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Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-K

 

(Mark One)

 

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

For the Fiscal Year Ended December 31, 2020

 

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

Commission File Number 001-16071

 

ABRAXAS PETROLEUM CORPORATION

(Exact name of Registrant as specified in its charter)

 

 

Nevada

 

74-2584033

(State or Other Jurisdiction of

Incorporation or Organization)

 

(I.R.S. Employer Identification Number)

 

 

 

18803 Meisner Drive

San Antonio, TX 78258

(Address of principal executive offices)

 

(210) 490-4788

Registrant’s telephone number, including area code

 

SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:

 

Title of each class:

Trading Symbol

Name of each exchange on which registered:

Common Stock, par value $.01 per share

AXAS

The NASDAQ Stock Market, LLC

 

SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:

 

None

 

Indicate by check mark if the registrant is a well-known seasoned issuer as defined in Rule 405 of the Securities Act.  Yes ☐ No ☒

 

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes ☐ No ☒

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes ☒ No ☐

 

Indicate by check mark if the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).  Yes ☒ No ☐

 

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.   Yes ☐ No ☒   

 

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer or a smaller reporting company. See definition of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act (check one):

   

Large accelerated filer ☐

Accelerated filer  ☐

Non-accelerated filer   ☐  

Smaller reporting company ☒

 

Emerging Growth Company ☐

 

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes ☐ No ☒

 

As of June 30, 2020, the last day of the registrant’s most recently completed second fiscal quarter, the aggregate market value of the common stock held by non-affiliates of the registrant was $31,865,614 based on the closing sale price as reported on The NASDAQ Stock Market.

 

As of  April 30, 2021, there were 8,421,910 shares of common stock outstanding.

 

Documents Incorporated by Reference:

     

Document

 

Parts Into Which Incorporated

 

 

 

 

 

 

ABRAXAS PETROLEUM CORPORATION

FORM 10-K

TABLE OF CONTENTS

 

 

 

Page

     

Part  I

 

 

 

 

 

Item 1.

Business

5

Item 1A.

Risk Factors

14

Item 1B.

Unresolved Staff Comments

30

Item 2.

Properties

30

Item 3.

Legal Proceedings

36

Item 4.

Mine Safety Disclosures

36

 

 

 

Part II

 

 

 

 

 

Item 5.

Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

37

Item 6.

Selected Financial Data

37

Item 7.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

38

Item 7A.

Quantitative and Qualitative Disclosure about Market Risk

49

Item 8.

Financial Statements and Supplementary Data

50

Item 9.

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

50

Item 9A.

Controls and Procedures

50

Item 9B.

Other Information

50

 

 

 

Part III

 

 

 

 

 

Item 10.

Directors, Executive Officers and Corporate Governance

51

Item 11.

Executive Compensation

51

Item 12.

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

51

Item 13.

Certain Relationships and Related Transactions, and Director Independence

51

Item 14.

Principal Accountant Fees and Services

51

 

 

 

Part IV

 

 

 

 

 

Item 15.

Exhibits and Financial Statement Schedules

62

 

 

 

Item 16.

Form 10-K Summary

63

 

 

 
 

We make forward-looking statements throughout this report.  Whenever you read a statement that is not simply a statement of historical fact (such as statements including words like “believe,” “expect,” “anticipate,” “intend,” “will,” “plan,” “seek,” “may,” “estimate,” “could,” “potentially” or similar expressions), you must remember that these are forward-looking statements, and that our expectations may not be correct, even though we believe they are reasonable.  The forward-looking information contained in this report is generally located in the material set forth under the headings “Business,” “Properties,” “Risk Factors” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” but may be found in other locations as well.  These forward-looking statements generally relate to our plans and objectives for future operations and are based upon our management’s reasonable estimates of future results or trends.  The factors that may affect our expectations regarding our operations include, among others, the following:

 

 

the prices we receive for our production and the effectiveness of our hedging activities;

 

the availability of capital including under our credit facilities;

 

our success in development, exploitation and exploration activities;

 

declines in our production of oil and gas;

  our indebtedness and the significant amount of cash required to service our indebtedness,
  the proximity, capacity, cost and availability of pipelines and other transportation facilities,
 

limits on our growth and our ability to finance our operations, fund our capital needs and respond to changing conditions imposed by our credit facilities and restrictive debt covenants;

 

our ability to make planned capital expenditures;

  ceiling test write-downs resulting, and that could result in the future, from lower oil and gas prices;
  global or national health concerns, including the outbreak of pandemic or contagious disease, such as the coronavirus (COVID-19);
 

political and economic conditions in oil producing countries, especially those in the Middle East;

 

price and availability of alternative fuels;

 

our ability to procure services and equipment for our drilling and completion activities;

 

our acquisition and divestiture activities;

 

weather conditions and events; and

 

other factors discussed elsewhere in this report.

 

Initial production, or IP, rates, for both our wells and for those wells that are located near our properties, are limited data points in each well’s productive history. These rates are sometimes actual rates and sometimes extrapolated or normalized rates. As such, the rates for a particular well may change as additional data becomes available. Peak production rates are not necessarily indicative or predictive of future production rates, expected ultimate recovery, or EUR, or economic rates of return from such wells and should not be relied upon for such purposes. Equally, the way we calculate and report peak IP rates and the methodologies employed by others may not be consistent, and thus the values reported may not be directly and meaningfully comparable. Lateral lengths described are indicative only. Actual completed lateral lengths depend on various considerations such as lease-line offsets. Abraxas standard length laterals, sometimes referred to as 5,000 foot laterals, are laterals with completed length generally between 4,000 feet and 5,500 feet. Mid-length laterals, sometimes referred to as 7,500 foot laterals, are laterals with completed length generally between 6,500 feet and 8,000 feet. Long laterals, sometimes referred to as 10,000 foot laterals, are laterals with completed length generally longer than 8,000 feet.

 

 

GLOSSARY OF TERMS

 

Unless otherwise indicated in this report, gas volumes are stated at the legal pressure base of the state or area in which the reserves are located at 60 degrees Fahrenheit.  Oil and gas equivalents are determined using the ratio of six Mcf of gas to one barrel of oil.

 

The following definitions shall apply to the technical terms used in this report.

 

Terms used to describe quantities of oil and gas:

 

Bbl” – barrel or barrels.

 

Bcf” – billion cubic feet of gas.

 

Bcfe” – billion cubic feet of gas equivalent.

 

Boe” – barrels of oil equivalent.

 

Boepd" - barrels of oil equivalents per day.

 

MBbl” – thousand barrels.

 

MBoe thousand barrels of oil equivalent.

 

Mcf” – thousand cubic feet of gas.

 

Mcfe” – thousand cubic feet of gas equivalent.

 

MMBbl” – million barrels.

 

“MMBoe” – million barrels of oil equivalent.

 

MMBtu” – million British Thermal Units of gas.

 

MMcf” – million cubic feet of gas.

 

MMcfe” – million cubic feet of gas equivalent.

 

“NGL” – natural gas liquids measured in barrels.

 

 Terms used to describe our interests in wells and acreage:

 

Developed acreage” means acreage which consists of leased acres spaced or assignable to productive wells.

 

Development well” is a well drilled within the proved area of an oil or gas reservoir to the depth or stratigraphic horizon (rock layer or formation) noted to be productive for the purpose of extracting reserves.

 

Dry hole” is an exploratory or development well found to be incapable of producing either oil or gas in sufficient quantities to justify completion.

 

Exploratory well” is a well drilled to find and produce oil or gas in an unproved area, to find a new reservoir in a field previously found to be producing in another reservoir, or to extend a known reservoir.

 

Gross acres” are the number of acres in which we own a working interest.

 

Gross well” is a well in which we own an interest.

 

Net acres” are the sum of fractional ownership working interests in gross acres (e.g., a 50% working interest in a lease covering 320 gross acres is equivalent to 160 net acres).

 

Net well” is the sum of fractional ownership working interests in gross wells.

 

Productive well” is an exploratory or a development well that is not a dry hole.

 

Undeveloped acreage” means those leased acres on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil and gas, regardless of whether or not such acreage contains proved reserves.

 

 

Terms used to assign a present value to or to classify our reserves:

 

Developed oil and gas reserves*” Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

 

(i)    Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

 

(ii)    Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

 

“Proved developed non-producing reserves*”  are those quantities of oil and gas reserves that are developed behind pipe in an existing well bore, from a shut-in well bore or that can be recovered through improved recovery only after the necessary equipment has been installed, or when the costs to do so are relatively minor. Shut-in reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not started producing, (2) wells that were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe reserves are expected to be recovered from zones in existing wells that will require additional completion work or future recompletion prior to the start of production.

 

“Proved developed reserves* Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

 

Proved oil and gas reserves*” Reserves that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.

 

“Proved undeveloped reserves” or “PUDs*”  Reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells, in each case where a relatively major expenditure is required.

 

PV-10” means estimated future net revenue, discounted at a rate of 10% per annum, before income taxes and with no price or cost escalation or de-escalation, calculated in accordance with guidelines promulgated by the Securities and Exchange Commission (“SEC”). PV-10 is considered a non-GAAP financial measure under SEC regulations because it does not include the effects of future income taxes, as is required in computing the standardized measure of discounted future net cash flows. We believe that PV-10 is an important measure that can be used to evaluate the relative significance of our oil and gas properties and that PV-10 is widely used by securities analysts and investors when evaluating oil and gas companies. Because many factors that are unique to each individual company impact the amount of future income taxes to be paid, the use of a pre-tax measure provides greater comparability of assets when evaluating companies. We believe that most other companies in the oil and gas industry calculate PV-10 on the same basis. PV-10 is computed on the same basis as the standardized measure of discounted future net cash flows but without deducting income taxes.

 

Standardized Measure” means estimated future net revenue, discounted at a rate of 10% per annum, after income taxes and with no price or cost escalation or de-escalation, calculated in accordance with Accounting Standards Codification (“ASC”) 932, “Disclosures About Oil and Gas Producing Activities.”

 

“Undeveloped oil and gas reserves*"” Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

 

* This definition is an abbreviated version of the complete definition set forth in Rule 4-10(a) of Regulation S-X. For the complete definition, see: http://www.ecfr.gov/cgi-bin/retrieveECFR?gp=1&SID=7aa25d3cede06103c0ecec861362497d&ty=HTML&h=L&n=pt17.3.210&r=PART#se17.3.210_14_610

 

 

Part I

 

Information contained in this report represents the consolidated operations of Abraxas Petroleum Corporation. The terms “Abraxas,”  “we,” “us,” “our,” or the “Company,” refer to Abraxas Petroleum Corporation, together with its consolidated subsidiaries including Raven Drilling, LLC  which is a wholly owned subsidiary that owns a drilling rig. Unless otherwise noted, all disclosures are for Continuing Operations.

 

Item 1. Business

 

General

 

We are an independent energy company primarily engaged in the acquisition, exploration, development and production of oil and gas.  At December 31, 2020, our estimated net proved reserves were 16.8 MMBoe, of which 100% were classified as proved developed, 57% were oil and 97% of which (on a Boe basis) were operated by us.  Our daily net production for the year ended December 31, 2020 was 4,922 Boepd, of which 63% was oil. Abraxas Petroleum Corporation was incorporated in Nevada in 1990. Our address is 18803 Meisner Drive, San Antonio, Texas 78258 and our phone number is (210) 490-4788.

 

COVID-19 Overview

 

In the first quarter of 2020, a new strain of coronavirus (“COVID-19”) emerged, creating a global health emergency that has been classified by the World Health Organization as a pandemic. As a result of the COVID-19 pandemic, consumer demand for both oil and gas has decreased as a direct result of travel restrictions placed by governments in an effort to curtail the spread of COVID-19. In addition, in March 2020, members of Organization of Petroleum Exporting Countries ("OPEC") failed to agree on production levels, which caused an increased supply of oil and gas and led to a substantial decrease in oil prices and an increasingly volatile market. OPEC agreed to cut global petroleum output but did not go far enough to offset the impact of COVID-19 on demand. As a result of this decrease in demand and increase in supply, the price of oil and gas has decreased, which has affected our liquidity. On one hand, the Company’s commodity hedges protected its cash flows in 2020 from such price decline but, on the other hand, if oil or natural gas prices remain depressed or decline the Company will be required to record oil and gas property write-downs.

 

In early March 2020, global oil and natural gas prices declined sharply, have since been volatile, rising in recent months, but may decline again. The Company expects ongoing oil and gas price volatility over the short term. The full impact of COVID-19 and the decrease in oil prices continues to evolve as of the date of this report. As such, it is uncertain as to the full magnitude that will have on the Company. Management is actively monitoring the global situation and the impact on the Company’s future operations, financial position and liquidity in fiscal year 2021. In response to the price volatility, the Company has taken action to reduce general and administrative costs, as well as  shutting in production in mid-March 2020, but subsequently started restoring production in mid-June, a majority of such wells were back on production in early September 2020. We have also suspended our capital expenditures indefinitely. 

 

Going Concern 

 

As discussed under Item 7. Managements 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 $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” as a result of events of default under our credit facilities. 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.

 

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 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. 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.

