ITEM 1. BUSINESS.
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, with a primary focus on oil and
natural gas shale plays and a secondary focus on conventional oil
and natural gas plays.
Business Operations
Overview
We are
an energy company engaged primarily in the acquisition,
exploration, development and production of oil and natural gas
shale plays in the Denver-Julesberg Basin (“
D-J Basin
”) in Colorado,
which contains hydrocarbon bearing deposits in several formations,
including the Niobrara, Codell, Greenhorn, Shannon, J-Sand, and
D-Sand. As of December 31, 2016, we held approximately 11,538 net
D-J Basin acres located in Weld County, Colorado through our
wholly-owned subsidiary Red Hawk Petroleum, LLC
(“
Red
Hawk
”), which acreage is located in the Wattenberg and
Wattenberg Extension areas of the D-J Basin, which we refer to as
our “
D-J Basin
Asset.
” As of December 31, 2016, we hold interests in
61 gross (17.4 net) wells in our D-J Basin Asset, of which 14 gross
(12.5 net) wells are operated by Red Hawk and are currently
producing, 25 gross (4.9 net) wells are non-operated, and 22 wells
have an after-payout interest. During the quarter-ended
December 31, 2016, the Company produced an average of approximately
1,232 gross (272 net) barrels of oil equivalent per day
(“
BOEPD
”) from its D-J
Basin Asset.
In
February 2015, the Company sold to MIE Jurassic Energy Corp.
(“
MIEJ
”), its then 80%
partner in Condor Energy Technology LLC (“
Condor
”), the
Company’s (i) 20% interest in Condor, and (ii) approximately
972 net acres and interests in three wells located in the
Company’s legacy, non-core Niobrara acreage located in Weld
County, Colorado, that were directly held by the Company in
Condor-operated wells. The assets sold included working interests
in five Condor-operated wells that produced approximately 26
barrels of oil per day, net to the Company’s interest, as of
February 2015, as well as approximately 2,300 net acres to the
Company’s interest in non-core Niobrara areas. The Company
and MIEJ also agreed to aggregate and restructure all liabilities
owed by the Company to MIEJ and Condor, reducing our debt
outstanding with MIEJ and Condor from approximately $9.4 million to
$4.925 million, revising and extending the terms of the outstanding
debt due to MIEJ, and reducing our senior debt by $500,000 through
MIEJ’s direct repayment of principal due to our senior
lenders. See greater details regarding this transaction below in
“
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
–
Liquidity and Capital Resources
–
Amendment to
PEDCO-MIEJ Note and Condor-MIEJ Note.
”
Also in
February 2015, we expanded our D-J Basin position through the
acquisition of additional acreage from Golden Globe Energy (US),
LLC (“
GGE
”), which acquisition
we refer to as the GGE Acquisition, which included approximately
12,977 additional net acres in the D-J Basin located almost
entirely within Weld County, Colorado, including acreage located in
the prolific Wattenberg core area, and interests in 53 gross wells
with an estimated then-current net daily production of
approximately 500 Boepd as of February 7, 2015. The majority of
these assets were originally conveyed to GGE’s
predecessor-in-interest, RJ Resources Corp., by us in March 2014 in
connection with our acquisition of substantially all of the
acreage, well interests and operations of Continental Resources,
Inc. (“
Continental
”) located in
the D-J Basin (the “
Continental
Acquisition
”), and are now included in our D-J Basin
Asset. As partial consideration paid by the Company to GGE in the
GGE Acquisition, the Company provided GGE with a one-year option to
acquire all of the Company’s interests in Caspian Energy
Inc., an Ontario, Canada company listed on the NEX board of the TSX
Venture Exchange that holds exploration and production assets in
Kazakhstan (“
Caspian
Energy
”), comprised of 23,182,880 shares of common
stock of Caspian Energy, for an option exercise price of $100,000.
The option provided to GGE was not exercised and has expired, but
was reissued to GGE in connection with the restructuring of certain
junior debt of the Company held by GGE’s affiliates in May
2016, with the option now expiring May 12, 2019, as described in
greater detail below under “
Recent Developments
”
– “
Junior Debt
Restructuring.
”
On
December 29, 2015, the Company entered into an Agreement and Plan
of Reorganization (as amended to date, the “
GOM Merger Agreement
”)
with White Hawk Energy, LLC (“
White Hawk
”) and GOM
Holdings, LLC (“
GOM
”), a Delaware limited
liability company. The GOM Merger Agreement provides for the
Company’s
acquisition
of GOM through an exchange of certain of the shares of the
Company’s common and preferred stock (the
“
Consideration
Shares
”), as
described in greater detail in the Notes, for 100% of the limited
liability company membership units of GOM (the
“
GOM
Units
”), with
the GOM Units being received by White Hawk and GOM receiving the
Consideration Shares, as described in greater detail in the Notes
from the Company (the “
GOM
Merger
”).
On February 29, 2016,
the parties entered into an amendment to the GOM Merger Agreement,
which amended the merger agreement in order to provide GOM
additional time to meet certain closing conditions contemplated by
the GOM Merger Agreement. The parties entered into the Amendment to
extend the deadline for closing the merger and the date after which
either party could terminate the GOM Merger Agreement if the merger
had not yet been consummated, from February 29, 2016 to no later
than April 15, 2016.
On
April 25, 2016, the Company entered into Amendment No. 2 to the GOM
Merger Agreement (the “
Amendment No. 2
”) with
White Hawk and GOM, which further amends the GOM Merger Agreement
in order to provide GOM additional time to meet certain closing
conditions contemplated by the GOM Merger Agreement. Pursuant to
Amendment No. 2, the parties agreed to remove the deadline for
closing the merger and work expeditiously in good faith toward
closing.
In
order for the Company to move forward with the GOM Merger, it is
requiring that GOM improve its financial position, including pay
off certain amounts of its accounts payable. The Company and GOM
continue to move forward with the merger, which the Company is
working to close as soon as possible, subject to satisfaction of
closing conditions including possible approval by applicable
bankruptcy courts, provided that the Company is unable to estimate
when, if ever, the bankruptcy courts may approve the merger (if and
as required), or the estimated timing to close such transaction
(see also “
The
closing of the GOM merger is subject to various risks and closing
conditions and such planned transaction may not occur on a timely
basis, if at all.
”, below under “
Part I
” –
“
Item 1A. Risk
Factors
”).
We have
listed below the total production volumes and total
revenue net to the Company for the years ended December 31,
2016, 2015, and 2014 attributable to our D-J Basin Asset, including
the calculated production volumes and revenue numbers for our D-J
Basin Asset held indirectly through Condor that would be net to our
interest if reported on a consolidated basis.
|
For the Years Ended December 31,
|
|
|
|
|
Oil
|
|
|
|
Total Production
(Bbls)
|
92,966
|
117,365
|
57,753
|
Average sales price
(per Bbl)
|
$
36.98
|
$
41.13
|
$
80.06
|
Natural
Gas:
|
|
|
|
Total Production
(Mcf)
|
168,555
|
343,967
|
94,981
|
Average sales price
(per Mcf)
|
$
1.98
|
$
1.54
|
$
5.42
|
Oil
Equivalents:
|
|
|
|
Total Production
(Boe) (1)
|
121,058
|
174,693
|
73,583
|
Average Daily
Production (Boe/d)
|
332
|
479
|
202
|
Average Production Costs (per
Boe)
(2)
|
$
10.42
|
$
6.63
|
$
15.78
|
_________________________
(1)
|
Assumes
6 Mcf of natural gas equivalents to 1 barrel of oil.
|
(2)
|
Excludes
ad valorem and severance taxes.
|
Business Strategy
We
believe that the D-J Basin shale play represents among the most
promising unconventional 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 Wattenberg and
Wattenberg Extension areas of Weld County, Colorado. 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 the next twelve months will be focused on
the development of our D-J Basin Asset. Our development plan calls
for the development of approximately $11.1 million in capital
expenditures in order to drill and complete, participate in the
drilling and completion of, and/or acquire approximately 3.3 net
wells in our D-J Basin Asset in 2017.
We expect our
projected cash flow from operations combined with our existing cash
on hand, up to $2.0 million of gross proceeds available from the
issuance of our common shares through National Securities
Corporation under our current “at the market offering,”
and approximately $18.0 million gross available under our
current senior debt facility will be sufficient to fund our
drilling plans and our operations in 2017, noting that
the advancement of all
or any portion of the approximately $18.0 million gross available
under our current senior debt facility is in the sole and absolute
discretion of the senior lenders and no senior lender is obligated
to fund all or any part of the requested funding (
See
“
Part I, Item 1.
Business
” — “
Recent Developments
”
— “
Senior Debt
Restructuring
”
and
“
Part
I
” – “
Item 1A. Risk Factors
”,
including “
Our Tranche A Notes and Tranche B
Notes include various covenants, reduces our flexibility, increases
our interest expense and may adversely impact our operations and
our costs.
”).
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 2017 capital expenditures
and/or repay or refinance a portion or all of our outstanding debt.
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 2018
.
The availability of additional borrowings under the senior debt
facility is subject to the Company providing matching funds for all
amounts borrowed, which additional borrowed funds may only be used
to fund development costs.
During
2016, the Company has focused on growth opportunities, while
addressing the expected liquidity requirements arising from a
significant decrease in oil and gas prices. The Company had the
following significant events:
|
●
|
Closed
a new $25.96 million delayed draw term loan facility in May 2016,
which funds are primarily to be used for funding the development of
new wells in the D-J Basin Asset, and of which $6.4 million was
drawn to fund drilling and completion costs related to 8 additional
wells located in the D-J Basin Asset.
|
|
●
|
Restructured
the Company’s previously outstanding senior debt in May 2016,
capitalizing all accrued and unpaid interest and extending the
maturity to June 11, 2019, with no payments due until after the new
delayed draw term loan facility has been paid off.
|
|
|
|
|
●
|
Implemented
general and administrative cost savings strategies (excluding
non-cash items) which resulted in reducing annual cash-based
general and administrative costs from approximately $3,360,000 in
2015 to $2,436,000 in 2016, with a current run-rate of
approximately $1,800,000 at the beginning of 2017.
|
|
|
|
|
●
|
Continued
to move forward with our business combination with GOM, which, if
consummated, is expected to result in significant additional proved
reserves production, and provide greater resources to raise capital
(see “
Part
I
” – “
Item 1A. Risk Factors
”,
including “
The
closing of the GOM merger is subject to various risks and closing
conditions and such planned transaction may not occur on a timely
basis, if at all
”, and other GOM Merger-related risk
factors).
|
Management is
continually reviewing the recoverability of its oil and gas assets
given the reduction of crude oil and natural gas prices during the
year. Over the course of the year, we have identified acreage that
we believe has a low probability of development in the near future
and have not renewed such leases where appropriate and impaired the
values as necessary. We believe that a significant portion of the
effects of lower crude oil prices are now being offset by the
continuing reduction of drilling and completion, collection,
selling and LOE costs. We believe the leases we currently plan to
develop in our 2017 development plan continue to be economic due to
our estimates of total recoverable reserves, expected production
rates and the continued reduction in development and operational
costs through this year. The recoverability of our oil and gas
assets is dependent on our ability to secure sufficient funds to
develop our properties. If we are unable to have access to our
credit facilities or alternative financing transactions, and crude
oil prices stay at their current prices or go lower or if the new
development and operational costs do not hold or such costs return
to higher levels, Company management may deem it appropriate in the
future to impair certain of our oil and gas properties in the event
we determine we will not be able to fully develop our drilling
program.
The
following chart reflects our current organizational
structure:
*Represents percentage of total
voting power based on 54,931,117 shares of common
stock and 66,625 shares of Series A Convertible Preferred Stock
(solely on an issued and outstanding basis) outstanding as of March
22, 2017, with beneficial ownership calculated in
accordance with Rule 13d-3 under the Exchange Act (but without
reflecting the conversion of convertible securities into voting
securities, including, notably, approximately 20,110,417 shares of
common stock issuable to MIEJ Holdings Corporation upon conversion
of principal and interest accrued through March 31, 2017 under the
New MIEJ Note at a “floor price” of $0.30 per share
– See “
Part
III
” – “
Item 7. Management’s Discussion
and Analysis of Financial Condition and Results of
Operations
” – “
Liquidity and Capital
Resources
” – “
Liquidity Outlook
”
– “
Amendment
to PEDCO-MIEJ Note and Condor-MIEJ Note
” and see also
“
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 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. Most 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 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
most 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:
Management
. We have assembled a
management team at our Company with extensive experience in the
fields of international business development, petroleum
engineering, geology, petroleum field development and production,
petroleum operations and finance. Several members of the team
developed and ran successful energy ventures that were
commercialized at Texaco, Erin Energy Corp. and other international
and domestic energy companies. We believe that our management team
is highly qualified to identify, acquire and exploit energy
resources in the U.S.
Our
management team is headed by our President and Chief Executive
Officer, Michael L. Peterson, who brings extensive experience in
the energy, corporate finance and securities sectors, including as
a Vice President of Goldman Sachs & Co., Chairman and Chief
Executive Officer of Nevo Energy, Inc. (formerly Solargen Energy,
Inc.), and a former director of Aemetis, Inc. (formerly AE Biofuels
Inc.). In addition, our Executive Vice President and General
Counsel, Clark R. Moore, has over 10 years of energy industry
experience, and formerly served as acting general counsel of Erin
Energy Corp.
Our
board of directors also brings extensive oil and gas industry
experience, headed by our Chairman Frank C. Ingriselli, an
international oil and gas industry veteran with nearly 40 years of
experience in the energy industry, including as the President of
Texaco International Operations Inc., President and Chief Executive
Officer of Timan Pechora Company, President of Texaco Technology
Ventures, and President, Chief Executive Officer and founder of
Erin Energy Corp. Also on our Board sits Ms. Elizabeth P. Smith,
who served in numerous executive-level capacities at Texaco,
including as Corporate Compliance Officer, Director of Investor
Relations, Vice President of Corporate Communications, and Vice
President of Texaco Inc. with responsibility and oversight of
Texaco’s Shareholder Services Group, and Adam McAfee, a
Certified Management Accountant and “
audit committee financial
expert
” with over 30 years’ experience, with
prior positions at Nevo Energy, Inc., Aemetis, Inc., Apple Computer
and others.
Key Advisors
. Our key advisors
include Tenet Advisory Group, LLC, which we refer to as TAG, and
other industry veterans. The TAG team replaced South Texas
Reservoir Alliance (“
STXRA
”) as our contract
operator with respect to our D-J Basin operations in January 2017,
pursuant to a customary written engagement providing for hourly
billing for work performed by TAG for us, and terminable upon 60
days prior notice by either party. TAG has experience in drilling
and completing horizontal wells, including over 150 horizontal
wells with lengths exceeding 4,000 feet from 2010 to 2016, as well
as experience in both slick water and hybrid multi-stage hydraulic
fracturing technologies and in the operation of shale wells and
fields. The TAG team has over 130 years of combined technical oil
and gas experience covering reservoir engineering, geology,
geophysics, drilling, completion, production operations, land and
marketing across multiple producing regions and basins including
East Texas, Onshore and Offshore Gulf Coast, Permian Basin,
Mid-Continent and the Rockies. We believe that our relationship
with TAG will supplement the core competencies of our management
team and provide us with petroleum and reservoir engineering,
petrophysical, and operational competencies that will help us to
evaluate, acquire, develop, and operate petroleum resources into
the future.
Significant acreage positions and
drilling potential
. We have accumulated interests in a total
of approximately 11,538 net acres in our core D-J Basin Asset
operating area, which we believe represents a significant
unconventional resource play. 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 D-J Basin Asset could contain up to
approximately 144 potential net wells based on 80 acre spacing,
providing us with a substantial drilling inventory for future
years.
Marketing
The
prices we receive for our oil and natural gas production fluctuate
widely. The recent collapse in oil prices is among the most severe
on record. The daily NYMEX WTI oil spot price went from a high of
$107.95 per Bbl in June 2014 to low of $26.19 per Bbl in February
2016, the lowest settlement in nearly 13 years and rebounding up
100% from its February 2016 low but still more than 50% off its
June 2014 high. The drop and volatility in crude oil pricing is due
in large part to increased production levels, crude oil inventories
and recessed global economic growth. Oil prices are also impacted
by real or perceived geopolitical risks in oil producing regions,
the relative strength of the U.S. dollar, weather and the global
economy. We expect, and have already begun to see, that depressed
oil prices will lead to cuts in the exploration and production
budgets to reduce incremental oil supply, which should ultimately
restore equilibrium to the world oil market and rebalance oil
prices. Decreases in these commodity prices adversely affect the
carrying value of our proved reserves and our revenues,
profitability and cash flows. Short-term disruptions of our oil and
natural gas production occur from time to time due to downstream
pipeline system failure, capacity issues and scheduled maintenance,
as well as maintenance and repairs involving our own well
operations. These situations can curtail our production
capabilities and ability to maintain a steady source of revenue for
our company. In addition, demand for natural gas has historically
been seasonal in nature, with peak demand and typically higher
prices during the colder winter months. See “
Risk Factors
”
below.
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 12-month crude oil purchase contract with a third
party buyer, expiring December 31, 2017, pursuant to which the
buyer purchases the crude oil produced from our 14 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 $3.15. 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.
In
connection with our Continental Acquisition in March 2014, we
became 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 have agreed to sell, and DCP has agreed to purchase, all gas
produced from six (6) 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
a period of ten years, terminating December 1, 2021.
In
connection with our Continental Acquisition in March 2014, 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 have agreed to sell, and Sterling
has agreed to purchase, all gas produced from eight (8) 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.
We
endeavor to ensure that title to our properties is in accordance
with standards generally accepted in the oil and natural gas
industry. Some of our acreage may be obtained through farmout
agreements, term assignments and other contractual arrangements
with third parties, the terms of which often will require the
drilling of wells or the undertaking of other exploratory or
development activities in order to retain our interests in the
acreage. Our title to these contractual interests will be
contingent upon our satisfactory fulfillment of these obligations.
