AXAS Abraxas Petroleum Corporation (CE)

Item 1A. Risk Factors

Going Concern 

As discussed under Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, our present level of indebtedness and the recent commodity price environment present challenges to our ability to comply with certain covenants in our credit facilities and under applicable auditing standards the independent accountants' opinion on our  financial statements for the year ended December 31, 2020 contains an explanatory paragraph regarding the Company's ability to continue as a "going concern". At December 31, 2020, we had a total of $95.0  million outstanding under our First Lien Credit Facility, $112.7 million under our Second Lien Credit facility and total indebtedness of  $220.5 million including a $10.0 million exit fee. As of April 30, 2021, we had a total of $89.5  million outstanding under our First Lien Credit Facility, $127.2  million under our Second Lien Credit Facility, including a $10.0 million exit fee, and total indebtedness of $219.4 million. If interest expense increases as a result of higher interest rates or increased borrowings, more cash flow from operations would be used to meet debt service requirements.

Specifically, with regard to our credit agreements, we did not satisfy the first lien debt to consolidated EBITDAX ratio covenant under our First Lien Credit Facility as of the December 31, 2020 measurement date and such failure represented an event of default under our First Lien Credit Facility. In addition,  we do not anticipate that we will  maintain compliance with the Second Lien Credit Facility total leverage ratio covenant or the minimum asset coverage ratio (as defined in Note 4), both of which will be  first tested as of September 30, 2021, over the next twelve months and, accordingly, the audit report prepared by our auditors with respect to the financial statements in this Form 10-K includes an explanatory paragraph expressing uncertainty as to our ability to continue as a “going concern.” The inability to maintain compliance with certain covenants of our Second Lien Credit Facility would represent an additional default under our First Lien Credit Facility as of the end of any such future fiscal quarters. The consolidated financial statements do not include any adjustments that might result from the outcome of the "going concern" uncertainty, with the exception of removing all proved undeveloped reserves and the corresponding capital requirements.

We are evaluating the available financial alternatives and are in discussion with our lenders seeking additional waivers or amendments to the covenants or other provisions of our credit facilities to address any current and future default relating to the covenants in question. The existing defaults at March 31, 2021 are subject to  forbearance agreements with our lenders that currently expire on May 6, 2021. No assurance can be provided that the forbearance agreements will be further extended. If, upon a future default, the Company is unable reach an agreement with its lenders or find acceptable alternative financing, the lenders under the Company's  First Lien Credit Facility may choose to accelerate repayment. If the Company's lenders accelerate the payment of amounts outstanding under its credit facilities, the Company does not currently have sufficient liquidity to repay such indebtedness and would need additional sources of capital to do so. The Company could attempt to obtain additional sources of capital from asset sales, public or private issuances of debt, equity or equity-linked securities, debt for equity swaps, or any combination thereof. However, the Company cannot provide any assurances that it will be successful in obtaining capital from such transactions on acceptable terms, or at all. 

Under applicable accounting principles these circumstances are deemed to create substantial doubt regarding the Company's ability to continue as a "going concern". The consolidated financial statements have been prepared on a "going concern" basis, which contemplates the realization of assets and the satisfaction of liabilities and other commitments in the normal course of business for the twelve-month period following the date of issuance of these consolidated financial statements. As such, the accompanying consolidated financial statements do not include any adjustments relating to the recoverability and classification of assets and their carrying amount, or the amount and classification of liabilities that may result should the Company be unable to continue as a "going concern".

In April 2021, we received notice that certain of our hedging agreements were being terminated as a result of events of default under the First Lien Credit Facility, and we voluntarily terminated most of our other hedging arrangements. As a result of the settlement of the terminated hedges, we have an outstanding obligations of $9.9 million. The settlement values of the terminated hedges were determined at various dates between April 15 and April 30, 2021. These obligations will be added to the balance of the First Lien Credit Facility and accrue interest  at the default interest rate, currently 6.7%, until repaid. The remaining  hedging agreements may also be terminated as a result of such events of default. The settlement of terminated hedging agreements may result in losses and limit our ability to reduce exposure to adverse fluctuations in oil and gas prices. See Note 14 “Subsequent Events” for current information regarding non-compliance with certain covenants.

Risks Related to Our Business

We have substantial indebtedness which may adversely affect our cash flow and business operations.

At December 31, 2020, we had a total of $95.0 million of indebtedness under our First Lien Credit Facility, $112.7 million under our Second Lien Credit Facility, and total indebtedness of $220.5 million, including a $10.0 million exit fee. As of April 30, 2021, we had a total of  $89.5 million indebtedness under our First Lien Credit Facility, $117.2 under our Second Lien Credit Facility and total indebtedness, including $10.0 million exit fee, and total indebtedness of $219.4 million. There is no further availability under our First Len Credit Facility. Our indebtedness could have important consequences to us, including:

Our ability to service our indebtedness will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing or delaying capital expenditures, acquisitions and/or selling assets, restructuring or refinancing our indebtedness or seeking additional debt or equity capital or bankruptcy protection. We may not be able to affect any of these remedies on satisfactory terms or at all.

A breach of the terms and conditions of our credit facilities, including the inability to comply with the required financial covenants, could result in an event of default. If an event of default occurs (after any applicable notice and cure periods), the lenders under our First Lien Credit Facility would be entitled to accelerate the repayment of amounts outstanding (including accrued and unpaid interest and fees). In such an event, the lenders under our First Lien Credit Facility could also foreclose upon any collateral securing such obligations, which may be all or substantially all of our assets.  If that occurred, we may not be able to continue to operate as a "going concern". For the fiscal quarter ended September 30, 2019, the Company was in violation of its current ratio covenant under its First Lien Credit Facility. A waiver of this violation was obtained and the lenders agreed not to charge default interest.  Additionally, due to the unprecedented conditions surrounding the outbreak and spread of the COVID-19 coronavirus pandemic, the decline in oil prices during the first half of 2020, and related geopolitical developments, we failed to file our Annual Report on Form 10-K for the period ended December 31, 2019 no later than 90 days after the end of such fiscal year, which resulted in violations of certain covenants under our First Lien Credit Facility and Second Lien Credit Facility (each as in effect prior to their amendments). We also failed to maintain the required hedges under the Second Lien Credit Facility with respect to the fiscal quarter ended March 31, 2020, which resulted in a violation of certain covenants under the Second Lien Credit Facility (as in effect prior to the amendment of the Second Lien Credit Facility). Subject to the terms and conditions of the First Lien Credit Facility and the Second Lien Credit Facility, a waiver was obtained from each of the lenders and each of the lenders agreed not to charge default interest with respect to such defaults. We cannot assure you that we will be able to obtain similar waivers in the future. The failure to make a payment under the Second Lien Credit Facility could result in an event of default. If an event of default occurs (after any applicable notice and cure periods), the lenders (the “Junior Lenders”) under the Second Lien Credit Facility would be entitled to accelerate the repayment of amounts outstanding under the Second Lien Credit Facility (including accrued interest, fees and reimbursements). In such an event, the Junior Lenders, subject to the rights of the lenders under the First Lien Credit Facility, could also foreclose upon any collateral securing such obligations, which may be all or substantially all of our assets. If that occurred, we may not be able to operate as a "going concern". 

