I
TEM 1 AND 2. BUSINESS AND
PROPERTIES.
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 shareholders of Pacific
Energy Development gained control of approximately 95% of the
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.
Office Leases
Our
corporate headquarters is located in approximately 4,600 square
feet of office space at 1250 Wood Branch Park Dr., Suite 400,
Houston, Texas 77079. We lease that space pursuant to a lease that
expires in August 2019 and the company is currently in negotiations
to extend its lease or move to new office space to accommodate
growth. The Company previously had additional office space at our
former corporate headquarters in Danville, California, which lease
was terminated in February 2019 without penalty or other amounts
due.
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,
2018, we held approximately 23,441 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, 2018, we held interests in 337 gross (337 net)
wells in our Permian Basin Asset of which 51 are active producers,
18 are active injectors and one well is an active Saltwater
Disposal Well (“
SWD
”), all of which are
held by PEDCO and operated by its wholly-owned operating
subsidiaries, and
interests in
69 gross (21.5 net) wells in our D-J Basin Asset, of which 18 gross
(16.2 net) wells are operated by Red Hawk and currently producing,
29 gross (5.2 net) wells are non-operated, and 22 wells have an
after-payout interest.
Restructuring
●
Prior
to June 2018, the Company focused primarily on development of the
unconventional shale formations within the D-J Basin. The Company
organically developed and aggregated oil and gas properties through
the energy industry downturn in 2016, in the process accumulating
$73.4 million in debt as of June 25, 2018.
●
On June 26, 2018, the Company secured a strategic
investment from SK Energy LLC (“
SK
Energy
”), which is owned
and controlled by Dr. Simon Kukes, who subsequently became the
Chief Executive Officer and a director of the Company on July 12,
2018, amounting to a $7.7 million note investment which proceeds,
and related transactions, resulted in the elimination of $78.3
million of outstanding liabilities, and which transactions also
included the $100,000 acquisition by SK Energy, from a third party,
of all the outstanding shares of the Company’s
then-outstanding Series A Convertible Preferred Stock (66,625
shares convertible into 47.6% of the Company’s outstanding
shares post-conversion(collectively referred to as the
“
Restructuring
”).
At the time of the Restructuring, the Company owned 9,607 net acres
located within the Wattenberg Core and Wattenberg Extension of the
D-J Basin.
●
The
result of the Restructuring was a simplified balance sheet, a
significant reduction in indebtedness, and a new management team
with a new corporate and enhanced operational focus.
Transformation
Simultaneously with
the Restructuring, the newly installed management team was in the
process of evaluating several acquisitions that contemplated a
shift in the Company’s overall business strategy to focus on
assets with the following characteristics:
o
Long-lived,
conventional oil and gas properties
o
Tighter
conventional reservoirs with historical underdeveloped vertical
recovery, ideal for horizontal development
o
Permeability and
rock properties significantly better than shale plays
o
Minimal to no
application of modern drilling and completion techniques and
technologies
o
Existing equipment,
facilities and available access to infrastructure
o
Large contiguous
acreage positions
Consistent with the
Company’s new business strategy, the Company consummated the
following transactions in August 2018:
Acquisition of Permian Basin Properties
On
August 31, 2018, the Company closed the acquisition of the Permian
Basin Asset in New Mexico, from Hunter Oil Company for a purchase
price of $21.3 million. The purchase price included $18.5 million
for all production, associated assets and acreage, $500,000 for the
operating entities and associated inventory, and $2.3 million of
restricted cash held in the operating companies for bonding with
the State of New Mexico. These properties had previously been
evaluated by the new management team and fit the new corporate
focus. Both the Milnesand and Chaveroo fields in the Permian Basin
Asset are legacy oil fields having produced to date 48 million
barrels of oil equivalent from the San Andres formation, via
40-acre vertical well spacing. The Company believes that by
applying horizontal drilling and modern completion techniques to
the Permian Basin Asset, downspacing to 20 acres can be achieved at
a lower cost, with significantly better recoveries than continued
vertical drilling.
To
finance this acquisition, the Company sold $23.6 million of
convertible debt with a conversion price of $2.13 per share. SK
Energy purchased $22.0 million of the convertible debt, which SK
Energy subsequently converted into common stock effective March 1,
2019, as discussed below under “
Recent Events
” –
“
SK Energy Note
Amendment; Note Purchases and
Conversion
”.
Acquisition of Additional D-J Basin Properties
In
August 2018 the Company also acquired additional assets consisting
of four operated wells and 2,340 net acres held by production in
the D-J Basin which added to the Company’s then-current
position. This consolidation of ownership in existing acreage
within the D-J Basin provides for a more focused development plan
related to these assets.
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 shareholder
value.
Specifically, we
seek to increase shareholder 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 DJ-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, 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 through 2019 will be focused on the development
of our Permian Basin Asset, with a secondary focus on development
of our D-J Basin Asset. Our 2019 total development plan calls for
the deployment of an estimated $52 million in capital, of which
approximately $22 million has been raised to date. On our Permian
Basin Asset four initial horizontal wells were drilled in December
2018 and January 2019 in phase one of our development plan,
followed by phase two which contemplates the drilling and
completion of an additional eight horizontal wells through 2020,
subject to, and based upon, the results from phase one, and in each
case, available funding. Our 2019 D-J Basin Asset development plan
is currently under evaluation for our operated acreage and our
non-operated acreage and is projected to require approximately $7.6
million in capital through 2019. Due to the held-by-production
nature of our Permian Basin assets, we believe capital can be
readily allocated to our D-J Basin assets if needed. 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) our projected cash flow from operations, (ii) our existing cash
on hand, (
iii) equity infusions
or loans (which may be convertible) made available from
our largest shareholder, SK Energy, which is owned and controlled
by Dr. Simon Kukes, our Chief Executive Officer and director, which
funding SK Energy is under no obligation to provide and which funds
may not be available on favorable terms, if at all. In addition, we
may seek additional funding through asset sales, farm-out
arrangements, lines of credit, or public or private debt or equity
financings to fund additional 2019 capital expenditures and/or
acquisitions. If market conditions are not conducive to
raising additional funds, the Company may choose to extend the
drilling program and associated capital expenditures further
into 2020.
The
following chart reflects our current organizational
structure:
*Represents
percentage of total voting power based on 45,288,828
shares of common stock (solely on an issued and outstanding basis)
outstanding as of March 27, 2019, with beneficial ownership
calculated in accordance with Rule 13d-3 of the Exchange Act (but
without reflecting the conversion of convertible securities into
voting securities, including, options exercisable for common stock
of the Company. Holdings of SK Energy LLC, an entity wholly-owned
and controlled by our CEO and director Dr. Simon Kukes, are also
included in holdings of Senior Management and Board – See
“
Part
III
” — “
Item 12. Security Ownership of Certain
Beneficial Owners and Management and Related Stockholder
Matters
.”
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.
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, Dr. 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 13 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
nearly 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 E&P and oil field
service companies. Furthermore, our Board includes H. Douglas
Evans, who brings over
40
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 current Chairman and
previously its 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.
Significant acreage positions and
drilling potential
. As of December 31, 2018, we have
accumulated interests in a total of approximately 23,441 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 current Permian Basin Asset could contain
over 195 potential net wells based on currently identified drilling
locations using 120-acre spacing, and our D-J Basin Asset could
contain up to approximately 149 potential net wells based on
80-acre spacing, providing us with a substantial drilling inventory
for future years.
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, 2018, sales to one customer comprised
47% of the Company’s total oil and gas revenues. 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. As a
consequence, the prices we receive for crude oil move up and down
in direct correlation with the oil market as it reacts to supply
and demand factors. Transportation costs related to moving crude
oil are also deducted from the price received for crude
oil.
We are
a party to a six-month crude oil purchase contract with a third
party buyer, expiring June 30, 2019, pursuant to which the buyer
purchases the crude oil produced from our 18 operated wells in our
D-J Basin Asset, at a price per barrel equal to the average of the
New York Mercantile Exchange’s ("
NYMEX
") daily settle quoted
price for Cushing/WTI for trade days only during a calendar month,
applicable to product delivered during any such calendar month,
less a per barrel differential of $6.60. The crude oil is purchased
at the wellhead, and we do not bear any incremental transportation
costs.
In
connection with our September 2018 acquisition of certain Permian
Basin assets from
Ridgeway Arizona Oil
Corp. (which we subsequently acquired), w
e also became a
party to a month-to-month crude oil purchase contract with a third
party buyer, pursuant to which the buyer purchases the crude oil
produced from our 69 operated wells in our Permian Basin Asset, at
a price per barrel equal to the average of the NYMEX daily settle
quoted price for Cushing/WTI for trade days only during a calendar
month, applicable to product delivered during any such calendar
month, less a per barrel differential of $3.64. The crude oil is
purchased at the wellhead, and we do not bear any incremental
transportation costs.