Our properties are also subject to customary royalty interests,
liens incident to financing arrangements, operating agreements,
taxes and other burdens that we believe will not materially
interfere with the use and operation of or affect the value of
these properties. We intend to maintain our leasehold interests by
making lease rental payments or by producing wells in paying
quantities prior to expiration of various time periods to avoid
lease termination.
Oil and Gas Properties
We
believe that the D-J Basin shale play represents among the most
promising unconventional 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 Wattenberg and
Wattenberg Extension areas of Weld County, Colorado. 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 2017 will be focused on the development of
our D-J Basin Asset.
However, if t
he Company consummates its merger
with GOM, the Company will work with GOM to prepare a projected
drilling and completion schedule and budget,
with the final
schedule and budget anticipated to be disclosed by the Company if
the
GOM Merger is
consummated and
once they are available
, which could impact our current 2017
drilling and completion plans.
Unless otherwise noted, the following table presents summary data
for our leasehold acreage in our core D-J Basin Asset as of
December 31, 2016 and our drilling capital budget with respect to
this acreage from January 1, 2017 to December 31, 2017. If
commodity prices do not increase 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, the success of
our drilling results as the year progresses, availability of
capital, and whether we consummate the GOM Merger. In the event the
GOM Merger is consummated, the Company plans to expand this
development plan to incorporate development of assets held by GOM,
with the final schedule and budget anticipated to be disclosed by
the Company once they are available
(see
“
Part
I
” – “
Item 1A. Risk Factors
”,
including “
The
closing of the GOM merger is subject to various risks and closing
conditions and such planned transaction may not occur on a timely
basis, if at all
”, and other GOM Merger-related risk
factors).
|
|
|
|
Drilling Capital
Budget
January 1, 2017
- December 31, 2017
|
|
|
|
|
|
|
Capital Cost to
the Company (2)
|
D-J Basin
Asset
|
11,538
|
80
|
144
|
|
|
|
Short
lateral
|
|
|
|
2.1
|
$
2,592,000
|
$
5,540,410
|
Long
lateral
|
|
|
|
1.2
|
$
4,763,000
|
$
5,573,464
|
Total
Assets
|
11,538
|
|
144
|
3.3
|
|
$
11,113,874
|
(1)
|
Potential Net Wells are calculated using 80 acre spacing, and not
taking into account additional wells that could be drilled as a
result of forced pooling in Niobrara, Colorado, where the D-J Basin
Asset is located, which allows for forced pooling, and which may
create more potential gross drilling locations than acre spacing
alone would otherwise indicate
.
|
(2)
|
Costs per well are gross costs while capital costs presented are
net to our working interests
.
|
D-J Basin Asset
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 is currently the
operator of 14 gross (12.5 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.
Non-Core Assets
We own
23,182,880 shares of common stock of Caspian Energy, a Canadian
publicly-traded company, representing approximately 5% of its
common stock. Caspian Energy holds the rights to explore and
develop certain oil and gas properties in the Republic of
Kazakhstan known as the North Block, a 1,470 square kilometer area
located in the vicinity of the Kazakh pre-Caspian Basin. As partial
consideration paid by the Company to GGE to restructure certain
junior Company debt held by GGE’s affiliates in May 2016, the
Company provided GGE an option to acquire all of the
Company’s interests in Caspian Energy for an option exercise
price of $100,000, which expires May 12, 2019.
Our Core Areas
The
majority of our capital expenditure budget for the period from
January 2017 to December 2017 will be focused on the development of
our core oil and natural gas properties located in the D-J Basin
Asset. For additional information, see “
Management’s Discussion and
Analysis of Financial Condition and Results of Operations-Liquidity
and Capital Resources.
”
D-J Basin Asset
As of
December 31, 2016 we held 11,538 net acres in oil and natural gas
properties related to our D-J Basin Asset. We currently own direct
interests in 61 gross (17.4 net) wells in our D-J Basin Asset, of
which 14 gross (12.5 net) wells are operated by Red Hawk and are
currently producing, 25 gross (4.9 net) wells are non-operated, and
22 wells have an after-payout interest.
Our development plan calls for the development of
approximately $11.1 million in capital expenditures in order to
drill and complete, participate in the drilling and completion of,
and/or acquire approximately 3.3 net wells in our D-J Basin Asset
in 2017.
We expect our projected cash flow from operations
combined with our existing cash on hand, up to $2.0 million of
gross proceeds available from the issuance of our common shares
through National Securities Corporation under our current “at
the market offering,” and
approximately $18.0 million gross available under our
current senior debt facility, will be sufficient to fund our
drilling plans and our operations in 2017
(see
“
Part
I
” – “
Item 1A. Risk Factors
”,
including “
Our Tranche A Notes and Tranche B
Notes include various covenants, reduces our flexibility, increases
our interest expense and may adversely impact our operations and
our costs.
”).
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 2017
capital expenditures and/or repay or refinance a portion or all of
our outstanding debt. 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 2018
. The availability of additional borrowings
under the senior debt facility is subject to the Company providing
matching funds for all amounts borrowed, which additional borrowed
funds may only be used to fund development costs.
Based
on publicly available information and information we have received
from our oilfield service vendors, average drilling and completion
costs for wells in our core area continue to be significantly below
prices we have seen in 2015 and prior years. In addition to more
favorable drilling and completion costs, average estimated ultimate
recoveries, or EURs, and initial 30-day average production rates
have continued to increase through improved completion techniques
in the area. The drilling and completion costs incurred, EURs and
initial production rates achieved by others may not be indicative
of the well costs we will incur or the results we will achieve from
our wells.
Our Non-Core Assets
As
described above, we own 23,182,880 shares of common stock of
Caspian Energy, a Canadian publicly-traded company, representing
approximately 5% of its common stock. As partial consideration paid
by the Company to GGE to restructure certain junior Company debt
held by GGE’s affiliates in May 2016, the Company provided
GGE an option to acquire all of the Company’s interests in
Caspian Energy for an option exercise price of $100,000, which
expires May 12, 2019, described in greater detail below under
“
Item 13. Certain
Relationships and Related Transactions, and Director
Independence
” – “
Agreements with Related Persons”
– “Golden Globe Energy (US), LLC
.
”
Recent Developments
Senior Debt Restructuring
On May 12, 2016 (the “
Closing
Date
”), the Company
entered into an Amended and Restated Note Purchase Agreement (the
“
Amended
NPA
”), with SHIP, BRe
BCLIC Sub, BRe WINIC 2013 LTC Primary, BRe WNIC 2013 LTC Sub,
Heartland Bank, BHLN-Pedco Corp. (“
BHLN
”),
BBLN-Pedco Corp. (“
BBLN
”),
and RJC Credit LLC (“
RJC
”)(together with BHLN and BBLN, the
“
Tranche A
Investors
” and the
“
Lenders
”),
and the Agent, as agent for the Lenders. The Amended NPA amended
and restated the March 2014 Notes (as defined and discussed below
under “
Item 7.
Management’s Discussion and Analysis of Financial Condition
and Results of Operations
” – “
Liquidity and Capital
Resources-Secured Debt Funding
”), and the Company issued new Senior
Secured Promissory Notes to each of the Lenders (collectively, the
“
Tranche B
Notes
”) in a transaction
that qualified as a troubled debt restructuring. RJC is also a
party to the RJC Junior Note (discussed below)(the
“
Senior Debt
Restructuring
”).
The
Amended NPA amended the Senior Notes as follows:
●
|
Created
new “Tranche A Notes,” in substantially the same form
and with similar terms as the Tranche B Notes, except as discussed
below, consisting of a term loan issuable in tranches with a
maximum aggregate principal amount of $25,960,000, with borrowed
funds accruing interest at 15% per annum, and maturing on May 11,
2019 (the “
Tranche A
Maturity Date
”) (the “
Tranche A Notes
,” and
together with the Tranche B Notes, the “
New Senior
Notes
”);
|
●
|
The
Company capitalized all accrued and unpaid interest under the
Senior Notes, renaming them “Tranche B Notes,” as a
term loan with an aggregate outstanding principal balance as of May
12, 2016 equal to $39,065,000. The Tranche B Notes mature on June
11, 2019 except for the Tranche B Note issued to RJC which matures
on July 11, 2019;
|
●
|
Amended
the provisions of the Senior Notes which required mandatory
prepayments from our revenues, replacing them with a Net Revenue
Sweep as described below; and
|
●
|
Provides
that interest on the Tranche B Notes will continue to accrue at the
rate of 15% per annum, but all accrued interest through December
31, 2017 shall be deferred until due and payable on the maturity
date, with all interest amounts deferred being added to the
principal of the Tranche B Notes on a monthly basis and that
following December 31, 2017, all interest will accrue and be paid
monthly in arrears in cash to the Tranche B Note holders, provided,
however, no payment may be made on the Tranche B Notes unless and
until the Tranche A Notes are repaid in full.
|
The
Tranche A Notes are substantially similar to the Tranche B Notes,
except that such notes are senior to the Tranche B Notes, accrue
interest until maturity and have priority to the payment of Monthly
Net Revenues as discussed below.
On the Closing Date, the Tranche A Investors
loaned the Company their pro rata share of an aggregate of
$6,422,000 (the “
Initial Tranche A
Funding
”). The Initial
Tranche A Funding net proceeds (also amounting to $6,422,000 less
legal fees of $127,000) were used by the Company to (i) fund
approximately $5.1 million due to a third party operator for
drilling and completion expenses related to the acquired working
interests in eight wells from Dome Energy, Inc.
(“
Dome
Energy
”), (ii) pay
$750,000 of the Company’s past due payables to Liberty
Oilfield Services, LLC (“
Liberty
”),
(iii) pay $445,000 of unpaid interest payments due to Heartland
Bank under its Tranche B Note through February 29, 2016, and (iv)
pay fees and expenses of $127,000 incurred in connection with the
transactions contemplated by the Amended NPA and related
documents.
Subject to the terms and conditions of the Amended
NPA, the Company may request each Tranche A Investor, from time to
time, to advance to the Company additional amounts of funding
(each, a “
Subsequent Tranche A
Funding
”), provided that:
(i) the Company may not request a Subsequent Tranche A Funding more
than one time in any calendar month; (ii) Agent shall have received
a written request from the Company at least 15 business days prior
to the requested date of such advance (the
“
Advance
Request
”); (iii) no Event
of Default or event that with the passage of time or the giving of
notice, or both, would become an Event of Default (a
“
Default
”)
shall have occurred and be continuing or would result therefrom;
and (iv) the Company shall provide to the Agent such documents,
instruments, certificates and other writings as the Agent shall
reasonably require in its sole and absolute discretion. The
advancement of all or any portion of the Subsequent Tranche A
Funding is in the sole and absolute discretion of the Agent and the
Investors and no Investor is obligated to fund all or any part of
the Subsequent Tranche A Funding. Each Subsequent Tranche A Funding
is required to be in a minimum amount of $500,000 and multiples of
$100,000 in excess thereof. The aggregate amount of Subsequent
Tranche A Fundings that may be made by the Investors under the
Amended NPA shall not exceed $18,577,876 and any Subsequent Tranche
A Funding repaid may not be re-borrowed.
In addition, subject to the terms and conditions
of the Amended NPA, RJC agreed to loan to the Company $240,000,
within 30 days of the Closing Date and within 30 days of each of
July 1, 2016, October 1, 2016 and January 1, 2017 (collectively,
the “
RJC
Fundings
” and
collectively with the Investor Tranche A Fundings, the
“
Fundings
”),
provided that no Event of Default or Default shall have occurred
and be continuing or would result therefrom. The aggregate amount
of the RJC Fundings made by RJC under the Amended NPA shall not
exceed $960,000 and any Funding repaid may not be
re-borrowed.
To guarantee RJC’s obligation in connection
with the RJC Fundings as required under the Amended NPA, GGE
entered into a Share Pledge Agreement with the Company, dated May
12, 2016 (the “
GGE Pledge
Agreement
”), pursuant to
which GGE agreed to pledge an aggregate of 10,000 shares of the
Company’s Series A Convertible Preferred Stock held by GGE
(convertible into 10,000,000 shares of Company common stock), which
pledged shares are subject to automatic cancellation and forfeiture
based on a schedule set forth in the GGE Share Pledge Agreement, in
the event RJC fails to meet each of its RJC Funding obligations
pursuant to the Amended NPA.
To date, RJC has not met its RJC Funding
obligations under the Amended NPA and the Company is entitled to
cancel and forfeit 10,000 shares of the Company’s Series A
Convertible Preferred Stock held by GGE (convertible into
10,000,000 shares of Company common stock) pursuant to the terms of
the GGE Pledge Agreement, which determination to cancel shares has
not been made, and which shares have not been cancelled, as of the
date of this filing.
As additional consideration for the entry into the
Amended NPA and transactions related thereto, the Company has
granted to BHLN and BBLN, warrants exercisable for an aggregate of
5,962,800 shares of common stock of the Company (the
“
Investor
Warrants
”). The warrants
have a 3 year term, are transferrable, and are exercisable on a
cashless basis at any time at $0.25 per share, subject to receipt
of additional listing approval of such underlying shares of common
stock from the NYSE MKT (which additional listing approval was
received from the NYSE MKT on June 1, 2016). The Investor Warrants
include a beneficial ownership limitation that prohibits the
exercise of the Investor Warrants to the extent such exercise would
result in the holder, together with its affiliates, holding more
than 9.99% of the Company’s outstanding voting stock (the
“
Blocker
Provision
”). The
estimated fair value of the Investor Warrants issued is
approximately $707,000 based on the Black-Scholes option pricing
model. The relative fair value allocated to the Tranche A Notes and
recorded as debt discount was $636,000.
Other than the Investor Warrants, no additional
warrants exercisable for common stock of the Company are due,
owing, or shall be granted to the Lenders pursuant to the Senior
Notes, as amended. In addition, warrants exercisable for an
aggregate of 349,111 shares of the Company’s common stock at
an exercise price of $1.50 per share and warrants exercisable for
an aggregate of 1,201,004 shares of the Company’s common
stock at an exercise price of $0.75 per share previously granted by
the Company to certain of the Lenders on September 10, 2015, in
connection with prior interest payment deferrals have been amended
and restated to provide that all such warrants are exercisable on a
cashless basis and include a Blocker Provision (the
“
Amended and Restated
Warrants
”).
Additionally, the Company also agreed to (a)
provide to the Agent and the Investors a monthly projected general
and administrative expense report (the “
Projected
G&A
”) and a monthly
comparison report of the Projected G&A provided for the
preceding month, with an explanation of any variances, provided
that in no event shall such variances exceed $150,000, and (B) pay
to the Agent within 2 business days following the end of each
calendar month all of the Company’s oil and gas revenue
received by the Company during such month (the
“
Net Revenue
Sweep
”), less (i) lease
operating expenses, (ii) interest payments due to Investors under
the New Senior Notes, (iii) general and administrative expenses not
to exceed $150,000 per month unless preapproved by the Agent (the
“
G&A
Cap
”), and (iv)
preapproved extraordinary expenses (together the
“
Monthly Net
Revenues
”). Amounts paid
to the Agent through the Net Revenue Sweep are applied first to the
repayment of principal and then interest due under the Tranche A
Notes until such notes are paid in full and then to the repayment
of principal and interest amounts due under the Tranche B
Notes.
The amounts outstanding under the New Senior Notes
are secured by a first priority security interest in all of the
Company’s and its subsidiaries’ assets, property, real
property, intellectual property, securities and proceeds therefrom,
granted in favor of the Agent for the benefit of the Lenders,
pursuant to a Security Agreement and a Patent Security Agreement,
each entered into as of March 7, 2014, as amended on May 12, 2016
(the “
Amended Security
Agreement
” and
“
Amended Patent
Agreement,
”
respectively). Additionally, the Agent, for the benefit of the
Lenders, was granted a mortgage and security interest in all of the
Company’s and its subsidiaries real property as located in
the State of Colorado and the State of Texas pursuant to (i) a
Leasehold Deed of Trust, Fixture Filing, Assignment of Rents and
Leases, and Security Agreements, dated March 7, 2014, as amended
May 12, 2016, filed in Weld County and Morgan County, Colorado; and
(ii) a Mortgage, Deed of Trust, Security Agreement, Financing
Statement and Assignment of Production to be filed in Matagorda
County, Texas (collectively, the “
Amended
Mortgages
”).
Additionally, the Company’s obligations
under the New Senior Notes, Amended NPA and related agreements were
guaranteed by the Company’s direct and indirect subsidiaries,
Pacific Energy Development Corp., White Hawk Petroleum, LLC
(“
White
Hawk
”), Pacific Energy
& Rare Earth Limited, Blackhawk Energy Limited, Pacific Energy
Development MSL, LLC and Red Hawk Petroleum, LLC pursuant to a
Guaranty Agreement, entered into on March 7, 2014, as amended
on May 12, 2016 (the “
Amended Guaranty
Agreement
”).
Other
than as described above, the terms of the Amended NPA (including
the covenants and obligations thereunder) are substantially the
same as the March 2014 Note Purchase Agreement, and the terms of
the Tranche A Notes and Tranche B Notes (including the events of
default, interest rates and conditions associated therewith) are
substantially the same as the original March 2014
Notes.
Junior Debt Restructuring
On May 12, 2016, the Company entered into an
Amendment No. 2 to Note and Security Agreement with RJC (the
“
Second
Amendment
”), pursuant to
which the Company and RJC agreed to amend the RJC Junior Note to
(i) capitalize all accrued and unpaid interest under the RJC Junior
Note as of the date of the parties’ entry into the Second
Amendment, and add it to note principal, making the then current
outstanding principal amount of the RJC Junior Note $9,379,432,
(ii) extend the “
Termination
Date
” thereunder (i.e.,
the maturity date) from December 31, 2017 to July 11, 2019, (iii)
provide that all future interest accruing under the RJC Junior Note
is deferred, due and payable on the Termination Date, with all
future interest amounts deferred being added to principal on the
first business day of the month following the month in which such
deferred interest is accrued, and (iv) subordinate the RJC Junior
Note to the Senior Notes.