In April 2021, we received notice that certain of our hedging agreements were being terminated as a result of events of default under the First Lien Credit Facility and we voluntarily terminated most of our other hedging arrangements. As a result of the settlement of the terminated hedges, we have an outstanding obligations of $9.9 million. The settlement values of the terminated hedges were determined at various dates between April 15 and April 30, 2021. These obligations will be added to the balance of the First Lien Credit Facility and accrue interest  at the default interest rate, currently 6.7%, until repaid. Our remaining hedging agreements may also be terminated as a result of such events of default. The settlement of terminated hedging agreements may result in losses and limit our ability to reduce exposure to adverse fluctuations in oil and gas prices. See Note 14 “Subsequent Events” for current information regarding non-compliance with certain covenants.

Depressed oil and/or gas prices would have a material and adverse effect on us.

Our financial results and the value of our properties are highly dependent on the general supply and demand for oil, gas and NGL, which impact the prices we ultimately realize on our sales of these commodities. Oil, gas and NGL prices are volatile and became more volatile during 2020. During the first half of 2020, there was a significant decline in oil, gas and NGL prices, which adversely affected our operating results and contributed to a reduction in our anticipated future capital expenditures. Prices improved in late 2020. In addition to the impact on our results of operations, future declines in oil and gas prices could cause us to write down the value of our estimated proved reserves. We recorded an impairment of $187.0 million for the year ended December 31, 2020. Oil and natural gas prices remain volatile, and as a result, we could and likely will record impairments in future periods, the amount of which will be dependent upon many factors such as future prices of oil, gas and NGL, increases or decreases in our reserve base, changes in estimated costs and expenses, and oil and gas property acquisitions.

 Prices in 2019 and 2020 have remained relatively low, sharply declining at the beginning of March 2020, and price volatility has continued into 2021.  A sustained weakness or further deterioration in commodity prices could materially and adversely impact our business by resulting in, or exacerbating, the following effects:

Market prices and our realized prices have been volatile and are likely to continue to be volatile in the future due to numerous factors beyond our control. These factors include:

Our cash flows from operations depend to a great extent on the prevailing prices for oil and gas, as well as our hedges to offset declines in price. Prolonged or substantial declines in oil and/or gas prices would materially and adversely affect our liquidity, the amount of cash flows we have available for our capital expenditures and other operating expenses, our ability to access the credit and capital markets and our results of operations.

The marketability of our production depends largely upon the availability, proximity and capacity of oil and gas gathering systems, pipelines, storage and processing facilities.

The marketability of our production depends in part upon processing, storage and transportation facilities, which are also known as midstream facilities, owned and operated by third parties.  Transportation space on such gathering systems and pipelines is limited and at times unavailable due to repairs or improvements being made to such facilities or due to such space being utilized by other companies with priority transportation agreements.  Our access to transportation options can also be affected by federal and state regulation of oil and gas production and transportation, general economic conditions and changes in supply and demand.  These factors and the availability of markets are beyond our control.  If adequate transportation and storage options are not available to us, the financial impact on us could be substantial and adversely affect our ability to produce and market our oil and gas. For example, our principal third party provider in the Bakken Field for these services has experienced, and may in the future, experience significantly increased gathering system pressures which have resulted in capacity constraints. These constraints, in turn, restricted our production and required us to flare gas, decreasing the volumes sold from our wells. Similarly, rapid production growth in the Permian Basin has strained the available midstream infrastructure there with adverse effects on our operations.

In addition to causing production curtailments and reducing the price we receive for the oil, gas and NGL we produce, given environmental impacts, including GHG production, regulatory agencies including the North Dakota Industrial Commission have adopted policies to reduce the volume of flared gas, the number of wells flaring and the duration of flaring. While these regulations have not had a material adverse effect on us to date, these current regulations relating to flaring gas or the adoption of additional regulations could cause us to shut-in production or curtail the drilling of new wells either of which could have a material adverse effect on us.

We rely on third parties to continue to construct additional midstream facilities and related infrastructure to accommodate our growth, and the ability and willingness of those parties to do so is subject to a variety of risks.

For example:

We have pursued a variety of strategies to alleviate some of the risks associated with the midstream services and facilities upon which we rely, including seeking alternative sources for processing and transporting gas that we produce. There can be no assurance that the strategies we pursue will be successful or adequate to meet our needs.

Lower oil and/or gas prices may also reduce the amount of oil and/or gas that we can produce economically.

Sustained substantial declines in oil and/or gas prices may render uneconomic a significant portion of our exploration, development and exploitation projects, which may result in our having to make significant downward adjustments to our estimated proved reserves. As a result, a prolonged or substantial decline in oil and/or gas prices such as we have experienced since mid-2014 has in the past caused, and would likely in the future cause, a material and adverse effect on our future business, financial condition, results of operations, liquidity and ability to finance capital expenditures. Additionally, if we experience significant sustained decreases in oil and gas prices such that the expected future cash flows from our oil and gas properties falls below the net book value of our properties, we may be required to write down the value of our oil and gas properties. Any such asset impairments could materially and adversely affect our results of operations and, in turn, the trading price of our common stock and ultimately lead to the Nasdaq Global Select Market's ("Nasdaq") decision to delist us.

For more information regarding Nasdaq's ability to delist us, the Listing Rule , and the effect of a reverse stock split, you should read the information under "Risk Related to Our Common Stock - Nasdaq could make a decision to delist us."

We may not be able to fund the capital expenditures that will be required for us to increase reserves and production.

We must make capital expenditures to develop our existing reserves and to discover new reserves.  Historically, we have financed our capital expenditures primarily with cash flows from operations, borrowings under credit facilities, sales of properties, monetizing derivative contracts and sales of debt and equity securities and we expect to continue to utilize these sources in the future to the extent available.  We cannot assure you that we will have sufficient capital resources in the future to finance all of our planned capital expenditures, additionally, our amended credit facilities, place restrictions on our capital expenditures.

Volatility in oil and gas prices, the timing of our drilling programs and drilling results will affect our cash flows from operations.  Lower prices and/or lower production could also decrease revenues and cash flows from operations, thus reducing the amount of financial resources available to meet our capital requirements, including reducing the amount available to pursue our drilling opportunities.  If our cash flows from operations does not increase as a result of capital expenditures, a greater percentage of our cash flows from operations will be required for debt service and operating expenses and our capital expenditures would, by necessity, be decreased.

If cash flows from operations or our borrowing base decrease, our ability to undertake exploration and development activities could be adversely affected.  As a result, our ability to replace production may be limited.  

If we cannot replace the production from the properties sold with production from our remaining properties, our cash flows from operations will likely decrease, which in turn, could decrease the amount of cash available for additional capital spending.

Restrictive debt covenants could limit our growth and our ability to finance our operations, fund our capital needs, respond to changing conditions and engage in other business activities that may be in our best interests.

Our First Lien Credit Facility and our Second Lien Credit Facility contain a number of significant covenants that, among other things, limit our ability to:

In addition, our credit facilities require us to maintain compliance with specified financial covenants.  Our ability to comply with these covenants may be adversely affected by events beyond our control, and we cannot assure you that we can maintain compliance with these covenants.  These financial covenants could limit our ability pursuant to the credit agreements to obtain future advances, make needed capital expenditures or otherwise conduct necessary or desirable business activities. We are also required to prepay outstanding amounts under the First Lien Credit Facility (and under certain circumstances, the Second Lien Credit Facility) with the proceeds from the termination of any derivative contracts and with respect to cash and liquid investments in excess of certain thresholds.

