Item 1 – Business
Overview
U.S. Energy Corp. (“U.S. Energy”,
the “Company”, “we” or “us”), is a Wyoming corporation organized in 1966. We are an independent
energy company focused on the acquisition and development of oil and gas producing properties in the continental United States.
Our business activities are currently focused in South Texas and the Williston Basin in North Dakota. However, we do not intend
to limit our focus to these geographic areas. We continue to focus on increasing production, reserves, revenues and cash flow from
operations while managing our level of debt.
We have historically explored for and produced
oil and gas through a non-operator business model. As a non-operator, we rely on our operating partners to propose, permit, drill,
complete and produce oil and gas wells. Before a well is drilled, the operator provides all oil and gas interest owners in the
designated well the opportunity to participate in the drilling and completion costs and revenues of the well on a pro-rata basis.
Our operating partners also produce, transport, market and account for all oil and gas production. We are currently developing
our capability to operate properties.
We believe that additional value can be
generated if we have the ability to operate oil and gas properties because operatorship will allow us to control drilling and production
timing, capital costs and future planning of operations. We plan to look for opportunities to operate our own wells in the near
future through acquisition of new oil and gas properties and/or by consolidating ownership in and around the areas in which we
currently participate. We believe the current price climate will make opportunities available for us to acquire and/or develop
operated properties, and our objective is to eventually operate the properties which comprise the majority of our production.
Office Location and Website
Our principal executive office is located
at 4643 S. Ulster Street, Suite 970, Denver, Colorado 80237, telephone (303) 993-3200.
Our website is www.usnrg.com. We make available
on this website, through a direct link to the Securities and Exchange Commission’s (the “SEC”) website at http://www.sec.gov,
free of charge, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, proxy statements
and Forms 3, 4 and 5 relating to stock ownership of our directors, executive officers and significant shareholders. You may also
find information related to our corporate governance, board committees and code of ethics on our website. Our website and the information
contained on or connected to our website are not incorporated by reference herein and should not be considered part of this document.
In addition, you may read and copy any materials we file with the SEC at the SEC's Public Reference Room, which is located at 100
F Street, NE, Room 1580, Washington, D.C. 20549. Information regarding the Public Reference Room may be obtained by calling the
SEC at (800) 732-0330.
Oil and Gas Operations
We currently participate in oil and gas
projects as a non-operating working interest owner through exploration and development agreements with various oil and gas exploration
and production companies. Our working interest varies by project and may change over time based on the terms of our leases and
operating agreements. These projects may result in numerous wells being drilled over the next three to five years depending on,
among other things, commodity prices and the availability of capital resources required to fund the expenditures. We are also actively
pursuing potential acquisitions of exploration, development and production-stage oil and gas properties or companies. Key attributes
of our oil and gas properties include the following:
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Estimated proved reserves of 887,142 BOE (74% oil and 26% natural gas) as of December 31, 2016, with a standardized measure value of $6.7 million.
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As of March 27, 2017, our oil and gas leases covered 95,839 gross and 7,958 net acres.
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151 gross (20.94 net) producing wells as of December 31, 2016 and as of March 27, 2017.
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581 BOE per day average net production for 2016.
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PV-10 (defined in “Glossary of Oil
and Gas Terms”) is a non-GAAP measure that is widely used in the oil and gas industry and is considered by institutional
investors and professional analysts when comparing companies. However, PV-10 data is not an alternative to the standardized measure
of discounted future net cash flows, which is calculated under GAAP and includes the effects of income taxes. The following table
reconciles the standardized measure of discounted future net cash flows to PV-10 as of December 31, 2016, 2015 and 2014:
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2016
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2015
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2014
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Standardized measure of discounted net cash flows
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$
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6,747
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$
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17,768
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$
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81,889
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Plus discounted impact of future income tax expense
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-
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-
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3,307
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PV-10
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$
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6,747
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$
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17,768
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$
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85,196
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Additional information about our standardized
measure and the changes during each of the last three years is included in Note 17 to our consolidated financial statements included
in Item 8 of this report on Form 10-K.
Activities with Operating Partners
The Company owns working interests in a
geographically and geologically diverse portfolio of oil-weighted prospects in varying stages of exploration and development. Prospect
stages range from prospect origination, including geologic and geophysical mapping, to leasing, exploratory drilling and development.
The Company participates in the prospect stages either for its own account or with prospective partners to enlarge its oil and
gas lease ownership base.
Each of the operators of our principal
prospects has a substantial technical staff. We believe that these arrangements currently allow us to deliver value to our shareholders
without having to build the full staff of geologists, engineers and land personnel required to work on diverse projects involving
horizontal drilling in North Dakota and South Texas and conventional exploration in our Gulf Coast prospects. However, consistent
with industry practice with smaller independent oil and gas companies, we also utilize specialized consultants with local expertise
as needed. We anticipate that as we establish an operational center in an area, we will hire appropriate resources to supply critical
aspects of the operations, such as drilling, completions and production.
Presented below is a description of key
oil and gas projects with our operating partners:
Williston Basin, North Dakota (Bakken and Three Forks Formations)
Statoil ASA.
On August 24,
2009, we entered into a Drilling Participation Agreement (the “DPA”) with a wholly-owned subsidiary of Brigham Exploration
Company (“Brigham”) to jointly explore for oil and gas in up to 19,200 gross acres in a portion of Brigham’s
Rough Rider prospect in Williams and McKenzie Counties, North Dakota. Brigham was subsequently acquired by Statoil ASA. As part
of the program we have participated in 26 wells and have proven up additional drilling locations depending on the successful development
of the Three Forks Formation. These properties currently operated by Statoil comprise approximately 22% of the PV-10 related to
our oil and gas reserves. Currently development has stopped due to the commodity price drop and high costs. We expect to develop
the remaining acreage in the future when economics allow an acceptable return on capital.
The leases in the units are a combination
of fee and state leases and all are held by production. In some areas, the rights may be depth limited to the Bakken and the upper
part of the Three Fork formations under the terms of the leases obtained by Brigham from third parties, while other leases may
have rights to all depths. Working interests earned vary according to Brigham’s interest.
Zavanna, LLC.
In December
2010, we signed two agreements with Zavanna, LLC (“Zavanna”) and other parties whereby we acquired 35% of Zavanna’s
working interests in oil and gas leases covering approximately 6,200 net acres in McKenzie County, North Dakota. The total net
acres subject to the agreement has increased to 6,500 as a result of subsequent acquisitions from third parties. The acquired acreage
is in two prospects – the Yellowstone Prospect and the SE HR Prospect. We expect this program will ultimately result in 27
gross 1,280-acre spacing units with the potential for 108 gross Bakken and 108 gross Three Forks wells, based on an assumed four
wells per formation in each spacing unit.
Effective December 2011, we sold an undivided
75% interest of our undeveloped acreage in the SE HR Prospect and the Yellowstone Prospect to GeoResources, Inc. and Yuma Exploration
and Production Company, Inc. Under the terms of the agreement, we retained the remaining 25% interest in the undeveloped acreage
and our original working interest in 10 completed wells in the SE HR and Yellowstone prospects. Our working interest in the remaining
locations will be approximately 8.75% and net revenue interests in new wells after the sale are expected to be in the range of
6.7% to 7.0%, proportionately reduced depending on Zavanna’s actual working interest percentages. These properties operated
by Zavanna currently comprise approximately 28% of the PV-10 related to our oil and gas reserves.
Texas and Louisiana (Gulf Coast)
Contango Oil and Gas Company (Eagle
Ford Shale)
.
In February 2011, we entered into a participation agreement with Crimson Exploration Inc. (“Crimson”)
to acquire a 30% working interest in an oil prospect and associated leases located in Zavala County, Texas (the “Leona River
prospect”). Crimson was subsequently acquired by Contango Oil and Gas Company (“Contango”) in 2013. Under the
terms of the agreement, we earned a 30% working interest (22.5% net revenue interest) in approximately 4,675 gross contiguous acres
(1,402 net mineral acres) through a combination of a cash payment and commitment well carry. All future drilling and leasing will
be on a heads up basis, meaning working interest participants are responsible for their own pro-rata share of costs. The prospect
is an Eagle Ford shale oil window target in Zavala County, Texas. Two wells were drilled by Crimson to a total depth of approximately
12,500 feet (approximately 6,000 feet vertical and 6,500 feet horizontal) at the Leona River prospect. These producing wells hold
the remaining development acreage.
In June 2011, we entered into a second
participation agreement with Crimson to acquire an interest in an Eagle Ford oil prospect and associated leases located in Zavala
and Dimmit Counties, Texas (the “Booth Tortuga prospect”). Under the terms of this second agreement with Crimson, we
have acquired 30% of Crimson’s working interest (approximately 22.5% net revenue interest) in approximately 7,186 gross acres
(2,156 net).
Contango is currently the operator of the
Leona River and Booth Tortuga prospects. All of the leases are currently held by production and comprise approximately 9% of the
PV-10 related to our oil and gas reserves. Currently, our total acreage in the Leona River prospect and the Booth Tortuga prospect
is approximately 11,861 gross acres (3,558 net). Based upon expected 120-acre spacing units, there is the potential for up to 98
gross and 30 net Eagle Ford drilling locations.
PetroQuest Energy, Inc.
We
have an interest in three natural gas and oil producing wells with PetroQuest Energy, Inc. (“PetroQuest”) in Coastal
Louisiana, with working interests of 11.9% (8.3% net revenue interest), 50.0% (36.0% net revenue interest) and 17.0% (12.75% net
revenue interest). Petro-Quest operates the wells. These properties operated by PetroQuest currently comprise approximately 17%
of the PV-10 related to our oil and gas reserves.
Environmental Laws and Regulations
For additional information regarding applicable
environmental laws and regulations, see
Oil and gas operations are subject to environmental and other regulations that can materially
adversely affect the timing and cost of operations
;
Hazardous Substances and Waste
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Air Emissions; Discharges into
Waters
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Health and Safety
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Endangered Species
; and
Global Warming and Climate Change
in Item 1A Risk Factors
in this Form 10-K.
Environmental Matters
Our operations and properties are subject
to extensive and changing federal, state and local laws and regulations relating to environmental protection, including the generation,
storage, handling, emission, transportation and discharge of materials into the environment, and relating to safety and health.
The recent trend in environmental legislation and regulation generally is toward stricter standards, and this trend will likely
continue. These laws and regulations may:
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Require the acquisition of a permit or other authorization before construction or drilling commences and for certain other activities;
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Limit or prohibit construction, drilling and other activities on certain lands lying within wilderness and other protected areas; and
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Impose substantial liabilities for pollution resulting from its operations.
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The permits required for our operations
may be subject to revocation, modification and renewal by issuing authorities. Governmental authorities have the power to
enforce their regulations, and violations are subject to fines or injunctions, or both. In the opinion of management, we
are in substantial compliance with current applicable environmental laws and regulations, and have no material commitments for
capital expenditures to comply with existing environmental requirements. Nevertheless, changes in existing environmental
laws and regulations or in interpretations thereof could have a significant impact on our company, as well as the oil and natural
gas industry in general.