As additional consideration for RJC’s
agreement to enter into the Second Amendment, the Company entered
into a Call Option Agreement with GGE, an affiliate of RJC, dated
May 12, 2016 (the “
GGE Option
Agreement
”), pursuant to
which the Company provided GGE an option to purchase 23,182,880
common shares of Caspian Energy Inc., a British Columbia
corporation, held by the Company, upon payment of $100,000 by GGE
to the Company, which option expires on the
“
Termination
Date
” of the RJC Junior
Note, as amended, as described above, currently May 12, 2019. The
Company originally issued an option to GGE in February 2015 to
acquire the Company’s interest in these shares in connection
with the Company’s acquisition of certain producing oil and
gas assets from GGE, which option expired unexercised in February
2016, as more fully described in the Company’s Current Report
on Form 8-K filed with the Securities and Exchange Commission on
February 24, 2015.
GOM Holdings, LLC Merger Agreement
On
December 29, 2015, the Company entered into an
Agreement and
Plan of Merger (the
“
GOM Merger
Agreement
”) with White Hawk Energy, LLC, a Delaware
limited liability company and wholly-owned subsidiary of the
Company (“
Merger
Sub
”), and GOM Holdings, LLC (“
GOM
”). The GOM Merger
Agreement provides for the Company’s acquisition of GOM
through an exchange of certain of the shares of the Company’s
common and preferred stock (the “
Consideration Shares
”),
as described in greater detail below, for 100% of the limited
liability company membership units of GOM (the “
GOM Units
”), with the GOM
Units being received by Merger Sub and GOM receiving the
Consideration Shares, as described in greater detail below from the
Company (the “
Merger
”).
On February 29, 2016, the Company entered into
Amendment No. 1 to Agreement and Plan of Merger and Reorganization
(the “
Amendment
”)
with Merger Sub and GOM which amends GOM Merger Agreement. In order
to provide GOM additional time to meet certain closing
conditions contemplated by the GOM Merger Agreement, the
parties entered into the Amendment to extend the deadline for
closing the Merger and the date after which either party could
terminate the GOM Merger Agreement if the Merger had not yet been
consummated, from February 29, 2016 to no later than April 15,
2016.
On April 25, 2016, the Company entered into
Amendment No. 2 to the GOM Merger Agreement (the
“
Amendment No.
2
”) with Merger Sub and
GOM, which further amends the GOM Merger Agreement in order to
provide GOM additional time to meet certain closing
conditions contemplated by the GOM Merger Agreement. Pursuant
to Amendment No. 2, the parties agreed to remove the deadline for
closing the Merger and work expeditiously in good faith toward
closing.
The
closing of the Merger is subject to various closing conditions as
described below and as set forth in greater detail in the GOM
Merger Agreement. At the Closing of the Merger, (i) GOM will
transfer the GOM Units to Merger Sub, solely in exchange for the
Consideration Shares, and (ii) Merger Sub will continue as a
wholly-owned subsidiary of the Company and will continue to carry
on the business of GOM. In exchange for the transfer of GOM Units
to Merger Sub, the Company will issue to the members of GOM, the
Consideration Shares as follows: (x) an aggregate of 1,551,552
shares of the Company’s restricted common stock (the
“
Common
Stock
”) and 698,448 restricted shares of the
Company’s to-be-designated Series B Convertible Preferred
Stock (the “
Series B
Preferred
” (described in greater detail below)), and
(y) will assume approximately $125 million of subordinated debt
from GOM’s existing lenders and a $30 million undrawn letter
of credit backing certain offshore asset retirement obligations
(the “
GOM
Debt
”), which GOM Debt is anticipated to be
restructured on terms and conditions mutually acceptable to the
Company and GOM prior to the Closing of the Merger.
At or
prior to Closing, we will file and cause to be effective a new
Certificate of Designations of PEDEVCO Corp. Establishing the
Designations, Preferences, Limitations, and Relative Rights of its
Series B Convertible Preferred Stock (the “
Certificate of
Designation
”), which will create 698,448 shares of
newly-designated Series B Preferred, all of which will be issued to
the members of GOM at Closing pro rata with their ownership of GOM.
The Series B Preferred will (i) have a liquidation preference
senior to all of the Company’s common stock and Series A
Convertible Preferred Stock equal to $250 per share (the
“
Liquidation
Preference
”), (ii) accrue an annual dividend equal to
10% of the Liquidation Preference, payable annually from the date
of issuance (the “
Dividend
”), (iii) vote
together with the common stock on all shareholder matters, with
each share having one (1) vote, and (iv) not be convertible into
common stock of the Company until both the Shareholder Approval and
NYSE MKT Approval are received (each as defined below). Upon the
Company’s receipt of the Shareholder Approval and NYSE MKT
Approval, (x) the Series B Preferred will automatically cease
accruing Dividends and all accrued and unpaid Dividends will be
automatically forfeited and forgiven in their entirety, (y) the
Liquidation Preference of the Series B Preferred will be reduced to
$0.001 per share from $250 per share, and (z) each share of Series
B Preferred will be convertible into common stock on a 1,000:1
basis (the “
Series B
Conversion
”), either (A) automatically upon the
determination of the Company’s board of directors in its sole
discretion (“
Company
Conversion
”), or (B) at the option of the holder at
any time (“
Holder
Conversion
”), provided that no Holder Conversion is
allowed to the extent the holder thereof would beneficially own
more than 9.9% of the Company’s Common Stock or voting
stock.
The
parties have made customary representations, warranties and
covenants in the GOM Merger Agreement including, among others,
covenants relating to (1) the conduct of each party’s
business during the interim period between the execution of the GOM
Merger Agreement and the consummation of the Merger, (2)
GOM’s Board of Managers’ and members’ approval of
the GOM Merger Agreement and the Merger, and (3) equity grants
anticipated to be made to the post-Closing management team by the
Company, contingent upon the Equity Plan Increase (described
below), which grants will be mutually agreed upon by the Company
and GOM prior to Closing. In addition, within 30 days of the
Closing, (A) the Company has agreed to use commercially reasonable
best efforts to file all the required documents with the SEC
necessary to seek shareholder approval (the “
Shareholder Approval
”) of
(i) the issuance of the shares of common stock in connection with
the Series B Conversion, (ii) an increase of shares available for
issuance under the Company’s 2012 Equity Incentive Plan equal
to 12.0% of the Company’s issued and outstanding capital
stock (calculated post-Closing, assuming conversion of all Company
Series A Preferred and Series B Preferred into Common Stock) (the
“
Equity Plan
Increase
”), and (iii) such other matters that are
required to be approved by the shareholders of the Company pursuant
to applicable rules and requirements of the SEC and NYSE MKT or
which in the reasonable determination of the Company, shall be
approved by the stockholders of the Company; and (B) the Company
agreed to use commercially reasonable best efforts to file all the
required documents with the NYSE MKT necessary to obtain NYSE MKT
approval of the listing of the Company upon the Series B Conversion
(the “
NYSE MKT
Approval
”), if and as necessary pursuant to applicable
NYSE MKT rules and regulations. The approval of the shareholders of
the Company is not required under applicable law for the closing of
the Merger, nor is it a required condition to closing the Merger,
and the Company does not intend to seek shareholder approval for
the closing of the Merger, only for the Shareholder Approval, after
the closing of the Merger, as described above.
The
Merger is subject to customary closing conditions, including (1)
approval of the agreement by the board of directors of the Company,
the sole Manager and member of Merger Sub, the Board of Managers of
GOM, and the members of GOM, (2) receipt of required regulatory
approvals, (3) the absence of any law or order prohibiting the
consummation of the Merger, (4) approval of the NYSE MKT for the
issuance of the common stock and shares of common stock issuable
upon conversion of the Series B Preferred to the members of GOM at
Closing, and (5) the effectiveness of the Certificate of
Designation. Each party’s obligation to complete the GOM
Merger is also subject to certain additional customary conditions,
including (a) subject to certain exceptions, the accuracy of the
representations and warranties of the other party, (b) performance
in all material respects by the other party of its obligations
under the GOM Merger Agreement, (c) completion of the restructuring
of each of the Company’s and GOM’s existing debt,
respectively, to the other party’s satisfaction, and (d) each
of the Company and GOM furnishing the other with evidence that each
has entered into amended employment agreements with certain of each
party’s employees as required and in forms acceptable to the
other party. In addition, each of the Company and GOM agreed to pay
all costs and expenses incurred by them in connection with the GOM
Merger Agreement.
The GOM
Merger Agreement also includes customary termination provisions for
both the Company and GOM. Specifically, and subject to the terms of
the GOM Merger Agreement, the agreement can be terminated by either
party at any time.
As of
the date of this filing, the Company and GOM continue to move
forward with the merger, which the Company is working to close as
soon as possible, subject to satisfaction of closing conditions
including possible approval by applicable bankruptcy courts,
provided that the Company is unable to estimate when, if ever, the
bankruptcy courts may approve the merger (if and as required), or
the estimated timing to close such transaction (see also
“
The closing of the
GOM merger is subject to various risks and closing conditions and
such planned transaction may not occur on a timely basis, if at
all.
”, above under “
Part I
” –
“
Item 1A. Risk
Factors
”).
The
parties intend, for U.S. federal income tax purposes, that the
Merger will qualify as a “
reorganization
” within
the meaning of Section 368(a) of the Internal Revenue Code of
1986.
GOM is
an investment owned by Platinum Partners Value Arbitrage Fund, LP,
a New York based investment firm (“
PPVAF
”). PPVAF also owns
RJ Credit LLC (“
RJC
”), which entity
originally loaned the Company approximately $5.9 million in
principal in connection with the Company’s March 2014 senior
note funding and $8.9 million in principal in connection with the
Company’s February 2015 acquisition of certain working
interests from GGE, each as restructured in May 2016, and PPVAF
also owns GGE, which entity is the holder of the Company’s
Series A Convertible Preferred stock (as discussed in
“
Part
II
” – “
Item 5. Market For Registrant’s
Common Equity, Related Stockholder Matters and Issuer Purchases of
Equity Securities
” – “
Preferred Stock
”). Each
of GOM, RJC and GGE were formerly advised by Platinum Management
(NY), LLC (“
PM
LLC
”). PPVAF, and, by virtue of being owned by PPVAF,
GGE, RJC, and GOM, are currently in the process of winding down and
liquidating their assets through the oversight and control of a
court-appointed liquidator in the Cayman Islands and are no longer
advised by PM LLC or any of its affiliates. Additionally, the
Company is aware that the former manager of PPVAF, PM LLC, is
currently under investigation by the U.S. Securities and Exchange
Commission and the Justice Department and that certain former
executives have been indicted by the Justice Department, however,
PM LLC and those certain executives no longer have any control over
PPVAF, GOM, RJC or GGE, which entities are currently solely under
the control of the Cayman Islands court-appointed
liquidators.
PM LLC
was also formerly an advisor to the entity that owns GGE, a greater
than 5% stockholder of the Company, from whom the Company acquired
approximately 12,977 net acres of oil and gas properties and
interests in 53 gross wells located in the Denver-Julesburg Basin,
Colorado in February 2015, in connection with which the Company
assumed approximately $8.35 million of subordinated notes payable
owed by GGE to RJC, issued to GGE 3,375,000 restricted shares of
the Company’s common stock (representing approximately 9.9%
of our then outstanding shares of common stock), and issued to GGE
66,625 restricted shares of the Company’s then
newly-designated Amended and Restated Series A Convertible
Preferred Stock (the “
Series A Preferred
”),
which can be converted into shares of the Company’s common
stock on a 1,000:1 basis, subject to a 9.9% ownership blocker. GGE,
as the sole holder of the Company’s Series A Preferred, has
the right to appoint two designees to the Company’s board of
directors for as long as GGE continues to hold 15,000 shares of
Series A Preferred designated as “
Tranche One Shares
” under
the Company’s Amended and Restated Certificate of
Designations of PEDEVCO Corp. Establishing the Designations,
Preferences, Limitations, and Relative Rights of its Series A
Convertible Preferred Stock. Mr. Steinberg is one of the Series A
Preferred shareholder designees to the board of directors in
connection with such right, provided that GGE has not designated
any further members of the board of directors at this
time.
Amendment to the 2012 Equity Incentive Plan
At the
Company’s Annual Meeting of Stockholders held on December 28,
2016 (the “
Annual
Meeting
”), the Company’s stockholders approved
an amendment to the Company’s 2012 Equity Incentive Plan (the
“
Plan
”)
to increase by 5,000,000, the number of shares of common stock
reserved for issuance under the Plan to a total of 15,000,000
shares.
Approval of Issuance of More Than 19.9% of the Company’s
Outstanding Shares of Common Stock Upon Conversion of the New MIEJ
Note
At the
Company’s Annual Meeting, the Company’s stockholders
approved, for purposes of Section 713 of the Company Guide of the
NYSE MKT, LLC, which we refer to as the NYSE MKT, the issuance of
more than 19.9% of our outstanding shares of common stock upon
conversion of the principal and accrued interest owed under an
outstanding Convertible Promissory Note in the principal amount of
$4.925 million, held by MIE Jurassic Energy Corporation
(“
MIEJ
”).
Appointment of New Director
At the Annual Meeting, the stockholders of the
Company appointed Frank C. Ingriselli, Elizabeth P. Smith, David Z.
Steinberg and Adam McAfee as members of the board of directors. Mr.
McAfee was appointed as a member of the board of directors to fill
the vacancy left by departing director, David C. Crikelair, who did
not stand for reelection at the Annual Meeting (Mr. Crikelair
previously served as the Chairman of the Audit Committee and as a
member of the Compensation Committee and Nominating and Corporate
Governance Committee). At the time of appointment, the board of
directors made the affirmative determination that Mr. McAfee was
“
independent
”
pursuant to applicable NYSE MKT rules and regulations and as
defined under Rule 10A-3 of the Exchange Act. Effective upon his
appointment to the board of directors on December 28, 2016, Mr.
McAfee was also appointed to serve on the Compensation Committee,
Nominating and Corporate Governance Committee, and Audit Committee
of the Company’s board of directors, replacing Mr. Crikelair
who previously served on each committee, with Mr. McAfee replacing
Mr. Crikelair as Chairman of the Audit Committee and as the
“
audit committee
financial expert
” as
defined under Item 407(d)(5) of Regulation S-K of the Securities
Exchange Act.
Pursuant to the Company’s Board of
Director’s compensation program (the
“
Board Compensation
Program
”), Mr. McAfee
shall receive a quarterly cash payment of $5,000, and on December
28, 2016 he received a grant of 545,455 restricted shares of
Company common stock valued at $60,000 on the date of grant, which
shares vest in full on the date that is one year following the date
of grant, subject to Mr. McAfee continuing to serve as a member of
the board of directors on such date and conditions of a
Restricted Shares Grant Agreement entered into by and between the
Company and Mr. McAfee.
Reverse Stock Split
At the
Company’s Annual Meeting, the Company’s stockholders
authorized
the board of directors of
the Company, in their sole discretion and without further
stockholder approval, to amend the Company’s Certificate of
Formation, at any time prior to the earlier of (a) the one year
anniversary of the Annual Meeting; and (b) the date of our 2017
annual meeting of stockholders, to effect a reverse stock split of
our outstanding common stock in a ratio of between one-for-two and
one-for-ten, provided that all fractional shares as a result of the
split shall be automatically rounded up to the next whole share.
The Company plans to effect the reverse split by May 3, 2017 as
required by the NYSE MKT.
Restricted Stock and Option Awards
On
December 28, 2016, in accordance with the terms of the
Company’s Board Compensation Program, the Company granted
545,455 shares of restricted Company common stock under the Plan to
each member of the Company’s board of directors –
Messrs. Ingriselli, McAfee and Steinberg, and Ms. Smith –
which shares vest on the date that is one year following the
anniversary date of each director’s appointment to the
Company’s board of directors as a non-employee director, in
each case subject to the recipient of the shares being a member of
the Company’s board of directors on such vesting date, and
subject to the terms and conditions of a Restricted Shares Grant
Agreement entered into by and between the Company and the
recipient.
In addition, on December 28, 2016, in connection
with the Company’s annual compensation review process, the
Company granted restricted stock awards to Messrs. Michael L.
Peterson (President and Chief Executive Officer) and Clark R. Moore
(Executive Vice President, General Counsel and Secretary), of
1,650,000 and 1,050,000 shares, respectively, and options to
purchase 600,000 shares of common stock to Gregory Overholtzer
(Chief Financial Officer), which options have an exercise price of
$0.11 per share and expire in five (5) years from the date of
grant. The restricted stock and option awards were granted under
the Company’s 2012 Equity Incentive Plan, as amended. The
restricted stock and option awards vest as follows: 50% of the
shares on the six (6) month anniversary of December 28, 2016 (the
“
Grant
Date
”); (ii) 30% on the
twelve (12) month anniversary of the Grant Date; and (iii) 20% on
the eighteen (18) month anniversary of the Grant Date, in each case
subject to the recipient of the shares or options being an employee
of or consultant to the Company on such vesting date, and subject
to the terms and conditions of a Restricted Shares Grant Agreement
or Stock Option Agreement, as applicable, entered into by and
between the Company and the recipient.
Notice of Delisting of Failure to Satisfy a Continued Listing Rule
or Standard; Transfer of Listing.
On December 27, 2016, the Company received notice
from the NYSE MKT LLC (the “
Exchange
”)
that the Company is not in compliance with Section 1003(a)(iii) of
the NYSE MKT Company Guide (“
Company
Guide
”) since it reported
stockholders’ equity of less than $6,000,000 at September 30,
2016 and has incurred net losses in its five most recent fiscal
years ended December 31, 2015.
Receipt of the letter does not have any immediate
effect upon the listing of the Company’s common stock,
provided that in order to maintain its listing on the Exchange, the
Exchange has requested that the Company submit a plan of compliance
(the “
Plan
”)
by January 27, 2017 addressing how the Company intends to regain
compliance with Section 1003(a)(iii) of the Company Guide by June
27, 2018.