A breach of any of these covenants could result in a default under our First Lien Credit Facility and our Second Lien Credit Facility. For example, at  fiscal quarter ended September 30, 2019, we were not in compliance with the current ratio under our First Lien Credit Facility, and we failed to file our Annual Report on Form 10-K for the period ended December 31, 2019 no later than 90 days after the end of such fiscal year, which resulted in violations of certain covenants under the First Lien Credit Facility. We also failed to maintain the required hedges under the Second Lien Credit Facility with respect to the fiscal quarter  ended March 31, 2020, which resulted in a violation of certain covenants under the Second Lien Credit Facility (as  in effect prior to our amendment of the Second Lien Credit Facility), for which a waiver was obtained. While we received waivers for these defaults, we cannot assure you that we will be able to obtain such waivers in the future. A default, if not cured or waived, could result in all of our indebtedness under the credit facilities becoming immediately due and payable. If that should occur, we may not be able to pay all such indebtedness or to borrow sufficient funds to refinance it. Even if new financing were then available, it may not be on terms acceptable or favorable to us.

See Item 1. Business, Going Concern and Note 14 "Subsequent Events" for current information regarding non-compliance with certain covenants.

Lower oil and gas prices increase the risk of ceiling limitation write-downs.

We use the full cost method to account for our oil and gas operations.  Accordingly, we capitalize the cost to acquire, explore for and develop our oil and gas properties.  Under full cost accounting rules, the net capitalized cost of our oil and gas properties may not exceed a “ceiling limit” which is based upon the present value of estimated future net cash flows from our proved reserves, discounted at 10%.  If the net capitalized costs of our oil and gas properties exceed the ceiling limit, we must charge the amount of the excess to earnings.  This is called a “ceiling limitation write-down.” This charge does not impact cash flows from operating activities, but it does reduce our stockholders’ equity and earnings.  The risk that we will be required to write-down the carrying value of our oil and gas properties increases when oil and gas prices are low, which could be further impacted by the SEC’s oil and gas reporting disclosures, which require us to use an average price over the prior 12-month period, rather than the year-end price, when calculating the PV-10.  In addition, write-downs may occur if we experience substantial downward adjustments to our estimated proved reserves.  An expense recorded in one period may not be reversed in a subsequent period even though oil and gas prices may have increased the ceiling applicable in the subsequent period.

At both December 31, 2019 and 2020, the net capitalized costs of our oil and gas properties exceeded the present value of estimated future cash flows from our proved reserves, resulting in recognition of an impairment of $51.3 million for the year ended December 31, 2019 and  $187.0 million for the year ended December 31, 2020. If commodity prices decline or continue to be depressed we will be required to record further write downs during 2021.

An increase in the differential between NYMEX and the reference or regional index price used to price our oil and gas would reduce our cash flows from operations.

Our oil and gas are priced in the local markets where it is produced based on local or regional supply and demand factors.  The prices we receive for our oil and gas are typically lower than the relevant benchmark prices, such as NYMEX.  The difference between the benchmark price and the price we receive is called a differential.  Numerous factors may influence local pricing, such as refinery capacity, location to market, product quality, pipeline capacity and specifications, upsets in the midstream or downstream sectors of the industry, trade restrictions and governmental regulations.  Additionally, insufficient pipeline capacity, lack of demand in any given operating area or other factors may cause the differential to increase in a particular area compared with other producing areas.  For example, production increases from competing Canadian and Rocky Mountain producers, combined with limited refining and pipeline capacity in the Rocky Mountain area, have gradually widened differentials in this area. In addition, we have a gas sales contract related to certain gas and NGL produced in the Rocky Mountain Region, which provides that if certain margins of gas and NGL prices are not met by the purchaser, we receive no sales proceeds.

During 2020, our differentials averaged $ (2.52) per Bbl of oil and $ (1.86) per Mcf of gas. Approximately  47% of our oil production during 2020 was from the Rocky Mountain region and approximately 53% from the Permian region.  As our production from the Rocky Mountain and Permian regions continues to increase, we expect that the effect our price differentials on our revenues will also increase.  Increases in the differential between the benchmark prices for oil and gas and the realized price we receive could significantly reduce our revenues and our cash flow from operations.

Our derivative contracts could result in financial losses or could reduce our cash flows.

To achieve more predictable cash flows and reduce our exposure to adverse fluctuations in the prices of oil and gas, we sometimes enter into derivative contracts, which we sometimes refer to as hedging arrangements, for a significant portion of our oil and gas production that could result in both realized and unrealized derivative contract losses.  As of December 31, 2020, we had NYMEX-based fixed price commodity swap arrangements, on approximately 88% of the oil production from our estimated net proved developed producing reserves (as of December 31, 2020) through December 31, 2021, 96% for 2022, 72%  for  2123 and 88%. for 2024.The extent of our commodity price exposure is related largely to the effectiveness and scope of our commodity price derivative contracts.  For example, the prices utilized in our derivative contracts were NYMEX-based, which may differ significantly from the actual prices we receive for oil and gas which are based on the local markets where the oil and gas is produced.  The prices that we receive for our oil and gas production are typically lower than the relevant benchmark prices that are used for calculating commodity derivative positions.  The difference between the benchmark price and the price we receive is called a differential, a significant portion of which is based on the delivery location which is called the basis differential.  As a result, our cash flows from operations are affected if the basis differentials widen more than anticipated. We entered into basis swaps to mitigate some of the effects of differentials, however they do not alleviate all of the effects of such differentials. Our cash flows from operations are also affected based upon the levels of our production.  If production is higher than we estimate, we  have greater commodity price exposure than intended.  If production is lower than the nominal amount that is subject to our hedging arrangements, we may be forced to satisfy all or a portion of our hedging arrangements without the benefit of the cash flows from our sale of the underlying physical commodity, resulting in a substantial reduction in cash flows from operations. In April 2021, we received notice that certain of our hedging agreements were being terminated as a result of events of default under the First Lien Credit Facility and we voluntarily terminated most of our other hedging arrangements. As a result of the settlement of the terminated hedges, we have outstanding obligations of $9.9 million. The settlement values of the terminated hedges were determined at various dates between April 15 and April 30, 2021. These obligations will be added to the balance of the First Lien Credit Facility and accrue interest  at the default interest rate, currently 6.7%, until repaid. Our remaining hedging agreements may also be terminated as a result of such events of default. The settlement of terminated hedging agreements may result in losses and limit our ability to reduce exposure to adverse fluctuations in oil and gas prices. See Note 14 “Subsequent Events” for current information regarding non-compliance with certain covenants

If the prices at which we hedge our oil and gas production are less than current market prices, our cash flows from operations could be adversely affected.

When our derivative contract prices are higher than market prices, we will incur realized and unrealized gains on our derivative contracts and conversely, when our contract prices are lower than market prices, we will incur realized and unrealized losses. For the year ended December 31, 2020, we recognized a gain on our oil and gas derivative contracts of $42.9 million, consisting of a gain of $17.5 million on our settled contracts and a gain of $25.4 million on open contracts. The gain on settled contracts resulted in an increase in cash flows from operations.  We have terminated most of our hedging arrangements subsequent to December 31, 2020.

We cannot assure you that any derivative contracts that we enter into, will adequately protect us from financial loss in the future due to circumstances such as:

The counterparties to our derivative contracts may be unable to perform their obligations to us which could adversely affect our cash flows.

At times when market prices are lower than our derivative contract prices, we are entitled to cash payments from the counterparties to our derivative contracts.  Any number of factors may adversely affect the ability of our counterparties to fulfill their contractual obligations to us.  If one of our counterparties is unable or unwilling to make the required payments to us, it could adversely affect our cash flows from operations.

The Company's expectations for future drilling activities will be realized over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of such activities.