Natural
Gas
.
Our
natural gas is sold under both long-term and short-term natural gas
purchase agreements. 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.
We are
a party to a Gas Purchase Contract, dated December 1, 2011, with
DCP Midstream, LP (which we refer to as “
DCP
”), pursuant to which
we sell to DCP all gas produced from nine of our D-J Basin Asset
operated wells and surrounding lands located in Weld County,
Colorado, at a purchase price equal to 83% of the net weighted
average value for gas attributable to us that is received by DCP at
its facilities sold during the month, less a $0.06/gallon local
fractionation fee for NGLs, for a period of ten years ending
December 1, 2021, after which time the contract reverts to a
month-to-month basis and is subject to cancellation by either party
at any time upon at least thirty (30) days advance
notice.
We also
became a party to a Gas Purchase Agreement, dated April 1, 2012, as
amended, with Sterling Energy Investments LLC, which we refer to as
Sterling, pursuant to which we sell to Sterling all gas produced
from nine of our D-J Basin Asset wells and surrounding lands
located in Weld County, Colorado, at a purchase price equal to 85%
of the revenue received by Sterling from the sale of gas after
processing at Sterling’s plant that is attributable to us
during the month, less a $0.50/Mcf gathering fee, subject to
escalation, for a period of twenty years, terminating April 1,
2032.
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, 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 2019 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, 2018 and our drilling capital budget with respect to this
acreage from January 1, 2019 to December 31, 2019. If commodity
prices drop significantly, we may delay drilling activities. The
ultimate amount of capital we will expend may fluctuate materially
based on, among other things, market conditions, commodity prices,
asset monetizations, non-operated project proposals, the success of
our drilling results as the year progresses, and availability of
capital
(see
“
Part
I
” – “
Item 1A. Risk
Factors
”.)
|
|
Drilling Capital
Budget
January 1, 2019
- December 31, 2019
|
Current
Core Assets:
|
|
|
|
Capital Cost to
the Company (2)
|
Permian Basin
Asset
|
23,441
|
12.0
|
$
3,291,667
|
$
39,500,000
|
D-J Basin
Asset
|
11,948
|
3.0
|
$
2,533,333
|
7,600,000
|
Facilities and
Infrastructure (3)
|
|
|
|
5,000,000
|
Total
Assets
|
35,389
|
15.0
|
|
$
52,100,000
|
(1) Includes drilling and completion of (i) four 1.0 mile lateral
wells in Phase One of the development of the Chaveroo Field in the
Permian Basin Asset, (ii) seven 1.0 mile lateral wells and one 1.5
mile lateral well in the Chaveroo, Chaveroo NE, and Milnesand
Fields of the Permian Basin Asset, and (iii) three gross horizontal
wells in the D-J Basin Asset, subject to pending AFEs from other
operators in the D-J Basin
.
(2)
Of the estimated $52.1 million total
capital cost to the Company, the Company has raised $22 million to
date and anticipates a portion to be funded by cash from
operations.
(3)
Estimated capital expenditures for construction of central
facilities including tank batteries, injection lines, heater
treaters, and SWD pumps in the Permian Basin Asset.
Our Core Areas
Permian Basin Asset
Effective September
1, 2018, we acquired 100% of the assets of Hunter Oil Company,
which assets we refer to as our “
Permian Basin Asset,
” and
which
assets we hold through our
wholly-owned subsidiary, PEDCO, with operations conducted through
PEDCO’s wholly-owned operating subsidiaries, EOR Operating
Company and Ridgeway Arizona Oil Corp. These interests are all
located in Chaves and Roosevelt Counties, New Mexico, where we
currently operate 337 gross (337 net) wells of which 51wells are
active producers, 18 wells are active injectors, and one well is an
active SWD. As of December 31, 2018, our Permian Basin Asset
acreage is located in the areas shaded in yellow in the sectional
map below.
It is
currently 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.
The
Company’s 23,441 net acres within the Chaveroo and Milnesand
fields of Chaves and Roosevelt Counties, New Mexico offer a rare
opportunity to drill infill horizontal wells targeting the higher
oil-saturations of the MPZs. There are currently 337 wellbores
within the leasehold, of which 51 are active producers and 18 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 two water handling
facilities, one in each field, that have a current combined
capacity of approximately 32,000 barrels of water per day
(bbl/d).
Infill San Andres Well Performance
(1)(2)(3)
Well
Names
|
|
Operator
|
|
County
|
|
LateralLength (feet)
|
|
Peak
IP30*
(bopd)
|
Parker
Minerals 4 22 H
|
|
Sheridan
Production Co.
|
|
Ector
|
|
2,059
|
|
571
|
Parker
Minerals 4 24H
|
|
Sheridan
Production Co.
|
|
Ector
|
|
1,846
|
|
550
|
Earlene
Fisher State 17 3H
|
|
Lime
Rock Resources
|
|
Andrews
|
|
3,692
|
|
514
|
University 14Q
1H
|
|
Ring
Energy
|
|
Andrews
|
|
4,951
|
|
509
|
Hamilton Unit
1H
|
|
Walsh
Petroleum
|
|
Yoakum
|
|
4,061
|
|
433
|
Persephone
1H
|
|
Ring
Energy
|
|
Andrews
|
|
7,067
|
|
402
|
Parker
Minerals 4 21H
|
|
Sheridan
Production Co.
|
|
Ector
|
|
3,187
|
|
351
|
Fisher
76C 6H
|
|
Lime
Rock Partners
|
|
Andrews
|
|
5,461
|
|
316
|
Dean
CSA 266H
|
|
Apache
Corporation
|
|
Cochran
|
|
5,710
|
|
309
|
Brahaney Unit
202H
|
|
Apache
Corporation
|
|
Yoakum
|
|
3,543
|
|
268
|
Captain
Ahab Harpoon 1H
|
|
Pacesetter
Energy
|
|
Andrews
|
|
5,097
|
|
264
|
Sooner
662 1H
|
|
Wishbone
Energy Partners
|
|
Yoakum
|
|
4,101
|
|
249
|
Dean
CSA 264H
|
|
Apache
Corporation
|
|
Cochran
|
|
5,924
|
|
233
|
Dunbar
05 6H
|
|
Sheridan
Production Co.
|
|
Gaines
|
|
4,513
|
|
225
|
Roberts
Unit 261H
|
|
Apache
Corporation
|
|
Yoakum
|
|
5,689
|
|
73
|
Source:
IHS Markit
*
Initial thirty (30) day production.
(1)
Performance analysis of 15 horizontal wells within
existing legacy vertical fields on 20-acre spacing or
less.
(2)
Production was normalized to a lateral length of
4,620’ to represent the length of Chaveroo & Milnesand
PUD locations.
(3)
Does not include the Transition Zone well performance to
date.
D-J Basin Asset
We have
grown our legacy D-J Basin Asset position to 11,948 net acres
following the August 1, 2018 acquisition of 2,340 net acres held by
production and four operated wells in Weld and Morgan Counties,
Colorado, discussed above.
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 County, Colorado. Red Hawk has an interest in 69 gross
(21.5 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 circled in the map below
.
The D-J Basin has seen a tremendous amount of growth in drilling
activity in the past 12 months. 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, Extraction Oil & Gas, SRC Energy and Bonanza
Creek.
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,
2018, 2017, and 2016:
|
|
|
|
|
|
|
|
Total
Revenues
|
$
4,523,000
|
$
3,015,000
|
$
3,968,000
|
|
|
|
|
Oil:
|
|
|
|
Total Production
(Bbls)
|
70,395
|
52,260
|
92,966
|
Average sales price
(per Bbl)
|
$
59.00
|
$
47.15
|
$
36.98
|
Natural
Gas:
|
|
|
|
Total Production
(Mcf)
|
89,769
|
100,254
|
168,555
|
Average sales price
(per Mcf)
|
$
2.56
|
$
2.97
|
$
2.04
|
NGL:
|
|
|
|
Total Production
(Mcf)
|
45,774
|
73,254
|
66,033
|
Average sales price
(per Mcf)
|
$
3.05
|
$
3.46
|
$
2.82
|
Oil
Equivalents:
|
|
|
|
Total Production
(Boe)
(1)
|
92,985
|
81,178
|
132,064
|
Average Daily
Production (Boe/d)
|
255
|
222
|
362
|
Average Production Costs (per Boe)
(2)
|
$
19.77
|
$
13.62
|
$
9.55
|
_________________________
(1)
|
Assumes
6 Mcf of natural gas and NGL equivalents to 1 barrel of
oil.
|
(2)
|
Excludes
workover costs, marketing, ad valorem and severance
taxes.
|
As of
December 31, 2018, production from our recent acquisition of the
Chaveroo and Milnesand fields in the third quarter 2018 are the
fields that each comprise 15% or more of our total proved reserves.