The Comprehensive Environmental, Response,
Compensation, and Liability Act (“CERCLA”) and comparable state statutes impose strict, joint and several liability
on owners and operators of sites and on persons who disposed of or arranged for the disposal of “hazardous substances”
found at such sites. It is not uncommon for the 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. The Federal Resource
Conservation and Recovery Act (“RCRA”) and comparable state statutes govern the disposal of “solid waste”
and “hazardous waste” and authorize the imposition of substantial fines and penalties for noncompliance. Although
CERCLA currently excludes petroleum from its definition of “hazardous substance,” state laws affecting our operations
may impose clean-up liability relating to petroleum and petroleum related products. In addition, although RCRA classifies
certain oil field wastes as “non-hazardous,” such exploration and production wastes could be reclassified as hazardous
wastes thereby making such wastes subject to more stringent handling and disposal requirements. Recent regulation and litigation
that has been brought against others in the industry under RCRA concern liability for earthquakes that were allegedly caused by
injection of oil field wastes.
The Endangered Species Act (“ESA”)
seeks to ensure that activities do not jeopardize endangered or threatened animal, fish and plant species, nor destroy or modify
the critical habitat of such species. Under ESA, exploration and production operations, as well as actions by federal agencies,
may not significantly impair or jeopardize the species or its habitat. ESA provides for criminal penalties for willful violations
of ESA. Other statutes that provide protection to animal and plant species and that may apply to our operations include,
but are not necessarily limited to, the Fish and Wildlife Coordination Act, the Fishery Conservation and Management Act, the Migratory
Bird Treaty Act and the National Historic Preservation Act. Although we believe that our operations are in substantial compliance
with such statutes, any change in these statutes or any reclassification of a species as endangered could subject our company (directly
or indirectly through our operating partners) to significant expenses to modify our operations or could force discontinuation of
certain operations altogether.
On April 17, 2012, the U.S. Environmental
Protection Agency (the “EPA”) finalized rules proposed on July 28, 2011 that establish new air emission controls under
the Clean Air Act (“CCA”) for oil and natural gas production and natural gas processing operations. Specifically, the
EPA’s rule package includes New Source Performance Standards (“NSPS”) for the oil and natural gas source category
to address emissions of sulfur dioxide and volatile organic compounds (“VOCs”) and a separate set of emission standards
to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. On August
5, 2013, the EPA issued final updates to its 2012 VOC performance standards for storage tanks. The rules establish specific new
requirements regarding emissions from compressors, dehydrators, storage tanks and other production equipment. In addition, the
rules revise leak detection requirements for natural gas processing plants. These rules have required a number of modifications
to the operations of our third-party operating partners, including the installation of new equipment to control emissions from
compressors.
We are subject to the federal authority
of the U.S. Environmental Protection Agency (the “EPA”) and its promulgated rules specifically as they pertain to the
Clean Air Act (“CCA”). Applicable to our business and operations, the CCA regulates the emissions, discharges and controls
of oil and natural gas production and natural gas processing operations. The CCA includes New Source Performance Standards (“NSPS”)
for the oil and natural gas source category to address emissions of sulfur dioxide, methane and volatile organic compounds (“VOCs”)
from new and modified oil and gas production, processing and transmission sources as well as a separate set of emission standards
to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. Further,
the CCA regulates the emissions from compressors, dehydrators, storage tanks and other production equipment as well as leak detection
for natural gas processing plants. Although we cannot predict the cost to comply with current and future rules and regulations
at this point, compliance with applicable rules could result in significant costs, including increased capital expenditures and
operating costs, and could adversely impact our business.
The current and future rules, regulations
and proposals requiring the installation of more sophisticated pollution control equipment could have a material adverse impact
on our business, results of operations and financial condition.
The federal Water Pollution Control Act
of 1972, or the Clean Water Act (the “CWA”), imposes restrictions and controls on the discharge of produced waters
and other pollutants into navigable waters. Permits must be obtained to discharge pollutants into state and federal waters
and to conduct construction activities in waters and wetlands. The CWA and certain state regulations prohibit the discharge
of produced water, sand, drilling fluids, drill cuttings, sediment and certain other substances related to the oil and gas industry
into certain coastal and offshore waters without an individual or general National Pollutant Discharge Elimination System discharge
permit. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits
for discharges of storm water runoff from certain types of facilities. Some states also maintain groundwater protection programs
that require permits for discharges or operations that may impact groundwater conditions. Costs may be associated with the treatment
of wastewater and/or developing and implementing storm water pollution prevention plans. The CWA and comparable state statutes
provide for civil, criminal and administrative penalties for unauthorized discharges of oil and other pollutants and impose liability
on parties responsible for those discharges, for the costs of cleaning up any environmental damage caused by the release and for
natural resource damages resulting from the release.
The underground injection of oil and natural
gas wastes are regulated by the Underground Injection Control program authorized by the Safe Drinking Water Act. The primary
objective of injection well operating requirements is to ensure the mechanical integrity of the injection apparatus and to prevent
migration of fluids from the injection zone into underground sources of drinking water. Substantially all of the oil and
natural gas production in which we have interests is developed from unconventional sources that require hydraulic fracturing as
part of the completion process. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into the
formation to stimulate oil and gas production. Legislation to amend the Safe Drinking Water Act to repeal the exemption for hydraulic
fracturing from the definition of “underground injection” and require federal permitting and regulatory control of
hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in
the fracturing process, were proposed in recent sessions of Congress. The U.S. Congress continues to consider legislation
to amend the Safe Drinking Water Act to address hydraulic fracturing operations.
Scrutiny of hydraulic fracturing activities
continues in other ways. The federal government is currently undertaking several studies of hydraulic fracturing’s
potential impacts. Several states, including North Dakota where many of our properties are located, have also proposed or
adopted legislative or regulatory restrictions on hydraulic fracturing. A number of municipalities in other states, including
Colorado and Texas, have enacted bans on hydraulic fracturing. New York State’s ban on hydraulic fracturing was recently
upheld by the Courts. In Colorado, the Colorado Supreme Court has ruled the municipal bans were preempted by state law. We
cannot predict whether any other legislation will ever be enacted and if so, what its provisions would be. If additional
levels of regulation and permits were required through the adoption of new laws and regulations at the federal or state level,
which could lead to delays, increased operating costs and process prohibitions that would materially adversely affect our revenue
and results of operations.
The National Environmental Policy Act (“NEPA”)
establishes a national environmental policy and goals for the protection, maintenance and enhancement of the environment and provides
a process for implementing these goals within federal agencies. A major federal agency action having the potential to significantly
impact the environment requires review under NEPA. Many of the activities of our third-party operating partners are covered
under categorical exclusions which results in a shorter NEPA review process. The Council on Environmental Quality has announced
an intention to reinvigorate NEPA reviews which may result in longer review processes that could lead to delays and increased costs
that could materially adversely affect our revenues and results of operations.
Climate Change
Significant studies and research have been
devoted to climate change, and climate change has developed into a major political issue in the United States and globally.
Certain research suggests that greenhouse gas emissions contribute to climate change and pose a threat to the environment.
Recent scientific research and political debate has focused in part on carbon dioxide and methane incidental to oil and natural
gas exploration and production.
In the United
States, legislative and regulatory initiatives are underway to limit greenhouse gas (“GHG”) emissions. The U.S. Congress
has considered legislation that would control GHG emissions through a “cap and trade” program and several states have
already implemented programs to reduce GHG emissions. The U.S. Supreme Court determined that GHG emissions fall within the
federal Clean Air Act, or the CAA, definition of an “air pollutant.” In response the EPA promulgated an endangerment
finding paving the way for regulation of GHG emissions under the CAA. In 2010, the EPA issued a final rule, known as the
“Tailoring Rule,” that makes certain large stationary sources and modification projects subject to permitting requirements
for greenhouse gas emissions under the Clean Air Act. A previous United States Supreme Court case
held
that the EPA’s “Tailoring Rule” was invalid, but held that if a source was subject to Prevention of Significant
Deterioration (“PSD”) or Title V based on emissions of conventional pollutants like sulfur dioxide, particulates, nitrogen
dioxide, carbon monoxide,
ozone or lead, then the EPA could also
require the source to control GHG emissions and the source would have to install Best Available Control Technology to do so.
As a result, a source no longer is required to meet PSD and Title V permitting requirements based solely on its GHG emissions,
but may still have to control GHG emissions if it is an otherwise regulated source.
Colorado became the first state in the
nation to adopt rules to control methane emissions from oil and gas facilities. On June 3, 2016, the EPA issued three final rules
that were intended to curb emissions of methane, VOCs and toxic air pollutants such as benzene from new, reconstructed and modified
oil and gas sources. These new regulations include leak detection and repair provisions, and may require controls to reduce methane
emissions from certain oil and gas facilities. To the extent our third party operating partners are required to further control
methane emissions, such controls could impact our business.
Certain EPA rules require the reporting
of GHGs from specified large GHG emission sources in the United States and have expanded existing GHG emissions reporting to include
onshore and offshore oil and natural gas systems. Our third-party operating partners are required to report their greenhouse
gas emissions under these rules. Because regulation of GHG emissions is relatively new, further regulatory, legislative and
judicial developments are likely to occur. Such developments may affect how these GHG initiatives will impact us. Moreover,
there is some litigation risk for tort claims against sources of GHG emissions alleging property damage under state common law.
Although we cannot predict the cost to comply with current and future rules and regulations at this point, compliance with applicable
rules could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact
our business.
Legislation or regulations that may be
adopted to address climate change could also affect the markets for our products by making our products more or less desirable
than competing sources of energy. To the extent that our products are competing with higher greenhouse gas emitting energy
sources, our products would become more desirable in the market with more stringent limitations on greenhouse gas emissions.
To the extent that our products are competing with lower GHG emitting energy sources such as solar and wind, our products would
become less desirable in the market with more stringent limitations on greenhouse gas emissions. We cannot predict with any
certainty at this time how these possibilities may affect our operations.
The majority of scientific studies on climate
change suggest that stronger storms may occur in the future in the areas where we operate, although the scientific studies are
not unanimous. Although operators may take steps to mitigate physical risks from storms, no assurance can be given that future
storms will not have a material adverse effect on our business.
Research and Development
No research and development expenditures
have been incurred, either on the Company’s account or sponsored by a customer of the Company, during the past three fiscal
years.
Insurance and Employees
The following summarizes the material aspects
of the Company’s insurance coverage:
General
We have liability insurance coverage in
amounts we deem sufficient for our business operations, consisting of property loss insurance on all major assets equal to the
approximate replacement value of the assets and additional liability and control of well insurance for our oil and gas drilling
programs. Payment of substantial liabilities in excess of coverage could require diversion of internal capital away from regular
business, which could result in curtailment of projected future operations.
Mt. Emmons Project
The Company was responsible for all costs
to operate the water treatment plant at the Mt. Emmons Project until the disposition of this property in February 2016. During
2016 and 2017, we have continued to maintain $10 million of coverage for environmental impairment liability.
Employees
As of December 31, 2016, we had 2 total
and full-time employees and we utilized several consultants on an as needed basis.
Forward Plan
In 2017 and beyond, we intend to seek additional
opportunities in the oil and gas sector, including but not limited to further acquisition of assets, participation with current
and new industry partners in their exploration and development projects, acquisition of operating companies, and the purchase and
exploration of new acreage positions.
Business Strategy
Key elements of our business strategies
include:
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Deploy our Capital in a Conservative and Strategic Manner and Review Opportunities to Bolster
our Liquidity
. In the current industry environment, maintaining liquidity is critical. Therefore, we will be highly selective
in the projects we evaluate and will review opportunities to bolster our liquidity and financial position through various means.
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Evaluate and Pursue Value-Enhancing Transactions
. We will continue to monitor the market
for strategic alternatives that we believe could enhance shareholder value.
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Continue to Develop Operating Capabilities
. We will continue to seek transactions where
we can gain operational control of any potential development activities. We seek to gain operatorship to retain more control over
the timing, selection and processes which will enhance our ability to maximize our return on invested capital.