The Company has identified drilling locations and prospects for future drilling opportunities, including development and exploratory drilling activities. These drilling locations and prospects represent a significant part of the Company's future drilling plans. For example, the Company's proved reserves as of December 31, 2020 included proved undeveloped reserves and proved developed reserves that are behind pipe of 884  MBbls of oil, 190 MBbls of NGL and 1,185  MMcf of gas. Due to the substantial doubt that the Company can continue as a "going concern" the proved undeveloped reserves were removed. If and when the Company has the  capital to complete the undeveloped reserves, they will be reinstated in the Company's total  proved reserves. The Company's ability to drill and develop these locations depends on a number of factors, including the availability of capital, regulatory approvals, negotiation of agreements with third parties, commodity prices, costs, access to and availability of equipment, services, resources and personnel and drilling results. There can be no assurance that the Company will drill these locations or that the Company will be able to produce oil or gas reserves from these locations or any other potential drilling locations. Changes in the laws or regulations on which the Company relies in planning and executing its drilling programs could adversely impact the Company's ability to successfully complete those programs. For example, under current Texas laws and regulations the Company may receive permits to drill, and may drill and complete, certain horizontal wells that traverse one or more units and/or leases; a change in those laws or regulations could adversely impact the Company's ability to drill those wells. Because of these uncertainties, the Company cannot give any assurance as to the timing of these activities or that they will ultimately result in the realization of proved reserves or meet the Company's expectations for success. As such, the Company's actual drilling activities may materially differ from the Company's current expectations, which could have a significant adverse effect on the Company's proved reserves, financial condition and results of operations.

We may be unable to acquire or develop additional reserves, in which case our results of operations and financial condition could be adversely affected.

Our future oil and gas production, and therefore our success, is highly dependent upon our ability to find, acquire and develop additional reserves that are profitable to produce.  The rate of production from our oil and gas properties and our proved reserves will decline as our reserves are produced.  Unless we acquire additional properties containing proved reserves, conduct successful development and exploration activities or, through engineering studies, identify additional behind-pipe zones or secondary recovery reserves, we cannot assure you that our exploration and development activities will result in increases in our proved reserves. Based on the reserve information set forth in our reserve report as of December 31, 2020, our average annual estimated decline rate for our net proved developed producing reserves is  39%; 18% ; 14% ; 12% ; 12% in  2021, 2022, 2023, 2024 and 2025, respectively, 9% in the following five years, and approximately 9% thereafter.  These rates of decline are estimates and actual production declines could be materially higher. We have not always been able to fully replace the production volumes lost from natural field declines and prior property sales.  As our proved reserves and consequently our production decline, our cash flow from operations, and the amount that we are able to borrow under our credit facilities could also decline.  

We may not find any commercially productive oil and gas reservoirs.

Drilling involves numerous risks, including the risk that the new wells we drill will be unproductive or that we will not recover all or any portion of our capital investment.  Drilling for oil and gas may be unprofitable.  Wells that are productive but do not produce sufficient net revenues after drilling, operating and other costs are unprofitable.   By their nature, estimates of undeveloped reserves are less certain.  Recovery of such reserves will require significant capital expenditures and successful drilling and completion operations.  Due to the substantial doubt of the Company remaining as a "going concern", all of the proved undeveloped reserves initially contained in the December 31, 2020 reserve report have been removed.   If the volume of oil and gas we produce decreases, our cash flows from operations may decrease.

The results of our drilling in unconventional formations, principally in emerging plays with limited drilling and production history using long laterals and modern completion techniques, are subject to more uncertainties than our drilling program in the more established plays and may not meet our expectations for reserves or production.

We drill wells in unconventional formations in several emerging plays.  Part of our drilling strategy to maximize recoveries from these formations involves the drilling of long horizontal laterals and the use of modern completion techniques of multi-stage fracture stimulations that have proven to be successful in other basins. Risks that we face include landing our well bore in the desired drilling zone, staying in the desired drilling zone, running casing the entire length of the well bore and being able to run tools and recover equipment the entire length of the well bore during completion. Our experience with horizontal drilling and multi-stage fracture stimulations of these formations to date, as well as the industry’s drilling and production history in these formations, is relatively limited. The ultimate success of these drilling and completion strategies and techniques will be better evaluated over time as more wells are drilled and longer term production profiles are established. In addition, based on reported decline rates in these emerging plays as well as the industry’s experience in these formations, we estimate that the average monthly rates of production may decline as much as 95% during the first twelve months of production. Actual decline rates may differ significantly. Accordingly, the results of our drilling in these unconventional formations are more uncertain than drilling results in other more established plays with longer reserve and production histories.

We may not be able to keep pace with technological developments in our industry.

The oil and gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement those new technologies at substantial cost. In addition, other oil and gas companies may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures and implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete or if we are unable to use the most advanced commercially available technology, our business, financial condition and results of operations could be materially adversely affected.

We may not adhere to our proposed drilling schedule.

Our final determination of whether to drill any scheduled or budgeted wells will be dependent on a number of factors, including:

Although we have identified numerous drilling locations, we may not be able to drill those locations within our expected time frame or at all.  In addition, our drilling schedule may vary from our expectations because of future uncertainties. For example, we have in the past, and may be required in the future, to delay drilling or completing wells in order to protect them from fracture stimulation of other wells in the same area.

We cannot control the activities on the properties we do not operate and are unable to ensure their proper operation and profitability.

We currently do not operate all of the properties in which we have an interest. Non-operated properties represented approximately 2.6% of our estimated net proved reserves on a Boe basis at December 31, 2020.  As a result, we have limited ability to exercise influence over and control the risks associated with operation of these properties. The failure of an operator to adequately perform operations, an operator’s breach of the applicable agreements or an operator’s failure to act in our best interests could reduce our production and revenues. The success and timing of our drilling and development activities on properties operated by others therefore depends upon a number of factors outside of our control, including:

Any of these events could significantly and adversely affect our anticipated exploitation and development activities.

Seasonal weather conditions and other factors could adversely affect our ability to conduct drilling activities.

Our operations could be adversely affected by weather conditions and wildlife restrictions on federal leases. In the Williston Basin, drilling and other oil and gas activities cannot be conducted as efficiently during the winter and spring months. Winter and severe weather conditions limit and may temporarily halt the ability to operate during such conditions. These constraints and the resulting shortages or high costs could delay or temporarily halt our oil and gas operations and materially increase our operating and capital costs, which could have a material adverse effect on our business, financial condition and results of operations.

The lack of availability or high cost of drilling rigs, equipment, supplies, personnel and oil field services could adversely affect our ability to execute our exploitation and development plans on a timely basis and within our budget.

Our industry is cyclical and, from time to time, there has been a shortage of drilling rigs, equipment, supplies, oil field services or qualified personnel. During these periods, the costs and delivery times of rigs, equipment and supplies are substantially greater. In addition, the demand for, and wage rates of, qualified drilling rig crews rise as the number of active rigs in service increases. During times and in areas of increased activity, the demand for oilfield services will also likely rise, and the costs of these services will likely increase, while the quality of these services may suffer. If the lack of availability or high cost of drilling rigs, equipment, supplies, oil field services or qualified personnel were particularly severe in any of our areas of operation, we could be materially and adversely affected. Delays could also have an adverse effect on our results of operations, including the timing of the initiation of production from new wells.

Our drilling operations may be curtailed, delayed or cancelled as a result of a variety of factors that are beyond our control.

Our drilling operations are subject to a number of risks, including:

Any of these events could adversely affect our ability to conduct operations or cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution or other environmental contamination, loss of wells, regulatory penalties, suspension of operations, and attorney’s fees and other expenses incurred in the prosecution or defense of litigation.