In prior periods, the Wattenberg field is the only field that
comprised 15% or more of our total proved reserves. The applicable
production volumes from these fields for the years ended December
31, 2018, 2017, and 2016 is represented in the table below in total
barrels (Bbls):
|
|
|
|
Chaveroo
|
3,631
|
-
|
-
|
Milnesand
|
2,917
|
-
|
-
|
Wattenberg
|
66,220
|
46,198
|
49,316
|
The
following table summarizes our gross and net developed and
undeveloped leasehold and mineral fee acreage at December 31,
2018:
|
|
|
|
|
|
|
|
|
|
|
D-J
Basin
|
205,994
|
11,948
|
183,370
|
9,388
|
22,624
|
2,560
|
Permian
Basin
|
23,829
|
23,441
|
20,783
|
20,555
|
3,046
|
2,886
|
Total
|
229,823
|
35,389
|
204,153
|
29,943
|
25,670
|
5,446
|
(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.
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, 2018 is 49, 170 and 2,566 for the years ending
December 31, 2019, 2020 and 2021, 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, 2018. This summary includes crude
oil wells in which we have a working interest:
|
|
|
Crude
oil
|
106.0
|
80.5
|
Natural
gas
|
-
|
-
|
Total*
|
106.0
|
80.5
|
*Includes crude oil
wells from our Permian Basin Asset acquisition, which occurred in
September 2018, and account for approximately 56% of our gross and
73% of our net totals, respectively.
Drilling Activity
We
drilled wells or participated in the drilling of wells as indicated
in the table below:
|
|
|
|
|
|
|
|
|
|
|
Development
|
|
|
|
|
|
|
Productive
|
-
|
-
|
3
|
0.2
|
-
|
-
|
Dry
|
-
|
-
|
-
|
-
|
-
|
-
|
Exploratory
|
|
|
|
|
|
|
Productive
|
-
|
-
|
-
|
-
|
-
|
-
|
Dry
|
-
|
-
|
-
|
-
|
-
|
-
|
*
Represents our participation in three
non-operated wells which were completed during the applicable
year.
The
following table sets forth information about wells for which
drilling was in progress or which were drilled but uncompleted at
December 31, 2018, which are not included in the above
table:
|
|
|
|
|
|
|
|
Development
wells
|
-
|
-
|
4
|
4.0
|
Exploratory
wells
|
-
|
-
|
-
|
-
|
Total
|
-
|
-
|
4
|
4.0
|
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, 2018, the
Company’s total estimated proved reserves were 12.4 million
Boe of which 11.5 million Bbls were crude oil reserves, and 5.4
million Mcf were natural gas and NGL reserves.
Internal Controls.
Clayton Riddle,
our Vice
President of Development (a non-executive position), 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 Bachelor of Science degree in
Petroleum Engineering with in excess of 15 years of oil and gas
experience, including in excess of five years as a reserves
estimator and is a member of 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.
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
incorporated by reference into 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)
”.
Material Events During the Year Ended December 31,
2018
SK Energy Note and Related Transactions
On June 26, 2018, the Company borrowed $7.7
million from SK Energy, which amount was evidenced by a Promissory
Note dated June 25, 2018, in the amount of $7.7 million (the
“
SK Energy
Note
”). SK Energy is 100%
owned and controlled by Dr. Simon Kukes, our Chief Executive
Officer and director. The SK Energy Note accrues interest monthly
at 8% per annum, payable quarterly (beginning October 15, 2018), in
either cash or shares of common stock (at the option of the
Company), or with the consent of SK Energy, such interest may be
accrued and capitalized. If interest on the SK Energy Note is paid
in common stock, SK Energy will be due that number of shares of
common stock as equals the amount due divided by the average of the
closing sales prices of the Company’s common stock for the
ten trading days immediately preceding the last day of the calendar
quarter prior to the applicable payment date, rounded up to the
nearest whole share of common stock (the “
Interest
Shares
”). The SK Energy
Note is due and payable on June 25, 2021, but may be prepaid at any
time, without penalty. Other than in connection with the Interest
Shares. The SK Energy Note contains standard and customary events
of default and upon the occurrence of an event of default, the
amount owed under the SK Energy Note accrues interest at 10% per
annum. As additional consideration for SK Energy agreeing to the
terms of the SK Energy Note, the Company issued SK Energy 600,000
shares of common stock (the “
Loan
Shares
”).
As part of the same transaction and as a required
condition to closing the sale of the SK Energy Note, SK Energy
entered into a Stock Purchase Agreement with Golden Globe Energy
(US), LLC (“
GGE
”), the then holder of our outstanding
66,625 shares of Series A Convertible Preferred Stock (convertible
pursuant to their terms into 6,662,500 shares of the
Company’s common stock – 47.6% of the Company’s
then outstanding shares post-conversion), pursuant to which on June
25, 2018, SK Energy purchased, for $100,000, all of the Series A
Convertible Preferred Stock).
Debt Restructuring
On June 25, 2018, the Company entered into Debt
Repayment Agreements (the “
Repayment
Agreements
”, each
described in greater detail below) with (i) the holders of our then
outstanding Tranche A Secured Promissory Notes
(“
Tranche A
Notes
”) and Tranche B
Secured Promissory Notes (“
Tranche B
Notes
”), which the
Company entered into pursuant to the terms of the May 12, 2016
Amended and Restated Note Purchase Agreement, (ii) RJ Credit LLC
(“
RJC
”), which held a subordinated promissory
note issued by the Company pursuant to that certain Note and
Security Agreement, dated April 10, 2014, as amended (the
“
RJC Subordinated
Note
”), and (iii) MIE
Jurassic Energy Corporation, which held a subordinated promissory
note issued by the Company pursuant to that certain Amended and
Restated Secured Subordinated Promissory Note, dated February 18,
2015, as amended (the “
MIEJ
Note
”, and together with
the “
Tranche B
Notes,
” the
“
Junior
Notes
”), pursuant to
which, on June 26, 2018, the Company retired all of the then
outstanding Tranche A Notes, in the aggregate amount of
approximately $7,260,000 in exchange for cash paid of $3,800,000
and all of the then outstanding Junior Notes, in the aggregate
amount of approximately $70,299,000, in exchange for an aggregate
amount of cash paid of $3,876,000.
Pursuant to the terms of the Repayment Agreement
relating to the Tranche B Notes, in addition to the cash
consideration due to the Tranche B Note holders, as described
above, we agreed to grant to certain of the Junior Note holders
their pro rata share of warrants to purchase an aggregate of
1,448,472 shares of common stock of the Company (the
“
Repurchase
Warrants
”). The
Repurchase Warrants have a term of three years and an exercise
price equal to $0.322, one (1) cent above the closing price of the
Company’s common stock on June 26, 2018.
Additionally, on June 25, 2018, the Company
entered into a Debt Repayment Agreement (the
“
Bridge Note Repayment
Agreement
”) with all of
the holders of its convertible subordinated promissory notes issued
pursuant to the Second Amendment to Secured Promissory Notes, dated
March 7, 2014, originally issued on March 22, 2013 (the
“
Bridge
Notes
”), pursuant to
which all of the holders, holding in aggregate $475,000 of
outstanding principal amount under the Bridge Notes, agreed to the
payment and full satisfaction of all outstanding amounts (including
accrued interest and additional payment-in-kind) for 25% of the
principal amounts owed thereunder, or an aggregate amount of cash
paid of $119,000.
The
result of the above transactions was a net reduction of liabilities
of approximately $70,728,000 that were removed from the
Company’s balance sheet as of June 25, 2018. For the year
ended December 31, 2018, a gain on the settlement of all of these
debts in the amount of $70,309,000 was recorded ($70,631,000, net
of the expense related to the issuance of warrants to certain of
the Tranche A Note holders with an estimated fair value of $322,000
based on the Black-Scholes option pricing model).
NYSE American Compliance
On June 27, 2018, the NYSE American (the
“
Exchange
”)
notified the Company that it had regained compliance with the NYSE
American continued listing standards. Moving forward, the Company
will be subject to the Exchange’s normal continued listing
monitoring. In addition, in the event that the Company is again
determined to be noncompliant with any of the Exchange’s
continued listing standards within twelve (12) months of the
notice, the Exchange will consider the relationship between the
Company’s previous noncompliance and such new event of
noncompliance and take appropriate action which may include
implementing truncated compliance procedures or immediately
initiating delisting proceedings.