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Industry Operating Environment
The oil and natural gas industry is affected
by many factors that we generally cannot control. Government regulations, particularly in the areas of taxation, energy,
climate change and the environment, can have a significant impact on operations and profitability. Significant factors that
will impact oil prices in the current fiscal year and future periods include: political and social developments in the Middle East,
demand in Asian and European markets, and the extent to which members of OPEC and other oil exporting nations manage oil supply
through export quotas. Additionally, natural gas prices continue to be under pressure due to concerns over excess supply
of natural gas due to the high productivity of emerging shale plays in the United States. Natural gas prices are generally
determined by North American supply and demand and are also affected by imports and exports of liquefied natural gas. Weather
also has a significant impact on demand for natural gas since it is a primary heating source.
Oil and natural gas prices have fallen
significantly since their early third quarter 2014 levels and NYMEX WTI oil prices dropped to the $26 per Bbl level in February
2016. Although oil prices have increased since February 2016, they remain well below the $100 per Bbl oil prices realized during
2014. Lower oil and gas prices not only decrease our revenues, but an extended decline in oil or gas prices may materially and
adversely affect our future business, financial position, cash flows, results of operations, liquidity, ability to finance planned
capital expenditures and the oil and natural gas reserves that we can economically produce. Lower oil and gas prices may
also reduce the amount of our borrowing base under our credit agreement, which is determined at the discretion of the lenders based
on the collateral value of our proved reserves that have been mortgaged to the lenders.
Development
We primarily engage in oil and natural
gas exploration and production by participating, on a proportionate basis, alongside third-party interests in wells drilled and
completed in spacing units that include our acreage. In addition, from time-to-time, we acquire working interests in wells
in which we do not hold the underlying leasehold interests from third parties unable or unwilling to participate in particular
well proposals. We typically depend on drilling partners to propose, permit and initiate the drilling of wells. Prior
to commencing drilling, our partners are required to provide all owners of oil, natural gas and mineral interests within the designated
spacing unit the opportunity to participate in the drilling costs and revenues of the well to the extent of their pro-rata share
of such interest within the spacing unit. We assess each drilling opportunity on a case-by-case basis and participate in
wells that we expect to meet our return thresholds based upon our estimates of ultimate recoverable oil and natural gas, expected
oil and gas prices, expertise of the operator, and completed well cost from each project, as well as other factors. Historically,
we have participated pursuant to our working interest in a vast majority of the wells proposed to us. However, the recent
significant decline in oil prices has reduced both the number of well proposals we receive and the proportion of well proposals
in which we have elected to participate.
Competition
The oil and natural gas industry is intensely
competitive, and we compete with numerous other oil and natural gas exploration and production companies. Some of these companies
have substantially greater resources than we have. Not only do they explore for and produce oil and natural gas, but also
many carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis.
The operations of other companies may be able to pay more for exploratory prospects and productive oil and natural gas properties.
They may also have more resources to define, evaluate, bid for and purchase a greater number of properties and prospects than our
financial or human resources permit.
Our larger or integrated competitors may
be better able to absorb the burden of existing and future federal, state, and local laws and regulations than we can, which would
adversely affect our competitive position. Our ability to discover reserves and acquire additional properties in the future
will be dependent upon our ability and resources to evaluate and select suitable properties and to consummate transactions in this
highly competitive environment. In addition, we may be at a disadvantage in producing oil and natural gas properties and
bidding for exploratory prospects because we have fewer financial and human resources than other companies in our industry.
Should a larger and better financed company decide to directly compete with us, and be successful in its efforts, our business
could be adversely affected.
Marketing and Customers
The market for oil and natural gas that
will be produced from our properties depends on factors beyond our control, including the extent of domestic production and imports
of oil and natural gas, the proximity and capacity of pipelines and other transportation facilities, demand for oil and natural
gas, the marketing of competitive fuels and the effects of state and federal regulation. The oil and natural gas industry
also competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers.
Our oil production is expected to be sold
at prices tied to the spot oil markets. Our natural gas production is expected to be sold under short-term contracts and
priced based on first of the month index prices or on daily spot market prices. We rely on our operating partners to market
and sell our production. Our operating partners include a concentrated list of exploration and production companies, from
large publicly-traded companies to small, privately-owned companies. We believe the loss of one of our major operators would
have a material adverse effect on our company as a whole.
Seasonality
Winter weather conditions and lease stipulations
can limit or temporarily halt the drilling and producing activities of our operating partners and other oil and natural gas operations.
These constraints and the resulting shortages or high costs could delay or temporarily halt the operations of our operating partners
and materially increase our operating and capital costs. Such seasonal anomalies can also pose challenges for meeting well drilling
objectives and may increase competition for equipment, supplies and personnel during the spring and summer months, which could
lead to shortages and increase costs or delay or temporarily halt our operating partners’ operations.
Governmental Regulation
Our operations are subject to various rules,
regulations and limitations impacting the oil and natural gas exploration and production industry as whole.
Regulation of Oil and Natural Gas Production
Our oil and natural gas exploration, production
and related operations are subject to extensive rules and regulations promulgated by federal, state, tribal and local authorities
and agencies. For example, North Dakota require permits for drilling operations, drilling bonds and reports concerning operations
and impose other requirements relating to the exploration and production of oil and natural gas. Many states may also have
statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and natural
gas properties, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon
which wells are drilled, the sourcing and disposal of water used in the process of drilling, completion and abandonment, the establishment
of maximum rates of production from wells, and the regulation of spacing, plugging and abandonment of such wells. The effect
of these regulations is to limit the amount of oil and natural gas that we can produce from our wells and to limit the number of
wells or the locations at which we can drill. Moreover, many states impose a production or severance tax with respect to
the production and sale of oil, natural gas and natural gas liquids within their jurisdictions. Failure to comply with any
such rules and regulations can result in substantial penalties. The regulatory burden on the oil and natural gas industry
will most likely increase our cost of doing business and may affect our profitability. Because such rules and regulations
are frequently amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws.
Significant expenditures may be required to comply with governmental laws and regulations and may have a material adverse effect
on our financial condition and results of operations. Additionally, currently unforeseen environmental incidents may occur
or past non-compliance with environmental laws or regulations may be discovered. Therefore, 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 (“FERC”) and the courts. We cannot predict
when or whether any such proposals may become effective.
Regulation of Transportation of Oil
Sales of crude oil, condensate and natural
gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls
in the future. Our sales of crude oil are affected by the availability, terms and cost of transportation. The transportation
of oil by common carrier pipelines is also subject to rate and access regulation. The FERC regulates interstate oil pipeline
transportation rates under the Interstate Commerce Act. In general, interstate oil pipeline rates must be cost-based, although
settlement rates agreed to by all shippers are permitted and market-based rates may be permitted in certain circumstances.
Effective January 1, 1995, the FERC implemented regulations establishing an indexing system (based on inflation) for transportation
rates for oil pipelines that allows a pipeline to increase its rates annually up to a prescribed ceiling, without making a cost
of service filing. Every five years, the FERC reviews the appropriateness of the index level in relation to changes in industry
costs. On December 17, 2015, the FERC established a new price index for the five-year period which commenced on July 1, 2016.
Intrastate oil pipeline transportation
rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the
degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates varies from state to state. Insofar as
effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of
oil transportation rates will not affect our operations in any way that is of material difference from those of our competitors
who are similarly situated.
Further, interstate and intrastate common
carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must
offer service to all similarly situated shippers requesting service on the same terms and under the same rates. When oil pipelines
operate at full capacity, access is generally governed by pro-rationing provisions set forth in the pipelines’ published
tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same
extent as to our similarly situated competitors.
Regulation of Transportation and Sales
of Natural Gas
Historically, the transportation and sale
for resale of natural gas in interstate commerce has been regulated by the FERC under the Natural Gas Act of 1938 (“NGA”),
the Natural Gas Policy Act of 1978 (“NGPA”) and regulations issued under those statutes. In the past, the federal
government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently
be made at market prices, Congress could reenact price controls in the future.
Onshore gathering services, which occur
upstream of FERC jurisdictional transmission services, are regulated by the states. Although the FERC has set forth a general
test for determining whether facilities perform a non-jurisdictional gathering function or a jurisdictional transmission function,
the FERC’s determinations as to the classification of facilities is done on a case-by-case basis. State regulation of natural
gas gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements.
Although such regulation has not generally been affirmatively applied by state agencies, natural gas gathering may receive greater
regulatory scrutiny in the future.
Intrastate natural gas transportation and
facilities are also subject to regulation by state regulatory agencies, and certain transportation services provided by intrastate
pipelines are also regulated by FERC. The basis for intrastate regulation of natural gas transportation and the degree of regulatory
oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Insofar as such
regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable
basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate
and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those
of our competitors. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects
the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.
Mining Activities
As discussed in Note 6 to the audited financial
statements included in Item 8 of this report on Form 10-K and
Management’s Discussion and Analysis of Financial Condition
and Results of Operations
included in Item 7 of this report on Form 10-K, in February 2016 we disposed of our Mt. Emmons Project
located near Crested Butte, Colorado rather than continuing our long-term development strategy. Accordingly, our mining assets
and operations have been treated as discontinued operations as of December 31, 2016 and for all prior periods presented in our
financial statements.
Item 1A - Risk Factors
The following risk factors should be
carefully considered in evaluating the information in this Annual Report.
Risks Involving Our Business
The development of oil and gas properties
involves substantial risks that may result in a total loss of investment.
The business of exploring for and developing
natural gas and oil properties involves a high degree of business and financial risk, and thus a significant risk of loss of initial
investment that even a combination of experience, knowledge and careful evaluation may not be able to overcome. The cost and timing
of drilling, completing and operating wells is often uncertain. Factors which can delay or prevent drilling or production, or otherwise
impact expected results, include but are not limited to:
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unexpected drilling conditions;
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inability to obtain required permits from governmental authorities;
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inability to obtain, or limitations on, easements from land owners;
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uncertainty regarding our operating partners’ drilling schedules;
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high pressure or irregularities in geologic formations;
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fires, explosions, blowouts, cratering, pollution, spills and other environmental risks or accidents;
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changes in government regulations and issuance of local drilling restrictions or moratoria;
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reductions in commodity prices;
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unavailability or high cost of equipment, field services and labor.
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A productive well may become uneconomic
in the event that unusual quantities of water or other non-commercial substances are encountered in the well bore that impair or
prevent production. We may participate in wells that are or become unproductive or, though productive, do not produce in economic
quantities. In addition, even commercial wells can produce less, or have higher costs, than we projected.
In addition, initial 24-hour or other limited-duration
production rates announced regarding our oil and gas properties are not necessarily indicative of future production rates.
Dry holes and other unsuccessful or uneconomic
exploration, exploitation and development activities can adversely affect our cash flow, profitability and financial condition,
and can adversely affect our reserves. We do not currently operate any of our properties, and therefore have limited ability to
control the manner in which drilling and other exploration and development activities on our properties are conducted, which may
increase these risks. Conversely, our anticipated transition to an operated business model entails risks as well. For example,
the benefits of this transition may be less, or the costs may be greater, than we currently anticipate. In addition, we may be
subject to a greater risk of drilling dry holes or encountering other operational problems until our operating capabilities are
more fully developed. Similarly, we may incur liabilities as an operator that we have historically avoided through a non-operated
business model.
Our business has been and may continue to be impacted
by adverse commodity prices.
For the three years
ended December 31, 2016, oil prices have ranged from highs over $100 per barrel in mid-2014 to lows below $30 per barrel in 2016.