 

 

Our oil and gas assets are located in two operating regions, the Permian/Delaware Basin, and the Rocky Mountain as of December 31, 2020.  The following table sets forth certain information related to our properties as of and for the year ended December 31, 2020:

 

                           

Estimated Net Proved Reserves at December 31, 2020 (3)

   

Net Production for the Year Ended December 31, 2020

 
   

Gross Producing Wells

   

Average Working Interest

   

Total Net Acres

   

(Mboe)

   

% Oil

   

(Mboe)

   

% Oil

 

Permian/Delaware Basin (1)

    103       79.38 %     25,051       7,383       58 %     779       77 %

Rocky Mountain (2)

    468       15.65 %     16,850       9,395       56 %     1,022       52 %
Total United States     571       27.50 %     41,901       16,778       62 %     1,801       63 %

 

(1 ) Our properties in the Permian/Delaware Basin region are primarily located in Ward and Winkler Counties, Texas and produce oil and gas primarily from the Bone Spring and Wolfcamp formations. 

(2)  Our properties in the Rocky Mountain region are primarily located in the Williston Basin of North Dakota and Montana.  In this region, our wells produce oil and gas from various reservoirs, primarily the Bakken, Three Forks and Red River formations. 

(3)  Net proved reserves excludes proved undeveloped reserves due to the Company's inability to fund the drilling and completion activities within the next five years.

 

Strategy

 

Our business strategy is to focus our capital and resources on our core operated basins, improve financial flexibility and profitably grow production and reserves.  Key elements of our business strategy include:

 

Focus our capital and resources on our core operated basins. Our core basins consist of the Permian/Delaware Basin (Bone Spring and Wolfcamp) and Williston Basin (Bakken and Three Forks). Given the disparity which has existed during the past several years and which continues currently between oil and gas prices, the economics of drilling oil wells is far superior to drilling gas wells.  Due to declines in oil prices, during the first half of 2020, we suspended our planned capital expenditures for 2020. This suspension of our  capital expenditure budget is subject to change depending upon a number of factors, including the availability and costs of drilling and service equipment and crews, economic and industry conditions at the time of drilling, prevailing and anticipated prices for oil and gas, the availability of sufficient capital resources including under our credit facilities, the results of our exploitation efforts, our financial results and our ability to obtain permits for drilling locations. Due to the capital spending constraints imposed by our credit facilities, we have also not adopted a 2021 drilling budget but do plan to complete the six previously drilled uncompleted wells in the Bakken. As part of our efforts to focus our property portfolio, we also seek to sell assets we have deemed non-core. These include assets with a low working interest that are non-operated and/or that fall outside of our two core basins. Any proceeds from these asset sales have been and will continue to be used to reduce our indebtedness and/or be redeployed into our core operating basins. During 2019 we monetized our remaining Eagle Ford assets in South Texas as well as our non-operated properties in the Bakken.

 

Financial flexibility. Our primary source of capital is cash flows from operations. As of December 31, 2020, we had $95.0  million outstanding on our first lien credit facility (the "First Lien Credit Facility") with no availability, and $112.7 million under our second lien credit facility (the "Second Lien Credit Facility"), and we generated approximately $16.0 million of cash flows from operations for the year ended December 31, 2020. Additionally, any excess cash, as defined in the First Lien Credit Facility, must be used to reduce the balance and simultaneously reduce the borrowing base to the new outstanding balance.

 

We have also sold producing properties from time to time in order to provide us with financial flexibility. During 2019 we sold our non-operated Bakken properties and our remaining South Texas Eagle Ford properties, proceeds from these sales were approximately $23.4 million.  In January 2019, we announced that we had engaged Petrie Partners to assist us in identifying and assessing our options for our Bakken properties. In October 2019 we announced that we had broadened the engagement of Petrie Partners to include a more thorough review of our business and strategic plans, competitive positioning and potential alternative transactions that might further enhance shareholder value. Petrie’s expanded mandate to assess our options is a broad one, which might include sales of assets, merger or acquisition transactions, additional financing alternatives or other strategic transactions. There have not been any significant developments to date.

 

We seek to reduce the volatility of our cash flows from operations by hedging a portion of our production. 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 2023 and 88% for 2024. Substantially all of our hedging arrangements were terminated subsequent to December 31, 2020.

 

 

Profitably grow production and reserves. We have a substantial low-decline legacy production base as evidenced by our approximate 21-year average reserve life as of year-end 2020. Our capital is currently being deployed largely into unconventional oil assets with relatively predictable production profiles, yet steep initial decline rates. Therefore, the economics of these oil wells are highly dependent on both near term commodity prices and strong operational cost control. Cost savings achieved through efficiencies of using our own rig in the Williston Basin, and heightened focus on cost control in all of our operated positions both contribute to our historical success in adding low cost barrels to our production base.

 

2021 Budget and Drilling Activities

 

Due to the capital spending constraints imposed by our credit facilities, we have not adopted a drilling budget for 2021. As discussed under Item 7. Managements 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". Due to the Company's inability to continue as a "going concern", all future development cost and reserves related to proved undeveloped reserves as of  December 31, 2020 have been written off for financial reporting purposes. If and when the Company has adequate capital resources to fund the projects the reserves will be reinstated.

 

Markets and Customers

 

The revenue generated by our operations is highly dependent upon the prices we receive for our oil and gas. Historically, the markets for oil and gas have been volatile and are likely to continue to be volatile in the future. The prices we receive for our oil and gas production are subject to wide fluctuations and depend on numerous factors beyond our control including seasonality, the condition of the world wide economy (particularly the manufacturing sector), foreign imports, political conditions in other petroleum producing countries, the actions of the OPEC, domestic regulation, legislation and policies, the outbreak of pandemic or contagious diseases, such as the recent COVID-19 coronavirus.  Decreases in the prices we receive for our oil and gas have had, and could have in the future, an adverse effect on the carrying value of our proved reserves, our revenue, profitability and cash flow from operations. Refer to “Risk Factors – 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” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Critical Accounting Policies” for more information relating to the effects that decreases in oil and gas prices have on us. To help mitigate the impact of commodity price volatility, we hedge a portion of our production through the use of fixed price swaps and basis differential swap contracts. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations – General – Commodity Prices and Hedging Arrangements” and Note 11 of the notes to our consolidated financial statements for more information regarding our derivative activities.

 

Substantially all of our oil and gas is sold at current market prices under short-term arrangements, as is customary in the industry. During the year ended December 31, 2020, four purchasers of production accounted for approximately 73% of our oil and gas sales. During the year ended December 31, 2019, two purchasers of production accounted for approximately 71% of our oil and gas sales. We believe that there are numerous other purchasers available to buy our oil and gas and that the loss of any of these purchasers would not materially affect our ability to sell our oil and gas. Furthermore, the largest purchasers of our oil and gas have changed from year to year.

 

Regulation of Oil and Gas Activities

 

The exploration, production and transportation of all types of hydrocarbons are subject to significant governmental regulations. Our properties are affected from time to time in varying degrees by political developments and federal, state and local laws and regulations. In particular, oil and gas production operations and economics are, or in the past have been, affected by industry specific price controls, taxes, conservation, safety, environmental and other laws relating to the petroleum industry, and by changes in such laws and by periodically changing administrative regulations.

 

Federal, state and local laws and regulations govern oil and gas activities. Operators of oil and gas properties are required to have a number of permits in order to operate such properties, including operator permits and permits to dispose of salt water. In addition, under federal law, operators of oil and gas properties are required to possess certain certificates and permits in order to operate such properties. We possess all material requisite permits required by Federal, state and other local authorities in which we operate properties.

 

Development and Production

 

The operations of our properties are subject to various types of regulation at the federal, state and local levels. These types of regulations include requiring the operator of oil and gas properties to possess permits for the drilling and development of wells, post bonds in connection with various types of activities, and file reports concerning operations. Most states, and some counties and municipalities in which we operate, regulate one or more of the following:

 

 

the location of wells;

 

 

the method of drilling and casing wells;

 

 

the flaring of gas;

 

 

the method of completing and fracture stimulating wells;

 

 

the surface use and restoration of properties upon which wells are drilled;

 

 

the plugging and abandoning of wells; and

 

 

the notice to surface owners and other third parties.

 

 

Some states regulate the size and shape of development and spacing units or proration units for oil and gas properties. Some states allow forced pooling or unitization of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum allowable rates of production from oil and gas wells, generally prohibit the venting or flaring of gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and gas we can produce from our wells or limit the number of wells or the locations at which our wells can be drilled. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, gas and NGLs within its jurisdiction.

 

Operations on Federal or Indian oil and gas leases must comply with numerous regulatory restrictions, including various non-discrimination statutes, and certain of such operations must be conducted pursuant to certain on-site security regulations and other permits issued by various tribal and federal agencies, including the Bureau of Land Management and the Office of Natural Resources Revenue, which we refer to as ONRR, (formerly Minerals Management Service). ONRR establishes the basis for royalty payments due under federal oil and gas leases through regulations issued under applicable statutory authority. State regulatory authorities establish similar standards for royalty payments due under state oil and gas leases. The basis for royalty payments established by ONRR and the state regulatory authorities is generally applicable to all federal and state oil and gas leases. Accordingly, we believe that the impact of royalty regulation on the operations of our properties should generally be the same as the impact on our competitors. We believe that the operations of our properties are in material compliance with all applicable regulations as they pertain to Federal or Indian oil and gas leases.

 

The failure to comply with these rules and regulations can result in substantial penalties, including lease suspension or termination in certain cases. The regulatory burden on the oil and gas industry increases our cost of doing business and, consequently, affects our profitability. Our competitors in the oil and gas industry are subject to the same regulatory requirements and restrictions that affect us.

 

Regulation of Transportation and Sale of Gas in the United States

 

Historically, the transportation and sale for resale of gas in interstate commerce have been regulated pursuant to the Natural Gas Act of 1938, as amended, which we refer to as NGA, the Natural Gas Policy Act of 1978, as amended, which we refer to as NGPA, and regulations promulgated thereunder by the Federal Energy Regulatory Commission, which we refer to as FERC, and its predecessors. In the past, the federal government has regulated the prices at which gas could be sold. Deregulation of wellhead gas sales began with the enactment of the NGPA. In 1989, Congress enacted the Natural Gas Wellhead Decontrol Act, as amended, which we refer to as the Decontrol Act. The Decontrol Act removed all NGA and NGPA price and non-price controls affecting wellhead sales of gas effective January 1, 1993. While sales by producers of gas can currently be made at unregulated market prices, Congress could reenact price controls in the future.

 

Since 1985, FERC has endeavored to make gas transportation more accessible to gas buyers and sellers on an open and non-discriminatory basis. FERC has stated that open access policies are necessary to improve the competitive structure of the interstate gas pipeline industry and to create a regulatory framework that will put gas sellers into more direct contractual relations with gas buyers by, among other things, unbundling the sale of gas from the sale of transportation and storage services. Beginning in 1992, FERC issued Order No. 636 and a series of related orders, which we refer to collectively as Order No. 636, to implement its open access policies. As a result of the Order No. 636 program, the marketing and pricing of gas have been significantly altered. The interstate pipelines’ traditional role as wholesalers of gas has been eliminated and replaced by a structure under which pipelines provide transportation and storage service on an open access basis to others who buy and sell gas. FERC continues to regulate the rates that interstate pipelines may charge for such transportation and storage services. Although FERC’s orders do not directly regulate gas producers, they are intended to foster increased competition within all phases of the gas industry.

 

In 2000, FERC issued Order No. 637 and subsequent orders, which we refer to, collectively, as Order No. 637, which imposed a number of additional reforms designed to enhance competition in gas markets. Among other things, Order No. 637 effected changes in FERC regulations relating to scheduling procedures, capacity segmentation, penalties, rights of first refusal and information reporting. Most major aspects of Order No. 637 have been upheld on judicial review, and most pipelines’ tariff filings to implement the requirements of Order No. 637 have been accepted by the FERC and placed into effect.

 

The Energy Policy Act of 2005, which we refer to as EP Act 2005, gave FERC increased oversight and penalty authority regarding market manipulation and enforcement. EP Act 2005 amended the NGA to prohibit market manipulation and also amended the NGA and the NGPA to increase civil and criminal penalties for any violations of the NGA, NGPA and any rules, regulations or orders of FERC to up to $1,000,000 per day, per violation. In addition, FERC issued a final rule effective January 26, 2006, regarding market manipulation, which makes it unlawful for any entity, in connection with the purchase or sale of gas or transportation service subject to FERC jurisdiction, to defraud, make an untrue statement, or omit a material fact or engage in any practice, act, or course of business that operates or would operate as a fraud. This final rule works together with FERC’s enhanced penalty authority to provide increased oversight of the gas marketplace.

 

The gas industry historically has been very heavily regulated; therefore, there is no assurance that the less stringent regulatory approach currently pursued by FERC will continue. However, we do not believe that any action taken will affect us in a way that materially differs from the way it affects other gas producers, gatherers and marketers.