Series A Convertible Preferred Stock Amendment and
Conversion
In
connection with the Stock Purchase Agreement, and immediately
following the closing of the acquisition described in the Stock
Purchase Agreement (discussed above), the Company and SK Energy, as
the then holder of all of the then outstanding shares of Series A
Convertible Preferred Stock, agreed to the filing of an Amendment
to the Amended and Restated Certificate of Designations of PEDEVCO
Corp. Establishing the Designations, Preferences, Limitations and
Relative Rights of Its Series A Convertible Preferred Stock (the
“
Preferred
Amendment
”), which amended the designation of our
Series A Convertible Preferred Stock (the “
Designation
”) to remove
the beneficial ownership restriction contained therein, which
prevented any holder of Series A Convertible Preferred Stock from
converting such Series A Convertible Preferred Stock into shares of
common stock of the Company if such conversion would result in the
holder thereof holding more than 9.9% of the Company’s then
outstanding common stock. The Company filed the Preferred Amendment
with the Secretary of State of Texas on June 26, 2018.
On
July 3, 2018, SK Energy converted all of the Series A Convertible
Preferred Stock shares it acquired pursuant to the Stock Purchase
Agreement with GGE, pursuant to their terms, into 6,662,500 shares
of the Company’s common stock, representing 45.3% of the
Company’s then outstanding common stock, and resulting in
approximately 14,717,119 shares of the Company’s common stock
being issued and outstanding. The issuance was deemed a change of
control under applicable NYSE American rules and regulations,
provided that such issuance was previously approved at the 2015
annual meeting of shareholders of the Company held on October 7,
2015. The conversion transaction constituted a change in control of
the Company under applicable NYSE American rules and
regulations. The shares of common stock issued upon conversion
of the Series A Convertible Preferred Stock, together with the Loan
Shares (issued to SK Energy on June 26, 2018) totaled 49.9% of our
then outstanding shares of common stock, which shares are
beneficially owned by SK Energy and Dr. Kukes.
Convertible Note Sales
On August 1, 2018, we raised $23,600,000 through
the sale of $23,600,000 in Convertible Promissory Notes (the
“
Convertible
Notes
”). A total of
$22,000,000 in Convertible Notes was purchased by SK Energy;
$200,000 in Convertible Notes was purchased by an executive officer
of SK Energy; $500,000 in Convertible Notes was purchased by a
trust affiliated with John J. Scelfo, a director of the Company;
$500,000 in Convertible Notes was purchased by an entity affiliated
with Ivar Siem, our director, and J. Douglas Schick, who was
appointed as the President of the Company on August 1, 2018;
$200,000 in Convertible Notes was purchased by H. Douglas Evans,
who was appointed as a member of the Board of Directors on
September 27, 2018; and $200,000 in Convertible Notes were
purchased by an unaffiliated party.
The
Convertible Notes accrue interest monthly at 8.5% per annum, which
interest is payable on the maturity date unless otherwise converted
into our common stock as described below.
The Convertible Notes and all accrued interest
thereon are convertible into shares of our common stock, from time
to time after August 29, 2018, at the option of the holders
thereof, at a conversion price equal to the greater of (x) $0.10
above the greater of the book value of the Company’s common
stock and the closing sales price of the Company’s common
stock on the date the Convertible Notes were entered into (the
“
Book/Market
Price
”) (which
was $2.13 per share); (y) $1.63 per share; and (z) the
VWAP Price, defined as the volume weighted average price
(calculated by aggregate trading value on each trading day) of the
Company’s common stock for the 20 trading days ending August
29, 2018, which price was $2.08 per share, and which conversion
price is therefore $2.13 per share.
The conversion of the SK Energy Convertible Note
is subject to a 49.9% conversion limitation (for so long as SK
Energy or any of its affiliates holds such note), which prevents
the conversion of any portion thereof into common stock of the
Company if such conversion would result in SK Energy beneficially
owning (as such term is defined in the Exchange
Act)(“
Beneficially
Owning
”) more than 49.9%
of the Company’s outstanding shares of common
stock.
The conversion of the other Convertible Notes is
subject to a 4.99% conversion limitation, at any time such note is
Beneficially Owned by any party other than (i) SK Energy or any of
its affiliates (which is subject to the separate conversion
limitation described above); (ii) any officer of the Company; (iii)
any director of the Company; or (iv) any person which at the time
of first obtaining Beneficial Ownership of the Convertible Note
beneficially owns more than 9.99% of the Company’s
outstanding common stock or voting stock (collectively (ii) through
(iv), “
Borrower
Affiliates
”). The
Convertible Notes are not subject to a conversion limitation at any
time they are owned or held by Borrower
Affiliates.
The
Convertible Notes are due and payable on August 1, 2021, but may be
prepaid at any time, without penalty. The Convertible Notes contain
standard and customary events of default and upon the occurrence of
an event of default, the amount owed under the Convertible Notes
accrues interest at 10% per annum.
The
terms of the Convertible Notes may be amended or waived and such
amendment or waiver shall be applicable to all of the Convertible
Notes with the written consent of Convertible Note holders holding
at least a majority in interest of the then aggregate dollar value
of Convertible Notes outstanding.
Hunter Oil Purchase and Sale Agreement and Stock Purchase
Agreement
On August 1, 2018, we (through our wholly-owned
subsidiary PEDCO entered into a Purchase and Sale Agreement
with Milnesand Minerals Inc., a Delaware corporation, Chaveroo
Minerals Inc., a Delaware corporation, Ridgeway Arizona Oil Corp.,
an Arizona corporation (“
RAOC
”),
and EOR Operating Company, a Texas corporation
(“
EOR
”)(collectively “
Seller
”)(the
“
Purchase
Agreement
”). Pursuant to
the Purchase Agreement, PEDCO agreed to acquire certain oil and gas
assets described in greater detail below (the
“
Assets
”)
from the Seller in consideration for $18,500,000 (of which $500,000
is to be held back to provide for potential indemnification of
PEDCO under the Purchase Agreement and Stock Purchase Agreement
(described below), with one-half ($250,000) to be released to
Seller 90 days after closing (which amount has been released to
date) and the balance ($250,000) to be released 180 days after
closing (provided that if a court of competent jurisdiction
determines that any part of the amount withheld by PEDCO subsequent
to 180 days after closing was in fact due to the Seller, PEDCO is
required to pay Seller 200%, instead of 100%, of the amount so
retained)).
On
August 31, 2018, we closed the transactions contemplated by the
Purchase Agreement and acquired the Assets for an aggregate of
$18.5 million. The effective date of the acquisition was September
1, 2018.
The Purchase Agreement contains customary
representations and warranties of the parties, and indemnification
requirements (subject to a $25,000 aggregate minimum threshold and
a $1,000,000 cap as to each of buyer and seller).
The Purchase Agreement allows PEDCO to
audit the revenues and expenses of the Seller attributable to the
Assets for the period of three years prior to the closing, among
other things, and requires the Seller to provide assistance to
PEDCO in connection with such audit for the first 180 days
following closing (with such Seller’s reasonable costs
associated with such audit being reimbursed by PEDCO at the rate of
150% of such costs).
The Assets represent approximately 23,441 net
leasehold acres, current operated production, and all of
Seller’s leases and related rights, oil and gas and other
wells, equipment, easements, contract rights, and production
(effective as of the effective date) as described in the Purchase
Agreement. The Assets are located in the San Andres play in the
Permian Basin situated in west Texas and eastern New Mexico, with
all acreage and production 100% operated and substantially all
acreage held by production. See also the more detailed description
of the Assets under “
Oil and Gas
Properties
”,
below.
Also on August 1, 2018, PEDCO entered into a Stock
Purchase Agreement with Hunter Oil Production Corp.
(“
Hunter
Oil
”). Pursuant to the
Stock Purchase Agreement, which closed on August 31, 2018, PEDCO
acquired all of the stock of RAOC and EOR (the
“
Acquired
Companies
”) for a net of
$500,000 (an aggregate purchase price of $2,816,000, less
$2,316,000 in restricted cash which the Acquired Companies are
required to maintain as of the closing date). The Stock Purchase
Agreement contains customary representations and warranties of the
parties, post-closing adjustments, and indemnification requirements
requiring Hunter Oil to indemnify us for certain items (subject to
the $25,000 aggregate minimum threshold and $1,000,000 cap provided
for in the Purchase Agreement) and us to indemnify Hunter Oil for
certain items (which requirement does not include a threshold or
cap).
On
December 17, 2018 the Company and Seller agreed that the Company
would pay to Seller $25,000 for all post-closing adjustments and
post-closing support under the Purchase Agreement and accelerate
the payment by the Company to Seller of the final $250,000 to be
released 180 days after closing, which payments were made by the
Company to Seller on December 17, 2018.
