Item 1.
Business
” —
“
Regulation of the Oil
and Gas Industry
” and
“
Regulation of
Environmental and Occupational Safety and Health
Matters
” for a
further description of the laws and regulations that affect
us
.
We cannot predict the nature, outcome, or effect on us of future
regulatory initiatives, but such initiatives could materially
impact our results of operations, production, reserves, and other
aspects of our business.
For example,
in 2019, the EPA
increased the state of Colorado’s non-attainment ozone
classification for the Denver Metro North Front Range Ozone
Eight-Hour Non-Attainment ("
Denver Metro/North Front Range
NAA
") area from "moderate" to “serious” under
the 2008 national ambient air quality standard ("
NAAQS
"). This increase in
non-attainment status to "serious" triggered significant additional
obligations for the state under the CAA and resulted in Colorado
adopting new and more stringent air quality control requirements in
December 2020 that are applicable to our operations, with
additional obligations for the state under the CAA possible that
could result in new and more stringent air quality permitting and
control requirements, which may in turn result in significant costs
and delays in obtaining necessary permits applicable to our
operations.
Proposed changes to U.S. tax laws, if adopted, could have an
adverse effect on our business, financial condition, results of
operations, and cash flows.
From time to time, legislative proposals are made that would, if
enacted, result in the elimination of the immediate deduction for
intangible drilling and development costs, the elimination of the
deduction from income for domestic production activities relating
to oil and gas exploration and development, the repeal of the
percentage depletion allowance for oil and gas properties, and an
extension of the amortization period for certain geological and
geophysical expenditures. Such changes, if adopted, or other
similar changes that reduce or eliminate deductions currently
available with respect to oil and gas exploration and development,
could adversely affect our business, financial condition, results
of operations, and cash flows.
52
We may incur substantial costs to comply with the various federal,
state, and local laws and regulations that affect our oil and
natural gas operations, including as a result of the actions of
third parties.
We are affected
significantly by a substantial number of governmental regulations
relating to, among other things, the release or disposal of
materials into the environment, health and safety, land use, and
other matters. A summary of the principal environmental rules and
regulations to which we are currently subject is set forth
in
“
Part
I
” –
“
Item 1.
Business
” —
“
Regulation of the Oil
and Gas Industry
” and
“
Regulation of
Environmental and Occupational Safety and Health
Matters
”.
Compliance
with such laws and regulations often increases our cost of doing
business and thereby decreases our profitability. Failure to comply
with these laws and regulations may result in the assessment of
administrative, civil, and criminal penalties, the incurrence of
investigatory or remedial obligations, or the issuance of cease and
desist orders.
The environmental laws and regulations to which we are subject may,
among other things:
●
require us to apply for and receive a permit before drilling
commences or certain associated facilities are
developed;
●
restrict the types, quantities, and concentrations of substances
that can be released into the environment in connection with
drilling, hydraulic fracturing, and production
activities;
●
limit or prohibit
drilling activities on certain lands lying within wilderness,
wetlands and other “
waters
of the United States,
” threatened and
endangered species habitat, and other protected
areas;
●
require remedial measures to mitigate pollution from former
operations, such as plugging abandoned wells;
●
require us to add procedures and/or staff in order to comply with
applicable laws and regulations; and
●
impose substantial liabilities for pollution resulting from our
operations.
In addition, we could face liability under applicable environmental
laws and regulations as a result of the activities of previous
owners of our properties or other third parties. For example, over
the years, we have owned or leased numerous properties for oil and
natural gas activities upon which petroleum hydrocarbons or other
materials may have been released by us or by predecessor property
owners or lessees who were not under our control. Under applicable
environmental laws and regulations, including The Comprehensive
Environmental Response, Compensation, and Liability Act - otherwise
known as CERCLA or Superfund, and state laws, we could be held
liable for the removal or remediation of previously released
materials or property contamination at such locations, or at
third-party locations to which we have sent waste, regardless of
our fault, whether we were responsible for the release or whether
the operations at the time of the release were lawful.
Compliance with, or liabilities associated with violations of or
remediation obligations under, environmental laws and regulations
could have a material adverse effect on our results of operations
and financial condition.
Part of our strategy involves drilling in existing or emerging oil
and gas plays using some of the latest available horizontal
drilling and completion techniques. The results of our planned
exploratory drilling in these plays are subject to drilling and
completion technique risks, and drilling results may not meet our
expectations for reserves or production. As a result, we may incur
material write-downs and the value of our undeveloped acreage could
decline if drilling results are unsuccessful.
Our
operations in the Permian Basin in Chaves and Roosevelt Counties,
New Mexico, and the D-J Basin in Weld and Morgan Counties,
Colorado, involve utilizing the latest drilling and completion
techniques in order to maximize cumulative recoveries and therefore
generate the highest possible returns. Risks that we may face while
drilling include, but are not limited to, landing our well bore in
the desired drilling zone, staying in the desired drilling zone
while drilling horizontally through the formation, running our
casing the entire length of the well bore and being able to run
tools and other equipment consistently through the horizontal well
bore. Risks that we may face while completing our wells include,
but are not limited to, being able to fracture stimulate the
planned number of stages, being able to run tools the entire length
of the well bore during completion operations and successfully
cleaning out the well bore after completion of the final fracture
stimulation stage.
53
The
results of our drilling in new or emerging formations will be more
uncertain initially than drilling results in areas that are more
developed and have a longer history of established production.
Newer or emerging formations and areas have limited or no
production history and consequently we are less able to predict
future drilling results in these areas.
Ultimately,
the success of these drilling and completion techniques can only be
evaluated over time as more wells are drilled and production
profiles are established over a sufficiently long time period. If
our drilling results are less than anticipated or we are unable to
execute our drilling program because of capital constraints, lease
expirations, access to gathering systems and limited takeaway
capacity or otherwise, and/or natural gas and oil prices decline,
the return on our investment in these areas may not be as
attractive as we anticipate. Further, as a result of any of these
developments we could incur material write-downs of our oil and
natural gas properties and the value of our undeveloped acreage
could decline in the future.
Regulations could adversely affect our ability to hedge risks
associated with our business and our operating results and cash
flows.
Rules adopted by federal regulators establishing
federal regulation of the over-the-counter
(“
OTC
”) derivatives market and entities that
participate in that market may adversely affect our ability to
manage certain of our risks on a cost-effective basis. Such laws
and regulations may also adversely affect our ability to execute
our strategies with respect to hedging our exposure to variability
in expected future cash flows attributable to the future sale of
our oil and gas.
We
expect that our potential future hedging activities will remain
subject to significant and developing regulations and regulatory
oversight. However, the full impact of the various U.S. regulatory
developments in connection with these activities will not be known
with certainty until such derivatives market regulations are fully
implemented and related market practices and structures are fully
developed.
The Federal Government has instituted a moratorium on new oil and
gas leases and permits on federal onshore and offshore lands, which
if extended, or leads to a change in regulatory schemes, may have a
material adverse effect on the Company and its results of
operations.
On
January 20, 2021, the Acting U.S. Interior Secretary, instituted a
60-day moratorium on new oil and gas leases and permits on federal
onshore and offshore lands. A total of approximately 26% of the
Company’s acreage in New Mexico and 1% of the Company’s
acreage in Colorado are located on federal lands. It is currently
unclear whether the moratorium will be extended when it expires on
March 21, 2021, or whether such moratorium is the start of a change
in federal policies regarding the grant of oil and gas permits on
federal lands. The current moratorium does not currently affect the
Company, as the Company has no near-term plans to drill new wells
on any leases held on federal lands; however, if such moratorium
was to become permanent, or the federal government in the future
were to grant less permits on federal lands, make such permitting
process more difficult, costly, or to institute more stringent
rules relating to such permitting process, it could have a material
adverse effect on the value of the Company’s leases and/or
its ability to undertake oil and gas operations on such the portion
of its leases on federal lands.
Risks Related to Our Common Stock
We currently have a sporadic and volatile market for our common
stock, and the market for our common stock is and may remain
sporadic and volatile in the future.
We currently have a
highly sporadic and volatile market for our common stock, which
market is anticipated to remain sporadic and volatile in the
future.
Factors that could
affect our stock price or result in fluctuations in the market
price or trading volume of our common stock
include:
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our
actual or anticipated operating and financial performance and
drilling locations, including reserves estimates;
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quarterly
variations in the rate of growth of our financial indicators, such
as net income per share, net income and cash flows, or those of
companies that are perceived to be similar to us;
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changes
in revenue, cash flows or earnings estimates or publication of
reports by equity research analysts;
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54
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speculation
in the press or investment community;
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public
reaction to our press releases, announcements and filings with the
SEC;
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sales
of our common stock by us or other stockholders, or the perception
that such sales may occur;
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the
limited amount of our freely tradable common stock available in the
public marketplace;
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general
financial market conditions and oil and natural gas industry market
conditions, including fluctuations in commodity
prices;
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the
realization of any of the risk factors presented in this Annual
Report;
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the
recruitment or departure of key personnel;
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commencement
of, or involvement in, litigation;
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the
prices of oil and natural gas;
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the
success of our exploration and development operations, and the
marketing of any oil and natural gas we produce;
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changes
in market valuations of companies similar to ours; and
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domestic
and international economic, health, legal and regulatory factors
unrelated to our performance.
|
Our common stock is
listed on the NYSE American under the symbol
“
PED
.”
Our stock price may be impacted by factors that are unrelated or
disproportionate to our operating performance.
The stock markets in general have
experienced extreme volatility that has often been unrelated to the
operating performance of particular companies. These broad market
fluctuations may adversely affect the trading price of our common
stock. Additionally,
general economic,
political and market conditions, such as recessions, interest rates
or international currency fluctuations may adversely affect the
market price of our common stock. Due to the limited volume of our
shares which trade, we believe that our stock prices (bid, ask and
closing prices) may not be related to our actual value, and
not reflect the actual value of our common stock. Stockholders and
potential investors in our common stock should exercise caution
before making an investment in us.
Additionally,
as a result of the potential illiquidity and sporadic trading of
our common stock, investors may not be interested in owning our
common stock because of the inability to acquire or sell a
substantial block of our common stock at one time. This may have an
adverse effect on the market price of our common stock. In
addition, a stockholder may not be able to borrow funds using our
common stock as collateral because lenders may be unwilling to
accept the pledge of securities having such a limited market. We
cannot assure you that an active trading market for our common
stock will develop or, if one develops, be sustained.
An active and sustained trading market for our common stock may not
develop in the future.
Our
common stock currently trades on the NYSE American, although our
common stock’s trading volume has been low from time to time
and trading in our common stock has historically been sporadic.
Liquid and active trading markets usually result in less price
volatility and more efficiency in carrying out investors’
purchase and sale orders. However, our common stock may continue to
have a sporadic trading volume, and investors may not be interested
in owning our common stock because of the inability to acquire or
sell a substantial block of our common stock at one time. This
could have an adverse effect on the market price of our common
stock. In addition, a stockholder may not be able to borrow funds
using our common stock as collateral because lenders may be
unwilling to accept the pledge of securities having such a limited
market. We cannot assure you that an active trading market for our
common stock will develop or, if one develops, be
sustained.
55
Our outstanding options and warrants may adversely affect the
trading price of our common stock.
As
of December 31, 2020, there are outstanding stock options to
purchase 1,234,849 shares of our common stock at a weighted average
price per share of $2.43 and outstanding warrants to purchase
150,329 shares of our common stock at a weighted average exercise
price of $0.32. For the life of the options and warrants, the
holders have the opportunity to profit from a rise in the market
price of our common stock without assuming the risk of ownership.
The issuance of shares upon the exercise of outstanding securities
will also dilute the ownership interests of our existing
stockholders.
The
availability of these shares for public resale, as well as any
actual resales of these shares, could adversely affect the trading
price of our common stock. We previously filed registration
statements with the SEC on Form S-8 providing for the registration
of an aggregate of approximately 8,134,915 shares of our common
stock, issued, issuable or reserved for issuance under our equity
incentive plans. Subject to the satisfaction of vesting conditions,
the expiration of lockup agreements, any management 10b5-1 plans
and certain restrictions on sales by affiliates, shares registered
under registration statements on Form S-8 will be available for
resale immediately in the public market without
restriction.
We
cannot predict the size of future issuances of our common stock
pursuant to the exercise of outstanding options or warrants or
conversion of other securities, or the effect, if any, that future
issuances and sales of shares of our common stock may have on the
market price of our common stock. Sales or distributions of
substantial amounts of our common stock (including shares
issued in connection with an acquisition), or the perception that
such sales could occur, may cause the market price of our common
stock to decline.
We depend significantly upon the continued involvement of our
present management.
We
depend to a significant degree upon the involvement of our
management, specifically, our Chief Executive Officer, Mr. Simon
Kukes and our President, Mr. J. Douglas Schick. Our performance and
success are dependent to a large extent on the efforts and
continued employment of Simon Kukes and Mr. Schick. We do not
believe that Simon Kukes or Mr. Schick could be quickly replaced
with personnel of equal experience and capabilities, and their
successor(s) may not be as effective. If Mr. Kukes, Mr.
Schick, or any of our other key personnel resign or become unable
to continue in their present roles and if they are not adequately
replaced, our business operations could be adversely affected. We
have no employment or similar agreement in place with Mr. Kukes.
Mr. Schick is party to an employment agreement with us which has no
stated term and can be terminated by either party without
cause.
We
have an active board of directors that meets several times
throughout the year and is intimately involved in our business and
the determination of our operational strategies. Members of our
board of directors work closely with management to identify
potential prospects, acquisitions and areas for further
development. If any of our directors resign or become unable to
continue in their present role, it may be difficult to find
replacements with the same knowledge and experience and as a
result, our operations may be adversely affected.
Simon Kukes, our Chief Executive
Officer and a member of board of directors, beneficially
owns
68.1
% of our common stock
through SK Energy LLC, which gives him majority voting control over
stockholder matters and his interests may be different from your
interests.
Simon
Kukes, our Chief Executive Officer and member of the board of
directors, through his individual ownership of the Company and
through his position as principal and sole owner of SK Energy LLC,
which beneficially owns approximately 65.2% of our issued and
outstanding common stock and Mr. Kukes, together with the ownership
of SK Energy, beneficially owns approximately 68.1% of our issued
and outstanding common stock. As such, Mr. Kukes can control the
outcome of all matters requiring a stockholder vote, including the
election of directors, the adoption of amendments to our
certificate of formation or bylaws and the approval of mergers and
other significant corporate transactions. Subject to any fiduciary
duties owed to the stockholders generally, while Mr. Kukes’
interests may generally be aligned with the interests of our
stockholders, in some instances Mr. Kukes may have interests
different than the rest of our stockholders, including but not
limited to, future potential company financings in which SK Energy
may participate, or his leadership at the Company. Mr. Kukes’
influence or control of our company as a stockholder may have
the effect of delaying or preventing a change of control
of our company and may adversely affect the voting and other
rights of other stockholders. Because Mr. Kukes controls the
stockholder vote, investors may find it difficult to replace Mr.
Kukes (and such persons as he may appoint from time to
time) as members of our management if they disagree with the
way our business is being operated. Additionally, the interests of
Mr. Kukes may differ from the interests of the other stockholders
and thus result in corporate decisions that are adverse to other
stockholders.
56
Provisions of Texas law may have anti-takeover effects that could
prevent a change in control even if it might be beneficial to our
stockholders.
Provisions of Texas law may discourage, delay or
prevent someone from acquiring or merging with us, which may cause
the market price of our common stock to decline. Under Texas law, a
stockholder who beneficially owns more than 20% of our voting
stock, or any “
affiliated
stockholder,
” cannot
acquire us for a period of three years from the date this person
became an affiliated stockholder, unless various conditions are
met, such as approval of the transaction by our board of directors
before this person became an affiliated stockholder (such as the
approval of our board of directors of Mr. Kukes’ ownership of
the Company) or approval of the holders of at least two-thirds
of our outstanding voting shares not beneficially owned by the
affiliated stockholder.
We are subject to the Continued Listing Criteria of the NYSE
American and our failure to satisfy these criteria may result in
delisting of our common stock.
Our common stock is currently listed on the NYSE
American. In order to maintain this listing, we must maintain
certain share prices, financial and share distribution targets,
including maintaining a minimum amount of stockholders’
equity and a minimum number of public stockholders. In addition to
these objective standards, the NYSE American may delist the
securities of any issuer if, in its opinion, the issuer’s
financial condition and/or operating results appear unsatisfactory;
if it appears that the extent of public distribution or the
aggregate market value of the security has become so reduced as to
make continued listing on the NYSE American inadvisable; if the
issuer sells or disposes of principal operating assets or ceases to
be an operating company; if an issuer fails to comply with the NYSE
American’s listing requirements; if an issuer’s common
stock sells at what the NYSE American considers a
“
low selling
price
” (generally trading
below $0.20 per share for an extended period of time) and the
issuer fails to correct this via a reverse split of shares after
notification by the NYSE American (provided that issuers can also
be delisted if any shares of the issuer trade below $0.06 per
share); or if any other event occurs or any condition exists which
makes continued listing on the NYSE American, in its opinion,
inadvisable.
If
the NYSE American delists our common stock, investors may face
material adverse consequences, including, but not limited to, a
lack of trading market for our securities, reduced liquidity,
decreased analyst coverage of our securities, and an inability for
us to obtain additional financing to fund our
operations.
Due to the fact that our common stock is listed on the NYSE
American, we are subject to financial and other reporting and
corporate governance requirements which increase our costs and
expenses.
We are currently required to file annual and quarterly information
and other reports with the Securities and Exchange Commission that
are specified in Sections 13 and 15(d) of the Exchange Act.
Additionally, due to the fact that our common stock is listed on
the NYSE American, we are also subject to the requirements to
maintain independent directors, comply with other corporate
governance requirements and are required to pay annual listing and
stock issuance fees. These obligations require a commitment of
additional resources including, but not limited, to additional
expenses, and may result in the diversion of our senior
management’s time and attention from our day-to-day
operations. These obligations increase our expenses and may make it
more complicated or time consuming for us to undertake certain
corporate actions due to the fact that we may require NYSE approval
for such transactions and/or NYSE rules may require us to obtain
stockholder approval for such transactions.
General Risk Factors
Because we are a small company, the requirements of being a public
company, including compliance with the reporting requirements of
the Exchange Act and the requirements of the Sarbanes-Oxley
Act and the Dodd-Frank Act, may strain our resources, increase our
costs and distract management, and we may be unable to comply with
these requirements in a timely or cost-effective
manner.
As a public company with listed equity securities,
we must comply with the federal securities laws, rules and
regulations, including certain corporate governance provisions of
the Sarbanes-Oxley Act of 2002 (the “
Sarbanes-Oxley
Act
”) and the
Dodd-Frank Act, related rules and regulations of the SEC and the
NYSE American, with which a private company is not required to
comply. Complying with these laws, rules and regulations will
occupy a significant amount of time of our board of directors and
management and will significantly increase our costs and expenses,
which we cannot estimate accurately at this time. Among other
things, we must:
|
|
●
|
establish
and maintain a system of internal control over financial reporting
in compliance with the requirements of Section 404 of the
Sarbanes-Oxley Act and the related rules and regulations of the SEC
and the Public Company Accounting Oversight Board;
|
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|
|
|
|
|
●
|
comply
with rules and regulations promulgated by the NYSE
American;
|
|
|
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|
57
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●
|
prepare
and distribute periodic public reports in compliance with our
obligations under the federal securities laws;
|
|
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|
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●
|
maintain
various internal compliance and disclosures policies, such as those
relating to disclosure controls and procedures and insider trading
in our common stock;
|
|
|
|
|
|
|
●
|
involve
and retain to a greater degree outside counsel and accountants in
the above activities;
|
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●
|
maintain
a comprehensive internal audit function; and
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●
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maintain
an investor relations function.
|
In
addition, being a public company subject to these rules and
regulations may require us to accept less director and officer
liability insurance coverage than we desire or to incur substantial
costs to obtain coverage. These factors could also make it more
difficult for us to attract and retain qualified members of our
board of directors, particularly to serve on our audit committee,
and qualified executive officers.
We do not presently intend to pay any cash dividends on or
repurchase any shares of our common stock.
We
do not presently intend to pay any cash dividends on our common
stock or to repurchase any shares of our common stock. Any payment
of future dividends will be at the discretion of the board of
directors and will depend on, among other things, our earnings,
financial condition, capital requirements, level of indebtedness,
statutory and contractual restrictions applying to the payment of
dividends and other considerations that our board of directors
deems relevant. Cash dividend payments in the future may only be
made out of legally available funds and, if we experience
substantial losses, such funds may not be available. Accordingly,
you may have to sell some or all of your common stock in order to
generate cash flow from your investment, and there is no guarantee
that the price of our common stock that will prevail in the market
will ever exceed the price paid by you.
Our business could be adversely affected by security threats,
including cybersecurity threats.
We
face various security threats, including cybersecurity threats to
gain unauthorized access to our sensitive information or to render
our information or systems unusable, and threats to the security of
our facilities and infrastructure or third-party facilities and
infrastructure, such as gathering and processing facilities,
refineries, rail facilities and pipelines. The potential for such
security threats subjects our operations to increased risks that
could have a material adverse effect on our business, financial
condition and results of operations. For example, unauthorized
access to our seismic data, reserves information or other
proprietary information could lead to data corruption,
communication interruptions, or other disruptions to our
operations.
Our
implementation of various procedures and controls to monitor and
mitigate such security threats and to increase security for our
information, systems, facilities and infrastructure may result in
increased capital and operating costs. Moreover, there can be no
assurance that such procedures and controls will be sufficient to
prevent security breaches from occurring. If any of these security
breaches were to occur, they could lead to losses of, or damage to,
sensitive information or facilities, infrastructure and systems
essential to our business and operations, as well as data
corruption, reputational damage, communication interruptions or
other disruptions to our operations, which, in turn, could have a
material adverse effect on our business, financial position and
results of operations.
Future sales of our common stock could cause our stock price to
decline.
If our shareholders sell substantial amounts of
our common stock in the public market, the market price of our
common stock could decrease significantly. The perception in the
public market that our shareholders might sell shares of our common
stock could also depress the market price of our common stock. Up
to $100,000,000 in total aggregate value of securities have been
registered by us on a “
shelf
”
registration statement on Form S-3 (File No. 333-250904) that we
filed with the Securities and Exchange Commission on November 23,
2020 (the “
November 2020 Form
S-3
”), and which was
declared effective on December 2, 2020. To date, an aggregate of
approximately $8.95 million in securities have been sold by us
under the November 2020 Form S-3, leaving approximately $91.05
million in securities which will be eligible for sale in the public
markets from time to time, when sold and issued by us, subject to
the requirements of Form S-3, which limits us, until such time, if
ever, as our public float exceeds $75 million, from selling
securities in a public primary offering under Form S-3 with a value
exceeding more than one-third of the aggregate market value of the
common stock held by non-affiliates of the Company every twelve
months. Additionally, if our existing shareholders sell, or
indicate an intention to sell, substantial amounts of our common
stock in the public market, the trading price of our common stock
could decline significantly. The market price for shares of our
common stock may drop significantly when such securities are sold
in the public markets. A decline in the price of shares of our
common stock might impede our ability to raise capital through the
issuance of additional shares of our common stock or other equity
securities.
58
The threat and impact of terrorist attacks, cyber-attacks or
similar hostilities may adversely impact our
operations.
We
cannot assess the extent of either the threat or the potential
impact of future terrorist attacks on the energy industry in
general, and on us in particular, either in the short-term or in
the long-term. Uncertainty surrounding such hostilities may affect
our operations in unpredictable ways, including the possibility
that infrastructure facilities, including pipelines and gathering
systems, production facilities, processing plants and refineries,
could be targets of, or indirect casualties of, an act of terror, a
cyber-attack or electronic security breach, or an act of
war.
We may have difficulty managing growth in our business, which could
have a material adverse effect on our business, financial condition
and results of operations and our ability to execute our business
plan in a timely fashion.
Because
of our small size, growth in accordance with our business plans, if
achieved, will place a significant strain on our financial,
technical, operational and management resources. As we expand our
activities, including our planned increase in oil exploration,
development and production, and increase the number of projects we
are evaluating or in which we participate, there will be additional
demands on our financial, technical and management resources. The
failure to continue to upgrade our technical, administrative,
operating and financial control systems or the occurrence of
unexpected expansion difficulties, including the inability to
recruit and retain experienced managers, geoscientists, petroleum
engineers and landmen could have a material adverse effect on our
business, financial condition and results of operations and our
ability to execute our business plan in a timely
fashion.
Failure to adequately protect critical data and technology systems
could materially affect our operations.
Information
technology solution failures, network disruptions and breaches of
data security could disrupt our operations by causing delays or
cancellation of customer orders, impeding processing of
transactions and reporting financial results, resulting in the
unintentional disclosure of customer, employee or our information,
or damage to our reputation. There can be no assurance that a
system failure or data security breach will not have a material
adverse effect on our financial condition, results of operations or
cash flows.
Stockholders may be diluted significantly through our efforts to
obtain financing and satisfy obligations through the issuance of
securities.
Wherever possible, our
board of directors will attempt to use non-cash consideration to
satisfy obligations. In many instances, we believe that the
non-cash consideration will consist of shares of our common stock,
preferred stock or warrants to purchase shares of our common stock.
Our board of directors has authority, without action or vote of the
stockholders,
subject to
the requirements of the NYSE American (which generally require
stockholder approval for any transactions which would result in the
issuance of more than 20% of our then outstanding shares of common
stock or voting rights representing over 20% of our then
outstanding shares of stock, subject to certain exceptions,
including sales in a public offering and/or sales which are
undertaken at or above the lower of the closing price immediately
preceding the signing of the binding agreement or the average
closing price for the five trading days immediately preceding the
signing of the binding agreement),
to issue all or part of
the authorized but unissued shares of common stock, preferred stock
or warrants to purchase such shares of common stock. In addition,
we may attempt to raise capital by selling shares of our common
stock, possibly at a discount to market in the future. These
actions will result in dilution of the ownership interests of
existing stockholders and may further dilute common stock book
value, and that dilution may be material. Such issuances may also
serve to enhance existing management’s ability to maintain
control of us, because the shares may be issued to parties or
entities committed to supporting existing
management.
Our board of directors can authorize the issuance of preferred
stock, which could diminish the rights of holders of our common
stock and make a change of control of our company more
difficult even if it might benefit our stockholders.
Our
board of directors is authorized to issue shares of preferred stock
in one or more series and to fix the voting powers, preferences and
other rights and limitations of the preferred stock. Shares of
preferred stock may be issued by our board of directors without
stockholder approval, with voting powers and such preferences and
relative, participating, optional or other special rights and
powers as determined by our board of directors, which may be
greater than the shares of common stock currently outstanding. As a
result, shares of preferred stock may be issued by our board of
directors which cause the holders to have majority voting power
over our shares, provide the holders of the preferred stock the
right to convert the shares of preferred stock they hold into
shares of our common stock, which may cause substantial dilution to
our then common stock stockholders and/or have other rights and
preferences greater than those of our common stock stockholders
including having a preference over our common stock with respect to
dividends or distributions on liquidation or
dissolution.
59
Investors
should keep in mind that the board of directors has the authority
to issue additional shares of common stock and preferred stock,
which could cause substantial dilution to our existing
stockholders. Additionally, the dilutive effect of any preferred
stock which we may issue may be exacerbated given the fact that
such preferred stock may have voting rights and/or other rights or
preferences which could provide the preferred stockholders with
substantial voting control over us subsequent to the date of this
Annual Report and/or give those holders the power to prevent or
cause a change in control, even if that change in control might
benefit our stockholders. As a result, the issuance of shares of
common stock and/or preferred stock may cause the value of our
securities to decrease.
Securities analysts may not cover, or continue to cover, our common
stock and this may have a negative impact on our common
stock’s market price.
The trading market for our common stock will depend, in part, on
the research and reports that securities or industry analysts
publish about us or our business. We do not have any control over
independent analysts (provided that we have engaged various
non-independent analysts). We currently only have a few independent
analysts that cover our common stock, and these analysts may
discontinue coverage of our common stock at any time. Further, we
may not be able to obtain additional research coverage by
independent securities and industry analysts. If no independent
securities or industry analysts continue coverage of us, the
trading price for our common stock could be negatively impacted. If
one or more of the analysts who covers us downgrades our common
stock, changes their opinion of our shares or publishes inaccurate
or unfavorable research about our business, our stock price could
decline. If one or more of these analysts ceases coverage of us or
fails to publish reports on us regularly, demand for our common
stock could decrease and we could lose visibility in the financial
markets, which could cause our stock price and trading volume to
decline.
If persons engage in short sales of our common stock, including
sales of shares to be issued upon exercise of our outstanding
warrants, the price of our common stock may decline.
Selling
short is a technique used by a stockholder to take advantage of an
anticipated decline in the price of a security. In addition,
holders of options and warrants will sometimes sell short knowing
they can, in effect, cover through the exercise of an option or
warrant, thus locking in a profit. A significant number of short
sales or a large volume of other sales within a relatively short
period of time can create downward pressure on the market price of
a security. Further sales of common stock issued upon exercise of
our outstanding warrants could cause even greater declines in the
price of our common stock due to the number of additional shares
available in the market upon such exercise, which could encourage
short sales that could further undermine the value of our common
stock. Stockholders could, therefore, experience a decline in the
values of their investment as a result of short sales of our common
stock.
ITEM 1B.
U
NRESOLVED STAFF
COMMENTS.
None.
ITEM 2.
P
ROPERTIES.
The
information regarding the Company’s oil and gas properties as
required by Item 102 of Regulation S-K is included in
“
Item 1.
Business
”, above and incorporated in this
Item 2
by
reference.
Office Leases
In June
2018, the Company assumed the lease for its corporate office space
located in Houston, Texas from American Resources, Inc., an entity
beneficially owned and controlled by Ivar Siem, a director of the
Company, and J. Douglas Schick, the Company’s President. The
term of the lease ended on August 31, 2019.
Effective September
1, 2019, the Company moved its corporate headquarters from 1250
Wood Branch Park Dr., Suite 400, Houston, Texas 77079 to 575 N.
Dairy Ashford, Suite 210, Houston, Texas 77079 in connection with
the expiration of its former office space lease. The Company
entered into a sublease on approximately 5,200 square feet of
office space that expires on August 31, 2023 and has a base monthly
rent of approximately $10,000 with the first month rent due
beginning on January 1, 2020. The Company paid a security deposit
of $9,600.
On
November 1, 2019, the Company began subleasing approximately 300
square feet of office space at its current headquarters to SK
Energy, which is owned and controlled by Simon Kukes, our Chief
Executive Officer and a member of the Board of Directors. The lease
renews on a monthly basis, may be terminated by either party at any
time upon prior written notice delivered to the other party, and
has a monthly base rent of $1,200.