 

Generally, intrastate gas transportation is subject to regulation by state regulatory agencies, although FERC does regulate the rates, terms, and conditions of service provided by intrastate pipelines that transport gas subject to FERC’s NGA jurisdiction pursuant to Section 311 of the NGPA. The basis for state regulation of intrastate gas transportation and the degree of regulatory oversight and scrutiny given to intrastate gas pipeline rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate gas transportation in any states in which we operate and ship gas on an intrastate basis will not affect the operations of our properties in any way that is materially different from the effect of such regulation on our competitors.

 

 

Gas Gathering in the United States

 

Section 1(b) of the NGA exempts gas gathering facilities from the jurisdiction of the FERC. FERC has developed tests for determining which facilities constitute jurisdictional transportation facilities under the NGA and which facilities constitute gathering facilities exempt from FERC’s NGA jurisdiction. From time to time, FERC reconsiders its test for defining non-jurisdictional gathering. FERC has also permitted jurisdictional pipelines to “spin down” exempt gathering facilities into affiliated entities that are not subject to FERC jurisdiction, although FERC continues to examine the circumstances in which such a “spin down” is appropriate and whether it should reassert jurisdiction over certain gathering companies and facilities that previously had been “spun down.” We cannot predict the effect that FERC’s activities in this regard may have on the operations of our properties, but we do not expect these activities to affect the operations in any way that is materially different from the effect thereof on our competitors.

 

State regulation of gathering facilities generally includes various safety, environmental, and in some circumstances, non-discriminatory take or service requirements, but does not generally entail rate regulation. In the United States, gas gathering has received greater regulatory scrutiny at both the state and federal levels in the wake of the interstate pipeline restructuring under FERC Order 636. For example, the Texas Railroad Commission enacted a Natural Gas Transportation Standards and Code of Conduct to provide regulatory support for the state’s more active review of rates, services and practices associated with the gathering and transportation of gas by an entity that provides such services to others for a fee, in order to prohibit such entities from unduly discriminating in favor of their affiliates.

 

Regulation of Transportation of Oil in the United States

 

Sales of oil, condensate and gas liquids are not currently regulated and are made at negotiated prices. The transportation of oil in common carrier pipelines is subject to rate regulation. FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act. In general, interstate oil pipeline rates must be cost-based, although settlement rates agreed to by all shippers are permitted and market-based rates may be permitted in certain circumstances. Effective January 1, 1995, FERC implemented regulations establishing an indexing system (based on inflation) for transportation rates for oil that allowed for an increase or decrease in the cost of transporting oil to the purchaser. A review of these regulations by FERC in 2000 was successfully challenged on appeal by an association of oil pipelines. On remand, FERC, in February 2003, increased the index slightly, effective July 2001. Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulations, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect the operations of our properties in any way that is materially different from the effect of such regulation on our competitors.

 

Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our competitors.

 

All of our oil is sold on lease, at which time custody transfers, either by truck or pipeline. We are not able to determine how much of our sold oil is ultimately shipped to market centers using rail transportation facilities owned and operated by third parties. The U.S. Department of Transportation’s (“U.S. DOT”) Pipeline and Hazardous Materials Safety Administration (“PHMSA”) establishes safety regulations relating to transportation of oil by rail transportation. In addition, third party rail operators are subject to the regulatory jurisdiction of the Surface Transportation Board of the U.S. DOT, the Federal Railroad Administration (“FRA”) of the DOT, the U.S. Occupational Safety and Health Administration, as well as other federal regulatory agencies. Additionally, various state and local agencies have jurisdiction over disposal of hazardous waste and seek to regulate movement of hazardous materials in ways not preempted by federal law.

 

In response to rail accidents occurring between 2002 and 2008, the U.S. Congress passed the Rail Safety and Improvement Act of 2008, which implemented regulations governing different areas related to railroad safety. Recently, in response to train derailments occurring in 2013, U.S. regulators have been implementing or considering new rules to address the safety risks of transporting oil by rail. On January 23, 2014, the National Transportation Safety Board (“NTSB”) issued a series of recommendations to the FRA and PHMSA 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.

 

We do not currently own or operate rail transportation facilities or rail cars; however, the adoption of any regulations that impact the testing or handling of shipments of oil by rail transportation 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. At this time, it is not possible to estimate the potential impact on our business if new federal or state rail transportation regulations are enacted.

 

 

Environmental Matters

 

Oil and gas operations are subject to numerous federal, state and local laws and regulations controlling the generation, use, treatment, storage and disposal of materials and the discharge of materials into the environment or otherwise relating to the protection of the environment. These laws and regulations may: 

 

 

require the acquisition of a permit or other authorization before construction or drilling commences;

 

impose design, construction and permitting requirements on facilities in conjunction with oil and gas operations, including the construction of pollution control devices;

 

require protective measures to prevent certain fluids from coming into contact with ground water;

 

restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling, production, and gas processing activities;

 

suspend, limit or prohibit construction, drilling and other activities in certain lands lying within wilderness, wetlands, and areas inhabited by threatened or endangered species and other protected areas;

 

require remedial measures to mitigate pollution from historical and on-going operations such as the use of pits and plugging of abandoned wells;

 

require disclosure of chemicals injected into wells in conjunction with hydraulic fracturing operations;

 

restrict injection of liquids into subsurface strata that may contaminate groundwater or increase seismic activity;

 

restrict the availability of water necessary for hydraulic fracturing operations;

 

impose substantial penalties for violations of environmental rules or pollution resulting from our operations;

  curtail production in association with permit limits; and
 

curtail or prohibit production for exceeding gas flaring limits.

 

Environmental permits that the operators of properties are required to possess may be subject to revocation, modification, and renewal by issuing authorities. Governmental authorities have the power to enforce compliance with their regulations and permits, and violations are subject to injunction, civil fines, and even criminal penalties. Our management believes that we are in substantial compliance with current environmental laws and regulations, and that we will not be required to make material capital expenditures to comply with existing laws. Nevertheless, changes in existing environmental laws and regulations or interpretations thereof could have a significant impact on our operations as well as the oil and gas industry in general, and thus we are unable to predict the ultimate cost and effects of future changes in environmental laws and regulations.

 

We are not currently involved in any administrative, judicial or legal proceedings arising under federal, state, or local environmental protection laws and regulations, or under federal or state common law, which would have a material adverse effect on our respective financial positions or results of operations. Moreover, we maintain insurance against the costs of clean-up operations, but we are not fully insured against all such risks. A serious incident of pollution may result in the suspension or cessation of operations in the affected area.

 

 

The following is a discussion of the current relevant environmental laws and regulations that relate to our operations.

 

Comprehensive Environmental Response, Compensation and Liability Act. The Comprehensive Environmental Response, Compensation and Liability Act, also known as Superfund, and which we refer to as "CERCLA", and comparable state statutes impose strict joint, and several liability, without regard to fault or legality of conduct, on certain classes of persons who are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include among others, the current and former owners or operators of a disposal site or sites where a release occurred and companies that arranged for the transportation or disposal of the hazardous substances released at the site. Under CERCLA, such persons or companies may be retroactively liable for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies. CERCLA authorizes the Environmental Protection Agency ("EPA"), and in some cases third parties, to take actions in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. In addition, it is not uncommon for neighboring land owners and other third parties to file claims for personal injury, property damage, and recovery of response costs allegedly caused by the hazardous substances released into the environment.

 

In the course of our ordinary operations, certain wastes may be generated that may fall within CERCLA’s definition of a “hazardous substance.” We may be liable under CERCLA or comparable state statutes for all or part of the costs required to clean up sites at which these wastes have been disposed. Although CERCLA contains a “petroleum exclusion” from the definition of “hazardous substance,” state laws affecting our operations impose cleanup liability relating to petroleum and petroleum related products, including oil cleanups.

 

We currently own or lease, and have in the past owned or leased, numerous properties that for many years have been used for the exploration and production of oil and gas. Although we have utilized standard industry operating and disposal practices at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties we owned or leased or on or under other locations where such wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes was not under our control. These properties and the wastes disposed thereon may be subject to CERCLA, RCRA (as defined below), and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes, including wastes disposed or released by prior owners or operators; to clean up contaminated property, including contaminated groundwater; or to perform remedial operations to prevent future contamination.

 

Oil Pollution Act of 1990.  Federal regulations also require certain owners and operators of facilities that store or otherwise handle oil to prepare and implement spill response plans relating to the potential discharge of oil into surface waters. The Federal Oil Pollution Act, which we refer to as OPA, and analogous state laws, contain numerous requirements relating to prevention of, reporting of, and response to oil spills into waters of the United States.  A failure to comply with OPA’s requirements or inadequate cooperation during a spill response action may subject a responsible party to civil or criminal enforcement actions. We are not aware of any action or event that would subject us to liability under OPA, and we believe that compliance with OPA’s financial responsibility and other operating requirements will not have a material adverse effect on our financial position or results of operations.

 

Resource Conservation and Recovery Act.   The Resource Conservation and Recovery Act, which we refer to as "RCRA", is the principal federal statute governing the treatment, storage and disposal of hazardous and non-hazardous solid wastes.  RCRA imposes stringent requirements and liability for failure to meet such requirements, on persons who generate or transport regulated waste materials and also on persons who own or operate a waste treatment, storage or disposal facility. Analogous state laws also impose requirements associated with the management such wastes. At present, RCRA includes a statutory exemption that allows most oil and gas exploration and production wastes to be classified and regulated as non-hazardous wastes. A similar exemption is contained in many of the state counterparts to RCRA.  At various times in the past, proposals have been made to amend RCRA to rescind the exemption that excludes oil and gas exploration and production wastes from regulation as hazardous wastes. Repeal or modification of the exemption by administrative, legislative or judicial process, or modification of similar exemptions in applicable state statutes, would increase the volume of hazardous waste we are required to manage and dispose and would cause us to incur increased operating expenses. Also, in the ordinary course of our operations, we generate small amounts of ordinary industrial wastes, such as paint wastes, waste solvents and waste oils that may be regulated as hazardous wastes. We believe that our operations comply in all material respects with the requirements of RCRA and its state counterparts.

 

Naturally Occurring Radioactive Materials, which we refer to as "NORM", are materials not covered by the Atomic Energy Act, whose radioactivity is enhanced by technological operations such as mineral extraction or processing through exploration and production conducted by the oil and gas industry. NORM wastes are regulated under the RCRA framework, but primary responsibility for NORM regulation has been a state function. Standards have been developed for worker protection; treatment, storage and disposal of NORM waste; management of waste piles, containers and tanks; and limitations upon the release of NORM contaminated land for unrestricted use. We believe that the operations of our properties are in material compliance with all applicable NORM standards established by the various states in which we operate wells.

 

 

Clean Water Act.   The Clean Water Act, which we refer to as the "CWA", and analogous state laws, impose restrictions and controls on the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by EPA or an analogous state agency. The CWA regulates storm water run-off from oil and gas facilities and requires a storm water discharge permit for certain activities. Such a permit requires the regulated facility to monitor and sample storm water run-off from its operations. The CWA and regulations implemented thereunder also prohibit discharges of dredged and fill material in wetlands and other waters of the United States unless authorized by an appropriately issued permit. Spill prevention, control and countermeasure requirements of the CWA require appropriate containment berms and similar structures to help prevent the contamination of waters of the United States in the event of a petroleum hydrocarbon tank spill, rupture or leak. The reach and scope of the CWA, and the determination of what water bodies and land areas are regulated as waters of the U.S., is the subject of various rules adopted by  EPA and the U.S. Army Corps of Engineers which we refer to as the WOTUS Rules, and on-going federal court litigation arising out of the rules and recent amendments. The WOTUS Rules, litigation over the rules, and the associated regulatory uncertainty, could impact our operations by subjecting new land and waters to regulation, and increase our cost of operations. The CWA and comparable state statutes provide for civil, criminal and administrative penalties for unauthorized discharges of oil and other pollutants and impose liability on parties responsible for those discharges for the costs of cleaning up any environmental damage caused by the release and for resource damages resulting from the release. We believe that the operations of our properties comply in all material respects with the requirements of the CWA and state statutes enacted to control water pollution.

 

Safe Drinking Water Act. Our operations also produce wastewaters that are disposed via underground injection wells. These activities are regulated by the Safe Drinking Water Act, which we refer to as the "SDWA", and analogous state and local laws. Underground injection is the subsurface placement of fluid through a well, such as the reinjection of brine produced and separated from oil and gas production., or the flow-back of hydraulic fracturing fluids. The main goal of the SDWA is the protection of usable aquifers. The primary objective of injection well operating requirements is to ensure the mechanical integrity of the injection apparatus and to prevent migration of fluids from the injection zone into underground sources of drinking water. Injection well operations are strictly controlled, and certain wastes, absent an exemption, cannot be injected into underground injection control wells. In most states, no underground injection may take place except as authorized by permit or rule. In addition, subsurface injection of water or other produced fluids from drilling or hydraulic fracturing processes have come under increased public and governmental scrutiny. Some jurisdictions, Texas for example, have adopted new and more stringent rules for injection wells aimed at reducing the potential for earthquakes associated with injection activities, including new restrictions on siting of such injection wells. We currently own and operate various underground injection wells and rely on third-party owned injection wells. Failure to comply with our permits could subject us to civil and/or criminal enforcement. More stringent regulations of injection wells could additionally increase our cost of operations. We believe that we are in compliance in all material respects with the requirements of applicable state underground injection control programs and our permits.