Condor Acquisition
On August 1, 2018, Red Hawk, our
wholly-owned subsidiary entered into a Membership Interest Purchase
Agreement (the “
Membership Purchase
Agreement
”) with MIE
Jurassic Energy Corporation (“
MIEJ
”).
Pursuant to the Membership Purchase Agreement, MIEJ sold Red Hawk
100% of the outstanding membership interests of Condor Energy
Technology LLC (“
Condor
”)
in consideration for $537,000. Condor owns approximately 2,340 net
leasehold acres, 100% held by production (HBP), located in Weld and
Morgan Counties, Colorado, with four operated producing wells. The
Membership Purchase Agreement contains customary representations
and warranties and provides that, as of the August 1, 2018
effective date, Red Hawk will assume responsibility for all costs,
expenses and obligations outstanding and unpaid that are
attributable to the properties as of the effective date and
thereafter, and Red Hawk will also be entitled to all income and
revenues received by Condor that are attributable to the
properties, even if received by Condor with respect to oil and gas
production prior to the effective date.
The Company previously owned 20% of Condor through
PEDCO, along with MIEJ, which then held 80% of Condor, until
February 19, 2015, when we and PEDCO entered into a Settlement
Agreement (the “
MIEJ Settlement
Agreement
”) with MIEJ,
whereby, among other things, PEDCO sold its full 20% interest in
Condor to MIEJ. Additionally, until June 25, 2018, when such amount
was repaid pursuant to a Debt Repayment Agreement (described in
greater detail in the Current Report on Form 8-K which we filed
with the SEC on June 25, 2018), we owed approximately $6.4 million
to MIEJ pursuant to the terms of a Secured Subordinated Promissory
Note (the “
MIEJ
Note
”).
Warrant Repurchase Agreements
On
August 31, 2018, we entered into warrant repurchase agreements with
certain of the Junior Note holders who received Repurchase
Warrants, namely Senior Health Insurance Company of Pennsylvania,
Principal Growth Strategies, LLC, and RJ Credit LLC (collectively,
the “
Warrant
Holders
”). Pursuant to the warrant repurchase
agreements, the Company repurchased warrants to purchase an
aggregate of 1,105,935 shares of the Company’s common stock
(the shares of common stock issuable upon exercise of which such
Repurchase Warrants, the “
Warrant Shares
”) held by
the Warrant Holders, which warrants had a term of three years
(through August 25, 2021) and an exercise price equal to $0.322 per
share, as discussed above under “
Debt Restructuring
”. The
Repurchase Warrants were repurchased for an aggregate of $1,095,000
or $0.99 per Warrant Share, which amount the Company paid to the
Warrant Holders on September 17, 2018. Effective on the date of
payment of the warrant purchase amounts, the Repurchase Warrants
and the agreements evidencing such Repurchase Warrants were deemed
to have been repurchased by the Company and cancelled. The Warrant
Repurchase Agreements also included a release by which the Warrant
Holders released the Company from any liability or claims
associated with the Repurchase Warrants and certain of the Warrant
Repurchase Agreements included a release by which we released the
applicable Warrant Holders party thereto. The terms of the Warrant
Repurchase Agreements were individually negotiated with each
associated group of Warrant Holders.
Additional Convertible Note Sales
On October 25, 2018, the Company borrowed an
additional $7.0 million from SK Energy, through the issuance of a
convertible promissory note in the amount of $7.0 million (the
“
October 2018
Convertible Note
”)
.
The
October 2018 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 October 2018 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 $1.79 per share. Further, the conversion of the
October 2018 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 October 2018 Convertible Note is due and payable on October 25,
2021 but may be prepaid at any time without
penalty.
Also
on October 25, 2018, the Company and SK Energy agreed to convert an
aggregate of $164,000 of interest accrued under the SK Energy Note
from its effective date through September 30, 2018 into 75,118
shares of the Company’s common stock, based on a conversion
price equal to $2.18 per share, pursuant to the conversion terms of
the SK Energy Note.
Recent Events
January 2019 SK Energy Convertible Note
On January 11, 2019, the Company borrowed an
additional $15.0 million from SK Energy, 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 Convertible Note is
due and payable on January 11, 2022, but may be prepaid at any time
without penalty.
Manzano Acquisition
On
February 1, 2019, for consideration of $700,000, the Company
completed an asset purchase from Manzano, LLC and Manzano Energy
Partners II, LLC, 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.
Convertible Notes Amendment and Conversion
On
February 15, 2019, the Company and SK Energy agreed to amend the
Convertible Notes and October 2018 Convertible Note described in
Note 7, 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
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 $125,729 of accrued interest under the January
2019 Note into common stock of the Company at a conversion price of
$1.50 per share as set forth in the January 2019 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 $186,776
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
SK Energy Note Amendment to Promissory Note (the
“
SK Energy Note
Amendment
”) which amended the $7.7 million principal
amount 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 Promissory 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
”).
As
a result of the Conversions, as of the date of the report, the
Company now has no debt on its balance sheet and 45,288,828 shares
of common stock issued and outstanding.
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) and New Mexico Environment
Department (administers environmental protection laws). The Oil
Conservation Division of the New Mexico Energy, Minerals and
Natural Resources Department requires 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.
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.
We anticipate that the COGCC,
the
Conservation Division of the New Mexico Energy, Minerals, and
Natural Resources Department and New Mexico Environment Department
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 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.
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, FERC has additional, jurisdiction over the
purchase or sale of gas or the purchase or sale of transportation
services subject to 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 FERC.
FERC’s rules implementing this provision make it unlawful, in
connection with the purchase or sale of gas subject to the
jurisdiction of FERC, or the purchase or sale of transportation
services subject to the jurisdiction of 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 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, 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 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 FERC in monitoring
those markets and in detecting market
manipulation.
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 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 FERC.
The
rates charged by many interstate liquids pipelines are currently
adjusted pursuant to an annual indexing methodology established and
regulated by FERC, under which pipelines increase or decrease their
rates in accordance with an index adjustment specified by FERC. For
the five-year period beginning July 1, 2016, 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 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
for 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 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.
Regulation of Environmental and Occupational Safety and Health
Matters
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.
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.
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 Water Pollution Control Act, also
known as the Clean Water Act (“
CWA
”), and analogous state laws, impose
restrictions and strict controls with respect to the discharge of
pollutants, including spills and leaks of oil and hazardous
substances, into state waters and waters of the United States. The
discharge of pollutants into regulated waters is prohibited, except
in accordance with the terms of a permit issued by the EPA or an
analogous state agency. Spill prevention, control and
countermeasure plan requirements imposed under the CWA require
appropriate containment berms and similar structures to help
prevent the contamination of navigable waters in the event of a
petroleum hydrocarbon tank spill, rupture or leak. In addition, the
CWA and analogous state laws require individual permits or coverage
under general permits for discharges of storm water runoff from
certain types of facilities. The CWA also prohibits the discharge
of dredge and fill material in regulated waters, including
wetlands, unless authorized by permit.
In June 2015, the EPA and the U.S. Army Corps of
Engineers (“
Corps”
)
published a final rule to revise the definition of "waters of the
United States" (“
WOTUS”
)
for all Clean Water Act programs, but legal challenges to this rule
followed and the rule was stayed nationwide by the U.S. Sixth
Circuit Court of Appeals in October 2015. In response to this
decision, the EPA and the Corps resumed nationwide use of the
agencies' prior regulations defining the term "waters of the United
States." However, in January 2018, the U.S. Supreme Court ruled
that the rule revising the WOTUS definition must first be reviewed
in the federal district courts, which could result in a withdrawal
of the stay by the Sixth Circuit. In addition, the EPA has issued
proposals to repeal the rule revising the WOTUS definition and to
delay its implementation until 2020 to allow time for the EPA to
reconsider the definition of the term "waters of the United
States." To the extent this rule or a revised rule expands the
scope of the CWA's jurisdiction, we could face increased costs and
delays with respect to obtaining permits for dredge and fill
activities in wetland areas in connection with any expansion
activities. Federal and state regulatory agencies may impose
substantial administrative, civil and criminal penalties as well as
other enforcement mechanisms for non-compliance with discharge
permits or other requirements of the CWA and analogous state laws
and regulations, including spills and other non-authorized
discharges.
Federal and state
regulatory agencies can impose administrative, civil and criminal
penalties for non-compliance with discharge permits or other
requirements of the CWA and analogous state laws and
regulations.
The Oil Pollution Act of 1990
(“
OPA
”), amends the CWA and sets minimum
standards for prevention, containment and cleanup of oil spills.
The OPA applies to vessels, offshore facilities, and onshore
facilities, including exploration and production facilities that
may affect waters of the United States. Under OPA, responsible
parties including owners and operators of onshore facilities may be
held strictly liable for oil cleanup costs and natural resource
damages as well as a variety of public and private damages that may
result from oil spills. The OPA also requires owners or operators
of certain onshore facilities to prepare Facility Response Plans
for responding to a worst-case discharge of oil into waters of the
United States.