Global markets, in reaction to general economic conditions and perceived impacts of future global supply, have caused large fluctuations
in price, and we believe significant future price swings are likely. Natural gas prices and NGL prices have experienced declines
of comparable magnitude since mid-2014. Declines in the prices we receive for our oil and gas production have and may continue
to adversely affect many aspects of our business, including our financial condition, revenues, results of operations, cash flows,
liquidity, reserves, rate of growth and the carrying value of our oil and gas properties, all of which depend primarily or in part
upon those prices. The reduction in drilling activity will likely result in lower production and, together with lower realized
oil prices, lower revenue and EBITDAX. Declines in the prices we receive for our oil and gas can also adversely affect our ability
to finance capital expenditures, make acquisitions, raise capital and satisfy our financial obligations. In addition, declines
in prices can reduce the amount of oil and gas that we can produce economically and the estimated future cash flow from that production
and, as a result, adversely affect the quantity and present value of our proved reserves. Among other things, a reduction in the
amount or present value of our reserves can limit the capital available to us, and the availability of other sources of capital
likely will be based to a significant degree on the estimated quantity and value of the reserves.
The Williston Basin oil price differential
could have adverse impacts on our revenue.
Generally, crude oil produced from the
Bakken formation in North Dakota is high quality (36 to 44 degrees API, which is comparable to West Texas Intermediate Crude).
During 2016, our realized oil prices in the Williston Basin were approximately $6.00 per barrel less than West Texas Intermediate
(“WTI”) quoted prices for crude oil. This discount, or differential, may widen in the future, which would reduce the
price we receive for our production. We may also be adversely affected by widening differentials in other areas of operation.
Drilling and completion costs for the wells
we drill in the Williston Basin are comparable to or higher than other areas where there is no price differential. This makes it
more likely that a downturn in oil prices will result in a ceiling limitation write-down of our Williston Basin oil and gas properties.
A widening of the differential would reduce the cash flow from our Williston Basin properties and adversely impact our ability
to participate fully in drilling with Statoil, Zavanna and other operators and to effect our strategy of transitioning to an operated
business model. Our production in other areas could also be affected by adverse changes in differentials. In addition, changes
in differentials could make it more difficult for us to effectively hedge our exposure to changes in commodity prices.
The agreement governing our debt
contain various covenants that limit our discretion in the operation of our business, could prohibit us from engaging in transactions
we believe to be beneficial, and could lead to the accelerated repayment of our debt.
The debt agreement between our wholly-owned
subsidiary, Energy One LLC (“Energy One”), and Wells Fargo Bank, N.A. contains restrictive covenants that limit Energy
One’s ability to engage in activities that may be in our long-term best interests. Our ability to borrow under the Credit
Facility is subject to compliance with certain financial covenants, including covenants that require the (i) interest coverage
ratio (EBITDAX to interest expense) to exceed 3.0 to 1.0; (ii) total debt to EBITDAX ratio to be less than 3.5 to 1; and (iii)
the current ratio to exceed 1.0 to 1.0, each as defined in the Credit Facility. Our prior and continuing failure to comply with
these covenants in the future has resulted in an event of default that, if not cured or waived, could result in the acceleration
of all or a portion of our indebtedness. We do not have sufficient capital resources to satisfy our debt obligations in the event
of an acceleration of all or a significant portion of our outstanding indebtedness. Adverse commodity prices and reduced drilling
activity may result in continuing breaches of the covenants in the Credit Facility. The ongoing availability of borrowings under
this Credit Facility through the maturity date of July 30, 2017, or the receipt of funding from alternative sources, is critical
to our ability to survive until oil and gas prices recover.
Additionally, the Credit Facility restricts
Energy One’s ability to incur additional debt, pay cash dividends and other restricted payments, sell assets, enter into
transactions with affiliates, and to merge or consolidate with another company. These restrictions on our ability to operate our
business could seriously harm our business by, among other things, limiting our ability to take advantage of financings, mergers
and acquisitions, and other corporate opportunities.
We require funding for our working
capital deficit and debt obligations. We may be unable to obtain such funding, particularly as we are in continuing breach of covenants
in the Credit Facility.
Our working capital at December 31, 2016
was negative $6.0 million which is primarily the result of classifying $6.0 million of borrowings under the Credit Facility with
Wells Fargo as a current liability. During 2015 and 2016, we were unable to maintain compliance with certain financial ratio covenants
in the Credit Facility with Wells Fargo. In April 2016, Wells Fargo provided a waiver for non-compliance with the covenants in
the Credit Facility for the fiscal quarter ended December 31, 2015. In August 2016 Wells Fargo agreed to enter into a fourth amendment
to the Credit Facility that provided for, among other things, a limited waiver of the negative financial covenants for the fiscal
quarters ended March 31, 2016 and June 30, 2016. The Company violated the financial ratio covenants for the fiscal quarters ended
September 30, 2016 and December 31, 2016, which constituted an event of default under the credit agreement. Accordingly, Wells
Fargo has the immediate right to demand acceleration of all outstanding borrowings and has the ability to foreclose upon the existing
collateral. Wells Fargo notified the Company that default rate interest is accruing on all outstanding balances under the Credit
Facility. Even though this debt does not mature until July 2017, we have been unable to comply with the debt covenants during 2017
and we project continuing non-compliance. While Wells Fargo has historically provided waivers for our non-compliance, there is
no assurance that it will continue to do so in the future. In addition, the borrowing base under the Credit Facility is subject
to redetermination periodically and from time to time in the lenders’ discretion. Borrowing base reductions may occur as
a result of unfavorable changes in commodity prices, asset sales, performance issues or other events. In addition to reducing the
capital available to finance our operations, a reduction in the borrowing base could cause us to be required to repay amounts outstanding
under the Credit Facility in excess of the reduced borrowing base, and the funds necessary to do so may not be available at that
time. Currently, we do not have adequate funding to repay Wells Fargo if it chooses to demand an accelerated repayment of the outstand
borrowings or foreclose upon the existing collateral. The ongoing availability of borrowings under this Credit Facility through
the maturity date of July 30, 2017, or the receipt of funding from alternative sources, is critical to the Company’s ability
to survive until oil and gas prices recover.
Regardless of our ability to comply with
the covenants under the Credit Facility, we will pursue alternative funding sources before the facility matures in July 2017. Other
sources of external debt or equity financing may not be available when needed on acceptable terms or at all, especially during
periods in which financial market conditions are unfavorable. Also, the issuance of equity may be dilutive to existing shareholders.
During 2017, we will attempt to obtain a larger credit facility that will enable the repayment of amounts outstanding under the
Credit Facility and provide capital resources to participate in acquisition and development activities; obtaining additional financing
is an important objective for us in 2017 and may be critical in our efforts to continue to operate and to avoid bankruptcy, liquidation
or similar proceedings. We cannot provide any assurance that we will be successful in this regard.
Should we be unsuccessful in these efforts
to refinance the Credit Facility, we may be forced to sell assets to raise sufficient capital to repay the Credit Facility by the
maturity date of July 30, 2017. The sale of sufficient assets to repay the Credit Facility in full would likely include substantially
all of the Company’s income-producing properties, resulting, in effect, in the liquidation of the Company.
Our industry partners may elect to engage
in drilling activities that we are unwilling or unable to participate in during 2017. Our exploration and development agreements
contain customary industry non-consent provisions. Pursuant to these provisions, if a well is proposed to be drilled or completed
but a working interest owner elects not to participate, the resulting revenues (which otherwise would go to the non-participant)
flow to the participants until they receive from 150% to 300% of the capital they provided to cover the non-participant’s
share. In order to be in position to avoid non-consent penalties and to make opportunistic investments in new assets, we will continue
to evaluate various options to obtain additional capital, including additional debt financing, sales of one or more producing or
non-producing oil and gas assets and the issuance of shares of our common stock.
The oil and gas business presents the opportunity
for significant returns on investment, but achievement of such returns is subject to high risk. For example, initial results from
one or more of the oil and gas programs could be marginal but warrant investing in more wells. Dry holes, over-budget exploration
costs, low commodity prices, or any combination of these or other adverse factors, could result in production revenues below projections,
thus adversely impacting cash expected to be available for continued work in a program, and a reduction in cash available for investment
in other programs. These types of events could require a reassessment of priorities and therefore potential re-allocations of existing
capital and could also mandate obtaining new capital. There can be no assurance that we will be able to complete any financing
transaction on acceptable terms.
We may be unable to continue as a going concern.
We have substantial debt obligations and
our ongoing capital and operating expenditures will exceed the revenue we expect to receive from our oil and natural gas operations
in the near future. If we are unable to raise substantial additional funding, refinance existing indebtedness or consummate significant
asset sales on a timely basis and/or on acceptable terms, we may be required to significantly curtail our business and operations.
The consolidated financial statements included
in this report on Form 10-K have been prepared on a going concern basis of accounting, which contemplates the realization of assets
and the satisfaction of liabilities in the normal course of business. The consolidated financial statements do not reflect any
adjustments that might be necessary should we be unable to continue as a going concern. Our ability to continue as a going concern
is subject to, among other factors, our ability to monetize assets, our ability to obtain financing or refinance existing indebtedness,
our ability to continue our cost cutting efforts, oil and gas commodity prices, our ability to recognize, acquire and develop strategic
interests and prospects, the speed and cost with which we can develop our prospects and the ability to adapt our business by integrating
specific operations associated with operating companies. There can be no assurance that we will be able to obtain additional funding
on a timely basis and on satisfactory terms, or at all. In addition, no assurance can be given that any such funding, if obtained,
will be adequate to meet our capital needs and support our growth. If additional funding cannot be obtained on a timely basis and
on satisfactory terms, then our operations would be materially negatively impacted and we may be unable to continue as a going
concern. If we become unable to continue as a going concern, we may find it necessary to file a voluntary petition for reorganization
under the Bankruptcy Code in order to provide us additional time to identify an appropriate solution to our financial situation
and implement a plan of reorganization aimed at improving our capital structure. For additional information, please see Items 7
and 8 contained in this report on Form 10-K.
Competition may limit our opportunities
in the oil and gas business.
The oil and gas business is very competitive.
We compete with many public and private exploration and development companies in finding investment opportunities. We also compete
with oil and gas operators in acquiring acreage positions. Our principal competitors are small to mid-size companies with in-house
petroleum exploration and drilling expertise. Many of our competitors possess and employ financial, technical and personnel resources
substantially greater than ours. They also may be willing and able to pay more for oil and gas properties than our financial resources
permit, and may be able to define, evaluate, bid for and purchase a greater number of properties. In addition, there is substantial
competition in the oil and gas industry for investment capital, and we may not be able to compete successfully in raising additional
capital if needed.
Successful exploitation of the Buda
formation, the Williston Basin (Bakken and Three Forks shales) and the Eagle Ford shale is subject to risks related to horizontal
drilling and completion techniques.
Operations in the Buda formation and the
Bakken, Three Forks and Eagle Ford shales in many cases involve utilizing the latest drilling and completion techniques in an effort
to generate the highest possible cumulative recoveries and therefore generate the highest possible returns. Risks that are encountered
while drilling include, but are not limited to, landing the well bore in the desired drilling zone, staying in the zone while drilling
horizontally through the shale formation, running casing the entire length of the well bore (as applicable to the formation) and
being able to run tools and other equipment consistently through the horizontal well bore.
For wells that are hydraulically fractured,
completion risks include, but are not limited to, being able to fracture stimulate the planned number of frac stages, and successfully
cleaning out the well bore after completion of the final fracture stimulation stage. Ultimately, the success of these latest drilling
and completion techniques can only be evaluated over time as more wells are drilled and production profiles are established over
a sufficient period of time.