60
The
Company also had a lease for 187 square feet of office space
located in Danville, California for the Company’s Executive
Vice President and General Counsel. The monthly rent was $1,200,
discounted to $960 from April 2020 through the expiration of the
lease on August 28, 2020. The Company did not renew this lease upon
expiration in an effort to further reduce Company
expenses.
For the
year ended December 31, 2020 and 2019, the Company incurred lease
expense of $103,000 and $139,000, respectively, for the combined
leases.
ITEM 3.
L
EGAL PROCEEDINGS
From
time to time, we may become party to litigation or other legal
proceedings that we consider to be a part of the ordinary course of
our business. We are not currently involved in any legal
proceedings that we believe could reasonably be expected to have a
material adverse effect on our business, prospects, financial
condition or results of operations. We may become involved in
material legal proceedings in the future.
ITEM 4.
M
INE SAFETY
DISCLOSURES.
Not
applicable
61
PART II
ITEM 5.
M
ARKET FOR REGISTRANT’S
COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF
EQUITY SECURITIES.
Market Information
Since
September 10, 2013, the Company’s shares of common stock have
traded on the NYSE American under the ticker symbol
“
PED.
”
Stockholders
As of
March 19, 2021, there were 79,441,603 shares of our common stock
issued and outstanding held by approximately 700 holders of record
of our common stock, not including any persons who hold their stock
in “
street
name
”.
Common Stock
The
Company is authorized to issue 200,000,000 shares of common stock
with $0.001 par value per share. Holders of shares of common stock
are entitled to one vote per share on each matter submitted to a
vote of stockholders. In the event of liquidation, holders of
common stock are entitled to share pro rata in the distribution of
assets remaining after payment of liabilities, if any. Holders of
common stock have no cumulative voting rights, and, accordingly,
the holders of a majority of the outstanding shares have the
ability to elect all of the directors of the Company. Holders of
common stock have no preemptive or other rights to subscribe for
shares. Holders of common stock are entitled to such dividends as
may be declared by the Board out of funds legally available
therefore. The outstanding shares of common stock are validly
issued, fully paid and non-assessable.
Preferred Stock
At
December 31, 2020 and as of the date of this filing, the Company
was authorized to issue 100,000,000 shares of preferred stock with
a par value of $0.001 per share, of which 25,000,000 shares have
been designated “Series A Convertible Preferred Stock”.
As of December 31, 2020, and 2019, there were no shares of the
Company’s Series A Convertible Preferred Stock outstanding,
respectively, and there are no outstanding shares of preferred
stock as of the date of this filing.
Stock Transfer Agent
Our
stock transfer agent is American Stock Transfer & Trust
Company, LLC, located at 6201 15
th
Ave., Brooklyn, New
York 11219.
Recent Sales of Unregistered Securities
There
have been no sales of unregistered securities during the year ended
December 31, 2020 and from the period from January 1, 2021 to the
filing date of this report, which have not previously been
disclosed in a Quarterly Report on Form 10-Q or in a Current Report
on Form 8-K.
Use of Proceeds From Sale of Registered Securities
Our
Registration Statement on Form S-3 (Reg. No. 333-250904) in
connection with the sale by us of up to $100 million in securities
(common stock, preferred stock, warrants and units) was declared
effective by the Securities and Exchange Commission on December 2,
2020.
On
February 3, 2021, we filed a final Rule 424(b)(5) prospectus
supplement relating to the primary offering by us in a firm
commitment underwritten public offering of 5,190,000 shares of
common stock at a public offering price per share of
$1.50. The underwriters of the offering (Kingswood
Capital Markets, division of Benchmark Investments, Inc. as sole
bookrunner and Dawson James Securities) were also provided an
option to purchase an additional 778,500 shares from us, at the
public offering price less the underwriting discount, within 45
days of the offering to cover over-allotments, if any, which
overallotment option was exercised in full by the underwriters. The
offering (including the sale of the underwriters’
overallotment shares) closed on February 5, 2021. The net proceeds
to us from our sale of the common stock (including the shares sold
in connection with the exercise of the underwriters’
overallotment) were approximately $8.3 million (after deducting the
underwriting discount and commissions and offering expenses payable
by us). No further shares will be sold under the prospectus
supplement.
62
No
payments for our expenses were made in the offering described above
directly or indirectly to (i) any of our directors, officers or
their associates, (ii) any person(s) owning 10% or more of any
class of our equity securities or (iii) any of our affiliates.
There has been no material change in the planned use of proceeds
from our offering as described in our final prospectus filed with
the SEC pursuant to Rule 424(b).
Issuer Purchases of Equity Securities
None.
ITEM 6.
S
ELECTED FINANCIAL
DATA
Not
required under Regulation S-K for “
smaller reporting
companies
.”
63
ITEM 7.
M
ANAGEMENT’S DISCUSSION
AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
The following discussion and analysis of our financial condition
and results of operations should be read in conjunction with the
consolidated financial statements and related notes appearing
elsewhere in this Annual Report. The following discussion contains
“
forward-looking
statements
” that reflect our future plans, estimates,
beliefs and expected performance. We caution you that assumptions,
expectations, projections, intentions or beliefs about future
events may, and often do, vary from actual results and the
differences can be material. See “
Risk
Factors
” and “
Forward-Looking
Statements
.
”
Overview
We are an oil and gas company focused on the
development, acquisition and production of oil and natural
gas
assets where the latest in modern drilling and
completion techniques and technologies have yet to be applied. In
particular, we focus on legacy proven properties where there is a
long production history, well defined geology and existing
infrastructure that can be leveraged when applying modern field
management technologies. Our current properties are located in the
San Andres formation of the Permian Basin situated in West Texas
and eastern New Mexico
and in the
Denver-Julesberg Basin in Colorado. As of December 31, 2020,
we held approximately 37,068 net Permian Basin acres located in
Chaves and Roosevelt Counties, New Mexico, through PEDCO and
approximately 11,948 net D-J Basin acres located in Weld and Morgan
Counties, Colorado, through our wholly-owned operating subsidiary,
Red Hawk. As of December 31, 2020, we held interests in 379
gross (302 net) wells in our Permian Basin Asset of which 26
are active producers, 15 are active injectors and two are active
Saltwater Disposal Wells (“
SWD
”s), all of which are held by PEDCO and
operated by its wholly-owned operating subsidiaries, and interests
in 77 gross (22.0 net) wells in our D-J Basin Asset, of which
18 gross (16.2 net) wells are operated by Red Hawk and
currently producing, 38 gross (5.8 net) wells are
non-operated, and 21 wells have an after-payout
interest.
Detailed
information about our business plans and operations, including our
core D-J Basin and Permian Basin Assets, is contained under
“
Part
1
” — “
Item 1.
Business
” above.
How We Conduct Our Business and Evaluate Our
Operations
Our use
of capital for acquisitions and development allows us to direct our
capital resources to what we believe to be the most attractive
opportunities as market conditions evolve. We have historically
acquired properties that we believe had significant appreciation
potential. We intend to continue to acquire both operated and
non-operated properties to the extent we believe they meet our
return objectives.
We will
use a variety of financial and operational metrics to assess the
performance of our oil and natural gas operations,
including:
●
production
volumes;
●
realized
prices on the sale of oil and natural gas, including the effects of
our commodity derivative contracts;
●
oil
and natural gas production and operating expenses;
●
capital
expenditures;
●
general
and administrative expenses;
●
net
cash provided by operating activities; and
●
net
income.
Reserves
Our
estimated net proved crude oil and natural gas reserves at December
31, 2020 and 2019 were approximately 14.1 MMBoe and 14.0 MMBoe,
respectively. The 0.1 MMBoe increase was primarily due to increases
in the type curve from 2019’s year-end report resulting from
historical performance and our optimization of our future
development plans to focus on areas with the highest remaining oil
in place, which was derived from technical work and studies of our
assets since their acquisition, offset by 2020 produced volumes and
minor adjustments due to commodity pricing.
Using the average monthly crude oil price of
$39.57 per Bbl and natural gas price of $1.99 per thousand cubic
feet (“Mcf”) for the twelve months ended December
31, 2020, our estimated discounted future net cash flow
(“
PV-10
”) before tax
expenses for our proved reserves was approximately $58.2 million,
of which approximately $36.7 million are proved
undeveloped
reserves. Total reserve value at December 31, 2020, represents a
decrease of approximately $64.5 million or 53% from a year earlier
using the same SEC pricing and reserves methodology. The decrease
is strictly attributable to commodity pricing as the average
pricing for 2019 was significantly higher at $55.69 per Bbl for
crude oil and $2.58 per Mcf for natural gas.
64
The
reserves as of December 31, 2020 were determined in accordance with
standard industry practices and SEC regulations by the licensed
independent petroleum engineering firm of Cawley, Gillespie &
Associates, Inc. A large portion of the proved undeveloped crude
oil reserves are associated with the Permian Basin formation.
Although these hydrocarbon quantities have been determined in
accordance with industry standards, they are prepared using the
subjective judgments of the independent engineers and may actually
be more or less.
Oil and Natural Gas Sales Volumes
During the year ended December 31, 2020, our net
crude oil, natural gas, and NGLs sales volumes decreased to 252,807
Bbls or 691 Bopd from 266,070 Bbls, or 729 Bopd, a 5% decrease over
the previous fiscal year. The production decrease is primarily
related to the Company
shutting-in all of its operated
producing wells in its Permian Basin Asset and D-J Basin Asset in
late April 2020, as a result of the COVID-19 outbreak, and the
sharp decline in oil prices which occurred partially as a result of
the decreased demand for oil caused by such outbreak. In early June
2020, as prices began to partially recover, we opened up production
for 90% of our previously producing operated wells. In total, we
shut-in all our operated wells for a period of 42 days during the
months of April through June 2020.
Significant Capital Expenditures
The
table below sets out the significant components of capital
expenditures for the year ended December 31, 2020 (in
thousands):
|
Capital
Expenditures
|
|
|
Leasehold
Acquisitions
|
$
157
|
|
Drilling
and Facilities
|
5,786
|
|
Total*
|
$
5,943
|
*(see
“
Item 8. Financial
Statements and Supplementary Data
” -
“
Note 6 - Oil and Gas
Properties
”).
Market Conditions and Commodity Prices
Our
financial results depend on many factors, particularly the price of
crude oil and natural gas and our ability to market our production
on economically attractive terms. Commodity prices are affected by
many factors outside of our control, including changes in market
supply and demand, which are impacted by weather conditions,
inventory storage levels, basis differentials and other factors. As
a result, we cannot accurately predict future commodity prices and,
therefore, we cannot determine with any degree of certainty what
effect increases or decreases in these prices will have on our
production volumes or revenues. In addition to production volumes
and commodity prices, finding and developing sufficient amounts of
crude oil and natural gas reserves at economical costs are critical
to our long-term success. We expect prices to remain volatile for
the remainder of the year. For information about the impact of
realized commodity prices on our crude oil and natural gas and
condensate revenues, refer to “
Results of Operations
”
below.
Results of Operations
The following discussion and analysis of the
results of operations for each of the two fiscal years in the years
ended December 31, 2020 and 2019 should be read in conjunction with
the consolidated financial statements of PEDEVCO Corp. and notes
thereto included herein (see “
Item 8. Financial
Statements and Supplementary Data
”).
We
reported a net loss for the year ended December 31, 2020 of $32.7
million, or ($0.45) per share, compared to a net loss for the
year ended December 31, 2019 of $11.1 million or ($0.22) per share.
The increase in net loss of $21.6 million was primarily due to a
$19.3 million impairment of our oil and gas properties located in
our D-J Basin Asset. Excluding this significant transaction, our
net loss increased by $2.3 million, due to a reduction in revenue
of $4.9 million, when comparing the current period to the prior
period as a result of the COVID-19 outbreak, and the sharp decline
in oil prices which occurred partially as a result of the decreased
demand for oil caused by such outbreak, offset by a reduction of
$1.7 million in operating expenses and by $2.0 million in other
income items related to less interest on debt coupled with accounts
receivable and payable settlements.
65
Net Revenues
The
following table sets forth the revenue and
production data for the years ended December 31, 2020 and
2019:
|
|
|
|
%
|
|
|
|
2020
|
2019
|
Increase
(Decrease)
|
Increase
(Decrease)
|
|
Sale Volumes:
|
|
|
|
|
|
Crude
Oil (Bbls)
|
204,983
|
234,378
|
(29,395
)
|
(13
%)
|
|
Natural
Gas (Mcf)
|
191,337
|
153,251
|
38,086
|
25
%
|
|
NGL
(Bbls)
|
15,934
|
6,150
|
9,784
|
159
%
|
|
Total
(Boe) (1)
|
252,807
|
266,070
|
(13,263
)
|
(5
%)
|
|
|
|
|
|
|
|
Crude
Oil (Bbls per day)
|
560
|
642
|
(82
)
|
(13
%)
|
|
Natural
Gas (Mcf per day)
|
523
|
420
|
103
|
25
%
|
|
NGL
(Bbls per day)
|
44
|
17
|
27
|
159
%
|
|
Total
(Boe per day) (1)
|
691
|
729
|
(38
)
|
(5
%)
|
|
|
|
|
|
|
|
Average Sale Price:
|
|
|
|
|
|
Crude
Oil ($/Bbl)
|
$
36,83
|
$
53.41
|
$
(16.58
)
|
(31
%)
|
|
Natural
Gas($/Mcf)
|
1.72
|
2.43
|
(0.71
)
|
(29
%)
|
|
NGL
($/Bbl)
|
11.20
|
13.28
|
(2.08
)
|
(16
%)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Operating Revenues (In thousands):
|
|
|
|
|
|
Crude
Oil
|
$
7,551
|
$
12,518
|
$
(4,967
)
|
(40
%)
|
|
Natural
Gas
|
330
|
372
|
(42
)
|
(11
%)
|
|
NGL
|
178
|
82
|
96
|
117
%
|
|
Total Revenues
|
$
8,059
|
$
12,972
|
$
(4,913
)
|
(38
%)
|
|
(1)
|
Assumes
6 Mcf of natural gas equivalents to 1 barrel of oil.
|
Total crude oil and natural gas revenues for the
year ended December 31, 2020 decreased $4.9 million, or 38%, to
$8.1 million, compared to $13.0 million for the same period a year
ago due
primarily to an unfavorable price variance of $4.0
million, coupled with an unfavorable volume variance of $0.9
million. Although we shut-in all of our operated wells for 42 days
during the second quarter of 2020, as a result of the severe
reduction in pricing from the decreased demand in oil and
gas-related to the COVID-19 outbreak, production amounts declined
by a nominal 5% overall in the current period compared to the prior
period, primarily from five new productive wells brought online
during the latter part of the 2019 fiscal year, combined with the
four new productive wells brought online in the 2020 fiscal year in
our Permian Basin Asset, as well as our participation (non-operated
working interest) in the drilling and completion of 11 productive
wells in our D-J Basin Asset, which occurred in the latter part of
the 2019 fiscal year and which were realized in the 2020
period.
66
Net Operating and Other (Income) Expenses
The
following table sets forth operating and other expenses
for the years ended December 31, 2020 and 2019 (In
thousands):
|
|
2020
|
2019
|
Increase (Decrease)
|
% Increase (Decrease)
|
|
|
|
|
|
|
|
Direct
Lease Operating Expense
|
$
3,310
|
$
4,077
|
$
(767
)
|
(19
%)
|
|
Workovers
|
187
|
1,421
|
(1,234
)
|
(87
%)
|
|
Other*
|
957
|
1,319
|
(362
)
|
(27
%)
|
|
Loss
(gain) on settlement of ARO
|
(19
)
|
496
|
(515
)
|
(104
%)
|
|
Lease
Operating Expenses
|
4,435
|
7,313
|
(2,878
)
|
(39
%)
|
|
|
|
|
|
|
|
Exploration
Expenses
|
31
|
110
|
(79
)
|
(72
%)
|
|
Depreciation,
Depletion,
|
|
|
|
|
|
Amortization
and Accretion
|
11,343
|
11,031
|
312
|
3
%
|
|
Impairment
of Oil and Gas Properties
|
19,331
|
-
|
19,331
|
100
%
|
|
|
|
|
|
|
|
General
and Administrative (Cash)
|
$
3,917
|
$
4,228
|
$
(311
)
|
(7
%)
|
|
Share-Based
Compensation (Non-Cash)
|
2,824
|
1,557
|
1,267
|
81
%
|
|
Total
General and Administrative Expense
|
$
6,741
|
$
5,785
|
$
956
|
17
%
|
|
|
|
|
|
|
|
Gain
on Sale of Oil and Gas Properties
|
-
|
1,040
|
(1,040
)
|
(100
%)
|
|
|
|
|
|
|
|
Interest
Expense
|
$
2
|
$
824
|
$
(822
)
|
(100
%)
|
|
Interest
Income
|
$
40
|
$
55
|
$
(15
)
|
(27
%)
|
|
Other
Income (Expense)
|
$
1,094
|
$
(106
)
|
$
1,200
|
(1,132
%)
|
*Includes severance, ad valorem taxes and marketing
costs.
Lease Operating
Expenses.
The decrease of $2.9 million was due to the
shut-in of all of our operated wells for 42 days during the 2020
period related to the severe reduction in pricing from the
decreased demand related to the COVID-19 outbreak. Additionally,
direct operating lease expenses decreased relative to the overall
production increase due to the existing infrastructure and tank
batteries already in place for the recently completed wells in our
Permian Basin Asset. Additional workover activities were also down
during the 2020 period due to the economic downturn, and the
decision by management to hold off on such workover activities
until prices recovered.
When comparing
periods, the Company also incurred a $0.5 million loss on the
plugging and abandonment of seven wells located in our Permian
Asset during the 2019 period. The Company also experienced
unforeseen fishing and cleanout costs, in addition to a lack of
available service providers, which resulted in additional premium
charges during the 2019 period.
Exploration
Expense.
There was a
nominal change in exploration expenses for 2020 compared to 2019,
as there was a minimal increase in exploration activity undertaken
by the Company in the current year’s period compared to the
prior year’s period.
Depreciation, Depletion,
Amortization and Accretion.
The $0.3 million increase was
primarily the result of year-end reserve adjustments offset by an
overall production decrease for the current year’s period, as
noted above, when compared to the prior year’s
period.
Impairment of Oil and Gas Properties
.
For the year ended December 31, 2020, impairment of oil and gas
properties was $19,331,000, compared to $-0- for the year ended
December 31, 2019. The impairment in 2020 resulted from a reduction
of our reserve value for our D-J Basin assets relative to the
carrying amount of our D-J Basin assets, which was strictly
commodity price driven as our total reserves were 14.1 MMBoe and
14.0 MMBoe for 2020 and 2019, respectively, while
our estimated discounted future net cash flow
("
PV-10
") before tax
expenses for our proved reserves was approximately $58.2 million
and $122.7 million for 2020 and 2019, respectively, representing
52.5% decrease when comparing the current year to the prior
year.
67
General and Administrative
Expenses (excluding share-based compensation).
The decrease
of $0.3 million in general and administrative expenses (excluding
share-based compensation) was primarily due to an $0.8 million
decrease, as well as other cost decreases, in the 2020 period,
resulting from a 20% reduction in salary for all of the
Company’s salaried employees and officers implemented on
April 1, 2020, and a reduction of non-essential contractors, offset
by $0.5 million in costs related to the terminated SandRidge
Permian Trust Offer to Exchange (see “Part 1” —
“
Item 1. Business
– 2020 Material Events
”).
Share-Based
Compensation.
Share-based
compensation, which is included in general and administrative
expenses in the Statements of Operations, increased by $1.3
million, primarily due to an increase in the awarding of employee
share-based options and restricted shares as compensation during
the 2020 period. Share-based compensation is utilized
to
conserve cash resources for use in field development activities and
operations.
Gain on Sale of Oil and Gas
Properties.
In
the 2019 period, the Company sold rights to 85.5 net acres and
acquired 121 net acres of oil and gas leases located in Weld
County, Colorado, to a third party, for aggregate proceeds of $1.2
million and recognized a gain on sale of oil and gas properties of
$1.0 million. No similar transaction occurred in the 2020
period.
Interest Expense.
The decrease of $0.8 million was
due primarily to the Company having no significant debt in the
current period, compared to 2019 year’s period. The Company
recognized $2,000 in interest related to our PPP Loan in the 2020
period.
Interest Income and Other Expense.
Includes interest earned from our interest-bearing cash accounts,
and for the 2020 period includes the settlement of accounts
payables for $0.9 million and the settlement of $0.1 million of
accounts receivable, compared to the prior period, which included
the write-off of a $0.1 million third party option related to an
option to acquire shares of Caspian Energy, which expired
unexercised.
Liquidity and Capital Resources
The
primary sources of cash for the Company during the year ended
December 31, 2020, were from the sales of crude oil and natural gas
and funds provided by our entry into a PPP loan (see
“
Part I - Financial
Information
” - “
Item 1. Financial
Statements
” - “
Note 7 – PPP
Loan
”). The primary uses of cash were funds used for
development costs and operations. To help conserve its operating
cash, effective April 1, 2020, the Company implemented a 20%
reduction in salary for all of the Company’s salaried
employees and officers, to continue until the oil markets have
recovered to acceptable levels, which the Company has determined
has not occurred to date.
Impact of COVID-19
In
December 2019, a novel strain of coronavirus, which causes the
infectious disease known as COVID-19, was reported in Wuhan, China.
The World Health Organization declared COVID-19 a “Public
Health Emergency of International Concern” on January 30,
2020, and a global pandemic on March 11, 2020. COVID-19 has, since
the early part of 2020, reduced worldwide economic activity. Due to
COVID-19, the Company or its employees, suppliers, and other
partners may be prevented from conducting business activities at
full capacity for an indefinite period of time, including due to
the spread of the disease within these groups or due to shutdowns
that may be requested or mandated by governmental authorities.
While it is not possible at this time to estimate the full impact
that COVID-19 will have on the Company’s business, the
continued spread of COVID-19 and the measures taken by the
governments of countries affected and in which the Company operates
have disrupted, and may continue to disrupt, the operation of the
Company’s business for a prolonged period. The COVID-19
outbreak and mitigation measures have also had an adverse impact on
global economic conditions, as well as an adverse effect on the
Company’s business and financial condition and may continue
to have an adverse effect on the Company, including on its
potential to conduct financings on terms acceptable to the Company,
if at all. In addition, the Company has taken temporary
precautionary measures intended to help minimize the risk of the
virus to its employees, vendors, and guests, including limiting the
number of occupants at the Company’s Houston headquarters and
requiring all others to work remotely, and discouraging employee
attendance at in-person work-related meetings, which could
negatively affect the Company’s business. The extent to which
the COVID-19 outbreak will continue to impact the Company’s
results will depend on future developments that are highly
uncertain and cannot be predicted, including new information that
may emerge concerning the severity of the virus, the availability
and efficacy of vaccines, the ability of the general public to
obtain such vaccines and the willingness of individuals to be
vaccinated, and the actions to contain its impact. However, any
further decrease in the price of oil, or the demand for oil and
gas, will likely have a negative impact on our results of
operations and cash flows.
68
As discussed above, we shut-in our operated
production from mid-April through early June 2020, which directly
contributed to a decrease in production volumes from 96,515 Boe for
the three months ended March 31, 2020, to 46,530 Boe for the three
months ended June 30, 2020, representing a decrease of 52%.
Similarly, our crude oil, natural gas, and NGLs sales revenues
decreased from $2,832,000 for the three months ended March 31,
2020, to $656,000 for the three months ended June 30, 2020,
representing a decrease of 77%, largely due to our decreased
production, as well as decreases in NYMEX pricing and significantly
widened differentials, largely due to the global COVID-19 pandemic,
and the sharp decline in the demand for, and price of, oil and gas,
in connection therewith. For the year ended December 31, 2020, our
production totaled 252,807 Boe which was only a 5% decrease from
the prior period year end of 266,070 Boe. We were able to maintain
similar production numbers due to three operated wells being
completed and brought online in our Permian Basin Asset, with a
fourth well brought online in the Permian Basin Asset in the latter
part of 2020. However, due to
the significant price decline
in early 2020, our sales revenues of $8,059,000 for the 2020 period
were not able to match our pre-COVID-19 fiscal year 2019 sales
revenues of $12,972,000.
In
response to the effects of COVID-19, the Company has adopted
policies, procedures, and practices both in its Houston office
headquarters and across its field operations to protect its
employees, contractors, and guests from COVID-19, including the
adoption of a COVID-19 Response Plan, implementation of contractor
questionnaires to assess COVID-19 risk and exposure prior to
entering any Company facility or worksite, adopting best practices,
guidelines and protocols recommended by the Centers for Disease
Control (the “
CDC
”) and the Office of
the Texas Governor for the prevention of exposure and spread of
COVID-19, and instituting weekly management calls discussing the
Company’s ongoing response to the COVID-19 pandemic and
effectiveness thereof. Given the Company’s robust online
systems and workflow practices and procedures, the Company has not
experienced any material challenges or reductions in efficiency or
effectiveness of its office-based workforce, while its field
personnel continues to attend to their daily field operations
uninterrupted, while mindful of social distancing and other
preventative measures and safeguards recommended by the
CDC.
Further, to help conserve its operating cash, in
April 2020 the Company initiated significant G&A cost-reduction
measures, including reducing all employee and officer salaries by
20%, until market conditions significantly improve, cutting all
discretionary spending, undertaking additional actions resulting in
a nearly 20% cash G&A reduction in the second and third
quarters of 2020, from our original G&A budget, and negotiating
reductions of approximately $1 million in vendor accounts payable.
Additionally, the Company implemented cost-reduction measures that
reduced lease operating expenses (“
LOE
”) by over 35% in
2020.
We plan to continue to
closely monitor the global energy markets and oil and gas pricing,
with our
2021 development plan
being subject to revision, if and as necessary, to react to market
conditions in the best interest of its shareholders, while
prioritizing its financial strength and
liquidity.
Working Capital
At
December 31, 2020, the Company’s total current assets of $8.8
million exceeded its total current liabilities of $2.0 million,
resulting in a working capital surplus of $6.8 million, while at
December 31, 2019, the Company’s total current assets of
$27.1 million exceeded its total current liabilities of $15.2
million, resulting in a working capital surplus of $11.9 million.
The $5.1 million decrease in our working capital surplus is
primarily related to cash used to fund payables and accrued
expenses related to the completion of our capital drilling projects
and current operational expenses. Notwithstanding such decrease in
working capital, as discussed below, in February 2021, we raised
$8.3 million of cash pursuant to an underwritten offering of common
stock.
Financing
Other than obtaining the $370,000 PPP loan and
repayment of the Original PPP loan (
see “
Item 8. Financial Statements and
Supplementary Data
” - “
Note 7 – PPP
Loan
”)
, we did not engage
in any financing transactions during the year ended December 31,
2020. However, on February 5, 2021, we closed an underwritten
public offering of 5,968,500 shares of common stock at a public
offering price of $1.50 per share, which included the full exercise
of the underwriter’s over-allotment option, for net proceeds
(after deducting the underwriters’ discount equal to 6% of
the public offering price and expenses associated with the
offering) of approximately $8.3 million.
69
We expect that we will have sufficient cash
available to meet our needs over the foreseeable future, which cash
we anticipate being available from (i) projected cash flow from our
operations, (ii) existing cash on hand, (iii) equity infusions or
loans (which may be convertible) made available from SK Energy
LLC
(“
SK
Energy
”)
, which is 100%
owned and controlled by Simon Kukes, our Chief Executive Officer
and director, which funding SK Energy is under no obligation to
provide, (iv) public or private debt or equity financings, and (v)
funding through credit or loan facilities. In addition, we may seek
additional funding through asset sales, farm-out arrangements, and
credit facilities to fund potential acquisitions in 2021. If market
conditions are not conducive to developing our assets consistent
with our 2021 development program, the Company may choose to delay
or extend the drilling program and associated capital expenditures
into the future. Furthermore, as a result of the COVID-19
outbreak, and the sharp decline in oil prices which occurred
partially as a result of the decreased demand for oil caused by
such outbreak and the actions taken globally to stop the spread of
such virus, in mid-April 2020, the Company shut-in all of its
operated producing wells in its Permian Basin Asset and D-J Basin
Asset to preserve the Company’s oil and gas reserves for
production during a more favorable oil price environment, with the
Company now back on full production from its operated wells in the
Permian Basin and the D-J Basin that the Company had shut-in in
mid-April 2020 due to the partial recovery of oil prices in early
June 2020. If oil prices deteriorate significantly from
current levels, the Company expects to again shut-in some or all of
its oil and gas production, which would result in reduced or no
cash flow being generated from operations during the period such
wells are shut-in, have a material adverse effect on the
Company’s projected cash flow from operations, and, once our
cash on hand is depleted, eventually require additional infusions
of capital through debt and/or equity financings, asset sales,
farm-out arrangements, lines of credit, or other means, which may
not be available on favorable terms, if at all.
Cash Flows (in thousands)
|
|
Year Ended December 31,
|
|
|
|
2020
|
2019
|
|
Cash
flows provided by operating activities
|
$
12
|
$
1,669
|
|
Cash
flows used in investing activities
|
(14,770
)
|
(39,736
)
|
|
Cash
flows provided by financing activities
|
370
|
58,000
|
|
Net (decrease) increase in cash and restricted cash
|
$
(14,388
)
|
$
19,933
|
Cash Flows provided by (used in) Operating
Activities.
Net cash provided by operating
activities decreased by $1.7 million for the current year, when
compared to the prior year, primarily due to a decrease in our net
loss of $2.3 million, which was primarily commodity price-driven,
and when not factoring in our $19.3 million impairment of our oil
and gas properties, coupled with net increases to certain of our
other components of working capital of $1.9 million, offset by net
decreases in operating activities of $2.5 million.
Cash Flows used in Investing
Activities.
There was a decrease in net cash used in
investing activities of $25.0 million due to a reduction in capital
spending related to drilling and completion costs when comparing
the 2020 period to the 2019 period, mainly due to reductions and
delays in spending associated with the decline in oil prices caused
by COVID-19.
Cash Flows provided by Financing
Activities.
There was $0.4 million in net cash flows
provided by obtaining PPP Loan financing in the 2020 period,
compared to $58.0 million in proceeds from financing in the 2019
period from the issuance of a related party note payable, which has
since been converted to common stock, and the sale of common
stock.
Off-Balance Sheet Arrangements
The
Company does not participate in financial transactions that
generate relationships with unconsolidated entities or financial
partnerships. As of December 31, 2020, we did not have any
off-balance sheet arrangements.
70
Critical Accounting Policies
Our
discussion and analysis of our financial condition and results of
operations is based on our financial statements, which have been
prepared in accordance with accounting principles generally
accepted in the United States. The preparation of these financial
statements requires us to make estimates and judgments that affect
the reported amounts of assets, liabilities, revenues and expenses.