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, as of 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
The Clean Air Act
(the “
CAA
”)
and comparable state laws restrict the emission of air pollutants
from many sources, such as, for example, tank batteries and
compressor stations, through air emissions standards, construction
and operating permitting programs and the imposition of other
compliance standards. These laws and regulations may require us to
obtain pre-approval for the construction or modification of certain
projects or facilities expected to produce or significantly
increase air emissions, obtain and strictly comply with stringent
air permit requirements or utilize specific equipment or
technologies to control emissions of certain pollutants. The need
to obtain permits has the potential to delay the development of oil
and natural gas projects. Over the next several years, we may be
charged royalties on natural gas losses or required to incur
certain capital expenditures for air pollution control equipment or
other air emissions related issues. For example, in October 2015,
the EPA issued a final rule under the CAA, lowering the National
Ambient Air Quality Standard (“
NAAQS
”)
for ground-level ozone from 75 parts per billion
(“
ppb
”)
for the 8-hour primary and secondary ozone standards to 70 ppb for
both standards.
In 2018, the
EPA finalized the initial area designations for the 2015 ozone
standard. Certain areas, such as the Denver Metro North Front Range
(representing the counties (or parts thereof) South, East and North
of Denver, Colorado), were designated as marginal (i.e., the lowest
level of non-attainment) non-attainment (i.e., as an
area
that
does not meet (or that contributes to ambient air quality in a
nearby area that does not meet) the national primary or secondary
ambient air quality standard for a NAAQS). The Denver Metro North
Front Range area is currently under significant threat of being
redesignated as a serious non-attainment area for ozone due to high
levels detected in 2016 and 2017. Colorado is seeking an extension
to the attainment date and the EPA has proposed to retroactively
approve the requested extension by one year, to July 20, 2019. It
is not likely that another one-year extension will be granted and
the Denver Metro North Front Range area may be reclassified to
serious non-attainment for 2020. Reclassification of areas or
imposition of more stringent standards (including a lowering of the
major source threshold for volatile organic compounds and oxides of
nitrogen and the resulting increased likelihood that a source may
be subject to Non-Attainment New Source Review) may make it more
difficult to construct new or modified sources of air pollution in
newly designated non-attainment areas. Also, states are expected to
implement more stringent requirements as a result of this new final
rule, which could apply to our operations. In addition, during the
fall of 2016, EPA issued final Control Techniques Guidelines
(“
CTGs
”)
for reducing volatile organic compound emissions from existing oil
and natural gas equipment and processes in ozone non-attainment
areas, including the Denver Metro North Front Range Ozone 8-hour
Non-Attainment area. In 2017, as part of the federal CTG process
for oil and natural gas, Colorado undertook a stakeholder and
rulemaking effort to compare the CTGs to existing Colorado
requirements to ensure they meet applicable federal requirements,
which resulted in revisions to Colorado's Regulation Number 7
(which relates to the control of ozone and hydrocarbons via oil and
gas omissions). The new state regulations include more stringent
air quality control requirements applicable to our operations. In
another example, in June 2016, the EPA finalized a revised rule
regarding criteria for aggregating multiple small surface sites
into a single source for air-quality permitting purposes applicable
to the oil and gas industry. This rule could cause small
facilities, on an aggregate basis, to be deemed a major source,
thereby triggering more stringent permitting requirements.
Compliance with these or other air pollution control and permitting
requirements have the potential to delay the development of oil and
natural gas projects and increase our costs of development and
production, which costs could have a material adverse impact on our
business and results of operations
.
Regulation of GHG Emissions
In
response to findings that emissions of carbon dioxide, methane and
other greenhouse gases (“
GHGs
”) present an
endangerment to public health and the environment, the EPA has
adopted regulations under existing provisions of the Clean Air Act
that, among other things, establish Prevention of Significant
Deterioration (“
PSD
”) construction and
Title V operating permit reviews for certain large stationary
sources that are already potential major sources of certain
principal, or criteria, pollutant emissions. Facilities required to
obtain PSD permits for their GHG emissions also will be required to
meet “best available control technology” standards that
typically will be established by state agencies. In addition, the
EPA has adopted rules requiring the monitoring and annual reporting
of GHG emissions from specified large, GHG emission sources in the
United States, including certain onshore and offshore oil and
natural gas production sources, which include certain of our
operations.
Federal agencies also have begun directly
regulating emissions of methane, a GHG, from oil and natural gas
operations. In June 2016, the EPA published the New Source
Performance Standards (“
NSPS
”)
Subpart OOOOa standards that require certain new, modified or
reconstructed facilities in the oil and natural gas sector to
reduce these methane gas and volatile organic compound emissions.
These Subpart OOOOa standards expand previously issued NSPS
published by the EPA in 2012 and known as Subpart OOOO, by using
certain equipment-specific emissions control practices. However, in
April 2017, the EPA announced that it would review this methane
rule for new, modified and reconstructed sources and initiated
reconsideration proceedings to potentially revise or rescind
portions of the rule. In June 2017, the EPA also proposed a
two-year stay of certain requirements of the methane rule pending
the reconsideration proceedings; however, the rule remains in
effect in the meantime. Similarly, in November 2016, the federal
Bureau of Land Management (“
BLM
”) issued a final rule to reduce methane
emissions by regulating venting, flaring, and leaks from oil and
gas operations on federal and American Indian lands.
California and New
Mexico have challenged the rule in ongoing litigation. In addition,
in April 2018, a coalition of states filed a lawsuit aiming to
force EPA to establish guidelines for limiting methane emissions
from existing sources in the oil and natural gas section; that
lawsuit is currently pending
.
On
the international level, in December 2015, the United States joined
the international community at the 21st Conference of the Parties
of the United Nations Framework Convention on Climate Change in
Paris, France that prepared an agreement requiring member countries
to review and “represent a progression” in their
intended nationally determined contributions, which set GHG
emission reduction goals every five years beginning in 2020. This
“Paris Agreement” was signed by the United States in
April 2016 and entered into force in November 2016; however, this
agreement does not create any binding obligations for nations to
limit their GHG emissions, but rather includes pledges to
voluntarily limit or reduce future emissions. In follow-up to an
earlier announcement by President Trump, in August 2017, the U.S.
Department of State officially informed the United Nations of the
intent of the United States to withdraw from the Paris Agreement.
The Paris Agreement provides for a four-year exit process beginning
when it took effect in November 2016, which would result in an
effective exit date of November 2020. The United States’
adherence to the exit process and/or the terms on which the United
States may re-enter the Paris Agreement or a separately negotiated
agreement are unclear at this time.
The
adoption and implementation of any international, federal or state
legislation or regulations that require reporting of GHG or
otherwise limit emissions of GHG from our equipment and operations
could result in increased costs to reduce emissions of GHG
associated with our operations as well as delays or restrictions in
our ability to permit GHG emissions from new or modified sources.
In addition, substantial limitations on GHG emissions could
adversely affect demand for the oil, natural gas and NGL we produce
and lower the value of our reserves, which devaluation could be
significant. One or more of these developments could have a
materially adverse effect on our business, financial condition and
results of operations. Additionally, it should be noted that
increasing concentrations of GHG in the Earth’s atmosphere
may produce climate changes that have significant physical effects,
such as increased frequency and severity of storms, floods and
other climatic events; if any such effects were to occur, they
could have an adverse effect on our exploration and production
operations. At this time, we have not developed a comprehensive
plan to address the legal, economic, social or physical impacts of
climate change on our operations. Finally, notwithstanding
potential risks related to climate change, the International Energy
Agency, an autonomous intergovernmental organization involved in
international energy policy, estimates that global energy demand
will continue to rise and will not peak until after 2040 and oil
and gas will continue to represent a substantial percentage of
global energy use over that time. However, recent activism directed
at shifting funding away from companies with energy-related assets
could result in limitations or restrictions on certain sources of
funding for the energy sector.
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,
o
n 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
.”
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.
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.
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.
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:
●
damage
to or destruction of property, equipment and the
environment;
●
personal injury or
loss of life; and
●
suspension of
operations.
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, 2018, we employed 14 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.
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, will 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 93% of our estimated proved reserves as of
December 31, 2018 were oil, our financial results are more
sensitive to movements in oil prices
.
Since mid-2014, the price of crude oil has significantly declined,
although the price of crude has subsequently recovered to current
levels. As a result, we experienced significant decreases in crude
oil revenues and recorded asset impairment charges driven by
commodity price declines. 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 may cause further
decline in our stock price. During the year ended December 31,
2018, the daily NYMEX WTI oil spot price ranged from a high of
$77.41 per Bbl to a low of $44.48 per Bbl and the NYMEX natural gas
Henry Hub spot price ranged from a high of $6.24 per MMBtu to a low
of $2.49 per MMBtu.