We do not insure against all potential operating risks. We might incur substantial losses from, and be subject to substantial liability claims for, uninsured or underinsured risks related to our oil and gas operations.

We do not insure against all risks. Our oil and gas exploitation and production activities are subject to hazards and risks associated with drilling for, producing and transporting oil and gas, and any of these risks can cause substantial losses resulting from:

We might elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. Losses and liabilities arising from uninsured and underinsured events or in amounts in excess of existing insurance coverage could have a material adverse effect on our business, financial condition or results of operations.

Hydraulic fracturing, the process used for extracting oil and gas from shale and other formations, could be the subject of further regulation that could impact the timing and cost of development.

Hydraulic fracturing is the primary completion method used to extract reserves located in many of the unconventional oil and gas plays. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure, usually down tubing or casing that is cemented in the wellbore, into hydrocarbon-bearing formations at depth to stimulate oil and gas production. We use this completion technique on substantially all of our wells. Depending on the legislation that may ultimately be enacted or the regulations that may be adopted at the federal and state levels, exploration, exploitation and production activities that entail hydraulic fracturing could be subject to additional regulation and permitting requirements. Some states in which we operate, including Texas, have implemented disclosure requirements related to chemicals used in hydraulic fracturing, and while the BLM has rescinded its rules governing hydraulic fracturing on federal and tribal lands (which action itself is subject to pending litigation), we anticipate further regulation of hydraulic fracturing and related activities by states and local governments. Individually or collectively, such existing and new legislation or regulation could lead to operational delays or increased operating costs and could result in additional burdens that could increase the costs and delay the development of unconventional oil and gas resources from formations which are not commercial without the use of hydraulic fracturing. This could have an adverse effect on our business, financial condition and results of operations.

Hydraulic fracturing is typically regulated by state oil and gas commissions; however, the EPA has asserted federal regulatory authority over hydraulic fracturing involving diesel fuels under the Underground Injection Control Program established under the Safe Drinking Water Act, or SDWA, and published permitting guidance and an interpretive memorandum addressing the performance of such activities.   In addition, the U.S. Congress, from time to time, has considered adopting legislation intended to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic-fracturing process. In the event that a new federal level of legal restrictions relating to the hydraulic fracturing process is adopted in areas where we currently or in the future plan to operate, we may incur additional costs to comply with such federal requirements that may be significant in nature, become subject to additional permitting requirements and experience added delays or curtailment in the pursuit of exploration, development or production activities.

Certain states in which we operate, including Texas, have adopted, and other states are considering adopting, regulations that could impose new or more stringent permitting, disclosures, and/or well-construction requirements on hydraulic-fracturing operations.    In addition to state laws, local land use restrictions, such as city ordinances, may restrict or prohibit drilling in general or hydraulic fracturing in particular. In some states, including Texas, water use may also be regulated and potentially curtailed by local groundwater management districts which could impact water available for hydraulic fracturing. We believe that we follow applicable standard industry practices and legal requirements for groundwater protection in our hydraulic fracturing activities.  Nonetheless, in the event state or local restrictions are adopted in areas where we are currently conducting, or in the future plan to conduct operations, we may incur additional costs to comply with such requirements that may be significant in nature, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps be limited or precluded in the drilling of wells or in the amounts that we are ultimately able to produce from our reserves.

See “Item 1. Business – Environmental Matters – Hydraulic Fracturing” above for additional discussion related to environmental risks associated with our hydraulic fracturing activities.

Our operations are substantially dependent on the availability of water. Restrictions on our ability to obtain water may have an adverse effect on our financial condition, results of operations and cash flows from operations.

Water is an essential component of both the drilling and hydraulic fracturing processes. Historically, we have been able to purchase water from local land owners and other sources for use in our operations. Over the past few years, extreme drought conditions persisted in West and South Texas. Although conditions have improved, we cannot guarantee what conditions may occur in the future. Severe drought conditions can result in local water districts taking steps to restrict the use of water subject to their jurisdiction for drilling and hydraulic fracturing in order to protect the local water supply. If we are unable to obtain water to use in our operations from local resources, we may be unable to economically produce oil and gas, which could have an adverse effect on our financial condition, results of operations and cash flows from operations.

Studies noting a connection between increased seismic activity and the injection of wastewater from oil and gas operations could result in new laws or regulations which would increase our cost of operations.

Some studies have noted an increase in localized frequency of seismic activity associated with underground injection wastewater from oil and gas operations. If the results of these studies are confirmed, new legislative and regulatory initiatives could require additional monitoring, restrict the injection of produced water in certain disposal wells or modify or curtail hydraulic fracturing operations. These actions could lead to operational delays, increased compliance costs or otherwise adversely impact our operations.

We face various risks associated with the trend toward increased anti-development activity.

As new technologies have been applied to our industry, we have seen significant growth in oil and gas supply in recent years, particularly in the U.S. With this expansion of oil and gas development activity, opposition toward oil and gas drilling and development activity has been growing both in the U.S. and globally. Companies in the oil and gas industry, such as us, can be the target of opposition to development from certain stakeholder groups. These anti-development efforts could be focused on:

Future anti-development efforts could result in the following:

Costs associated with responding to these initiatives or complying with any new legal or regulatory requirements resulting from these activities could be substantial and not adequately provided for, could have a material adverse effect on our business, financial condition and results of operations. In addition, the use of social media channels can be used to cause rapid, widespread reputational harm.

The adoption of derivatives legislation and regulations related to derivative contracts could have an adverse impact on our ability to hedge risks associated with our business.  

Title VII of the Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Act establishes federal oversight and regulation of over-the-counter, or OTC, derivatives and requires the Commodity Futures Trading Commission, or CFTC, and the SEC to enact further regulations affecting derivative contracts, including the derivative contracts we use to hedge our exposure to price volatility through the OTC market. Although the CFTC and the SEC have issued final regulations in certain areas, final rules in other areas and the scope of relevant definitions and/or exemptions still remain to be finalized. In one of its rulemaking proceedings still pending under the Dodd-Frank Act, on November 5, 2013 (as modified and re-proposed on December 30, 2016), the CFTC approved a proposed rule imposing position limits for certain futures and option contracts in various commodities (including gas) and for swaps that are their economic equivalents. Certain specified types of hedging transactions are proposed to be exempt from these position limits, provided that such hedging transactions satisfy the CFTC’s requirements for “bona fide hedging” transactions or positions. Similarly, on December 16, 2016, the CFTC issued a proposed rule regarding the capital that a swap dealer, or major swap participant, is required to post with respect to its swap business, but has not yet issued a final rule. On January 6, 2016, the CFTC issued a final rule on margin requirements for uncleared swap transactions, which includes an exemption for commercial end-users, entering into uncleared swaps in order to hedge commercial risks affecting their business, from any requirement to post margin to secure such swap transactions. In addition, on July 19, 2012, the CFTC issued a final rule authorizing an exception for commercial end-users using swaps to hedge their commercial risks from the otherwise applicable mandatory obligation under the Dodd-Frank Act to clear all swap transactions through a registered derivatives clearing organization and to trade all such swaps on a registered exchange. The Dodd-Frank Act also imposes recordkeeping and reporting obligations on counterparties to swap transactions and other regulatory compliance obligations. All of the above regulations and requirements could increase the costs to us of entering into, and lessen the availability of, derivative contracts to hedge or mitigate our exposure to volatility in oil, gas and NGL prices and other commercial risks affecting our business.