We base our estimates on historical experience and on various other
assumptions that we believe to be reasonable under the
circumstances, the results of which form the basis for making
judgments about the carrying values of assets and liabilities that
are not readily apparent from other sources. Actual results may
differ from these estimates under different assumptions or
conditions. We believe the following critical accounting policies
affect our most significant judgments and estimates used in
preparation of our financial statements.
Oil and Gas Properties, Successful Efforts
Method.
The successful efforts method of accounting is
used for oil and gas exploration and production activities. Under
this method, all costs for development wells, support equipment and
facilities, and proved mineral interests in oil and gas properties
are capitalized. Geological and geophysical costs are expensed when
incurred. Costs of exploratory wells are capitalized as exploration
and evaluation assets pending determination of whether the wells
find proved oil and gas reserves. Proved oil and gas reserves are
the estimated quantities of crude oil and natural gas which
geological and engineering data demonstrate with reasonable
certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions, (i.e., prices and
costs as of the date the estimate is made). Prices include
consideration of changes in existing prices provided only by
contractual arrangements, but not on escalations based upon future
conditions.
Exploratory wells
in areas not requiring major capital expenditures are evaluated for
economic viability within one year of completion of drilling. The
related well costs are expensed as dry holes if it is determined
that such economic viability is not attained. Otherwise, the
related well costs are reclassified to oil and gas properties and
subject to impairment review. For exploratory wells that are found
to have economically viable reserves in areas where major capital
expenditure will be required before production can commence, the
related well costs remain capitalized only if additional drilling
is under way or firmly planned. Otherwise, the related well costs
are expensed as dry holes.
Exploration and
evaluation expenditures incurred subsequent to the acquisition of
an exploration asset in a business combination are accounted for in
accordance with the policy outlined above.
Depreciation,
depletion and amortization of capitalized oil and gas properties is
calculated on a field-by-field basis using the unit of production
method. Lease acquisition costs are amortized over the total
estimated proved developed and undeveloped reserves and all other
capitalized costs are amortized over proved developed reserves.
Costs specific to developmental
wells
for which drilling is in progress or uncompleted
are
capitalized as wells in progress and not subject to amortization
until completion and production commences, at which time
amortization on the basis of production will begin.
Revenue
Recognition.
The
Company’s revenue is comprised entirely of revenue from
exploration and production activities. The Company’s oil is
sold primarily to marketers, gatherers, and refiners. Natural gas
is sold primarily to interstate and intrastate natural-gas
pipelines, direct end-users, industrial users, local distribution
companies, and natural-gas marketers. NGLs are sold primarily to
direct end-users, refiners, and marketers. Payment is generally
received from the customer in the month following
delivery.
Contracts with
customers have varying terms, including month-to-month contracts,
and contracts with a finite term. The Company recognizes sales
revenues for oil, natural gas, and NGLs based on the amount of each
product sold to a customer when control transfers to the customer.
Generally, control transfers at the time of delivery to the
customer at a pipeline interconnect, the tailgate of a processing
facility, or as a tanker lifting is completed. Revenue is measured
based on the contract price, which may be index-based or fixed, and
may include adjustments for market differentials and downstream
costs incurred by the customer, including gathering,
transportation, and fuel costs.
Revenues are
recognized for the sale of the Company’s net share of
production volumes. Sales on behalf of other working interest
owners and royalty interest owners are not recognized as
revenues.
71
Stock-Based Compensation.
Pursuant
to the provisions of Financial Accounting Standards Board
(“
FASB
”) Accounting
Standards Codification (“
ASC
”) 718,
Compensation – Stock Compensation, which establishes
accounting for equity instruments exchanged for employee service,
we utilize the Black-Scholes option pricing model to estimate the
fair value of employee stock option awards at the date of grant,
which requires the input of highly subjective assumptions,
including expected volatility and expected life. Changes in these
inputs and assumptions can materially affect the measure of
estimated fair value of our share-based compensation. These
assumptions are subjective and generally require significant
analysis and judgment to develop. When estimating fair value, some
of the assumptions will be based on, or determined from, external
data and other assumptions may be derived from our historical
experience with stock-based payment arrangements. The appropriate
weight to place on historical experience is a matter of judgment,
based on relevant facts and circumstances. We estimate volatility
by considering historical stock volatility. We have opted to use
the simplified method for estimating expected term, which is equal
to the midpoint between the vesting period and the contractual
term.
Recently Adopted Accounting
Pronouncements.
Refer to Note 3 of the Notes to the
Consolidated Financial Statements, “Summary of Significant
Accounting Policies,” for a discussion of recently adopted
accounting pronouncements.
ITEM 7A.
Q
UANTITATIVE AND QUALITATIVE
DISCLOSURE ABOUT MARKET RISK.
Not
required under Regulation S-K for “
smaller reporting
companies.
”
72
INDEX TO FINANCIAL STATEMENTS
|
Audited Financial Statements for Years Ended December 31, 2020 and
2019
|
|
|
|
|
|
PEDEVCO Corp.:
|
|
|
74
|
|
|
76
|
|
|
77
|
|
|
78
|
|
|
79
|
|
|
80
|
73
R
EPORT OF INDEPENDENT REGISTERED
PUBLIC ACCOUNTING FIRM
To the
Shareholders and the Board of Directors of
PEDEVCO
Corp.
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of
PEDEVCO Corp. (the “Company”) as of December 31,
2020 and 2019, the related consolidated statements of operations,
shareholders’ equity and cash flows for each of the years
ended December 31, 2020 and 2019, and the related notes
(collectively referred to as the “financial
statements”). In our opinion, the financial statements
present fairly, in all material respects, the financial position of
the Company as of December 31, 2020 and 2019, and the results of
its operations and its cash flows for each of the years ended
December 31, 2020 and 2019, in conformity with accounting
principles generally accepted in the United States of
America.
Basis for Opinion
These
financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on the
Company's financial statements based on our audit
s
. We are a public accounting firm
registered with the Public Company Accounting Oversight Board
(United States) ("PCAOB") and are required to be independent with
respect to the Company in accordance with the U.S. federal
securities laws and the applicable rules and regulations of the
Securities and Exchange Commission and the PCAOB.
We
conducted our audit
s
in
accordance with the standards of the PCAOB. Those standards require
that we plan and perform the audit
s
to obtain reasonable assurance about
whether the financial statements are free of material misstatement,
whether due to error or fraud. The Company is not required to have,
nor were we engaged to perform, an audit of its internal control
over financial reporting. As part of our audit
s
we are required to obtain an
understanding of internal control over financial reporting but not
for the purpose of expressing an opinion on the effectiveness of
the Company's internal control over financial reporting.
Accordingly, we express no such opinion.
Our
audit
s
included performing
procedures to assess the risks of material misstatement of the
financial statements, whether due to error or fraud, and performing
procedures that respond to those risks. Such procedures included
examining, on a test basis, evidence regarding the amounts and
disclosures in the financial statements. Our audit
s
also included evaluating the
accounting principles used and significant estimates made by
management, as well as evaluating the overall presentation of the
financial statements. We believe that our audit
s
provide a reasonable basis for our
opinion.
Critical Audit Matters
The
critical audit matters communicated below are matters arising from
the current period audit of the financial statements that were
communicated or required to be communicated to the audit committee
and that: (1) relate to accounts or disclosures that are material
to the financial statements and (2) involved our especially
challenging, subjective, or complex judgments. The communication of
critical audit matters does not alter in any way our opinion on the
financial statements, taken as a whole, and we are not, by
communicating the critical audit matters below, providing separate
opinions on the critical audit matters or on the accounts or
disclosures to which they relate.
Depreciation, depletion and amortization and impairment of oil and
gas properties
At
December 31, 2020, the net carrying value of the Company’s
oil and gas properties was $66,998 thousand, and depreciation,
depletion and amortization (“DD&A”) expense was
$11,054 thousand, and impairment expense was $19,331 thousand for
the year then ended. As described in Note 3, the Company follows
the successful efforts method of accounting for its oil and gas
properties. DD&A of the cost of proved oil and gas properties
is calculated using the unit-of-production method based on proved
oil and gas reserves, as estimated by the Company’s internal
reservoir engineers. When circumstances indicate that the carrying
value of property and equipment may not be recoverable, the Company
compares unamortized capitalized costs to the expected undiscounted
pre-tax future cash flows for the associated assets. If the
expected undiscounted pre-tax future cash flows are lower than the
unamortized capitalized cost, the capitalized cost is reduced to
fair value.
74
Proved
oil and gas reserves are those quantities of natural gas, crude
oil, condensate, and natural gas liquids, which by analysis of
geoscience and engineering data, can be estimated with reasonable
certainty to be economically producible from a given date forward,
from known reservoirs, and under existing economic conditions,
operating methods, and government regulations. Additionally, the
expected future cash flows used for impairment reviews and related
fair value calculations are based on judgmental assessments of
future production volumes from estimated oil and gas reserves.
Significant judgment is required by the Company’s internal
and external reservoir engineers in evaluating geological and
engineering data when estimating oil and gas reserves. Estimating
reserves also requires the selection of inputs, including oil and
gas price assumptions, future operating and capital costs
assumptions, and tax rates by jurisdiction, among others. Because
of the complexity involved in estimating oil and gas reserves,
management engaged independent petroleum engineers to prepare the
proved oil and gas reserve estimates for select properties as of
December 31, 2020.
Auditing
the Company’s DD&A and impairment calculations is complex
because of the use of the work of the internal reservoir engineers
and the independent petroleum engineers and the evaluation of
management’s determination of the inputs described above used
by the engineers in estimating oil and gas reserves.
We
obtained an understanding of the Company’s controls over its
process to calculate DD&A and impairment, including
management’s controls over the completeness and accuracy of
the financial data provided to the engineers for use in estimating
oil and gas reserves.
Our
audit procedures included, among others, evaluating the
professional qualifications and objectivity of the independent
petroleum engineers primarily responsible for the preparation of
the reserve estimates for select properties. In addition, in
assessing whether we can use the work of the engineers, we
evaluated the completeness and accuracy of the financial data and
inputs described above used by the engineers in estimating oil and
gas reserves by agreeing them to source documentation, and we
identified and evaluated corroborative and contrary evidence. For
proved undeveloped reserves, we evaluated management’s
development plan for compliance with the SEC rule that undrilled
locations are scheduled to be drilled within five years, unless
specific circumstances justify a longer time, by assessing
consistency of the development projections with the Company’s
development plan and the availability of capital relative to the
development plan. We also tested the mathematical accuracy of the
DD&A and impairment calculations, including comparing the oil
and gas reserve amounts used in the calculations to the
Company’s reserve reports.
/s/
Marcum
llp
Marcum
llp
We have
served as the Company's auditor since 2008.
Houston,
Texas
March
22, 2021
75
PEDEVCO CORP.
CONSOLIDATED
B
ALANCE SHEETS
(amounts
in thousands, except share and per share data)
|
|
December 31,
|
|
|
|
2020
|
2019
|
|
Assets
|
|
|
|
Current
assets:
|
|
|
|
Cash
|
$
8,027
|
$
22,415
|
|
Accounts
receivable – oil and gas
|
660
|
4,602
|
|
Prepaid
expenses and other current assets
|
66
|
73
|
|
Total
current assets
|
8,753
|
27,090
|
|
|
|
|
|
Oil
and gas properties:
|
|
|
|
Oil
and gas properties, subject to amortization, net
|
69,994
|
76,952
|
|
Oil
and gas properties, not subject to amortization, net
|
4
|
14,896
|
|
Total
oil and gas properties, net
|
66,998
|
91,848
|
|
|
|
|
|
Operating
lease – right-of-use asset
|
270
|
360
|
|
Other
assets
|
3,543
|
3,598
|
|
Total
assets
|
$
79,564
|
$
122,896
|
|
|
|
|
|
Liabilities and Shareholders’ Equity
|
|
|
|
Current
liabilities:
|
|
|
|
Accounts
payable
|
$
212
|
$
12,099
|
|
Accrued
expenses
|
303
|
1,972
|
|
Revenue
payable
|
836
|
827
|
|
PPP
loan - current
|
288
|
-
|
|
Operating
lease liabilities – current
|
105
|
97
|
|
Asset
retirement obligations – current
|
234
|
225
|
|
Total
current liabilities
|
1,978
|
15,220
|
|
|
|
|
|
Long-term
liabilities:
|
|
|
|
PPP
loan-net of current portion
|
82
|
-
|
|
Operating
lease liabilities, net of current portion
|
195
|
300
|
|
Asset
retirement obligations, net of current portion
|
1,673
|
1,874
|
|
Total
liabilities
|
3,928
|
15,220
|
|
|
|
|
|
Commitments
and contingencies
|
|
|
|
|
|
|
|
Shareholders’
equity:
|
|
|
|
Common
stock, $0.001 par value, 200,000,000 shares authorized; 72,463,340
and 71,061,328 shares issued and outstanding,
respectively
|
72
|
71
|
|
Additional
paid-in capital
|
203,850
|
201,027
|
|
Accumulated
deficit
|
(128,286
)
|
(95,596
)
|
|
Total
shareholders’ equity
|
75,636
|
105,502
|
|
Total
liabilities and shareholders’ equity
|
$
79,564
|
$
122,896
|
See
accompanying notes to consolidated financial
statements.
76
PEDEVCO CORP.
CONSOLIDATED STATEMENTS OF
O
PERATIONS
(amounts
in thousands, except share and per share data)
|
|
December 31,
|
|
|
Revenue:
|
2020
|
2019
|
|
Oil
and gas sales
|
$
8,059
|
$
12,972
|
|
|
|
|
|
Operating
expenses:
|
|
|
|
Lease
operating costs
|
4,435
|
6,817
|
|
Exploration
expense
|
31
|
110
|
|
Selling,
general and administrative expense
|
6,741
|
5,785
|
|
Depreciation,
depletion, amortization and accretion
|
11,343
|
11,031
|
|
Loss
on settlement of asset retirement obligations
|
-
|
496
|
|
Impairment
of oil and gas properties
|
19,331
|
-
|
|
Total
operating expenses
|
41,881
|
24,239
|
|
|
|
|
|
Gain
on sale of oil and gas properties
|
-
|
1,040
|
|
Operating
loss
|
(33,822
)
|
(10,227
)
|
|
|
|
|
|
Other
income (expense):
|
|
|
|
Interest
expense
|
(2
)
|
(824
)
|
|
Interest
income
|
40
|
55
|
|
Other
income (expense)
|
1,094
|
(106
)
|
|
Total
other income (expense)
|
1,132
|
(875
)
|
|
|
|
|
|
Net
loss
|
$
(32,690
)
|
$
(11,102
)
|
|
|
|
|
|
Loss per
common share:
|
|
|
|
Basic
|
$
(0.45
)
|
$
(0.22
)
|
|
Diluted
|
$
(0.45
)
|
$
(0.22
)
|
|
|
|
|
|
Weighted
average number of common shares outstanding:
|
|
|
|
Basic
|
72,209,553
|
51,214,986
|
|
Diluted
|
72,209,553
|
51,214,986
|
See
accompanying notes to consolidated financial
statements.
77
PEDEVCO CORP.
CONSOLIDATED STATEMENTS OF
C
ASH
FLOWS
(amounts
in thousands)
|
|
December 31,
|
|
|
|
2020
|
2019
|
|
Cash
Flows From Operating Activities:
|
|
|
|
Net
loss
|
$
(32,690
)
|
$
(11,102
)
|
|
Adjustments
to reconcile net loss to net cash provided by operating
activities:
|
|
|
|
Depreciation,
depletion and amortization
|
11,343
|
11,031
|
|
Impairment
of oil and gas properties
|
19,331
|
-
|
|
Share-based
compensation expense
|
2,824
|
1,557
|
|
Loss
on disposal of fixed asset
|
24
|
-
|
|
Gain
on sale of oil and gas properties
|
-
|
(1,040
)
|
|
Amortization
of debt discount
|
-
|
161
|
|
Amortization
of right-of-use asset
|
90
|
37
|
|
Changes
in operating assets and liabilities:
|
|
|
|
Accounts
receivable – oil and gas
|
3,942
|
(3,760
)
|
|
Prepaid
expenses and other current assets
|
7
|
131
|
|
Accounts
payable
|
(3,199
)
|
5,414
|
|
Accrued
expenses
|
(1,669
)
|
(1,413
)
|
|
Accrued
expenses – related parties
|
-
|
1,175
|
|
Revenue
payable
|
9
|
(10
)
|
|
Net
cash provided by operating activities
|
12
|
1,669
|
|
|
|
|
|
Cash
Flows From Investing Activities:
|
|
|
|
Cash
paid for the acquisition of oil and gas properties
|
-
|
(1,120
)
|
|
Cash
paid for drilling and completion costs
|
(14,770
)
|
(39,700
)
|
|
Cash
paid for other property and equipment
|
-
|
(81
)
|
|
Proceeds
from the sale of oil and gas property
|
-
|
1,175
|
|
Cash
paid for security deposit
|
-
|
(10
)
|
|
Net
cash used in investing activities
|
(14,770
)
|
(39,736
)
|
|
|
|
|
|
Cash
Flows From Financing Activities:
|
|
|
|
Proceeds
from PPP loans
|
740
|
-
|
|
Repayment
of PPP loan
|
(370
)
|
-
|
|
Proceeds
from notes payable – related parties
|
-
|
15,000
|
|
Proceeds
from the issuance of common stock
|
-
|
43,000
|
|
Net
cash provided by financing activities
|
370
|
58,000
|
|
|
|
|
|
|
|
|
|
Net
(decrease) increase in cash and restricted cash
|
(14,388
)
|
19,933
|
|
Cash
and restricted cash at beginning of year
|
25,712
|
5,779
|
|
Cash
and restricted cash at end of year
|
$
11,324
|
$
25,712
|
|
|
|
|
|
|
|
|
|
Supplemental
Disclosure of Cash Flow Information
|
|
|
|
Cash
paid for:
|
|
|
|
Interest
|
$
-
|
$
-
|
|
Income
taxes
|
$
-
|
$
-
|
|
|
|
|
|
Noncash
investing and financing activities:
|
|
|
|
Change
in accrued oil and gas development costs
|
$
8,827
|
$
2,056
|
|
Acquisition
of asset retirement obligations
|
$
-
|
$
54
|
|
Change
in estimates of asset retirement costs
|
$
439
|
$
695
|
|
Common
stock issued for debt conversion
|
$
-
|
$
55,075
|
|
Issuance
of restricted common stock
|
$
1
|
$
1
|
See
accompanying notes to consolidated financial
statements.
78
PEDEVCO CORP.
CONSOLIDATED STATEMENT CHANGES IN SHAREHOLDERS'
E
QUITY
For the Years Ended December 31, 2020 and 2019
(amounts
in thousands, except share amounts)
|
|
Common Stock
|
|
|
|
|
|
|
Shares
|
Amount
|
Additional Paid-in Capital
|
Accumulated Deficit
|
Totals
|
|
Balances at December 31, 2018
|
15,808,445
|
$
16
|
$
101,450
|
$
(84,494
)
|
$
16,972
|
|
Issuance of
common stock for debt conversion
|
29,480,383
|
29
|
55,046
|
-
|
55,075
|
|
Issuance of
restricted common stock
|
430,000
|
1
|
(1
)
|
-
|
-
|
|
Issuance of
common stock to non-affiliates
|
10,150,000
|
10
|
14,990
|
-
|
15,000
|
|
Issuance of
common stock to affiliate
|
15,122,662
|
15
|
27,985
|
-
|
28,000
|
|
Warrants
exercised
|
60,056
|
-
|
-
|
-
|
-
|
|
Cashless
exercise of stock options
|
9,782
|
-
|
-
|
-
|
-
|
|
Share-based
compensation
|
-
|
-
|
1,557
|
-
|
1,557
|
|
Net
loss
|
-
|
-
|
-
|
(11,102
)
|
(11,102
)
|
|
Balances at December 31, 2019
|
71,061,328
|
71
|
201,027
|
(95,596
)
|
105,502
|
|
Issuance of
restricted common stock
|
1,359,000
|
1
|
(1
)
|
-
|
-
|
|
Rescinded
restricted common stock
|
(129,000
)
|
-
|
-
|
-
|
-
|
|
Issuance of
common stock to non-affiliate
|
70,000
|
-
|
-
|
-
|
-
|
|
Issuance of
common stock to affiliate
|
70,000
|
-
|
-
|
-
|
-
|
|
Cashless
exercise of stock options
|
32,012
|
-
|
-
|
-
|
-
|
|
Share-based
compensation
|
-
|
-
|
2,824
|
-
|
2,824
|
|
Net
loss
|
-
|
-
|
-
|
(32,690
)
|
(32,690
)
|
|
Balances at December 31, 2020
|
72,463,340
|
$
72
|
$
203,850
|
$
(128,286
)
|
$
75,636
|
See
accompanying notes to consolidated financial
statements.
79
PEDEVCO CORP.
N
OTES TO CONSOLIDATED FINANCIAL
STATEMENTS
NOTE 1 – BASIS OF PRESENTATION
The
accompanying consolidated financial statements of PEDEVCO Corp.
(“PEDEVCO” or the “Company”), have been
prepared in accordance with accounting principles generally
accepted in the United States of America (“US
GAAP”) and the rules of the Securities and Exchange
Commission (“SEC”).
The
Company’s consolidated financial statements include the
accounts of the Company, its wholly-owned subsidiaries and
subsidiaries in which the Company has a controlling financial
interest. All significant inter-company accounts and transactions
have been eliminated in consolidation.
NOTE 2 – DESCRIPTION OF BUSINESS
PEDEVCO
is
an oil and gas company focused on
the development, acquisition and production of oil and natural
gas
assets where the latest in modern drilling and
completion techniques and technologies have yet to be applied. In
particular, the Company focuses on legacy proven properties where
there is a long production history, well defined geology and
existing infrastructure that can be leveraged when applying modern
field management technologies. The Company’s current
properties are located in the San Andres formation of the Permian
Basin situated in West Texas and eastern New Mexico (the
“Permian Basin”) and
in the Denver-Julesberg Basin (“D-J Basin”) in
Colorado. The Company holds its Permian Basin acres located
in Chaves and Roosevelt Counties, New Mexico, through its
wholly-owned operating subsidiary, Pacific Energy Development Corp.
(“PEDCO”), which asset the Company refers to as its
“Permian Basin Asset,” and it holds its D-J Basin acres
located in Weld and Morgan Counties, Colorado, through its
wholly-owned operating subsidiary, Red Hawk Petroleum, LLC
(“Red Hawk”), which asset the Company refers to as its
“D-J Basin Asset.”
The Company believes that horizontal development
and exploitation of conventional assets in the Permian Basin and
development of the Wattenberg and Wattenberg Extension in the D-J
Basin represent among the most economic oil and natural gas plays
in the United States (“U.S.”). Moving forward,
the Company plans to optimize its existing assets and
opportunistically seek additional acreage proximate to its
currently held core acreage, as well as other attractive onshore
U.S. oil and gas assets that fit the Company’s acquisition
criteria, that Company management believes can be developed using
its technical and operating expertise and be accretive to
shareholder value.
NOTE 3 – SUMMARY OF SIGNIFICANT ACCOUNTING
POLICIES
Basis of Presentation and Principles of
Consolidation.
The consolidated financial statements
herein have been prepared in accordance with GAAP and include the
accounts of the Company and those of its wholly and partially-owned
subsidiaries as follows: (i) Blast AFJ, Inc., a Delaware
corporation; (ii) PEDCO, a Nevada corporation; (iii) Red
Hawk, a Nevada limited liability company; (iv)
Ridgeway Arizona Oil Corp., an Arizona corporation
(“RAOC”); (v) EOR Operating Company, a Texas
corporation (“EOR”); (vi) SRPT Acquisition, LLC, a
Texas limited liability company formed on October 16, 2020 in
connection with the Company’s proposed acquisition, which has
since been abandoned, of all of the issued and outstanding Common
Units of the SandRidge Permian Trust; and (vii) Condor Energy
Technology LLC, a Nevada limited liability company
(“Condor”), acquired by Red Hawk on August 1, 2018 in
connection with the Company’s acquisition of part of its D-J
Basin Asset, which was dissolved on October 30, 2019.
All
significant intercompany accounts and transactions have been
eliminated.
Use of Estimates in Financial Statement
Preparation.
The preparation of financial statements in
conformity with US GAAP requires management to make estimates and
assumptions that affect the reported amounts of assets,
liabilities, revenues and expenses, as well as certain financial
statement disclosures. While management believes that the estimates
and assumptions used in the preparation of the financial statements
are appropriate, actual results could differ from these estimates.
Significant estimates generally include those with respect to the
amount of recoverable oil and gas reserves, the fair value of
financial instruments, oil and gas depletion, asset retirement
obligations, and stock-based compensation.
80
Cash and Cash Equivalents.
The
Company considers all highly liquid investments with original
maturities of three months or less to be cash equivalents. As of
December 31, 2020, and December 31, 2019, cash equivalents
consisted of money market funds and cash on deposit. The Company
includes restricted cash within cash and cash equivalents on the
consolidated statements of cash flows.
Concentrations of Credit
Risk.
Financial instruments which potentially subject
the Company to concentrations of credit risk include cash deposits
placed with financial institutions.
The Company periodically assesses the financial
condition of its financial institutions and considers any possible
credit risk to be minimal.
Sales
to two customers comprised 63%, and 11%, respectively, of the
Company’s total oil and gas revenues for the year ended
December 31, 2020. The Company believes that, in the event
that its primary customers are unable or unwilling to continue to
purchase the Company’s production, there are a substantial
number of alternative buyers for its production at comparable
prices.
Accounts Receivable.
Accounts
receivable typically consist of oil and gas receivables. The
Company has classified these as short-term assets in the balance
sheet because the Company expects repayment or recovery within the
next 12 months. The Company evaluates these accounts receivable for
collectability considering the results of operations of these
related entities and, when necessary, records allowances for
expected unrecoverable amounts. To date, no allowances have been
recorded. Included in accounts receivable – oil and gas are
$14,000 related to receivables from joint interest
owners.
Bad Debt Expense.
The Company’s
ability to collect outstanding receivables is critical to its
operating performance and cash flows. Accounts receivable are
stated at an amount management expects to collect from outstanding
balances. The Company extends credit in the normal course of
business. The Company regularly reviews outstanding receivables and
when the Company determines that a party may not be able to make
required payments, a charge to bad debt expense in the period of
determination is made. Though the Company’s bad debts have
not historically been significant, the Company could experience
increased bad debt expense should a financial downturn
occur.
Equipment.
Equipment is stated at
cost less accumulated depreciation and amortization. Maintenance
and repairs are charged to expense as incurred. Renewals and
betterments which extend the life or improve existing equipment are
capitalized. Upon disposition or retirement of equipment, the cost
and related accumulated depreciation are removed, and any resulting
gain or loss is reflected in operations. Depreciation is provided
using the straight-line method over the estimated useful lives of
the assets, which are 3 to 10 years.
Oil and Gas Properties, Successful Efforts
Method.
The successful efforts method of accounting is
used for oil and gas exploration and production activities. Under
this method, all costs for development wells, support equipment and
facilities, and proved mineral interests in oil and gas properties
are capitalized. Geological and geophysical costs are expensed when
incurred. Costs of exploratory wells are capitalized as exploration
and evaluation assets pending determination of whether the wells
find proved oil and gas reserves. Proved oil and gas reserves are
the estimated quantities of crude oil and natural gas which
geological and engineering data demonstrate with reasonable
certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions, (i.e., prices and
costs as of the date the estimate is made). Prices include
consideration of changes in existing prices provided only by
contractual arrangements, but not on escalations based upon future
conditions.
Exploratory wells
in areas not requiring major capital expenditures are evaluated for
economic viability within one year of completion of drilling. The
related well costs are expensed as dry holes if it is determined
that such economic viability is not attained. Otherwise, the
related well costs are reclassified to oil and gas properties and
subject to impairment review. For exploratory wells that are found
to have economically viable reserves in areas where major capital
expenditure will be required before production can commence, the
related well costs remain capitalized only if additional drilling
is under way or firmly planned. Otherwise, the related well costs
are expensed as dry holes.
Exploration and
evaluation expenditures incurred subsequent to the acquisition of
an exploration asset in a business combination are accounted for in
accordance with the policy outlined above.
81
Depreciation,
depletion and amortization of capitalized oil and gas properties is
calculated on a field-by-field basis using the unit of production
method. Lease acquisition costs are amortized over the total
estimated proved developed and undeveloped reserves and all other
capitalized costs are amortized over proved developed reserves.
Costs specific to developmental
wells
for which drilling is in progress or uncompleted
are
capitalized as wells in progress and not subject to amortization
until completion and production commences, at which time
amortization on the basis of production will begin.
Impairment of Long-Lived
Assets.
The Company reviews the carrying value of its
long-lived assets annually or whenever events or changes in
circumstances indicate that the historical cost-carrying value of
an asset may no longer be appropriate. The Company assesses
recoverability of the carrying value of the asset by estimating the
future net undiscounted cash flows expected to result from the
asset, including eventual disposition. If the future net
undiscounted cash flows are less than the carrying value of the
asset, an impairment loss is recorded equal to the difference
between the asset’s carrying value and estimated fair
value.
Asset Retirement Obligations.
If a
reasonable estimate of the fair value of an obligation to perform
site reclamation, dismantle facilities or plug and abandon wells
can be made, the Company will record a liability (an asset
retirement obligation or “ARO”) on its
consolidated balance sheet and capitalize the present value of the
asset retirement cost in oil and gas properties in the period in
which the retirement obligation is incurred. In general, the amount
of an ARO and the costs capitalized will be equal to the estimated
future cost to satisfy the abandonment obligation assuming the
normal operation of the asset, using current prices that are
escalated by an assumed inflation factor up to the estimated
settlement date, which is then discounted back to the date that the
abandonment obligation was incurred using an assumed cost of funds
for the Company. After recording these amounts, the ARO will be
accreted to its future estimated value using the same assumed cost
of funds and the capitalized costs are depreciated on a
unit-of-production basis over the estimated proved developed
reserves. Both the accretion and the depreciation will be included
in depreciation, depletion and amortization expense on our
consolidated statements of operations.
Revenue Recognition.
The
Company’s revenue is comprised entirely of revenue from
exploration and production activities. The Company’s oil is
sold primarily to marketers, gatherers, and refiners. Natural gas
is sold primarily to interstate and intrastate natural-gas
pipelines, direct end-users, industrial users, local distribution
companies, and natural-gas marketers. NGLs are sold primarily to
direct end-users, refiners, and marketers. Payment is generally
received from the customer in the month following
delivery.