Costs for any individual well will vary
due to a variety of factors. These wells are significantly more expensive than a typical onshore shallow conventional well. Accordingly,
unsuccessful exploration or development activity affecting even a small number of wells could have a significant impact on our
results of operations. Costs other than drilling and completion costs can also be significant for Williston Basin, Eagle Ford and
other wells.
If our access to oil and gas markets
is restricted, it could negatively impact our production and revenues. Securing access to takeaway capacity may be particularly
difficult in less developed areas of the Williston Basin.
Market conditions or limited availability
of satisfactory oil and gas transportation arrangements may hinder our access to oil and gas markets or delay our production. The
availability of a ready market for our oil and gas production depends on a number of factors, including the demand for and supply
of oil and gas and the proximity of reserves to pipelines and other midstream facilities. Our ability to market our production
depends in substantial part on the availability and capacity of gathering systems, pipelines, rail transportation and processing
facilities owned and operated by third parties. In particular, access to adequate gathering systems or pipeline or rail takeaway
capacity is limited in the Williston Basin. In order to secure takeaway capacity and related services, we or our operating partners
may be forced to enter into arrangements that are not as favorable to operators as those in other areas.
If we are unable to replace reserves,
we will not be able to sustain production.
Our future operations depend on our ability
to find, develop, or acquire crude oil, natural gas, and NGL reserves that are economically producible. Our properties produce
crude oil, natural gas, and NGLs at a declining rate over time. In order to maintain current production rates, we must locate and
develop or acquire new crude oil, natural gas, and NGL reserves to replace those being depleted by production. Without successful
drilling or acquisition activities, our reserves and production will decline over time. In addition, competition for crude oil
and gas properties is intense, and many of our competitors have financial, technical, human, and other resources necessary to evaluate
and integrate acquisitions that are substantially greater than those available to us.
As part of our growth strategy, we have
made and may continue to make acquisitions. However, suitable acquisition candidates may not continue to be available on terms
and conditions we find acceptable, and acquisitions pose substantial risks to our business, financial condition and results of
operations. In pursuing acquisitions, we compete with other companies, many of which have greater financial and other resources
than we do. In the event we do complete an acquisition, its successful impact on our business will depend on a number of factors,
many of which are beyond our control. These factors include the purchase price for the acquisition, future crude oil, natural gas,
and NGL prices, the ability to reasonably estimate or assess the recoverable volumes of reserves, rates of future production and
future net revenues attainable from reserves, future operating and capital costs, results of future exploration, exploitation,
and development activities on the acquired properties, and future abandonment and possible future environmental or other liabilities.
There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves, actual future production rates,
and associated costs and potential liabilities with respect to prospective acquisition targets. Actual results may vary substantially
from those assumed in the estimates. A customary review of subject properties will not necessarily reveal all existing or potential
problems.
Additionally, significant acquisitions
can change the nature of our operations and business depending upon the character of the acquired properties if they have substantially
different operating and geological characteristics or are in different geographic locations than our existing properties. To the
extent that acquired properties are substantially different than our existing properties, our ability to efficiently realize the
expected economic benefits of such transactions may be limited. If we are unable to integrate acquisitions successfully and realize
anticipated economic, operational and other benefits in a timely manner, substantial costs and delays or other operational, technical
or financial problems could result.
Integrating acquired businesses and properties
involves a number of special risks. These risks include the possibility that management may be distracted from regular business
concerns by the need to integrate operations and systems and that unforeseen difficulties can arise in integrating operations and
systems and in retaining and assimilating employees. Any of these or other similar risks could lead to potential adverse short-term
or long-term effects on our operating results and may cause us to not be able to realize any or all of the anticipated benefits
of the acquisitions.
Lower oil and gas prices may cause us to record ceiling
test write-downs.
We use the full cost method of accounting
to account for our oil and gas investments. Accordingly, we capitalize the cost to acquire, explore for and develop these properties.
Under full cost accounting rules, the net capitalized cost of oil and gas properties may not exceed a “ceiling limit”
that is based upon the present value of estimated future net revenues from proved reserves, discounted at 10%, plus the lower of
the cost or fair market value of unproved properties. If net capitalized costs exceed the ceiling limit, we must charge the amount
of the excess to earnings (a charge referred to as a “ceiling test write-down”). The risk of a ceiling test write-down
increases when oil and gas prices are depressed, if we have substantial downward revisions in estimated proved reserves or if we
drill unproductive wells.
Under the full cost method, all costs associated
with the acquisition, exploration and development of oil and gas properties are capitalized and accumulated in a country-wide cost
center. This includes any internal costs that are directly related to development and exploration activities, but does not include
any costs related to production, general corporate overhead or similar activities. Proceeds received from disposals are credited
against accumulated cost, except when the sale represents a significant disposal of reserves, in which case a gain or loss is recognized.
The sum of net capitalized costs and estimated future development and dismantlement costs for each cost center is depleted on the
equivalent unit-of-production method, based on proved oil and gas reserves. Excluded from amounts subject to depreciation, depletion
and amortization are costs associated with unevaluated properties.
Under the full cost method, net capitalized
costs are limited to the lower of (a) unamortized cost reduced by the related net deferred tax liability and asset retirement obligations,
and (b) the cost center ceiling. The cost center ceiling is defined as the sum of (i) estimated future net revenue, discounted
at 10% per annum, from proved reserves, based on unescalated costs, adjusted for contract provisions, any financial derivatives
that hedge our oil and gas revenue and asset retirement obligations, and unescalated oil and gas prices during the period, (ii)
the cost of properties not being amortized, and (iii) the lower of cost or market value of unproved properties included in the
cost being amortized, less (iv) income tax effects related to tax assets directly attributable to the natural gas and crude oil
properties. If the net book value reduced by the related net deferred income tax liability and asset retirement obligations exceeds
the cost center ceiling limitation, a non-cash impairment charge is required in the period in which the impairment occurs.
We perform a quarterly ceiling test for
our only oil and gas cost center, which is the United States. During 2016, capitalized costs for oil and gas properties exceeded
the ceiling and we recorded aggregate ceiling test write-downs of $9.6 million primarily due to a decline in the prices of oil
and gas. The ceiling test incorporates assumptions regarding pricing and discount rates over which we have no influence in the
determination of present value. In arriving at the ceiling test for the year ended December 31, 2016, we used a weighted average
price applicable to our properties of $42.75 per barrel for oil and $2.48 per Mcfe for natural gas to compute the future cash flows
of each of the producing properties at that date.
Capitalized costs associated with unevaluated
properties include exploratory wells in progress, costs for seismic analysis of exploratory drilling locations, and leasehold costs
related to unproved properties. Unevaluated properties not subject to depreciation, depletion and amortization amounted to an aggregate
of $4.7 million as of December 31, 2016. These costs will be transferred to evaluated properties to the extent that we subsequently
determine the properties are impaired or if proved reserves are established.
We do not currently serve as operator
for any of our oil and gas properties. Many of our joint operating agreements contain provisions that may be subject to legal interpretation,
including allocation of non-consent interests, complex payout calculations that impact the timing of reversionary interests, and
the impact of joint interest audits.
Substantially all of our oil and gas interests
are subject to joint operating and similar agreements. Some of these agreements include payment provisions that are complex and
subject to different interpretations and/or can be erroneously applied in particular situations. In the past, we received significant
overpayments due to an operator’s failure to timely recognize the payout implications of our joint operating agreements.
The operator has elected to withhold the net revenues from all of our wells that it operates to recover these overpayments, decreasing
cash flows that would otherwise be available to operate our business.
We believe certain operators have failed
to allocate our share of non-consent ownership interests which results in contingent liabilities to the extent we have not been
billed for our proportionate share of such interests, and contingent assets to the extent that we have not received our share of
the net revenues. We record net contingent liabilities for the obligations that we believe are probable. Additionally, we believe
an operator has failed to allocate our share of certain royalty interests that we are entitled to under a participation agreement.
The ultimate resolution of these uncertainties about our working interests and net revenue interests can extend over a long period
of time and we can incur substantial amounts of legal fees to resolve disputes with the operators of our properties.
Joint interest audits are a normal process
in our business to ensure that operators adhere to standard industry practices in the billing of costs and expenses related to
our oil and gas properties. However, the ultimate resolution of joint interest audits can extend over a long period of time in
which we attempt to recover excessive amounts charged by the operator. Joint interest audits result in incremental costs for the
audit services and we can incur substantial amounts of legal fees to resolve disputes with the operators of our properties.
We do not currently operate our drilling
locations. Therefore, we will not be able to control the timing of exploration or development efforts, associated costs, or the
rate of production of these non-operated assets.
We do not currently operate any of the
prospects we hold with industry partners. As a non-operator, our ability to exercise influence over the operations of the drilling
programs is limited. In the usual case in the oil and gas industry, new work is proposed by the operator and often is approved
by most of the non-operating parties. If the work is approved by the holders of a majority of the working interests, but we disagree
with the proposal and do not (or are unable to) participate, we will forfeit our share of revenues from the well until the participants
receive 150% to 300% of their investment. In some cases, we could lose all of our interest in the well. We would avoid a penalty
of this kind only if a majority of the working interest owners agree with us and the proposal does not proceed.
The success and timing of our drilling
and development activities on properties operated by others depend upon a number of factors outside of our control, including:
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the nature and timing of the operator’s drilling and other activities;
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the timing and amount of required capital expenditures;
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the operator’s geological and engineering expertise and financial resources;
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the approval of other participants in drilling wells; and
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the operator’s selection of suitable technology.
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The fact that our industry partners serve
as operator makes it more difficult for us to predict future production, cash flows and liquidity needs. Our ability to grow our
production and reserves depends on decisions by our partners to drill wells in which we have an interest, and they may elect to
reduce or suspend the drilling of those wells.
Our estimated reserves are based
on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or the relevant underlying
assumptions will materially affect the quantity and present value of our reserves.
Oil and gas reserve reports are prepared
by independent consultants to provide estimates of the quantities of hydrocarbons that can be economically recovered from proved
properties, utilizing commodity prices for a trailing 12-month period and taking into account expected capital, operating and other
expenditures. These reports also provide estimates of the future net present value of the reserves, which we use for internal planning
purposes and for testing the carrying value of the properties on our balance sheet.
The reserve data included in this report
represent estimates only. Estimating quantities of, and future cash flows from, proved oil and gas reserves is a complex process.
It requires interpretations of available technical data and various estimates, including estimates based upon assumptions relating
to economic factors, such as future production costs; ad valorem, severance and excise taxes; availability of capital; estimates
of required capital expenditures, workover and remedial costs; and the assumed effect of governmental regulation. The assumptions
underlying our estimates of our proved reserves could prove to be inaccurate, and any significant inaccuracy could materially affect,
among other things, future estimates of the reserves, the economically recoverable quantities of oil and gas attributable to the
properties, the classifications of reserves based on risk of recovery, and estimates of our future net cash flows.
At December 31, 2016, 99% of our estimated
proved reserves were producing and 1% were proved developed non-producing. Estimation of proved undeveloped reserves and proved
developed non-producing reserves is almost always based on analogy to existing wells, volumetric analysis or probabilistic methods,
in contrast to the performance data used to estimate producing reserves. Recovery of proved undeveloped reserves requires significant
capital expenditures and successful drilling operations. Revenue from estimated proved developed non-producing and proved undeveloped
reserves will not be realized until sometime in the future, if at all.