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 $84,494,000 from the date of inception (February 9, 2011)
through December 31, 2018. 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 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, acquire assets and complete exploration and
drilling operations. 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.
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 our 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 our debt and other obligations. If we are unable
to service our 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 our indebtedness, seeking
additional capital, or any combination of the foregoing. If we
raise additional 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 our 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 existing or 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 our indebtedness or to fund our other liquidity
needs.
If
for any reason we are unable to meet our future debt service and
repayment obligations, we may be in default under the terms of the
agreements governing our indebtedness, which could allow our
creditors at that time to declare our 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
our 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:
●
fluctuations in
prices of crude oil, natural gas and NGLs produced from the wells
in these areas;
●
natural
disasters such as the flooding that occurred in the D-J Basin area
in September 2013;
●
restrictive
governmental regulations; and
●
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.
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.
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 spud, 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:
●
general economic
and industry conditions, including the prices received for oil and
natural gas;
●
shortages of, or
delays in, obtaining equipment, including hydraulic fracturing
equipment, and qualified personnel;
●
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;
●
potential drainage
by operators on adjacent properties;
●
loss of, or damage
to, oilfield development and service tools;
●
problems with title
to the underlying properties;
●
increases in
severance taxes;
●
adverse weather
conditions that delay drilling activities or cause producing wells
to be shut down;
●
domestic and
foreign governmental regulations; and
●
proximity to and
capacity of transportation facilities.
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.
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 may 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 oil
fell dramatically starting in mid-2014 from a high of over $100 per
barrel in June 2014 to lows below $30 per barrel in early 2016, and
has only recently recovered to current levels, in each case based
on West Texas Intermediate (WTI) prices, due to a combination of
factors including increased U.S. supply, global economic concerns,
the likely resumption of oil exports from Iran and OPEC’s
decision not to reduce supply. 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:
●
the domestic and
foreign supply of oil, NGLs and natural gas;
●
the domestic and
foreign demand for oil, NGLs and natural gas;
●
the prices and
availability of competitors’ supplies of oil, NGLs and
natural gas;
●
the actions of the
Organization of Petroleum Exporting Countries, or OPEC, and
state-controlled oil companies relating to oil price and production
controls;
●
the price and
quantity of foreign imports of oil, NGLs and natural
gas;
●
the impact of U.S.
dollar exchange rates on oil, NGLs and natural gas
prices;
●
domestic and
foreign governmental regulations and taxes;
●
speculative trading
of oil, NGLs and natural gas futures contracts;
●
localized supply
and demand fundamentals, including the availability, proximity and
capacity of gathering and transportation systems for natural
gas;
●
the availability of
refining capacity;
●
the prices and
availability of alternative fuel sources;
●
weather conditions
and natural disasters;
●
political
conditions in or affecting oil, NGLs and natural gas producing
regions, including the Middle East and South America;
●
the continued
threat of terrorism and the impact of military action and civil
unrest;
●
public pressure on,
and legislative and regulatory interest within, federal, state and
local governments to stop, significantly limit or regulate
hydraulic fracturing activities;
●
the level of global
oil, NGL and natural gas inventories and exploration and
production activity;
●
authorization of
exports from the Unites States of liquefied natural
gas;
●
the impact of
energy conservation efforts;
●
technological
advances affecting energy consumption; and
●
overall worldwide
economic conditions.
Declines
in oil, NGL or natural gas prices would not only reduce our
revenue, but could reduce the amount of oil, NGL and natural
gas that we can produce economically. Should natural gas, NGL or
oil prices decrease from current levels and remain there for an
extended period of time, we may elect in the future to delay some
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 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. We also test our
goodwill and indefinite-lived intangible assets for impairment at
least annually on December 31 of each year, or when events or
changes in the business environment indicate that the carrying
value of a reporting unit may exceed its fair value. If conditions
in any of the businesses in which we compete were to deteriorate,
we could determine that certain of our assets were 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.
Declining general economic, business or industry conditions may
have a material adverse effect on our results of operations,
liquidity and financial condition.
Concerns
over global economic conditions, energy costs, geopolitical issues,
inflation, the availability and cost of credit, the United States
mortgage market and a declining real estate market in the United
States 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. Concerns about
global economic growth have had a significant adverse impact on
global financial markets and commodity prices. If the economic
climate in the United States or abroad continues to deteriorate,
demand for petroleum products could diminish, which could 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.
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:
●
our estimated
proved oil and natural gas reserves;
●
the amount of oil
and natural gas we produce from existing wells;
●
the prices at which
we sell our production;
●
the costs of
developing and producing our oil and natural gas
reserves;
●
our ability to
acquire, locate and produce new reserves;
●
the ability and
willingness of banks to lend to us; and
●
our ability to
access the equity and debt capital markets.
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, 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:
●
the quality and
quantity of available data;
●
the interpretation
of that data;
●
the judgment of the
persons preparing the estimate; and
●
the accuracy of the
assumptions.
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.
We may record impairments of oil and gas properties that would
reduce our shareholders’ equity.
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. The risk that we will be required to
recognize impairments of our oil and gas properties increases
during periods of low oil or gas prices. 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.
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:
●
unusual or
unexpected geologic formations;
●
adverse weather
conditions;
●
unanticipated
pressures;
●
loss of drilling
fluid circulation;
●
blowouts where oil
or natural gas flows uncontrolled at a wellhead;
●
cratering or
collapse of the formation;
●
pipe or cement
leaks, failures or casing collapses;
●
releases of
hazardous substances or other waste materials that cause
environmental damage;
●
pressures or
irregularities in formations; and
●
equipment failures
or accidents.
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 general liability coverage and $10 million umbrella
coverage that covers our and our subsidiaries’ business and
operations. Our wholly-owned subsidiary, Red Hawk, which operates
our D-J Basin Asset, also maintains a $10 million control of well
insurance policy that covers its operations in Colorado, and our
wholly-owned subsidiary, PEDCO, which operates our Permian Basin
Asset through its wholly-owned subsidiaries EOR and RAOC, also
maintains a $10 million control of well insurance policy that
covers its operations in New Mexico. 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.
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.
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.
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, 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.
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
shareholders 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:
●
the difficulty of
integrating acquired companies, concepts and
operations;
●
the potential
disruption of the ongoing businesses and distraction of our
management and the management of acquired companies;
●
change in our
business focus and/or management;
●
difficulties in
maintaining uniform standards, controls, procedures and
policies;
●
the potential
impairment of relationships with employees and partners as a result
of any integration of new management personnel;
●
the potential
inability to manage an increased number of locations and
employees;
●
our ability to
successfully manage the companies and/or concepts
acquired;
●
the failure to
realize efficiencies, synergies and cost savings; or
●
the effect of any
government regulations which relate to the business
acquired.
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:
●
a significant
portion of our cash flows could be used to service our
indebtedness;
●
a high level of
debt would increase our vulnerability to general adverse economic
and industry conditions;
●
any covenants
contained in the agreements governing our outstanding indebtedness
could limit our ability to borrow additional funds;
●
dispose of assets,
pay dividends and make certain investments;
●
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
●
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.
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.
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 senior lender.
Dr. 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 Dr. Simon Kukes is the principal of SK Energy
LLC, the Company’s largest shareholder. Dr. Kukes also
beneficially owns 82.4% 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.
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, the demand for hydraulic fracturing services currently
exceeds 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 has further amplified this equipment and crew
shortage. 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:
●
timing and amount
of capital expenditures;
●
the
operator’s expertise and financial resources;
●
the rate of
production of reserves, if any;
●
approval of other
participants in drilling wells; and
●
selection of
technology.
The marketability of our production is dependent upon oil and
natural gas gathering and transportation facilities owned and
operated by third parties, and the unavailability of satisfactory
oil and natural gas transportation arrangements would have a
material adverse effect on our revenue.
The
unavailability of satisfactory oil and natural gas transportation
arrangements may hinder our access to oil and natural gas markets
or delay 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 and terminal
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. 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. If that
were to occur, we would be unable to realize revenue from those
wells until production arrangements were made to deliver our
production to market. Furthermore, if we were required to shut-in
wells we might also be obligated to pay shut-in royalties to
certain mineral interest owners in order to maintain our leases. 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.
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 and what prices will be charged. 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 could adversely affect 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 could 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.
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.
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:
●
actual prices we
receive for oil and natural gas;
●
actual cost and
timing of development and production expenditures;
●
the amount and
timing of actual production; and
●
changes in
governmental regulations or taxation.
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.
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.