Contracts with
customers have varying terms, including month-to-month contracts,
and contracts with a finite term. The Company recognizes sales
revenues for oil, natural gas, and NGLs based on the amount of each
product sold to a customer when control transfers to the customer.
Generally, control transfers at the time of delivery to the
customer at a pipeline interconnect, the tailgate of a processing
facility, or as a tanker lifting is completed. Revenue is measured
based on the contract price, which may be index-based or fixed, and
may include adjustments for market differentials and downstream
costs incurred by the customer, including gathering,
transportation, and fuel costs.
Revenues are
recognized for the sale of the Company’s net share of
production volumes. Sales on behalf of other working interest
owners and royalty interest owners are not recognized as
revenues.
Income Taxes.
The Company utilizes
the asset and liability method in accounting for income taxes.
Under this method, deferred tax assets and liabilities are
recognized for operating loss and tax credit carry-forwards and for
the future tax consequences attributable to differences between the
financial statement carrying amounts of existing assets and
liabilities and their respective tax bases. Deferred tax assets and
liabilities are measured using enacted tax rates expected to apply
to taxable income in the year in which those temporary differences
are expected to be recovered or settled. The effect on deferred tax
assets and liabilities of a change in tax rates is recognized in
the results of operations in the period that includes the enactment
date. A valuation allowance is recorded to reduce the carrying
amounts of deferred tax assets unless it is more likely than not
that the value of such assets will be realized.
Uncertain Tax Positions.
The Company
evaluates uncertain tax positions to recognize a tax benefit from
an uncertain tax position only if it is more likely than not that
the tax position will be sustained on examination by the taxing
authorities based on the technical merits of the position. Those
tax positions failing to qualify for initial recognition are
recognized in the first interim period in which they meet the more
likely than not standard or are resolved through negotiation or
litigation with the taxing authority, or upon expiration of the
statute of limitations. De-recognition of a tax position that was
previously recognized occurs when an entity subsequently determines
that a tax position no longer meets the more likely than not
threshold of being sustained.
82
The
Company is subject to ongoing tax exposures, examinations and
assessments in various jurisdictions. Accordingly, the Company may
incur additional tax expense based upon the outcomes of such
matters. In addition, when applicable, the Company will adjust tax
expense to reflect the Company’s ongoing assessments of such
matters, which require judgment and can materially increase or
decrease its effective rate as well as impact operating
results.
Stock-Based Compensation.
The
Company utilizes the Black-Scholes option pricing model to estimate
the fair value of employee stock option awards at the date of
grant, which requires the input of highly subjective assumptions,
including expected volatility and expected life. Changes in these
inputs and assumptions can materially affect the measure of
estimated fair value of our share-based compensation. These
assumptions are subjective and generally require significant
analysis and judgment to develop. When estimating fair value, some
of the assumptions will be based on, or determined from, external
data and other assumptions may be derived from our historical
experience with stock-based payment arrangements. The appropriate
weight to place on historical experience is a matter of judgment,
based on relevant facts and circumstances.
The
Company estimates volatility by considering the historical stock
volatility. The Company has opted to use the simplified method for
estimating expected term, which is generally equal to the midpoint
between the vesting period and the contractual term.
Earnings (Loss) per Common Share.
Basic earnings (loss) per share (“EPS”) is
computed by dividing net income (loss) available to common
shareholders (numerator) by the weighted average number of
shares outstanding (denominator) during the period. Diluted
EPS give effect to all dilutive potential common shares outstanding
during the period using the treasury stock method and convertible
preferred stock using the if-converted method. In computing diluted
EPS, the average stock price for the period is used to determine
the number of shares assumed to be purchased from the exercise of
stock options and/or warrants. Diluted EPS excluded all dilutive
potential shares if their effect is anti-dilutive. For the year
ended December 31, 2020, potentially dilutive securities related to
options (1,234,849) and warrants (150,329) were not included in the
calculation of diluted net loss per share because to do so would be
anti-dilutive.
Recently Adopted Accounting
Pronouncements.
Effective January
1, 2020, we adopted Financial Accounting Standard Board
(“FASB”) Accounting Standards Update
(“ASU”) 2016-13, Measurement of Credit Losses on
Financial Instruments, which changed the way entities recognize
impairment of most financial assets. Short-term and long-term
financial assets, as defined by the standard, are impacted by
immediate recognition of estimated credit losses in the financial
statements, reflecting the net amount expected to be collected. The
adoption of this standard did not have an impact on our
Consolidated Financial Statements.
The
Company does not expect the adoption of any other recently issued
accounting pronouncements to have a significant impact on its
financial position, results of operations, or cash
flows.
Subsequent Events.
The Company has
evaluated all transactions through the date the consolidated
financial statements were issued for subsequent event disclosure
consideration.
NOTE 4 – CASH
The following table provides a reconciliation of
cash and restricted cash reported within the balance sheets on
December 31, 2020 and 2019, which sum to the total of such amounts
shown in the accompanying audited consolidated statements of cash
flows (in thousands):
|
|
2020
|
2019
|
|
Cash
|
$
8,027
|
$
22,415
|
|
Restricted
cash included in other assets
|
3,297
|
3,297
|
|
Total
cash and restricted cash as shown in the consolidated statements of
cash flows
|
$
11,324
|
$
25,712
|
83
NOTE 5 – REVENUE FROM CONTRACTS WITH CUSTOMERS
Disaggregation of Revenue from Contracts with
Customers.
The following table disaggregates revenue by
significant product type for the years ended December 31, 2020 and
2019 (in thousands):
|
|
2020
|
2019
|
|
Oil
sales
|
$
7,551
|
$
12,518
|
|
Natural
gas sales
|
330
|
372
|
|
Natural
gas liquids sales
|
178
|
82
|
|
Total
revenue from customers
|
$
8,059
|
$
12,972
|
There
were no significant contract liabilities or transaction price
allocations to any remaining performance obligations as of December
31, 2020 or 2019, respectively.
NOTE 6 – OIL AND GAS PROPERTIES
The
following tables summarize the Company’s oil and gas
activities by classification for the years ended December 31, 2020
and 2019, respectively (in thousands):
|
|
Balance at
December 31,
|
|
|
|
Balance at
December 31,
|
|
|
2019
|
Additions
|
Disposals
|
Transfers
|
2020
|
|
Oil and gas
properties, subject to amortization
|
$
126,114
|
$
5,542
|
$
-
|
$
15,294
|
$
146,950
|
|
Oil and gas
properties, not subject to amortization
|
14,896
|
402
|
-
|
(15,294
)
|
4
|
|
Asset retirement
costs
|
1,547
|
(439
)
|
-
|
-
|
1,108
|
|
Accumulated
depreciation, depletion and impairment
|
(50,709
)
|
(30,355
)
|
-
|
-
|
(81,064
)
|
|
Total oil and gas
assets
|
$
91,848
|
$
(24,850
)
|
$
-
|
$
-
|
$
66,998
|
|
|
Balance at
December 31,
|
|
|
|
Balance at
December 31,
|
|
|
2018
|
Additions
|
Disposals
|
Transfers
|
2019
|
|
Oil and gas
properties, subject to amortization
|
$
70,803
|
$
29,900
|
$
(135
)
|
$
6,596
|
$
107,164
|
|
Oil and gas
properties, not subject to amortization
|
8,516
|
12,976
|
-
|
(6,596
)
|
14,896
|
|
Asset retirement
costs
|
2,188
|
(641
)
|
-
|
-
|
1,547
|
|
Accumulated
depreciation and depletion
|
(21,045
)
|
(10,714
)
|
-
|
-
|
(31,759
)
|
|
Total oil and gas
assets
|
$
60,462
|
$
31,521
|
$
(135
)
|
$
-
|
$
91,848
|
For the
year ended December 31, 2020, the Company incurred $5,943,000 in
net capital costs primarily related to the drilling and completion
of four new horizontal wells and a saltwater disposal well
(“SWD”) in its Permian Basin Asset. The SWD was drilled
to increase the produced water injection capacity for the
Company’s Chaveroo field and, in turn, increase production of
the corresponding wells therein. The drilling and completion of the
SWD had been postponed due to the downturn in the economic
conditions in the oil and gas industry during the first quarter of
2020, but with the subsequent partial uptick in oil prices, the
Company completed the SWD in September 2020.
Also,
the Company transferred $15,294,000 in capital costs from the four
completed wells and the SWD noted above, for which production had
not commenced, from proved developed non-producing properties, to
proved properties, when production began during the current year.
The majority of the capital costs for three of the four wells were
incurred in the prior year.
For the
year ended December 31, 2019, the Company incurred $26,362,000 in
drilling and completion costs relating to the drilling of nine
wells and corresponding facility costs in its Permian Basin Asset,
in addition to amounts incurred for the participation (non-operated
working interest) in the drilling of 11 total wells in the DJ
Basin ($2,500,000 noted below), and the acquisition of oil and gas
assets from Manzano LLC and Manzano Energy Partners II, LLC
(“Manzano”) ($764,000 noted below) and from a
private operator ($350,000 noted below). Also, the Company
transferred $6,596,000 in capital costs from four wells which were
not completed at the beginning of the period from unproved
properties to proved properties when production began in March and
April of 2019. At December 31, 2019, drilling and completion costs
of $12,976,000 had been incurred for four of the nine wells in its
Permian Asset; however, as production had not yet commenced, this
amount was included in the amount not subject to amortization at
December 31, 2019.
84
The
depletion recorded for production on proved properties for the year
ended December 31, 2020 and 2019, amounted to $11,023,000 and
$10,714,000, respectively. The Company recorded impairment of
properties subject to amortization for the years ended December 31,
2020 and 2019, of $19,331,000 and $-0-, respectively. The
impairment in 2020 was due to a reduction in the reserve value with
our D-J Basin assets relative to the carrying amount of the D-J
Basin assets.
On
February 1, 2019, for consideration of $743,000, plus $21,000 in
acquisition costs, the Company completed an asset purchase from
Manzano, whereby the Company purchased approximately 18,000 net
leasehold acres, ownership and operated production from one
horizontal well currently producing from the San Andres play in the
Permian Basin, ownership of three additional shut-in wells, and
ownership of one saltwater disposal well. The Company subsequently
drilled one Manzano well in Phase Two of its 2019 development plan,
which has yet to be completed.
On
March 7, 2019, Red Hawk sold rights to 85.5 net acres of oil and
gas leases located in Weld County, Colorado, to a third party, for
aggregate proceeds of $1.2 million and recognized a gain on sale of
oil and gas properties of $920,000 on the Statement of Operations.
The sale agreement included a provision whereby the purchaser was
required to assign Red Hawk 85 net acres of leaseholds in an area
located where the Company already owns other leases in Weld County,
Colorado, within nine months from the date of the sale, or to repay
the Company up to $200,000 (proportionally adjusted for the amount
of leasehold delivered). In December 2019, the purchaser assigned
Red Hawk 121 net acres of leaseholds with a value of $121,000,
which the Company recognized as an additional gain on the Statement
of Operations.
On June
10, 2019, for consideration of $350,000, the Company completed an
asset purchase from a private operator, whereby the Company
purchased approximately 2,076 net leasehold acres, ownership and
operated production from 22 vertical wells currently producing from
the San Andres play in the Permian Basin and ownership of three
injection wells.
During
2019, the Company participated in the drilling and completion of 11
horizontal wells in the D-J Basin by third-party outside operators
and incurred $2.5 million in net participation costs.
NOTE 7 – PPP LOAN
On April 22, 2020, the Company received loan
proceeds of $370,000 (the “Original PPP Loan”) under
the U. S. Small Business Administration’s (“SBA”)
Paycheck Protection Program (“PPP”)
established as part of
the Coronavirus Aid, Relief and Economic Security Act (“CARES
Act”)
, and
o
n
April 23, 2020, the SBA issued guidance that cast doubt on the
ability of public companies to qualify for a PPP loan. As a result,
out of an abundance of caution, on May 1, 2020, the Company repaid
the full amount of the Original PPP Loan to
Texas Capital Bank, N.A.
Upon
the issuance of further guidance from the SBA, which clarified the
ability of public companies to receive PPP loans,
on June 2, 2020, the Company again received loan
proceeds of $370,000 (the “New PPP Loan”) under the SBA
PPP. The New PPP Loan is evidenced by a promissory note, dated as
of May 28, 2020 (the “Note”), between the Company and
Texas Capital Bank, N.A. The Note has a two-year term, bears
interest at the rate of 1.00% per annum, and may be prepaid at any
time without payment of any premium. No payments of
principal or interest are due during the six-month period beginning
on the date of the Note. The principal and accrued interest under
the Note are forgivable after eight weeks if the Company uses the
New PPP Loan proceeds for eligible purposes, including payroll,
benefits, rent, and utilities, and otherwise complies with PPP
requirements, with the full principal and accrued interest expected
to be forgiven in full by the Company. As of December 31, 2020, the
Company has accrued $2,000 in interest on the Note.
As of
December 31, 2020, the full amount of the loan was outstanding,
with $288,000 included in current liabilities on the balance
sheet.
As
of the issuance date of these financial statements, the Company
believes that it has used the loan proceeds only for eligible
expenses, has submitted the necessary loan forgiveness application
to Texas Capital Bank, N.A., and the SBA has notified the Company
that the SBA has selected its loan for review. The Company is
awaiting completion of the review and confirmation from the SBA on
its loan forgiveness determination.
85
NOTE 8 – ASSET RETIREMENT OBLIGATION
Activity
related to the Company’s asset retirement obligations is as
follows for the year ended December 31, 2020 (in
thousands):
|
|
2020
|
|
Balance at the
beginning of the period
(1)
|
$
2,099
|
|
Accretion
expense
|
289
|
|
Liabilities
settled
|
(42
)
|
|
Changes in
estimates
|
(439
)
|
|
Balance at end of
period
(2)
|
$
1,907
|
(1)
Includes $225,000 of current asset retirement obligations at
December 31, 2019.
(2)
Includes $234,000 of current asset retirement obligations at
December 31, 2020.
NOTE 9 – COMMITMENTS AND CONTINGENCIES
Lease Agreements
Currently, the
Company has one operating lease for office space that requires
Accounting Standards Codification (ASC) Topic 842 treatment,
discussed below.
The
Company’s leases typically do not provide an implicit rate.
Accordingly, the Company is required to use its incremental
borrowing rate in determining the present value of lease payments
based on the information available at the commencement date. The
Company’s incremental borrowing rate would reflect the
estimated rate of interest that it would pay to borrow on a
collateralized basis over a similar term, an amount equal to the
lease payments in a similar economic environment. However, the
Company currently maintains no debt, and in order to apply an
appropriate discount rate, the Company used an average discount
rate of eight publicly traded peer group companies similar to it
based on size, geographic location, asset types, and/or operating
characteristics.
The
Company has a sublease for its corporate offices in Houston, Texas
on approximately 5,200 square feet of office space that expires on
August 31, 2023, and has a base monthly rent of approximately
$10,000.
The
Company also had a lease for 187 square feet of office space
located in Danville, California for the Company’s Executive
Vice President and General Counsel. The monthly rent was $1,200,
discounted to $960 from April 2020 through its expiration on August
28, 2020. The Company did not renew this lease upon expiration in
an effort to further reduce Company expenses.
For the
year ended December 31, 2020, the Company incurred lease expense of
$103,000, for the combined leases.
Supplemental cash
flow information related to the Company’s operating lease is
included in the table below (in thousands):
|
|
Year
Ended
|
|
|
December
31,
2020
|
|
Cash
paid for amounts included in the measurement of lease
liabilities
|
$
115
|
Supplemental
balance sheet information related to operating leases is included
in the table below (in thousands):
|
|
December 31,
2020
|
|
Operating
lease – right-of-use asset
|
$
270
|
|
|
|
|
Operating
lease liabilities - current
|
$
105
|
|
Operating
lease liabilities - long-term
|
195
|
|
Total
lease liability
|
$
300
|
86
The
weighted-average remaining lease term for the Company’s
operating lease is 2.7 years as of December 31, 2020, with a
weighted-average discount rate of 5.35%.
Lease
liability with enforceable contract terms that have greater than
one-year terms are as follows (in thousands):
|
2021
|
$
118
|
|
2022
|
121
|
|
2023
|
82
|
|
Thereafter
|
-
|
|
Total
lease payments
|
321
|
|
Less
imputed interest
|
(21
)
|
|
Total
lease liability
|
$
300
|
Leasehold Drilling Commitments
The
Company’s oil and gas leasehold acreage is subject to
expiration of leases if the Company does not drill and hold such
acreage by production or otherwise exercises options to extend such
leases, if available, in exchange for payment of additional cash
consideration. In the D-J Basin Asset, no net acres expire during
2021, and no net acres expire thereafter (net to our direct
ownership interest only), as all leases are held by production. In
the Permian Basin Asset, 3,865, 1,395 and 80 net acres are set to
expire for the years ending December 31, 2021, 2022 and 2023,
respectively, without meeting drilling commitments or term
assignment extensions (net to our direct ownership interest only).
The Company plans to hold significantly all of this acreage through
a program of drilling and completing producing wells. If the
Company is not able to drill and complete a well before term
assignment expiration, the Company may seek to extend terms of
contractual assignments.
Other Commitments
Although the
Company may, from time to time, be involved in litigation and
claims arising out of its operations in the normal course of
business, the Company is not currently a party to any material
legal proceeding. In addition, the Company is not aware of any
material legal or governmental proceedings against it or
contemplated to be brought against it.
As part
of its regular operations, the Company may become party to various
pending or threatened claims, lawsuits and administrative
proceedings seeking damages or other remedies concerning its
commercial operations, products, employees and other
matters.
Although the
Company provides no assurance about the outcome of these or any
other pending legal and administrative proceedings and the effect
such outcomes may have on the Company, the Company believes that
any ultimate liability resulting from the outcome of such
proceedings, to the extent not otherwise provided for or covered by
insurance, will not have a material adverse effect on the
Company’s financial condition or results of
operations.
NOTE 10 – SHAREHOLDERS’ EQUITY
Common Stock
During
the year ended December 31, 2020, the Company granted an aggregate
of 1,499,000 restricted stock awards to various employees, board
members, affiliates, and a consultant of the Company. Additionally,
129,000 shares of restricted common stock were forfeited to the
Company and canceled
due
to employee terminations (see Note 11 below).
On
February 15, 2019 and March 1, 2019, $22.3 million and $32.8
million of outstanding note payables and accrued interest were
converted into 14,098,778 and 15,381,605 shares of the
Company’s common stock, respectively.
87
On May
16, 2019, the Company sold an aggregate of 1,500,000 shares of its
restricted common stock to two third-party purchasers at a price of
$2.00 per share, or $3 million in aggregate, pursuant to
subscription agreements, and on September 17, 2019, the Company
sold an aggregate of 8,400,000 shares of its restricted common
stock to an additional third-party purchaser, Viktor Tkachev, who
became an affiliate of the Company, after the issuance, at a price
of $1.43 per share, or $12 million in aggregate, pursuant to a
subscription agreement.
On May
21, 2019, SK Energy, which is owned and controlled by Mr. Simon
Kukes, the Company’s Chief Executive Officer and a member of
the Board of Directors, purchased 6,818,181 shares of restricted
common stock from the Company at a price of $2.20 per share, or $15
million in aggregate, pursuant to a subscription agreement, and on
September 17, 2019, SK Energy purchased an additional 8,204,481
shares of restricted common stock from the Company at a price of
$1.58 per share, or $13 million in aggregate, pursuant to a
subscription agreement.
As a
result of the 2019 purchases above, SK Energy, which beneficially
owned 78.2% of the Company’s outstanding common stock prior
to the May 16, 2019 subscription agreement, beneficially owned
73.2% of the Company’s outstanding common stock after all of
the subscriptions discussed above. Currently, SK Energy
beneficially owns 65.2% of the Company’s outstanding common
stock as of the date of this report.
Warrants
During
the year ended December 31, 2020, no warrants were granted,
exercised, or canceled, and as of December 31, 2020, the
Company had warrants to purchase 150,329 shares of common stock
outstanding, with an exercise price of $0.32 per share and a June
25, 2021 expiration date.
During
the year ended December 31, 2019, no warrants were granted, and
warrants to purchase 470,077 shares of common stock expired.
Additionally, on April 1, 2019, the Company issued 60,056 total
shares of common stock upon the cashless exercise of two warrants
to purchase an aggregate of 596,280 shares of common stock with an
exercise price of $2.50 per share, based on a current market value
of $2.78 per share, under the terms of each warrant.
The
intrinsic value of outstanding as well as exercisable warrants at
December 31, 2020 and 2019 was $179,000 and $201,000,
respectively.
Warrant
activity during the years ended December 31, 2020 and 2019
was:
|
|
2020
|
2019
|
||||
|
|
Number of Warrants
|
Weighted Average Exercise Price
|
Weighted Average Remaining Contract Term (Years)
|
Number of Warrants
|
Weighted Average Exercise Price
|
Weighted Average Remaining Contract Term (Years)
|
|
Outstanding
at Beginning of Period
|
150,329
|
$
0.32
|
1.5
|
1,216,686
|
$
6.36
|
0.8
|
|
Expired/Cancelled
|
-
|
|
|
(470,077
)
|
13.19
|
|
|
Exercised
|
-
|
|
|
(596,280
)
|
2.50
|
|
|
Outstanding
at End of Period
|
150,329
|
$
0.32
|
0.5
|
150,329
|
$
0.32
|
1.5
|
|
Exercisable
at End of Period
|
150,329
|
$
0.32
|
0.5
|
150,329
|
0.32
|
1.5
|
NOTE 11 – SHARE-BASED COMPENSATION
2012 Incentive Plan
On July
27, 2012, the shareholders of the Company approved the 2012 Equity
Incentive Plan (the “2012 Incentive Plan”), which was
previously approved by the Board of Directors on June 27, 2012 and
authorizes the issuance of various forms of stock-based awards,
including incentive or non-qualified options, restricted stock
awards, performance shares and other securities as described in
greater detail in the 2012 Incentive Plan, to the Company’s
employees, officers, directors and consultants. The 2012 Incentive
Plan was amended on June 27, 2014, October 7, 2015 and December 28,
2016, December 28, 2017, September 27, 2018 and August 28, 2019 to
increase by 500,000, 300,000, 500,000, 1,500,000, 3,000,000 and
2,000,000 (to 8,000,000 currently), respectively, the number of
shares of common stock reserved for issuance under the 2012
Incentive Plan.
88
A total
of 8,000,000 shares of common stock are eligible to be issued under
the 2012 Incentive Plan as of December 31, 2020, of which 5,350,130
shares have been issued as restricted stock, 1,159,500 shares are
subject to issuance upon exercise of issued and outstanding
options, and 1,490,370 shares remain available for future issuance
as of December 31, 2020.
PEDCO 2012 Equity Incentive Plan
As a
result of the July 27, 2012 merger by and between the Company,
Blast Acquisition Corp., a wholly-owned Nevada subsidiary of the
Company (“MergerCo”), and Pacific Energy Development
Corp., a privately-held Nevada corporation
(“PEDCO”) pursuant to which MergerCo was merged
with and into PEDCO, with PEDCO continuing as the surviving entity
and becoming a wholly-owned subsidiary of the Company, in a
transaction structured to qualify as a tax-free reorganization (the
“Merger”), the Company assumed the PEDCO 2012 Equity
Incentive Plan (the “PEDCO Incentive Plan”), which was
adopted by PEDCO on February 9, 2012. The PEDCO Incentive Plan
authorized PEDCO to issue an aggregate of 100,000 shares of common
stock in the form of restricted shares, incentive stock options,
non-qualified stock options, share appreciation rights, performance
shares, and performance units under the PEDCO Incentive Plan. As of
December 31, 2020, options to purchase an aggregate of 21,635
shares of the Company’s common stock and 55,168 shares of the
Company’s restricted common stock have been granted under
this plan (all of which were granted by PEDCO prior to the closing
of the merger with the Company, with such grants being assumed by
the Company and remaining subject to the PEDCO Incentive Plan
following the consummation of the merger). The Company does not
plan to grant any additional awards under the PEDCO Incentive
Plan.
The
Company measures the cost of employee services received in exchange
for an award of equity instruments based on the grant-date fair
value of the award over the vesting period.
Common Stock
On
January 13, 2020, restricted stock awards were granted to various
employees and one consultant for an aggregate of 1,049,000
(including 924,000 restricted stock awards to officers of the
Company) and 70,000 shares, respectively, of the Company’s
common stock, under the Company’s Amended and Restated 2012
Equity Incentive Plan. The grant of the 1,049,000 shares of
restricted stock vest as follows: 33.3% vest each subsequent year
from the date of grant, contingent upon the recipient’s
continued service with the Company. These shares have a total fair
value of $1,172,000, based on the market price on the issuance
date. The grant of the 70,000 shares of restricted stock was made
to a Company advisor and vest as follows: 100% on the first
anniversary of the grant date, subject to the recipient’s
continued service with the Company. These advisor shares have a
total fair value of $118,000, based on the market price on the
issuance date.
In February 2020 and August 2020, 55,000 and
74,000 shares of restricted common stock, respectively, were
forfeited to the Company and canceled
due to an employee termination. As a result, these
shares are once again eligible to be awarded under the
Company’s Amended and Restated 2012 Equity Incentive
Plan.
On
August 27, 2020, restricted stock awards were granted to three
board members, an affiliate and an advisor for an aggregate of
240,000, 70,000, and 70,000 shares, respectively, of the
Company’s restricted common stock, under the Company’s
Amended and Restated 2012 Equity Incentive Plan. The grant of the
240,000 shares of restricted common stock vest as follows: 100% of
170,000 shares and 100% of 70,000 shares vesting on July 12, 2021
and September 21, 2021, respectively, contingent upon each
recipient’s continued service with the Company. These shares
have a total fair value of $506,000, based on the market price on
the issuance date. The grant of the remaining aggregate of
140,000 shares of restricted common stock vest as follows: 100% on
the six-month anniversary of the grant date, subject to each
recipient’s continued service with the Company. These
affiliate and advisor shares have a total fair value of $295,000,
based on the market price on the issuance date.
In
April 2019, restricted stock awards were granted to three new
employees and one consultant for an aggregate of 160,000 shares of
the Company’s common stock, under the Company’s Amended
and Restated 2012 Equity Incentive Plan. The grant for a total of
50,000 of the restricted stock awards vests as follows: 100% on the
one-year anniversary of the grant date, subject to the
recipient’s continued service with the Company. These shares
have a total fair value of $135,000 based on the market price on
the issuance date. The grants for 110,000 shares of restricted
stock vest as follows: 50% on the one-year anniversary of the grant
date and 50% on the second-year anniversary of the grant date,
subject to the recipient’s continued service with the
Company. These shares have a total fair value of $253,000 based on
the market price on the issuance date.
89
On July
18, 2019, 50,000 shares of restricted stock were awarded to an
advisor under the Company’s Amended and Restated 2012 Equity
Incentive Plan. The restricted stock vests as follows: 100% on the
six-month anniversary of the grant date, subject to the
recipient’s continued service with the Company. These shares
have a total fair value of $83,000, based on the market price on
the issuance date.
On
August 28, 2019, restricted stock awards were granted to three
directors for an aggregate of 170,000 shares of the Company’s
common stock, under the Company’s Amended and Restated 2012
Equity Incentive Plan. The grant for a total of 120,000 of the
restricted stock awards vests as follows: 100% on July 12, 2020,
subject to the recipient’s continued service with the
Company. These shares have a total fair value of $187,000 based on
the market price on the issuance date. The grants for 50,000 shares
of restricted stock vest as follows: 100% on September 27, 2020,
subject to the recipient’s continued service with the
Company. These shares have a total fair value of $78,000 based on
the market price on the issuance date. Additionally, 50,000 shares
of restricted stock were awarded to a director for advisory
services provided to the Company under the Company’s Amended
and Restated 2012 Equity Incentive Plan. The restricted stock vests
as follows: 100% on July 12, 2020, subject to the recipient’s
continued service with the Company. These shares have a total fair
value of $78,000, based on the market price on the issuance
date.
On
October 5, 2019, 250,000 shares of restricted stock were awarded to
an advisor under the Company’s Amended and Restated 2012
Equity Incentive Plan. The restricted stock vests as follows: 100%
on the six-month anniversary of the grant date, subject to the
recipient’s continued service with the Company. These shares
have a total fair value of $350,000, based on the market price on
the issuance date.
On
November 8, 2019, the Company entered into an Advisory Agreement
and Restricted Shares Grant Agreement with Viktor Tkachev, a
greater than 10% shareholder of the Company (who acquired $12
million of shares of common stock on September 17, 2019),
under which Mr. Tkachev agreed to provide strategic planning and
business development services, and pursuant to which 100,000 shares
of restricted common stock were awarded to Mr. Tkachev under the
Company’s Amended and Restated 2012 Equity Incentive Plan,
100% of which vest on the six-month anniversary of the grant date,
subject to the recipient’s continued service with the Company
and the terms and conditions of these agreements. These shares have
a total fair value of $128,000 based on the market price on the
issuance date.
Also on
November 8, 2019, the Company entered into an Advisory Agreement
with Ivar Siem, a member of the Board of Directors, pursuant to
which the 50,000 restricted shares of common stock previously
awarded to Mr. Siem on August 28, 2019 under the Plan continue to
vest, with 100% vesting on July 12, 2020, subject to Mr. Siem
continuing to provide advisory services to the Company on such
vesting date, and subject to the terms and conditions of a
Restricted Shares Grant Agreement entered into by and between the
Company and Mr. Siem on August 28, 2019. The Advisory Agreement
contains customary confidentiality, indemnification and no conflict
language; and may be terminated by the Company or the advisor with
15 days prior written notice for any reason.
The
awarded shares above are subject to trading restrictions, and
forfeiture, subject to the vesting terms described above. When such
securities are vested in accordance with their terms, the trading
restrictions are lifted.
Stock-based
compensation expense recorded related to restricted stock during
the years ended December 31, 2020 and 2019 was $2,323,000 and
$1,259,000, respectively. The remaining amount of unamortized
stock-based compensation expense related to restricted stock
at December 31, 2020 and 2019 was $1,144,000 and $999,000,
respectively.
Options
On
January 13, 2020, the Company granted options to purchase an
aggregate of 733,000 shares of common stock to various Company
employees at an exercise price of $1.68 per share. The options have
a term of five years and fully vest in January 2023, with 33.3% of
each grant vesting each subsequent year from the date of grant,
contingent upon each recipient’s continued service with the
Company. The aggregate fair value of the options on the date of
grant, using the Black-Scholes model, was $1,053,000. Variables
used in the Black-Scholes option-pricing model for the options
issued include: (1) a discount rate of 1.63% based on the
applicable US Treasury bill rate, (2) expected term of 3.5 years,
(3) expected volatility of 155% based on the trading history of the
Company, and (4) zero expected dividends.