You should not assume that the present
values referred to in this report represent the current market value of our estimated oil and gas reserves. The timing and success
of the production and the expenses related to the development of oil and gas properties, each of which is subject to numerous risks
and uncertainties, will affect the timing and amount of actual future net cash flows from our proved reserves and their present
value. In addition, our PV-10 and standardized measure estimates are based on costs as of the date of the estimates and assume
fixed commodity prices. Actual future prices and costs may be materially higher or lower than the prices and costs used in the
estimate.
Further, the use of a 10% discount factor
to calculate PV-10 and standardized measure values may not necessarily represent the most appropriate discount factor given actual
interest rates and risks to which our business or the oil and gas industry in general are subject.
The use of derivative arrangements
in oil and gas production could result in financial losses or reduce income.
From time to time, we use derivative instruments,
typically fixed-rate swaps and costless collars, to manage price risk underlying our oil production. The fair value of our derivative
instruments is marked to market at the end of each quarter and the resulting unrealized gains or losses due to changes in the fair
value of our derivative instruments is recognized in current earnings. Accordingly, our earnings may fluctuate significantly as
a result of changes in the fair value of our derivative instruments.
Our actual future production may be significantly
higher or lower than we estimate at the time we enter into derivative contracts for the relevant period. If the actual amount of
production is higher than we estimated, we will have greater commodity price exposure than we intended. If the actual amount of
production is lower than the notional amount that is subject to our derivative instruments, we might be forced to satisfy all or
a portion of our derivative transactions without the benefit of the cash flow from our sale of the underlying physical commodity,
resulting in a substantial diminution of our liquidity. As a result of these factors, our hedging activities may not be as effective
as we intend in reducing the volatility of our cash flows, and in certain circumstances may actually increase the volatility of
our cash flows.
Derivative instruments also expose us to
the risk of financial loss in some circumstances, including when:
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the counter-party to the derivative instrument defaults on its contract obligations;
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there is an increase in the differential between the underlying price in the derivative instrument and actual prices received; or
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the steps we take to monitor our derivative financial instruments do not detect and prevent transactions that are inconsistent with our risk management strategies.
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In addition, depending on the type of derivative
arrangements we enter into, the agreements could limit the benefit we would receive from increases in oil prices. It cannot be
assumed that the hedging transactions we have entered into, or will enter into, will adequately protect us from fluctuations in
commodity prices.
Additionally, the Dodd-Frank Wall Street
Reform and Consumer Protection Act, or the Dodd-Frank Act, among other things, imposes restrictions on the use and trading of certain
derivatives, including energy derivatives. The nature and scope of those restrictions will be determined in significant part through
regulations that either have been or are in the process of being implemented by the SEC, the Commodities Futures Trading Commission
and other regulators. If, as a result of the Dodd-Frank Act or its implementing regulations, capital or margin requirements or
other limitations relating to our commodity derivative activities are imposed, this could have an adverse effect on our ability
to implement our hedging strategy. In particular, a requirement to post cash collateral in connection with our derivative positions
(which are currently not collateralized unless our counterparty’s exposure reaches a certain level) would likely make it
impracticable to implement our current hedging strategy. In addition, requirements and limitations imposed on our derivative counterparties
could increase the costs of pursuing our hedging strategy.
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, the loss of our lease and prospective drilling opportunities.
Unless production is established within
the spacing units covering the undeveloped acres on which some of our potential drilling locations are identified, the leases for
such acreage will expire. The cost to renew such leases may increase significantly, and we may not be able to renew such leases
on commercially reasonable terms or at all. The risk that our leases may expire will generally increase when commodity prices fall,
as lower prices may cause our operating partners to reduce the number of wells they drill. In addition, on certain portions of
our acreage, third-party leases could become immediately effective if our leases expire. As such, our actual drilling activities
may materially differ from our current expectations, which could adversely affect our business.
Our producing properties are primarily
located in the Williston Basin and South Texas, making us vulnerable to risks associated with having operations concentrated in
these geographic areas.
Because our operations are geographically
concentrated in the Williston Basin and South Texas, the success and profitability of our operations may be disproportionally exposed
to the effect of regional events. These include, among others, regulatory issues, natural disasters and fluctuations in the prices
of crude oil and gas produced from wells in the region and other regional supply and demand factors, including gathering, pipeline
and other transportation capacity constraints, available rigs, equipment, oil field services, supplies, labor and infrastructure
capacity. Any of these events has the potential to cause producing wells to be shut-in, delay operations and growth plans, decrease
cash flows, increase operating and capital costs and prevent development of lease inventory before expiration. In addition, our
operations in the Williston Basin may be adversely affected by seasonal weather and lease stipulations designed to protect wildlife,
which can intensify competition for services, infrastructure and equipment during months when drilling is possible and may result
in periodic shortages. Any of these risks could have a material adverse effect on our financial condition and results of operations.
Insurance may be insufficient to cover future liabilities.
Our business is currently focused on oil
and gas exploration and development and we also have potential exposure to general liability and property damage associated with
the ownership of other corporate assets. In the past, we relied primarily on the operators of our oil and gas properties to obtain
and maintain liability insurance for our working interest in our oil and gas properties. In some cases, we may continue to rely
on those operators’ insurance coverage policies depending on the coverage. Since 2011 we have obtained our own insurance
policies for our oil and gas operations that are broader in scope and coverage and are in our control. We also maintain insurance
policies for liabilities associated with and damage to general corporate assets.
We also have separate policies for environmental
exposures related to our prior ownership of the water treatment plant operations related to our discontinued mining operations.
These policies provide coverage for remediation events adversely impacting the environment. See “Insurance” below.
We would be liable for claims in excess
of coverage and for any deductible provided for in the relevant policy. If uncovered liabilities are substantial, payment could
adversely impact the Company’s cash on hand, resulting in possible curtailment of operations. Moreover, some liabilities
are not insurable at a reasonable cost or at all.
Oil and gas operations are subject
to environmental and other regulations that can materially adversely affect the timing and cost of operations.
Our operations are subject to stringent
and complex federal, state and local laws and regulations relating to the protection of human health and safety, the environment
and natural resources. These laws and regulations can restrict or impact our business activities in many ways, such as:
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requiring the installation of pollution-control equipment or otherwise restricting the handling or disposal of wastes and other substances associated with operations;
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limiting or prohibiting construction activities in sensitive areas, such as wetlands, coastal regions or areas that contain endangered or threatened species and/or species of special statewide concern or their habitats;
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requiring investigatory and remedial actions to address pollution caused by our operations or attributable to former operations;
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requiring noise, lighting, visual impact, odor and/or dust mitigation, setbacks, landscaping, fencing, and other measures;
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restricting access to certain equipment or areas to a limited set of employees or contractors who have proper certification or permits to conduct work (e.g., confined space entry and process safety maintenance requirements); and
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restricting or even prohibiting water use based upon availability, impacts or other factors.
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Failure to comply with these laws and regulations
may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties,
the imposition of remedial or restoration obligations, and the issuance of orders enjoining future operations or imposing additional
compliance requirements. Certain environmental statutes impose strict, joint and several liability for costs required to clean
up and restore sites where hazardous substances, hydrocarbons or wastes have been disposed or otherwise released. Moreover, local
restrictions, such as state or local moratoria, city ordinances, zoning laws and traffic regulations, may restrict or prohibit
the execution of operational plans. In addition, third parties, such as neighboring landowners, may file claims alleging property
damage, nuisance or personal injury arising from our operations or from the release of hazardous substances, hydrocarbons or other
waste products into the environment.
The trend in environmental regulation is
to place more restrictions and limitations on activities that may affect the environment. We monitor developments at the federal,
state and local levels to inform our actions pertaining to future regulatory requirements that might be imposed to mitigate the
costs of compliance with any such requirements. We also monitor industry groups that help formulate recommendations for addressing
existing or future regulations and that share best practices and lessons learned in relation to pollution prevention and incident
investigations.
Below is a discussion of the major environmental,
health and safety laws and regulations that relate to our business. We believe that we are in material compliance with these laws
and regulations. We do not believe that compliance with existing environmental, health and safety laws or regulations will have
a material adverse effect on our financial condition, results of operations or cash flow. At this point, however, we cannot reasonably
predict what applicable laws, regulations or guidance may eventually be adopted with respect to our operations or the ultimate
cost to comply with such requirements.
Hazardous Substances and Waste
Federal and state laws, in particular the
federal Resource Conservation and Recovery Act (RCRA) regulate hazardous and non-hazardous wastes. In the course of our operations,
we and others generate petroleum hydrocarbon wastes, produced water and ordinary industrial wastes. Under a longstanding legal
framework, certain of these wastes are not subject to federal regulations governing hazardous wastes, although they are regulated
under other federal and state waste laws. At various times in the past, most recently in December 2016, proposals have been made
to amend RCRA or otherwise eliminate the exemption applicable to crude oil and natural gas exploration and production wastes. Repeal
or modifications of this exemption by administrative, legislative or judicial process, or through changes in applicable state statutes,
would increase the volume of hazardous waste we are required to manage and dispose and would cause us, as well as our competitors,
to incur significantly increased operating expenses.
Federal, state and local laws may also
require us to remove or remediate wastes or hazardous substances that have been previously disposed or released into the environment.
This can include removing or remediating wastes or hazardous substances disposed or released by us (or prior owners or operators)
in accordance with then current laws, suspending or ceasing operations at contaminated areas, or performing remedial well plugging
operations or response actions to reduce the risk of future contamination. Federal laws, including the Comprehensive Environmental
Response, Compensation, and Liability Act (CERCLA) and analogous state laws impose joint and several liability, without regard
to fault or legality of the original conduct, on classes of persons who are considered legally responsible for releases of a hazardous
substance into the environment. These persons include the owner or operator of the site where the release occurred, persons who
disposed or arranged for the disposal of hazardous substances at the site, and any person who accepted hazardous substances for
transportation to the site. CERCLA and analogous state laws also authorize the EPA, state environmental agencies and, in some cases,
third parties to take action to prevent or respond to threats to human health or the environment and/or seek recovery of the costs
of such actions from responsible classes of persons.
The Underground Injection Control (UIC)
Program authorized by the Safe Drinking Water Act prohibits any underground injection unless authorized by a permit. Permits for
Class II UIC wells may be issued by the EPA or by a state regulatory agency if EPA has delegated its UIC Program authority. Because
some states have become concerned that the disposal of produced water could under certain circumstances contribute to seismicity,
they have adopted or are considering adopting additional regulations governing such disposal.
Air Emissions
We are subject to the federal Clean Air
Act (CAA) and comparable state laws and regulations. Among other things, these laws and regulations regulate emissions of air pollutants
from various industrial sources, including compressor stations and production equipment, and impose various control, monitoring
and reporting requirements. Permits and related compliance obligations under the CAA, each state's development and promulgation
of regulatory programs to comport with federal requirements, as well as changes to state implementation plans for controlling air
emissions in regional non-attainment or near-non-attainment areas, may require oil and gas exploration and production operators
to incur future capital expenditures in connection with the addition or modification of existing air emission control equipment
and strategies.
Discharges into Waters
The federal Water Pollution Control Act,
or the Clean Water Act (CWA), and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants
into state waters as well as waters of the U.S. Spill prevention, control and countermeasure regulations require appropriate containment
berms and similar structures to help prevent the contamination of regulated waters in the event of a 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 and construction activities.
The Oil Pollution Act of 1990 (OPA) establishes
strict liability for owners and operators of facilities that release oil into waters of the United States. The OPA and its associated
regulations impose a variety of requirements on responsible parties related to the prevention of oil spills and liability for damages
resulting from such spills. A ''responsible party'' under the OPA includes owners and operators of certain onshore facilities from
which a release may affect waters of the United States.