 

Clean Air Act.    The Clean Air Act, which we refer to as the CAA, and state air pollution laws and regulations provide a framework for national, state and local efforts to protect air quality. The operation of our properties utilize equipment that emits air pollutants which may be subject to federal and state air pollution control laws. These laws require utilization of air emissions abatement equipment to achieve prescribed emissions limitations and ambient air quality standards, as well as operating permits for existing equipment and construction permits for new and modified equipment. In the past few years, EPA has adopted new more restrictive regulations governing air emissions from oil and gas operations, including regulations which restrict emissions of methane, volatile organic compounds and hazardous air pollutants.  

 

Permits and related compliance obligations under the CAA, as well as changes to state implementation plans for controlling air emissions in regional non-attainment areas may require us to incur future capital expenditures in connection with the addition or modification of existing air emission control equipment and strategies. In addition, some oil and gas facilities may be included within the categories of hazardous air pollutant sources, which are subject to more stringent regulation under the CAA. Failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations and enforcement actions. We may be required to incur capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions. We believe that we are in compliance in all material respects with the requirements of applicable federal and state air pollution control laws.

 

 

Hydraulic Fracturing. Most of our current operations depend on the use of hydraulic fracturing to enhance production from oil and gas wells.  This technology involves the injection of fluids—usually consisting mostly of water but typically including small amounts of chemical additives—as well as sand, or other proppants, into a well under high pressure in order to create fractures in the rock that allow oil or gas to flow more freely to the wellbore.  Many of our newer wells would not be economical without the use of hydraulic fracturing to stimulate the formation to enhance production from the well.  Hydraulic fracturing operations have historically been overseen by state regulators as part of their oil and gas regulatory programs, but where these operations occur on federal or tribal lands they are subject to regulation by the U.S. Department of the Interior, Bureau of Land Management (“BLM”).  In addition to federal legislative and regulatory actions, some states and local governments have considered imposing, or have adopted various conditions and restrictions on hydraulic fracturing operations, including but not limited to requirements regarding chemical disclosure, casing and cementing of wells, withdrawal of water for use in hydraulic fracturing, baseline testing of nearby water wells, and restrictions on the type of additives that may be used in hydraulic fracturing operations.  In some states, including Texas, water use may also be regulated and potentially curtailed by local groundwater management districts which could impact the availability of water for hydraulic fracturing.  If these types of restrictions are widely adopted, we could be subject to increased costs and possibly limits on the productivity of certain wells, and these laws could make it easier for third parties to initiate litigation against us in the event of perceived problems with water wells in the vicinity of an oil or gas well or other alleged environmental problems.  Additional information concerning hydraulic fracturing is included under Item 1A "Risk Factors."

 

 Climate Change and Greenhouse Gas Regulation. Scientific studies have indicated that emissions of certain gases may be contributing to warming of the Earth’s atmosphere. In response to these studies, many nations have agreed to limit emissions of “greenhouse gases” or “GHGs” pursuant to efforts spearheaded by the United Nations. 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. It is possible that domestic and international regulations addressing climate change 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. Given widely divergent political views on climate change regulation, we are unable to predict the timing, scope and effect of any 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. In addition, several states and local governments have adopted, or are considering adopting, regulations or ordinances to reduce emissions of GHGs. Restrictions on emissions of methane or carbon dioxide that may be imposed in various states could adversely affect our operations and demand for our products. The various efforts to regulate the emissions of GHGs (including lawsuits pending in United States federal courts) may affect the cost of our operations, may affect the public’s perception of our industry, and may reduce demand for our products.

 

An example of the uncertainty in regulations comes from the BLM flaring rule. In November 2016, BLM issued a final rule to further restrict venting and flaring of gas from oil and gas operations on public lands.  Then, BLM issued a stay of these requirements in December 2017. In September 2018, BLM published a final rule to modify and rescind substantial portions of the flaring rule. The rescission was challenged by litigation filed in the U.S. District Court for the Northern District of California. If the litigation is successful and the rule restricting flaring of gas becomes effective, we would have to curtail production from the affected wells and would incur additional costs of compliance as well as increased monitoring and recordkeeping for some of our facilities.

 

Any of the climate change regulatory and legislative initiatives described above could have a material adverse effect on our business, financial condition, and results of operations. Additional information concerning climate change is included under Item 1A. “Risk Factors.”

 

National Environmental Policy Act.    Oil and gas exploration and production activities on federal lands are subject to the National Environmental Policy Act, which we refer to as NEPA. NEPA requires federal agencies, including the Department of the Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. If we were to conduct any exploration and production activities on federal lands in the future, those activities may need to obtain governmental permits that are subject to the requirements of NEPA. This process has the potential to delay the development of oil and gas projects and increase the cost of such operations.

 

Endangered Species Act.  The Endangered Species Act, which we refer to as the ESA, restricts activities that may affect endangered or threatened species or their habitats. While some of our properties may be located in areas that may be designated as habitat for endangered or threatened species, we believe that we are in substantial compliance with the ESA.  Looking forward, we expect more listings of such species to occur, in light of renewed efforts by certain environmental activists to use the ESA as a mechanism to restrict land development and energy production. Such listings could include habitat in areas where we operate or plan to operate, or which could adversely affect our ability to secure needed sand, water or other materials for our operations or to transport oil or gas via pipeline to our customers. Further, some of the species could become subject to voluntary rangeland conservation plans that could affect our operations of sources of materials. Such listing of additional species, or the discovery of previously unidentified endangered or threatened species, or the adoption of conservation plans, could cause us to incur additional costs or become subject to operating restrictions, construction delays, or bans on operating in the affected areas.

 

Abandonment Costs.    All of our oil and gas wells will require proper plugging and abandonment at some time in the future. We have posted bonds with most regulatory agencies to ensure compliance with our plugging responsibility. Plugging and abandonment operations and associated reclamation of the surface site are important components of our environmental management system. We plan accordingly for the ultimate disposition of properties that are no longer producing.

 

Title to Properties

 

As is customary in the oil and gas industry, we make only a cursory review of title to undeveloped oil and gas leases at the time we acquire them. However, before drilling commences, we make a thorough title search, and any material defects in title are remedied prior to the time actual drilling of a well begins. To the extent title opinions or other investigations reflect title defects, we, rather than the seller/lessor of the undeveloped property, are typically obligated to cure any title defect at our expense. If we were unable to remedy or cure any title defect of a nature such that it would not be prudent to commence drilling operations on the property, we could suffer a loss of our entire investment in the property. We believe that we have good title to our properties, some of which are subject to immaterial encumbrances, easements and restrictions. The oil and gas properties we own are also typically subject to royalty and other similar non-cost bearing interests customary in the industry. We do not believe that any of these encumbrances or burdens will materially affect our ownership or use of our properties.

 

Competition

 

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 and services to explore for such reserves and knowledgeable personnel to conduct all phases of oil and gas 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 near-term operations, we cannot assure you that such materials and resources will be available to us in the future.

 

Employees

 

As of April 30, 2021, we had 62 full-time employees. We retain independent geological, land, marketing, engineering and health and safety consultants from time to time and expect to continue to do so in the future. We operate on the fundamental philosophy that people are our most valuable asset as every person who works for us has the potential to impact our success. Identifying quality talent is at the core of everything we do and our success is dependent upon our ability to attract, develop and retain highly qualified employees. Our core values include honesty/integrity, treating people fairly, high performance, efficient and effective processes, open communication and being respected in our local communities. These values establish the foundation on which the culture is built and represent the key expectations we have of our employees. We believe our culture and commitment to our employees creates an environment that allows us to attract and retain our qualified talent, while simultaneously providing significant value to the Company and its stockholders by helping our employees attain their highest level of creativity and efficiency.

 

 

Available Information

 

We file annual, quarterly and current reports, proxy statements and other information with the Securities and Exchange Commission (“SEC”). You may read and copy any document we file with the SEC at the SEC’s public reference room at 100 F Street, NE, Room 1580, Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for information on the public reference room. The SEC maintains an internet web site that contains annual, quarterly and current reports, proxy statements and other information that issuers (including Abraxas) file electronically with the SEC. The SEC’s web site is www.sec.gov.

 

Our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and other reports and amendments filed with the SEC are available free of charge on our web site at www.abraxaspetroleum.com in the Investor Relations section as soon as practicable after such reports are filed.  Information on our web site is not incorporated by reference into this Form 10-K and should not be considered part of this report or any other filing that we make with the SEC.

 

 

Item 1A. Risk Factors

 

Going Concern 

 

As discussed under Item 7. Managements 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:

 

 

affecting our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes which may be impaired or not available on favorable terms;

 

requiring us to meet financial tests contained in our credit facilities and future debt arrangements that may affect our flexibility in planning for and reacting to changes in our business, including future business opportunities;

 

requiring us to use a substantial portion of our cash flow from operations to make principal and interest payments on our indebtedness, reducing the funds that would otherwise be available for operations and future business opportunities; and

 

making us more vulnerable to competitive pressures if there is a downturn in our business or the economy in general, than our competitors with less debt.

 

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:

 

 

reducing the amount of oil, gas and NGL that we can produce economically;

 

limiting our financial flexibility, liquidity and access to sources of capital, such as equity and debt;

 

reducing our revenues, cash flows from operations and profitability;

 

causing us to decrease our capital expenditures or maintain reduced capital spending for an extended period, resulting in lower future production of oil, gas and NGL; and

 

reducing the carrying value of our properties, resulting in additional noncash write-downs.

 

 

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:

 

 

the level of demand;

 

domestic and global supplies of oil, NGL and gas;

 

the price and quantity of imported and exported oil, NGL and gas;

 

the actions of other oil exporting nations;

 

weather conditions and changes in weather patterns;

 

the availability, proximity and capacity of appropriate transportation facilities, gathering, processing and compression facilities, storage facilities and refining facilities;

  global or national health concerns, including the outbreak of pandemic or contagious disease, such as the coronavirus (COVID-19);
 

worldwide economic and political conditions, including political instability or armed conflict in oil and gas producing regions, competition for markets and political initiatives disfavoring fossil fuels;

 

the price and availability of, and demand for, competing energy sources, including alternative energy sources;

 

the nature and extent of governmental regulation, including environmental regulation, regulation of derivatives transactions and hedging activities, tax laws and regulations and laws and regulations with respect to the import and export of oil, gas and related commodities;

 

the level and effect of trading in commodity futures markets, including trading by commodity price speculators and others, and;

 

the effect of worldwide energy conservation measures.

 

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:

 

Decreases in commodity prices in recent years have resulted in reduced investment in midstream facilities by some third parties;

 

Various interest groups have protested the construction of new pipelines, and particularly pipelines near water bodies, in various places throughout the country, and protests have at times physically interrupted pipeline construction activities;

 

Some companies in our industry have sought to reject volume commitment agreements with midstream providers in bankruptcy proceedings, and the risk that such efforts will succeed, or that upstream energy company counterparties will otherwise be unable or unwilling to satisfy their volume commitments, may have the effect of reducing investment in midstream infrastructure; and

 

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:

 

 

incur or guarantee additional indebtedness and issue certain types of preferred stock or redeemable stock;

 

transfer or sell assets;

 

create liens on assets;

 

pay dividends or make other distributions on capital stock or make other restricted payments, including repurchasing, redeeming or retiring capital stock or subordinated debt or making certain investments or acquisitions;

 

engage in transactions with affiliates;

 

make any change in the principal nature of our business;

 

permit a change of control; or

 

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

 

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:

 

 

highly volatile oil and gas prices;

 

our production being less than expected; or

 

a counterparty to one of our hedging transactions defaulting on its contractual obligations.

 

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:

 

 

prevailing and anticipated prices for oil and gas;

 

the availability and costs of drilling and service equipment and crews;

 

economic and industry conditions at the time of drilling;

 

the availability of sufficient capital resources;

 

the results of our exploitation efforts;

 

the acquisition, review and interpretation of seismic data;

 

our ability to obtain permits for and to access drilling locations;

 

continuous drilling obligations; and

 

lease expirations.

 

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:

 

 

the operator could refuse to initiate exploitation or development projects and if we proceed with any of those projects, we may not receive any funding from the operator with respect to that project;

 

the operator may initiate exploitation or development projects on a different schedule than we would prefer;

 

the operator may propose greater capital expenditures than we wish, including expenditures to drill more wells or build more facilities on a project than we have funds for, which may mean that we cannot participate in those projects and thus, not participate in the associated revenue stream; and

 

the operator may not have sufficient expertise or resources.

 

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:

 

 

unexpected drilling conditions;

 

facility or equipment failure or accidents;

 

adverse weather conditions;

 

title problems;

  delays due to protection from fracture stimulations of nearby wells,
 

unusual or unexpected geological formations;

 

fires, blowouts and explosions; and

 

uncontrollable pressures or flows of oil or gas or well fluids.