The Company’s management submitted a Plan to
the Exchange by the January 27, 2017 deadline and the Exchange has
accepted the Company’s Plan. As such, the Company will be
able to continue its listing during the plan period and will be
subject to continued periodic review by the Exchange staff. If the
Company is unable to regain compliance with the continued listing
standards by June 27, 2018, or the Company does not make progress
consistent with the Plan during the plan period, the Company will
be subject to delisting procedures as set forth in the Company
Guide. The Company may then appeal such a determination by the
staff of the Exchange in accordance with the provisions of the
Company Guide. There can be no assurance that the Company will be
able to achieve compliance with the Exchange’s continued
listing standards within the required time frame. Until the Company
regains compliance with the Exchange’s listing standards, a
“
.BC
” indicator will be affixed to the
Company’s trading symbol to denote non-compliance with
the Exchange’s continued listing standards; provided that as
disclosed in the Current Report on Form 8-K filed by the Company on
November 9, 2016, a “
.BC
” indicator is already affixed to the
Company’s trading symbol due to the fact that the Company is
not in compliance with Section 1003(f)(v) of the Company
Guide.
Shale Oil and Natural Gas Overview
The
surge of oil and natural gas production from underground shale rock
formations has had a dramatic impact on the oil and natural gas
market in the U.S., where the practice was first developed, and
globally. Shale oil production is facilitated by the combination of
a set of technologies that had been applied separately to other
hydrocarbon reservoir types for many decades. In combination these
technologies and techniques have enabled large volumes of oil to be
produced from deposits with characteristics that would not
otherwise permit oil to flow at rates sufficient to justify its
exploitation. The application of horizontal drilling, hydraulic
fracturing and advanced reservoir assessment tools to these
reservoirs is unlocking a global resource of shale and other
unconventional oil and natural gas that the International Energy
Agency estimates could eventually double recoverable global oil
reserves.
In
2008, U.S. natural gas production was in a decline, and the U.S.
was on its way to becoming a significant importer of liquefied
natural gas (LNG). By 2009, U.S.-marketed natural gas production
was 14% higher than in 2005, and in 2010 it surpassed the previous
annual production record set in 1973. Since 2010 alone, the U.S.
production of tight oil has increased from less than 1 million
barrels per day (MMBbl/d) in 2010, to more than 3 MMBbl/d in the
second half of 2013, and to more than 4 MMBbl/d in 2016. This
turnaround is mainly attributable to shale oil and natural gas
output that has more than quintupled since 2007. Knowledge is
expanding rapidly concerning the shale oil reservoirs that are
already being exploited and others that appear suitable for
development with current technology. In its 2016 Annual Energy
Outlook, the U.S. Energy Information Administration
(“
EIA
”)
estimated in its high resource case that total domestic crude oil
production would increase to approximately 17 MMBbl/d by 2040,
approximately 12 MMBbl/d of which would come from tight oil
production, with net U.S. oil imports declining through 2040, with
the U.S. becoming a net petroleum exporter in late 2022 and
continuing as a net exporter through 2040.
Oil and
natural gas produced from shale is considered an unconventional
resource. Commercial oil and natural gas production from
unconventional sources requires special techniques in order to
achieve attractive oil and natural gas flow rates. Unlike
conventional oil and natural gas, which is typically generated in
deeper source rock and subsequently migrates into a sandstone
structure with an overlying impermeable layer forming a
“
trap,
”
shale oil and natural gas is generated from organic material
contained within the shale and retained by the rock’s
inherent low permeability. Permeability is a measure of the ease
with which natural gas, oil or other fluids can flow through the
material. The same low permeability that secures large volumes of
natural gas and liquids in place within the shale strata makes it
much more difficult to extract them, even with a large pressure
difference between the reservoir and the surface. The location and
potential of many of today’s productive shale reservoirs were
known for many years, but until the development of current shale
oil and natural gas techniques these deposits were considered
noncommercial or inaccessible.
The
main challenge of shale oil and natural gas drilling is to overcome
the low permeability of the shale reservoirs. A conventional
vertical oil or natural gas well drilled into one of these
reservoirs might achieve production, though at reduced rates and
for a limited duration before the oil or natural gas volume in
proximity to the wellbore is exhausted. That often renders such an
approach impractical and uneconomic for exploiting shale oil and
natural gas. The two main technologies associated with U.S. shale
oil and natural gas production are horizontal drilling and
hydraulic fracturing, or “
hydrofracking.
” They are
employed to overcome these constraints by greatly increasing the
exposure of each well to the shale stratum and enabling oil and
natural gas located farther from the well to flow through the rock
and replace the nearby oil and natural gas that has been extracted
to the surface.
Instead
of drilling a simple vertical well through the shale and then
perforating the well within the zone where it is in contact with
the shale, the drilling company drills a directional well
vertically to within proximity of the shale and then executes a
90-degree turn in order to intersect the shale and then travel for
a significant horizontal distance through it. A typical North
American shale well has a horizontal extent of 1,000 feet to 8,000
feet or more.
Once
the lateral portion of the well has reached the desired extent, the
other main technique of shale oil and natural gas drilling is
deployed. After the well has been completed, the farthest section
of the lateral is perforated, opening up holes through which fluid
can flow. This portion of the reservoir is then hydrofracked by
injecting fluid into the well under high pressure to fracture the
exposed shale rock and open up pathways through which oil and
natural gas can flow. The “
fracking fluid
” consists
mainly of water with a variety of chemical additives intended to
reduce friction and dissolve minerals, among other purposes, along
with sand or sand-like material to prop open the new pathways
created by hydrofracking. This process is then repeated at
intervals along the well’s horizontal extent, successively
perforating and hydrofracking each section in turn. This process
creates a producing well that emulates the effect of a vertical
well drilled into a conventional oil and natural gas reservoir by
substituting multiple horizontal “
pay zones
” in the shale
stratum for the thinner but more prolific vertical pay zone in a
more permeable reservoir. Compared to conventional oil and natural
gas drilling, the production of oil and natural gas from shale
reservoirs thus entails more drilling, on average, and requires a
substantial supply of water.
Shale
oil and natural gas are currently being produced from a number of
reservoirs in the U.S. According to the EIA, the seven most
prolific shale production areas in the Lower 48 states, which
together account for 92% of domestic oil production growth and all
domestic natural gas production growth during 2011-2014, are the
Bakken Shale located in North Dakota and Eastern Montana, the
Niobrara Shale in northeastern Colorado and parts of adjacent
Wyoming, Nebraska, and Kansas, the Eagle Ford Shale in southern
Texas, the Marcellus Shale spanning several states in the
northeastern U.S., the Utica Shale in eastern Ohio, the Haynesville
Shale in eastern Texas and western Louisiana, and the Permian Shale
in western Texas and eastern New Mexico. According to the
EIA’s September 2015 assessment, the total technically
recoverable world resources of shale oil and gas are estimated at
418.9 billion barrels (oil) and 7,576.6 trillion cubic feet (gas),
with an estimated 78.2 billion barrels (oil) and 622.5 trillion
cubic feet (gas) being concentrated in the U.S.
Beginning in 2014,
the oil and natural gas industry began to experience a sharp
decline in commodity prices, with the daily NYMEX WTI oil spot
price went from a high of $107.95 per Bbl in June 2014 to low of
$26.19 per Bbl in February 2016, the lowest settlement in nearly 13
years. This recent decline in oil prices has resulted in a slowing
of the pace of U.S. shale oil production, with Baker Hughes’
rig count data showing a decrease in the number of oil rigs
operating in the DJ-Niobrara from 42 rigs at the end of December
2014 to 25 rigs at the end of December 2016. However, this has also
led to average drilling and completion costs for wells in the
DJ-Niobrara significantly dropping from between $4.3 million
(short-lateral) and $8.3 million (long lateral) per well in early
2015 to between $2.7 million and $5.0 million per well currently,
which reduced costs partially offset the decline in commodity
prices, resulting in new shale oil wells drilled in more thermally
mature formations of the DJ-Niobrara expected to continue to yield
positive economic returns.
Regulation of the Oil and Gas Industry
Our 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.
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
$1.0 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 million MMBtus 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 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.
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. For example, on
May 4, 2016, several non-governmental environmental groups
filed suit against the EPA in the U.S. District Court for the
District of Columbia for failing to
timely assess its RCRA Subtitle D
criteria regulations for oil and natural gas wastes, asserting that
the agency is required to review its Subtitle D regulations every
three years but has not conducted an assessment on those oil and
natural gas waste regulations since July 1988. Any such change
could result in an increase in our as well as the oil and natural
gas exploration and production industry’s costs to manage and
dispose of wastes, which could have a material adverse effect on
our results of operations and financial position. In the course of
our operations, we generate some amounts of ordinary industrial
wastes, such as paint wastes, waste solvents and waste oils that
may be regulated as hazardous
wastes.
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. The EPA
has issued final rules attempting to clarify the federal
jurisdictional reach over waters of the United States but this rule
has been stayed
nationwide by the U.S. Sixth
Circuit Court of Appeals as that appellate court and numerous
district courts ponder lawsuits opposing implementation of the
rule. In February 2016, a split three-judge panel of the Sixth
Circuit Court of Appeals concluded that it has jurisdiction to
review challenges to these final rules and the Sixth Circuit
subsequently elected not to review this decision en banc but it is
currently unknown whether other federal Circuit Courts or state
courts currently considering this rulemaking will place their cases
on hold, pending the Sixth Circuit’s hearing of the case.
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, federal and
some state agencies have begun investigating whether such wells
have caused increased seismic activity, and some states have shut
down or imposed moratoria on the use of such disposal wells. In
response to these concerns, regulators in some states have adopted,
and other states are considering adopting, additional requirements
related to seismic safety. Increased costs associated with the
transportation and disposal of produced water, including the cost
of complying with regulations concerning produced water disposal,
may reduce our profitability; however, these costs are commonly
incurred by all oil and natural gas producers and we do not believe
that the costs associated with the disposal of produced water will
have a material adverse effect on our
operations.
Air Emissions
The
Clean Air Act (“
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
toobtain 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, on
January 22, 2016, the federal Bureau of Land Management
(“
BLM
”)
released a proposed rule aimed at reducing natural gas lost
through natural gas venting, flaring and equipment leaks from both
new and existing production activities on federal lands. Except
where natural gas loss is “unavoidable,” as defined by
the proposed rule, operators would be charged royalties on natural
gas losses from onshore federal and Indian mineral leases
administered by the BLM. In a second example, the EPA promulgated
rules in 2012 under the CAA that subject oil and natural gas
production, processing, transmission and storage operations to
regulation under the New Source Performance Standards
(“
NSPS
”) and a separate set
of requirements to address certain hazardous air pollutants
frequently associated with oil and natural gas production and
processing activities pursuant to the National Standards for
Emission of Hazardous Air Pollutants (“
NESHAPS
”) program. With
regards to production activities, these final rules require, among
other things, the reduction of volatile organic compound
(“
VOC
”)
emissions from certain fractured and refractured natural gas wells
for which well completion operations are conducted and further
requires that a subset of these selected wells use reduced emission
completions, also known as “green completions.” These
regulations also establish specific new requirements regarding
emissions from production-related wet seal and reciprocating
compressors, and from pneumatic controllers and storage vessels. On
June 3, 2016, the EPA published final rules establishing new
air emission controls for methane emissions from certain new,
modified or reconstructed equipment and processes in the oil and
natural gas source category, including production, processing,
transmission and storage activities. The EPA’s final rules
include the NSPS to limit methane emissions from equipment and
processes across the oil and natural gas source category. The rules
also extend limitations on VOC emissions to sources that were
unregulated under the previous NSPS at Subpart OOOO. Affected
methane and VOC sources include hydraulically fractured (or
re-fractured) oil and natural gas well completions, fugitive
emissions from well sites and compressors, and pneumatic pumps. In
a third example, on October 1, 2015, the EPA issued a final
rule under the Clean Air Act, lowering the National Ambient Air
Quality Standard (“
NAAQS
”) for ground-level
ozone from the current standard of 75 parts per billion
(“
ppb
”)
for the current 8-hour primary and secondary ozone standards to 70
ppb for both standards. The final rule became effective on
December 28, 2015. States are expected to implement more
stringent requirements as a result of this new final rule, which
could apply to our operations.
Compliance with one
or more of these and other air pollution control and permitting
requirements has the potential to delay the development of oil and
natural gas projects and increase our costs of development and
production, which costs could be significant.
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.
While
Congress has from time to time considered legislation to reduce
emissions of GHGs, there has not been significant activity in the
form of adopted legislation to reduce GHG emissions at the federal
level in recent years. In the absence of such federal climate
legislation, a number of state and regional efforts have emerged
that are aimed at tracking and/or reducing GHG emissions by means
of cap and trade programs that typically require major sources of
GHG emissions to acquire and surrender emission allowances in
return for emitting those GHGs. In addition, the United States is
one of almost 200 nations that, in December 2015, agreed to the
Paris Agreement, an international climate change agreement in
Paris, France (“
Paris Agreement
”) that
calls for countries to set their own GHG emissions targets
and be transparent about the measures each country will use to
achieve its GHG emissions targets. A long-term goal of this Paris
Agreement is to limit global warming to below two degrees Celsius
by 2100 from temperatures in the pre-industrial era. The Paris
Agreement entered into force in November 2016. Although it is
not possible at this time to predict how new laws or regulations in
the United States or any legal requirements imposed following the
United States’ agreeing to the Paris Agreement that may be
adopted or issued to address GHG emissions would impact our
business, any such future laws, regulations or legal requirements
imposing reporting or permitting obligations on, or limiting
emissions of GHGs from, our equipment and operations could require
us to incur costs to reduce emissions of GHGs 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 and natural gas we produce. Finally, it should
be noted that increasing concentrations of GHGs 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.
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, the EPA published final CAA regulations in 2012 and, more
recently, in June 2016 governing performance standards, including
standards for the capture of air emissions released during oil and
natural gas hydraulic fracturing, leak detection, and permitting;
published on June 28, 2016 an effluent limited guideline final
rule prohibiting the discharge of wastewater from onshore
unconventional oil and natural gas extraction facilities to
publicly owned wastewater treatment plants; 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 stringent
standards relating to hydraulic fracturing on federal and American
Indian lands, but on June 21, 2016, a Wyoming federal judge
struck down this final rule, finding that the BLM lacked
congressional authority to promulgate the rule. Also, 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 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. States could elect to prohibit high volume
hydraulic fracturing altogether, following the approach taken by
the State of New York in 2015. In addition to state laws, local
land use restrictions, such as city ordinances, may restrict
drilling in general and/or hydraulic fracturing in particular. For
example, several cities in Colorado passed temporary or permanent
moratoria on hydraulic fracturing within their respective
cities’ limits in 2012-2013 but, since that time, in response
to lawsuits brought by an industry trade group, the Colorado Oil
and Gas Association, local district courts struck down the
ordinances for certain of those Colorado cities in 2014,
primarily on the basis that state law preempts local bans on
hydraulic fracturing. The cities of Fort Collins and Longmont,
among those cities whose ordinances were struck down in 2014,
appealed their decisions to the Colorado Supreme Court, but on
May 2, 2016, the state supreme court upheld the lower court
rulings in the two cases, holding that the legal measures pursued
by Fort Collins and Longmont were pre-empted by state law and,
therefore, unenforceable. Notwithstanding attempts at the local
level to prohibit hydraulic fracturing, there exists the
opportunity for cities to adopt local ordinances allowing hydraulic
fracturing activities within their jurisdictions but regulating the
time, place and manner of those activities.
In addition, 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 aimed at significantly limiting or
preventing oil and natural gas development. In response to such
initiatives, the Governor of Colorado created the Task Force on
State and Local Regulation of Oil and Gas Operations
(“
Task
Force
”) in September 2014
to make recommendations to the state legislature regarding the
responsible development of Colorado’s oil and gas resources.
In February 2015, the Task Force made nine non-binding
recommendations to the Governor that will require legislative or
regulatory action to be implemented. See “
Risk
Factors—Federal, state and local legislative and regulatory
initiatives relating to hydraulic fracturing as well as
governmental reviews of such activities could result in increased
costs and additional operating restrictions or delays in the
completion of oil and natural gas wells and adversely affect our
production,
” for more
information on these recommendations. It is possible that, as a
result of the Task Force’s recommendations, the Colorado
state legislature could seek to adopt new policies or legislation
relating to oil and natural gas operations, including measures that
would give local governments in Colorado greater authority to limit
hydraulic fracturing and other oil and natural gas operations or
require greater distances between well sites and occupied
structures. In addition, it is possible that notwithstanding the
recommendations made by the Task Force, certain interest groups in
Colorado or even members of the Colorado state legislature may seek
to pursue ballot initiatives in the future, and/or legislation that
may or may not coincide with the Task Force’s
recommendations, including, among other things, pursuit of
initiatives or legislation for changes in state law that would
allow local governments to ban hydraulic fracturing in
Colorado.
In
the event that ballot initiatives or local or state restrictions or
prohibitions are adopted in areas where we conduct operations,
including the Wattenberg Field in Colorado, 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.
Certain governmental reviews are either underway
or being proposed that focus on environmental aspects of hydraulic
fracturing practices. The White House Council on Environmental
Quality is coordinating an administration-wide review of hydraulic
fracturing practices. Additionally, in December 2016, the EPA
released its final report on the potential impacts of hydraulic
fracturing on drinking water resources. The EPA report concluded
that hydraulic fracturing activities have not led to widespread,
systemic impacts on drinking water resources in the United States,
although there are above and below ground mechanisms by which
hydraulic fracturing activities have the potential to impact
drinking water resources. Other governmental agencies, including
the United States Department of Energy and the United States
Department of the Interior, are evaluating various other aspects of
hydraulic fracturing. These ongoing or proposed studies could spur
initiatives to further regulate hydraulic fracturing under the
federal SDWA or other regulatory mechanisms.
Ballot Initiatives that would Further Limit Certain Oil and Natural
Gas Development Activities
In accordance with the Colorado Constitution,
citizens in Colorado have the right to pursue amended or new state
legislation through a ballot initiative process. Proponents of
legal requirements imposing more stringent restrictions on oil and
gas exploration and production activities in Colorado sought to
include on the November 2016 ballot certain ballot initiatives
that, if approved, would have allowed revisions to the state
constitution in a manner that would make such exploration and
production activities in the state more difficult in the future.
