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Item 1A. Risk Factors

2021-03-12 compared with 2020-03-12 · 297 added, 371 removed, 188 unchanged (78% of the section changed)

Risks Related to Our Business and the Oil, Natural Gas and NGL Industry

Our business and operations have been and will likely continue to be adversely affected by the recent COVID-19 pandemic.

The spread of COVID-19 caused, and is continuing to cause, severe disruptions in the worldwide and U.S.

economy, including the global and domestic decreased demand for oil and natural gas, which has had an adverse effect on our business, financial condition and results of operations.

Moreover, since the beginning of January 2020, the COVID-19 pandemic has caused significant disruption in the financial markets both globally and in the United States.

The continued spread of COVID-19 could also negatively impact the availability of key personnel and adequate staffing for us and our operating partners to conduct business.

If COVID-19 continues to spread or the response to contain the COVID-19 pandemic is unsuccessful, we could continue to experience a material adverse effect on our business, financial condition and results of operations.

The duration and extent to which the COVID-19 crisis and oil price volatility adversely affects our business, financial condition and results of operations will depend on future developments, which are highly uncertain and cannot be predicted, including the scope and duration of the pandemic and actions taken by foreign and domestic governmental authorities and other third parties in response.

Volatility in commodity prices has had an adverse impact on our financial condition and results of operations, and on the level at which we are able to hedge our anticipated future production, which could continue to materially and adversely affect us, and we cannot predict the ultimate impact of this situation on our business, financial condition and results of operations.

The foregoing has had, and we expect will continue to have, an adverse effect on our business, financial condition, liquidity and results of operations.

These factors will likely have the effect of heightening many of the other risks described in this “Risk Factors” section.

Without limiting the generality of the foregoing, some impacts of the COVID-19 pandemic and recent oil market developments that could have an adverse effect on our business, financial condition, liquidity and results of operations, include:

• significantly reduced prices for our oil production, resulting from a world-wide decrease in demand for hydrocarbons and a resulting oversupply of existing production;

• further decreases in the demand for our oil production, resulting from significantly decreased levels of global, regional and local travel as a result of federal, state and local government-imposed quarantines, including shelter-in-place mandates, enacted to slow the spread of the coronavirus;

• significantly reduced development activity on our properties by operators in the Willison Basin;

• increased likelihood that the operators of our wells will curtail or shut-in production, either voluntarily or as a result of third-party and regulatory mandates, due to depressed oil prices, lack of storage, and/or other market, social, legal, or political forces;

• increased costs associated with, or actual unavailability of, facilities for the storage of oil, gas and NGL production, in the markets in which we operate;

• increased operational difficulties associated with, or an inability to, deliver oil and NGLs to end-markets, resulting from pipeline and storage constraints;

• the potential for loss of leasehold or asset value for failure to produce oil and gas in paying quantities;

• increased third-party credit risk resulting from adverse market conditions, a lack of access to capital and storage, and the failure of certain of our counterparties to continue as going concerns;

• increased costs, either directly or indirectly, related to facility modifications, social distancing measures or other best practices implemented in response to the COVID-19 pandemic and or due to changes in federal, state, and local laws and regulations;

• reducing estimated volumes and value attributable to our proved reserves;

• reducing carrying value of our oil and gas properties due to recognizing impairments on such properties;

• limiting access to, or increasing the cost of, sources of capital such as equity and long-term debt.

In addition, the COVID-19 pandemic and recent commodity market developments may also affect our business, operations or financial condition in a manner that is not presently known to us or that we currently do not expect to present a significant risk to our business, operations or financial condition.

Oil and natural gas prices are volatile.

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Oil and natural gas prices have fluctuated significantly, including periods of rapid and material decline, in recent years.

The prices we receive for our oil and natural gas production heavily influences our revenue, cash flows, profitability, access to capital and future rate of growth.

Although we seek to mitigate volatility and potential declines in oil prices through derivative arrangements that hedge a portion of our expected production, this merely seeks to mitigate (not eliminate) these risks, and such activities come with their own risks.

The prices we receive for our oil and natural gas production heavily influences our production, revenue, cash flows, profitability, reserve bookings and access to capital.

Although we seek to mitigate volatility and potential declines in commodity prices through derivative arrangements that hedge a portion of our expected production, this merely seeks to mitigate (not eliminate) these risks, and such activities come with their own risks.

The prices we receive for our production and the levels of our production depend on numerous factors beyond our control.

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• political and economic conditions, including embargoes, in oil-producing countries or affecting other oil-producing activity;

• the level of global oil and natural gas exploration and production activity;

• the level of global oil and natural gas inventories;

• the level of global oil and natural gas exploration, production activity and inventories;

• changes in U.S.

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These factors and the volatility of the energy markets make it extremely difficult to predict oil and natural gas prices.

Lower oil and natural gas prices have in the past and may in the future adversely affect our revenues, the amount of oil and natural gas that our operators can produce economically, and our reserve bookings.

A substantial or extended decline in oil or natural gas prices, such as the rapid decline that began in late 2014, has resulted in and could result in future impairments of our proved oil and natural gas properties and may materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures.

A substantial or extended decline in oil or natural gas prices, such as the significant and rapid decline that occurred in 2020, has resulted in and could result in future impairments of our proved oil and natural gas properties and may materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures.

To the extent commodity prices received from production are insufficient to fund planned capital expenditures, we may be required to reduce spending or borrow or issue additional equity to cover any such shortfall.

Lower oil and natural gas prices may limit our ability to comply with the covenants under our revolving credit facility (or other debt instruments) and/or limit our ability to access borrowing availability thereunder, which is dependent on many factors including the value of our proved reserves.

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Our estimated reserves are based on many assumptions that may prove to be inaccurate.

Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

Determining the amount of oil and natural gas recoverable from various formations involves significant complexity and uncertainty.

No one can measure underground accumulations of oil or natural gas in an exact way.

Oil and natural gas reserve engineering requires subjective estimates of underground accumulations of oil and/or natural gas and assumptions concerning future oil and natural gas prices, production levels, and operating, exploration and development costs.

Some of our reserve estimates are made without the benefit of a lengthy production history and are less reliable than estimates based on a lengthy production history.

As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may prove to be inaccurate.

We routinely make estimates of oil and natural gas reserves in connection with managing our business and preparing reports to our lenders and investors.

We make these reserve estimates using various assumptions, including assumptions as to oil and natural gas prices, development schedules, drilling and operating expenses, capital expenditures, taxes and availability of funds.

Some of these assumptions are inherently subjective, and the accuracy of our reserve estimates relies in part on the ability of our management team, reserve engineers and other advisors to make accurate assumptions.

Any significant variance from these assumptions by actual figures could greatly affect our estimates of reserves, the economically recoverable quantities of oil, natural gas and NGLs attributable to any particular group of properties, the classifications of reserves based on risk of recovery, and estimates of the future net cash flows.

Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, often result in the actual quantities of oil, natural gas and NGLs we ultimately recover being different from our reserve estimates.

Any significant variance could materially affect the estimated quantities and present value of reserves shown in this Annual Report on Form 10-K, subsequent reports we file with the SEC or other company materials.

In addition, we may adjust estimates of net proved reserves to reflect production history, changes in operating costs, results of exploration and development, prevailing oil and natural gas prices and any other factors, many of which are beyond our control.

Drilling for and producing oil, natural gas and NGLs are high risk activities with many uncertainties that could adversely affect our financial condition or results of operations.

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In addition, drilling and producing operations on our acreage may be curtailed, delayed or canceled by our operators as a result of other factors, including:

• declines in oil or natural gas prices;

• declines in oil or natural gas prices, as occurred in 2020 in connection with the COVID-19 pandemic;

• infrastructure limitations, such as the gas gathering and processing constraints experienced in the Williston Basin in 2019;

• the high cost, shortages or delivery delays of equipment and services;

• shortages of or delays in obtaining water for hydraulic fracturing operations;

• unexpected operational events;

• adverse weather conditions;

• facility or equipment malfunctions;

• title problems;

• pipeline ruptures or spills;

• the high cost, shortages or delays of equipment, materials and services;

• unexpected operational events, pipeline ruptures or spills, adverse weather conditions, facility malfunctions or title problems;

• compliance with environmental and other governmental requirements;

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• unusual or unexpected geological formations;

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• loss of drilling fluid circulation;

• formations with abnormal pressures;

• environmental hazards, such as oil, natural gas or well fluids spills or releases, pipeline or tank ruptures and discharges of toxic gas;

• blowouts, craterings and explosions;

• fires, blowouts, craterings and explosions;

• uncontrollable flows of oil, natural gas or well fluids;

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We may be required to record further writedowns of our oil and natural gas properties.