On
August 27, 2020, the Company issued 32,012 total shares of common
stock upon the cashless exercise of stock options to purchase an
aggregate of 37,500 shares of common stock with an exercise price
of $0.3088 per share, based on a then-current market value of $2.11
per share, under the terms of the options. The options had an
intrinsic value of $68,000 on the exercise date.
90
On
August 14, 2019, the Company issued 9,782 total shares of common
stock upon the cashless exercise of stock options to purchase an
aggregate of 12,500 shares of common stock with an exercise price
of $0.31 per share, based on a then current market value of $1.42
per share, under the terms of the options. The options had an
intrinsic value of $14,000 on the exercise date.
During
the year ended December 31, 2020 and 2019, the Company recognized
stock option-based compensation expense related to options of
$501,000 and $298,000, respectively.
The
remaining amount of unamortized stock options expense at December
31, 2020 and 2019 was $315,000 and $22,000,
respectively.
The
intrinsic value of outstanding and exercisable options at December
31, 2020 and 2019 was $121,000 and $197,000,
respectively.
Option
activity during the years-ended December 31, 2020 and 2019
was:
|
|
2020
|
2019
|
||||
|
|
Number of Stock Options
|
Weighted Average Grant Price
|
Weighted Average Remaining Contract Term (Years)
|
Number of Stock Options
|
Weighted Average Grant Price
|
Weighted Average Remaining Contract Term (Years)
|
|
Outstanding
at Beginning of Period
|
753,349
|
$
2.93
|
2.5
|
890,232
|
$
3.26
|
3.3
|
|
Granted
|
733,000
|
1.68
|
|
-
|
|
|
|
Expired/Canceled
|
(214,000
)
|
2.00
|
|
(124,383
)
|
6.13
|
|
|
Exercised
|
(37,500
)
|
0.31
|
|
(12,500
)
|
0.31
|
|
|
Outstanding
at End of Period
|
1,234,849
|
$
2.43
|
2.7
|
753,349
|
$
2.93
|
2.5
|
|
Exercisable
at End of Period
|
665,182
|
$
3.08
|
1.6
|
720,016
|
$
3.00
|
2.4
|
NOTE 12 – INCOME TAXES
Due to
the Company’s net losses, there were no provisions for income
taxes for the years ended December 31, 2020 and 2019.
The
following table reconciles the U.S. federal statutory income tax
rate in effect for the years ended December 31, 2020 and 2019,
and the Company’s effective tax rate:
|
|
2020
|
2019
|
|
U.S.
federal statutory income tax (benefit)
|
21.00
%
|
21.00
%
|
|
State
and local income tax, net of benefits
|
6.64
%
|
6.64
%
|
|
Amortization
of debt discount
|
0.00
%
|
-2.05
%
|
|
Officer
life insurance and D&O insurance
|
0.00
%
|
-0.05
%
|
|
Stock-based
compensation
|
-0.20
%
|
-0.62
%
|
|
Utilization
of net operating loss carryforwards
|
0.02
%
|
0.03
%
|
|
Tax
rate changes and other
|
0.00
%
|
0.00
%
|
|
Valuation
allowance for deferred income tax assets
|
-27.46
%
|
-24.95
%
|
|
Effective
income tax rate
|
0.00
%
|
0.00
%
|
91
Deferred income tax
assets as of December 31, 2020 and 2019 are as follows (in
thousands):
|
Deferred Tax Assets
|
2020
|
2019
|
|
|
|
|
|
Difference
in depreciation, depletion, and capitalization methods – oil
and natural gas properties
|
$
712
|
$
529
|
|
Accretion
|
80
|
80
|
|
Impairment
|
5,343
|
-
|
|
Interest Expense -
PPP Loan
|
1
|
-
|
|
Stock-Based
Compensation
|
975
|
584
|
|
Net
Operating loss – federal taxes
|
25,507
|
23,183
|
|
Net
operating loss – state taxes
|
3,874
|
3,139
|
|
Total
deferred tax asset
|
36,492
|
27,515
|
|
Less
valuation allowance
|
(36,492
)
|
(27,515
)
|
|
Total
deferred tax assets
|
$
-
|
$
-
|
In
assessing the realization of deferred tax assets, management
considers whether it is more likely than not that some portion or
all deferred assets will not be realized. The ultimate realization
of the deferred tax assets is dependent upon the generation of
future taxable income during the periods in which those temporary
differences become deductible.
Utilization of NOL
and tax credit carryforwards may be subject to a substantial annual
limitation due to ownership change limitations that may have
occurred or that could occur in the future, as required by the
Internal Revenue Code (the “Code”), as amended, as well
as similar state provisions. In general, an “ownership
change” as defined by the Code results from a transaction or
series of transactions over a three-year period resulting in an
ownership change of more than 50 percent of the outstanding stock
of a company by certain shareholders or public groups.
Based
on the available objective evidence, management believes it is more
likely than not that the net deferred tax assets will not be fully
realizable. Accordingly, management has applied a full valuation
allowance against its net deferred tax assets at December 31, 2020
and 2019. The net change in the total valuation allowance from
December 31, 2020 to December 31, 2019 was an Increase of
$8,977,000.
The
Company’s policy is to recognize interest and penalties
accrued on any unrecognized tax benefits as a component of income
tax expense. As of December 31, 2020 and 2019, the Company did not
have any significant uncertain tax positions or unrecognized tax
benefits. The Company did not have associated accrued interest or
penalties, nor was any interest expense or penalties recognized for
the years ended December 31, 2020 and 2019.
As of
December 31, 2020, the Company has federal net operating loss
carryforwards of approximately $122,000,000, which if not utilized,
approximately $95,000,000 of which will begin expiring in 2023 and
ending 2037, respectively, and $27,000,000 under CARES Act can be
carried back up to five years but also, can be carried forward
indefinitely, limited to 80% of a given years taxable
income.
The
Company currently has tax returns open for examination by the
Internal Revenue Service for all years, since 2016.
NOTE 13 – SUBSEQUENT EVENTS
On
January 19, 2021, the Company granted options to purchase an
aggregate of 550,000 shares of common stock to various Company
employees at an exercise price of $1.39 per share. The options have
a term of five years and fully vest in January 2024. 33.3% vest
each subsequent year from the date of grant, contingent upon the
recipient’s continued service with the Company. The aggregate
fair value of the options on the date of grant, using the
Black-Scholes model, was $654,000. Variables used in the
Black-Scholes option-pricing model for the options issued include:
(1) a discount rate of 0.045% based on the applicable US Treasury
bill rate, (2) expected term of 3.5 years, (3) expected volatility
of 156% based on the trading history of the Company, and (4) zero
expected dividends.
92
Additionally, on
January 19, 2021, restricted stock awards were granted to officers
of the Company for an aggregate of 940,000 of the Company’s
common stock, under the Company’s Amended and Restated 2012
Equity Incentive Plan. The grant for the 940,000 shares of
restricted stock vest as follows: 33.3% vest each subsequent year
from the date of grant contingent upon the recipient’s
continued service with the Company. These shares have a total fair
value of $1,307,000 based on the market price on the issuance
date.
On
January 28, 2021, the Company issued 86,430 total shares of common
stock upon the cashless exercise of stock options to purchase an
aggregate of 191,999 shares of common stock with an exercise price
ranging between $1.10 and $1.68 per share, based on a then-current
market value of $2.89 per share, under the terms of the options.
The options had an intrinsic value of $250,000 on the exercise
date.
On
February 5, 2021, the Company closed
an underwritten public offering of 5,968,500
shares of common stock at a public offering price of $1.50 per
share, which included the full exercise of the underwriter’s
over-allotment option, for
net proceeds (after deducting the
underwriters’ discount equal to 6% of the public offering
price and expenses associated with the offering) of approximately
$8.3 million.
On
February 28, 2021, 16,667 shares of restricted common stock were
rescinded due to an employee termination. As a result, these shares
were canceled and returned to the Company’s Amended and
Restated 2012 Equity Incentive Plan.
On
March 18, 2021, the Company consummated the sale of certain assets
and associated liabilities located in its D-J Basin Asset to a
third-party purchaser for an aggregate purchase price received at
closing of $1.9 million, which purchase price is subject to certain
standard post-closing adjustments.
93
SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING
ACTIVITIES
(UNAUDITED)
The
following disclosures for the Company are made in accordance with
authoritative guidance regarding disclosures about oil and natural
gas producing activities. Users of this information should be aware
that the process of estimating quantities of “proved,”
“proved developed,” and “proved
undeveloped” crude oil, natural gas liquids and natural gas
reserves is complex, requiring significant subjective decisions in
the evaluation of all available geological, engineering and
economic data for each reservoir. The data for a given reservoir
may also change substantially over time as a result of numerous
factors including, but not limited to, additional development
activity, evolving production history and continual reassessment of
the viability of production under varying economic conditions.
Consequently, material revisions (upward or downward) to
existing reserve estimates may occur from time to time. Although
reasonable effort is made to ensure that reserve estimates reported
represent the most accurate assessments possible, the significance
of the subjective decisions required and variances in available
data for various reservoirs make these estimates generally less
precise than other estimates presented in connection with financial
statement disclosures.
Proved
reserves
. Reserves of oil and
natural gas that have been proved to a high degree of certainty by
analysis of the producing history of a reservoir and/or by
volumetric analysis of adequate geological and engineering
data.
Proved developed
reserves
. Proved reserves that
can be expected to be recovered through existing wells and
facilities and by existing operating methods.
Proved undeveloped
reserves or PUDs
. Proved
reserves that are expected to be recovered from new wells on
undrilled acreage or from existing wells where a relatively major
expenditure is required for recompletion.
94
PROVED RESERVE SUMMARY
All
of the Company’s reserves are located in the United States.
The following tables sets forth the changes in the Company’s
net proved reserves (including developed and undeveloped
reserves) for the years ended December 31, 2020 and 2019.
Reserves estimates as of December 31, 2020 were estimated by the
independent petroleum consulting firm Cawley, Gillespie &
Associates, Inc. The reserve report is incorporated herein by
reference to Exhibit 99.1 of the Annual Report on Form 10-K which
these financial statements are filed with.
|
|
December 31,
|
|
|
|
2020
|
2019
|
|
Crude Oil (MBbls)
|
|
|
|
Net
proved reserves at beginning of year
|
12,359
|
11,538
|
|
Revisions
of previous estimates
|
(17
)
|
105
|
|
Purchases
in place
|
-
|
1,083
|
|
Extensions,
discoveries and other additions
|
-
|
-
|
|
Sales
in place
|
-
|
(52
)
|
|
Production
|
(246
)
|
(315
)
|
|
Net
proved reserves at end of year
|
12,096
|
12,359
|
|
|
|
|
|
Natural Gas (Mmcf)
|
|
|
|
Net
proved reserves at beginning of year
|
9,746
|
5,283
|
|
Revisions
of previous estimates
|
2,348
|
4,071
|
|
Purchases
in place
|
-
|
742
|
|
Extensions,
discoveries and other additions
|
-
|
-
|
|
Sales
in place
|
-
|
(123
)
|
|
Production
|
(199
)
|
(227
)
|
|
Net
proved reserves at end of year
|
11,895
|
9,746
|
|
|
|
|
|
NGL (MBbbls)
|
|
|
|
Net
proved reserves at beginning of year
|
48
|
17
|
|
Revisions
of previous estimates
|
3
|
49
|
|
Purchases
in place
|
-
|
-
|
|
Extensions,
discoveries and other additions
|
-
|
-
|
|
Sales
in place
|
-
|
(3
)
|
|
Production
|
(17
)
|
(15
)
|
|
Net
proved reserves at end of year
|
34
|
48
|
|
|
|
|
|
Oil Equivalents (MBoe)
|
|
|
|
Net
proved reserves at beginning of year
|
14,032
|
12,435
|
|
Revisions
of previous estimates
|
377
|
832
|
|
Purchases
in place
|
-
|
1,207
|
|
Extensions,
discoveries and other additions
|
-
|
-
|
|
Sales
in place
|
-
|
(75
)
|
|
Production
|
(296
)
|
(367
)
|
|
Net
proved reserves at end of year
|
14,113
|
14,032
|
RESERVES
During
the year ended December 31, 2020, the Company’s reserves
increased by 0.1 MMBoe of proved reserves. Included in the
increase, the Company had a 0.4 MMBoe increase in proved developed
producing reserves resulting from proved developed non-producing
reserves moving into the proved developed producing reserves
category as the Company brought online several of its Phase II
development wells, this resulted in a decrease in its proved
developed non-producing reserves of 0.5 MMBoe. The Company also had
a 0.2 MMBoe increase in proved undeveloped reserves, noted
below.
95
The
following table sets forth the Company’s proved developed and
undeveloped reserves at December 31, 2020 and 2019,
respectively:
|
|
2020
|
2019
|
|
Proved Developed Reserves
|
|
|
|
Crude
Oil (MBbls)
|
1,243
|
938
|
|
Natural
Gas (Mmcf)
|
1,443
|
983
|
|
NGL
(MBbls)
|
34
|
48
|
|
Oil Equivalents (MMBoe)
|
1,518
|
1,151
|
|
|
|
|
|
Proved Developed Non-Producing Reserves
|
|
|
|
Crude
Oil (MBbls)
|
584
|
1,045
|
|
Natural
Gas (Mmcf)
|
588
|
619
|
|
NGL
(MBbls)
|
-
|
-
|
|
Oil Equivalents (MMBoe)
|
682
|
1,148
|
|
|
|
|
|
Proved Undeveloped Reserves
|
|
|
|
Crude
Oil (MBbls)
|
10,269
|
10,376
|
|
Natural
Gas (Mmcf)
|
9,864
|
8,144
|
|
NGL
(MBbls)
|
-
|
-
|
|
Oil Equivalents (MMBoe)
|
11,913
|
11,733
|
|
|
|
|
|
Proved Reserves
|
|
|
|
Crude
Oil (MBbls)
|
12,096
|
12,359
|
|
Natural
Gas (Mmcf)
|
11,895
|
9,747
|
|
NGL
(MBbls)
|
34
|
48
|
|
Oil Equivalents (MMBoe)
|
14,113
|
14,032
|
Proved Undeveloped Reserves
For the
year ended December 31, 2020, total proved undeveloped reserves
(PUDs) increased by 0.2 MMBoe to 11.9 million MMBoe. The
change in proved undeveloped reserves was:
●
due
to increases in the type curves from the 2019 reserve report due to
historical outperformance of the 2019 type curves primarily in our
Chaveroo field in the Permian Basin; and
●
optimization
of our future development plans to focus on areas with the highest
remaining oil in place. The changes to the future development plan
were derived from technical work and studies of our Permian assets
since acquisition in 2018.
The
Company’s plan is to convert its remaining PUD balance as of
December 31, 2020 to proved developed reserves within five years or
prior to the end of fiscal year 2025, provided that we are able to
obtain adequate funding and capital over the time
period.
Capitalized Costs Relating to
Oil and Natural Gas Producing Activities
. The following table sets forth the capitalized
costs relating to the Company’s crude oil and natural gas
producing activities at December 31, 2020 and 2019 (in
thousands):
|
|
2020
|
2019
|
|
Proved
oil and gas properties
|
$
148,062
|
$
123,607
|
|
Unproved
oil and gas properties
|
-
|
-
|
|
Total oil & gas properties
|
148,062
|
123,607
|
|
Accumulated
depreciation and depletion and impairment
|
(81,064
)
|
(31,759
)
|
|
Net Capitalized Costs
|
$
66,998
|
$
91,848
|
96
Costs Incurred in Oil and
Natural Gas Property Acquisition, Exploration and Development
Activities
. The following table
sets forth the costs incurred in the Company’s oil and
natural gas property acquisition, exploration and development
activities for the years ended December 31, 2020 and 2019 (in
thousands):
|
|
2020
|
2019
|
|
Acquisition
of properties
|
|
|
|
Proved
|
$
157
|
$
1,120
|
|
Unproved
|
-
|
-
|
|
Exploration
costs
|
-
|
-
|
|
Development
costs
|
5,786
|
41,810
|
|
Total
|
$
5,943
|
$
42,930
|
Results of Operations for Oil
and Natural Gas Producing Activities
. The following table sets forth the results of
operations for oil and natural gas producing activities for the
years ended December 31, 2020 and 2019 (in
thousands):
|
|
2020
|
2019
|
|
Crude
oil and natural gas revenues
|
$
8,059
|
$
12,972
|
|
Production
costs
|
(4,435
)
|
(6,817
)
|
|
Depreciation
and depletion and impairment
|
(30,354
)
|
(11,031
)
|
|
Results of operations for producing activities, excluding corporate
overhead and interest costs
|
$
(26,730
)
|
$
(4,876
)
|
Standardized Measure of
Discounted Future Net Cash Flows Relating to Proved Oil and Natural
Gas Reserves.
The following
information has been developed utilizing procedures prescribed by
ASC Topic 932 and based on crude oil and natural gas reserves and
production volumes estimated by the independent petroleum
consultants of the Company. The estimates were based on a 12-month
average of first-of-the-month commodity prices for the years ended
December 31, 2020 and 2019. The following information may
be useful for certain comparison purposes, but should not be solely
relied upon in evaluating the Company or its performance. Further,
information contained in the following table should not be
considered as representative of realistic assessments of future
cash flows, nor should the Standardized Measure of Discounted
Future Net Cash Flows be viewed as representative of the current
value of the Company.
The
future cash flows presented below are based on cost rates and
statutory income tax rates in existence as of the date of the
projections and average prices over the preceding twelve months. It
is expected that material revisions to some estimates of crude oil
and natural gas reserves may occur in the future, development and
production of the reserves may occur in periods other than those
assumed, and actual prices realized and costs incurred may vary
significantly from those used.
Management
does not rely upon the following information in making investment
and operating decisions. Such decisions are based upon a wide range
of factors, including estimates of probable and possible as well as
proved reserves, and varying price and cost assumptions considered
more representative of a range of possible economic conditions that
may be anticipated.
The
following table sets forth the standardized measure of discounted
future net cash flows from projected production of the
Company’s oil and natural gas reserves as of December 31,
2012 and 2019 (in thousands):
|
|
2020
|
2019
|
|
Future
cash inflows
|
$
483,461
|
$
696,130
|
|
Future
production costs
|
(180,211
)
|
(272,623
)
|
|
Future
development costs
|
(140,963
)
|
(174,401
)
|
|
Future
income taxes
|
(6,856
)
|
(47,797
)
|
|
Future
net cash flows
|
155,431
|
201,309
|
|
Discount
to present value at 10% annual rate
|
(98,156
)
|
(97,546
)
|
|
Standardized
measure of discounted future net
|
|
|
|
cash
flows relating to proved oil and gas
|
|
|
|
reserves
|
$
57,275
|
$
103,763
|
97
Changes in Standardized
Measure of Discounted Future Net Cash Flows.
The following table sets forth the changes in the
standardized measure of discounted future net cash flows for each
of the years ended December 31, 2020 and 2019 (in
thousands):
|
|
2020
|
2019
|
|
Standardized
measure, beginning of year
|
$
103,763
|
$
130,818
|
|
Crude
oil and natural gas sales, net of production costs
|
(6,656
)
|
(3,406
)
|
|
Net
changes in prices and production costs
|
(57,483
)
|
(64,318
)
|
|
Extensions,
discoveries, additions and improved recovery
|
-
|
-
|
|
Changes
in estimated future development costs
|
12,002
|
37,149
|
|
Development
costs incurred
|
-
|
-
|
|
Revisions
of previous quantity estimates
|
1,510
|
(2,622
)
|
|
Accretion
of discount
|
(13,249
)
|
(37,109
)
|
|
Net
change in income taxes
|
18,006
|
31,494
|
|
Purchases
of reserves in place
|
-
|
12,343
|
|
Sales
of reserves in place
|
-
|
(1,483
)
|
|
Change
in timing of estimated future production
|
(618
)
|
897
|
|
Standardized
measure, end of year
|
$
57,275
|
$
103,763
|
98
ITEM 9.
C
HANGES IN AND DISAGREEMENTS
WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
DISCLOSURE.
None.
ITEM 9A.
C
ONTROLS AND
PROCEDURES.
Disclosure Controls and Procedures
Disclosure controls
and procedures are designed to ensure that information required to
be disclosed in our reports filed or submitted under the Exchange
Act is recorded, processed, summarized and reported, within the
time period specified in the SEC’s rules and forms and is
accumulated and communicated to the Company’s management, as
appropriate, in order to allow timely decisions in connection with
required disclosure.
Evaluation of Disclosure Controls and Procedures
Under
the supervision and with the participation of our management,
including our Chief Executive Officer (“
CEO
”) and Chief
Accounting Officer (“
CAO
”), we conducted an
evaluation of the effectiveness of the design and operation of our
disclosure controls and procedures, as defined in Rules 13a-15(e)
and 15d-15(e) under the Exchange Act as of the end of the
period covered by this Annual Report. Based on this evaluation, our
CEO and CAO concluded as of December 31, 2020, that our disclosure
controls and procedures were effective.
Management’s Report on Internal Control Over Financial
Reporting
Management of the
Company is responsible for establishing and maintaining adequate
internal control over financial reporting as defined in Rules
13a-15(f) and 15d-15(f) under the Exchange Act. The
Company’s internal control over financial reporting is
designed to provide reasonable assurance regarding the reliability
of financial reporting and the preparation of financial statements
for external purposes in accordance with GAAP, but because of its
inherent limitations, internal control over financial reporting may
not prevent or detect misstatements. The Company’s internal
control over financial reporting includes those policies and
procedures that are designed to:
|
|
●
|
pertain
to the maintenance of records that, in reasonable detail,
accurately and fairly reflect the transactions and dispositions of
the assets of the Company;
|
|
|
|
|
|
|
●
|
provide
reasonable assurance that transactions are recorded as necessary to
permit preparation of financial statements in accordance with GAAP,
and that receipts and expenditures of the Company are being made
only in accordance with authorizations of management and directors
of the Company; and
|
|
|
|
|
|
|
●
|
provide
reasonable assurance regarding prevention or timely detection of
unauthorized acquisition, use or disposition of the Company’s
assets that could have a material effect on the financial
statements.
|
Management assessed
the effectiveness of the Company’s internal control over
financial reporting as of December 31, 2020. In making this
assessment, management used the criteria set forth by the Committee
of Sponsoring Organizations of the Treadway Commission (COSO) in
Internal Control— Integrated Framework (2013). Based on our
assessment, management believes that the Company’s internal
controls over financial reporting were effective as of December 31,
2020.
Changes in Internal Control Over Financial Reporting
There
were no changes in our internal controls over financial reporting
during the year ended December 31, 2020 that have materially
affected or are reasonably likely to materially affect, our
internal controls over financial reporting, including any
corrective actions with regard to significant deficiencies and
material weaknesses.
99
As a
result of COVID-19, our workforce has operated primarily in a work
from home environment for the quarter ended December 31, 2020.
While pre-existing controls were not specifically designed to
operate in our current work from home operating environment, we
don’t believe that such work from home actions have had a
material adverse effect on our internal controls over financial
reporting. We have continued to re-evaluate and refine our
financial reporting process to provide reasonable assurance that we
could report our financial results accurately and
timely.
Limitations on the Effectiveness of Controls
The
Company’s disclosure controls and procedures are designed to
provide the Company’s Chief Executive Officer and Chief
Accounting Officer with reasonable assurances that the
Company’s disclosure controls and procedures will achieve
their objectives. However, the Company’s management does not
expect that the Company’s disclosure controls and procedures
or the Company’s internal control over financial reporting
can or will prevent all human error. A control system, no matter
how well designed and implemented, can provide only reasonable, not
absolute, assurance that the objectives of the control system are
met. Furthermore, the design of a control system must reflect the
fact that there are internal resource constraints, and the benefit
of controls must be weighed relative to their corresponding costs.
Because of the limitations in all control systems, no evaluation of
controls can provide complete assurance that all control issues and
instances of error, if any, within the Company’s company are
detected. These inherent limitations include the realities that
judgments in decision-making can be faulty, and that breakdowns can
occur due to human error or mistake. Additionally, controls, no
matter how well designed, could be circumvented by the individual
acts of specific persons within the organization. The design of any
system of controls is also based in part upon certain assumptions
about the likelihood of future events, and there can be no
assurance that any design will succeed in achieving its stated
objectives under all potential future conditions.
Attestation Report of the Registered Public Accounting
Firm
This
report does not include an attestation report of our registered
public accounting firm regarding our internal controls over
financial reporting. Under SEC rules, such attestation is not
required for smaller reporting companies such as the
Company.
ITEM 9B.
O
THER
INFORMATION.
Because
this Annual Report on Form 10-K is being filed within four business
days from the date of the reportable events, we have elected to
make the following disclosures in this Annual Report on Form 10-K
instead of in a Current Report on Form 8-K under
Items 1.01
and
2.01
, as
applicable:
Item 1.01 Entry into a Material Definitive Agreement.
On
March 18, 2021, the Company, through its wholly-owned subsidiary
Red Hawk, consummated the sale of certain assets and associated
liabilities located in its D-J Basin Asset to DJ Homestead, LLC and
Petro Operating Company, LLC (collectively, the “
Buyer
”) pursuant to a
Purchase and Sale Agreement, dated December 29, 2019, entered into
by and among Red Hawk and the Buyer. The assets conveyed by
Red Hawk to the Buyer in the transaction included approximately 230
net acres located in the Company’s D-J Basin Asset and Red
Hawk’s interests in three non-operated wells located in the
D-J Basin Asset, which currently produce approximately 105
Boepd. The effective date of the transaction ranged between
December 1, 2018 and December 1, 2019 depending upon the specific
assets sold, and the aggregate purchase price received by Red Hawk
at closing was $4,821,343 in cash, which included $3,034,850 in
reimbursements to Red Hawk for expenses previously paid by Red Hawk
as a participant in these three non-operated wells and other
expenses previously paid related to these assets, reduced by
$2,950,097 for revenue previously received by Red Hawk with respect
to these wells following the effective date through closing, for
net cash received by Red Hawk at closing of $1,871,246. The
final purchase price is further subject to customary post-closing
adjustments.
100
The description of the Purchase and Sale Agreement above is
qualified in its entirety by reference to the Purchase and Sale
Agreement and Closing Letter, copies of which are filed herewith as
Exhibits 10.37
and
10.38
,
respectively.
Item 2.01 Completion of Acquisition or Disposition of
Assets.
The disclosures in “
Item 9B. Other Information—Item
1.01
”, are incorporated by reference into this
Item 2.01
in their
entirety.
101
PART III
Information about our Executive Officers and Directors
The
following table sets forth the name, age and position held by each
of our executive officers and directors. Directors are elected for
a period of one year and thereafter serve until the next annual
meeting at which their successors are duly elected by the
shareholders.
|
Name
|
|
Age
|
|
Position
|
|
|
|
|
|
|
|
John J.
Scelfo
|
|
63
|
|
Chairman
of the Board
|
|
Simon
Kukes
|
|
74
|
|
Chief
Executive Officer and Director
|
|
J.
Douglas Schick
|
|
45
|
|
President
|
|
Paul
Pinkston
|
|
53
|
|
Chief
Accounting Officer
|
|
Clark
R. Moore
|
|
48
|
|
Executive
Vice President, General Counsel and Secretary
|
|
Ivar
Siem
|
|
74
|
|
Director
|
|
H.
Douglas Evans
|
|
72
|
|
Director
|
There
is no arrangement or understanding between our directors and
executive officers and any other person pursuant to which any
director or officer was or is to be selected as a director or
officer, and there is no arrangement, plan or understanding as to
whether non-management shareholders will exercise their voting
rights to continue to elect the current board of directors (the
“
Board
”). There are also
no arrangements, agreements or understandings to our knowledge
between non-management shareholders that may directly or indirectly
participate in or influence the management of our
affairs.
Business Experience
The
following is a brief description of the business experience and
background of our current directors and executive officers. There
are no family relationships among any of the directors or executive
officers.
John J. Scelfo, Chairman of the Board (Director since July
2018)
Mr.
Scelfo brings over 40 years of experience in oil and gas
management, finance and accounting to the PEDEVCO Board. Mr. Scelfo
currently serves as principal and owner of JJS Capital Group, a
Fort Lauderdale, Florida-based family investment company that he
formed in April 2014. Prior to forming JJS Capital, Mr. Scelfo was
Senior Vice President, Finance and Corporate Development (from
February 2004 to March 2014), and Chief Financial Officer,
Worldwide Exploration & Producing (from April 2003 to January
2004) of New York, New York-based Hess Corporation, a large
integrated oil and gas company, where he served as one of eight
members of the company’s Executive Committee and was
responsible for the company’s corporate treasury, strategy
and upstream commercial activities. Prior to joining Hess
Corporation, Mr. Scelfo served as Executive Vice President and
Chief Financial Officer of publicly listed Sirius Satellite Radio
(from April 2001 to March 2003), as Vice President and Chief
Financial Officer of Asia Pacific & Japan for Dell Computer
(November 1999 to March 2001), and in various roles of increasing
responsibility with Mobil Corporation (from June 1980 to October
1999).
Mr.
Scelfo holds a bachelor’s degree and an M.B.A. from Cornell
University. In 2011, he was awarded Cornell ILR School’s
Alpern Award given to those who “have been exceedingly
generous in their support of the ILR School in general and in
support of Off-Campus Credit Programs in
particular.”
Simon Kukes, Chief Executive Officer and Director (Chief Executive
and Director since July 2018)
Simon
Kukes is a globally renowned consultant for oil and gas businesses
in both the United States and Russia.
102
Holding
various positions over the years, Kukes has served as the principal
of his personal investment company, SK Energy LLC, since April
2013. From January 2005 to April 2013, Kukes was the CEO at
Samara-Nafta, a Russian oil company that partnered with US-based
international oil company, Hess Corporation. He was also the
President and Chief Executive of Tyumen Oil Company (TNK) from 1998
until it combined with British Petroleum in 2003 to create TNK-BP.
Following his time at TNK, Kukes joined Yukos Oil Company in Moscow
presiding as the CEO and Chairman. From 1979 to 1986 he was the
Technical Director of oil-refining and petro-chemistry for Phillips
Petroleum and in 1986 joined Amoco and in 1993 became
Vice-President over marketing and business development for Amoco.
Since October 2014, Kukes has served on the board of directors of
Leverate Technological Trading Ltd., an Israel-based technology and
services provider in the brokerage industry, since June 2014 he has
served on the board of directors of Fletschhorn, a Swiss-based
hotel and restaurant company, and since June 2018 he has served on
the board of directors of GLAMZ Ltd., a privately-held Israel-based
beauty products and salon booking platform company.
Kukes
boasts several awards and achievements over his lifespan. In 1999,
the Wall Street Journal voted Kukes as one of the Top 10 Central
European Executives. He is also the recipient of the Medal of the
Ministry for Natural Resources of the Russian Federation, as well
as the American Society of Competition Development Award for
Leadership. In 2003, he was named by The Financial Times and
PricewaterhouseCoopers as one of the 64 most respected business
leaders in the world.