It is not possible at this time to predict when the CFTC will issue final rules applicable to position limits or capital requirements. Moreover, our ability to satisfy the CFTC’s requirements for the various exemptions available for a commercial end-user using swaps to hedge or mitigate its commercial risks may affect whether we are required to comply with margin and certain clearing and trade-execution requirements in connection with our derivative activities. If we do not qualify for the commercial end-user exception, we may be required to post margin or clear certain transactions, which could reduce our liquidity and cash available for capital expenditures and our ability to hedge may be impacted. When a final rule on capital requirements is issued, the Dodd-Frank Act may require our current swap counterparties to post additional capital as a result of entering into uncleared derivatives with us, which could increase the costs to us of entering into, and lessen the availability of us to, derivative contracts. The Dodd-Frank Act may also require our current counterparties to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties, and may cause some entities to cease their current business as hedge providers. These changes could reduce the liquidity of the derivatives markets thereby reducing the ability of commercial end-users to have access to derivative contracts to hedge or mitigate their exposure to volatility in oil, gas, and NGL prices. The Dodd-Frank Act and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect our available capital for other commercial operations purposes), materially alter the terms of future swaps relative to the terms of our existing bilaterally negotiated derivative contracts, and reduce the availability of derivatives to protect us against commercial risks we encounter.

In addition, federal banking regulators have adopted new capital requirements for certain regulated financial institutions in connection with the Basel III Accord. The Federal Reserve Board also issued proposed regulations on September 30, 2016, proposing to impose higher risk-weighted capital requirements on financial institutions active in physical commodities, such as oil and gas. If and when these proposed regulations are fully implemented, financial institutions subject to these higher capital requirements may require that we provide cash or other collateral with respect to our obligations under the financial derivatives and other contracts we may enter into with such financial institutions in order to reduce the amount of capital such financial institutions may have to maintain. Alternatively, financial institutions subject to these capital requirements may price transactions so that we will have to pay a premium to enter into derivatives and other physical commodity transactions in an amount that will compensate the financial institutions for the additional capital costs relating to such derivatives and physical commodity transactions. Rules implementing the Basel III Accord and higher risk-weighted capital requirements could materially reduce our liquidity and increase the cost of derivative contracts and other physical commodity contracts (including through requirements to post collateral, which could adversely affect our available capital for other commercial operations purposes). In addition, certain foreign jurisdictions may adopt or implement laws and regulations relating to margin and central clearing requirements, which in each case may affect our counterparties and the derivatives markets generally.

If we reduce our use of derivative contracts as a result of any of the foregoing regulations or requirements, our results of operations may become more volatile and cash flows less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the volatility of oil, gas, and NGL prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil, gas, and NGL. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our financial position, results of operations, or cash flows from operations.

If we were to experience an ownership change, we could be limited in our ability to use net operating losses arising prior to the ownership change to offset future taxable income. In addition, our ability to use net operating loss carry forwards to reduce future tax payments may be limited if our taxable income does not reach sufficient levels.

As of December 31, 2020, we had pre 2018 net operating loss carryforwards or NOLs, for federal income tax purposes of $245.2 million and post 2018 NOLs of $140.0 million. If we were to experience an "ownership change," as determined under Section 382 of the Internal Revenue Code of 1986, as amended (the "Code"), our ability to offset taxable income arising after the ownership change with NOLs arising prior to the ownership change would be limited, possibly substantially. An ownership change would establish an annual limitation on the amount of our pre-change NOLs we could utilize to offset our taxable income in any future taxable year to an amount generally equal to the value of our stock immediately prior to the ownership change multiplied by the long-term tax-exempt rate. In general, an ownership change will occur if there is a cumulative increase in our ownership of more than 50 percentage points by one or more "5% shareholders" (as defined in the Code) at any time during a rolling three-year period.

As a result of the Tax Cuts and Jobs Act of 2017, and The Coronavirus Aid, Relief, and Economic Security Act of 2020, NOLs  arising before January 1, 2018, and NOLs arising after January 1, 2018, are subject to different rules. Our pre-2018 NOLs will expire in varying amounts from 2023 through 2037, if not utilized; and can offset 100% of future taxable income for regular tax purposes. Our NOLs arising in 2018, 2019 and 2020 can generally be carried back five years, carried forward indefinitely and can offset 100% of future taxable income for tax years before January 1, 2021 and up to 80% of future taxable income for tax years after December 31, 2020. Any NOLs arising on or after January 1, 2021, cannot be carried back, can generally be carried forward indefinitely and can offset up to 80% of future taxable income. Our ability to use our NOLs during this period will be dependent on our ability to generate taxable income, and the NOLs could expire before we generate sufficient taxable income.

Cyber-attacks targeting systems and infrastructure used by the oil and gas industry may adversely impact our operations.

Our business has become increasingly dependent on digital technologies to conduct certain exploration, development and production activities.  We depend on digital technology to estimate quantities of oil and gas reserves, process and record financial and operating data, analyze seismic and drilling information, and communicate with our employees and third-party partners.  Unauthorized access to our seismic data, reserves information or other proprietary information could lead to data corruption, communication interruption, or other operational disruptions in our exploration or production operations.  In addition, computer technology controls nearly all of the oil and gas distribution systems in the United States and abroad, which are necessary to transport our production to market.  A cyber-attack directed at oil and gas distribution systems could damage critical distribution and storage assets or the environment, delay or prevent delivery of production to markets and make it difficult or impossible to accurately account for production and settle transactions.

While we have not experienced significant cyber-attacks, we may suffer such-attacks in the future. Further, as cyber-attacks continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber-attacks.

We rely on independent experts and technical or operational service providers over whom we may have limited control.

We use independent contractors to provide us with certain technical assistance and services.  We rely upon the owners and operators of rigs and drilling equipment, and upon providers of field services, to drill and develop our prospects to production.  We also rely upon the services of other third parties to explore and/or analyze our prospects to determine a method in which the prospects may be developed in a cost-effective manner.  Our limited control over the activities and business practices of these service providers, any inability on our part to maintain satisfactory commercial relationships with them or their failure to provide quality services could materially adversely affect our business, results of operations and financial condition.

We depend on our President, CEO and Chairman of the Board and the loss of his services could have an adverse effect on our operations.

We depend to a large extent on Robert L.G. Watson, our President and Chief Executive Officer, for our management, business and financial contacts.  Mr. Watson may terminate his employment agreement with us at any time on 30 days' notice, but, if he terminates without good reason, he would not be entitled to the severance benefits provided under the terms of that agreement.  Mr. Watson is not precluded from working for, with or on behalf of a competitor upon termination of his employment with us.  If Mr. Watson were no longer able or willing to act as President, Chief Executive Officer and Chairman of the Board, the loss of his services could have an adverse effect on our operations.

Risks Related to Our Industry

Market conditions for oil and gas, and particularly volatility of prices for oil and gas, could adversely affect our revenue, cash flows from operations, profitability and growth.

Our revenue, cash flows from operations, profitability and future rate of growth depend substantially upon prevailing prices for oil and gas.  Prices also affect the amount of cash flows available for capital expenditures and our ability to borrow money or raise additional capital.  Lower prices may also make it uneconomical for us to increase or even continue current production levels of oil and gas.  At the beginning of 2019, OPEC members and some nonmembers, including Russia, renewed pledges to reduce planned production in an effort to draw down a global oversupply and to rebalance supply and demand. As a result of a decrease in global demand for oil and natural gas due to the recent coronavirus outbreak, at the beginning of March 2020, negotiations to extend this pledge were unsuccessful. As a result, Saudi Arabia announced a significant reduction in its export prices and Russia announced that all agreed oil production cuts between members of OPEC and Russia would expire on April 1, 2020. Following these announcements, global oil and natural gas prices declined sharply and may continue to decline. Subsequently further negotiations in April 2020 resulted in an agreement to reduce production volumes in an effort to stabilize global oil prices. While prices have recovered from the lows in March 2020, they remain at depressed levels.  We expect ongoing oil price volatility as supply increases over the short term as a result of Saudi Arabia and Russia’s actions.