In 2015 and 2016 we were required to write down the carrying value of certain of our oil and natural gas properties, and further writedowns could be required in the future.

Writedowns may occur when oil and natural gas prices are low, or if we have downward adjustments to our estimated proved reserves, increases in our estimates of operating or development costs, deterioration in drilling results or mechanical problems with wells where the cost to redrill or repair is not supported by the expected economics.

In 2020, we were required to write down the carrying value of certain of our oil and natural gas properties, and further writedowns could be required in the future.

Under the full cost method of accounting, capitalized oil and gas property costs less accumulated depletion and net of deferred income taxes may not exceed an amount equal to the present value, discounted at 10%, of estimated future net revenues from proved oil and gas reserves plus the cost of unproved properties not subject to amortization (without regard to estimates of fair value), or estimated fair value, if lower, of unproved properties that are subject to amortization.

Should capitalized costs exceed this ceiling, an impairment would be recognized.

Our company did not record any impairments during 2017, 2018 or 2019, but if a lower pricing environment reoccurs we could be required to further write down the value of our oil and natural gas properties.

If lower average monthly pricing is reflected in the trailing twelve-month average pricing calculation, the present value of our future net revenues could decline and one or more impairments could be recognized.

The quarterly ceiling test considers many factors including reserves, capital expenditure estimates and trailing twelve-month average prices.

SEC defined prices for each quarter in 2019 were as follows:

SEC Defined Prices for 12 Months Ended NYMEX Oil

(per Bbl) Henry Hub Gas Price

December 31, 2019 $ 55.69 $ 2.58

September 30, 2019 57.77 2.87

June 30, 2019 61.39 3.02

March 31, 2019 63.00 3.07

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Any significant reduction in our borrowing base under our revolving credit facility, and any limit on our ability to comply with the covenants thereunder, will negatively impact our liquidity and, consequently, our ability to fund our operations, and we may not have sufficient funds to repay borrowings under our revolving credit facility or any other obligation if required as a result of a borrowing base reduction.

Availability under our revolving credit facility is subject to a borrowing base, with scheduled semiannual (April 1 and October 1) and other elective borrowing base redeterminations based upon, among other things, projected revenues from, and asset values of, the oil and natural gas properties securing the revolving credit facility.

The lenders under the revolving credit facility can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under our revolving credit facility.

Our revolving credit facility includes covenants that require the ratio of (a) our Total Net Debt (as defined therein) to (b) EBITDAX (as defined therein), to not exceed 3.50 to 1.00 and (ii) the ratio of Current Assets (as defined therein) to Current Liabilities (as defined therein) to be greater than or equal to 1.00 to 1.00, in each case, as of the last day of any fiscal quarter.

Reductions in estimates of our producing oil, NGL and natural gas reserves could result in a reduction of our borrowing base thereunder.

The same could also arise from other factors, including but not limited to:

• lower commodity prices or production;

• inability to drill or unfavorable drilling results;

• changes in crude oil, NGL and natural gas reserve engineering;

• increased operating and/or capital costs.

As of December 31, 2019, we had $580.0 million of borrowings outstanding under our revolving credit facility.

We expect to make further borrowings under our revolving credit facility in the future.

Any significant reduction in our borrowing base could result in a default under current and/or future debt instruments, negatively impact our liquidity and our ability to fund our operations and, as a result, could have a material adverse effect on our financial position, results of operation and cash flow.

Further, if the outstanding borrowings under our revolving credit facility were to exceed the borrowing base as a result of any such redetermination, we could be required to repay the excess.

If we do not have sufficient funds and we are otherwise unable to arrange new financing, we may have to sell significant assets.

Any such sale could have a material adverse effect on our business and financial results.

Depending on future commodity price levels, the trailing twelve-month average price used in the ceiling calculation may decline, which could cause additional future write downs of our oil and natural gas properties.

In addition to commodity prices, our production rates, levels of proved reserves, future development costs, transfers of unevaluated properties and other factors will determine our actual ceiling test calculation and impairment analysis in future periods.

Our estimated reserves are based on many assumptions that may prove to be inaccurate.

Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

Determining the amount of oil and natural gas recoverable from various formations involves significant complexity and uncertainty.

No one can measure underground accumulations of oil or natural gas in an exact way.

Some of our reserve estimates are made without the benefit of a lengthy production history and are less reliable than estimates based on a lengthy production history.

As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may prove to be inaccurate.

We routinely make estimates of oil and natural gas reserves in connection with managing our business and preparing reports to our lenders and investors.

Numerous changes over time to the assumptions on which our reserve estimates are based result in the actual quantities of oil, natural gas and NGLs we ultimately recover being different from our reserve estimates.

Our future success depends on our ability to replace reserves that our operators produce.

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We have added significant net wells and production from wellbore-only acquisitions, where we don’t hold the underlying leasehold interest that would entitle us to participate in future wells.

For example, our Pivotal Acquisition in 2018 consisted primarily of producing wellbore interests without associated future development rights.

Future oil and natural gas production, therefore, is highly dependent upon our level of success in acquiring or finding additional reserves that are economically recoverable.

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Additionally, we cannot assure you that unproved reserves or undeveloped acreage that we acquire will be profitably developed, that new wells drilled on our properties will be productive or that we will recover all or any portion of our investments in our properties and reserves.

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As a non-operator, our development of successful operations relies extensively on third-parties, which could have a material adverse effect on our results of operation.

We have only participated in wells operated by third parties.

The success of our business operations depends on the timing of drilling activities and success of our third-party operators.

If our operators are not successful in the development, exploitation, production and exploration activities relating to our leasehold interests, or are unable or unwilling to perform, our financial condition and results of operation would be materially adversely affected.

These risks are heightened in a low commodity price environment, which may present significant challenges to our operators.

The challenges and risks faced by our operators may be similar to or greater than our own, including with respect to their ability to service their debt, remain in compliance with their debt instruments and, if necessary, access additional capital.

Certain oil and gas operators filed for bankruptcy as a result of the low commodity price environment that began in 2014 and a challenging industry environment (including low commodity prices) could result in additional operators being forced into bankruptcy.

The insolvency of an operator of any of our properties, the failure of an operator of any of our properties to adequately perform operations or an operator’s breach of applicable agreements could reduce our production and revenue and result in our liability to governmental authorities for compliance with environmental, safety and other regulatory requirements, to the operator’s suppliers and vendors and to royalty owners under oil and gas leases jointly owned with the operator or another insolvent owner.

Finally, an operator of our properties may have the right, if another non-operator fails to pay its share of costs because of its insolvency or otherwise, to require us to pay our proportionate share of the defaulting party’s share of costs.

Our operators will make decisions in connection with their operations (subject to their contractual and legal obligations to other owners of working interests), which may not be in our best interests.

Additionally, we may have virtually no ability to exercise influence over the operational decisions of our operators, including the setting of capital expenditure budgets and drilling locations and schedules.

Dependence on our operators could prevent us from realizing our target returns for those locations.

The success and timing of development activities by our operators will depend on a number of factors that will largely be outside of our control, including:

• oil and natural gas prices and other factors generally affecting industry operating environment;

• the timing and amount of capital expenditures;

• their expertise and financial resources;

• approval of other participants in drilling wells;

• selection of technology;

• the rate of production of reserves, if any.

We could experience periods of higher costs as activity levels in the Williston Basin fluctuate or if commodity prices rise.

These increases could reduce our profitability, cash flow, and ability to complete development activities as planned.

An increase in commodity prices or other factors could result in increased activity and investment in the Williston Basin.

As a result of increased activity in the Williston Basin, competition for equipment, labor and supplies would also be expected to increase.

Likewise, higher oil, natural gas and NGL prices generally increase the demand for equipment, labor and supplies, and can lead to shortages of, and increasing costs for, drilling equipment, services and personnel.

Shortages of, or increasing costs for, experienced drilling crews and equipment and services could restrict our operating partners’ ability to drill the wells and conduct the operations that we currently expect.

In addition, capital and operating costs in the oil and natural gas industry have generally risen during periods of increasing commodity prices as producers seek to increase production in order to capitalize on higher commodity prices.

In situations where cost inflation exceeds commodity price inflation, our profitability and cash flow, and our operators’ ability to complete development activities as scheduled and on budget, may be negatively impacted.

Any delay in the drilling of new wells or significant increase in drilling costs could reduce our revenues and cash flows.

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Our lack of industry and geographical diversification may increase the risk of an investment in our company.