Among the ballot initiatives pursued in 2016 were Initiative
Number 75 (“
Initiative
75
”), which sought to
authorize local governmental control over oil and natural gas
development in Colorado that could have resulted in the imposition
of more stringent requirements than currently implemented under
state law, and Initiative 78 (“
Initiative
78
”), which proposed a
much more stringent 2,500-foot mandatory setback between an oil and
natural gas development facility (including oil and natural gas
wells, production and processing equipment and pits) and specified
occupied structures and areas of special concern. Changes sought
under these ballot initiatives would have applied to new oil and
gas development facilities in Colorado. Proponents of these
measures collected signatures for placing Initiatives 75 and 78 on
the November 2016 ballot and submitted those signatures to the
Colorado Secretary of State by the August 8, 2016 deadline.
However, on August 29, 2016, the Secretary of State announced
that the proponents had failed to gather enough valid signatures to
put Initiatives 75 and 78 on the November 2016 ballot.
Notwithstanding the Colorado Secretary of State’s
announcement on August 29, 2016, in the event that ballot
initiatives or local or state restrictions or prohibitions are
adopted in the future in areas where we conduct operations 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.
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’ 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 a 2011
settlement agreement, the U.S. Fish and Wildlife Service
(“
FWS
”)
is required to make a determination on listing of numerous species
as endangered or threatened under the FSA by no later than
completion of the agency’s 2017 fiscal year. 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, 2016, we employed 6 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.
GLOSSARY OF OIL AND NATURAL GAS TERMS
The
following is a description of the meanings of some of the oil and
natural gas terms used in this Annual Report.
AFE
or
Authorization for Expenditures
.
A document that lays out proposed expenses for a particular project
and authorizes an individual or group to spend a certain amount of
money for that project.
Bbl
. One stock tank barrel, or
42 U.S. gallons liquid volume, used in this Annual Report in
reference to crude oil or other liquid hydrocarbons.
Bcf.
An abbreviation for
billion cubic feet. Unit used to measure large quantities of gas,
approximately equal to 1 trillion Btu.
Boe
. Barrels of oil equivalent,
determined using the ratio of one Bbl of crude oil, condensate or
natural gas liquids, to six Mcf of natural gas.
Boepd
. Barrels of oil
equivalent per day.
Bopd
. Barrels of oil per
day.
Btu or British thermal unit
.
The quantity of heat required to raise the temperature of one pound
of water by one degree Fahrenheit.
Completion
. The operations
required to establish production of oil or natural gas from a
wellbore, usually involving perforations, stimulation and/or
installation of permanent equipment in the well or, in the case of
a dry hole, the reporting of abandonment to the appropriate
agency.
Condensate
. Liquid hydrocarbons
associated with the production of a primarily natural gas
reserve.
Conventional resources
. Natural
gas or oil that is produced by a well drilled into a geologic
formation in which the reservoir and fluid characteristics permit
the natural gas or oil to readily flow to the
wellbore.
Developed acreage
. The number
of acres that are allocated or assignable to productive
wells.
Development well
. A well
drilled into a proved oil or natural gas reservoir to the depth of
a stratigraphic horizon known to be productive.
Estimated ultimate recovery or
EUR
. Estimated ultimate recovery is the sum of reserves
remaining as of a given date and cumulative production as of that
date.
Exploratory well
. A well
drilled to find and produce oil or natural gas reserves not
classified as proved, to find a new reservoir in a field previously
found to be productive of oil or natural gas in another reservoir
or to extend a known reservoir.
Farmin or farmout
. An agreement
under which the owner of a working interest in an oil or natural
gas lease assigns the working interest or a portion of the working
interest to another party who desires to drill on the leased
acreage. Generally, the assignee is required to drill one or more
wells in order to earn its interest in the acreage. The assignor
usually retains a royalty or reversionary interest in the lease.
The interest received by an assignee is a “
farmin
” while the
interest transferred by the assignor is a “
farmout.
”
FERC
. Federal Energy Regulatory
Commission.
Field
. An area consisting of a
single reservoir or multiple reservoirs all grouped on or related
to the same individual geological structural feature and/or
stratigraphic condition.
Gross acres or gross wells
. The
total acres or wells in which a working interest is
owned.
Henry Hub
. A natural gas
pipeline located in Erath, Louisiana that serves as the official
delivery location for futures contracts on the NYMEX. The
settlement prices at the Henry Hub are used as benchmarks for the
entire North American natural gas market.
Held by production
. An oil and
natural gas property under lease in which the lease continues to be
in force after the primary term of the lease in accordance with its
terms as a result of production from the property.
Horizontal drilling or well
. A
drilling operation in which a portion of the well is drilled
horizontally within a productive or potentially productive
formation. This operation typically yields a horizontal well that
has the ability to produce higher volumes than a vertical well
drilled in the same formation. A horizontal well is designed to
replace multiple vertical wells, resulting in lower capital
expenditures for draining like acreage and limiting surface
disruption.
Liquids
. Liquids, or natural
gas liquids, are marketable liquid products including ethane,
propane, butane and pentane resulting from the further processing
of liquefiable hydrocarbons separated from raw natural gas by a
natural gas processing facility.
LOE
or
Lease operating expenses
. The
costs of maintaining and operating property and equipment on a
producing oil and gas lease.
MBbl
. One thousand barrels of
crude oil or other liquid hydrocarbons.
MMBbl/d
. One thousand barrels
of crude oil or other liquid hydrocarbons per day.
Mcf
. One thousand cubic feet of
natural gas.
Mcfgpd
. Thousands of cubic feet
of natural gas per day.
MMcf
. One million cubic feet of
natural gas.
MMBtu
. One million British
thermal units.
Net acres or net wells
. The sum
of the fractional working interest owned in gross acres or
wells.
Net revenue interest
. The
interest that defines the percentage of revenue that an owner of a
well receives from the sale of oil, natural gas and/or natural gas
liquids that are produced from the well.
NYMEX
. New York Mercantile
Exchange.
Permeability
. A reference to
the ability of oil and/or natural gas to flow through a
reservoir.
Petrophysical analysis
. The
interpretation of well log measurements, obtained from a string of
electronic tools inserted into the borehole, and from core
measurements, in which rock samples are retrieved from the
subsurface, then combining these measurements with other relevant
geological and geophysical information to describe the reservoir
rock properties.
Play
. A set of known or
postulated oil and/or natural gas accumulations sharing similar
geologic, geographic and temporal properties, such as source rock,
migration pathways, timing, trapping mechanism and hydrocarbon
type.
Possible reserves
. Additional
reserves that are less certain to be recognized than probable
reserves.
Probable reserves
. Additional
reserves that are less certain to be recognized than proved
reserves but which, in sum with proved reserves, are as likely as
not to be recovered.
Producing well, production well or
productive well
. A well that is found to be capable of
producing hydrocarbons in sufficient quantities such that proceeds
from the sale of the well’s production exceed
production-related expenses and taxes.
Properties
. Natural gas and oil
wells, production and related equipment and facilities and natural
gas, oil or other mineral fee, leasehold and related
interests.
Prospect
. A specific geographic
area which, based on supporting geological, geophysical or other
data and also preliminary economic analysis using reasonably
anticipated prices and costs, is considered to have potential for
the discovery of commercial hydrocarbons.
Proved developed reserves
.
Proved reserves that can be expected to be recovered through
existing wells and facilities and by existing operating
methods.
Proved reserves
. Reserves of
oil and natural gas that have been proved to a high degree of
certainty by analysis of the producing history of a reservoir
and/or by volumetric analysis of adequate geological and
engineering data.
Proved undeveloped reserves or
PUDs
. Proved reserves that are expected to be recovered from
new wells on undrilled acreage or from existing wells where a
relatively major expenditure is required for
recompletion.
Repeatability
. The potential
ability to drill multiple wells within a prospect or
trend.
Reservoir
. A porous and
permeable underground formation containing a natural accumulation
of producible oil and/or natural gas that is confined by
impermeable rock or water barriers and is individual and separate
from other reservoirs.
Royalty interest
. An interest
in an oil and natural gas lease that gives the owner of the
interest the right to receive a portion of the production from the
leased acreage (or of the proceeds of the sale thereof), but
generally does not require the owner to pay any portion of the
costs of drilling or operating the wells on the leased acreage.
Royalties may be either landowner’s royalties, which are
reserved by the owner of the leased acreage at the time the lease
is granted, or overriding royalties, which are usually reserved by
an owner of the leasehold in connection with a transfer to a
subsequent owner.
2-D seismic
. The method by
which a cross-section of the earth’s subsurface is created
through the interpretation of reflecting seismic data collected
along a single source profile.
3-D seismic
. The method by
which a three-dimensional image of the earth’s subsurface is
created through the interpretation of reflection seismic data
collected over a surface grid. 3-D seismic surveys allow for a more
detailed understanding of the subsurface than do 2-D seismic
surveys and contribute significantly to field appraisal,
exploitation and production.
Trend
. A region of oil and/or
natural gas production, the geographic limits of which have not
been fully defined, having geological characteristics that have
been ascertained through supporting geological, geophysical or
other data to contain the potential for oil and/or natural gas
reserves in a particular formation or series of
formations.
Unconventional resource play
. A
set of known or postulated oil and or natural gas resources or
reserves warranting further exploration which are extracted from
(a) low-permeability sandstone and shale formations and (b) coalbed
methane. These plays require the application of advanced technology
to extract the oil and natural gas resources.
Undeveloped acreage
. Lease
acreage on which wells have not been drilled or completed to a
point that would permit the production of commercial quantities of
oil and natural gas, regardless of whether such acreage contains
proved reserves. Undeveloped acreage is usually considered to be
all acreage that is not allocated or assignable to productive
wells.
Unproved and unevaluated
properties
. Refers to properties where no drilling or other
actions have been undertaken that permit such property to be
classified as proved.
Vertical well
. A hole drilled
vertically into the earth from which oil, natural gas or water
flows is pumped.
Volumetric reserve analysis
. A
technique used to estimate the amount of recoverable oil and
natural gas. It involves calculating the volume of reservoir rock
and adjusting that volume for the rock porosity, hydrocarbon
saturation, formation volume factor and recovery
factor.
Wellbore
. The hole made by a
well.
WTI
or
West Texas Intermediate
. A
grade of crude oil used as a benchmark in oil pricing. This grade
is described as light because of its relatively low density, and
sweet because of its low sulfur content.
Working interest
. The operating
interest that gives the owner the right to drill, produce and
conduct operating activities on the property and receive a share of
production.
ITEM 1A. RISK FACTORS.
An investment in our common stock involves a high degree of risk.
You should carefully consider the risks described below as well as
the other information in this filing before deciding to invest in
our company. Any of the risk factors described below could
significantly and adversely affect our business, prospects,
financial condition and results of operations. Additional risks and
uncertainties not currently known or that are currently considered
to be immaterial may also materially and adversely affect our
business, prospects, financial condition and results of operations.
As a result, the trading price or value of our common stock could
be materially adversely affected and you may lose all or part of
your investment.
Risks Related to the Oil and Natural Gas Industry and Our
Business
Continuation of the recent declines, or further declines, in oil
and, to a lesser extent, 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 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 58% of our
estimated proved reserves as of December 31, 2016 were oil,
our financial results are more sensitive to movements in oil
prices. Since mid-2014, the price of crude oil has significantly
declined. 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, like the current commodity price
environment, 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, 2016, the
daily NYMEX WTI oil spot price ranged from a high of $54.01 per Bbl
to a low of $26.19 per Bbl and the NYMEX natural gas Henry Hub spot
price ranged from a high of $3.59 per MMBtu to a low of $1.73 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 $101,731,000 from the
date of inception (February 9, 2011) through December 31, 2016.
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. 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.
We require significant additional financing to pay our outstanding
liabilities and in the event we cannot raise additional funding or
undertake a business combination transaction prior to the due date
of such liabilities, we may be forced to sell assets, our debtors
may foreclose on our assets or we may be forced to seek bankruptcy
protection.
We
currently have significant indebtedness and our debt agreements
require us to use a significant portion of our revenues to pay down
our outstanding debt. 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 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.
We are currently working to complete the GOM Merger, which we
believe will provide us additional capital, but in the event we are
unable to raise necessary funding in the future or complete a
business combination or similar transaction in the near term, we
may not be able to pay our debts (or make required amortization and
principal payments on such debts) as they come due or continue to
drill wells and/or participate in their drilling.
If this
were to happen, we may be forced to scale back our business plan,
sell or liquidate assets to satisfy outstanding debts (or our
creditors may undertake a foreclosure of such assets in order to
satisfy amounts we owe to such creditors, with or without our
assistance) and/or take other steps which may include seeking
bankruptcy protection, all of which could result in the value of
our outstanding securities declining in value or becoming
worthless.
We may not be able to generate sufficient cash flow to meet our
debt service and other obligations due to events beyond our
control.
Our
ability to generate cash flows from operations, to make scheduled
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 debt service and repayment
obligations, we would be in default under the terms of the
agreements governing our indebtedness, which would allow our
creditors at that time to declare all of our outstanding
indebtedness to be due and payable. This would likely in turn
trigger cross-acceleration or cross-default rights between our
applicable debt agreements. 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 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.
Our Tranche A Notes and Tranche B Notes include various covenants,
reduces our financial flexibility, increases our interest expense
and may adversely impact our operations and our costs.
In
connection with our acquisition of certain assets from Continental
on March 7, 2014, we entered into a senior debt facility pursuant
to which we borrowed $34.5 million initially and have subsequently
borrowed an additional $2.0 million (our “
Tranche B Notes
”) which
amounts represent a significant amount of indebtedness. In
addition, in connection with our Senior Debt Restructuring in May
2016, we borrowed an additional $6.4 million (our
“
Tranche A
Notes
,” and together with our Tranche B Notes, our
“
senior debt
facility
”), leaving approximately $18.0 million
available for future drilling operations thereunder, subject to the
terms and conditions of such facility which amounts also represent
a significant amount of indebtedness.
This
senior debt facility includes various covenants (positive and
negative) binding us, including:
|
●
|
requiring
that we maintain the registration of our common stock under Section
12 of the Securities Exchange Act of 1934, as amended;
|
|
|
|
|
●
|
requiring
that we maintain the listing of our common stock on the NYSE
MKT;
|
|
|
|
|
●
|
requiring
that we timely file periodic reports under the Exchange
Act;
|
|
|
|
|
●
|
requiring
that we provide the lenders yearly and quarterly budgets and
certain reserve reports;
|
|
|
|
|
●
|
requiring
that we provide capital expenditure plans to the lenders prior to
making certain expenditures;
|
|
|
|
|
●
|
prohibiting
us and our subsidiaries from creating or becoming subject to any
indebtedness, except pursuant to certain limited exceptions;
and
|
|
|
|
|
●
|
prohibiting
us or our subsidiaries from merging, selling assets (except in the
usual course of business), altering our organizational structure,
winding up or liquidating, except in certain limited
circumstances.
|
Our
senior debt facility affects our operations in several ways,
including the following:
|
●
|
a
significant portion of our cash flows must be used to service the
debt facility, with the Company required to pay all of its oil and
gas revenues on a monthly basis to the lenders, subject to a
monthly general and administrative expense (“G&A”)
cap of $150,000 which is permitted to be applied against Company
general and administrative expenses. See “
Part I
,
Item 1. Business
” —
“
Recent
Developments
” — “
Senior Debt
Restructuring
”);
|
|
|
|
|
●
|
the
high level of debt could increase our vulnerability to general
adverse economic and industry conditions;
|
|
|
|
|
●
|
limiting
our ability to borrow additional funds, dispose of assets, pay
dividends and make certain investments; and
|
|
|
|
|
●
|
the
debt covenants may affect our flexibility in planning for, and
reacting to, changes in the economy and in our
industry.
|
The
high level of indebtedness under our senior debt facility 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, all revenues we do generate above $150,000
per month will be required to be used to repay the 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 to
pay the interest or principal due on the debt, fund our business
plan and satisfy our other obligations and liabilities, 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 do
not currently have any commitments of additional capital except
pursuant to the terms of these debt facilities. We can provide no
assurance that additional financing will be available on favorable
terms, if at all. If we choose to raise additional capital through
the sale of other debt or equity securities, such sales may cause
substantial dilution to our existing shareholders.
A portion of our Tranche B Notes,
our junior debt held by RJC, and all of our Series A Convertible
Preferred stock are held by entities whose parent company is in
liquidation, which may have a negative impact on the Company and
its business.
Each of
GOM, RJC and GGE are owned by Partners Value Arbitrage Fund, LP, a
New York based investment firm (“
PPVAF
”), and were
formerly advised by Platinum Management (NY), LLC
(“
PM
LLC
”). PPVAF, and, by virtue of being owned by PPVAF,
GGE, RJC, and GOM, are currently in the process of winding down and
liquidating their assets through the oversight and control of a
court-appointed liquidator in the Cayman Islands and are no longer
advised by PM LLC or any of its affiliates. Additionally, the
Company is aware that the former manager of PPVAF, PM LLC, is
currently under investigation by the U.S. Securities and Exchange
Commission and the Justice Department and that certain former
executives have been indicted by the Justice Department, however,
PM LLC and those certain executives no longer have any control over
PPVAF, GOM, RJC or GGE, which entities are currently solely under
the control of the Cayman Islands court-appointed liquidators.
While the Company does not foresee that the confluence of these
events or control of these entities by the court-appointed
liquidator will disrupt or have a negative impact on the Company or
its business, these extraordinary events may have a negative impact
on the Company and its business, including, but not limited to,
potential inability or delays in the Company’s efforts to
restructure Company debt and equity controlled by the liquidator or
consummate the GOM Merger.
The repayment of our senior debt facility is secured by a security
interest in all of our assets.
The
repayment of our senior debt facility (which has an outstanding
principal balance of approximately $48.95 million as of March 1,
2017 and provides us the option, pursuant to the terms of the debt
facility, to borrow an additional approximately $18.0 million) is
secured by a first priority security interest in all of our assets,
property, real property and the securities of our subsidiaries and
the repayment of such debt is further guaranteed by certain of our
subsidiaries. If we default in the repayment of the senior
debt facility and/or any of the terms and conditions thereof,
the lenders may enforce their security interest over our assets
which secure the repayment of such debt, and we could be forced to
curtail or abandon our current business plans and operations. If
that were to happen, any investment in the Company could become
worthless.