Kukes
attended several prestigious universities all over the globe,
receiving his Bachelor of Science in Chemical Engineering from the
University for Chemical Technology in Moscow, where he graduated
with Honors. From there, he pursued his PhD in Physical Chemistry
at the Academy of Sciences in Moscow, where he would later be a
Research Associate for Nuclear and Electronic Resonance. Kukes then
attended Rice University in Houston, Texas, where he was a
Postdoctoral Fellow. Kukes has also served as an Adjunct Professor
at the University of Delaware and on the Editorial Board of Fuel
Magazine.
His
commitment to the oil and gas industry has inspired Kukes to
publish more than 60 scientific papers and two books on the oil and
gas industry of Russia and the United States. Kukes is also the
holder of more than 130 patents, primarily in Oil and Petrochemical
Processing.
J. Douglas Schick, President
Mr.
Schick has over twenty years of experience in the oil and gas
industry. Prior to joining the Company as President on August 1,
2018, Mr. Schick was employed by American Resources, Inc., a
Houston, Texas-based privately-held oil and gas investment,
development and operating company which he co-founded and continues
to serve as Chief Executive Officer (from August 2017 to the
present) and formerly as Chief Financial Officer and Vice
President of Business Development (from August 2013 to August
2017), provided that Mr. Schick’s service to American
Resources requires only minimal time commitment from Mr. Schick
that does not conflict with his duties and responsibilities to the
Company. Prior to starting American Resources, Mr. Schick served as
the founder, owner and principal of J. Douglas Enterprises, a
Houston, Texas-based energy industry focused business development
and financial consulting firm (from June 2011 to August
2013) as Vice President of Finance (from January 2011 until
its sale in June 2011) for Highland Oil and Gas, a private
equity-backed E&P company headquartered in Houston, Texas, as
Manager of Planning and then Director of Planning at Houston,
Texas-based Mariner Energy, Inc. (from December 2006 until its
merger with Apache Corp. in December 2010), and in various roles of
increasing responsibility in finance, planning, M&A, treasury
and accounting at The Houston Exploration Company, ConocoPhillips
and Shell Oil Company (from 1998 to 2006). Mr. Schick current
serves on the Board of Directors of Rockdale Marcellus, LLC, a
Houston, Texas-based subsidiary of Rockdale Energy, LLC engaged in
the development of natural gas in Northeastern
Pennsylvania.
Mr.
Schick holds a BBA in Finance from New Mexico State University and
an MBA with a specialization in Finance from Tulane
University.
103
Paul A. Pinkston, Chief Accounting Officer
Mr.
Pinkston brings over 20 years of accounting, compliance, and
financial reporting expertise to the Company, with extensive
experience in handling and managing corporate compliance, financial
reporting and audits, and other regulatory functions for companies
engaged in the oil and gas industry in the U.S. Prior to
joining the Company on December 1, 2018, from August 2017 to
February 2018, Mr. Pinkston served as Corporate Controller and
Secretary for Trecora Resources (NYSE: TREC), a Sugar Land,
Texas-based petrochemical manufacturing and customer processing
service company. Prior to joining Trecora Resources, from May
2013 to June 2017, Mr. Pinkston served in various roles of
increasing authority and responsibility at Camber Energy, Inc.
(NYSE American: CEI), a Houston, Texas-based oil and gas
exploration and production company, including as Camber
Energy’s Chief Accounting Officer, Secretary and Treasurer
(August 2016 to June 2017), and as its Director of Financial
Reporting (May 2013 to August 2016). Before joining Camber
Energy, Mr. Pinkston served as a Senior Consultant with Sirius
Solutions LLLP, where he performed accounting, audit and finance
consulting services (January 2006 to May 2013), as a Corporate
Auditor performing internal audits for Baker Hughes, Inc. (January
2002 to November 2005), and as a Senior Auditor, conducting public
and private audits, at Arthur Andersen LLP (from September 1998 to
November 2001).
Mr.
Pinkston received a Bachelor of Business Administration (Finance
and Marketing) degree from the University of Texas and earned
a Master of Business Administration (Accounting) degree from
the University of Houston. Mr. Pinkston is a Certified Public
Accountant registered in the State of Texas.
Clark R. Moore, Executive Vice President, General Counsel and
Secretary
Mr.
Moore has served as the Executive Vice President, General Counsel,
and Secretary of Pacific Energy Development since its inception in
February 2011, and has served as the Executive Vice President,
General Counsel, and Secretary of the Company since its acquisition
of Pacific Energy Development in July 2012. Mr. Moore began his
career in 2000 as a corporate attorney at the law firm of Venture
Law Group located in Menlo Park, California, which later merged
into Heller Ehrman LLP in 2003. In 2004, Mr. Moore left Heller
Ehrman LLP and launched a legal consulting practice focused on
representation of private and public company clients in the energy
and high-tech industries. In September 2006, Mr. Moore joined Erin
Energy Corporation (OTCMKTS:ERN) (formerly CAMAC Energy, Inc.), an
independent energy company headquartered in Houston, Texas, as its
acting General Counsel and continued to serve in that role through
February 2011, when he left to serve as a co-founder of Pacific
Energy Development. In addition, since June 1, 2018, Mr. Moore has
served as a partner at Foundation Law Group, LLP.
Mr.
Moore received his J.D. with Distinction from Stanford Law School
and his B.A. with Honors from the University of
Washington.
Ivar Siem, Director (Director since July 2018)
Mr.
Siem has broad experience from both the upstream and the service
segments of the oil and gas industry, has been the founder of
several companies, and has been involved in several roll-ups and
restructuring processes throughout his career. He currently serves
as the Chairman of American Resources, Inc., and as a Managing
Partner of its affiliated investment vehicle, Norexas, LLC, both
privately held Houston, Texas-based companies active in oil and gas
investment, acquisition and development and has served in that
capacity since 2013. Previously, Mr. Siem served as Chairman and
Chief Executive Officer of American Resources, Inc. (from 2013
through July 2017) and Chairman of Blue Dolphin Energy Company
(OTCQX: BDCO), Houston, Texas after taking the company out of
bankruptcy in 1990. Blue Dolphin was an offshore Gulf of Mexico
operator until a merger in 2012 with an independent refiner and
marketer of petroleum products. Mr. Siem’s role as CEO ended
with the merger and he left the board in 2014. From January 2007 to
present, Mr. Siem served as President of Drillmar Oil and Gas,
Inc., a subsidiary of Drillmar Energy, Inc. In 1999, Mr. Siem
acquired a small distressed public company, American Resources
Offshore, Inc. and worked with creditors and existing management to
achieve a voluntary reorganization. From 1995 to 2000, Mr. Siem
served as Chairman and interim CEO of DI Industries/Grey Wolf
Drilling while restructuring the company financially and
operationally. Through several mergers and acquisitions, the
company emerged as one of the leading land drilling contractors in
the US. The company was subsequently acquired by Precision Drilling
in 2008. From 1996 to 1997 Mr. Siem served as the initial Chairman
and CEO of Seateam Technology ASA when it was spun off from DSND
ASA and listed on the Oslo exchange. Prior to Seateam, Mr. Siem
held various executive roles at multiple E&P and oil field
service companies. Mr. Siem started his career at Amoco working as
an engineer in various segments of upstream
operations.
104
Mr.
Siem is currently on the Board of Directors at Siem Industries,
Inc., the Drillmar Energy Group of companies, and Petrolia Energy
Corporation (OTCQB: BBLS), and has served on the board of several
privately held and publicly traded companies including Frupor SA,
Avenir ASA, and DSND ASA. Siem Industries is a holding company
which invests in shipping and offshore oil and gas construction
services. Frupor SA, is a Portuguese agricultural business, which
Mr. Siem cofounded with his brother O. M. Siem in
1988.
Mr.
Siem holds a Bachelor of Science in Mechanical Engineering with a
minor in Petroleum from the University of California, Berkeley and
an Executive MBA from the Amos Tuck School of Business, Dartmouth
University.
H. Douglas Evans, Director (Director since September
2018)
Mr.
Evans has 50 years of oil and gas industry experience, 40 years of
which have been spent in various executive management positions
with Gulf Interstate Engineering Company (“
GIE
”), a privately-held
Houston, Texas-based firm specializing in the engineering of oil,
gas and liquid pipeline systems, where he has served as Honorary
Chairman since November 2017, and previously served as President
and Chief Executive Officer (July 2004-November 2017), President
(February 2003-November 2017), Senior Vice President (September
1994-July 2004), and in various other roles since he joined the
company in 1978. During Mr. Evans’ tenure as an executive at
GIE, he has successfully overseen the company’s organic
growth from $25 million in sales in 1996 to over $250 million in
sales in recent years, with GIE involved in almost every major
onshore oil and gas pipeline in the world over the last 20
years.
Mr.
Evans holds a B.S. Civil Engineering and Master of Business
Administration from Queen’s University at Kingston, Ontario,
and is a registered Professional Engineer in Ontario and Alberta,
Canada. Mr. Evans currently serves as Honorary Chairman of GIE
(since November 2017), and previously a member of the Board of
Directors of Gulf Interstate Field Services, a GIE affiliate
engaged in providing oil and gas pipeline construction inspection
services, and a number of other GIE affiliated companies, the Board
of Directors and Chairman of the Strategy Committee for the
International Pipe Line and Offshore Contractors Association
(IPLOCA) (through September 2019), a member of the Board of
Houston, Texas-based Crossroads School, Inc. (since 2004), and a
former member of the Board of the Cystic Fibrosis Foundation
– Texas Gulf Coast Chapter.
Director Qualifications
The
Board believes that each of our directors is highly qualified to
serve as a member of the Board. Each of the directors has
contributed to the mix of skills, core competencies and
qualifications of the Board. When evaluating candidates for
election to the Board, the Board seeks candidates with certain
qualities that it believes are important, including integrity, an
objective perspective, good judgment, and leadership skills. Our
directors are highly educated and have diverse backgrounds and
talents and extensive track records of success in what we believe
are highly relevant positions.
Family Relationships
None of
our directors are related by blood, marriage, or adoption to any
other director, executive officer, or other key
employees.
Arrangements between Officers and Directors
There
is no arrangement or understanding between our directors and
executive officers and any other person pursuant to which any
director or officer was or is to be selected as a director or
officer. There are also no arrangements, agreements or
understandings to our knowledge between non-management shareholders
that may directly or indirectly participate in or influence the
management of our affairs.
105
Other Directorships
Other
than Mr. Siem, who currently serves on the Board of Directors of
Petrolia Energy Corporation, (OTCQB: BBLS), no directors of the
Company are also directors of issuers with a class of securities
registered under Section 12 of the Exchange Act (or which otherwise
are required to file periodic reports under the Exchange
Act).
Involvement in Certain Legal Proceedings
To the best of our
knowledge, during the
past ten years, none of our directors or executive officers were
involved in any of the following: (1) any bankruptcy
petition filed by or against any business of which such person was
a general partner or executive officer either at the time of the
bankruptcy or within two years prior to that time; (2) any
conviction in a
criminal proceeding or
being a named subject to a pending criminal proceeding (excluding
traffic violations and other minor offenses); (3) being
subject to any order, judgment, or decree, not subsequently
reversed, suspended or vacated, of any court of competent
jurisdiction, permanently or temporarily enjoining, barring,
suspending or otherwise limiting his involvement in any type of
business, securities or banking activities; (4) being found by
a court of competent jurisdiction (in a civil action), the SEC or
the Commodities Futures Trading Commission to have violated a
federal or state securities or commodities law; (5) being the
subject of, or a party to, any Federal or State judicial or
administrative order, judgment, decree, or finding, not
subsequently reversed, suspended or vacated, relating to an alleged
violation of (i) any Federal or State securities or
commodities law or regulation; (ii) any law or regulation
respecting financial institutions or insurance companies including,
but not limited to, a temporary or permanent injunction, order of
disgorgement or restitution, civil money penalty or temporary or
permanent cease-and-desist order, or removal or prohibition order;
or (iii) any law or regulation prohibiting mail or wire fraud
or fraud in connection with any business entity; or (6) being
the subject of, or a party to, any sanction or order, not
subsequently reversed, suspended or vacated, of any self-regulatory
organization (as defined in Section 3(a)(26) of the Exchange
Act), any registered entity (as defined in Section 1(a)(29) of
the Commodity Exchange Act), or any equivalent exchange,
association, entity or organization that has disciplinary authority
over its members or persons associated with a
member.
Board Leadership Structure
Our board of directors has the responsibility for
selecting our appropriate leadership structure. In making
leadership structure determinations, the board of directors
considers many factors, including the specific needs of our
business and what is in the best interests of our shareholders. Our
current leadership structure is comprised of a separate Chairman of
the board of directors and Chief Executive Officer
("
CEO
"). Mr. John J. Scelfo serves as Chairman and
Simon Kukes serves as CEO. The board of directors does not have a
policy as to whether the Chairman should be an independent
director, an affiliated director, or a member of management. Our
board of directors believes that the Company’s current
leadership structure is appropriate because it effectively
allocates authority, responsibility, and oversight between
management (the Company’s CEO, Simon Kukes) and the
members of our board of directors. It does this by giving primary
responsibility for the operational leadership and strategic
direction of the Company to its CEO, while enabling our Chairman to
facilitate our board of directors’ oversight of management,
promote communication between management and our board of
directors, and support our board of directors’ consideration
of key governance matters. The board of directors believes that its
programs for overseeing risk, as described below, would be
effective under a variety of leadership frameworks and therefore do
not materially affect its choice of structure.
Risk Oversight
Effective risk
oversight is an important priority of the board of directors.
Because risks are considered in virtually every business decision,
the board of directors discusses risk throughout the year generally
or in connection with specific proposed actions. The board of
directors’ approach to risk oversight includes understanding
the critical risks in our business and strategy, evaluating our
risk management processes, allocating responsibilities for risk
oversight among the full board of directors, and fostering an
appropriate culture of integrity and compliance with legal
responsibilities.
106
The
board of directors exercises direct oversight of strategic risks to
us. Our Audit Committee reviews and assesses our processes to
manage business and financial risk and financial reporting risk. It
also reviews our policies for risk assessment and assesses steps
management has taken to control significant risks. Our Compensation
Committee oversees risks relating to compensation programs and
policies. In each case management periodically reports to our board
of directors or the relevant committee, which provides the relevant
oversight on risk assessment and mitigation.
Director Independence
Our
board of directors has determined that Mr. Scelfo and Mr. Evans are
independent directors as defined in the NYSE American rules
governing members of boards of directors and as defined under Rule
10A-3 of the Exchange Act. Accordingly, 50% of the members of our
board of directors are independent as defined in the NYSE American
rules governing members of boards of directors and as defined under
Rule 10A-3 of the Exchange Act.
Committees of our Board of Directors
On
September 5, 2013, and effective September 10, 2013, the board of
directors adopted charters for the Nominating and Corporate
Governance Committee, Compensation Committee and Audit Committee.
We currently maintain a Nominating and Corporate Governance
Committee, Compensation Committee and Audit Committee.
The
committees of the Board of Directors consist of the following
members as of the date of this filing:
|
Director
|
|
Audit Committee
|
|
Compensation Committee
|
|
Nominating and Corporate Governance Committee
|
|
Independent
|
|
Simon Kukes
|
|
|
|
|
|
|
|
|
|
Ivar Siem
|
|
|
|
|
|
|
|
|
|
John J. Scelfo (1)
|
|
C
|
|
C
|
|
M
|
|
X
|
|
H. Douglas Evans
|
|
M
|
|
M
|
|
C
|
|
X
|
C - Chairman of Committee.
M – Member.
(1) – Chairman of the board of directors.
Each of
these committees has the duties described below and operates under
a charter that has been approved by our board of directors and is
posted on our website. Our website address is
http://www.PEDEVCO.com
.
Information contained on our website is expressly not incorporated
by reference into this Annual Report.
Audit
Committee
The audit committee selects, on behalf of our
board of directors, an independent public accounting firm to audit
our financial statements, discusses with the independent auditors
their independence, reviews and discusses the audited financial
statements with the independent auditors and management, and
recommends to the board of directors whether the audited financial
statements should be included in our annual reports to be filed
with the SEC. Mr. Scelfo serves as Chair of the Audit Committee and
our board of directors has determined that Mr. Scelfo is an
“
audit committee
financial expert
” as
defined under Item 407(d)(5) of Regulation S-K of the Exchange
Act.
During
the year ended December 31, 2020, the audit committee held four
meetings.
107
Compensation
Committee
The
compensation committee reviews and approves (a) the annual
salaries and other compensation of our executive officers, and
(b) individual stock and stock option grants. The compensation
committee also provides assistance and recommendations with respect
to our compensation policies and practices and assists with the
administration of our compensation plans.
Mr. Scelfo
serves as Chair of the
compensation committee.
During
the year ended December 31, 2020, the compensation committee held
three meetings.
Nominating
and Corporate Governance Committee
The
nominating and corporate governance committee assists our board of
directors in fulfilling its responsibilities by: identifying and
approving individuals qualified to serve as members of our board of
directors, selecting director nominees for our annual meetings of
shareholders, evaluating the performance of our board of directors,
and developing and recommending to our board of directors corporate
governance guidelines and oversight procedures with respect to
corporate governance and ethical conduct.
Mr. Scelfo
serves as Chair of the
nominating and corporate governance committee.
The
nominating and governance committee of the board of directors
considers nominees for director based upon a number of
qualifications, including their personal and professional
integrity, ability, judgment, and effectiveness in serving the
long-term interests of our shareholders. There are no specific,
minimum or absolute criteria for membership on the board of
directors. The committee makes every effort to ensure that the
board of directors and its committees include at least the required
number of independent directors, as that term is defined by
applicable standards promulgated by the NYSE
American
and/or the SEC.
The
nominating and governance committee may use its network of contacts
to compile a list of potential candidates. The nominating and
governance committee has not in the past relied upon professional
search firms to identify director nominees but may engage such
firms if so desired. The nominating and governance committee may
meet to discuss and consider candidates’ qualifications and
then choose a candidate by majority vote.
The
nominating and governance committee will consider qualified
director candidates recommended in good faith by shareholders,
provided those nominees meet the requirements of NYSE
American
and applicable federal securities
law. The nominating and governance committee’s evaluation of
candidates recommended by shareholders does not differ materially
from its evaluation of candidates recommended from other
sources. The Committee will consider candidates recommended by
shareholders if the information relating to such candidates are
properly submitted in writing to the Secretary of the Company in
accordance with the manner described for shareholder proposals
under “
Stockholder
Proposals for 2021 Annual Meeting of Stockholders and 2021 Proxy
Materials
” on page 38 of our
definitive proxy
statement
for the 2020 Annual Meeting of stockholders.
Individuals recommended by stockholders in accordance with these
procedures will receive the same consideration received by
individuals identified to the Committee through other
means.
During
the year ended December 31, 2020, the nominating and corporate
governance committee held one meeting.
Insider Trading/Anti-Hedging Policies
All
employees, officers and directors of, and consultants and
contractors to, us or any of our subsidiaries are subject to our
Insider Trading Policy. The policy prohibits the unauthorized
disclosure of any nonpublic information acquired in the workplace
and the misuse of material nonpublic information in securities
trading. The policy also includes specific anti-hedging
provisions.
To ensure compliance with the policy and
applicable federal and state securities laws, all individuals
subject to the policy must refrain from the purchase or sale of our
securities except in designated trading windows or pursuant to
preapproved 10b5-1 trading plans. Even during a trading window
period, certain identified insiders, which include the named
executive officers and directors, must comply with our designated
pre-clearance policy prior to trading in our securities. The
anti-hedging provisions prohibit all employees, officers and
directors from engaging in “
short
sales
” of our securities
or from trading in options with maturities less than nine months on
our stock.
Policy on Equity Ownership
The Company does not have a policy on equity
ownership at this time. However, as illustrated in the beneficial
ownership table under “
Item
12. Security Ownership of Certain Beneficial Owners and Management
and Related Stockholder Matters.
”, below, all Named Executive Officers and
directors are beneficial owners of stock of the
Company.
Compensation Recovery
Under the Sarbanes–Oxley Act of 2002 (the
“
Sarbanes-Oxley
Act
”), in the event of
misconduct that results in a financial restatement that would have
reduced a previously paid incentive amount, we can recoup those
improper payments from our Chief Executive Officer and Chief
Accounting Officer. We plan to implement a claw back policy in the
future, although we have not yet implemented such
policy.
Meetings of the Board of Directors and Annual Meeting
During the fiscal year that ended on December 31, 2020, the Board
held eleven meetings and took various other actions via the
unanimous written consent of the board of directors and the various
committees described above. All directors attended all of the board
of directors’ meetings and committee meetings relating to the
committees on which each director served during fiscal year 2020.
The Company held annual shareholders meetings on June 26, 2014,
October 7, 2015, December 28, 2016, December 28, 2017, September
27, 2018, August 28, 2019 and August 27, 2020, at which meetings
all directors were present in person or via teleconference. Each
director of the Company is expected to be present at annual
meetings of shareholders, absent exigent circumstances that prevent
their attendance. Where a director is unable to attend an annual
meeting in person but is able to do so by electronic conferencing,
the Company will arrange for the director’s participation by
means where the director can hear, and be heard, by those present
at the meeting.
Executive Sessions of the Board of Directors
The
independent members of our board of directors meet in executive
session (with no management directors or management
present) from time to time. The executive sessions include
whatever topics the independent directors deem
appropriate.
In
2012, in accordance with SEC rules, our board of directors adopted
a Code of Business Conduct and Ethics for our directors, officers
and employees. Our board of directors believes that these
individuals must set an exemplary standard of conduct. This code
sets forth ethical standards to which these persons must adhere and
other aspects of accounting, auditing and financial compliance, as
applicable. The Code of Business Conduct and Ethics is available on
our website at
www.PEDEVCO.com
.
Please note that the information contained on our website is not
incorporated by reference in, or considered to be a part of, this
Annual Report.
We
intend to disclose any amendments to our Code of Business Conduct
and Ethics and any waivers with respect to our Code of Business
Conduct and Ethics granted to our principal executive officer, our
principal financial officer, or any of our other employees
performing similar functions on our website at
www.pacificenergydevelopment.com, within four business days after
the amendment or waiver. In such case, the disclosure regarding the
amendment or waiver will remain available on our website for at
least 12 months after the initial disclosure. There have been
no waivers granted with respect to our Code of Business Conduct and
Ethics to any such officers or employees to date.
108
Shareholder Communications
Our
stockholders and other interested parties may communicate with
members of the board of directors by submitting such communications
in writing to our Corporate Secretary, 575 N. Dairy Ashford, Suite
210, Houston, Texas 77079 who, upon receipt of any communication
other than one that is clearly marked “Confidential,”
will note the date the communication was received, open the
communication, make a copy of it for our files and promptly forward
the communication to the director(s) to whom it is addressed.
Upon receipt of any communication that is clearly marked
“
Confidential,
” our
Corporate Secretary will not open the communication, but will note
the date the communication was received and promptly forward the
communication to the director(s) to whom it is addressed. If
the correspondence is not addressed to any particular board member
or members, the communication will be forwarded to a board member
to bring to the attention of the board of directors.
Delinquent Section 16(a) Reports
Section
16(a) of the Exchange Act requires our executive officers and
directors and persons who own more than 10% of a registered class
of our equity securities to file with the SEC initial statements of
beneficial ownership, reports of changes in ownership and annual
reports concerning their ownership in our common stock and other
equity securities, on Form 3, 4 and 5 respectively. Executive
officers, directors and greater than 10% stockholders are required
by the SEC regulations to furnish our company with copies of all
Section 16(a) reports they file.
Based
solely on our review of the copies of such reports received by us
and on written representation by our officers and directors
regarding their compliance with the applicable reporting
requirements under Section 16(a) of the Exchange Act, we
believe that all filings required to be made under Section
16(a) during 2020 were timely made.
Compensation of Executive Officers
The
following table sets forth the compensation for services paid in
all capacities for the two fiscal years ended December 31, 2020 and
2019 to (a) Simon Kukes, our current Chief Executive Officer
and Director, (b) J. Douglas Schick, our current President,
(c) Clark R. Moore, our Executive Vice President, General
Counsel and Secretary, and (d) Paul A Pinkston, our current
Chief Accounting Officer (collectively, the “
Named Executive
Officers
”). There were no other executive officers who
received compensation in excess of $100,000 in either 2020 or
2019.
109
Summary Compensation Table
|
Name and Principal Position
|
|
Fiscal Year
|
Salary ($)
|
Bonus ($)
|
Option Awards ($)
|
Stock Awards ($)
|
All Other Compensation
($)
|
Total ($)
|
|
Simon
Kukes
|
|
2020
|
-
|
-
|
-
|
856,800
(1)
|
-
|
856,800
|
|
Chief
Executive Officer
|
|
2019
|
-
|
-
|
-
|
-
|
-
|
-
|
|
|
|
|
|
|
|
|
|
|
|
J. Douglas
Schick
|
|
2020
|
212,500
|
63,000
|
-
|
272,160
(2)
|
-
|
547,660
|
|
President
|
|
2019
|
250,000
|
-
|
-
|
-
|
-
|
250,000
|
|
|
|
|
|
|
|
|
|
|
|
Clark R.
Moore
|
|
2020
|
212,500
|
63,000
|
-
|
272,160
(3)
|
27,691
(4)
|
575,351
|
|
Executive Vice
President, General Counsel and Secretary
|
|
2019
|
250,000
|
-
|
-
|
-
|
-
|
250,000
|
|
|
|
|
|
|
|
|
|
|
|
Paul A.
Pinkston
|
|
2020
|
119,861
|
18,000
|
-
|
151,200
(5)
|
-
|
289,061
|
|
Chief
Accounting Officer
|
|
2019
|
140,000
|
-
|
-
|
-
|
-
|
140,000
|
Does not include perquisites and other personal benefits or
property, unless the aggregate amount of such compensation is more
than $10,000. No executive officer earned any non-equity
incentive plan compensation or nonqualified deferred compensation
during the periods reported above.
Stock Awards represent
the aggregate grant date fair value of awards computed in
accordance with Financial Accounting Standards Board Accounting
Standard Codification Topic 718. For additional information on the
valuation assumptions with respect to the restricted stock grants,
refer to “
Part
II
” - “
Item
8. Financial Statements and Supplementary Data
” -
“
Note 11 –
Share-Based Compensation
”. These amounts do not
correspond to the actual value that will be recognized by the named
individuals from these awards.
|
(1)
|
Consists
of the value of 510,000 shares of restricted common stock granted
in January 2020 at $1.68 per share.
|
|
(2)
|
Consists
of the value of 162,000 shares of restricted common stock granted
in January 2020 at $1.68 per share.
|
|
(3)
|
Consists
of the value of 162,000 shares of restricted common stock granted
in January 2020 at $1.68 per share.
|
|
(4)
|
Consists
of accrued vacation paid out during the applicable fiscal year in
cash.
|
|
(5)
|
Consists
of the value of 90,000 shares of restricted common stock granted in
January 2020 at $1.68 per share.
|
110
Outstanding Equity Awards at Year Ended December 31,
2020
The
following table sets forth information as of December 31, 2020
concerning outstanding equity awards for the executive officers
named in the Summary Compensation Table.
Outstanding Equity Awards at Fiscal Year-End
|
|
Option Awards
|
Stock Awards
(3)
|
||||
|
Name
|
Number of securities underlying unexercised options
(#) exercisable
|
Number of
securities underlying unexercised
options (#)
unexercisable
|
Option Exercise price
($)
|
Option expiration date
|
Number of shares or units of
stock that have not vested (#)
|
Market value of shares or units
of stock that have not vested ($)(4)
|
|
Simon
Kukes
|
-
|
-
|
-
|
-
|
200,000
(1)
|
$
302,000
|
|
|
-
|
-
|
-
|
-
|
510,000
(2)
|
$
770,100
|
|
|
|
|
|
|
|
|
|
J. Douglas
Schick
|
-
|
-
|
-
|
-
|
74,677
(1)
|
$
112,762
|
|
|
-
|
-
|
-
|
-
|
162,000
(2)
|
$
244,620
|
|
|
|
|
|
|
|
|
|
Clark R.
Moore
|
18,887
|
-
|
$
5.10
|
6/18/2022
|
17,000
(1)
|
$
25,670
|
|
|
4,447
|
-
|
$
5.10
|
6/18/2022
|
162,000
(2)
|
$
244,620
|
|
|
28,000
*
|
-
|
$
2.20
|
1/7/2021
|
-
|
-
|
|
|
|
|
|
|
|
|
|
Paul A.
Pinkston
|
-
|
-
|
-
|
-
|
90,000
(2)
|
135,900
|
|
(1)
|
Stock
award vests on December 12, 2021, subject to the holder remaining
an employee of or consultant to the Company on such vesting
dates.
|
|
(2)
|
Stock
award vests 33.3% on January 13, 2021, 33.3% on January 13, 2022,
and January 13, 2023, subject to the holder remaining an employee
of or consultant to the Company on such vesting dates.
|
(3) There were no unearned shares, units or other rights that have
not vested as of December 31, 2020.
(4)
Calculated by
multiplying
the closing market price of the Company’s common stock at the
end of the last completed fiscal year by the number of shares of
stock.
* Since expired unexercised.
Issuances of Equity to Executive Officers
See above and see also
“
Part II
” -
“
Item 8. Financial
Statements and Supplementary Data
” –
“
Note 11 –
Share-Based Compensation
”, for equity issuances to
executive officers for the years ended December 31, 2020 and
2019, respectively.
111
Compensation of Directors
The
following table sets forth compensation information with respect to
our non-executive directors during our fiscal year ended December
31, 2020.
|
Name
|
Fees Earned or Paid in Cash ($)*
|
Stock Awards ($) (1) (2)
|
All Other Compensation ($)
|
Total ($)
|
|
John
J. Scelfo
|
$
-
|
$
211,000
|
$
-
|
$
211,000
|
|
Ivar
Siem
|
$
-
|
$
147,700
|
$
-
|
$
147,700
|
|
H.
Douglas Evans
|
$
-
|
$
147,700
|
$
-
|
$
147,700
|
* The
table above does not include the amount of any expense
reimbursements paid to the above directors. No directors received
any Non-Equity Incentive Plan Compensation or Nonqualified Deferred
Compensation. Does not include perquisites and other personal
benefits, or property, unless the aggregate amount of such
compensation is more than $10,000.
|
(1)
|
Amounts
in this column represent the aggregate grant date fair value of
awards computed in accordance with Financial Accounting Standards
Board Accounting Standard Codification Topic 718. For additional
information on the valuation assumptions with respect to the
restricted stock grants, refer to “Part II” -
“
Item 8. Financial Statements and
Supplementary Data
” - “
Note 11 – Share-Based
Compensation
”. These amounts do not
correspond to the actual value that will be recognized by the named
individuals from these awards.
|
|
(2)
|
Mr.