Our business focus is on the oil and natural gas industry in properties that are primarily in the areas of the Williston Basin located in Montana and North Dakota.

While other companies may have the ability to manage their risk by diversification, the narrow focus of our business, in terms of both the industry focus and geographic scope of our business, means that we will likely be impacted more acutely by factors affecting our industry or the region in which we operate than we would if our business were more diversified.

As a result of the narrow focus of our business, we may be disproportionately exposed to the effects of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, market limitations, weather events or interruption of the processing or transportation of oil or natural gas.

Additionally, we may be exposed to further risks, such as changes in field-wide rules and regulations that could cause us to permanently or temporarily shut-in all of our wells within the Williston Basin.

Locations that the operators of our properties decide to drill may not yield oil or natural gas in commercially viable quantities.

The cost of drilling, completing and operating a well is often uncertain, and cost factors can adversely affect the economics of a well.

Our efforts will be uneconomical if the operators of our properties drill dry holes or wells that are productive but do not produce enough to be commercially viable after drilling, operating and other costs.

If the operators of our properties drill future wells that are identified as dry holes, the drilling success rate would decline and may adversely affect our results of operations.

To the extent we are unable to obtain future hedges at attractive prices or our derivative activities are not effective, our cash flows and financial condition may be adversely impacted.

To achieve more predictable cash flows and reduce our exposure to adverse fluctuations in the price of oil, we enter into derivative instrument contracts for a portion of our expected oil production, which may include swaps, collars, puts and other structures.

In accordance with applicable accounting principles, we are required to record our derivatives at fair market value, and they are included on our balance sheet as assets or liabilities and in our statements of income as gain (loss) on derivatives, net.

Accordingly, our earnings may fluctuate significantly as a result of changes in the fair market value of our derivative instruments.

Our derivatives activities could result in financial losses or could reduce our cash flow.

We enter into swaps, collars or other derivatives arrangements from time to time to hedge our expected production depending on projected production levels and expected market conditions.

While intended to mitigate the effects of volatile oil and natural gas prices, such transactions may limit our potential gains and increase our potential losses if oil and natural gas prices were to rise substantially over the price established by the hedge.

Our actual future production may be significantly higher or lower than we estimate at the time we enter into derivative contracts for such period.

If the actual amount of production is higher than we estimate, 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 financial 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.

In addition, such transactions may expose us to the risk of loss in certain circumstances, including instances in which:

• a counterparty to our derivative contracts is unable to satisfy its obligations under the contracts;

• our production is less than expected;

• there is a widening of price differentials between delivery points for our production and the delivery point assumed in the derivative arrangement.

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Our ability to use net operating loss carryforwards to offset future taxable income may be subject to certain limitations.

We have net operating loss (“NOL”) carryforwards that we may use to offset against taxable income for U.S.

federal income tax purposes.

At December 31, 2019, we had an estimated NOL carryforward of approximately $341.7 million for United States federal income tax purposes.

In general, under Section 382 of the Internal Revenue Code of 1986, as amended (the “IRC”), a corporation that undergoes an “ownership change” can be subject to limitations on the use of its NOLs to offset future taxable income.

We underwent an “ownership change” during 2018 and, as a result, the use of our existing NOL carryforwards are subject to limitations under Section 382, which are generally determined by multiplying the value of our stock at the time of the ownership change by the applicable long term tax exempt rate as defined in Section 382.

See Note 10 to our financial statements.

Future changes in our stock ownership, some of which are outside of our control, could result in an additional ownership change under Section 382 of the IRC.

Changes in United States federal income tax law may have an adverse effect on our cash flows, results of operations or financial condition overall.

On December 22, 2017, the President signed into law Public Law No.

115-97, a comprehensive tax reform bill commonly referred to as the Tax Cuts and Jobs Act (the “Act”) that significantly reformed the IRC.

The Act, among other things, (i) reduces the U.S.

corporate income tax rate, (ii) repeals the corporate alternative minimum tax, (iii) eliminates the deduction for certain domestic production activities, (iv) imposes new limitations on the utilization of net operating losses, and (v) provides for more general changes to the taxation of corporations, including changes to cost recovery rules and to the deductibility of interest expense, which may impact the taxation of oil and gas companies.

The Act is complex and far-reaching and we cannot predict with certainty the resulting impact its enactment has on us.

The ultimate impact of the Act may differ from our estimates due to changes in interpretations and assumptions made by us as well as additional regulatory guidance that may be issued and any such changes in interpretations or assumptions could adversely affect our business and financial condition.

See Note 10 to our financial statements.

federal income tax deductions currently available with respect to natural gas and oil exploration and development may be eliminated as a result of future legislation.

In past years, legislation has been proposed that would, if enacted into law, make significant changes to U.S.

tax laws, including certain key U.S.

federal income tax provisions currently available to oil and gas companies.

Such legislative changes have included, but not been limited to, (i) the repeal of the percentage depletion allowance for natural gas and oil properties, (ii) the elimination of current deductions for intangible drilling and development costs, and (iii) an extension of the amortization period for certain geological and geophysical expenditures.

Although these provisions were largely unchanged in the Tax Act, Congress could consider, and could include, some or all of these proposals as part of future tax reform legislation.

Moreover, other more general features of any additional tax reform legislation, including changes to cost recovery rules, may be developed that also would change the taxation of oil and gas companies.

It is unclear whether these or similar changes will be enacted in future legislation and, if enacted, how soon any such changes could take effect.

The passage of any legislation as a result of these proposals or any similar changes in U.S.

federal income tax laws could eliminate or postpone certain tax deductions that currently are available with respect to oil and gas development or increase costs, and any such changes could have an adverse effect on our financial position, results of operations and cash flows.

The present value of future net cash flows from our proved reserves is not necessarily the same as the current market value of our estimated proved reserves.

We base the estimated discounted future net cash flows from our proved reserves using a 12-month average price and costs in effect on the day of the estimate.

However, actual future net cash flows from our oil and natural gas properties will be affected by factors such as:

• the volume, pricing and duration of our oil and natural gas hedging contracts;

We base the estimated discounted future net cash flows from our proved reserves using a specified pricing and cost assumptions.

However, actual future net cash flows from our oil and natural gas properties will be affected by factors such as the volume, pricing and duration of our oil and natural gas hedging contracts;

actual prices we receive for oil, natural gas and NGLs;

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the amount and timing of actual production;

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• changes in governmental regulations or taxation.

The timing of both our production and our incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value.

and changes in governmental regulations or taxation.

In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general.

Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves, which could adversely affect our business, results of operations and financial condition.

Our business depends on oil and natural gas transportation and processing facilities and other assets that are owned by third parties.

Our business depends on third party transportation and processing facilities and other assets that are owned by third parties.

The marketability of our oil and natural gas depends in part on the availability, proximity and capacity of pipeline systems, processing facilities, oil trucking fleets and rail transportation assets owned by third parties.

The lack of available capacity on these systems and facilities, whether as a result of proration, physical damage, scheduled maintenance or other reasons, could result in a substantial increase in costs, the shut-in of producing wells or the delay or discontinuance of development plans for our properties.

During 2019, we experienced significant delays and production curtailments that we believe were due in part to gas gathering and processing constraints.

The lack of available capacity on these systems and facilities, whether as a result of proration, physical damage, scheduled maintenance, legal or other reasons such as suspension of service due to legal challenges (see below regarding the Dakota Access Pipeline), could result in a substantial increase in costs, declines in realized commodity prices, the shut-in of producing wells or the delay or discontinuance of development plans for our properties.

During 2019 and into 2020, we experienced significant delays and production curtailments, and declines in realized natural gas prices, that we believe were due in part to gas gathering and processing constraints in the Williston Basin.

The negative effects arising from these and similar circumstances may last for an extended period of time.

In many cases, operators are provided only with limited, if any, notice as to when these circumstances will arise and their duration.

In addition, many of our wells are drilled in locations in the Williston Basin that are serviced to a limited extent, if at all, by gathering and transportation pipelines, which may or may not have sufficient capacity to transport production from all of the wells in the area.

In addition, our wells may be drilled in locations that are serviced to a limited extent, if at all, by gathering and transportation pipelines, which may or may not have sufficient capacity to transport production from all of the wells in the area.

As a result, we rely on third party oil trucking to transport a significant portion of our production to third party transportation pipelines, rail loading facilities and other market access points.

The Dakota Access Pipeline (“DAPL”), a major pipeline running out of the Williston Basin, is subject to ongoing litigation (the “DAPL Litigation”) that could threaten its continued operation.