The occurrence of an event of default under the notes sold in
connection with our senior debt facility could have a material
adverse effect on us and our financial condition.
The
notes issued in connection with our senior debt facility include
standard and customary events of default, including, among other
things, our or any subsidiary’s default in the payment of any
indebtedness under any agreement, or failure to comply with the
terms and conditions of any other agreement related to indebtedness
or otherwise, if the effect of such failure or default, is to
cause, or permit the holder or holders thereof, or any counterparty
to an agreement relating to indebtedness, to cause indebtedness, or
amounts due thereunder, in an aggregate amount of $250,000 or more
to become due prior to its stated date of maturity or the date such
amount would otherwise have been due notwithstanding such default,
subject to certain exclusions; the loss, suspension or revocation
of, or failure to renew, any license or permit, if such license or
permit is not obtained or reinstated within thirty (30) days,
unless such loss, suspension, revocation or failure to renew could
not reasonably be expected to have a material adverse effect on us;
or there is filed against us or any of our subsidiaries or any of
our officers, members or managers any civil or criminal action,
suit or proceeding under any federal or state racketeering statute
(including, without limitation, the Racketeer Influenced and
Corrupt Organization Act of 1970), or any civil or criminal action,
suit or proceeding under any other applicable law is filed by any
governmental entity, that could result in the confiscation or
forfeiture of any material portion of any collateral subject to any
security interest held by the investors or their agent or other
assets of such entity or person, and such action, suit or
proceeding is not dismissed within one hundred twenty (120)
days.
Upon an
event of default under the notes, the holder of such note may
declare the entire unpaid balance (as well as any interest, fees
and expenses) immediately due and payable. Funding to repay such
notes may not be available timely, on favorable terms, if at all,
and any default by us of the terms and conditions of the notes
would likely have a material adverse effect on our results of
operations, financial condition and the value of our common
stock.
We owe certain obligations to MIEJ under the New MIEJ Note, which
is secured by a subordinated security interest in substantially all
of our assets and is convertible into shares of our common stock
subject to the terms of such New MIEJ Note, and may result in
substantial dilution to existing shareholders.
The New
MIEJ Note is subordinated in every way to the senior credit
facility as well as to New Senior Lending (defined below); however,
MIEJ has no control over our cash flow, nor is MIEJ’s consent
required in connection with any disposition, sale, or use of any of
our assets, provided that the requirements of the New MIEJ Note
requiring the prepayment of interest, where applicable, as
described below are followed. We have the right under the New MIEJ
Note to enter into a loan, or a series of new loans or any other
new non-equity investment or assumption of indebtedness (a
“
New Senior
Lending
”) which will be senior to the New MIEJ Note,
without the prior consent of MIEJ, provided that, in addition to
the approximately $35.5 million principal balance of the original
PEDEVCO Senior Loan created in March 2014, the New Senior Lending
is subject to a cap of an additional $60 million in the aggregate,
such that the total lending, debt or similar investment under such
cap shall not exceed $95 million in the aggregate (the
“
Senior Debt
Cap
”), with any portion of New Senior Lending in
excess of the Senior Debt Cap advanced first to MIEJ until the New
MIEJ Note is paid in full. The New MIEJ Note shall automatically,
and without further consent from MIEJ, be subordinated in every way
to any such New Senior Lending. Should we enter into any new
financing transaction that results in raising New Senior Lending of
at least $20 million in excess of the balance of the PEDEVCO Senior
Loan, then MIEJ has a right to be paid all interest and fees that
have accrued on the New MIEJ Note each and every time that a new
financing transaction reaches or exceeds the $20 million
threshold.
The New
MIEJ Note was originally due and payable on March 8, 2017, but is
now due and payable on March 8, 2019, due to an automatic maturity
date extension as a result of the May 2016 Senior Debt
Restructuring, and with such date also subject to additional
automatic extensions upon the occurrence of a Long-Term Financing
or additional PEDEVCO Senior Lending Restructuring (each as defined
below) (the “
Maturity
”). On a one-time
basis, the PEDEVCO Senior Loan may be refinanced by a new loan
(“
Long-Term
Financing
”) by one or more third party replacement
lenders (“
Replacement Lenders
”),
and in such event we are required to undertake commercially
reasonable best efforts to cause the Replacement Lenders to
simultaneously refinance both the PEDEVCO Senior Loan and the New
MIEJ Note as part of such Long-Term Financing. Despite such
efforts, should the Replacement Lenders be unable or unwilling to
include the New MIEJ Note in such financing, then the Long-Term
Financing may proceed without including the New MIEJ Note, and the
New MIEJ Note shall remain in place and shall be automatically
subordinated, without further consent of MIEJ, to such Long-Term
Financing. Furthermore, upon the occurrence of a Long-Term
Financing, the Maturity of the New MIEJ Note is automatically
extended, without further consent of MIEJ, to the same maturity
date of the Long-Term Financing (the “
Extended Maturity Date
”),
provided that the Extended Maturity Date may not exceed March 8,
2020. Additionally, upon the closing of such Long-Term Financing:
(a) the Long-Term Financing is required to be subject to the Senior
Debt Cap, (b) we are required to make commercially reasonable best
efforts for the Long-Term Financing to include adequate reserves or
other payment provisions whereby MIEJ is paid all interest and fees
accrued on the New MIEJ Note commencing as of March 8, 2017 (and
annually thereafter, until such time as the New MIEJ Note is paid
in full), but in any event the Replacement Lenders are required to
agree to allow for quarterly interest payments (starting March 31,
2017) of not less than 5% per annum on the outstanding balance of
the New MIEJ Note, plus a one-time payment of accrued interest (not
to exceed $500,000) as of March 31, 2017 (the “
Subordinated Interest
Payments
”), and the remaining 5% interest shall
continue to accrue, and (c) MIEJ has the Right of Conversion
(defined below) commencing as of March 8, 2017, the original
maturity date of the New MIEJ Note. If the PEDEVCO Senior Loan
and/or New Senior Lending is not refinanced by Replacement Lenders,
but is instead refinanced, restructured or extended by the existing
Investors (a “
PEDEVCO Senior Lending
Restructuring
”), the maturity of both the New MIEJ
Note and the PEDEVCO Senior Loan may be extended to no later than
March 8, 2019, without requiring the consent of MIEJ, provided that
(i) any such extension of the maturity date of the New MIEJ Note
past March 8, 2017 shall give MIEJ the Right of Conversion
(described below) commencing on March 8, 2017, and (ii) such
extension agreement shall include payment provisions whereby MIEJ
shall be paid all interest and fees accrued on the New MIEJ Note as
of March 8, 2018. The May 2016 Senior Debt Restructuring qualified
as a PEDEVCO Senior Lending Restructuring and the issuance of the
Tranche A Notes qualified as a New Senior Lending, the result of
which the Maturity of the New MIEJ Note has been extended to March
8, 2019. The New MIEJ Note may be prepaid any time without
penalty.
The New
MIEJ Note has a conversion feature that provides that beginning
March 8, 2017, MIEJ has the right, at its discretion, to have the
outstanding balance of the New MIEJ Note plus any accrued and
unpaid interest thereon converted in whole or in part into our
common stock at a price (the “
Conversion Price
”) equal
to 80% of the average closing price per share of our common stock
over the then previous 60 days from the date MIEJ exercises its
conversion right (subject to adjustment for stock splits,
recapitalizations and the like)(such event, a “
Right of Conversion
”);
provided, however, that in no event shall the Conversion Price be
less than $0.30 per share (the “
Floor Price
”). The New
MIEJ Note originally included a conversion limitation subject to us
receiving shareholder approval under applicable NYSE MKT rules, but
at the 2016 Annual Meeting held on December 28, 2016, the
Company’s stockholders approved the full conversion of the
New MIEJ Note and the New MIEJ Note is now fully convertible into
our common stock in accordance with its terms.
If an
event of default occurs under the New MIEJ Note, MIEJ may enforce
their security interests over our assets (subject to the
subordination rights in such note) which secure the repayment of
such obligations, and we could be forced to curtail or abandon our
current business plans and operations. If that were to happen, any
investment in us could become worthless.
The
required interest and principal payments due under the New MIEJ
Note may make it harder for us to refinance the New MIEJ Note or
raise funding in the future, or could materially decrease the
amount of cash we receive for our operations upon any refinancing
or funding.
The
issuance of common stock pursuant to the terms of the New MIEJ Note
could result in immediate and substantial dilution to the interests
of other stockholders.
A substantial part of our crude oil, natural gas and NGLs
production is located in the D-J Basin, making us vulnerable to
risks associated with operating primarily in a single geographic
area. In addition, we have a large amount of proved reserves
attributable to a small number of producing
formations.
Our
operations are focused primarily in the D-J Basin of Weld County,
Colorado, which means our current producing properties and new
drilling opportunities are geographically concentrated in that
area. 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 the area;
|
|
|
|
|
●
|
natural
disasters such as the flooding that occurred in the 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 D-J Basin have negatively
affected 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 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
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 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 and natural gas heavily influence our
revenue, profitability, cash flow available for capital
expenditures, access to capital and future rate of growth. Oil 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 prices for oil and
natural gas have been volatile. For example, the price of oil has
fallen dramatically since mid-2014, with a high over $100 per
barrel in June 2014 to lows below $30 per barrel in early 2016, in
each case based on 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 have
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 and natural gas;
|
|
|
|
|
●
|
the
domestic and foreign demand for oil and natural gas;
|
|
●
|
the
prices and availability of competitors’ supplies of oil 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 and natural
gas;
|
|
|
|
|
●
|
the
impact of U.S. dollar exchange rates on oil and natural gas
prices;
|
|
|
|
|
●
|
domestic
and foreign governmental regulations and taxes;
|
|
|
|
|
●
|
speculative
trading of oil 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 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 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 or
natural gas prices would not only reduce our revenue, but could
reduce the amount of oil and natural gas that we can produce
economically. Should natural gas 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.
The report of our independent registered public accounting firm
expressed substantial doubt about the Company’s ability to
continue as a going concern.
Our
auditors indicated in their report on the Company’s
consolidated audited financial statements for the fiscal year ended
December 31, 2016 that conditions existed that could raise
substantial doubt about our ability to continue as a going concern
due in part to the current crude oil price environment and the fact
that the Company had a working capital deficit and accumulated
deficit at December 31, 2016. Uncertainties related to our
continuation as a going concern may impair our ability to finance
our operations through the sale of equity, incurring debt, or other
financing alternatives and/or negatively affect our relationships
with partners and service providers. Our ability to continue as a
going concern will depend upon the availability and terms of future
funding, our ability to grow our operations and integrate newly
acquired assets and operations, our ability to acquire additional
assets and operations, and our ability to improve operating margins
and regain profitability. If we are unable to achieve these goals,
our business would be jeopardized and the Company may not be able
to continue. If we ceased operations, it is likely that all of our
investors would lose their investment.
The
Company will seek financing from other sources. Such financings may
not be available or, if available, may not be on terms acceptable
to the Company. Accordingly, the financial statements do not
include any adjustments related to the recoverability of assets or
classification of liabilities that might be necessary should the
Company be unable to continue as a going concern. The ability of
the Company to continue as a going concern is dependent upon its
ability to raise capital to meet its obligations and attain
profitable 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. As a result, there is an
increased risk that we will incur an impairment in 2017. In
addition, 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;
|
|
|
|
|
●
|
natural
disasters;
|
|
|
|
|
●
|
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;
|
|
|
|
|
●
|
fires
or explosions;
|
|
|
|
|
●
|
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. 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 unconventional 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 state of 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 Colorado, natural
disasters in Colorado, competition for equipment, services and
materials available in Colorado and access to infrastructure and
markets in Colorado.
Unless we replace our oil and natural gas reserves, our reserves
and production will decline, which would 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, including our planned combination with
GOM, 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.
Failure to
complete the GOM Merger could negatively impact our stock price and
future business and financial results.
If the
GOM Merger is not completed, our ongoing business may be adversely
affected and we would be subject to a number of risks, including
the following:
|
●
|
we will
not realize the benefits expected from the GOM Merger, including a
potentially enhanced competitive and financial position, expansion
of assets and therefore opportunities, and will instead be subject
to all the risks we currently face as an independent
company;
|
|
|
|
|
●
|
we may
experience negative reactions from the financial markets and our
partners and employees;
|
|
|
|
|
●
|
the GOM
Merger Agreement places certain restrictions on the conduct of our
business prior to the completion of the GOM Merger or the
termination of the GOM Merger Agreement. Such restrictions, the
waiver of which is subject to the consent of GOM, may prevent us
from making certain acquisitions, taking certain other specified
actions or otherwise pursuing business opportunities during the
pendency of the GOM Merger; and
|
|
|
|
|
●
|
matters
relating to the GOM Merger (including integration planning) may
require substantial commitments of time and resources by our
management, which would otherwise have been devoted to other
opportunities that may have been beneficial to us as an independent
company.
|
The GOM Merger Agreement may be terminated in accordance with its
terms and the GOM Merger may not be completed.
The GOM
Merger Agreement is subject to a number of conditions which must be
fulfilled in order to complete the GOM Merger. Those conditions
include (1) approval of the GOM Merger Agreement by the board of
directors of the Company, the sole Manager and member of Merger
Sub, the Board of Managers of GOM, and the members of GOM, (2)
receipt of required regulatory approvals, (3) the absence of any
law or order prohibiting the consummation of the GOM Merger, and
(4) approval of the NYSE MKT for the issuance of the common stock
and shares of common stock issuable upon conversion of the Series B
Preferred to the members of GOM at closing. In addition, prior to
the closing of the GOM Merger, either the Company or GOM may
terminate the GOM Merger at any time.
Termination of the GOM Merger Agreement could negatively impact the
Company.
In the
event the GOM Merger Agreement is terminated, our business may have
been adversely impacted by our failure to pursue other beneficial
opportunities due to the focus of management on the GOM Merger, and
the market price of our common stock might decline to the extent
that the current market price reflects a market assumption that the
GOM Merger will be completed. If the GOM Merger Agreement is
terminated and our board of directors seeks another transaction or
business combination, our stockholders cannot be certain that we
will be able to find a party willing to offer equivalent or more
attractive consideration than the consideration provided for by the
GOM Merger.
The closing of the GOM merger is subject to various risks and
closing conditions and such planned transaction may not occur on a
timely basis, if at all.
The
GOM Merger is subject to various closing conditions as set forth in
greater detail in the GOM Merger Agreement. Additionally, the
Company is aware that the parent company of GOM has experienced
significant liquidity problems, is currently under investigation by
the U.S. Securities and Exchange Commission and the Justice
Department, is currently under the control of a court-appointed
liquidator that is taking steps to liquidate its assets, including
the assets subject to the GOM Merger, has filed for Bankruptcy
protection, and certain of its assets are also subject to separate
Bankruptcy proceedings initiated by certain creditors. In addition,
to the extent GOM’s assets are encumbered by debt, and such
debtholders do not agree to the assumption of the debt by the
Company, or to otherwise refinance or restructure such debt as
needed to consummate the GOM Merger, GOM and the Company may not be
able to consummate the GOM Merger. Any one of these circumstances
may delay the closing of the GOM Merger or prevent certain closing
conditions associated therewith from occurring, which in turn could
prevent the merger from closing.
We will be subject to business uncertainties and contractual
restrictions while the GOM Merger is pending.
Uncertainty about
the effect of the GOM Merger on employees and partners may have an
adverse effect on us. These uncertainties may impair our ability to
attract, retain and motivate key personnel until the GOM Merger is
completed, and could cause partners and others that deal with us to
seek to change existing business relationships, cease doing
business with us or cause potential new partners to delay doing
business with us until the GOM Merger has been successfully
completed. Retention of certain employees may be challenging during
the pendency of the GOM Merger, as certain employees may experience
uncertainty about their future roles or compensation structure. If
key employees depart because of issues relating to the uncertainty
and difficulty of integration or a desire not to remain with the
business, our business following the GOM Merger could be negatively
impacted. In addition, the GOM Merger Agreement restricts us from
making certain acquisitions and taking other specified actions
until the GOM Merger is completed without the consent of GOM. These
restrictions may prevent us from pursuing attractive business
opportunities that may arise prior to the completion of the GOM
Merger.
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 filing 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.
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 intend to 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 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.
Strategic relationships, including with Tenet Advisory Group, upon
which we may rely, are subject to risks and uncertainties which may
adversely affect our business, financial conditions and results of
operations.
Our
ability to explore, develop and produce oil and natural gas
resources successfully and acquire oil and natural gas interests
and acreage depends on our developing and maintaining close working
relationships with industry participants and on our ability to
select and evaluate suitable acquisition opportunities in a highly
competitive environment. These realities are subject to risks and
uncertainties that may adversely affect our business, financial
condition and results of operations.
To
develop our business, we will endeavor to use the business
relationships of our management and board to enter into strategic
relationships, which may take the form of contractual arrangements
with other oil and natural gas companies, including those that
supply equipment and other resources that we expect to use in our
business. For example, we have retained Tenet Advisory Group, LLC
as a key advisor for our operations, exploration and drilling
efforts. We may not be able to establish these strategic
relationships, or if established, we may not be able to maintain
them. In addition, the dynamics of our relationships with strategic
partners may require us to incur expenses or undertake activities
we would not otherwise be inclined to incur in order to fulfill our
obligations to these partners or maintain our relationships. If our
strategic relationships are not established or maintained, our
business, financial condition and results of operations may be
adversely affected.
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 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 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 will
derive 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 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.
We may incur additional indebtedness which could reduce our
financial flexibility, increase interest expense and adversely
impact our operations and our unit costs.
In the
future, we may incur significant amounts of additional indebtedness
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.
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 choose not to hedge our exposure to reductions in oil
and natural gas prices by purchasing futures and by using other
hedging strategies, we may be subject to 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
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 & Gas Conservation Commission (the
“
COGCC
”)
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.
We are subject to stringent federal, state and local laws and
regulations related to environmental and occupational health and
safety issues that could adversely affect the cost, manner or
feasibility of conducting our operations or expose us to
significant liabilities.