Prices for oil and gas are subject to large fluctuations in response to relatively minor changes in the supply and demand for oil and gas, market uncertainty and a variety of other factors beyond our control, including:

Events beyond our control, including a global or domestic health crisis, may result in unexpected adverse operating and financial results.   In response to the COVID-19 pandemic governments around the world, including U.S. federal, state, and local governments, have imposed restrictions intended to limit the extent and spread of the virus, including travel restrictions, quarantines and business closures. These and other actions could, among other things, impact the ability of our employees and contractors to perform their duties, cause increased technology and security risk due to extended and company-wide telecommuting and lead to disruptions in our permitting activities and critical business relationships. Additionally, the COVID-19 outbreak and governmental restrictions have significantly impacted economic activity and markets and have dramatically reduced current and anticipated demand for oil and natural gas, adversely impacting the prices we receive for our production. The severity and duration of the current COVID-19 outbreak and the potential for future outbreaks are uncertain and difficult to predict. COVID-19 or another similar outbreak may negatively impact our business in numerous ways, including, but not limited to, the following:    

  The COVID-19 pandemic may also have the effect of heightening many of the other risks set forth in this Item 1A, “Risk Factors”. Any of these factors could have a material adverse effect on our business, operations, financial results and liquidity. Recently, oil and natural gas have declined to historically low levels and we have reduced our planned capital expenditures, delayed our drilling and completion plans and have begun shutting-in most of our producing wells, among other responses. We are unable to predict the ultimate adverse impact of COVID-19 on our business, which will depend on numerous evolving factors and future developments, including the length of time that the pandemic continues, its ongoing effect on the demand for oil and natural gas and the response of the overall economy and the financial markets after governmental restrictions are eased.
 

Estimates of proved reserves and future net revenue are inherently imprecise.

The process of estimating oil and gas reserves in accordance with SEC requirements is complex and involves decisions and assumptions in evaluating the available geological, geophysical, engineering and economic data.  Accordingly, these estimates are imprecise.  Actual future production, oil and gas prices, revenues, taxes, capital expenditures, operating expenses and quantities of recoverable oil and gas reserves most likely will vary from those estimated.  Any significant variance could materially affect the estimated quantities and present value of our reserves.  In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and gas prices and other factors, many of which are beyond our control.

The estimates of our reserves as of December 31, 2020 are based upon various assumptions about future production levels, prices and costs that may not prove to be correct over time.  In particular, estimates of oil and gas reserves, future net revenue from proved reserves and the present value of our oil and gas properties are based on the assumption that future oil and gas prices remain the same as the twelve month first-day-of-the-month average oil and gas prices for the year ended December 31, 2020.  The average realized sales prices used for purposes of such estimates were $39.54 per Bbl of oil and $2.03 per Mcf of gas. The December 31, 2020 estimates also assume that we will make future capital expenditures of approximately$6.3 million in the aggregate primarily from 2020 through 2024, which are necessary to develop and realize the value of proved reserves on our properties.  We cannot assure you that we will have sufficient capital in the future to make these capital expenditures. Any significant variance in actual results from these assumptions could also materially affect the estimated quantity and value of our reserves set forth or incorporated by reference in this report.

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 reserves.  Any material inaccuracies in our 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.

As required by SEC regulations, we based the estimated discounted future net cash flows from our proved reserves as of December 31, 2020 on the twelve month first-day-of-the-month average oil and gas prices for the year ended December 31, 2020 and costs in effect on December 31, 2020, the date of the estimate.  However, actual future net cash flows from our properties will be affected by factors such as:

In addition, the 10% discount factor we use when calculating discounted future net cash flows, which is required by the SEC, 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 gas industry in general.  Any material inaccuracies in our 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 operations are subject to the numerous risks of oil and gas drilling and production activities.

Our oil and gas drilling and production activities are subject to numerous risks, many of which are beyond our control.  These risks include the risk of fire, explosions, blow-outs, pipe failure, abnormally pressured formations and environmental hazards.  Environmental hazards include oil and saltwater spills, gas leaks, ruptures, discharges of toxic gases, underground migration and surface spills or mishandling of any toxic fracture fluids, including chemical additives.  In addition, title problems, weather conditions and mechanical difficulties or shortages or delays in delivery of drilling rigs and other equipment could negatively affect our operations.  If any of these or other similar industry operating risks occur, we could have substantial losses.  Substantial losses also may result from injury or loss of life, severe damage to or destruction of property, clean-up responsibilities, environmental damage, regulatory investigation and penalties and suspension of operations.  In accordance with industry practice, we maintain insurance against some, but not all, of the risks described above.  We cannot assure you that our insurance will be adequate to cover losses or liabilities.  Also, we cannot predict the continued availability of insurance at premium levels that justify its purchase.

We operate in a highly competitive industry which may adversely affect our operations.

We operate in a highly competitive environment.  The principal resources necessary for the exploration and production of oil and gas are leasehold prospects under which oil and gas reserves may be discovered, drilling rigs and related equipment to explore for such reserves and knowledgeable personnel to conduct all phases of operations.  We must compete for such resources with both major oil and gas companies and independent operators.  Many of these competitors have financial and other resources substantially greater than ours.  Although we believe our current operating and financial resources are adequate to preclude any significant disruption of our operations, we cannot assure you that such resources will be available to us in the future.

Our oil and gas operations are subject to various U.S. federal, state and local regulations that materially affect our operations.

In the oil and gas industry, matters regulated include permits for drilling and completion operations, drilling and abandonment bonds, reports concerning operations, the spacing of wells and unitization and pooling of properties, the disposal of wastes and taxation.  At various times, regulatory agencies have imposed price controls and limitations on production.  In order to conserve supplies of oil and gas, these agencies have at times restricted the rates of flow from oil and gas wells below actual production capacity.  U.S. federal, state and local laws regulate production, handling, storage, transportation and disposal of oil and gas by-products and other substances and materials produced or used in connection with oil and gas operations.  To date, our expenditures related to complying with these laws and for remediation of existing environmental contamination have not been significant.  We believe that we are in substantial compliance with all applicable laws and regulations.  However, the requirements of such laws and regulations are frequently changed.  We cannot predict the ultimate cost of compliance with these requirements or their effect on our operations.

Recently enacted federal legislation will affect our tax position concerning tax deductions currently available with respect to oil and gas drilling may adversely affect our net earnings.

In December 2017, Congress enacted the budget reconciliation act commonly referred to as the Tax Cuts and Jobs Act, or TCJA. The law made significant changes to U.S. federal income tax laws, including reducing the corporate income tax rate from 35 percent to 21 percent, repealing the corporate alternative minimum tax, or AMT, partially limiting the deductibility of interest expense and NOLs, eliminating the deduction for certain U.S. production activities and allowing the immediate deduction of certain new investments in lieu of depreciation expense over time. Many aspects of the TCJA are unclear and may not be clarified for some time.