In July 2020, a federal district court ordered DAPL to be shut down no later than August 6, 2020, pending the completion of an environmental impact statement (“EIS”) that is expected to take at least a year to complete.

The district court’s shut-down order was subsequently temporarily stayed by a federal circuit court of appeals, and DAPL currently remains operational.

However, in January 2021, a federal circuit court of appeals agreed with the federal district court that the government should have conducted an EIS before going forward with the pipeline, and vacated easements granted for its construction to cross beneath Lake Oahe, a reservoir along the Missouri River maintained by the U.S.

Army Corps of Engineers (“USACE”).

The federal circuit court of appeals did not agree with the lower court’s decision that the pipeline should be shut down, and instead left the decision on how to proceed to the USACE.

A shut-down remains possible, and there is no guarantee that DAPL will be permitted to resume or continue operations following the completion of the EIS and/or the DAPL Litigation.

Any significant curtailment in gathering system or pipeline capacity, or the unavailability of sufficient third party trucking or rail capacity, could adversely affect our business, results of operations and financial condition.

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If our leases expire and we are unable to renew the leases, we will lose our right to participate in the development of the related properties.

Drilling plans for these areas are generally in the discretion of third party operators and are subject to change based on various factors that are beyond our control, such as:

Drilling plans for these areas are generally in the discretion of third party operators and are subject to change

based on various factors that are beyond our control, such as:

the availability and cost of capital, equipment, services and personnel;

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This could limit access to jobsites and operators’ ability to service wells in these areas.

Significant capital expenditures are required to develop our properties and replace our reserves.

Our exploration, development and acquisition activities require substantial capital expenditures.

Historically, we have funded our capital expenditures through a combination of cash flow from operations, borrowings under our credit facilities, debt issuances, and equity issuances.

We have also engaged in asset sales from time to time.

If our access to capital were limited due to numerous factors, which could include a decrease in operating cash flow due to lower oil and natural gas prices or decreased production or deterioration of the credit and capital markets, we would have a reduced ability to develop our

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properties and replace our reserves.

We may not be able to incur additional debt under our revolving credit facility, issue debt or equity, engage in asset sales or access other methods of financing on acceptable terms to develop our properties and/or meet our reserve replacement requirements.

We may be unable to obtain additional capital that we will require to implement our business plan.

Future acquisitions and future exploration, development, production and marketing activities, will require a substantial amount of capital.

Cash reserves, cash from operations and borrowings under our revolving credit facility may not be sufficient to fund both our continuing operations and our potential future growth.

We may require additional capital to continue to grow our business through acquisitions and to further expand our exploration and development programs.

We may be unable to obtain additional capital if and when required.

We may pursue sources of additional capital through various financing transactions or arrangements, including joint venturing of projects, debt financing, equity financing or other means.

We may not be successful in consummating suitable financing transactions in the time period required or at all, and we may not be able to obtain the capital we require by other means.

If the amount of capital we are able to raise from financing activities, together with our cash from operations, is not sufficient to satisfy our capital requirements, we may not be able to implement our business plan and may be required to scale back our operations, sell assets at unattractive prices or obtain financing on unattractive terms, any of which could adversely affect our business, results of operations and financial condition.

The development of our proved undeveloped reserves in the Williston Basin and other areas of operation may take longer and may require higher levels of capital expenditures than we currently anticipate.

As a non-operator, our development of successful operations relies extensively on third-parties, which could have a material adverse effect on our results of operation.

We have only participated in wells operated by third parties.

The success of our business operations depends on the timing of drilling activities and success of our third-party operators.

These risks are heightened in a low commodity price environment, which may present significant challenges to our operators.

Commodity prices and/or other conditions have in the past and may in the future cause oil and gas operators to file for bankruptcy.

We may have no ability to exercise influence over the operational decisions of our operators, including the setting of capital expenditure budgets and drilling locations and schedules.

Dependence on our operators could prevent us from realizing our target returns for those locations.

The success and timing of development activities by our operators will depend on a number of factors that will largely be outside of our control, including, oil and natural gas prices and other factors generally affecting industry operating environment;

the timing and amount of capital expenditures;

their expertise and financial resources;

approval of other participants in drilling wells;

selection of technology;

and the rate of production of reserves, if any.

The inability of one or more of our operating partners to meet their obligations to us may adversely affect our financial results.

Our principal exposures to credit risk are through receivables resulting from the sale of our oil and natural gas production, which operating partners market on our behalf to energy marketing companies, refineries and their affiliates.

We are subject to credit risk due to the concentration of our oil and natural gas receivables with a limited number of operating partners.

This concentration may impact our overall credit risk since these entities may be similarly affected by changes in economic and other conditions.

A low commodity price environment may strain our operating partners, which could heighten this risk.

The inability or failure of our operating partners to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results.

We could experience periods of higher costs as activity levels fluctuate or if commodity prices rise.

These increases could reduce our profitability, cash flow, and ability to complete development activities as planned.

An increase in commodity prices or other factors could result in increased development activity and investment in our areas of operations, which may increase competition for and cost of equipment, labor and supplies.

Shortages of, or increasing costs for, experienced drilling crews and equipment, labor or supplies could restrict our operating partners’ ability to conduct desired or expected operations.

Any delay in the drilling of new wells or significant increase in drilling costs could reduce our revenues and cash flows.

The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate.

Therefore, our undeveloped reserves may not be ultimately developed or produced.

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Our acquisition strategy will subject us to certain risks associated with the inherent uncertainty in evaluating properties for which we have limited information.

We intend to expand our operations in part through acquisitions.

We intend to expand our operations in part through acquisitions, including without limitation the pending Reliance Acquisition.

Our decision to acquire a property will depend in part on the evaluation of data obtained from production reports and engineering studies, geophysical and geological analyses and seismic and other information, the results of which are often inconclusive and subject to various interpretations.

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• dilution to shareholders if we use equity as consideration for, or to finance, acquisitions;

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• the assumption of unknown liabilities, losses or costs for which we are not indemnified or for which our indemnity is inadequate;

• an inability to hire, train or retain qualified personnel to manage and operate our growing business and assets;

• an increase in our costs or a decrease in our revenues associated with any potential royalty owner or landowner claims or disputes.

• an increase in our costs or a decrease in our revenues associated with any potential royalty owner or landowner claims or disputes, or other litigation encountered in connection with an acquisition.

If the Reliance Acquisition is consummated, we may be unable to successfully integrate the Reliance Assets into our business or achieve the anticipated benefits of the Reliance Acquisition.

Our ability to achieve the anticipated benefits of the Reliance Acquisition will depend in part upon whether we can integrate the acquired assets into our existing business in an efficient and effective manner.

We may not be able to accomplish this integration process successfully.

The successful acquisition of producing properties requires an assessment of several factors, including:

• recoverable reserves;

• future oil and natural gas prices and their appropriate differentials;

• availability and cost of transportation of production to markets;

• availability and cost of drilling equipment and of skilled personnel;

• development and operating costs including access to water and potential environmental and other liabilities;

• regulatory, permitting and similar matters.

The accuracy of these assessments is inherently uncertain.

In connection with these assessments, we have performed a review of the subject properties that we believe to be generally consistent with industry practices.

The review was based on our analysis of historical production data, assumptions regarding capital expenditures and anticipated production declines without review by an independent petroleum engineering firm.

Data used in such review was furnished by the seller or obtained from publicly available sources.

Our review may not reveal all existing or potential problems or permit us to fully assess the deficiencies and potential recoverable reserves for all of the acquired properties, and the reserves and production related to the acquired assets may differ materially after such data is further reviewed.

Inspections will not always be performed on every well, and environmental problems are not necessarily observable even when an inspection is undertaken.

Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or a portion of the underlying deficiencies.

We are often not entitled to contractual indemnification for environmental liabilities and acquire properties on an “as is” basis, and, as is the case with certain liabilities associated with the assets to be acquired in the Reliance Acquisition, we are entitled to indemnification for only certain environmental liabilities.

The integration process may be subject to delays or changed circumstances, and we can give no assurance that the acquired assets will perform in accordance with our expectations or that our expectations with respect to integration as a result of the Reliance Acquisition will materialize.

Failure to complete the Reliance Acquisition could negatively impact our future business and financial results.

The consummation of the pending Reliance Acquisition is subject to various customary and other closing conditions, some of which are beyond our control, and we cannot assure you that the Reliance Acquisition will be consummated.

If the Reliance Acquisition is not completed or if there are significant delays in completing the Reliance Acquisition, our future business and financial results and the trading price of our common stock could be negatively affected.

In particular, there may be negative reactions from the financial markets due to the fact that current prices of our common stock may reflect a market assumption that the Reliance Acquisition will be completed.