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. These laws and regulations may impose
numerous obligations applicable to our operations including the
acquisition of a permit before conducting drilling and other
regulated activities; the restriction of types, quantities and
concentration of materials that may be released into the
environment; the limitation or prohibition of drilling activities
on certain lands lying within wilderness, wetlands and other
protected areas; the application of specific health and safety
criteria addressing worker protection; and the imposition of
substantial liabilities for pollution resulting from our
operations. Numerous governmental authorities, such as the EPA and
analogous state agencies have the power to enforce compliance with
these laws and regulations and the permits issued under them. Such
enforcement actions often involve taking difficult and costly
compliance measures or corrective actions. Failure to comply with
these laws and regulations may result in the assessment of
sanctions, including administrative, civil or criminal penalties,
the imposition of investigatory or remedial obligations, and the
issuance of orders limiting or prohibiting some or all of our
operations. In addition, we may experience delays in obtaining or
be unable to obtain required permits, which may delay or interrupt
our operations or specific projects and limit our growth and
revenue.
There is inherent risk of
incurring significant environmental costs and liabilities in the
performance of our operations due to our handling of petroleum
hydrocarbons and other hazardous substances and wastes, as a result
of air emissions and wastewater discharges related to our
operations, and because of historical operations and waste disposal
practices at our leased and owned properties. Spills or other
releases of regulated substances, including such spills and
releases that occur in the future, could expose us to material
losses, expenditures and liabilities under applicable environmental
laws and regulations. Under certain of such laws and regulations,
we could be subject to strict, joint and several
liability for the removal or
remediation of previously released materials or property
contamination, regardless of whether we were responsible for the
release or contamination and even if our operations met previous
standards in the industry at the time they were conducted. We may
not be able to recover some or any of these costs from insurance.
Changes in environmental laws and regulations occur frequently, and
any changes that result in more stringent or costly well drilling,
construction, completion or water management activities, air
emissions control or waste handling, storage, transport, disposal
or cleanup requirements could require us to make significant
expenditures to attain and maintain compliance and may otherwise
have a material adverse effect on our results of operations,
competitive position or financial condition. For example, on
October 1, 2015, the EPA issued a final rule under the Clean
Air Act, lowering the National Ambient Air Quality Standard
(“
NAAQS
”)
for ground-level ozone from the current standard of 75 parts per
billion (“
ppb
”)
for the current 8-hour primary and secondary ozone standards to 70
ppb for both standards. States are expected to implement more
stringent requirements as a result of this new final rule, which
could apply to our operations. Compliance with this more stringent
standard and other environmental regulations could delay or
prohibit our ability to obtain permits for operations or require us
to install additional pollution control equipment, the costs of
which could be significant. Please read “
Part
I
”
– “
Item
1. Business
” —
“
Regulation
of the Oil and Gas Industry
” and
“
Regulation
of Environmental and Occupational Safety and Health
Matters
”
for a further description of the laws and regulations that affect
us.
Should we fail to comply with all applicable regulatory agency
administered statutes, rules, regulations and orders, we could be
subject to substantial penalties and fines.
Under the Energy Policy Act of
2005 (“
EPAct
2005
”),
the Federal Energy Regulatory Commission (the
“
FERC
”)
has civil penalty authority under the Natural Gas Act of 1938
(“
NGA
”)
to impose penalties for current violations of up to $1 million
per day for each violation. The FERC may also impose administrative
and criminal remedies and disgorgement of profits associated with
any violation. While our operations have not been regulated by FERC
as a natural gas company under the NGA, FERC has adopted
regulations that may subject certain of our otherwise non-FERC
jurisdictional facilities to FERC annual reporting requirements. We
also must comply with the anti-market manipulation rules enforced
by FERC. Additional rules and regulations pertaining to those and
other matters may be considered or adopted by FERC from time to
time. Additionally, the Federal Trade Commission
(“
FTC
”)
has regulations intended to prohibit market manipulation in the
petroleum industry with authority to fine violators of the
regulations civil penalties of up to $1 million per day and
the Commodity Futures Trading Commission
(“
CFTC
”)
prohibits market manipulation in the markets regulated by the CFTC,
including similar anti-manipulation authority with respect to oil
swaps and futures contracts as that granted to the CFTC with
respect to oil purchases and sales. The CFTC rules subject
violators to a civil penalty of up to the greater of
$1 million or triple the monetary gain to the person for
each
violation. Failure to comply with
those regulations in the future could subject us to civil penalty
liability, as described in “
Part
I
”
– “
Item
1. Business
” —
“
Regulation
of the Oil and Gas Industry
”.
Climate change laws and regulations restricting emissions of
greenhouse gases could result in increased operating costs and
reduced demand for the oil, natural gas and NGL that we produce
while potential physical effects of climate change could disrupt
our production and cause us to incur significant costs in preparing
for or responding to those effects.
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 GHG emissions from 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 oil and
natural gas production sources, which include certain of our
operations.
While Congress has from time to
time considered legislation to reduce emissions of GHGs, there has
not been significant activity in the form of adopted legislation to
reduce GHG emissions at the federal level in recent years. In the
absence of such federal climate legislation, a number of state and
regional efforts have emerged that are aimed at tracking and/or
reducing GHG emissions by means of cap and trade programs that
typically require major sources of GHG emissions to acquire and
surrender emission allowances in return for emitting those GHGs. In
addition, the United States is one of almost 200 nations that, in
December 2015, agreed to an international climate change agreement
in Paris, France (“
Paris
Agreement
”) that calls for countries
to set their own GHG emissions targets and be transparent about the
measures each country will use to achieve its GHG emissions
targets. Although it is not possible at this time to predict how
new laws or regulations in the United States or any legal
requirements imposed following the United States’ agreeing to
the Paris Agreement that may be adopted or issued to address GHG
emissions would impact our business, any such future laws,
regulations or legal requirements imposing reporting or permitting
obligations on, or limiting emissions of GHGs from, our equipment
and operations could require us to incur costs to reduce emissions
of GHGs 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. Finally, it should be noted that increasing
concentrations of GHGs 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.
Federal, state and local legislative and regulatory initiatives
relating to hydraulic fracturing as well as governmental reviews of
such activities could result in increased costs and additional
operating restrictions or delays in the completion of oil and
natural gas wells and adversely affect our production.
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, the EPA has published final Clean Air Act
(“
CAA
”) regulations in 2012 and, more recently,
in June 2016 governing performance standards, including standards
for the capture of air emissions released during oil and natural
gas hydraulic fracturing, leak detection, and permitting; published
on June 28, 2016 an effluent limited guideline final rule
prohibiting the discharge of wastewater from onshore unconventional
oil and natural gas extraction facilities to publicly owned
wastewater treatment plants; 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 federal Bureau of
Land Management (“
BLM
”) published a final rule in March 2015,
establishing stringent standards relating to 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, on June 21, 2016, a Wyoming
federal judge struck down this final rule, finding that the BLM
lacked congressional authority to promulgate the rule. Also, 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.
Certain governmental
reviews are either underway or being proposed that focus on
environmental aspects of hydraulic fracturing practices. The White
House Council on Environmental Quality is coordinating an
administration-wide review of hydraulic fracturing practices.
Additionally, in December 2016, the EPA released its final report
on the potential impacts of hydraulic fracturing on drinking water
resources. The EPA report concluded that hydraulic fracturing
activities have not led to widespread, systemic impacts on drinking
water resources in the United States, although there are above and
below ground mechanisms by which hydraulic fracturing activities
have the potential to impact drinking water resources. Other
governmental agencies, including the United States Department of
Energy and the United States Department of the Interior, are
evaluating various other aspects of hydraulic fracturing. These
ongoing or proposed studies could spur initiatives to further
regulate hydraulic fracturing under the federal SDWA or other
regulatory mechanisms.
At the state level,
Colorado, where we conduct operations, is among the states that has
adopted, and other states are considering adopting, regulations
that impose new or more stringent permitting,
disclosure or well-construction
requirements on hydraulic fracturing operations. In addition to
state laws, local land use restrictions may restrict drilling in
general and/or hydraulic fracturing in particular. For example,
several cities in Colorado passed temporary or permanent moratoria
on hydraulic fracturing within their respective cities’
limits in 2012-2013 but, since that time, in response to lawsuits
brought by an industry trade group, the Colorado Oil and Gas
Association, local district courts struck down the ordinances for
certain of those Colorado cities in 2014, primarily on the basis
that state law preempts local bans on hydraulic fracturing. The
cities of Fort Collins and Longmont, among those cities whose
ordinances were struck down in 2014, appealed their decisions to
the Colorado Supreme Court, but on May 2, 2016, the state
supreme court upheld the lower court rulings in those two cases,
holding that a five-year moratorium on hydraulic fracturing adopted
by Fort Collins and a ban on fracturing adopted by Longmont were
pre-empted by state law and, therefore, unenforceable. Another suit
brought by the Colorado trade group against one other city,
Broomfield, who had adopted a moratorium on fracturing, has been on
hold pending the outcome of the Colorado Supreme Court ruling in
the Fort Collins and Longmont cases. Notwithstanding attempts at
the local level to prohibit hydraulic fracturing, there exists the
opportunity for cities to adopt local ordinances allowing hydraulic
fracturing activities within their jurisdictions but regulating the
time, place and manner of those activities.
In addition, 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 aimed at
significantly limiting or preventing oil and natural gas
development. In response to such initiatives, the Governor of
Colorado created a Task Force on State and Local Regulation of Oil
and Gas Operations (“
Task
Force
”)
in September 2014 to make recommendations to the state legislature
regarding the responsible development of Colorado’s oil and
gas resources. In February 2015, the Task Force made nine
non-binding recommendations to the Governor that will require
legislative or regulatory action to be implemented. Among other
things, the recommendations received from the Task Force would
require pursuit of state rulemaking targeting increased
collaborative efforts between oil and natural gas operators and
local governments regarding large-scale oil and natural gas
facilities in defined “
urban
mitigation areas
”; operator registration
with local government designees and possible advance notice of
future oil and natural gas drilling and production facility
locations that would be integrated into the local comprehensive
planning process; development of enhanced local governmental
designee roles and functions to more effectively serve as liaisons
between industry, residents and local officials; increased staffing
levels at the state environmental and oil and natural gas agencies;
establishing an oil and natural gas information clearinghouse;
establishing a working group to investigate ways to reduce oil and
natural gas vehicular traffic on roadways; pursuit of state air
emissions rules including methane emissions capture rules; and
establishing a compliance assistance program to assist oil and
natural gas operators in complying with applicable rules. On
January 25, 2016, two of the recommendations, regarding the
collaboration of local governments, the COGCC and oil and natural
gas operators in the siting of large scale oil and natural gas
facilities in defined urban mitigation areas and long-term planning
for including future oil and natural gas development in local
comprehensive planning processes, were approved by the COGCC as new
rules. It is possible that the COGCC could elect to pursue one or
more of the remaining Task Force recommendations or the Colorado
state legislature could seek to adopt new policies or legislation
relating to oil and natural gas operations, including measures that
would give local governments in Colorado greater authority to limit
hydraulic fracturing and other oil and natural gas operations or
require greater distances between well sites and occupied
structures. In addition, it is possible that notwithstanding the
recommendations made by the Task Force, certain interest groups in
Colorado or even members of the Colorado state legislature may seek
to pursue ballot initiatives in the future and/or legislation that
may or may not coincide with the Task Force’s
recommendations, including, among other things, pursuit of
initiatives or legislation for changes in state law that would
allow local governments to ban hydraulic fracturing in
Colorado.
In
the event that ballot initiatives or local or state restrictions or
prohibitions are adopted in areas where we conduct operations,
including the Wattenberg Field 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.
Please read “
Part
I
” –
“
Item 1.
Business
” —
“
Regulation of the Oil
and Gas Industry
” and
“
Regulation of
Environmental and Occupational Safety and Health
Matters
” for a further
description of the laws and regulations that affect
us.
Ballot initiatives that would impose more stringent restrictions
for new oil and natural gas wells and related facilities may serve
to limit future oil and natural gas exploration and production
activities and could have a material adverse effect on our results
of operations, financial position and business.
Proponents of legal requirements imposing
more stringent restrictions on oil and gas exploration and
production activities in Colorado sought to include on the November
2016 ballot certain ballot initiatives that, if approved, would
have allowed revisions to the state constitution in a manner that
would have made such exploration and production activities in the
state more difficult in the future. Among the ballot initiatives
pursued in 2016 were ballot initiative Number 75
(“
Initiative
75
”), which sought to
authorize local governmental to control oil and natural gas
development in Colorado that could have resulted in the imposition
of more stringent requirements than currently implemented under
state law, and ballot initiative Number 78
(“
Initiative
78
”), which proposed a
much more stringent 2,500-foot mandatory setback between an oil and
natural gas development facility (including oil and natural gas
wells, production and processing equipment and pits) and specified
occupied structures and areas of special concern. Changes sought
under these ballot initiatives would have applied to new oil and
gas development facilities in Colorado. Proponents of these
measures collected signatures for placing Initiatives 75 and 78 on
the November 2016 ballot and submitted those signatures to the
Colorado Secretary of State by the August 8, 2016 deadline.
However, on August 29, 2016, the Secretary of State announced
that the proponents had failed to gather enough valid signatures to
put Initiatives 75 and 78 on the November 2016 ballot.
Notwithstanding the Colorado Secretary of State’s
announcement on August 29, 2016, in the event that ballot
initiatives or local or state restrictions or prohibitions are
adopted in the future in areas where we conduct operations 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.
Recently announced rules regulating methane emissions from oil and
natural gas operations could cause us to incur increased capital
expenditures and operating costs or delays in production of oil and
natural gas, which could have a material adverse effect on our
business.
On June 3, 2016, the EPA
published final rules establishing new air emission controls for
methane emissions from certain new, modified or reconstructed
equipment and processes in the oil and natural gas source category,
including production, processing, transmission and storage
activities, as part of an overall effort to reduce methane
emissions in the oil and natural gas source category by up to 45%
from 2012 levels by the year 2025. The EPA’s final rules
include New Source Performance Standards
(“
NSPS
”)
to limit methane emissions from equipment and processes across the
oil and natural gas source category. The rules also extend
limitations on volatile organic compound
(“
VOC
”)
emissions to sources that were unregulated under the previous NSPS
at Subpart OOOO. Affected methane and
VOC sources include hydraulically
fractured (or re-fractured) oil and natural gas well completions,
fugitive emissions from well sites and compressors, and pneumatic
pumps. The new methane and VOC standards require the implementation
of the best system of emission reduction to achieve these emission
reductions, mirroring the existing VOC standards under Subpart
OOOO. These rules could require a number of modifications to our
operations, including the installation of new equipment to control
methane and VOC emissions from certain hydraulic fracturing wells,
which could result in significant costs, including increased
capital expenditures and operating costs, and could adversely
impact or delay oil and natural gas production activities, which
could have a material adverse effect on our
business.
Restrictions on drilling activities intended to protect certain
species of wildlife may adversely affect our ability to conduct
drilling activities areas where we operate.
Oil
and natural gas operations in our operating areas may be adversely
affected by seasonal or permanent restrictions on drilling
activities designed to protect various wildlife. Seasonal
restrictions may limit our ability to operate in protected areas
and can intensify competition for drilling rigs, oilfield
equipment, services, supplies and qualified personnel, which may
lead to periodic shortages when drilling is allowed. These
constraints and the resulting shortages or high costs could delay
our operations or materially increase our operating and capital
costs. Permanent restrictions imposed to protect endangered species
could prohibit drilling in certain areas or require the
implementation of expensive mitigation measures. The designation of
previously unprotected species in areas where we operate as
threatened or endangered could cause us to incur increased costs
arising from species protection measures or could result in
limitations on our exploration and production activities that could
have a material adverse impact on our ability to develop and
produce our reserves.
As a result of future legislation, certain U.S. federal income tax
deductions currently available with respect to oil and gas
exploration and development may be eliminated and our production
may be subject to the imposition of new U.S. federal
taxes.
The
U.S. President’s Fiscal Year 2017 Budget Proposal and
legislation introduced in a prior session of Congress includes
proposals that, if enacted into law, would eliminate certain key
U.S. federal income tax provisions currently available to oil and
gas exploration and production companies or potentially make our
operations subject to the imposition of new U.S. federal taxes.
These changes include, but are not limited to, (i) the repeal
of the percentage depletion allowance for oil and gas properties,
(ii) the elimination of current deductions for intangible
drilling and development costs, (iii) the elimination of the
deduction for certain domestic production activities, (iv) an
extension of the amortization period for certain geological and
geophysical expenditures and (v) imposition of a $10.25 per
barrel fee on oil, to be paid by oil companies (but the budget does
not describe where and how such a fee would be collected). It is
unclear whether these or similar changes will be enacted and, if
enacted, how soon any such changes could become effective. The
passage of any legislation as a result of these proposals or any
similar changes in U.S. federal income tax laws could eliminate or
postpone certain tax deductions that are currently available with
respect to oil and gas exploration and development, and any such
change, as well as any changes to or the imposition of new U.S.
federal, state or local taxes (including the imposition of, or
increase in production, severance or similar taxes), could increase
the cost of exploration and development of oil and gas resources,
which would negatively affect our financial condition and results
of operations.
Part of our strategy involves drilling in existing or emerging
shale 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 D-J Basin in Weld County, 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.
Our acreage must be drilled before lease expiration, generally
within three to five years, 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 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. 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 shale
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 shale 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 Colorado, could
materially and adversely affect our operations and the timeliness
of executing our development plans within our budget.
The derivatives legislation adopted by Congress, and implementation
of that legislation by federal agencies, could have an adverse
impact on our ability to hedge risks associated with our
business.