Congress has recently considered, is considering, and may continue to consider, legislation that, if adopted in its proposed or similar form, would deprive some companies involved in oil and gas exploration and production activities in certain U.S. federal income tax incentives and deductions currently available to such companies.  These changes include, but are not limited to (i) the repeal of the percentage depletion allowance for oil and gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain domestic production activities and (iv) an extension of the amortization period for certain geological and geophysical expenditures.

It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective and whether such changes may apply retroactively.  Although we are unable to predict whether any of these or other proposals will ultimately be enacted, the passage of any legislation as a result of these proposals or any other similar changes to U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available to us, and any such change could negatively affect our financial condition and results of operations.

Climate change and regulations related to GHGs could have an adverse effect on our operations and on the demand for oil and gas.

Scientific studies have indicated that emissions of certain gases may be contributing to warming of the Earth’s atmosphere. Domestically, the Fourth National Climate Assessment report, released in November 2018, noted that climate change is mostly driven by GHG emissions and that climate change is accelerating. Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of oil, gas, and refined petroleum products, are considered GHGs. We expect continuing debate, especially in the political arena, over how to address climate change and what policies and regulations are necessary to address the issue. In response to various scientific studies, governments have begun adopting domestic and international climate change regulations that require reporting and reduction of emissions of GHGs. It is possible that international efforts spear-headed by the United Nations and subsequent domestic and international regulations will have adverse effects on the market for oil, gas and other fossil fuel products as well as adverse effects on the business and operations of companies engaged in the exploration for, and production of, oil, gas and other fossil fuel products. In the United States, at the state level and local level, several states and localities, either individually or through multi-state regional initiatives, have begun implementing legal measures to reduce emissions of GHGs. At the federal level, various climate change legislative measures have been considered by the U.S. Congress, but it is not possible at this time to predict when, or if, Congress will act on climate change legislation, although any major initiatives in this area are unlikely to become law in the near future due to opposition in Congress. We are unable to predict the timing, scope and effect of any currently proposed or future investigations, laws, regulations or treaties regarding climate change and GHG emissions, but the direct and indirect costs of such investigations, laws, regulations and treaties (if enacted) could materially and adversely affect our operations, financial condition and results of operations.

Any laws or regulations that may be adopted to restrict or reduce emissions of GHGs could require us to incur increased operating and compliance costs, and could have an adverse effect on demand for the oil and gas that we produce and, as a result, our financial condition and results of operations could be adversely affected.

In addition, local weather effects associated with climate change, including more severe rainfall events, more intense storms, flooding, or droughts could adversely affect our facilities or the scheduling of deliveries or the cost of supplies needed to run our business.

EPA’s ground-level ozone standards may result in more stringent regulation of air emissions from, and adverse economic impacts on, our operations.

Effective December 2015, the EPA adopted a final rule under the Clean Air Act, lowering the National Ambient Air Quality Standard (NAAQS) for ground-level ozone from 75 parts per billion to 70 parts per billion under both the primary and secondary standards designed to provide protection of public health and welfare, respectively.  EPA has now issued new area designations with respect to ground-level ozone, and in November 2018 EPA issued final requirements for implementation that apply to state and local agencies. Areas of the country that have been reclassified so that they are no longer in attainment with the 2015 standard will be more costly and difficult for operators to construct new or modified sources of air pollution, including those associated with our operations. Moreover, such reclassified areas more stringent regulations may require among other things, installation of new emission controls on some of our equipment, result in longer permitting timelines, and significantly increase our capital expenditures and operating costs.

Proposed legislation and regulation under consideration regarding rail transportation could increase our operating costs, reduce our liquidity, delay our operations or otherwise alter the way we conduct our business.

We presently sell all of our oil production at the lease, either by truck or pipeline, where custody transfers to the purchaser, accordingly it is unknown to us how much of the oil production is ultimately shipped by rail. In response to recent train derailments occurring in the United States, U.S. regulators are implementing or considering new rules to address the safety risks of transporting oil by rail. On January 23, 2014, the NTSB issued a series of recommendations to address safety risks, including (i) requiring expanded hazardous material route planning for railroads to avoid populated and other sensitive areas, (ii) developing an audit program to ensure rail carriers that carry petroleum products have adequate response capabilities to address worst-case discharges of the entire quantity of product carried on a train, and (iii) auditing shippers and rail carriers to ensure they are properly classifying hazardous materials in transportation and that they have adequate safety and security plans in place. Additionally, on February 25, 2014 the DOT issued an emergency order requiring all persons, prior to offering oil into transportation, to ensure such product is properly tested and classed and to assure all shipments by rail of oil be handled as a Packing Group I or II hazardous material. The introduction of these or other regulations that result in new requirements addressing the type, design, specifications or construction of rail cars used to transport oil could result in severe transportation capacity constraints during the period in which new rail cars are retrofitted or constructed to meet new specifications.

We do not currently own or operate rail transportation facilities or rail cars; however, the adoption of any regulations that impact the testing or rail transportation of oil could increase our costs of doing business and limit our ability to transport and sell our 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 from operations.

Risks Related to Our Common Stock

Future issuance of additional shares of common stock could cause dilution of ownership interests and adversely affect our stock price.

We are currently authorized to issue 20,000,000 shares of common stock with such rights as determined by our board of directors.  In the future, we may increase our authorized shares of common stock or issue previously authorized and unissued securities, resulting in the dilution of the ownership interests of current stockholders.  The potential issuance of any such additional shares of common stock may create downward pressure on the trading price of our common stock.  We may also issue additional shares of common stock or other securities that are convertible into or exercisable for common stock for capital raising or other business purposes.  Future sales of substantial amounts of common stock, or the perception that sales could occur, could have a material adverse effect on the price of our common stock.

We will not pay dividends on our common stock for the foreseeable future.

We currently anticipate that we will retain all future earnings, if any, to finance the growth and development of our business. We do not intend to pay cash dividends in the foreseeable future.  In addition, our credit facilities prohibit us from paying dividends and making other cash distributions.

Shares eligible for future sale may depress our stock price.

At December 31, 2020, we had 8,421,910 shares of common stock outstanding of which 208,020 shares were held by affiliates and, in addition, 194,695 shares of common stock were subject to outstanding options granted under stock option plans (of which 192,096 shares were vested at December 31, 2020).

All of the shares of common stock held by affiliates are restricted or are control securities under Rule 144 promulgated under the Securities Act.  The shares of common stock issuable upon exercise of stock options have been registered under the Securities Act.  Sales of shares of common stock under Rule 144 or another exemption under the Securities Act or pursuant to a registration statement could have a material adverse effect on the price of our common stock and could impair our ability to raise additional capital through the sale of equity securities.

The price of our common stock has been volatile and could continue to fluctuate substantially.

Our common stock is traded on The Nasdaq Stock Market (the "Nasdaq").  The market price of our common stock has been volatile and could fluctuate substantially based on a variety of factors, including the following:

We may issue shares of preferred stock with greater rights than our common stock.

Subject to the rules of The NASDAQ Stock Market, our articles of incorporation authorize our board of directors to issue one or more series of preferred stock and set the terms of the preferred stock without seeking any further approval from holders of our common stock.  Any preferred stock that is issued may rank ahead of our common stock in terms of dividends, priority and liquidation premiums and may have greater voting rights than our common stock.  

Anti-takeover provisions could make a third party acquisition of us difficult.

Our articles of incorporation and bylaws provide for a classified board of directors, with each member serving a three-year term, and eliminate the ability of stockholders to call special meetings or take action by written consent.  Each of the provisions in our articles of incorporation and bylaws could make it more difficult for a third party to acquire us without the approval of our board.  In addition, the Nevada corporate statute also contains certain provisions that could make an acquisition by a third party more difficult.