The loss of any member of our management team, upon whose knowledge, relationships with industry participants, leadership and technical expertise we rely could diminish our ability to conduct our operations and harm our ability to execute our business plan.

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The members of our management team may terminate their employment with our company at any time.

If we were to lose members of our management team, we may not be able to replace the knowledge that they possess.

In addition, we may not be able to establish or maintain strategic relationships with industry participants.

If we were to lose the services of the members of our management team, our ability to conduct our operations and execute our business plan could be materially harmed.

If we were to lose members of our management team, we may not be able to replace the knowledge or relationships that they possess and our ability to execute our business plan could be materially harmed.

Deficiencies of title to our leased interests could significantly affect our financial condition.

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Furthermore, title issues may arise at a later date that were not initially detected in any title review or examination.

Any one or more of the foregoing could require us to reverse revenues previously recognized and potentially negatively affect our cash flows and results of operations.

Any one or more of the foregoing could require us to reverse revenues previously recognized and potentially negatively affect our cash flows and results of

Our failure to obtain perfect title to our leaseholds may adversely affect our current production and reserves and our ability in the future to increase production and reserves.

Competition may limit our ability to obtain rights to explore and develop oil and natural gas reserves.

The oil and natural gas industry is highly competitive.

Other oil and natural gas companies may seek to acquire oil and natural gas leases and other properties and services we will need to operate our business in the areas in which we expect to operate.

Additionally, other companies engaged in our line of business may compete with us from time to time in obtaining capital from investors.

Competitors include larger companies which, in particular, may have access to greater resources, may be more successful in the recruitment and retention of qualified employees and may conduct their own refining and petroleum marketing operations, which may give them a competitive advantage.

In addition, actual or potential competitors may be strengthened through the acquisition of additional assets and interests.

If we are unable to compete effectively or respond adequately to competitive pressures, our results of operation and financial condition may be materially adversely affected.

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Insufficient transportation, refining or processing capacity in the Williston Basin could cause significant fluctuations in our realized oil and natural gas prices.

The Williston Basin crude oil business environment has historically been characterized by periods when oil production has surpassed local transportation and refining capacity, resulting in substantial discounts in the price received for crude oil versus prices quoted for WTI crude oil.

Although additional Williston Basin transportation takeaway capacity has been added over the last several years, production also increased substantially during the same period.

The increased production coupled with delays in rail car arrivals and commissioning of rail loading facilities has caused price differentials to significantly increase at times.

Similarly, gas gathering and processing constraints and other factors have resulted and may result in significant declines in our realized natural gas prices.

Crude oil from the Bakken/Three Forks formations may pose unique hazards that may have an adverse effect on our operations.

In 2015, the U.S.

Department of Transportation (“USDOT”) concluded that crude oil from the Bakken/ Three Forks formations has a higher volatility than most other U.S.

crude oil and thus is more ignitable and flammable.

Based on that information, and several fires involving rail transportation of crude oil, USDOT issued a rail safety rule in 2015 that included new construction standards for rail tank cars constructed after October 1, 2015.

The final rule created a new North American tank car standard known as the DOT Specification 117 (“DOT-117”) rail car with thicker steel and redesigned bottom outlet valves, among other improvements over the then-standard DOT Specification 111 (“DOT-111”) tank car.

The final rule established a schedule for retrofitting or replacing older tank cars and included mandates for using electronically controlled pneumatic (“ECP”) braking systems and for performing routing analyses, among other requirements.

In December 2017, the USDOT repealed the ECP provisions of the 2015 rail safety rule.

USDOT issued a final rule in 2019 expanding the applicability of oil spill response plans for high-hazard flammable trains.

In addition, the rail industry has adopted increased precautions for crude shipments.

Any new restrictions that significantly affect transportation of crude oil production could materially and adversely affect our financial condition, results of operations and cash flows.

Our business involves the selling and shipping by rail of crude oil, including from the Bakken shale, which involves risks of derailment, accidents and liabilities associated with cleanup and damages, as well as potential regulatory changes that may adversely impact our business, financial condition or results of operations.

A portion of our crude oil production is transported to market centers by rail.

Derailments in North America of trains transporting crude oil have caused various regulatory agencies and industry organizations, as well as federal, state and municipal governments, to focus attention on transportation by rail of flammable materials.

Transportation safety regulators in the United States and Canada are concerned that crude oil from the Bakken shale may be more flammable than crude oil from other producing regions and are investigating that issue and are also considering changes to existing regulations to address those possible risks, as noted directly above.

In May 2015, USDOT’s Pipelines and Hazardous Materials Safety Administration (“PHMSA”) adopted a final rule that, among other things, imposed a new and enhanced tank car design standard for certain tank cars carrying crude oil and ethanol, a phase out by as early as January 2018 for older DOT-111 tank cars that were not retrofitted, and a classification and testing program for unrefined petroleum based products, including crude oil.

The rule also included new operational requirements such as routing analyses, speed restrictions and enhanced braking controls.

However, in December 2017, the USDOT repealed the enhanced braking control provisions of the May 2015 rail safety rule.

USDOT is expected to issue a final rule in 2018 expanding the applicability of oil spill response plans for high-hazard flammable trains.

Transport Canada has also issued legal requirements that align with the rule adopted by PHMSA, including standards relating to train speed restrictions, route risk analyses and a phase out of non-compliant DOT-111 tank cars.

Any changes to existing laws and regulations, or promulgation of new laws and regulations, including any voluntary measures by the rail industry, that result in new requirements for the design, construction or operation of tank cars used to transport crude oil could increase our costs of doing business and limit our ability to transport and sell our crude oil at favorable prices at market centers throughout the United States, the consequences of which could have a material adverse effect on our financial condition, results of operations and cash flows.

To the extent that new regulations require design changes or other modifications of tank cars, we may incur significant constraints on transportation capacity during the period while tank cars are being retrofitted or newly constructed to comply with the new regulations.

In addition, any derailment of crude oil from the Bakken shale involving crude oil that we have sold or are shipping may result in claims being brought against us that may involve significant liabilities.

Although we believe that we are adequately insured against such events, we cannot assure you that our insurance policies will cover the entirety of any damages that may arise from such an event.

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Market conditions or operational impediments may hinder our access to oil and natural gas markets or delay our production.

Market conditions or the unavailability of satisfactory oil and natural gas transportation arrangements may hinder our access to oil and natural gas markets or delay our production.

The availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for and supply of oil and natural gas and the proximity of reserves to pipelines and terminal facilities.

Our ability to market our production depends, in substantial part, on the availability and capacity of gathering systems, pipelines and processing facilities owned and operated by third-parties.

Our failure to obtain such services on acceptable terms could materially harm our business.

The operators of our wells may be required to shut in wells due to lack of a market or inadequacy or unavailability of crude oil or natural gas pipelines, processing or gathering system capacity.

If our production becomes shut-in for any of these or other reasons, we would be unable to realize revenue from those wells until other arrangements were made to deliver the products to market.

Our lack of industry and geographical diversification may increase the risk of an investment in our company.

We have begun to diversify with the pending Reliance Acquisition in the Appalachian Basin and smaller acquisitions in the Permian Basin, however our operations remain heavily concentrated in primarily oil wells in the Williston Basin.

While other companies may have the ability to manage their risk by diversification, the narrow focus of our business, in terms of both the industry focus and geographic scope of our business, means that we will likely be impacted more acutely by factors affecting our industry or the regions in which we operate than we would if our business were more diversified.

As a result of the narrow focus of our business, we may be disproportionately exposed to the effects of regional supply and demand factors, delays or interruptions of production from wells in our areas caused by governmental regulation, processing or transportation capacity constraints, market limitations, weather events or interruption of the processing or transportation of oil or natural gas.

Our derivatives activities could adversely affect our cash flow, results of operations and financial condition.

To achieve more predictable cash flows and reduce our exposure to adverse fluctuations in the price of oil and natural gas, we enter into derivative instrument contracts for a portion of our expected production, which may include swaps, collars, puts and other structures.

Accordingly, our earnings may fluctuate significantly as a result of changes in the fair market value of our derivative instruments.

In addition, while intended to mitigate the effects of volatile oil and natural gas prices, our derivatives transactions may limit our potential gains and increase our potential losses if oil and natural gas prices were to rise substantially over the price established by the hedge.

Our actual future production may be significantly higher or lower than we estimate at the time we enter into derivative contracts for such period.

If the actual amount of production is higher than we estimate, we will have greater commodity price exposure than we intended.