On July
21, 2010, President Obama signed into law the Dodd-Frank Wall
Street Reform and Consumer Protection Act, the Dodd-Frank Act,
which, among other things, sets forth the new framework for
regulating certain derivative products including the commodity
hedges of the type that we may elect to use, but many aspects of
this law are subject to further rulemaking and will take effect
over several years. As a result, it is difficult to anticipate the
overall impact of the Dodd-Frank Act on our ability or willingness
to enter into and maintain such commodity hedges and the terms of
such hedges. There is a possibility that the Dodd-Frank Act could
have a substantial and adverse impact on our ability to enter into
and maintain these commodity hedges. In particular, the Dodd-Frank
Act could result in the implementation of position limits and
additional regulatory requirements on derivative arrangements,
which could include new margin, reporting and clearing
requirements. In addition, this legislation could have a
substantial impact on our counterparties and may increase the cost
of our derivative arrangements in the future.
If
these types of commodity hedges become unavailable or uneconomic,
our commodity price risk could increase, which would increase the
volatility of revenues and may decrease the amount of credit
available to us. Any limitations or changes in our use of
derivative arrangements could also materially affect our future
ability to conduct acquisitions.
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 deep shale oil and natural gas
production during both the drilling and hydraulic fracturing, or
fracking processes. Our operations could be adversely impacted if
we are unable to locate sufficient amounts of water, or dispose of
or recycle water used in our exploration and production operations.
Currently, the quantity of water required in certain completion
operations, such as hydraulic fracturing, and changing regulations
governing usage may lead to water constraints and supply concerns
(particularly in some parts of the country). Colorado and other
western states have recently experienced a drought. As a result,
future availability of water from certain sources used in the past
may be limited. Moreover, the imposition of new environmental
initiatives and conditions could include restrictions on our
ability to conduct certain operations such as hydraulic fracturing
or disposal of waste, including, but not limited to, produced
water, drilling fluids and other wastes associated with the
exploration, development or production of oil and natural gas. The
CWA and analogous state laws impose restrictions and strict
controls regarding the discharge of pollutants, including produced
waters and other oil and natural gas waste, into navigable waters
or other regulated federal and state waters. Permits or other
approvals must be obtained to discharge pollutants to regulated
waters and to conduct construction activities in such waters and
wetlands. Uncertainty regarding regulatory jurisdiction over
wetlands and other regulated waters has, and will continue to,
complicate and increase the cost of obtaining such permits or other
approvals. The CWA and analogous state laws provide for civil,
criminal and administrative penalties for any unauthorized
discharges of pollutants and unauthorized discharges of reportable
quantities of oil and other hazardous substances. Many state
discharge regulations, and the Federal National Pollutant Discharge
Elimination System General permits issued by the EPA, prohibit the
discharge of produced water and sand, drilling fluids, drill
cuttings and certain other substances related to the oil and
natural gas industry into coastal waters. While generally exempt
under federal programs, many state agencies have also adopted
regulations requiring certain oil and natural gas exploration and
production facilities to obtain permits for storm water discharges.
In October 2011, the EPA announced its intention to develop federal
pretreatment standards for wastewater discharges associated with
hydraulic fracturing activities. If adopted, the pretreatment rules
will require coalbed methane and shale gas operations to pretreat
wastewater before transferring it to treatment facilities Some
states have banned the treatment of fracturing wastewater at
publicly owned treatment facilities. There has been recent
nationwide concern over earthquakes associated with Class II
underground injection control wells, a predominant storage method
for crude oil and gas wastewater. It is likely that new rules and
regulations will be developed to address these concerns, possibly
eliminating access to Class II wells in certain locations, and
increasing the cost of disposal in others. Finally, the EPA study
noted above has focused and will continue to focus on various
stages of water use in hydraulic fracturing operations. It is
possible that, following the conclusion of the EPA’s study,
the agency will move to more strictly regulate the use of water in
hydraulic fracturing operations. While we cannot predict the impact
that these changes may have on our business at this time, they may
be material to our business, financial condition, and operations.
Compliance with environmental regulations and permit requirements
governing the withdrawal, storage and use of surface water or
groundwater necessary for hydraulic fracturing of wells or the
disposal or recycling of water will increase our operating costs
and may cause delays, interruptions or termination of our
operations, the extent of which cannot be predicted. In addition,
our inability to meet our water supply needs to conduct our
completion operations may impact our business, and any such future
laws and regulations could negatively affect our financial
condition, results of operations and cash flows.
Restrictions on drilling activities intended to protect certain
species of wildlife may adversely affect our ability to conduct
drilling activities in some of the areas where we
operate.
Oil and
natural gas operations in our operating areas can be adversely
affected by seasonal or permanent restrictions on drilling
activities designed to protect various wildlife. Seasonal
restrictions may limit our ability to operate in protected areas
and can intensify competition for drilling rigs, oilfield
equipment, services, supplies and qualified personnel, which may
lead to periodic shortages when drilling is allowed. These
constraints and the resulting shortages or high costs could delay
our operations and materially increase our operating and capital
costs. Permanent restrictions imposed to protect endangered species
could prohibit drilling in certain areas or require the
implementation of expensive mitigation measures.
As a
result of a settlement approved by the U.S. District Court for the
District of Columbia on September 9, 2011, the U.S. Fish and
Wildlife Service is required to consider listing more than 250
species as endangered under the Endangered Species Act. The law
prohibits the harming of endangered or threatened species, provides
for habitat protection, and imposes stringent penalties for
noncompliance. The final designation of previously unprotected
species in areas where we operate as threatened or endangered could
cause us to incur increased costs arising from species protection
measures or could result in limitations, delays, or prohibitions on
our exploration and production activities that could have an
adverse impact on our ability to develop and produce our
reserves.
Potential conflicts of interest could arise for certain members of
our management team that hold management positions with other
entities.
Michael
L. Peterson, our President and Chief Executive Officer, and Clark
R. Moore, our Executive Vice President, General Counsel and
Secretary, hold various other management positions with
privately-held companies not involved in the oil and gas industry.
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.
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.
Currently pending or 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.
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
MKT 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 MKT,
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
sustain
ed.
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
.
The issuance of common stock upon conversion of our convertible
notes will cause immediate and substantial dilution.
The
issuance of common stock upon conversion of our outstanding
convertible bridge notes in the aggregate amount of $475,000 in
principal and $48,000 of payment in kind, along with interest on
the principal amount of such notes, which allow the holders thereof
the right to convert such amounts from time to time, subject to
certain limitations, into common stock of the Company, as is
determined by dividing the amount converted by a conversion price
by the greater of (i) 80% of the average of the closing price per
share of our publicly traded common stock for the five (5) trading
days immediately preceding the date of the conversion notice
provide by the holder; and (ii) $0.50 per share, will result in
immediate and substantial dilution to the interests of other
stockholders.
In
addition, that certain Amended and Restated Secured Subordinated
Promissory Note, in the principal amount $4.925 million, dated
February 19, 2015, issued by the Company to MIE Jurassic Energy
Corporation (“
MIEJ
”), provides MIEJ the
right, beginning March 8, 2017, to convert the outstanding balance
plus accrued and unpaid interest thereon, into common stock of the
Company at a price equal to 80% of the average closing price per
share of common stock over the then previous 60 days from the date
MIEJ exercises its conversion right, subject to a floor price of
$0.30 per share of common stock. Any such issuances of common stock
will result in immediate and substantial dilution to the interests
of other stockholders.
The continuously adjustable conversion price feature of our
convertible notes could require us to issue a substantially greater
number of shares, which may adversely affect the market price of
our common stock and cause dilution to our existing
stockholders.
Our
existing stockholders may experience substantial dilution of their
investment upon conversion of the convertible bridge notes and New
MIEJ Note. The convertible bridge notes are convertible into shares
of common stock as described in the risk factor above entitled
“
The issuance of
common stock upon conversion of our convertible notes will cause
immediate and substantial dilution
”, at a discount to
the trading price of our common stock, subject to a floor of $0.50
per share, and the New MIEJ Note is convertible into shares of
common stock as described in the same risk factor after March 8,
2017 at a discount to the trading price of our common stock,
subject to a floor of $0.30 per share and other restrictions. As a
result, the number of shares issuable could prove to be
significantly greater in the event of a decrease in the trading
price of our common stock, which decrease could cause substantial
dilution to our existing stockholders. As sequential conversions
and sales take place, the price of our common stock may decline,
and if so, the holders of the convertible bridge notes and New MIEJ
Note would be entitled to receive an increasing number of shares,
which could then be sold, triggering further price declines and
conversions for even larger numbers of shares, which would cause
additional dilution to our existing stockholders and could cause
the value of our common stock to decline.
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 MKT, 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
MKT;
|
|
|
|
|
●
|
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 (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 $17.5 million in securities
have been sold by us under the prior Form S-3 which the December
2016 Form S-3 replaced, leaving approximately $82.5 million in
securities which will be eligible for sale in the public markets
from time to time, when sold and issued by us, subject to the
requirements of Form S-3, which limits us, until such time, if
ever, as our public float exceeds $75 million, from selling
securities in a public primary offering under Form S-3 with a value
exceeding more than one-third of the aggregate market value of the
common stock held by non-affiliates of the Company every twelve
months. 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, provided that to date, we have not
sold any securities under the At Market Issuance Sales Agreement or
the prospectus associated therewith. 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, 2016, there were outstanding stock options to purchase
approximately 5,187,223 shares of our common stock and outstanding
warrants to purchase approximately 12,566,079 shares of 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 16,349,138 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.
Seven of our directors and executive officers own
approximately 17.5% of our common stock, and three of our
major shareholders own approximately 17.6% of our common stock,
which may give them influence over important corporate matters in
which their interests are different from your
interests.
Seven
of our directors and executive officers beneficially own
approximately 17.5% of our outstanding shares of common stock,
and our largest three non-director or officer shareholders own
approximately 17.6% of our outstanding voting shares of common
stock and Series A Preferred Stock (excluding exercise of warrants
and options and other convertible securities held thereby) based on
a total of 54,997,742 shares of common stock and Series A Preferred
Stock outstanding as of March 22, 2017. These directors, executive
officers and major shareholders will be positioned to influence or
control to some degree the outcome of 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.
These directors, executive officers and major shareholders, subject
to any fiduciary duties owed to the shareholders generally, may
have interests different than the rest of our shareholders. Their
influence or control of our company 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. In addition, due to the ownership interest of these
directors and officers in our common stock, they may be able to
remain entrenched in their positions.
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 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. To date
our board of directors has authorized Series A Convertible
Preferred Stock, the rights and preferences associated therewith,
and risks related to such preferred stock, is described in greater
detail under “
Risks
Related to Our Series A Convertible Preferred Stock
”.
We have also agreed to issue Series B Preferred stock in the event
the GOM Merger closes as described in greater detail above under
“
Item 1.
Business
” – “
Business Overview
”
— “
Recent
Developments
” – “
GOM Holdings, LLC Merger
Agreement
”.
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 filing 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
MKT (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),
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 MKT
and our failure to satisfy these criteria may result in delisting
of our common stock.
Our common stock is currently listed on the NYSE
MKT. 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 MKT 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 MKT 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 MKT’s listing
requirements; if an issuer’s common stock sells at what the
NYSE MKT 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 MKT (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 MKT, in its opinion,
inadvisable.
If
the NYSE MKT 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.
We are required to complete a reverse stock split of our issued and
outstanding common stock prior to May 3, 2017, in order to continue
to trade our common stock on the NYSE MKT.
On November 3, 2016, we were notified by the NYSE
MKT that our common stock had been selling for a low price per
share (i.e., under $0.20 per share), for a substantial period of
time, and that our continued listing on the NYSE MKT was predicated
on us completing a reverse stock split of our issued and
outstanding common stock by May 3, 2017. Pursuant to the rules of
the NYSE MKT, if an issuer’s common stock sells at what the
NYSE MKT 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 after notification
by the NYSE MKT (provided that issuers can also be delisted if any
shares of the issuer trade below $0.06 per share), the NYSE MKT may
delist the securities of such issuer. The NYSE MKT also advised us
that we were ‘below compliance’ with applicable NYSE
MKT listing standards due to the low trading price of our common
stock and that a “.BC” indicator would be affixed to
our trading symbol until such time as we regained compliance with
the NYSE MKT’s listing standards. While the Company obtained
stockholder approval for a reverse stock split at our 2016 annual
meeting of stockholders on December 28, 2016, in the event we fail
to effect a reverse stock split by May 3, 2017, the NYSE MKT may
delist our common stock. If the NYSE MKT 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. In addition, delisting from the NYSE MKT might
negatively impact our reputation and, as a consequence, our
business. Finally, if we were delisted from the NYSE MKT and are
not able to list our common stock on another national exchange we
will no longer be eligible to use Form S-3 registration statements,
which may delay our ability to raise funds in the future, may limit
the type of offerings of common stock we could undertake, and could
increase the expenses of any offering.
We are currently below compliance with certain continued listing
requirements of the NYSE MKT. If we are delisted from the NYSE MKT,
your ability to sell your shares of our common stock may be limited
by the penny stock restrictions, which could further limit the
marketability of your shares.
On December 27, 2016,
we received notice from the NYSE MKT LLC (the
“
Exchange
”)
that we were not in compliance with Section 1003(a)(iii) of the
NYSE MKT Company Guide (“
Company
Guide
”) since we
reported stockholders’ equity of less than $6,000,000 at
September 30, 2016 and had incurred net losses in our five most
recent fiscal years ended December 31, 2015. Receipt of
the letter does not have any immediate effect upon the listing of
our common stock, provided that in order to maintain our listing on
the Exchange, the Exchange requested that we submit a plan of
compliance (the “
Plan
”)
by January 27, 2017 addressing how we intend to regain compliance
with Section 1003(a)(iii) of the Company Guide by
June 27, 2018
. We
submitted our Plan to the Exchange by the requested deadline, and
such plan was accepted by the Exchange on February 13,
2017. In connection with such acceptance, we have been
provided until
June 27,
2018
to regain compliance
with Section 1003(a)(iii) of the Company Guide, which requires our
stockholders’ equity to be at least $6 million. If
we do not make progress consistent with the Plan during the Plan
period or regain compliance with the applicable continued listing
standards of the Exchange by
June 27, 2018
, the Exchange will
initiate delisting proceedings as appropriate. We are
confident that we will be able to regain compliance with applicable
listing standards by
June 27,
2018
, provided that if we
are unable to regain compliance, our common stock will be delisted
from the Exchange.
If our common stock is delisted, it could come
within the definition of “
penny
stock
” as defined in the
Exchange Act and could be covered by Rule 15g-9 of the
Exchange Act. That Rule imposes additional sales practice
requirements on broker-dealers who sell securities to persons other
than established customers and accredited investors. For
transactions covered by Rule 15g-9, the broker-dealer must
make a special suitability determination for the purchaser and
receive the purchaser’s written agreement to the transaction
prior to the sale. Consequently, Rule 15g-9, if it were to
become applicable, would affect the ability or willingness of
broker-dealers to sell our securities, and accordingly would affect
the ability of stockholders to sell their securities in the public
market. These additional procedures could also limit our ability to
raise additional capital in the future.
Due to the fact that our common stock is listed on the NYSE MKT, 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 MKT, 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.
Risks Related to Our Series A Convertible Preferred
Stock
The issuance of common stock upon conversion of the Series A
Convertible Preferred stock will cause immediate and substantial
dilution to existing shareholders.
Our 66,625 outstanding shares of Series A Convertible Preferred
stock are convertible into common stock on a 1,000:1 basis (subject
to certain limitations on conversions described in the Series A
Preferred designation), provided that no conversion of the Series A
Convertible Preferred stock is allowed in the event the holder
thereof would beneficially own more than 9.9% of our common stock
or voting stock.
The issuance of common stock upon conversion of the Series A
Convertible Preferred stock will result in immediate and
substantial dilution to the interests of other stockholders since
the holder of the Series A Convertible Preferred stock may
ultimately receive and sell the full amount of shares issuable in
connection with the conversion of such Series A Convertible
Preferred stock. Although the Series A Convertible Preferred stock
may not be converted if such conversion would cause the holder
thereof to own more than 9.9% of our outstanding common stock, this
restriction does not prevent the holder from converting some of its
holdings, selling those shares, and then converting the rest of its
holdings, while still staying below the 9.9% limit. In this way,
the holder of the Series A Convertible Preferred stock could sell
more than this limit while never actually holding more shares than
this limit allows. If the holder of the Series A Convertible
Preferred stock chooses to do this, it will cause substantial
dilution to the then holders of our common stock.
The issuance and sale of common stock upon conversion of the Series
A Convertible Preferred stock may depress the market price of our
common stock.
All of
our Series A Convertible Preferred Stock is held by GGE, the parent
company of which is controlled by a court-appointed liquidator that
is currently taking steps to liquidate GGE’s parent
company’s assets. If GGE were to distribute our Series A
Convertible Preferred Stock in connection with such liquidation,
and/or these shares are converted in sequential conversions and
sales of such converted shares take place, the price of our common
stock may decline.
In addition, the common stock issuable upon conversion of the
Series A Convertible Preferred stock may represent overhang that
may also adversely affect the market price of our common stock.
Overhang occurs when there is a greater supply of a company’s
stock in the market than there is demand for that stock. When this
happens the price of the company’s stock will decrease, and
any additional shares which shareholders attempt to sell in the
market will only further decrease the share price. If the share
volume of our common stock cannot absorb converted shares sold by
the Series A Convertible Preferred stock holder, then the value of
our common stock will likely decrease.
The holder of our Series A Convertible Preferred stock has the
right to appoint two members to our board of
directors.
In
February 2015, by resolution of the board of directors, we formally
increased the size of our board of directors from three (3) members
to five (5) members. Pursuant to the designation of the Series A
Convertible Preferred stock, we provided the holder thereof the
right, upon notice to us, to appoint designees to fill the two (2)
vacant seats, one of which must be an independent director as
defined by applicable rules. In July 2015, David Z. Steinberg
joined our board of directors as one of the holder’s
independent director designees. The holder’s second designee
has not been appointed to date. Mr. Steinberg was formerly employed
by PM LLC, the former advisor and former affiliate of PPVAF, GOM,
RJC and GGE, from May 2009 to November 2016. The board appointment
rights continue until the holder no longer holds any of the first
tranche of shares issued to the holder. The board appointment
rights mean that assuming such rights are exercised; the common
stock shareholders may only have the right to appoint 60% (three of
five members) of our board of directors.