Health and Safety
The Occupational Safety and Health Act
(OSHA) and comparable state laws regulate the protection of the health and safety of employees. The federal Occupational Safety
and Health Administration has established workplace safety standards that provide guidelines for maintaining a safe workplace in
light of potential hazards, such as employee exposure to hazardous substances. OSHA also requires employee training and maintenance
of records, and the OSHA hazard communication standard and EPA community right-to-know regulations under the Emergency Planning
and Community Right-to-Know Act of 1986 require that we organize and/or disclose information about hazardous materials used or
produced in our operations.
Endangered Species
The Endangered Species Act (ESA) prohibits
the taking of endangered or threatened species or their habitats. While some of our assets and lease acreage may be located in
areas that are designated as habitats for endangered or threatened species, we believe that we are in material compliance with
the ESA. However, the designation of previously unidentified endangered or threatened species in areas where we intend to operate
could materially limit or delay our plans.
Global Warming and Climate Change
At the federal level, EPA regulations require
companies to establish and report an inventory of greenhouse gas emissions. Legislative and regulatory proposals for restricting
greenhouse gas emissions or otherwise addressing climate change could require us to incur additional operating costs and could
adversely affect demand for the oil and natural gas that we sell. The EPA recently finalized new standards of performance limiting
methane emissions from oil and gas sources. The potential increase in operating costs could include new or increased costs to (i)
obtain permits, (ii) operate and maintain our equipment and facilities, (iii) install new emission controls on equipment and facilities,
(iv) acquire allowances authorizing greenhouse gas emissions, (v) pay taxes related to greenhouse gas emissions and (vi) administer
and manage a greenhouse gas emissions program. In addition to these federal actions, various state governments and/or regional
agencies may consider enacting new legislation and/or promulgating new regulations governing or restricting the emission of greenhouse
gases from stationary sources.
In addition, the United States was actively
involved in the United Nations Conference on Climate Change in Paris, which led to the creation of the Paris Agreement. The Paris
Agreement requires countries to review and “represent a progression” in their nationally determined contributions,
which set emissions reduction goals, every five years. The Paris Agreement could further drive regulation in the United States.
Restrictions on emissions of methane or carbon dioxide that have been or may be imposed in various states, or at the federal level
could adversely affect the oil and gas industry. Moreover, incentives to conserve energy or use alternative energy sources as a
means of addressing climate change could reduce demand for oil and natural gas. Finally, we note that some scientists have concluded
that increasing concentrations of greenhouse gases in the Earth's atmosphere may produce climate changes that have significant
physical effects, such as higher sea levels, increased frequency and severity of storms, droughts, floods, and other climatic events.
If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations.
The EPA has authority to regulate underground
injections that contain diesel in the fluid system under the Safe Drinking Water Act (the “SDWA”), and has published
an interpretive memorandum and permitting guidance related to regulation of fracturing fluids using this regulatory authority.
The EPA announced plans to update its chloride water quality criteria for the protection of aquatic life under the Clean Water
Act. Flowback and produced water from the hydraulic fracturing process contain total dissolved solids, including chlorides, and
regulation of these fluids could be affected by the new criteria. The EPA has announced that it will develop pre-treatment standards
for disposal of wastewater produced from shale gas operations through publicly owned treatment works. The regulations will be developed
under the EPA’s Effluent Guidelines Program under the authority of the Clean Water Act. On April 7, 2015, the EPA published
a proposed rule requiring federal pre-treatment standards for wastewater generated during the hydraulic fracturing process in the
Federal Register. If adopted, the new pre-treatment rules will require shale gas operations to pre-treat wastewater before transferring
it to publicly owned treatment facilities. The public comment period for the proposed rule ended on July 17, 2015. If the EPA implements
further regulations of hydraulic fracturing, we may incur additional costs to comply with such requirements that may be significant
in nature, experience delays or curtailment in the pursuit of exploration, development, or production activities, and could even
be prohibited from drilling and/or completing certain wells.
The state of Texas has adopted, and other
states are considering adopting, regulations that could impose more stringent permitting, public disclosure, waste disposal, and
well construction requirements on hydraulic fracturing operations or otherwise seek to ban fracturing activities altogether. In
addition to state laws, local land use restrictions, such as city ordinances, may restrict or prohibit the performance of drilling
in general and/or hydraulic fracturing in particular. Recently, several municipalities have passed or proposed zoning ordinances
that ban or strictly regulate hydraulic fracturing within city boundaries, setting the stage for challenges by state regulators
and third-parties. Similar events and processes are playing out in several cities, counties, and townships across the United States.
In the event state, local, or municipal legal restrictions are adopted in areas where we are currently conducting, or in the future
plan to conduct, operations, we may incur additional costs to comply with such requirements that may be significant in nature,
experience delays or curtailment in the pursuit of exploration, development, or production activities, and could even be prohibited
from drilling and/or completing certain wells.
Several federal governmental agencies are
actively involved in studies or reviews that focus on environmental aspects and impacts of hydraulic fracturing practices. A number
of federal agencies are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic
fracturing. On June 4, 2015, the EPA issued a draft assessment of potential impacts to drinking water resources from hydraulic
fracturing. The draft report did not find widespread impacts to drinking water from hydraulic fracturing. The EPA’s inspector
general released a report on July 16, 2015 recommending increased EPA oversight of permit issuances as well as the chemicals used
in hydraulic fracturing. The United States Department of Energy is also actively involved in research on hydraulic fracturing practices,
including groundwater protection.
On March 26, 2015, the Bureau of Land Management
(“BLM”) published a final rule governing hydraulic fracturing on federal and Indian lands, including private surface
lands with underlying federal minerals. The rule was scheduled to become effective on June 24, 2015, but was temporarily stayed
by a federal court. The rule requires public disclosure of chemicals used in hydraulic fracturing on federal and Indian lands,
confirmation that wells used in hydraulic fracturing operations meet certain construction standards, development of appropriate
plans for managing flowback water that returns to the surface, heightened standards for interim storage of recovered waste fluids,
and submission of detailed information to the BLM regarding the geology, depth and location of pre-existing wells. Several states,
tribes, and industry groups filed several pending lawsuits challenging the rule and the BLM’s authority to regulate hydraulic
fracturing. In February 2016 the U.S. District Court in Wyoming issued a preliminary injunction staying implantation of BLM’s
hydraulic fracturing regulations. BLM has appealed the preliminary injunction to the Tenth Circuit Court of Appeals. The outcome
of this litigation is uncertain. If the rule becomes effective, we expect to incur additional costs to comply with such requirements
that may be significant in nature, and we could experience delays or even curtailment in the pursuit of hydraulic fracturing activities
in certain wells. The rule could also affect drilling units that include both private and federal mineral resources.
Legislation has been introduced before
Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic
fracturing process. If hydraulic fracturing becomes regulated at the federal level, our fracturing activities could become subject
to additional permit or disclosure requirements, associated permitting delays, operational restrictions, litigation risk, and potential
cost increases. Additionally, certain members of Congress have called upon the United States Government Accountability Office to
investigate how hydraulic fracturing might adversely affect water resources, the SEC to investigate the natural gas industry and
any possible misleading of investors or the public regarding the economic feasibility of pursuing natural gas deposits in shales
by means of hydraulic fracturing, and the United States Energy Information Administration to provide a better understanding of
that agency’s estimates regarding natural gas reserves, including reserves from shale formations, as well as uncertainties
associated with those estimates. The United States Geological Survey Offices of Energy Resources Program, Water Resources and Natural
Hazards and Environmental Health Offices also have ongoing research projects on hydraulic fracturing. These ongoing studies, depending
on their course and outcomes, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory
processes.
Further, on August 16, 2012, the EPA issued
final rules subjecting all new and modified oil and gas operations (production, processing, transmission, storage, and distribution)
to regulation under the New Source Performance Standards (“NSPS”) and all existing and new operations to the National
Emission Standards for Hazardous Air Pollutants (“NESHAP”) programs. The EPA rules also include NSPS standards for
completions of hydraulically fractured gas wells. These standards require the use of reduced emission completion (“REC”)
techniques developed in the EPA’s Natural Gas STAR program along with the pit flaring of gas not sent to the gathering line
beginning in January 2015. The standards are applicable to newly drilled and fractured wells as well as existing wells that are
refractured. Further, the regulations under NESHAP include maximum achievable control technology (“MACT”) standards
for those glycol dehydrators and certain storage vessels at major sources of hazardous air pollutants not currently subject to
MACT standards. These rules will require additional control equipment, changes to procedure, and extensive monitoring and reporting.
The EPA stated in January 2013, however, that it intends to reconsider portions of the final rule. On September 23, 2013, the EPA
published new standards for storage tanks subject to the NSPS. In December 2014, the EPA finalized additional updates to the 2012
NSPS. The amendments clarified stages for flowback and the point at which green completion equipment is required and updated requirements
for storage tanks and leak detection requirements for processing plants. The EPA has stated that it continues to review other issues
raised in petitions for reconsideration.
On December 17, 2014, the EPA proposed
to revise and lower the existing 75 ppb National Ambient Air Quality Standard (“NAAQS”) for ozone under the federal
Clean Air Act to a range within 65-70 ppb. On October 1, 2015, EPA finalized a rule that lowered the standard to 70 ppb. This lowered
ozone NAAQS could result in an expansion of ozone nonattainment areas across the United States, including areas in which we operate.
Oil and gas operations in ozone nonattainment areas likely would be subject to more stringent emission controls, emission offset
requirements for new sources, and increased permitting delays and costs. This could require a number of modifications to our operations,
including the installation of new equipment to control emissions from our wells. Compliance with such rules could result in significant
costs, including increased capital expenditures and operating costs, and could adversely impact our business.
The EPA also has initiated a stakeholder
and potential rulemaking process under the Toxic Substances Control Act (“TSCA”) to obtain data on chemical substances
and mixtures used in hydraulic fracturing. The EPA has not indicated when it intends to issue a proposed rule, but it issued an
Advanced Notice of Proposed Rulemaking in May 2014, seeking public comment on a variety of issues related to the TSCA rulemaking.
Increased regulation and attention given
to the hydraulic fracturing process could lead to greater opposition, including litigation, to oil and gas production activities
using hydraulic fracturing techniques. Disclosure of chemicals used in the hydraulic fracturing process could make it easier for
third parties opposing such activities to pursue legal proceedings against producers and service providers based on allegations
that specific chemicals used in the fracturing process could adversely affect human health or the environment, including groundwater.
Over the past few years, several court cases have addressed aspects of hydraulic fracturing. In a case that could delay operations
on public lands, a court in California held that the BLM did not adequately consider the impact of hydraulic fracturing and horizontal
drilling before issuing leases. Courts in New York and Colorado reduced the level of evidence required before a court will agree
to consider alleged damage claims from hydraulic fracturing by property owners. Litigation resulting in financial compensation
for damages linked to hydraulic fracturing, including damages from induced seismicity, could spur future litigation and bring increased
attention to the practice of hydraulic fracturing. Judicial decisions could also lead to increased regulation, permitting requirements,
enforcement actions, and penalties. Additional legislation or regulation could also lead to operational delays or restrictions
or increased costs in the exploration for, and production of, oil, natural gas, and associated liquids, including from the development
of shale plays, or could make it more difficult to perform hydraulic fracturing. The adoption of additional federal, state, or
local laws, or the implementation of new regulations, regarding hydraulic fracturing could potentially cause a decrease in the
completion of new oil and gas wells, or an increase in compliance costs and delays, which could adversely affect our financial
position, results of operations, and cash flows.