In addition, such transactions may expose us to the risk of loss in certain circumstances, including instances in which a counterparty to our derivative contracts is unable to satisfy its obligations under the contracts;

our production is less than expected;

or there is a widening of price differentials between delivery points for our production and the delivery point assumed in the derivative arrangement.

Decommissioning costs are unknown and may be substantial.

Unplanned costs could divert resources from other projects.

We may become responsible for costs associated with plugging, abandoning and reclaiming wells, pipelines and other facilities that we use for production of oil and natural gas reserves.

Abandonment and reclamation of these facilities and the costs associated therewith is often referred to as “decommissioning.” We accrue a liability for decommissioning costs associated with our wells, but have not established any cash reserve account for these potential costs in respect of any of our properties.

If decommissioning is required before economic depletion of our properties or if our estimates of the costs of decommissioning exceed the value of the reserves remaining at any particular time to cover such decommissioning costs, we may have to draw on funds from other sources to satisfy such costs.

The use of other funds to satisfy such decommissioning costs could impair our ability to focus capital investment in other areas of our business.

We depend on computer and telecommunications systems, and failures in our systems or cyber security attacks could significantly disrupt our business operations.

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We believe that we have positive relations with our related vendors and maintain adequate anti-virus and malware software and controls;

however, any interruptions to our arrangements with third parties for our computing and communications infrastructure or any other interruptions to, or breaches of, our information systems could lead to data corruption, communication interruption, loss of sensitive or confidential information or otherwise significantly disrupt our business operations.

however, any interruptions to our arrangements with third parties for our computing and communications infrastructure or any other interruptions to, or breaches of, our

information systems could lead to data corruption, communication interruption, loss of sensitive or confidential information or otherwise significantly disrupt our business operations.

Although we utilize various procedures and controls to monitor these threats and mitigate our exposure to such threats, there can be no assurance that these procedures and controls will be sufficient in preventing security threats from materializing.

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however, there can be no assurance that we will not suffer material losses in the future either as a result of an interruption to or a breach of our systems or those of our third party vendors and service providers.

We are subject to litigation and adverse outcomes in such litigation could have an adverse effect on our financial condition.

We are, and from time to time may become, subject to litigation and various legal proceedings, including stockholder derivative suits, class action lawsuits and other matters, that involve claims for substantial amounts of money or for other relief or that might necessitate changes to our business or operations.

For example, in August 2016, Jeffrey Fries, individually and on behalf of all others similarly situated, filed a class action complaint in the United States District Court for the Southern District of New York against the Company.

The complaint was amended in January 2018 and alleged violations of the Exchange Act, and Rule 10b-5 thereunder.

Although this particular complaint was ultimately dismissed, the defense of these actions may be both time consuming and expensive.

We evaluate these litigation claims and legal proceedings to assess the likelihood of unfavorable outcomes and to estimate, if possible, the amount of potential losses.

Based on these assessments and estimates, we may establish reserves and/or disclose the relevant litigation claims or legal proceedings, as and when required or appropriate.

These assessments and estimates are based on information available to management at the time of such assessment or estimation and involve a significant amount of judgment.

As a result, actual outcomes or losses could differ materially from those envisioned by our current assessments and estimates.

Our failure to successfully defend or settle any litigation or legal proceedings could result in liability that, to the extent not covered by our insurance, could have an adverse effect on our business, financial condition and results of operations.

Risks Related to Our Financing and Indebtedness

Any significant reduction in our borrowing base under our revolving credit facility will negatively impact our liquidity and could adversely affect our business and financial results.

The lenders under the revolving credit facility can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under our revolving credit facility.

Reductions in estimates of our producing oil, NGL and natural gas reserves could result in a reduction of our borrowing base thereunder.

The same could also arise from other factors, including but not limited to lower commodity prices or production;

inability to drill or unfavorable drilling results;

changes in crude oil, NGL and natural gas reserve engineering;

increased operating and/or capital costs;

or other factors affecting our lenders’ ability or willingness to lend (including factors that may be unrelated to our company).

Further, if the outstanding borrowings under our revolving credit facility were to exceed the borrowing base as a result of any such redetermination, we could be required to repay the excess.

If we do not have sufficient funds and we are otherwise unable to arrange new financing, we may have to sell significant assets or take other actions to address.

Any such sale or other actions could have a material adverse effect on our business and financial results.

Our revolving credit facility and other agreements governing indebtedness contain operating and financial restrictions that may restrict our business and financing activities.

Our revolving credit facility, the indenture governing our senior indebtedness, and any future indebtedness we incur may contain a number of restrictive covenants that will impose significant operating and financial restrictions on us, including restrictions on our ability to, among other things:

declare or pay any dividend or make any other distributions on, purchase or redeem our equity interests or purchase or redeem certain debt;

make loans or certain investments;

make certain acquisitions and investments;

incur or guarantee additional indebtedness or issue certain types of equity securities;

transfer or sell assets;

create subsidiaries;

consolidate, merge or transfer all or substantially all of our assets;

and engage in transactions with our affiliates.

In addition, the revolving credit facility requires us to maintain compliance with certain financial covenants and other covenants.

As a result of these covenants, we could be limited in the manner in which we conduct our business, and we may be unable to engage in favorable business activities or finance future operations or capital needs.

Our ability to comply with some of the covenants and restrictions may be affected by events beyond our control.

If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired.

A failure to comply with the covenants, ratios or tests in our revolving credit facility or any other indebtedness could result in an event of default under our revolving credit facility or our other indebtedness, which, if not cured or waived, could have a material adverse effect on our business, financial condition and results of operations.

If an event of default under our revolving credit facility occurs and remains uncured, the lenders thereunder would not be required to lend any additional amounts to us;

could elect to declare all borrowings outstanding, together with accrued and unpaid interest and fees, to be due and payable;

may have the ability to require us to apply all of our available cash to repay these borrowings;

and may prevent us from making debt service payments under our other agreements.

An event of default or an acceleration under our revolving credit facility could result in an event of default and an acceleration under other existing or future indebtedness.

Conversely, an event of default or an acceleration under any other existing or future indebtedness could result in an event of default and an acceleration under our revolving credit facility.

In addition, our obligations under the revolving credit facility are collateralized by perfected liens and security interests on substantially all of our assets and if we default thereunder the lenders could seek to foreclose on our assets.

We may not be able to generate enough cash flow to meet our debt obligations or our obligations related to our preferred stock.

We expect our earnings and cash flow to vary significantly from year to year due to the cyclical nature of our industry.

As a result, the amount of debt that we can service in some periods may not be appropriate for us in other periods.

Additionally, our future cash flow may be insufficient to meet our debt obligations and commitments, or to permit us to pay dividends on our preferred stock.

Any insufficiency could negatively impact our business.

A range of economic, competitive, business and industry factors will affect our future financial performance, and, as a result, our ability to generate cash flow from operations and to pay our debt or dividends on our preferred stock.

Many of these factors, such as oil and natural gas prices, economic and financial conditions in our industry and the global economy or competitive initiatives of our competitors, are beyond our control.

If we do not generate enough cash flow from operations to satisfy our debt obligations, we may have to undertake alternative financing plans, such as refinancing or restructuring our debt;

selling assets;

reducing or delaying capital investments;

or seeking to raise additional capital.

However, we cannot assure you that undertaking alternative financing plans, if necessary, would allow us to meet our debt obligations or pay dividends on our preferred stock.

Our inability to generate sufficient cash flow to satisfy our debt obligations or pay dividends on our preferred stock, or to obtain alternative financing, could materially and adversely affect our business, financial condition, results of operations and prospects.

We currently owe cumulative dividends with respect to our Series A Preferred Stock, which precludes us from paying dividends with respect to our common stock and has certain other potential or actual adverse consequences.

Our Series A Preferred Stock accrues dividends that are payable semi-annually in arrears on May 15 and November 15 of each year, which commenced on May 15, 2020, when, as and if declared by our Board.

As of December 31, 2020, no dividends had been declared or paid, and there were approximately $16.3 million of accumulated dividends on the Series A Preferred Stock.

Our failure to pay dividends with respect to the Series A Preferred Stock precludes us from paying dividends or making other distributions on our common stock unless all accumulated and unpaid dividends on the Series A Preferred Stock for all preceding dividend periods have been or contemporaneously are declared and paid in full.

Additionally, if dividends on the Series A Preferred Stock are in arrears and unpaid for three or more semi-annual dividend periods (whether or not consecutive), the holders of the Series A Preferred Stock will be entitled to elect two additional directors to serve on the Board during the term of such payment arrearage.