 

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:

 

 

environmental hazards, such as uncontrollable flows of oil, gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater, underground migration and surface spills or mishandling of chemical additives;

 

abnormally pressured formations;

 

mechanical difficulties, such as stuck oil field drilling and service tools and casing collapse;

 

leaks of gas, oil, condensate, NGL and other hydrocarbons or losses of these hydrocarbons as a result of accidents during drilling and completion operations, or in the gathering and transportation of hydrocarbons, malfunctions of pipelines, measurement equipment or processing or other facilities in the Company’s operations or at delivery points to third parties;

 

fires and explosions;

 

personal injuries and death;

 

regulatory investigations and penalties; and

 

natural disasters.

 

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:

 

 

limiting oil and gas development;

 

reducing access to federal and state owned lands;

 

delaying or canceling certain projects such as offshore drilling, shale development, and pipeline construction;

 

limiting or banning the use of hydraulic fracturing;

 

denying air-quality permits for drilling; and

 

advocating for increased regulations on shale drilling and hydraulic fracturing.

 

Future anti-development efforts could result in the following:

 

 

blocked development;

 

denial or delay of drilling permits;

 

shortening of lease terms or reduction in lease size;

 

restrictions on installation or operation of gathering or processing facilities;

 

restrictions on the use of certain operating practices, such as hydraulic fracturing;

 

reduced access to water supplies or restrictions on water disposal;

 

reduce access to sand, or other proppants, required for hydraulic fracturing;

 

limited access or damage to or destruction of our property;

 

legal challenges or lawsuits;

 

increased regulation of our business;

 

damaging publicity and reputational harm;

 

increased costs of doing business;

 

reduction in demand for our products; and

 

other adverse effects on our ability to develop our properties and expand production.

 

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:

 

 

changes in foreign and domestic supply and demand for oil and gas;

 

political stability and economic conditions in oil producing countries, particularly in the Middle East, including Saudi Arabia and Russia;

 

weather conditions;

 

global or national health concerns, including the outbreak of pandemic or contagious disease;

 

price and level of foreign imports;

 

terrorist activity;

 

availability of pipeline and other secondary capacity;

 

general economic conditions;

 

domestic and foreign governmental regulation; and

 

the price and availability of alternative fuel sources.

 

 

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:    

 

  reducing our revenues if the outbreak results in a substantial or prolonged decrease in demand for oil and natural gas due to an economic downturn or recession;
  disrupting our operations if our employees or contractors are unable to work due to illness or if our field operations are suspended or temporarily shut-down or restricted due to measures designed to contain the outbreak; 
  disrupting the operations of our midstream service providers, on whom we rely for the gathering, processing and transportation of our production, due to measures designed to contain the outbreak, and/or the difficult economic environment may lead to capital spending constraints, bankruptcy, the closing of facilities or inability to maintain infrastructure, which may adversely affect our ability to market our production, increase our costs, lower the prices we receive, or result in the shut-in of our producing wells or a delay or discontinuation of our development plans; and
  the disruption and instability in the financial markets and the uncertainty in the general business environment may affect our ability to access capital, monetize assets and successfully execute our plans.

 

  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:

 

 

supply of and demand for our oil and gas;

 

actual prices we receive for our oil and gas;

 

our actual operating costs;

 

the amount and timing of our capital expenditures;

 

the amount and timing of our actual production; and

 

changes in governmental regulations or taxation.

 

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:

 

 

fluctuations in commodity prices;

 

variations in results of operations;

 

legislative or regulatory changes;

 

general trends in the oil and gas industry;

 

sales of common stock or other actions by our stockholders;

 

additions or departures of key management personnel;

 

commencement of or involvement in litigation;

 

speculation in the press or investment community regarding our business;

 

an inability to maintain the listing of our common stock on a national securities exchange;

 

market conditions; and

 

analysts’ estimates and other events in the oil and gas industry.

 

 

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.

 

 

Item 1B. Unresolved Staff Comments

 

None.

 

Item 2. Properties

 

Exploratory and Developmental Acreage

 

Our principal oil and gas properties consist of producing and non-producing oil and gas leases, including reserves of oil and gas in place. The following table sets forth our developed and undeveloped acreage and fee mineral acreage as of December 31, 2020.

 

   

Developed Acreage

   

Undeveloped Acreage

   

Fee Mineral Acreage (1)

         
   

Gross Acres

   

Net Acres

   

Gross Acres

   

Net Acres

   

Gross Acres

   

Net Acres

    Total Net Acres (2)  

Permian/Delaware Basin

    18,242       13,868       13,196       8,792       9,556       2,391       25,051  

Rocky Mountain

    20,778       11,509       9,185       5,235       2,078       106       16,850  

Total

    39,020       25,377       22,381       14,027       11,634       2,497       41,901  

 

 

(1)

Fee mineral acreage represents fee simple absolute ownership of the mineral estate or fraction thereof.

 

(2)

Includes 640 net acres in the Permian Basin region that are included in both developed and fee mineral acres.

 

The following table sets forth Abraxas’ net undeveloped acreage subject to expiration by year:

 

 

   

2021

   

2022

   

2023

   

2024

   

2025

 

Permian/Delaware Basin

    593       -       -       -       -  

Rocky Mountain

    -       -       -       -       -  
Total     593       -       -       -       -  

 

Productive Wells

 

The following table sets forth our gross and net productive wells, expressed separately for oil and gas, as of December 31, 2020: 

 

   

Productive Wells

 
   

Oil

   

Gas

 
   

Gross

   

Net

   

Gross

   

Net

 

Permian/Delaware Basin

    57.0       48.2       46.0       33.6  

Rocky Mountain

    149.0       68.1       319.0       6.9  
      206.0       116.3       365.0       40.5  

 

 

Reserves Information

 

The estimation and disclosure requirements we employ conform to the definition of proved reserves with the Modernization of Oil and Gas Reporting rules, which were issued by the SEC in 2008. This accounting standard requires that the average first-day-of-the-month price during the 12-month period preceding the end of the year be used when estimating reserve quantities and permits the use of reliable technologies to determine proved reserves, if those technologies have been demonstrated to result in reliable conclusions about reserves volumes.

 

The Company’s proved oil and gas reserves have been estimated by an independent petroleum engineering firm, DeGolyer & MacNaughton, as of December 31, 2019 and 2020, assisted by the engineering and operations departments of the Company. For the year ended December 31, 2020, DeGolyer & MacNaughton, of Dallas, Texas estimated reserves for our properties comprising approximately 93% of the PV-10 of our proved oil and gas reserves. Proved reserves for the remaining 7% of our properties  were estimated by Abraxas personnel because we determined that it was not practical for DeGolyer & MacNaughton to prepare reserves estimates for these properties as they are located in a widely dispersed geographic area and have relatively low value. DeGolyer & MacNaughton's reserve report as of December 31, 2020 included a total of 125 properties and our internal report included 121 properties.

 

The technical personnel responsible for preparing the reserve estimates at DeGolyer & MacNaughton meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. DeGolyer & MacNaughton is an independent firm of petroleum engineers, geologists, geophysicists, and petrophysicists. They do not own an interest in any of our properties and are not employed on a contingent fee basis. All reports by DeGolyer & MacNaughton were developed utilizing their own geological and engineering data, supplemented by data provided by Abraxas.  The report of DeGolyer & MacNaughton, dated February 12, 2021, which contains further discussions of the reserve estimates and evaluations prepared by DeGolyer & MacNaughton as well as the qualifications of DeGolyer & MacNaughton’s technical personnel responsible for overseeing such estimates and evaluations is attached as Exhibit 99.1 to this report.

 

Estimates of reserves at December 31, 2020 were assisted by the engineering department of Abraxas which is directly responsible for Abraxas’ reserve evaluation process.  The Vice President of Engineering manages this department and is the primary technical person responsible for this process.  The Vice President of Engineering holds a Bachelor of Science degree in Petroleum Engineering and is a Registered Professional Engineer in the State of Texas; he has 42 years of experience in reserve evaluations. The operations department of Abraxas also assisted in the process. Reserve information as well as models used to estimate such reserves are stored on secured databases.  Non-technical inputs used in reserve estimation models, including oil and gas prices, production costs, future capital expenditures and Abraxas’ net ownership percentages, were obtained from other departments within Abraxas.

 

Oil and gas reserves and the estimates of the present value of future net revenues therefrom were determined based on prices and costs as prescribed by SEC and Financial Accounting Standards Board, or FASB, guidelines. Reserve calculations involve the estimate of future net recoverable reserves of oil and gas and the timing and amount of future net revenues to be received therefrom. Such estimates are not precise and are based on assumptions regarding a variety of factors, many of which are variable and uncertain. Proved oil and gas reserves are the estimated quantities of oil and gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed oil and gas reserves are those expected to be recovered through existing wells with existing equipment and operating methods.  Proved reserves were estimated in accordance with guidelines established by the SEC and the FASB, which require that reserve estimates be prepared under existing economic and operating conditions with no provision for price and cost escalations or de-escalations except by contractual arrangements. For the year ended December 31, 2020, commodity prices over the prior 12-month period and year end costs were used in estimating future net cash flows.

 

The following table sets forth certain information regarding estimates of our oil and gas reserves as of December 31, 2020. All of our reserves are located in the United States. 

 

Summary of Oil, NGL and Gas Reserves

 

As of December 31, 2020

 

Reserve Category

 

Oil (MBbls)

   

NGL (MBbls)

   

Gas (MMcf)

   

Oil equivalents (MBoe)

 

Proved

                               

Developed

    9,537       3,187       24,318       16,778  

Undeveloped

    -       -       -       -  

Total Proved

    9,537       3,187       24,318       16,778  

 

As of December 31, 2020, we did not recognize any proved undeveloped reserves. During 2020, our proved undeveloped reserves are excluded from our total proved reserves primarily due to capital constraints, as a result of the uncertainty of  the Company to continuing as a "going concern" as described in Item 1. Going Concern.

 

Our estimates of proved developed reserves, proved undeveloped reserves, and total proved reserves at December 31, 2019 and 2020, and changes in proved reserves during the last two years are presented in the Supplemental Oil and Gas Disclosures under Item 8 of this report.  Also presented in the Supplemental Information are our estimates of future net cash flows and discounted future net cash flows from proved reserves.

 

We have not filed information with a federal authority or agency with respect to our estimated total proved reserves at December 31, 2020. We report gross proved reserves of operated properties in the United States to the U.S. Department of Energy on an annual basis; these reported reserves are derived from the same data used to estimate and report proved reserves in this report.

 

 

The process of estimating oil and gas reserves 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 set forth or incorporated by reference in this report.  We may also adjust estimates of 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. In particular, estimates of oil and gas reserves, future net revenue from reserves and the PV-10 thereof for the oil and gas properties described in this report are based on the assumption that future oil and gas prices remain the same as oil and gas prices utilized in the December 31, 2020 report. 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. It is also assumed that we will make future capital expenditures of approximately $6.3 million in the aggregate primarily in the years 2020 through 2024, which are necessary to develop and realize the value of proved reserves on our properties. Any significant variance in actual results from these assumptions could also materially affect the estimated quantity and value of reserves set forth herein.

 

You should not assume that the present value of future net revenues referred to in this report is the current market value of our estimated oil and gas reserves. In accordance with SEC requirements, the estimated discounted future net cash flows from proved reserves are calculated using the average first-day-of-the-month price over the prior 12-month period.  Costs used in the estimated discounted future net cash flows are costs as of the end of the period. Because we use the full cost method to account for our oil and gas operations, we are susceptible to significant non-cash charges during times of volatile commodity prices because the full cost pool may be impaired when prices are low. This is known as a “ceiling limitation write-down.” This charge does not impact cash flows from operating activities but does reduce our stockholders’ equity and reported earnings. We have experienced ceiling limitation write-downs in the past and we cannot assure you that we will not experience additional ceiling limitation write-downs in the future. As of December 31, 2020, the Company’s net capitalized costs of oil and gas properties exceeded the present value of our estimated proved reserves by $187.0 million, resulting in the recording of a proved property impairment of $187.0 million. As of December 31, 2019, the Company’s net capitalized costs of oil and gas properties  exceeded the present value of our estimated proved reserves by $51.3 million, resulting in the recording of a proved property impairment of $51.3 million. If commodity prices decrease, we could be required to further write down the carrying value of our reserves in the future.

 

For more information regarding the full cost method of accounting, you should read the information under “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Critical Accounting Policies.”

 

Actual future prices and costs may be materially higher or lower than the prices and costs used in the reserve report. Any changes in consumption by gas purchasers or in governmental regulations or taxation will also affect actual future net cash flows. The timing of both the production and the expenses from the development and production of oil and gas properties will affect the timing of actual future net cash flows from proved reserves and their present value. In addition, the 10% discount factor, which is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes, is not necessarily the most accurate discount factor. Our effective interest rate on borrowings at various times and the risks associated with us or the oil and gas industry in general will affect the accuracy of the 10% discount factor.

 

Proved Undeveloped Reserves

 

Changes in PUDs. Significant changes to PUDs that occurred during 2020 are summarized in the table below.  As a result of the uncertainty that we can continue as a "going concern" we are not recognizing any proved undeveloped reserves as of    December 31, 2020.