Changes in the legal and regulatory environment governing the oil
and natural gas industry, particularly changes in the current
Colorado forced pooling system, could have a material adverse
effect on our business.
Our business is subject to various forms of
government regulation, including laws and regulations 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. This methodology is especially important for our operations
in the Greeley area, where there are many interest holders. Changes
in the legal and regulatory environment governing our industry,
particularly any changes to Colorado forced pooling procedures that
make forced pooling more difficult to accomplish, could result in
increased compliance costs and adversely affect our business,
financial condition and results of operations.
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.
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. Although none of the proposed initiatives were
passed, future initiatives are possible. Similarly, 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 and 2. Business
and Properties
” —
“
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.
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.
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 and 2. Business
and Properties
” —
“
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, The Resource Conservation and
Recovery Act (“
RCRA
”), 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.
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.
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.
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 D-J Basin Asset acreage must be drilled
before lease expiration, generally within three to five years, and
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.
Our
leases on oil and natural gas properties in the D-J Basin typically
have a primary term of three to five years, after which they expire
unless, prior to expiration, production is established within the
spacing units covering the undeveloped acres. Currently 11,738 of
our D-J Basin Asset acreage is held by production and not subject
to lease expiration, with approximately 220 acres subject to lease
expiration if these acres are not developed by us or other
operators in whose wells we participate on such acreage prior to
expiration. Similarly, currently 2,886 of our Permian Basin Asset
acreage is held by production and not subject to lease expiration,
with approximately 20,555 acres 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 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.
The swaps regulatory and other provisions of the Dodd-Frank Act and
the rules adopted thereunder and other regulations could adversely
affect our ability to hedge risks associated with our business and
our operating results and cash flows.
The provisions of The Dodd-Frank Wall Street
Reform and Consumer Protection Act (the “
Dodd-Frank
Act
”) and the rules
adopted and to be adopted by the Commodity Futures Trading
Commission (“
CFTC
”),
the SEC and other 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.
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 could materially adversely affect our business,
results of operations and financial condition.
Our
results of operations are materially affected by the conditions of
the global economies and the credit, commodities and stock markets.
Among other things, we may be adversely impacted if consumers of
oil and gas are not able to access sufficient capital to continue
to operate their businesses or to operate them at prior levels. 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.
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 recently acquired 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 recently acquired 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.
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:
●
drilling wells that
are significantly longer and/or deeper than more conventional
wells;
●
landing our
wellbore 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 wellbore; and
●
being able to run
tools and other equipment consistently through the horizontal
wellbore.
Risks
that we face while completing our wells include, but are not
limited to, the following:
●
the ability to
fracture stimulate the planned number of stages in a horizontal or
lateral well bore;
●
the ability to run
tools the entire length of the wellbore during completion
operations; and
●
the ability to
successfully clean out the wellbore after completion of the final
fracture stimulation stage.
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 approximate nine months we have been significantly
dependent on capital provided to us by SK Energy.
Since
June 2018, SK Energy, which is owned and controlled by Dr. Simon
Kukes, the Company’s Chief Executive Officer and director,
has loaned us an aggregate of $51,700,000 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. 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. 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.
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.
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.
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.
Risks Related to Our Common Stock
We currently have an illiquid and volatile market for our common
stock, and the market for our common stock is and may remain
illiquid and volatile in the future.
We currently have a
highly sporadic, illiquid and volatile market for our common stock,
which market is anticipated to remain sporadic, illiquid 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:
●
our actual or
anticipated operating and financial performance and drilling
locations, including reserves estimates;
●
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;
●
changes in revenue,
cash flows or earnings estimates or publication of reports by
equity research analysts;
●
speculation in the
press or investment community;
●
public reaction to
our press releases, announcements and filings with the
SEC;
●
sales of our common
stock by us or other shareholders, or the perception that such
sales may occur;
●
the limited amount
of our freely tradable common stock available in the public
marketplace;
●
general financial
market conditions and oil and natural gas industry market
conditions, including fluctuations in commodity
prices;
●
the realization of
any of the risk factors presented in this Annual
Report;
●
the recruitment or
departure of key personnel;
●
commencement of, or
involvement in, litigation;
●
the prices of oil
and natural gas;
●
the success of our
exploration and development operations, and the marketing of any
oil and natural gas we produce;
●
changes in market
valuations of companies similar to ours; and
●
domestic and
international economic, 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. Shareholders and
potential investors in our common stock should exercise caution
before making an investment in us.
Additionally,
as a result of the illiquidity 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. Such illiquidity could have an adverse effect on
the market price of our common stock. In addition, a shareholder
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 liquid 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 is very low. 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 limited
trading volume, and many 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. Such illiquidity
could have an adverse effect on the market price of our common
stock. In addition, a shareholder 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.
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.
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;
●
comply with rules
and regulations promulgated by the NYSE American;
●
prepare and
distribute periodic public reports in compliance with our
obligations under the federal securities laws;
●
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;
●
maintain a
comprehensive internal audit function; and
●
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.
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/A (File No. 333-214415) that we
filed with the Securities and Exchange Commission on December 20,
2016, and which was declared effective on January 17, 2017. To
date, an aggregate of approximately $18.1 million in securities
have been sold by us under the prior Form S-3 which the December
2016 Form S-3 replaced, leaving approximately $81.9 million in
securities which will be eligible for sale in the public markets
from time to 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. We have also entered into an At
Market Issuance Sales Agreement, or sales agreement, with National
Securities Corporation, or NSC, relating to up to $2.0 million of
shares of our common stock which may be offered from time to time
in “
at the market
offerings
” and filed a
final prospectus in connection with such offering with the SEC,
pursuant to which the Company has, to date, sold an aggregate of
590,335 shares of common stock at prices ranging from $0.90 to
$1.12 per share for an aggregate purchase price of $641,000, to
which an underwriter’s fee of 3.0% was applied, leaving
approximately $1.36 million remaining available for issuance
thereunder, subject to limitation under the SEC’s
“
Baby Shelf
Rules
”. 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.
Our outstanding options, warrants and convertible
securities may adversely affect the trading price of our
common stock.
As
of December 31, 2018, there are outstanding stock options to
purchase 890,232 shares of our common stock and outstanding
warrants to purchase 1,216,685 shares of our common stock. 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 6,134,915 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, Dr. 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 Dr. Kukes and Mr. Schick. We do not believe
that Dr. 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 Dr. 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 Dr. 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.
Dr. Simon Kukes, our Chief Executive
Officer and a member of board of directors, beneficially owns
approximately
82.4
% of our
common stock through SK Energy LLC, which gives him majority voting
control over shareholder matters and his interests may be different
from your interests.
Dr.
Simon Kukes, our Chief Executive Officer and member of the board of
directors, is the principal and sole owner of SK Energy LLC, which
beneficially owns approximately 81.2% of our issued and outstanding
common stock and Dr. Kukes, together with the ownership of SK
Energy, beneficially owns approximately 82.4% of our issued and
outstanding common stock. As such, Dr. Kukes can control the
outcome of all matters requiring a shareholder 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 shareholders generally, while Dr. Kukes’
interests may generally be aligned with the interests of our
shareholders, in some instances Dr. Kukes may have interests
different than the rest of our shareholders, including but not
limited to, future potential company financings in which SK Energy
may participate, or his leadership at the Company. Dr. Kukes’
influence or control of our company as a shareholder 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 shareholders. Because Dr. Kukes controls the
shareholder vote, investors may find it difficult to replace Dr.
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 Dr.
Kukes may differ from the interests of the other shareholders and
thus result in corporate decisions that are adverse to other
shareholders.
Provisions of Texas law may have anti-takeover effects that could
prevent a change in control even if it might be beneficial to our
shareholders.
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
shareholder who beneficially owns more than 20% of our voting
stock, or any “
affiliated
shareholder,
” cannot
acquire us for a period of three years from the date this person
became an affiliated shareholder, unless various conditions are
met, such as approval of the transaction by our board of directors
before this person became an affiliated shareholder (such as the
approval of our board of directors of Dr. 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 shareholder.
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 shareholders.
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
shareholder 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 shareholders and/or have other rights and
preferences greater than those of our common stock shareholders
including having a preference over our common stock with respect to
dividends or distributions on liquidation or
dissolution.
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
shareholders. 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 shareholders 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 shareholders. 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.
Shareholders 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
shareholders,
subject to
the requirements of the NYSE American (which generally require
shareholder 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 offerings and/or sales which are
undertaken at or above the greater of the book value and/or market
value of the issuer’s common stock on the date the
transaction is agreed to be completed),
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 shareholders 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.
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 shareholders’
equity and a minimum number of public shareholders. 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
shareholder approval for such transactions.
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. Shareholders could, therefore, experience a decline in the
values of their investment as a result of short sales of our common
stock.