Since dividends are currently in arrears for two semi-annual dividend periods, this would occur as a result of the next semi-annual dividend period for which dividends are not paid.

Our variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to increase significantly.

Borrowings under our revolving credit facility bear interest at variable rates and expose us to interest rate risk.

If interest rates increase and we are unable to effectively hedge our interest rate risk, our debt service obligations on the variable rate indebtedness would increase even if the amount borrowed remained the same, and our net income and cash available for servicing our indebtedness would decrease.

Changes in the method of determining LIBOR, or the replacement of LIBOR with an alternative reference rate, may adversely affect interest rates under our revolving credit agreement.

LIBOR is a basic rate of interest widely used as a global reference for setting interest rates on loans and payment rates on other financial instruments.

Our revolving credit agreement uses LIBOR as the reference rate for Eurodollar denominated borrowings.

In 2017, the United Kingdom’s Financial Conduct Authority, which regulates LIBOR, announced that it intends to phase out LIBOR by the end of 2021.

It is unclear if LIBOR will cease to exist at that time, if new methods of calculating LIBOR will be established such that it continues to exist after 2021 or whether different reference rates will develop.

It is impossible to predict the effect these developments, any discontinuance, modification or other reforms to LIBOR or the establishment of alternative reference rates may have on LIBOR, other benchmark rates or floating rate debt instruments.

Although our revolving credit agreement contains LIBOR alternative provisions and the ability to negotiate an alternative reference rate, new methods of calculating reference rates or other reforms could cause the interest rates under our revolving credit agreement to be materially different than expected, which could have an adverse effect on our business, financial position and results of operations, and our ability to pay dividends on our common stock.

We may be able to incur substantially more debt.

This could further exacerbate the risks associated with our substantial indebtedness.

We may be able to incur substantial additional indebtedness in the future, subject to certain limitations, including under our revolving credit facility, our senior notes and under any future debt agreements.

If new debt is added to our current debt levels, the related risks that we now face could increase.

Our level of indebtedness could, for instance, prevent us from

engaging in transactions that might otherwise be beneficial to us or from making desirable capital expenditures.

This could put us at a competitive disadvantage relative to other less leveraged competitors that have more cash flow to devote to their operations.

In addition, the incurrence of additional indebtedness could make it more difficult to satisfy our existing financial obligations.

Our business plan requires significant capital expenditures, which we may be unable to obtain on favorable terms or at all.

Our exploration, development and acquisition activities require substantial capital expenditures.

Historically, we have funded our capital expenditures through a combination of cash flow from operations, borrowings under our credit facilities, debt issuances, and equity issuances.

Cash reserves, cash from operations and borrowings under our revolving credit facility may not be sufficient to fund our continuing operations and business plan and goals.

We may require additional capital and we may be unable to obtain such capital if and when required.

We may not be able to incur additional debt under our revolving credit facility, issue debt or equity, engage in asset sales or access other methods of financing on acceptable terms or at all.

Risks Related to Legal and Regulatory Matters

The current administration, acting through the executive branch and/or in coordination with Congress, could enact rules and regulations that restrict our ability to acquire federal leases in the future and/or impose more onerous permitting and other costly environmental, health and safety requirements.

President Biden has stated that he intends to issue Executive Orders to permanently protect certain federal lands, establish monuments, restrict new oil and gas permitting on public lands and waters, and modify royalties to account for climate costs.

In January 2021, President Biden signed an Executive Order temporarily suspending oil and gas permitting on federal lands and waters.

In addition, the current administration has indicated that his administration is likely to pursue more stringent methane pollution limits for new and existing oil and gas operations.

These efforts, among others, are intended to support the current administration’s stated goal of addressing climate change.

Potential actions of a Democratic-controlled Congress include imposing more restrictive laws and regulations pertaining to permitting, limitations on greenhouse gas emissions, increased requirements for financial assurance and bonding for decommissioning liabilities, and carbon taxes.

Any of these administrative or Congressional actions could adversely affect our financial condition and results of operations by restricting the lands available for development and/or access to permits required for such development, or by imposing additional and costly environmental, health and safety requirements.

Our ability to use net operating loss carryforwards to offset future taxable income may be subject to certain limitations.

We have net operating loss (“NOL”) carryforwards that we may use to offset against taxable income for U.S.

federal income tax purposes.

At December 31, 2020, we had an estimated NOL carryforward of approximately $474.5 million for United States federal income tax purposes.

See Note 10 to our financial statements.

Future changes in our stock ownership, some of which are outside of our control, could result in an additional ownership change under Section 382 of the IRC.

federal income tax deductions currently available with respect to natural gas and oil exploration and development may be eliminated as a result of future legislation.

In past years, legislation has been proposed that would, if enacted into law, make significant changes to U.S.

tax laws, including certain key U.S.

federal income tax provisions currently available to oil and gas companies.

period for certain geological and geophysical expenditures.

Although these provisions were largely unchanged in the Tax Act, Congress could consider, and could include, some or all of these proposals as part of future tax reform legislation.

It is unclear whether these or similar changes will be enacted in future legislation and, if enacted, how soon any such changes could take effect.

The passage of any legislation as a result of these proposals or any similar changes in U.S.

The enactment of new or increased severance taxes and impact fees on natural gas production could negatively impact the assets we expect to acquire in the Reliance Acquisition.

The tax laws, rules and regulations that affect the operation of the assets that we expect to acquire in the pending Reliance Acquisition are subject to change.

For example, Pennsylvania’s governor has in past legislative sessions proposed legislation to impose a state severance tax on the extraction of natural resources, including natural gas produced from the Marcellus Shale formation, either in replacement of or in addition to the existing state impact fee.

Pennsylvania’s legislature has not thus far advanced any of the governor’s severance tax proposals;

however, severance tax legislation may continue to be proposed in future legislative sessions.

Any such tax increase or change could adversely impact our earnings, cash flows and financial position as it relates to these assets.

A portion of our crude oil production is transported to market centers by rail.

Our derivative activities expose us to potential regulatory risks .

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Failure to comply with such regulations, as interpreted and enforced, could have a material adverse effect on our business, results of operations and financial condition.

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Legislative and regulatory developments could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business .

In July of 2010, the United States Congress enacted the Dodd-Frank Wall Street Reform and Consumer Protection Act (“Dodd-Frank Act”), which contains measures aimed at increasing the transparency and stability of the over-the-counter (“OTC”) derivatives market and preventing excessive speculation.

In November 2013, the CFTC re-proposed implementing regulations imposing position limits for certain physical commodity contracts in the major energy markets and economically equivalent futures, options and swaps, with exemptions for certain bona fide hedging positions.

The CFTC’s initial position limit rules were vacated by a federal court in 2012.

It is not clear when the re-proposed rules on position limits would become effective.

CFTC rules under the Dodd-Frank Act also may impose clearing and trade execution requirements in connection with our derivatives activities, although currently those requirements do not extend to derivatives based on physical commodities in the energy markets and some or all of our derivatives activities may be exempt from such requirements based on our non-financial end-user status.

Regulations issued under the Dodd-Frank Act also may require certain counterparties to our derivative instruments to spin off some of their derivative activities to a separate entity, which may not be as creditworthy as the current counterparty.

The final rules are being phased in over time depending on the finalization of certain other rules to be promulgated jointly by the CFTC and the SEC.

The legislation and regulations could significantly increase the cost of derivative contracts (including from swap recordkeeping and reporting requirements and through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties.

We maintain an active hedging program related to oil price risks.

The Dodd-Frank Act and rules and regulations thereunder could reduce trading positions and the market-making activities of our counterparties.

The Dodd-Frank Wall Street Reform and Consumer Protection Act (“Dodd-Frank Act”) contains measures aimed at increasing the transparency and stability of the over-the-counter (“OTC”) derivatives market and preventing excessive speculation.

In one of the rulemaking proceedings still pending under the Dodd-Frank Act, the CFTC issued in January 2020 (withdrawing previous proposals from 2013 and 2016), proposed rules imposing position limits for certain futures and options contracts in various commodities (including oil and gas) and for swaps that are their economic equivalents.

Under the proposed rules on position limits, certain types of derivative transactions are exempt from these limits, provided that such derivative transactions satisfy the CFTC's requirements for certain enumerated “bona fide” derivative transactions.

The CFTC has also adopted final rules regarding aggregation of positions, under which a party that controls the trading of, or owns ten percent or more of the equity interests in, another party will have to aggregate the positions of the controlled or owned party with its own positions for purposes of determining compliance with position limits unless an exemption applies.

The CFTC’s aggregation rules are now in effect, although CFTC staff has granted relief until August 12, 2022 from various conditions and requirements in the final aggregation rules.