Scelfo, Mr. Evans and Mr. Siem received grants of 100,000, 70,000
and 70,000 shares of restricted stock, respectively, on August 27,
2020, each with an aggregate grant date fair value of $211,000,
$147,000 and $147,000, respectively, which will vest in full on
July 12, 2021, September 27, 2021, and July 12, 2021, respectively.
For the year ended December 31, 2020, there was compensation of
$169,000, related to these grants.
|
Effective September
27, 2018, the Board no longer has a formal compensation program;
provided that the Board of Directors and/or the Compensation
Committee may authorize compensation (including, but not limited to
cash, options and restricted stock) to the members of the
Board of Directors from time to time in their
discretion.
Agreements with Current Named Executive Officers
Simon Kukes
.
Simon Kukes has agreed to receive an annual salary
of $1 as his compensation for serving as Chief Executive Officer of
the Company and as a member of the Board of Directors and to not
charge the Company for any personal business expenses he incurs in
connection with such positions. Notwithstanding the above, Simon
Kukes was not paid any salary for 2019 or 2018. Notwithstanding the
above, Simon Kukes may receive bonuses (in any amount) consisting
of cash, grants of restricted stock and/or options granted in the
Board of Directors’ sole discretion, from time to time,
provided that none are currently contemplated.
112
J. Douglas
Schick
. On August 1, 2018, in
connection with his appointment as President of the Company, we
entered into an offer letter with J. Douglas Schick (the
“
Offer
Letter
”). Pursuant to the
Offer Letter, Mr. Schick agreed to serve as President of the
Company on an at-will basis; the Company agreed to pay Mr. Schick
$20,833 per month (which has been reduced by the Temporary
Salary Reductions discussed below) and that Mr. Schick is eligible
for an annual bonus in the discretion of the Company totaling up to
40% of his then current salary and may also receive bonuses (in any
amount) consisting of cash, grants of restricted stock and/or
options granted in the Board of Directors’ sole discretion,
from time to time. Mr. Schick’s employment may be terminated
by him or the Company with 30 days prior written notice. In
the event Mr. Schick’s employment with the Company is
terminated by the Company without “
Cause
,”
the Company will (a) pay Mr. Schick an amount equal to twelve
(12) months of his then-current annual base salary, and
(b) immediately accelerate by twelve (12) months the
vesting of all outstanding Company restricted stock and options
exercisable for Company capital stock held by Mr. Schick. For
purposes of the Offer Letter, “
Cause
”
means Mr. Schick’s (1) conviction of, or plea of nolo
contendere to, a felony or any other crime involving moral
turpitude; (2) fraud on or misappropriation of any funds or
property of the Company or any of its affiliates, customers or
vendors; (3) act of material dishonesty, willful misconduct,
willful violation of any law, rule or regulation, or breach of
fiduciary duty involving personal profit, in each case made in
connection with his responsibilities as an employee, officer or
director of the Company and which has, or could reasonably be
deemed to result in, a material adverse effect upon the Company;
(4) illegal use or distribution of drugs; (5) willful
material violation of any policy or code of conduct of the Company;
or (6) material breach of any provision of the Offer Letter or
any other employment, non-disclosure, non-competition,
non-solicitation or other similar agreement executed by him for the
benefit of the Company or any of its affiliates, all as reasonably
determined in good faith by the Board of Directors of the Company.
However, an event that is or would constitute
“
Cause
”
shall cease to be “
Cause
”
if he reverses the action or cures the default that constitutes
“
Cause
”
within 10 days after the Company notifies him in writing that Cause
exists.
The
Offer Letter contains standard confidentiality provisions; a
standard non-compete restriction prohibiting Mr. Schick from
competing against the Company during the term of his employment and
for one year thereafter in connection with any directly competitive
enterprise, commercial venture, or project involving petroleum
exploration, development, or production activities in the same
geographic areas as the Company’s activities or doing
business with the Company during the six-month period before the
termination of his employment, with certain exceptions; and a
non-solicitation provision prohibiting him from inducing or
attempting to induce any employee of the company from leaving their
employment with the Company and/or attempting to induce any
consultant, service provider, customer or business relation of the
Company from terminating their relationship with the Company during
the term of his employment and for one year
thereafter.
On
March 31, 2020, Mr. Schick and the Company entered into an
amendment to his Offer Letter discussed in greater detail below
under “Temporary Salary Reductions and Amendments to
Employment Agreements”.
113
Clark R.
Moore.
Pacific Energy
Development, our wholly-owned subsidiary, has entered into an
employment agreement, dated June 10, 2011, as amended January 11,
2013, with Clark Moore, its Executive Vice President, Secretary and
General Counsel (the “
Moore Employment
Agreement
”), pursuant to
which, effective June 1, 2011, Mr. Moore has been employed by
Pacific Energy Development, with a current annual base salary
of $250,000 (which has been reduced by the Temporary Salary
Reductions discussed below), and a target annual cash bonus of
between 20% and 40% of his base salary, awardable by the board of
directors in its discretion, provided that Mr. Moore may also
receive bonuses (in any amount) consisting of cash, grants of
restricted stock and/or options granted in the Board of
Directors’ sole discretion, from time to time. In addition,
Mr. Moore’s employment agreement includes, among other
things, severance payment provisions that would require the Company
to make lump sum payments equal to 18 months’ salary and
target bonus to Mr. Moore in the event his employment is terminated
due to his death or disability, terminated without
“
Cause
”
or if he voluntarily resigns for “
Good
Reason
” (36 months in
connection with a “
Change of
Control
”), and
continuation of benefits for up to 36 months (48 months in
connection with a “
Change of
Control
”), as such terms
are defined in the employment agreement. The employment agreement
also prohibits Mr. Moore from engaging in competitive activities
during and following termination of his employment that would
result in disclosure of our confidential information but does not
contain a general restriction on engaging in competitive
activities.
For purposes of the Moore Employment Agreement,
the term “
Cause
”
means his (1) conviction of, or plea of nolo contendere to, a
felony or any other crime involving moral turpitude; (2) fraud
on or misappropriation of any funds or property of our company or
any of its affiliates, customers or vendors; (3) act of
material dishonesty, willful misconduct, willful violation of any
law, rule or regulation, or breach of fiduciary duty involving
personal profit, in each case made in connection with his
responsibilities as an employee, officer or director of our company
and which has, or could reasonably be deemed to result in, a
Material Adverse Effect upon our company; (4) illegal use or
distribution of drugs; (5) material violation of any policy or
code of conduct of our company; or (6) material breach of any
provision of the employment agreement or any other employment,
non-disclosure, non-competition, non-solicitation or other similar
agreement executed by him for the benefit of our company or any of
its affiliates, all as reasonably determined in good faith by the
board of directors of our company. However, an event that is or
would constitute “
Cause
”
shall cease to be “
Cause
”
if he reverses the action or cures the default that constitutes
“
Cause
”
within 10 days after our company notifies him in writing that Cause
exists. No act or failure to act on Mr. Moore’s part will be
considered “
willful
”
unless it is done, or omitted to be done, by him in bad faith or
without reasonable belief that such action or omission was in the
best interests of our company. Any act or failure to act that is
based on authority given pursuant to a resolution duly passed by
the board of directors, or the advice of counsel to our company,
shall be conclusively presumed to be done, or omitted to be done,
in good faith and in the best interests of the
Company.
For purposes of the Moore Employment Agreement,
“
Material Adverse
Effect
” means any event,
change or effect that is materially adverse to the condition
(financial or otherwise), properties, assets, liabilities,
business, operations or results of operations of our company or its
subsidiaries, taken as a whole.
For purposes of the Moore Employment Agreement,
“
Good
Reason
” means the
occurrence of any of the following without his written consent:
(a) the assignment to him of duties substantially inconsistent
with this employment agreement or a material adverse change in his
titles or authority; (b) any failure by our company to comply
with the compensation provisions of the agreement in any material
way; (c) any material breach of the employment agreement by
our company; or (d) the relocation of him by more than fifty
(50) miles from the location of our company’s office
located in Danville, California. However, an event that is or would
constitute “
Good
Reason
” shall cease to be
“
Good
Reason
” if: (i) he
does not terminate employment within 45 days after the event
occurs; (ii) before he terminates employment, we reverse the
action or cure the default that constitutes
“
Good
Reason
” within 10 days
after he notifies us in writing that Good Reason exists; or
(iii) he was a primary instigator of the
“
Good
Reason
” event and the
circumstances make it inappropriate for him to receive
“
Good
Reason
” termination
benefits under the employment agreement (e.g., he agrees
temporarily to relinquish his position on the occurrence of a
merger transaction he assists in negotiating).
114
For purposes of the Moore Employment Agreement,
“
Change of
Control
” means:
(i) a merger, consolidation or sale of capital stock by
existing holders of capital stock of our company that results in
more than 50% of the combined voting power of the then outstanding
capital stock of our company or its successor changing ownership;
(ii) the sale, or exclusive license, of all or substantially
all of our company’s assets; or (iii) the individuals
constituting our company’s board of directors as of the date
of the employment agreement (the “
Incumbent Board of
Directors
”) cease
for any reason to constitute at least 1/2 of the members of the
board of directors; provided, however, that if the election, or
nomination for election by our stockholders, of any new director
was approved by a vote of the Incumbent Board of Directors, such
new director shall be considered a member of the Incumbent Board of
Directors. Notwithstanding the foregoing and for purposes of
clarity, a transaction shall not constitute a Change in Control if:
(w) its sole purpose is to change the state of our
company’s incorporation; (x) its sole purpose is to
create a holding company that will be owned in substantially the
same proportions by the persons who held our company’s
securities immediately before such transaction; or (y) it is a
transaction effected primarily for the purpose of financing our
company with cash (as determined by the board of directors in its
discretion and without regard to whether such transaction is
effectuated by a merger, equity financing or
otherwise).
On
March 31, 2020, Mr. Moore and Pacific Energy Development entered
into an amendment to his employment agreement discussed in greater
detail below under “Temporary Salary Reductions and
Amendments to Employment Agreements”.
Paul A. Pinkston.
On December 1, 2018, the Company
appointed Mr. Pinkston as the Chief Accounting Officer of the
Company and Mr. Pinkston commenced employment with the Company
pursuant to the terms of an Offer Letter, dated October 16, 2018,
and effective December 1, 2018, entered into by and between the
Company and Mr. Pinkston (the “
Pinkston Offer
Letter
”). Also effective
on December 1, 2018, Mr. Pinkston commenced serving as the
Company’s Principal Financial and Accounting Officer of the
Company.
Pursuant
to the Pinkston Offer Letter, Mr. Pinkston agreed to serve as Chief
Accounting Officer of the Company on an at-will basis, the Company
agreed to pay Mr. Pinkston $11,666.67 per month (subject to the
Temporary Salary Reductions discussed below), Mr. Pinkston is
eligible for an annual bonus in the discretion of the Board of
Directors of the Company totaling up to 30% of his then current
salary, provided that Mr. Pinkston may also receive bonuses (in any
amount) consisting of cash, grants of restricted stock and/or
options granted in the Board of Directors’ sole discretion,
from time to time. Mr. Pinkston’s employment may be
terminated by him or the Company with 30 days prior written notice.
In addition, Mr. Pinkston was granted 30,000 shares of the
Company’s common stock under the Company’s employee
equity incentive plan, 50% of which shares vest on Mr.
Pinkston’s one (1) year anniversary of his employment
commencement date, and 50% of which shares vest on Mr.
Pinkston’s two (2) year anniversary of his employment
commencement date, subject to Mr. Pinkston’s continued
service with the Company and the terms of a Board-approved
restricted stock purchase agreement entered into between Mr.
Pinkston and the Company.
The
Pinkston Offer Letter contains standard confidentiality provisions
and a standard a non-solicitation provision prohibiting him from
inducing or attempting to induce any employee of the Company from
leaving their employment with the Company and/or attempting to
induce any consultant, service provider, customer or business
relation of the Company from terminating their relationship with
the Company during the term of his employment and for one year
thereafter.
Temporary Salary Reductions and Amendments to Employment
Agreements
On
March 31, 2020, as part of our efforts to reduce operating and
corporate costs, the independent Compensation Committee of the
Board approved a 20% reduction in salary for all of the
Company’s salaried employees, effective April 1, 2020 (the
“
Temporary Salary
Reductions
”).
In
connection with the 20% salary reduction, on March 31, 2020, the
Company and each of Mr. Douglas J. Schick, our President, and Mr.
Clark R. Moore, our Executive Vice President, General Counsel, and
Secretary, entered into amendments to their respective employment
agreements (the “
Amendments
”) to effect
the salary reductions on a temporary basis, until such time as the
Company determines, in its reasonable discretion, that oil markets
have recovered to acceptable levels (the “
Salary Reduction
Period
”), which determination has not been made to
date. The Amendments to Messrs. Schick’s and Moore’s
employment agreements do not, however, reduce the amount of
severance compensation that such executive would receive under
their respective employment agreements in the event of an
applicable termination of their respective employment, subject to
the terms of such employment agreements.
115
In
addition, the amendment entered into with Mr. Schick includes a
provision whereby, in the event Mr. Schick’s employment with
the Company is voluntarily terminated by him due to the
Company’s failing to pay his base salary (as currently
reduced as disclosed above) without his written consent, the
Company will (a) continue to pay Mr. Schick an amount equal to his
base salary as in effect immediately before his termination of
employment on the same bi-monthly schedule and amounts (less
required withholdings) as he received such salary payments prior to
his date of termination (the “
Cash Payments
”), which
Cash Payments shall be reported by the Company on IRS Form 1099 as
income to Mr. Schick and will continue until the earlier to occur
of (x) the date that is twelve (12) months after the termination of
his employment or (y) the date that he commences employment with
another employer that pays him a base salary equal to, or greater
than, his base salary as in effect immediately before his
termination of employment, provided that, if his new employer pays
him less than his Company base salary, he shall only be entitled to
Cash Payment amounts going forward through the remainder of the
twelve (12) month term equal to (i) his Company base salary at the
time of his termination minus the salary he receives from his new
employer; and (b) continue to vest his outstanding Company
restricted stock and options exercisable for Company capital stock
issued to him by the Company which are then held by him on his date
of termination on their then-current vesting schedules during the
period of up to twelve (12) months that he continues to receive the
Cash Payments, in exchange for a full and complete release of
claims against the Company, its affiliates, officers and directors
in a form reasonably acceptable to the Company. Upon the date that
his Cash Payments discontinue, he shall no longer continue to vest
into any outstanding Company restricted stock or options. The Cash
Payments payable to Mr. Schick and the other amounts, based on his
salary, which may be due to him upon termination of his offer
letter upon certain events, and subject to the terms thereof,
during the Salary Reduction Period will continue to be based on Mr.
Schick’s non-reduced salary.
As
discussed above, Simon Kukes, our Chief Executive Officer and
director, has agreed to receive an annual salary of $1 as his
compensation for serving as Chief Executive Officer of the Company
and as a member of our Board and to not charge the Company for any
personal business expenses he incurs in connection with such
positions. The Company does not currently have a formal written
agreement in place with Simon Kukes. To date, Simon Kukes has not
accepted any salary from the Company (including his $1 annual
compensation).
Equity Incentive Plans
2012 Plan
General.
On June 26, 2012, our
board of directors adopted the Blast Energy Services, Inc. 2012
Equity Incentive Plan, which was approved by our stockholders on
July 30, 2012 and subsequently renamed to the PEDEVCO Corp. 2012
Equity Incentive Plan in connection with our name change from Blast
Energy Services, Inc. to PEDEVCO Corp. The 2012 Equity Incentive
Plan provides for awards of incentive stock options, non-statutory
stock options, rights to acquire restricted stock, stock
appreciation rights, or SARs, and performance units and performance
shares. Subject to the provisions of the 2012 Equity Incentive Plan
relating to adjustments upon changes in our common stock, an
aggregate of
200,000
shares of
common stock were reserved for issuance under the 2012 Equity
Incentive Plan. On April 23, 2014, the board of directors adopted
an amended and restated 2012 Equity Incentive Plan, to increase by
500,000
shares, the number of
awards available for issuance under the plan, which was approved by
stockholders on June 27, 2014. On July 27, 2015, the board of
directors adopted an amended and restated 2012 Equity Incentive
Plan, to increase by
300,000
shares, the number of awards available for issuance under the plan,
which was approved by stockholders on October 7, 2015. On October
21, 2016, the board of directors adopted an amended and restated
2012 Equity Incentive Plan, to increase by
500,000
shares, the number of awards
available for issuance under the plan, which was approved by
stockholders on December 28, 2016. On November 6, 2017, the board
of directors adopted an amended and restated 2012 Equity Incentive
Plan, to increase by 1,500,000 shares, the number of awards
available for issuance under the plan, which was approved by
stockholders on December 28, 2017. On August 10, 2018, the board of
directors adopted an amended and restated 2012 Equity Incentive
Plan, to increase by 3,000,000 shares, the number of awards
available for issuance under the plan, which was approved by
stockholders on September 27, 2018. On July 1, 2019, the board of
directors adopted an amended and restated 2012 Equity Incentive
Plan, to increase by 2,000,000 shares (to 8,000,000 in aggregate),
the number of awards available for issuance under the plan, which
was approved by stockholders on August 28, 2019.
116
We
refer to the 2012 Amended and Restated Incentive Plan as the 2012
Plan.
Purpose.
Our board of directors adopted the
2012 Plan to provide a means by which our employees, directors and
consultants may be given an opportunity to benefit from increases
in the value of our common stock, to assist in attracting and
retaining the services of such persons, to bind the interests of
eligible recipients more closely to our interests by offering them
opportunities to acquire shares of our common stock and to afford
such persons stock-based compensation opportunities that are
competitive with those afforded by similar businesses.
Administration.
Unless it
delegates administration to a committee, our board of directors
administers the 2012 Plan. Subject to the provisions of the 2012
Plan, our board of directors has the power to construe and
interpret the 2012 Plan, and to determine: (a) the fair value
of common stock subject to awards issued under the 2012 Plan;
(b) the persons to whom and the dates on which awards will be
granted; (c) what types or combinations of types of awards
will be granted; (d) the number of shares of common stock to
be subject to each award; (e) the time or times during the
term of each award within which all or a portion of such award may
be exercised; (f) the exercise price or purchase price of each
award; and (g) the types of consideration permitted to
exercise or purchase each award and other terms of the
awards.
Eligibility.
Incentive stock options may be
granted under the 2012 Plan only to employees of us and our
affiliates. Employees, directors and consultants of us and our
affiliates are eligible to receive all other types of awards under
the 2012 Plan.
Terms of Options and SARs.
The
exercise price of incentive stock options may not be less than the
fair market value of the common stock subject to the option on the
date of the grant and, in some cases, may not be less than 110% of
such fair market value. The exercise price of non-statutory options
also may not be less than the fair market value of the common stock
on the date of grant.
Options
granted under the 2012 Plan may be exercisable in cumulative
increments, or “
vest,
” as determined by
our board of directors. Our board of directors has the power to
accelerate the time as of which an option may vest or be exercised.
The maximum term of options, SARs and performance shares and units
under the 2012 Plan is ten years, except that in certain
cases, the maximum term is five years. Options, SARs and
performance shares and units awarded under the 2012 Plan generally
will terminate three months after termination of the
participant’s service, subject to certain
exceptions.
A
recipient may not transfer an incentive stock option otherwise than
by will or by the laws of descent and distribution. During the
lifetime of the recipient, only the recipient may exercise an
option, SAR or performance share or unit. Our board of directors
may grant non-statutory stock options, SARs and performance shares
and units that are transferable to the extent provided in the
applicable written agreement.
Terms of Restricted Stock
Awards.
Our board of directors may issue shares of
restricted stock under the 2012 Plan as a grant or for such
consideration, including services, and, subject to the
Sarbanes-Oxley Act of 2002, promissory notes, as determined in its
sole discretion.
Shares
of restricted stock acquired under a restricted stock purchase or
grant agreement may, but need not, be subject to forfeiture to us
or other restrictions that will lapse in accordance with a vesting
schedule to be determined by our board of directors. In the event a
recipient’s employment or service with us terminates, any or
all of the shares of common stock held by such recipient that have
not vested as of the date of termination under the terms of the
restricted stock agreement may be forfeited to us in accordance
with such restricted stock agreement.
Rights
to acquire shares of common stock under the restricted stock
purchase or grant agreement shall be transferable by the recipient
only upon such terms and conditions as are set forth in the
restricted stock agreement, as our board of directors shall
determine in its discretion, so long as shares of common stock
awarded under the restricted stock agreement remain subject to the
terms of such agreement.
117
Adjustment Provisions.
If any change is made to our
outstanding shares of common stock without our receipt of
consideration (whether through reorganization, stock dividend or
stock split, or other specified change in our capital structure),
appropriate adjustments may be made in the class and maximum number
of shares of common stock subject to the 2012 Plan and outstanding
awards. In that event, the 2012 Plan will be appropriately adjusted
in the class and maximum number of shares of common stock subject
to the 2012 Plan, and outstanding awards may be adjusted in the
class, number of shares and price per share of common stock subject
to such awards.
Effect of Certain Corporate
Events.
In the
event of (a) a liquidation or dissolution of the Company;
(b) a merger or consolidation of the Company with or into
another corporation or entity (other than a merger with a
wholly-owned subsidiary); (c) a sale of all or substantially
all of the assets of the Company; or (d) a purchase or other
acquisition of more than 50% of the outstanding stock of the
Company by one person or by more than one person acting in concert,
any surviving or acquiring corporation may assume awards
outstanding under the 2012 Plan or may substitute similar awards.
Unless the stock award agreement otherwise provides, in the event
any surviving or acquiring corporation does not assume such awards
or substitute similar awards, then the awards will terminate if not
exercised at or prior to such event.
Duration, Amendment and
Termination.
Our board of directors may suspend or
terminate the 2012 Plan without stockholder approval or
ratification at any time or from time to time. Unless sooner
terminated, the 2012 Plan will terminate ten years from the date of
its adoption by our board of directors, i.e., in
June
2022.
Our
board of directors may also amend the 2012 Plan at any time, and
from time to time. However, except as it relates to adjustments
upon changes in common stock, no amendment will be effective unless
approved by our stockholders to the extent stockholder approval is
necessary to preserve incentive stock option treatment for federal
income tax purposes. Our board of directors may submit any other
amendment to the 2012 Plan for stockholder approval if it concludes
that stockholder approval is otherwise advisable.
As of
the date of this Annual Report, options to purchase
1,316,167
shares of common stock and
6,359,893
shares of restricted
stock have been issued under the 2012 Plan, with
323,940
shares of common stock remaining
available for issuance under the 2012 Plan. The options have a
weighted average exercise price of $
1.85
per share and have expiration dates
ranging from 2021 to
2026
.
2012 Pacific Energy Development (Pre-Merger) Plan
On
February 9, 2012, prior to the Pacific Energy Development merger,
Pacific Energy Development adopted the Pacific Energy Development
2012 Equity Incentive Plan, which we refer to as the 2012
Pre-Merger Plan. We assumed the obligations of the 2012 Pre-Merger
Plan pursuant to the Pacific Energy Development merger, though the
2012 Pre-Merger Plan has been superseded by the 2012 Plan
(described above).
The
2012 Pre-Merger Plan provides for awards of incentive stock
options, non-statutory stock options, rights to acquire restricted
stock, stock appreciation rights, or SARs, and performance units
and performance shares. Subject to the provisions of the 2012
Pre-Merger Plan relating to adjustments upon changes in our common
stock, an aggregate of
100
,000
shares of common stock have been reserved for issuance under the
2012 Pre-Merger Plan.
The
board of directors of Pacific Energy Development adopted the 2012
Pre-Merger Plan to provide a means by which its employees,
directors and consultants may be given an opportunity to benefit
from increases in the value of its common stock, to assist in
attracting and retaining the services of such persons, to bind the
interests of eligible recipients more closely to our interests by
offering them opportunities to acquire shares of our common stock
and to afford such persons stock-based compensation opportunities
that are competitive with those afforded by similar
businesses.
118
The
exercise price of incentive stock options may not be less than the
fair market value of the common stock subject to the option on the
date of the grant and, in some cases, may not be less than 110% of
such fair market value. The exercise price of non-statutory options
also may not be less than the fair market value of the common stock
on the date of grant. Options granted under the 2012 Pre-Merger
Plan may be exercisable in cumulative increments, or
“
vest,
”
as determined by the board of directors of Pacific Energy
Development at the time of grant.
Shares
of restricted stock could be issued under the 2012 Pre-Merger
Plan as a grant or for such consideration, including services, and,
subject to the Sarbanes-Oxley Act of 2002, promissory notes, as
determined in the sole discretion of the Pacific Energy Development
board of directors. Shares of restricted stock acquired under a
restricted stock purchase or grant agreement could, but need not,
be subject to forfeiture or other restrictions that will lapse in
accordance with a vesting schedule determined by the board of
directors of Pacific Energy Development at the time of grant. In
the event a recipient’s employment or service with the
Company terminates, any or all of the shares of common stock held
by such recipient that have not vested as of the date of
termination under the terms of the restricted stock agreement may
be forfeited to the Company in accordance with such restricted
stock agreement.
Appropriate
adjustments may be made to outstanding awards in the event of
changes in our outstanding shares of common stock, whether through
reorganization, stock dividend or stock split, or other specified
change in capital structure of the Company. In the event of
liquidation, merger or consolidation, sale of all or substantially
all of the assets of the Company, or other change in control, any
surviving or acquiring corporation may assume awards outstanding
under the 2012 Pre-Merger Plan or may substitute similar awards.
Unless the stock award agreement otherwise provides, in the event
any surviving or acquiring corporation does not assume such awards
or substitute similar awards, then the awards will terminate if not
exercised at or prior to such event.
As of
the date of this Annual Report,
21,635
options remain outstanding under the
2012 Pre-Merger Plan. These options have a weighted average
exercise price of $
4.98
per
share and have expiration dates ranging from
May 31, 2021
to June 18, 2022.
ITEM 12.
S
ECURITY
OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED
STOCKHOLDER MATTERS.
The following table sets forth, as of
March 19, 2021, the number and
percentage of outstanding shares of our common stock beneficially
owned by: (a) each person who is known by us to be the
beneficial owner of more than 5% of our outstanding shares of
common stock; (b) each of our directors; (c) each of our
Named Executive Officers; and (d) all current directors and
Named Executive Officers, as a group. As of March 19, 2021, there
were 79,441,603 shares of common stock and no shares of preferred
stock issued and outstanding.
Beneficial
ownership has been determined in accordance with Rule 13d-3 under
the Exchange Act. Under this rule, certain shares may be deemed to
be beneficially owned by more than one person (if, for example,
persons share the power to vote or the power to dispose of the
shares). In addition, shares are deemed to be beneficially owned by
a person if the person has the right to acquire shares (for
example, upon exercise of an option or warrant or upon conversion
of a convertible security) within 60 days of the date as of
which the information is provided. In computing the percentage
ownership of any person, the amount of shares is deemed to include
the amount of shares beneficially owned by such person by reason of
such acquisition rights. As a result, the percentage of outstanding
shares of any person as shown in the following table does not
necessarily reflect the person’s actual voting power at any
particular date.
119
Beneficial
ownership as set forth below is based on our review of our record
stockholders list and public ownership reports filed by certain
stockholders of the Company, and may not include certain securities
held in brokerage accounts or beneficially owned by the
stockholders described below.
|
|
Common Stock
|
|
|
|
Number of Common Stock Shares Beneficially Owned (1)
|
Percent of Common Stock (1)
|
|
Named Executive Officers and Directors
|
|
|
|
Simon
G. Kukes (2)
|
54,066,368
|
68.1
%
|
|
Clark
R. Moore (3)
|
564,277
|
*
|
|
J.
Douglas Schick (4)
|
472,400
|
*
|
|
Ivar
Siem (5)
|
307,100
|
*
|
|
John
J. Scelfo (6)
|
269,500
|
*
|
|
H.
Douglas Evans (7)
|
250,000
|
*
|
|
Paul
A. Pinkston (8)
|
240,000
|
*
|
|
All Named Executive Officers and Directors as a group (seven
persons)
|
56,169,645
|
70.5
%
|
|
|
|
|
|
Greater than 5% Stockholders
|
|
|
|
SK
Energy, LLC (9)
|
51,791,325
|
65.2
%
|
|
Viktor
Tkachev (10)
|
8,270,000
|
10.4
%
|
|
Arhitektora
Vlasova Street 22
Apt
93
|
|
|
|
Moscow,
Russia 117393
|
|
|
*Less than 1%.
Unless otherwise stated, the address of each stockholder is c/o
PEDEVCO Corp.,
575 N. Dairy Ashford, Suite 210, Houston,
Texas 77079.
(1)
Ownership
voting percentages are based on 79,441,603 total shares of common
stock which were outstanding as of March 19, 2021.
(2)
Consisting of the following: (a) 51,791,325
shares of common stock held by SK Energy LLC, an entity which Simon
G. Kukes is deemed to beneficially own; (b) 1,527,043 shares
of fully-vested common stock held by Simon Kukes; (c) 740,000
unvested shares of common stock held by Simon Kukes, 100,000 of
which vest on December 12, 2021, 170,000 of which vest on each of
January 13, 2022 and January 13, 2023, and 100,000 of which vest on
each of January 19, 2022, January 19, 2023 and January 19, 2024
provided that Simon Kukes remains employed by us, or is a
consultant to us, on such vesting dates; (d) 2,000 shares of
fully-vested common stock held by the spouse of Simon Kukes; (e)
1,000 unvested shares of common stock held by the spouse of Simon
Kukes, which vest on December 12, 2021, provided that his spouse
remains an employee of, or consultant to, the Company on such
vesting date; and (f) options to purchase 5,000 of common stock
exercisable by the spouse of Simon Kukes at an exercise price of
$1.68 per share. Simon Kukes has voting control over his unvested
shares of common stock.
(3)
Consisting
of the following: (a) 163,076 fully-vested shares of common
stock held by Mr. Moore; (b) 2,867 fully-vested shares of
common stock held by Mr. Moore’s minor child, which he is
deemed to beneficially own; (c) 375,000 unvested shares of
common stock held by Mr. Moore, 17,000 of which vest on December
12, 2021, 54,000 of which vest on each of January 13, 2022 and
January 13, 2023, and 83,333 of which vest on each of January 19,
2022 and January 19, 2023, and 83,334 which vests on January 19,
2024, in each case provided that Mr. Moore remains employed by us,
or is a consultant to us, on such vesting dates; and
(d) options to purchase 23,334 shares of common stock
exercisable by Mr. Moore at an exercise price of $5.10 per share.