 

The following is a summary of the changes to the Company's proved undeveloped reserves that occurred during 2020: 

 

   

MBoe

 

PUDs at December 31, 2019

    39,125  
Revisions of prior estimates     (1,413 )
Extensions, discoveries, and other additions     -  
Conversion to developed     -  
Conversion to probable     (25,054 )
Other (1)     (12,658 )

PUDs at December 31, 2020

    -  

 

 

 

(1) At December 31, 2020  all proved undeveloped reserves were removed from our total proved reserves. This was primarily due to  the uncertainty of the Company remaining a "going concern" and  the availability of capital for developing those reserves. 

 

The following is additional information regarding the changes to the Company’s proved undeveloped reserves that occurred during 2020.

 

Revisions of prior estimates

 

A decrease of 1,413 MBoe of net reserves was attributed to decreased economic life calculations at the lower commodity pricing experienced during 2020.

 

Extensions, discoveries and other additions

 

The Company did not add any new proved undeveloped locations during 2020 due to either extensions or discoveries. Also, the Company did not convert any probable undeveloped to proved undeveloped reserves during 2020.

 

Conversion to developed:

 

The Company did not convert any proved undeveloped to proved developed reserves during 2020.

 

Conversion to probable:

 

The Company converted 29 proved undeveloped Wolfcamp A1 locations, and 25 3rd Bone Spring locations in Ward County, Texas, to probable undeveloped reserves during 2020 accounting for 17,601 MBoe of net reserves.  The Company converted five proved undeveloped Middle Bakken locations and nine Three Forks locations in McKenzie County, North Dakota, to probable undeveloped reserves during 2020 accounting for 5,153 MBoe of net reserves.  The Company converted two proved undeveloped Delaware Montoya locations in Ward County, Texas, to probable undeveloped reserves during 2020 accounting for 2,300 MBoe of net reserves.  All these locations are no longer included in the Company’s five-year development schedule.

 

Sold:

 

The Company did not sell any proved undeveloped locations during 2020.

 

Reconciliation of Standardized Measure to PV-10

 

PV-10 is the estimated present value of the future net revenues from our proved oil and gas reserves before income taxes discounted using a 10% discount rate. PV-10 is considered a non-GAAP financial measure under SEC regulations because it does not include the effects of future income taxes, as is required in computing the standardized measure of discounted future net cash flows. We believe that PV-10 is an important measure that can be used to evaluate the relative significance of our oil and gas properties and that PV-10 is widely used by securities analysts and investors when evaluating oil and gas companies. Because many factors that are unique to each individual company impact the amount of future income taxes to be paid, the use of a pre-tax measure provides greater comparability of assets when evaluating companies. We believe that most other companies in the oil and gas industry calculate PV-10 on the same basis. PV-10 is computed on the same basis as the standardized measure of discounted future net cash flows but without deducting income taxes.

 

The following table provides a reconciliation of the standardized measure of discounted future net cash flows to PV-10 at December 31, 2019 and 2020:

 

   

December 31,

 
   

2019

   

2020

 
   

(In thousands)

 

Standardized measure of discounted future net cash flows

  $ 307,612     $ 106,684  

Present value of future income taxes discounted at 10%

    -       -  

PV-10

  $ 307,612     $ 106,684  

 

 

Oil and Gas Production, Sales Prices and Production Costs

 

The following table presents our net oil, gas and NGL production, the average sales price per Bbl of oil and NGL and per Mcf of gas produced and the average cost of production per Boe of production sold, for the two years ended December 31, by our major operating regions:

 

   

Years Ended December 31,

 
   

2019

   

2020

 

Oil Production (Bbl)

               

Permian

    985,600       596,680  

Rocky Mountain

    1,348,192       536,032  

South Texas

    53,935       -  

Total

    2,387,727       1,132,712  

Gas Production (Mcf)

               

Permian

    1,380,003       689,684  

Rocky Mountain

    2,400,193       1,444,753  

South Texas

    296,273       -  

Total

    4,076,469       2,134,437  

NGL Production (Bbl)

               

Permian

    149,409       67,586  

Rocky Mountain

    398,809       245,469  

South Texas

    215          

Total

    548,433       313,055  
                 

Total Production (Boe) (1)

    3,615,572       1,801,507  
                 

Average sales price per Bbl of oil (2)

               

Permian

  $ 53.56     $ 38.36  

Rocky Mountain

  $ 50.85     $ 35.58  

South Texas

  $ 58.58     $ -  

Composite

  $ 52.14     $ 37.05  

Average sales price per Mcf of gas

               

Permian

  $ 0.36     $ 0.49  

Rocky Mountain

  $ 0.62     $ 0.17  

South Texas

  $ 2.04     $ -  

Composite

  $ 0.63     $ 0.27  

Average sales price per Bbl of NGL

               

Permian

  $ 4.03     $ 2.42  

Rocky Mountain

  $ 3.27     $ 1.08  

South Texas

  $ 15.41     $ -  

Composite

  $ 3.48     $ 1.37  

Average sales price per Boe (2)

  $ 35.68     $ 23.86  

Average cost of production per Boe produced (3)

               

Permian

  $ 11.33     $ 12.14  

Rocky Mountain

  $ 4.86     $ 7.03  

South Texas

  $ 17.27     $ -  

Composite

  $ 7.66     $ 9.24  

 

(1)

Oil and gas were combined by converting gas to Boe on the basis of 6 Mcf of gas to 1 Bbl of oil.

 

(2)

Before the impact of hedging activities.

 

(3)

Production costs include direct lease operating costs but exclude ad valorem taxes and production taxes.

 

 

Within the above major operating regions, the Rocky Mountain and the Permian/Delaware regions represented more than 15% of our proved reserves as of December 31, 2020. The following is a summary, by product sold, for each primary field in these regions, which represented 15% or more of our total proved reserves as of December 31, 2020, for the two years ended December 31:

 

   

Years Ended December 31,

 
   

2019

   

2020

 

Rocky Mountain Region

               

Oil production (Bbls)

               

Bakken/Three Forks

    1,298,000       509,518  

Gas production (Mcf)

               

Bakken/Three Forks

    2,360,608       1,428,355  

NGL production (Bbls)

               

Bakken/Three Forks

    397,836       244,835  

Average sales price per Bbl of oil (1)

               

Bakken/Three Forks

  $ 50.89     $ 35.78  

Average sales price of per Mcf of gas

               

Bakken/Three Forks

  $ 0.61     $ 0.17  

Average sales price per Bbl of NGL

               

Bakken/Three Forks

  $ 3.26     $ 1.08  

Average cost of production per Boe produced (2)

  $ 3.82     $ 5.96  
                 

Permian Region

               

Oil production (Bbls)

    892,030       538,086  

Wolfcamp

               

Gas Production (Mcf)

    822,165       375,507  

Wolfcamp

               

NGL production (Bbls)

    126,181       55,706  

Wolfcamp

               

Average sales price per Bbl of oil (1)

  $ 53.51     $ 38.64  

Wolfcamp

               

Average sales price of per Mcf of gas

  $ 0.24     $ 0.14  

Wolfcamp

               

Average sales price per Bbl of NGL

  $ 3.17     $ 1.70  

Wolfcamp

               

Average cost of production per Boe produced (2)

  $ 11.00     $ 12.97  

    

 

(1)

Before the impact of hedging activities.

 

(2)

Production costs include direct lease operating costs but exclude ad valorem taxes and production taxes.

 

Drilling Activities

 

The following table sets forth our gross and net interests in exploratory and development wells drilled and or completed during the two years ended December 31:

 

   

2019

   

2020

 
   

Gross

   

Net

   

Gross

   

Net

 

Exploratory

                               

Productive

                               

Permian/Delaware

    -       -       -       -  

Rocky Mountain

    -       -       -       -  

South Texas

    -       -       -       -  

Total

    -       -       -       -  
                                 

Development

                               

Productive

                               

Permian/Delaware

    9.0       7.3       -       -  

Rocky Mountain

    6.0       2.4       -       -  

South Texas

    -       -       -       -  

Total

    15.0       9.7       -       -  

 

In addition to the above drilling activity, as of December 31, 2020 we had 6.00 gross (5.4 net) operated wells in the Bakken that were drilled and uncompleted that are not represented in the above table.

 

 

Present Activities 

 

Due to the drastic decline in oil prices occurring in early March 2020, we suspended any drilling and completion work indefinitely.  As a result, we have taken steps to reduce our general and administrative cost reductions, including, but not limited to, reduction of salaries for our executive officers and reductions in our work force. 

 

Office Facilities

 

Our executive and administrative offices are located at 18803 Meisner Drive, San Antonio, Texas 78258, and consist of approximately 21,000 square feet. We own the building which is subject to a real estate lien note. 

 

Other Properties

 

We own 1.5 acres of land and an office building in Ward County, Texas and an office building and lot in Niobrara County, Wyoming and 582 acres of land, with shop and office, in McKenzie County, North Dakota. We own 21 vehicles which are used in the field by employees. We also own a workover rig, which is used for servicing our wells. Raven Drilling owns a 2000 HP drilling rig, primarily used for drilling wells in the Williston Basin. In North Dakota, we own three houses and a man-camp to house rig crews.

 

Item 3. Legal Proceedings

 

From time to time, we are involved in litigation relating to claims arising out of our operations in the normal course of business. At December 31, 2020, we were not engaged in any legal proceedings that are expected, individually or in the aggregate, to have a material adverse effect on our financial condition.

 

Item 4. Mine Safety Disclosures

 

Not applicable.

 

 

Part II

 

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

 

Market Information

 

Our common stock is traded on The NASDAQ Stock Market under the symbol "AXAS." The following table sets forth certain information as to the high and low sales price quoted for our common stock.

 

     

High

   

Low

 

Period

                 

2019

                 
 

First Quarter

  $ 30.00     $ 20.20  
 

Second Quarter

    31.00       19.00  
 

Third Quarter

    22.60       8.60  
 

Fourth Quarter

    10.40       4.40  
                   

2020

First Quarter

  $ 8.40     $ 1.80  
 

Second Quarter

    11.00       2.20  
 

Third Quarter

    5.20       2.80  
 

Fourth Quarter

    5.60       1.41  
                   

2021

First Quarter

  $ 4.99     $ 2.23  
  Second Quarter (Through April 30, 2021)     3.57       2.02  

 

Holders

   

As of April 30, 2021, we had 8,421,910 shares of common stock outstanding and approximately 55 stockholders of record.

 

Dividends

 

We have not paid any cash dividends on our common stock and it is not presently determinable when, if ever, we will pay cash dividends in the future. In addition, our credit facilities prohibit the payment of cash dividends on our common stock.

 

Item 6. Selected Financial Data

 

The following selected financial data is derived from our Consolidated Financial Statements as of and for the years ended December 31, 2016 through 2020. The data should be read in conjunction with our Consolidated Financial Statements and Notes thereto and other financial information included herein. See “Financial Statements and Supplementary Data” in Item 8. All share and per share amounts reflect the retroactive treatment of the Reverse Stock Split, see Note 3 to our Consolidated Financial Statements.

 

   

Year Ended December 31,

         
   

2016

           

2017

   

2018

   

2019

           

2020

         
   

(In thousands, except per share data)

         

Total revenue - continuing operations

  $ 56,555             $ 86,264     $ 149,167     $ 129,146             $ 43,043          

Net (loss) income

  $ (96,378 )           $ 16,006     $ 57,821     $ (65,004 )           $ (184,522 )        

Net (loss) income from continuing operations

  $ (96,378 )     (1 )   $ 16,006     $ 57,821     $ (65,004 )     (2 )   $ (184,522 )     (3 )

Net income (loss) from discontinued operations - net of tax

  $ -             $ -     $ -     $ -             $ -          

Net (loss) income per common share - diluted - continuing operations

  $ (15.80 )           $ 2.00     $ 6.80     $ (7.80 )           $ (22.01 )        

Weighted average shares outstanding - Diluted

    6,107               8,142       8,384       8,315               8,382          

Total assets

  $ 161,648             $ 273,806     $ 424,741     $ 354,631             $ 157,761          

Long-term debt, excluding current maturities

  $ 96,616             $ 87,354     $ 181,942     $ 192,718             $ 2,515          

Total stockholders' equity

  $ 18,505             $ 106,308     $ 166,510     $ 103,819             $ (72,967 )        

___________________________ 

 

(1)

Includes proved property impairment of $67.6 million.

(2) 

Includes proved property impairment of $51.3 million.
(3) Includes proved property impairment of $187.0 million

 

 

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

 

The following is a discussion of our consolidated financial condition, results of operations, liquidity and capital resources. This discussion should be read in conjunction with our Consolidated Financial Statements and the Notes thereto. See “Financial Statements and Supplementary Data” in Item 8.

 

General

 

We are an independent energy company primarily engaged in the acquisition, exploration, exploitation, development and production of oil and gas in the United States. Historically, we have grown through the acquisition and subsequent development and exploitation of producing properties, principally through the redevelopment of old fields utilizing new technologies such as modern log analysis and reservoir modeling techniques as well as 3-D seismic surveys and horizontal drilling. As a result of these activities, we believe that we have a number of development opportunities on our properties. In addition, we intend to expand upon our development activities with complementary acreage acquisitions in our core areas of operation. Success in our development and exploration activities is critical in the maintenance and growth of our current production levels and associated reserves.