These rules may affect both the size of the positions that we may hold and the ability or willingness of counterparties to trade with us, potentially increasing the costs of transactions.

Moreover, such changes could

materially reduce our access to derivative opportunities, which could adversely affect revenues or cash flow during periods of low commodity prices.

The CFTC also has designated certain interest rate swaps and credit default swaps for mandatory clearing and the associated rules also will require us, in connection with covered derivative activities, to comply with clearing and trade-execution requirements or to take steps to qualify for an exemption to such requirements.

Although we believe we qualify for the end-user exception from the mandatory clearing requirements for swaps entered to mitigate its commercial risks, the application of the mandatory clearing and trade execution requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use.

If our swaps do not qualify for the commercial end-user exception, or if the cost of entering into uncleared swaps becomes prohibitive, we may be required to clear such transactions.

The ultimate effect of these rules and any additional regulations on our business is uncertain.

The full impact of the Dodd-Frank Act and related regulatory requirements on our business will not be known until the regulations are fully implemented and the market for derivatives contracts has adjusted.

In addition, it is possible that the current administration could expand regulation of the over-the-counter derivatives market and the entities that participate in that market through either the Dodd-Frank Act or the enactment of new legislation.

Regulations issued under the Dodd-Frank Act (including any further regulations implemented thereunder) and any new legislation also may require certain counterparties to our derivative instruments to spin off some of their derivative activities to a separate entity, which may not be as creditworthy as the current counterparty.

Such legislation and regulations could significantly increase the cost of derivative contracts (including from swap recordkeeping and reporting requirements and through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties.

We maintain an active hedging program related to commodity price risks.

Such legislation and regulations could reduce trading positions and the market-making activities of our counterparties.

If we reduce our use of derivatives as a result of legislation and regulations or any resulting changes in the derivatives markets, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures or to make payments on our debt obligations.

Finally, the legislation was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas.

Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas.

Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices.

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Furthermore, we may be put at a competitive disadvantage to larger companies in our industry that can spread these additional costs over a greater number of wells and larger operating staff.

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Environmental risks may adversely affect our business.

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Any of the above risks could impair our ability to manage our business and have a material adverse effect on our operations, cash flows and financial position.

Climate change legislation or regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the oil and natural gas that we produce.

Various state governments and regional organizations have considered enacting new legislation and promulgating new regulations governing or restricting the emission of “greenhouse gases” (“GHG”) from stationary sources such as our equipment and operations.

At the federal levels, the EPA has determined that emissions of certain GHG present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes.

Based on its findings, the EPA has begun adopting and implementing regulations to restrict emissions of GHG.

In addition, the U.S.

Congress has from time to time considered adopting legislation to reduce emissions of GHG, though it is yet to do so, and almost one-half of the states have already taken legal measures to reduce emissions of GHG primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs.

Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants or major producers

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of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances that correspond to their annual emissions of GHGs.

The number of allowances available for purchase is reduced each year in an effort to achieve the overall GHG reduction goal.

As the number of GHG emission allowances declines each year, the cost or value of such allowances is expected to escalate significantly.

Additionally, in December 2015, the U.S.

joined the international community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France that prepared an agreement requiring member countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals every five years beginning in 2020.

This “Paris Agreement” was signed by the United States in April 2016 and entered in force in November 2016;

however, this agreement does not create any binding obligations for nations to limit their GHG emissions, but rather includes pledges to voluntarily limit or reduce future emissions.

In August 2017, the U.S.

State Department informed the United Nations of the intent of the United States to withdraw from the Paris Agreement.

The Paris Agreement provides for a four-year exit process beginning when it took effect in November 2016, which would result in an effective exit date of November 2020.

The United States’ adherence to the exit process and/or the terms on which the United States may reenter the Paris Agreement or separately negotiated agreement are unclear at this time.

The adoption of legislation or regulatory programs to reduce emissions of GHG could require our third-party operating partners, and indirectly us, to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements.

Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas produced by our operational interests.

Consequently, legislation and regulatory programs to reduce emissions of GHG could have an adverse effect on our business, financial condition and results of operations.

Regulation of GHG emissions could also result in reduced demand for our production, as oil and natural gas consumers seek to reduce their own GHG emissions.

Any regulation of GHG emissions, including through a cap-and-trade system, technology mandate, emissions tax, reporting requirement or other program, could have a material adverse effect on our business, results of operations and financial condition.

In addition, to the extent climate change results in more severe weather and significant physical effects, such as increased frequency and severity of storms, floods, droughts and other climatic effects, our own, our third-party operating partners or our customers’ operations may be disrupted, which could result in a decrease in our available products or reduce our customers’ demand for our products.

Further, there have been various legislative and regulatory proposals at the federal and state levels to provide incentives and subsidies to (i) shift more power generation to renewable energy sources and (ii) support technological advances to drive less energy consumption.

These incentives and subsidies could have a negative impact on oil, natural gas and NGL consumption.

Any of the above risks could impair our ability to manage our business and have a material adverse effect on our operations, cash flows and financial position.

Decommissioning costs are unknown and may be substantial.

Unplanned costs could divert resources from other projects.

We may become responsible for costs associated with plugging, abandoning and reclaiming wells, pipelines and other facilities that we use for production of oil and natural gas reserves.

The use of other funds to satisfy such decommissioning costs could impair our ability to focus capital investment in other areas of our business.

Our revolving credit facility, the indenture governing our senior secured notes and the unsecured VEN Bakken note contain operating and financial restrictions that may restrict our business and financing activities.

Our revolving credit facility, the indenture governing our senior secured notes and the unsecured VEN Bakken note contain, and any future indebtedness we incur may contain, a number of restrictive covenants that will impose significant operating and financial restrictions on us, including restrictions on our ability to, among other things:

• declare or pay any dividend or make any other distributions on, purchase or redeem our equity interests or purchase or redeem certain debt;

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• make loans or certain investments;

• make certain acquisitions and investments;

• incur or guarantee additional indebtedness or issue certain types of equity securities;

• incur liens;

• transfer or sell assets;

• create subsidiaries

• consolidate, merge or transfer all or substantially all of our assets;

• engage in transactions with our affiliates.

In addition, the revolving credit facility requires us to maintain compliance with certain financial covenants and other covenants.

Our ability to comply with some of the covenants and restrictions may be affected by events beyond our control.

If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired.

If an event of default under our revolving credit facility occurs and remains uncured, the lenders thereunder:

• would not be required to lend any additional amounts to us;

• could elect to declare all borrowings outstanding, together with accrued and unpaid interest and fees, to be due and payable;

• may have the ability to require us to apply all of our available cash to repay these borrowings;

• may prevent us from making debt service payments under our other agreements.

An event of default or an acceleration under our revolving credit facility could result in an event of default and an acceleration under other existing or future indebtedness, including the indenture governing the senior secured notes and the unsecured VEN Bakken note.

Conversely, an event of default or an acceleration under any other existing or future indebtedness could result in an event of default and an acceleration under our revolving credit facility.

In addition, our obligations under the revolving credit facility and the senior secured notes are collateralized by perfected liens and security interests on substantially all of our assets and if we default thereunder the lenders could seek to foreclose on our assets.

Our revolving credit facility limits the amounts we can borrow up to a borrowing base amount, which the lenders will determine on a semi-annual basis based upon projected revenues from our natural gas properties pursuant to engineering reports that we provide to the lenders.

In addition to the scheduled redeterminations, we, the administrative agent and the required lenders have the right to request one additional borrowing base redetermination during each period between scheduled redeterminations.

Any increase in the borrowing base requires the consent of all lenders.

Subject to customary grace periods, we will be required to repay outstanding borrowings in excess of the borrowing base.

The borrowing base will also automatically decrease upon the issuance of certain debt, the sale or other disposition of certain assets in excess of 5% of the borrowing base then in effect and the early termination of certain swap agreements.

We may not be able to generate enough cash flow to meet our debt obligations or our obligations related to our preferred stock.

We expect our earnings and cash flow to vary significantly from year to year due to the cyclical nature of our industry.

As a result, the amount of debt that we can service in some periods may not be appropriate for us in other periods.

Additionally, our future cash flow may be insufficient to meet our debt obligations and commitments, or to permit us to pay

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dividends on our preferred stock.

Any insufficiency could negatively impact our business.

If we do not generate enough cash flow from operations to satisfy our debt obligations, we may have to undertake alternative financing plans, such as:

• refinancing or restructuring our debt;

• selling assets;

• reducing or delaying capital investments;

• seeking to raise additional capital.