Requirements to reduce gas flaring could have an adverse
effect on our operations.
Wells in the Bakken and Three Forks formations
in North Dakota, where we have significant operations, produce natural gas as well as crude oil. Constraints in the current gas
gathering and processing network in certain areas have resulted in some of that natural gas being flared instead of gathered, processed
and sold. In June 2014, the North Dakota Industrial Commission, North Dakota’s chief energy regulator, adopted a policy to
reduce the volume of natural gas flared from oil wells in the Bakken and Three Forks formations. The Commission is requiring operators
to develop gas capture plans that describe how much natural gas is expected to be produced, how it will be delivered to a processor
and where it will be processed. Production caps or penalties will be imposed on certain wells that cannot meet the capture goals.
In addition, oil and gas projects are subject
to extensive permitting requirements. Failure to timely obtain required permits to start operations at a project could cause delay
and/or the failure of the project resulting in a potential write-off of the investments made.
Our ability to produce crude oil,
natural gas, and associated liquids economically and in commercial quantities could be impaired if we are unable to acquire adequate
supplies of water for our drilling operations and/or completions or are unable to dispose of or recycle the water we use at a reasonable
cost and in accordance with applicable environmental rules.
The hydraulic fracturing process on which
we and others in our industry depend to complete wells that will produce commercial quantities of crude oil, natural gas, and NGLs
requires the use and disposal of significant quantities of water. Our inability to secure sufficient amounts of water, or to dispose
of or recycle the water used in our operations, could adversely impact our operations. Moreover, the imposition of new environmental
initiatives and regulations could include restrictions on our ability to conduct certain operations such as hydraulic fracturing
or disposal of wastes, including, but not limited to, produced water, drilling fluids, and other wastes associated with the exploration,
development, or production of crude oil, natural gas, and NGLs.
Compliance with environmental regulations
and permit requirements governing the withdrawal, storage, and use of surface water or groundwater necessary for hydraulic fracturing
of wells may increase our operating costs and cause delays, interruptions, or termination of our operations, the extent of which
cannot be predicted, all of which could have an adverse effect on our operations and financial condition.
Legislative and regulatory initiatives
related to global warming and climate change could have an adverse effect on our operations and the demand for crude oil, natural
gas, and NGLs
In December 2009, the EPA made a finding
that emissions of carbon dioxide, methane, and other “greenhouse gases” endanger public health and the environment
because emissions of such gases contribute to warming of the earth’s atmosphere and other climatic changes. Based on this
finding, the EPA has adopted and implemented a comprehensive suite of regulations to restrict and otherwise regulate emissions
of greenhouse gases under existing provisions of the CAA. In particular, the EPA has adopted two sets of rules regulating greenhouse
gas emissions under the CAA. One rule requires a reduction in greenhouse gas emissions from motor vehicles, and the other regulates
permitting and greenhouse gas emissions from certain large stationary sources. These EPA regulatory actions have been challenged
by various industry groups, initially in the D.C. Circuit, which in 2012 ruled in favor of the EPA in all respects. However, in
June 2014, the United States Supreme Court reversed the D.C. Circuit and struck down the EPA’s greenhouse gas permitting
rules to the extent they impose a requirement to obtain a permit based solely on emissions of greenhouse gases. As a result of
that ruling, large sources of air pollutants other than greenhouse gases would still be required to implement the best available
capture technology for greenhouse gases. The EPA has also adopted reporting rules for greenhouse gas emissions from specified greenhouse
gas emission sources in the United States, including petroleum refineries as well as certain onshore oil and gas extraction and
production facilities.
Several other kinds of cases on greenhouse
gases have been heard by the courts in recent years. While courts have generally declined to assign direct liability for climate
change to large sources of greenhouse gas emissions, some have required increased scrutiny of such emissions by federal agencies
and permitting authorities. There is a continuing risk of claims being filed against companies that have significant greenhouse
gas emissions, and new claims for damages and increased government scrutiny will likely continue. Such cases often seek to challenge
air emissions permits that greenhouse gas emitters apply for, seek to force emitters to reduce their emissions, or seek damages
for alleged climate change impacts to the environment, people, and property. Any court rulings, laws or regulations that restrict
or require reduced emissions of greenhouse gases could lead to increased operating and compliance costs, and could have an adverse
effect on demand for the oil and gas that we produce.
Seasonal weather conditions adversely
affect our ability to conduct drilling activities in some of the areas where we operate.
Oil and gas operations in the Williston
Basin and the Gulf Coast can be adversely affected by seasonal weather conditions. In the Williston Basin, drilling and other oil
and gas activities sometimes cannot be conducted as effectively during the winter months, and this can materially increase our
operating and capital costs. Gulf Coast operations are also subject to the risk of adverse weather events, including hurricanes.
Shortages of equipment, services
and qualified personnel could reduce our cash flow and adversely affect results of operations.
The demand for qualified and experienced
field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the
oil and gas industry can fluctuate significantly, often in correlation with oil and gas prices and activity levels in new regions,
causing periodic shortages. These problems can be particularly severe in certain regions such as the Williston Basin and Texas.
During periods of high oil and gas prices, the demand for drilling rigs and equipment tends to increase along with increased activity
levels, and this may result in shortages of equipment. Higher oil and gas prices generally stimulate increased demand for equipment
and services and subsequently often result in increased prices for drilling rigs, crews and associated supplies, oilfield equipment
and services, and personnel in exploration, production and midstream operations. These types of shortages and subsequent price
increases could significantly decrease our profit margin, cash flow and operating results and/or restrict or delay our ability
to drill those wells and conduct those activities that we currently have planned and budgeted, causing us to miss our forecasts
and projections.
We depend on key personnel.
Our Chief Executive Officer (one of only
two employees) has experience in dealing with the acquisition of and financing of oil and gas properties. We rely extensively on
third party consultants for accounting, legal, professional engineering, geophysical and geological advice in oil and gas matters.
The loss of key personnel such as our Chief Executive Officer could adversely impact our business, as finding replacements could
be difficult as a result of competition for experienced personnel.
Risks Related to Our Stock
We have issued shares of Series A
Preferred Stock with rights superior to those of our common stock.
Our articles of incorporation authorize
the issuance of up to 100,000 shares of preferred stock, $0.01 par value. Shares of preferred stock may be issued with
such dividend, liquidation, voting and conversion features as may be determined by the Board of Directors without shareholder approval. Pursuant
to this authority, in February 2016 we approved the designation of 50,000 shares of Series A Convertible Preferred Stock (“Series
A Preferred”) in connection with the disposition of our mining segment.
The Series A Preferred accrues dividends
at a rate of 12.25% per annum of the Adjusted Liquidation Preference; such dividends are not payable in cash but are accrued and
compounded quarterly in arrears. The “Adjusted Liquidation Preference” is initially $40 per share of Series A Preferred
for an aggregate of $2.0 million, with increases each quarter by the accrued quarterly dividend. The Series A Preferred is senior
to other classes or series of shares of the Company with respect to dividend rights and rights upon liquidation. No dividend or
distribution will be declared or paid on our common stock, (i) unless approved by the holders of Series A Preferred and (ii) unless
and until a like dividend has been declared and paid on the Series A Preferred on an as-converted basis.
At the option of the holder, each share
of Series A Preferred may initially be converted into 13.33 shares of our common stock (the “Conversion Rate”) for
an aggregate of 666,667 shares. The Conversion Rate is subject to anti-dilution adjustments for stock splits, stock dividends and
certain reorganization events and to price-based anti-dilution protections. Each share of Series A Preferred will be convertible
into a number of shares of common stock equal to the ratio of the initial conversion value to the conversion value as adjusted
for accumulated dividends multiplied by the Conversion Rate. In no event will the aggregate number of shares of common stock issued
upon conversion be greater than 793,349 shares. The Series A Preferred will generally not vote with our common stock on an as-converted
basis on matters put before our shareholders. The holders of the Series A Preferred have the right to require us to repurchase
the Series A Preferred in connection with a change of control. The dividend, liquidation and other rights provided to holders of
the Series A Preferred will make it more difficult for holders of common stock to realize value from their investment.
Future equity transactions and exercises of outstanding
options or warrants could result in dilution.
From time to time, we have sold common
stock, warrants, convertible preferred stock and convertible debt to investors in private placements and public offerings. These
transactions caused dilution to existing shareholders. Also, from time to time, we issue options and warrants to employees, directors
and third parties as incentives, with exercise prices equal to the market price at the date of issuance. During 2016, we also granted
shares of restricted common stock that are subject to issuance upon future vesting events. Vesting of restricted common stock and
exercise of options and warrants would result in dilution to existing shareholders. Future issuances of equity securities, or securities
convertible into equity securities, would also have a dilutive effect on existing shareholders. In addition, the perception that
such issuances may occur could adversely affect the market price of our common stock.
We do not intend to declare dividends on our common stock.
We do not intend to declare dividends on
our common stock in the foreseeable future. Under the terms of our Series A Preferred Stock, we are prohibited from paying dividends
on our common stock without the approval of the holders of the Series A Preferred Stock. Accordingly, our common shareholders must
look solely to increases in the price of our common stock to realize a gain on their investment, and this may not occur.
We could implement take-over defense
mechanisms that could discourage some advantageous transactions.
Although our shareholder rights plan expired
in 2011, certain provisions of our governing documents and applicable law could have anti-takeover effects. For example, we are
subject to a number of provisions of the Wyoming Management Stability Act, an anti-takeover statute, and have a classified or “staggered”
board. We could implement additional anti-takeover defenses in the future. These existing or future defenses could prevent or discourage
a potential transaction in which shareholders would receive a takeover price in excess of then-current market values, even if a
majority of the shareholders support such a transaction.
Our stock price likely will continue
to be volatile.
Our stock is traded on the Nasdaq Capital
Market. In the two years ended December 31, 2016, our common stock has traded as high as $2.84 per share and as low as $0.11 per
share. We expect our common stock will continue to be subject to fluctuations as a result of a variety of factors, including factors
beyond our control. These factors include:
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price volatility in the oil and gas commodities markets;
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variations in our drilling, recompletion and operating activity;
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relatively small amounts of our common stock trading on any given day;
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additions or departures of key personnel;
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legislative and regulatory changes; and
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changes in the national and global economic outlook.
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The stock market has recently experienced
significant price and volume fluctuations, and oil and gas prices have declined significantly. These fluctuations have particularly
affected the market prices of securities of oil and gas companies like ours.
If our common
stock is delisted from the NASDAQ Capital Market, its liquidity and value could be reduced.
In
order for us to maintain the listing of our shares of common stock on the NASDAQ Capital Market®, the common stock must maintain
a minimum bid price of $1.00 as set forth in NASDAQ Marketplace Rule 5550(a)(2). If the closing bid price of the common stock
is below $1.00 for 30 consecutive trading days, then the closing bid price of the common stock must be $1.00 or more for 10 consecutive
trading days during a 180-day grace period to regain compliance with the rule. We cannot guarantee that we will be able to
remain in compliance with the minimum price requirement within the grace period or satisfy other continued listing requirements.
If our common stock is delisted from trading on the NASDAQ Capital Market, it may be eligible for trading over the counter, but
the delisting of our common stock from NASDAQ could adversely impact the liquidity and value of our common stock. On March 27,
2017, we were given notice by the NASDAQ Capital Market that the closing price of our common stock has traded below $1.00 for 30
consecutive days. We have 180 calendar days to return to compliance.