 

Our financial results depend upon many factors which significantly affect our results of operations including the following:

 

 

commodity prices and the effectiveness of our hedging arrangements;

 

 

the level of total sales volumes of oil and gas;

 

 

the availability of and our ability to raise additional capital resources and provide liquidity to meet cash flow needs;

 

 

the level of and interest rates on borrowings; and

 

 

the level and success of exploration and development activity.

 

Commodity Prices and Hedging Arrangements. The results of our operations are highly dependent upon the prices received for our oil and gas production. The prices we receive for our production are dependent upon spot market prices, differentials and the effectiveness of our derivative contracts, which we sometimes refer to as hedging arrangements. Substantially all of our sales of oil and gas are made in the spot market, or pursuant to contracts based on spot market prices, and not pursuant to long-term, fixed-price contracts. Accordingly, the prices received for our oil and gas production are dependent upon numerous factors beyond our control. Significant declines in prices for oil and gas could have a material adverse effect on our financial condition, results of operations, cash flows and quantities of reserves recoverable on an economic basis. 

 

Oil and gas prices have been volatile, and this volatility is expected to continue.  As a result of the many uncertainties associated with the world political environment, worldwide supplies of oil, NGL and gas, the availability of other worldwide energy supplies and the relative competitive relationships of various energy sources in the view of consumers, we are unable to predict what changes may occur in oil, NGL, and gas prices in the future.  The market price of oil, NGL and gas in 2021 will impact the amount of cash generated from operating activities, which will in turn impact our financial position. As of April 30, 2021, the NYMEX oil and gas price was $63.58 per Bbl of oil and $2.93 per Mcf of gas, respectively.

 

During 2020, the NYMEX future price for oil averaged $39.57 per barrel as compared to $57.05 per barrel in 2019 and the NYMEX future spot price for gas averaged $2.13 per Mcf compared to $2.53 per Mcf in 2019. Prices closed on December 31, 2020 at $48.52 per Bbl of oil and $2.13 per Mcf of gas.  If commodity prices decline from these levels, our revenue and cash flows from operations will also likely decline.  In addition, lower commodity prices could also reduce the amount of oil and gas that we can produce economically.  If oil and gas prices decline, our revenues, profitability and cash flows from operations will also likely decrease which could cause us to alter our business plans, including reducing our drilling activities. Such declines will require us to write down the carrying value of our oil and gas assets which will also cause a reduction in net income. 

 

The realized prices that we receive for our production differ from NYMEX futures and spot market prices, principally due to: 

 

 

basis differentials which are dependent on actual delivery location;

 

 

adjustments for BTU content;

 

 

quality of the hydrocarbons; and

 

 

gathering, processing and transportation costs.

 

The following table sets forth our average differentials for the years ended December 31,  2019 and 2020:

 

   

Oil

   

Gas

 
   

2019

   

2020

   

2019

   

2020

 

Average realized price

  $ 52.14     $ 37.05     $ 0.63     $ 0.27  

Average NYMEX price

  $ 57.05     $ 39.57     $ 2.53     $ 2.13  

Differential

  $ (4.91 )   $ (2.52 )   $ (1.90 )   $ (1.86 )

_______________________

 

(1)

Average realized prices are before the impact of hedging activities.

 

The Company’s derivative contracts as of December 31, 2020 and December 31, 2019 consisted of NYMEX-based fixed price swaps and basis differential swaps. Under fixed price swaps, we receive a fixed price for our production and pay a variable market price to the contract counter-party.

 

 

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 2023 and 88% for 2024. By removing a portion of price volatility on our future oil and gas production, we believe we will mitigate, but not eliminate, the potential effects of changing commodity prices on our cash flows from operations for those periods.  However, when prevailing market prices are higher than our contract prices, we will not realize increased cash flows on the portion of the production that has been hedged.  We have in the past and will in the future sustain losses on both open and settled derivative contracts if market prices are higher than our contract prices. Conversely, when prevailing market prices are lower than our contract prices, we will sustain realized and unrealized gains on our commodity derivative contracts. In 2020, we recorded a gain of $42.9 million, consisting of a gain of $17.5 million on closed contracts and a gain of $25.4 million related to open contracts. In 2019, we recognized a loss of $26.8 million, consisting of a loss of $6.0 million on closed contracts and a loss of $20.8 million related to open contracts. We have not designated any of these derivative contracts as a hedge as permitted by applicable accounting rules if certain conditions are met. Substantially all of our hedging contracts were terminated subsequent to March 31, 2021. See Note 14 "Subseqemt Events".

 

The following table sets forth our derivative contracts at December 31, 2020:

 

   

Oil - WTI

 

Contract Periods

 

Daily Volume (Bbl)

   

Swap Price (per Bbl)

 

Fixed Swaps

               

January - December 2021

    2,889     $ 57.62  

January - December 2022

    2,412     $ 50.60  
January - December 2023     1,498     $ 50.60  

January - December 2024

    1,585     $ 50.60  

 

At December 31, 2020, the aggregate fair market value of our commodity derivative contracts was an asset of approximately $19.4  million.

 

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.

 

Production Volumes. Our proved reserves will decline as oil and gas is produced, unless we find, acquire or develop additional properties containing proved reserves or conduct successful exploration and development activities.   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% , 13%  and 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.  While we have had some success in finding, acquiring and developing additional reserves, we have not always been able to fully replace the production volumes lost from natural field declines and property sales. Our ability to acquire or find additional reserves in the future will be dependent, in part, upon the amount of available funds for acquisition, exploration and development projects. The decline in oil prices that occurred in March 2020, resulted in the suspension of our 2020 drilling program as well as shutting in production for some period of time. Both of these events  impacted our production volumes and will impact them going forward.

 

In addition to our ability to successfully drill wells, we must also market our production which depends substantially on the availability, proximity and capacity of gathering systems, pipelines and processing facilities, which are also known as midstream facilities, owned and operated by third parties. If adequate midstream facilities and services are not available to us on a timely basis and at acceptable costs, our production and results of operations could be adversely affected. Both of our principal areas of operation (the Bakken and Permian Basin) have experienced substantial development in recent years, and this has made it more difficult for providers of midstream infrastructure and services to keep pace with the corresponding increases in field-wide production. The ultimate timing and availability of adequate infrastructure is not within our control and we could experience capacity constraints for extended periods of time that would negatively impact our ability to meet our production targets. Weather, regulatory developments and other factors also affect the adequacy of midstream infrastructure.

 

We had cash capital expenditures during 2020 of approximately $12.6 million. This amount includes a decrease in the amount of capital expenditures in accounts payable of $7.2 million, resulting in accrual based capital expenditures related to 2020 of $5.4  million. Due to declines in oil prices, we suspended our planned capital expenditures for 2020. This suspension of our  capital expenditure budget is subject to change depending upon a number of factors, including the availability and costs of drilling and service equipment and crews, economic and industry conditions at the time of drilling, prevailing and anticipated prices for oil and gas, the availability of sufficient capital resources the results of our exploitation efforts, our financial results and our ability to obtain permits for drilling locations.

 

The following table presents historical net production volumes for the years ended December 31, 2019 and 2020:

 

   

2019

   

2020

 

Total Production (Mboe)

    3,616       1,801  

Average daily production (Boepd)

    9,906       4,922  

% Oil

    66 %     63 %

 

Availability of Capital.  As described more fully under “Liquidity and Capital Resources” below, our sources of capital are cash flows from operating activities, cash on hand, proceeds from the sale of properties, monetizing of derivative instruments, and if an appropriate opportunity presents itself, the sale of debt or equity securities, although we may not be able to complete any financing on terms acceptable to us, if at all. Our credit facilities were amended in June 2020 and the  borrowing base under our First Lien Credit Facility was reduced to the then outstanding balance of $102.0 million, resulting in no additional availability, additionally, any excess cash, as defined in the First Lien Credit Facility, will be applied to the outstanding balance on a monthly basis, and the borrowing base will be reduced to the new outstanding balance.

 

 

Borrowings and Interest.  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.  As a result, we would need to increase our cash flow from operations in order to fund the development of our drilling opportunities which, in turn, will be dependent upon the level of our production volumes and commodity prices.

 

Exploration and Development Activity. We believe that our asset base, high degree of operational control and inventory of drilling projects position us for future growth. At December 31, 2020, we operated properties comprising approximately 97% of the Boe's of our estimated net proved reserves, giving us substantial control over the timing and incurrence of operating and capital expenditures. We have identified numerous additional drilling locations on our existing leaseholds, the successful development of which we believe could significantly increase our production and proved reserves. Over the five years ended December 31, 2020, we drilled or participated in 92 gross (42.8 net) wells all of which were commercially productive. The amendments to our First Lien Credit Facility and Second Lien Credit facility place severe restrictions on our future capital expenditures. We have suspended any planned drilling activity for  2021 indefinitely.

 

Our future oil and gas production, and therefore our success, is highly dependent upon our ability to find, finance, 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. If our proved reserves decline in the future, our production may also decline and, consequently, our cash flows from operations will decline. We may be unable to acquire or develop additional reserves, in which case our results of operations and financial condition could be adversely affected.

 

Results of Operations

 

Selected Operating Data

 

Not required for Smaller Reporting Company.

 

 

Comparison of Year Ended December 31, 2020 to Year Ended December 31, 2019

 

Revenue. During the year ended December 31, 2020, revenue decreased to $43.0 million from $129.1 million in 2019. The decrease in revenue was primarily due to lower sales volumes and lower prices for all products in 2020 . Lower sales volumes were the result of our decision to shut-in a significant amount of our production in mid-March as a result of the drastic price drop in early March due predominantly to the COVID 19 pandemic as well as geopolitical issues impacting supply and demand  Lower commodity prices negatively impacted revenue by  $18.5 million, while lower sales volumes had a negative impact on revenue of  $67.5 million. During 2020 we experienced a decrease in the average realized oil price of approximately 29% from 2019 levels. Average realized gas prices decreased by approximately 57% and average realized NGL prices decreased by approximately 75% from 2019 levels. 

 

Oil sales volumes decreased to 1,133 MBbls for the year ended December 31, 2020 from 2,388  MBbls for the same period of 2019. The decrease in oil sales volumes was primarily due to wells being shut in for most of the second quarter of 2020 due to severely depressed prices. We started bringing the shut in wells back on production in June, and had a majority of such wells back on production by early September. No new wells were brought on line in 2020. Gas sales volumes decreased to 2,134 MMcf for the year ended December 31, 2020 compared to 4,076 MMcf for the year ended December 31, 2019.  NGL sales decreased to 313 MBbls for the year ended December 31, 2020 compared to 548 MBbls for the same period of 2019. Overall BOE sales in 2020 were approximately 50%  of 2019 sales.

 

Lease Operating Expenses (“LOE”). LOE for the year ended December 31, 2020 decreased to $16.5 million from $27.6 million in 2019.  The decrease in LOE was primarily due to the disposition of our south Texas properties during the fourth quarter of 2019 and lower non-recurring LOE in 2020 as compared to 2019. Additionally, during the first nine months of 2020, we purchased certain production equipment that we had previously been renting and brought electrical power into most of our West Texas locations eliminating the need for generator rentals. We also reduced our work force in North Dakota in May 2020 and eliminated substantially all field overtime.   LOE per Boe for the year ended December 31, 2020 was $9.14  compared to $7.64 for the same period of 2019. The increase in LOE per Boe was attributable to lower sales volumes in 2020 as compared to 2019.

 

 

Production and Ad Valorem Taxes.  Production and ad valorem taxes for the year ended December 31, 2020 decreased to $4.6 million from $10.6 million in 2019. The decrease was primarily due to lower realized prices and sales volumes in 2020 as compared to 2019. Production and ad valorem taxes as a percentage of oil and gas revenue were 11% in 2020  compared to 8% for the same period of  2019. The increase in the percentage of revenue is primarily due to ad valorem taxes that are not impacted by production tax rates.

 

General and Administrative (“G&A”) Expense.  G&A expense, excluding stock-based compensation, decreased to $7.5 million for the year ended December 31, 2020 from $9.4 million in 2019.  G&A expense per Boe was $4.15 for the year ended December 31, 2020 compared to $2.60 for the same period of 2019. The reduction in total G&A expense was primarily due to a reduction in personnel in the corporate office, as well as reductions in salaries. Officer salaries were reduced by 20%  effective March 1, 2020, and our CEO took an additional 20% reduction in salary effective April 1, 2020.  The increase per Boe was primarily due to  lower sales volumes. Due to management's decision to shut in substantially all production for most of the second quarter and a portion of  the third quarter, management believes the absolute decrease in cost is more relevant than the cost per BOE.

 

Stock-Based Compensation.  Restricted stock, stock options and performance based restricted stock  granted to employees and directors are valued at the date of grant and expense is recognized over the securities vesting period. Stock-based compensation decreased to $1.3 million for the year ended December 31, 2020 compared to $1.9 million for the same period of 2019. The decrease was primarily due to the cancellation, forfeiture, and expiration of stock options.  The Company did not award any stock options in 2019 or 2020..