Mr. Moore has voting control over his unvested shares of common
stock.
120
(4)
Consisting
of the following: (a) 77,066 shares of fully-vested common
stock held by Mr. Schick; and (b) 395,334 unvested shares of
common stock held by Mr. Schick, 37,334 of which vest on December
12, 2021, 54,000 which vest on each of January 13, 2022 and January
13, 2023, and 83,333 which vests on each of January 19, 2022 and
January 19, 2023, and 83,334 which vest on January 19, 2024, in
each case provided that Mr. Schick remains employed by us, or is a
consultant to us, on such vesting dates. Mr. Schick has voting
control over his unvested shares of common stock.
(5)
Consisting of the following: (a) 187,100
shares of common stock held by American Resources Offshore Inc.,
which shares Mr. Siem is deemed to beneficially own (Mr. Siem
disclaims beneficial ownership of the securities held by American
Resources Offshore Inc., except to the extent of his pecuniary
interest therein); (b) 50,000 fully-vested shares of common
stock held by Mr. Siem; and (c)
70,000 unvested shares of
PEDEVCO Common Stock held by Mr. Siem, which vest on July 12, 2021,
provided that Mr. Siem remains a director, employee of, or
consultant to PEDEVCO on such vesting date. Mr. Siem has voting
control over his unvested shares of PEDEVCO Common
Stock.
(6)
Consisting
of the following: (a) 49,500 shares of fully-vested common
stock held by Mr. Scelfo; (b) 100,000 unvested shares of
common stock, which vest on July 12, 2021, provided that Mr. Scelfo
remains a director, employee of, or consultant to the Company on
such vesting date; and (c) options to purchase 120,000 shares
of common stock exercisable by Mr. Scelfo at an exercise price of
$2.19 per share. Mr. Scelfo has voting control over his unvested
shares of common stock.
(7)
Consisting
of the following: (a) 80,000 shares of fully-vested common
stock held by Mr. Evans; (b) 70,000 unvested shares of common
stock, which vest on September 27, 2021, provided that Mr. Evans
remains a director, employee of, or consultant to the Company on
such vesting date; and (c) options to purchase 100,000 shares
of common stock exercisable by Mr. Evans at an exercise price of
$2.19 per share. Mr. Evans has voting control over his unvested
shares of common stock.
(8)
Consisting of the following: (a) 40,000
shares of fully-vested common stock held by Mr. Pinkston; and
(b) 200,000 unvested shares of common stock
, 30,000 of
which vest on each of January 13, 2022 and January 13,
2023
, and 46,666 of which vest on of
January 19, 2022, and 46,667 of which vest on each of January 22,
2023 and January 19, 2024, in each case provided that Mr. Pinkston
remains employed by us, or is a consultant to us, on such vesting
dates. Mr. Pinkston has voting control over his unvested shares of
common stock.
(9)
Consisting
of 51,791,325 shares of common stock held by SK Energy LLC, an
entity which Simon G. Kukes is deemed to beneficially own due to
his position as the Chief Executive Officer and 100% owner of SK
Energy.
(10)
Consisting of the following 8,270,000 shares of
common stock held by Mr. Tkachev.
The
information presented with respect to the holder’s beneficial
ownership is based solely on the Company’s record stockholder
list and securities which the holder beneficially owns, to the best
of the Company’s knowledge, which information has not been
independently verified or confirmed.
121
To
our knowledge, except as indicated in the footnotes to this table
and pursuant to applicable community property laws, the persons
named in the table have sole voting and investment power with
respect to all shares of common stock shown as beneficially owned
by them.
Equity Compensation Plan Information
The
following table sets forth information, as of December 31, 2020,
with respect to our compensation plans under which common stock is
authorized for issuance.
|
Plan
Category
|
Number of securities to be issued upon exercise
of outstanding options, warrants and rights
(A)
|
Weighted-average exercise price of outstanding
options, warrants and rights
(B)
|
Number of securities remaining available for
future issuance under equity compensation plans (excluding
securities reflected in Column A)
(C)
|
|
Equity compensation
plans approved by stockholders (1)
|
1,181,135
|
$
2.31
|
1,490,370
(2)
|
|
Equity compensation
plans not approved by stockholders (3)
|
204,043
|
$
1.58
|
-
|
|
Total
|
1,385,178
|
$
2.20
|
1,490,370
|
|
(1)
|
Consists
of (i) options to purchase 21,635 shares of common stock
issued and outstanding under the Pacific Energy Development Corp.
2012 Amended and Restated Equity Incentive Plan, and
(ii) options to purchase 1,159,500 shares of common stock
issued and outstanding under the PEDEVCO Corp. 2012 Amended and
Restated Equity Incentive Plan.
|
|
(2)
|
Consists
of 1,490,370 shares of common stock reserved and available for
issuance under the PEDEVCO Corp. 2012 Amended and Restated Equity
Incentive Plan.
|
|
(3)
|
Consists
of (i) options to purchase 53,714 shares of common stock
granted by Pacific Energy Development Corp. to employees and
consultants of the company in October 2011 and June 2012, and
(ii) warrants to purchase 150,329 shares of common stock
granted by PEDEVCO Corp. to lenders in June 2018.
|
Changes in Control
The
Company is not currently aware of any arrangements which may at a
subsequent date result in a change of control of the
Company.
ITEM 13.
C
ERTAIN RELATIONSHIPS AND
RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE.
Except as referenced below or otherwise disclosed
above under “
Item 11. Executive
Compensation
”, which information is incorporated
by reference in this Item 13,
there
have been no transactions
since January 1, 2019
, and there is not currently any proposed
transaction, in which the Company was or is to be a participant,
where the amount involved exceeds
the lesser of $120,000 or
one percent of the average of the Company’s total assets at
year-end for the last two completed fiscal years
, and in which any officer, director, or any
stockholder owning greater than five percent (5%) of our
outstanding voting shares, nor any member of the above referenced
individual’s immediate family, had or will have a direct or
indirect material interest.
122
Related Transactions
January 2019 SK Energy Convertible Note
On January 11, 2019, the Company borrowed $15.0
million from SK Energy LLC, which is 100% owned and controlled by
Simon Kukes, the Company’s Chief Executive Officer and
director, through the issuance of a convertible promissory note in
the amount of $15.0 million (the “
January 2019
Convertible Note
”). The January 2019 Convertible Note
accrues interest monthly at 8.5% per annum, which is payable on the
maturity date, unless otherwise converted into shares of the
Company’s common stock as described below. The January 2019
Convertible Note and all accrued interest thereon are convertible
into shares of the Company’s common stock, at the option of
the holder thereof, at a conversion price equal to $1.50 per share.
Further, the conversion of the January 2019 Convertible Note is
subject to a 49.9% conversion limitation which prevents the
conversion of any portion thereof into common stock of the Company
if such conversion would result in SK Energy or any of its
affiliates beneficially owning more than 49.9% of the
Company’s outstanding shares of common stock. The January
2019, Convertible Note is due and payable on January 11, 2022 but
may be prepaid at any time without penalty. In February 2019, the
January 2019 Convertible Note was converted into common stock as
discussed below.
Convertible Notes Amendment and Conversion
On
February 15, 2019, the Company and SK Energy agreed to amend the
terms of $23.6 million in Convertible Promissory Notes sold in
August 2018 (including $22 million acquired by SK Energy) and
a $7 million Convertible Note sold to SK Energy in October 2018, as
well as the January 2019 Convertible Note, whereby each of the
notes were amended to remove the conversion limitation that
previously prevented SK Energy from converting any portion of the
notes into common stock of the Company if such conversion would
have resulted in SK Energy beneficially owning more than 49.9% of
the Company’s outstanding shares of common
stock.
123
Immediately
following the entry into the Amendment, on February 15, 2019, SK
Energy elected to convert (i) all $15,000,000 of the
outstanding principal and all $126,000 of accrued interest under
the January 2019 Convertible Note into common stock of the Company
at a conversion price of $1.50 per share as set forth in the
January 2019 Convertible Note into 10,083,819 shares of restricted
common stock of the Company, and (ii) all $7,000,000 of the
outstanding principal and all $18,700 of accrued interest under the
October 2018 note into common stock of the Company at a conversion
price of $1.79 per share as set forth in the October 2018 note into
4,014,959 shares of restricted common stock of the Company, which
shares in aggregate represented approximately 47.1% of the
Company’s then 29,907,223 shares of issued and outstanding
Company common stock after giving effect to the
conversions.
SK Energy Note Amendment; Note Purchases and
Conversion
On March 1, 2019, the Company and SK Energy
entered into a First Amendment to Promissory Note (the
“
SK Energy Note
Amendment
”) which
amended a note dated June 25, 2018, evidencing $7.7 million of
principal owed to SK Energy (the “
SK Energy
Note
”), to provide SK
Energy the right, at any time, at its option, to convert the
principal and interest owed under such SK Energy Note, into shares
of the Company’s common stock, at a conversion price of $2.13
per share. The SK Energy Note previously only included a conversion
feature whereby the Company had the option to pay quarterly
interest payments on the SK Energy Note in shares of Company common
stock instead of cash, at a conversion price per share calculated
based on the average closing sales price of the Company’s
common stock on the NYSE American for the ten trading days
immediately preceding the last day of the calendar quarter
immediately prior to the quarterly payment
date.
In addition, on March 1, 2019, the holders of
$1,500,000 in aggregate principal amount of Convertible Notes
issued by the Company on August 1, 2018 (the
“
August 2018
Notes
”) sold their
August 2018 Notes at face value plus accrued and unpaid interest
through March 1, 2019 to SK Energy (the “
August 2018 Note
Sale
”). Holders which
sold their August 2018 Notes pursuant to the August 2018 Note Sale
to SK Energy include an executive officer of SK Energy ($200,000 in
principal amount of August 2018 Notes); a trust affiliated with
John J. Scelfo, a director of the Company ($500,000 in principal
amount of August 2018 Notes); an entity affiliated with Ivar Siem,
a director of the Company, and J. Douglas Schick the President of
the Company ($500,000 in principal amount of August 2018 Notes);
and Harold Douglas Evans, a director of the Company ($200,000 in
principal amount of August 2018 Notes).
Following the August 2018 Note Sale, the
Company’s sole issued and outstanding debt was the
(i) $7,700,000 in principal, plus accrued interest, under the
SK Energy Note held by SK Energy, (ii) an aggregate of
$23,500,000 in principal, plus accrued interest, under the August
2018 Notes and SK Energy $22 million Convertible Note held by SK
Energy, and (iii) $100,000 in principal, plus accrued
interest, under an August 2018 Note held by an unaffiliated holder
(the “
Unaffiliated
Holder
”).
Immediately following the effectiveness of the SK
Energy Note Amendment and August 2018 Note Sale, on March 1, 2019,
SK Energy and the Unaffiliated Holder elected to convert all
$31,300,000 of outstanding principal and an aggregate of $1,462,818
of accrued interest under the SK Energy Note, SK Energy $22 million
Convertible Note and August 2018 Notes into common stock of the
Company at a conversion price of $2.13 per share (the
“
Conversion
Price
” and the
“
Conversions
”) as
set forth in the SK Energy Note, as amended, and the August 2018
Notes and SK Energy $22 million Convertible Note (collectively, the
“
Notes
”),
into an aggregate of 15,381,605 shares of restricted common stock
of the Company (the “
Conversion
Shares
”).
Common Stock Issuance to SK Energy LLC
On May 21, 2019, we raised $14,999,998.20
through the sale of 6,818,181 shares of restricted Company common
stock at a price of $2.20 per share (the “
Purchase
Price
”) to SK Energy,
pursuant to a Common Stock Subscription Agreement, dated May 21,
2019, entered into by and between the Company and SK Energy (the
“
Subscription
Agreement
”). The Purchase
Price represents a premium to the closing price of the
Company’s common stock on the NYSE American Exchange as of
the closing date and was above the greater of the book/market price
of the Company’s common stock for the purposes of the NYSE
American Exchange.
124
Advisory Agreements
Effective
November 8, 2019, the Company entered into an Advisory Agreement
and Restricted Shares Grant Agreement with Viktor Tkachev, a
greater than 10% shareholder of the Company (who acquired $12
million of shares of common stock on September 17,
2019), under which Mr. Tkachev agreed to provide strategic
planning and business development services, and pursuant to
which 100,000 shares of restricted common stock were awarded to Mr.
Tkachev under the Company’s Amended and Restated 2012 Equity
Incentive Plan (the “
Plan
”), vesting in full
on the six-month anniversary of the grant date, subject to his
continued service with the Company, in consideration for advisory
services to be provided by Mr. Tkachev to the Company. The Advisory
Agreement contains customary confidentiality, indemnification and
no conflict language, and unless terminated by the Company or the
advisor with 15 days prior written notice for any reason, the
Advisory Agreement has an indefinite term.
Effective
November 8, 2019, the Company entered into an Advisory Agreement
with Ivar Siem, a member of the Board of Directors, pursuant to
which the 50,000 restricted shares of common stock previously
awarded to Mr. Siem on August 28, 2019 under the Plan became fully
vested on July 12, 2020. The Advisory Agreement contains customary
confidentiality, indemnification and no conflict language; and,
unless terminated by the Company or the advisor with 15 days prior
written notice for any reason, the Advisory Agreement has an
indefinite term.
Additional Miscellaneous Related Party Transactions
On September 20, 2018, SK Energy entered into an
agreement with American Resources Inc. (“
American
”),
whose principals are Ivar Siem, a member of the Board of Directors
of the Company, and J. Douglas Schick, the President of the
Company. Pursuant to the agreement, American agreed to assist Dr.
Kukes with his investments in the Company and SK Energy agreed to
pay American 25% of the profit realized by SK Energy, if any,
following the sale or disposal of the securities of the Company
which SK Energy holds and may acquire in the future (prior to such
sale/disposition). The profit is to be calculated based on
(x) the amount of consideration received by SK Energy in
connection with the sale of such securities, minus (y) the
consideration paid by SK Energy for the securities, increased by
10% each year that such securities are held. The agreement has a
term of four years but can be terminated at any time by SK Energy
with written notice to American.
On
November 1, 2019, the Company began subleasing approximately 300
square feet of office space at its current headquarters to SK
Energy, which is owned and controlled by Dr. Kukes, our Chief
Executive Officer and a member of the Board of Directors. The lease
renews on a monthly basis, may be terminated by either party at any
time upon prior written notice delivered to the other party, and
has a monthly base rent of $1,200.
Additional related
party transactions are discussed in greater detail under
“
Item 8. Financial
Statements and Supplementary Data
” -
“
Note 10 –
Shareholders’ Equity – Common Stock
and
“
Note 11 –
Share-Based Compensation
”, of this Annual Report on
Form 10-K, all of which information and disclosures is incorporated
by reference into this “
Item 13. Certain Relationships and
Related Transactions, and Director
Independence
”.
Review and Approval of Related Party Transactions
We
have not adopted formal policies and procedures for the review,
approval or ratification of transactions, such as those described
above, with our executive officer(s), director(s) and
significant stockholders, provided that it is our policy that any
and all such transactions are presented and approved by the
independent members of the Board of Directors (typically through an
ad hoc committee formed solely for the purpose of approving each
individual transaction), or the Audit Committee, or a majority of
the board (with the interested parties abstaining) and future
material transactions between us and members of management or their
affiliates shall be on terms no less favorable than those available
from unaffiliated third parties.
125
In
addition, our Code of Ethics (described above under
“
Item 10. Directors, Executive
Officers and Corporate Governance
” –
“
Code of
Ethics
”), which is applicable to all of our employees,
officers and directors, requires that all employees, officers and
directors avoid any conflict, or the appearance of a conflict,
between an individual’s personal interests and our
interests.
Director Independence
Our
board of directors has determined that Mr. Scelfo and Mr. Evans are
independent directors as defined in the NYSE American rules
governing members of boards of directors or as defined under Rule
10A-3 of the Exchange Act. Accordingly, 50% of the members of our
board of directors are independent as defined in the NYSE American
rules governing members of boards of directors and as defined under
Rule 10A-3 of the Exchange Act.
ITEM 14.
P
RINCIPAL ACCOUNTANT FEES AND
SERVICES.
The
following table presents fees for professional audit services
performed by Marcum LLP for the audit of our annual financial
statements for the years ended December 31, 2020 and 2019 (in
thousands).
|
|
2020
|
2019
|
|
Audit Fees
(1)
|
$
181
|
$
131
|
|
Audit-Related Fees
(2)
|
-
|
-
|
|
Tax Fees
(3)
|
80
|
40
|
|
All Other Fees
(4)
|
19
|
14
|
|
Total
|
$
280
|
$
185
|
(1)
Audit fees include
professional services rendered for (1) the audit of our annual
financial statements for the fiscal years ended December 31, 2020
and 2019 and (ii) the reviews of the financial statements included
in our quarterly reports on Form 10-Q for such years.
(2)
Audit-related fees
consist of fees billed for professional services that are
reasonably related to the performance of the audit or review of our
consolidated financial statements but are not reported under
“Audit fees.”
(3)
Tax fees include
professional services relating to preparation of the annual tax
return.
(4)
Other fees include
professional services for review of various filings and issuance of
consents.
Pre-Approval Policies
It is
the policy of our board of directors that all services to be
provided by our independent registered public accounting firm,
including audit services and permitted audit-related and non-audit
services, must be pre-approved by our board of directors. Our board
of directors pre-approved all services, audit and non-audit,
provided to us by Marcum LLP for 2020 and 2019.
126
PART IV
ITEM 15.
E
XHIBITS AND FINANCIAL
STATEMENTS
(1) Financial Statements
INDEX TO FINANCIAL STATEMENTS
|
Audited Financial Statements for Years Ended December 31, 2020 and
2019
|
|
|
|
|
|
PEDEVCO Corp.:
|
|
|
Report
of Independent Registered Public Accounting Firm
|
74
|
|
Consolidated
Balance Sheets as of December 31, 2020 and 2019
|
76
|
|
Consolidated
Statements of Operations for the Years Ended December 31, 2020 and
2019
|
77
|
|
Consolidated
Statements of Cash Flows for the Years Ended December 31, 2020 and
2019
|
78
|
|
Consolidated
Statement of Changes in Shareholders’ Equity For the Years
Ended December 31, 2020 and 2019
|
79
|
|
Notes
to Consolidated Financial Statements
|
80
|
|
(2) Financial Statement Schedules
|
All
financial statement schedules have been omitted, since the required
information is not applicable or is not present in amounts
sufficient to require submission of the schedule, or because the
information required is included in the consolidated financial
statements and notes thereto included in this Form
10-K.
|
(3) Exhibits required by Item 601 of Regulation
S-K
|
|
|
|
|
|
|
|
Incorporated By Reference
|
||||||
|
Exhibit
No.
|
|
Description
|
|
Filed or furnished With This Annual Report on Form
10-K
|
|
Form
|
|
Exhibit
|
|
Filing Date/Period End Date
|
|
File Number
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1.1
|
|
|
|
|
8-K
|
|
1.1
|
|
February
3, 2021
|
|
001-35922
|
|
|
2.1#
|
|
|
|
|
8-K
|
|
2.1
|
|
January
14, 2019
|
|
001-35922
|
|
|
3.1
|
|
|
|
|
8-K
|
|
3.1
|
|
August 2, 2012
|
|
000-53725
|
|
|
3.2
|
|
|
|
|
8-K
|
|
3.1
|
|
April 23, 2013
|
|
000-53725
|
|
127
|
3.3
|
|
|
|
|
8-K
|
|
3.1
|
|
February 24, 2015
|
|
001-35922
|
|
|
3.4
|
|
|
|
|
8-K
|
|
3.1
|
|
March 27, 2017
|
|
333-64122
|
|
|
3.5
|
|
|
|
|
8-K
|
|
3.1
|
|
June 26, 2018
|
|
001-35922
|
|
|
3.6
|
|
|
|
|
8-K
|
|
3.3
|
|
March 6, 2008
|
|
333-64122
|
|
|
3.7
|
|
|
|
|
8-K
|
|
3.1
|
|
December 6, 2012
|
|
000-53725
|
|
|
3.8
|
|
|
|
|
8-K
|
|
3.1
|
|
October 21, 2016
|
|
001-35922
|
|
|
4.1
|
|
|
|
10-K
|
|
4.1
|
|
March 30, 2020
|
|
001-35922
|
||
|
4.2
|
|
|
|
|
S-3
|
|
4.1
|
|
October 23, 2013
|
|
333-191869
|
|
|
4.3
|
|
|
|
|
10-K
|
|
4.2
|
|
March 31, 2014
|
|
001-35922
|
|
|
4.4
|
|
|
|
|
S-8
|
|
4.13
|
|
October
31, 2013
|
|
333-192002
|
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|
4.5
|
|
|
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|
S-8
|
|
4.14
|
|
October
31, 2013
|
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333-192002
|
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|
10.1
|
|
|
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S-8
|
|
4.2
|
|
October
31, 2013
|
|
333-192002
|
|
|
10.2
|
|
|
|
|
S-8
|
|
4.3
|
|
October
31, 2013
|
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333-192002
|
|
|
10.3
|
|
|
|
|
S-8
|
|
4.4
|
|
October
31, 2013
|
|
333-192002
|
128
|
10.5
|
|
|
|
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S-8
|
|
4.5
|
|
October
31, 2013
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333-192002
|
|
|
10.6
|
|
|
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S-8
|
|
4.6
|
|
October
31, 2013
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333-192002
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|
10.7
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|
|
|
S-8
|
|
4.7
|
|
October
31, 2013
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333-192002
|
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|
10.8
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S-8
|
|
4.8
|
|
October
31, 2013
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333-192002
|
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|
10.9
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|
|
|
|
10-K
|
|
10.11
|
|
March
31, 2014
|
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001-35922
|
|
|
10.10
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|
|
|
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10-K
|
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10.20
|
|
March
31, 2014
|
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001-35922
|
|
|
10.11
|
|
|
|
|
10-K
|
|
10.43
|
|
March
31, 2014
|
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001-35922
|
|
|
10.12
|
|
|
|
|
10-K
|
|
10.44
|
|
March
31, 2014
|
|
001-35922
|
|
|
10.13
|
|
|
|
|
10-K
|
|
10.58
|
|
March
31, 2014
|
|
001-35922
|
|
|
10.18
|
|
|
|
|
8-K
|
|
10.5
|
|
May 17,
2016
|
|
001-35922
|
|
|
10.19
|
|
|
|
|
8-K
|
|
10.6
|
|
May 17,
2016
|
|
001-35922
|
|
|
10.20
|
|
|
|
|
8-K
|
|
10.5
|
|
June
26, 2018
|
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001-35922
|
|
|
10.21
|
|
|
|
|
8-K
|
|
10.4
|
|
August
1, 2018
|
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001-35922
|
|
|
10.22
|
|
|
|
8-K
|
|
10.1
|
|
December
3, 2018
|
|
001-35922
|
129
|
10.23
|
|
|
|
|
8-K
|
|
10.2
|
|
January
4, 2019
|
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001-35922
|
|
|
10.24
|
|
|
|
|
8-K
|
|
10.1
|
|
January
14, 2019
|
|
001-35922
|
|
|
10.25
|
|
|
|
|
8-K
|
|
10.4
|
|
February
19, 2019
|
|
001-35922
|
|
|
10.26
|
|
|
|
|
8-K
|
|
10.1
|
|
March
4, 2019
|
|
001-35922
|
|
|
10.27
|
|
|
|
|
8-K/A
|
|
10.1
|
|
August
12, 2019
|
|
001-35922
|
|
|
10.28
|
|
|
|
|
S-8
|
|
4.1
|
|
August
29, 2019
|
|
333-233525
|
|
|
10.29
|
|
|
|
|
8-K
|
|
10.1
|
|
September
18, 2019
|
|
001-35922
|
|
|
10.30
|
|
|
|
|
8-K
|
|
10.1
|
|
September
18, 2019
|
|
001-35922
|
|
|
10.31
|
|
|
|
|
10-Q
|
|
10.12
|
|
November
8, 2019
|
|
001-35922
|
|
|
10.32
|
|
|
|
|
10-Q
|
|
10.13
|
|
November
8, 2019
|
|
001-35922
|
|
|
10.33
|
|
|
|
|
10-Q
|
|
10.14
|
|
November
8, 2019
|
|
001-35922
|
|
|
10.34
|
|
|
|
|
8-K
|
|
10.3
|
|
March
31, 2020
|
|
001-35922
|
130
|
10.35
|
|
|
|
|
8-K
|
|
10.5
|
|
March
31, 2020
|
|
001-35922
|
|
|
10.36
|
|
|
|
|
8-K
|
|
10.1
|
|
February
3, 2021
|
|
001-35922
|
|
|
10.37#
|
|
|
X
|
|
|
|
|
|
|
|
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10.38
|
|
|
X
|
|
|
|
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|
|
|
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|
|
14.1
|
|
|
|
|
8-K/A
|
|
14.1
|
|
August 8,
2012
|
|
000-53725
|
|
|
21.1
|
|
|
X
|
|
|
|
|
|
|
|
|
|
|
23.1
|
|
|
X
|
|
|
|
|
|
|
|
|
|
|
23.2
|
|
|
X
|
|
|
|
|
|
|
|
|
|
|
31.1
|
|
|
X
|
|
|
|
|
|
|
|
|
|
|
31.2
|
|
|
X
|
|
|
|
|
|
|
|
|
|
|
32.1
|
|
|
*
|
|
|
|
|
|
|
|
|
|
|
32.2
|
|
|
*
|
|
|
|
|
|
|
|
|
|
|
99.1
|
|
|
*
|
|
|
|
|
|
|
|
|
|
|
99.2
|
|
|
|
|
8-K
|
|
99.1
|
|
September
5, 2013
|
|
001-35922
|
131
|
99.3
|
|
|
|
|
8-K
|
|
99.2
|
|
September
5, 2013
|
|
001-35922
|
|
|
99.4
|
|
|
|
|
8-K
|
|
99.3
|
|
September
5, 2013
|
|
001-35922
|
|
|
101.INS
|
|
XBRL
Instance Document
|
|
X
|
|
|
|
|
|
|
|
|
|
101.SCH
|
|
XBRL
Taxonomy Extension Schema Document
|
|
X
|
|
|
|
|
|
|
|
|
|
101.CAL
|
|
XBRL
Taxonomy Extension Calculation Linkbase Document
|
|
X
|
|
|
|
|
|
|
|
|
|
101.DEF
|
|
XBRL
Taxonomy Extension Definition Linkbase Document
|
|
X
|
|
|
|
|
|
|
|
|
|
101.LAB
|
|
XBRL
Taxonomy Extension Label Linkbase Document
|
|
X
|
|
|
|
|
|
|
|
|
|
101.PRE
|
|
XBRL
Taxonomy Extension Presentation Linkbase Document
|
|
X
|
|
|
|
|
|
|
|
|
X
Filed
herewith.
*
Furnished
herein.
**
Indicates
management contract or compensatory plan or
arrangement.
#
Schedules
and exhibits have been omitted pursuant to Item 601(b)(5) of
Regulation S-K. A copy of any omitted schedule or exhibit will be
furnished supplementally to the Securities and Exchange Commission
upon request; provided, however that PEDEVCO Corp. may request
confidential treatment pursuant to Rule 24b-2 of the Securities
Exchange Act of 1934, as amended, for any schedule or exhibit so
furnished.
ITEM 16. FORM 10-K
S
UMMARY.
None.
132
S
IGNATURES
Pursuant to the
requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the registrant has duly caused this report to be
signed on its behalf by the undersigned, thereunto duly
authorized.
|
|
PEDEVCO Corp.
|
||
|
|
|
|
|
|
March
23, 2021
|
By:
|
/s/
Simon Kukes
|
|
|
|
|
Simon
Kukes
|
|
|
|
|
Chief
Executive Officer and Director
|
|
|
|
|
(Principal
Executive Officer)
|
|
|
March
23, 2021
|
By:
|
/s/
Paul
A. Pinkston
|
|
|
|
|
Paul A.
Pinkston
|
|
|
|
|
Chief
Accounting Officer
(Principal
Financial and Accounting Officer)
|
|
|
|
|
|
|
Pursuant to the
requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates
indicated.
|
Signature
|
|
Title
|
|
Date
|
|
|
|
|
|
|
|
By: /s/ Simon Kukes
|
|
Chief Executive Officer and Director
|
|
March 23, 2021
|
|
Simon Kukes
|
|
(Principal Executive Officer)
|
|
|
|
|
|
|
|
|
|
By: /s/ Paul A. Pinkston
|
|
Chief Accounting Officer
|
|
March 23, 2021
|
|
Paul A. Pinkston
|
|
(Principal Financial and Accounting Officer)
|
|
|
|
|
|
|
|
|
|
By: /s/ John J. Scelfo
|
|
Chairman of the Board of Directors
|
|
March 23, 2021
|
|
John J. Scelfo
|
|
|
|
|
|
|
|
|
|
|
|
By: /s/ H. Douglas Evans
|
|
Director
|
|
March 23, 2021
|
|
H. Douglas Evans
|
|
|
|
|
|
|
|
|
|
|
|
By: /s/ Ivar Siem
|
|
Director
|
|
March 23, 2021
|
|
Ivar Siem
|
|
|
|
|
133
TABLE OF CONTENTS
Part I - Financial InformationItem 1. Financial StatementsNote 7 Ppp LoanItem 8. Financial Statements and Supplementary DataItem 7A. Quantitative and Qualitative Disclosure About Market RiskNote 1 Basis Of PresentationNote 2 Description Of BusinessNote 3 Summary Of Significant Accounting PoliciesNote 4 CashNote 5 Revenue From Contracts with CustomersNote 6 Oil and Gas PropertiesNote 8 Asset Retirement ObligationNote 9 Commitments and ContingenciesNote 10 Shareholders EquityNote 11 Share-based CompensationNote 12 Income TaxesNote 13 Subsequent EventsItem 9. Changes in and Disagreements with Accountants on Accounting and Financial DisclosureItem 9A. Controls and ProceduresItem 9B. Other InformationItem 1. 01 Entry Into A Material Definitive AgreementItem 2. 01 Completion Of Acquisition Or Disposition Of AssetsItem 9B. Other Information Item 1. 01Part IIIItem 10. Directors, Executive Officers and Corporate GovernanceItem 11. Executive CompensationPart IIItem 8. Financial Statements and Supplementary Data - Note 11 Share-based CompensationItem 12. Security Ownership Of Certain Beneficial Owners and Management and Related Stockholder MattersItem 13. Certain Relationships and Related Transactions, and Director IndependenceNote 10 Shareholders Equity Common StockItem 14. Principal Accountant Fees and ServicesPart IVItem 15. Exhibits and Financial StatementsItem 16. Form 10-k Summary