 

Depreciation, Depletion, and Amortization (“DD&A”) Expenses. DD&A expense excluding accretion of future site restoration, decreased to $24.4 million for the year ended December 31, 2020 from $52.3 million in 2019. The decrease was primarily due to lower future development cost included in the December 31, 2020 internal reserve report, as well as lower production volumes during the year  ended December 31, 2020 as compared to the same period of 2019.  DD&A expense per Boe for the year ended December 31, 2020 was $13.63 compared to $14.46 in the same period of  2019. The decrease in DD&A expense per Boe was primarily due to a lower full cost pool as the result of the impairment incurred as of December 31, 2019 and in 2020 as well as lower production volumes.

 

Interest Expense. Interest expense increased to $21.3 million in 2020 from $12.3 million for 2019. The increase was primarily due to higher debt levels in 2020 as compared to 2019, as well as higher overall  interest rates in 2020 as compared to 2019. In 2020 the interest rate on our First Lien Credit facility averaged 3.6% as compared to 5.7% in 2019. On November 13, 2019, we entered into the Term Loan Credit Agreement, which we refer to as the Second Lien Credit Facility. The average interest rate on the Second Lien Credit Facility was 13.75% for the year ended December 31, 2020. Approximately $12.7 million of interest on the Second Lien Credit Facility was paid in kind.

 

Income Taxes.  Due to losses in the periods and loss carry forwards, we did not recognize any income tax expense for the years ended December 31, 2020 and 2019.

 

(Gain) loss on Derivative Contracts. Derivative gains or losses are determined by actual derivative settlements during the period and by periodic mark to market valuation of derivative contracts in place. We have elected not to apply hedge accounting to our derivative contracts as prescribed by Accounting Standards Codification 815, Derivatives and Hedging "ASC 815"; therefore, fluctuations in the market value of the derivative contracts are recognized in earnings during the current period. Our derivative contracts consisted of fixed price swaps and basis differential swaps in 2020 and 2019. The net estimated value of our commodity derivative contracts was an asset of approximately $19.4 million as of December 31, 2020. When our derivative contract prices are higher than prevailing market prices, we recognize gains and conversely, when our derivative contract prices are lower than prevailing market prices, we incur losses. For the year ended December 31, 2020, we incurred a gain of $42.9 million, consisting of a gain of $17.5 million on closed contracts and a gain of $25.4 million on the mark to market valuation on open contracts. For the year ended December 31, 2019, we recognized a loss on our derivative contracts of approximately $26.8 million, consisting of a loss of $6.0 million on closed contracts and a loss of $20.8 million on the mark to market valuation of open contracts.

 

Ceiling Limitation Write-Down. We record the carrying value of our oil and gas properties using the full cost method of accounting for oil and gas properties. Under this method, we capitalize the cost to acquire, explore for and develop oil and gas properties.  Under the full cost accounting rules, the net capitalized cost of oil and gas properties less related deferred taxes, are limited by country, to the lower of the unamortized cost or the cost ceiling, defined as the sum of the present value of estimated unescalated future net revenues from proved reserves, discounted at 10%, plus the cost of properties not being amortized, if any, plus the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any, less related income taxes.  If the net capitalized cost of oil and gas properties exceeds the ceiling limit, we are subject to a ceiling limitation write-down to the extent of such excess. A ceiling limitation write-down is a charge to earnings which does not impact cash flows from operating activities. However, such write-downs do impact the amount of our stockholders' equity and reported earnings. During 2020, the net capitalized cost of our oil and gas properties exceeded the future net revenues from our estimated proved reserves resulting in the recording of an impairment of $187.0 million. For the year ended  December 31, 2019, the net capitalized cost of our oil and gas properties exceeded the future net revenues from our estimated proved reserves resulting in the recording of an impairment of $51.3 million. The year-end amounts were calculated in accordance with SEC rules utilizing the twelve month first-day-of-the-month average oil and gas prices utilized for the year ended 2020 which were $39.54 per Bbl of oil and $2.03 per Mcf of gas as adjusted to reflect the expected realized prices for our oil and gas reserves. The twelve month first-day-of-the-month average oil and gas prices utilized for the year ended 2019 were $50.03 per Bbl of oil and $0.56 per Mcf of gas as adjusted to reflect the expected realized prices for our oil and gas reserves.

 

 

 

 

Working Capital (Deficit). At December 31, 2020,  our current liabilities of $219.3 million exceeded our current assets of  $24.1 million resulting in a working capital deficit of $195.2 million. This compares to a working capital deficit of $28.6 million at December 31, 2019. Current assets at December 31, 2020 primarily consisted of  accounts receivable of $10.0 million, current amount of our derivative asset of $9.6 million and other current assets of $1.6 million.  Current liabilities at December 31, 2020 primarily consisted of trade payables of $6.1 million, revenues due third parties of $8.8 million, current maturities of long-term debt of $202.8 million, the current amount of our derivative liability of $0.5 million and accrued expenses of $0.3 million. 

 

Capital Expenditures. Capital expenditures in  2019 and 2020 were $93.0 million and $5.4 million, respectively.  The table below sets forth the components of these capital expenditures:

 

    Years Ended December 31,  
   

2019

   

2020

 
    (in thousands)  

Expenditure category:

               

Exploration/Development

  $ 92,884     $ 5,238  

Acquisitions

    -       -  

Facilities and other

    155       162  
    $ 93,039     $ 5,400  

 

 

During 2020 capital expenditures were primarily expenditures on our existing properties, designed to reduce lease operating expense, such as purchasing certain equipment as opposed to renting. We also performed extensive workovers on several wells in 2020.  In 2019, capital expenditures were for the exploration and development of our existing properties.  The level of capital expenditures will vary during future periods depending on economic and industry conditions and commodity prices. Should the prices of oil and gas decline and if our costs of operations increase or if our production volumes decrease, our cash flows from operations will decrease which may result in a reduction of capital expenditure. Due to capital expenditure limits imposed by our credit facilities, we have not adopted a capital drilling budget for 2021, but do intend to complete the six previously drilled wells in the Bakken. If we cannot incur significant capital expenditure, we will not be able to offset oil and gas production decreases caused by natural field declines. 

 

Sources and Uses of Capital. The net funds provided by and/or used in each of the operating, investing and financing activities are summarized in the following table and discussed in further detail below: 

 

    Years Ended December 31,  
   

2019

   

2020

 
    (in thousands)  

Net cash provided by operating activities

  $ 73,647     $ 15,985  

Net cash used in investing activities

    (84,967 )     (12,557 )

Net cash (used in) provided by financing activities

    10,453       (653 )
    $ (867 )   $ 2,775  

 

Operating activities for the year ended December 31, 2020 provided  $16.0 million in cash compared to $73.6 million in 2019. The reduction was primarily due to lower net income due to lower commodity prices and lower production volumes. Investing activities used  $12.6 million in 2020 primarily for the development of our existing properties. Cash expenditures for the year ended December 31, 2020 included a decrease in the accounts payable balance related to capital expenditures of $7.2 million, resulting in accrual based capital expenditures incurred during the period of $5.4 million. 

 

Operating activities for the year ended December 31, 2019 provided  $73.6 million in cash. The reduction from 2018 was primarily due to lower net income due to lower commodity prices. Investing activities used  $85.0 million in 2019 primarily for the development of our existing properties and leasehold acquisitions. Cash expenditures for the year ended December 31, 2019 included a decrease in the accounts payable balance related to capital expenditures of $16.5 million, and an increase in our asset retirement obligation liability of $0.8 million, resulting in accrual based capital expenditures, net of dispositions of $23.4 million, incurred during the period of $93.0  million. Financing activities provided $10.5  million primarily from net borrowings under our First Lien Credit Facility and Second Lien Credit Facility.

 

 

 

 

 

Future Capital Resources. Our principal sources of capital going forward, are cash flows from operations, proceeds from the sale of properties, monetizing of derivative instruments and if an opportunity presents itself, the sale of debt or equity securities, although we may not be able to complete financing on terms acceptable to us, if at all.

 

Cash from operating activities is dependent upon commodity prices and production volumes.  A decrease in commodity prices from current levels would likely reduce our cash flows from operations.  This could cause us to alter our business plans, including reducing our exploration and development plans.  Unless we otherwise expand and develop reserves, our production volumes may decline as reserves are produced.  In the future we may continue to sell producing properties, which could further reduce our production volumes. To offset the loss in production volumes resulting from natural field declines and sales of producing properties, we must conduct successful exploration and development activities, acquire additional producing properties or identify and develop additional behind-pipe zones or secondary recovery reserves. We believe our numerous drilling opportunities will allow us to increase our production volumes; however, our drilling activities are subject to numerous risks, including the risk that no commercially productive oil and gas reservoirs will be found.  If our proved reserves decline in the future, our production will also decline and, consequently, our cash flows from operations will decline. 

 

Contractual Obligations. We are committed to making cash payments in the future on the following types of agreements:

 

 

Long-term debt

 

Below is a schedule of the future payments that we are obligated to make based on agreements in place as of December 31, 2020:

 

   

Payments due in the twelve month periods ended:

 

Contractual Obligations (In thousands)

 

Total

   

December 31, 2021

   

December 31, 2022-2023

   

December 31, 2024-2025

   

Thereafter

 

Long-term debt (1)

  $ 220,505     $ 217,990     $ 2,515     $ -     $ -  

Interest on long-term debt (2)

    6,672       6,497       175       -       -  
Paid in kind interest on long-term debt (3)     21,130       21,130       -       -       -  
Lease obligations     282       63       88       32       99  

Total

  $ 248,589     $ 245,680     $ 2,778     $ 32     $ 99  

___________________________

 

(1)

These amounts represent the balances outstanding under our credit facilities and the real estate lien note. These payments assume that we will not borrow additional funds.

 

(2)

Interest expense assumes the balances of long-term debt at December 31, and current effective interest rates at that time.

  (3) Represents interest expense paid in kind on our Second Lien Credit Facility. Accrued interest is added to the outstanding balance and is payable at maturity.

 

We maintain a reserve for costs associated with the retirement of tangible long-lived assets. At December 31, 2020, our reserve for these obligations totaled $7.4 million for which no contractual commitments exist. For additional information relating to this obligation, see Note 1 of the Notes to Consolidated Financial Statements.

 

Off-Balance Sheet Arrangements. At December 31, 2020, we had no existing off-balance sheet arrangements, as defined under SEC regulations, that have, or are reasonably likely to have a current or future material effect on our financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that are material to investors.

 

Contingencies. From time to time, we are involved in litigation relating to claims arising out of our operations in the normal course of business. At December 31, 2020, we were not engaged in any legal proceedings that are expected, individually or in the aggregate, to have a material adverse effect on us.

 

Long-Term Indebtedness.

 

Long-term debt consisted of the following:

 

    Years Ended December 31,  
   

2019

   

2020

 
   

(In thousands)

 

First Lien Credit Facility

  $ 95,778     $ 95,000  
Second Lien Credit Facility     100,000       112,695  
Exit fee - Second Lien Credit Facility     -       10,000  

Real estate lien note

    3,091       2,810  
      198,869       220,505  

Less current maturities

    (280 )     (202,751 )
      198,589       17,754  
Deferred financing fees and debt issuance cost - net     (5,871 )     (15,239 )
Total long-term debt, net of deferred financing fees and debt issuance costs   $ 192,718     $ 2,515  

 

 

The following sections regarding the First Lien Credit Facility and Second Lien Credit Facility are qualified in their entirety by the disclosure contained in Item 1. Business, Going Concern, which is expressly incorporated in the sections below. Due to certain covenant violations as of December 31, 2020, and the potential for future violations, all of the debt related to our credit facilities has been classified as current liabilities.

 

First Lien Credit Facility

 

The Company has a senior secured First Lien Credit Facility with Société Générale, as administrative agent and issuing lender, and certain other lenders.  As of December 31, 2020,  $95.0 million was outstanding under the First Lien Credit Facility. 
 

Outstanding amounts under the First Lien Credit Facility accrue interest at a rate per annum equal to (a)(i) for borrowings that we elect to accrue interest at the reference rate  at the greater of (x) the reference rate announced from time to time by Société Générale, (y) the federal funds rate plus 0.5%, and (z)  daily one-month LIBOR plus, in each case, 1.5%-2.5%, depending on the utilization of the borrowing base, and (ii) for borrowings that  we elect to accrue interest at the Eurodollar rate, LIBOR plus 2.5%-3.5% depending on the utilization of the borrowing base, and (b) at any time an event of default exists, 3.0% plus the amounts set forth above. At December 31, 2020, the interest rate on the First Lien Credit Facility was approximately 3.6%.

     Subject to earlier termination rights and events of default, the stated maturity date of the First Lien Credit Facility is May 16, 2022. Interest is payable quarterly on reference rate advances and not less than quarterly on LIBOR advances. The Company is permitted to terminate the First Lien Credit Facility and is able, from time to time, to permanently reduce the lenders’ aggregate commitment under the First Lien Credit Facility in compliance with certain notice and dollar increment requirements.

 

Each of the Company's subsidiaries has guaranteed our obligations under the First Lien Credit Facility on a senior secured basis. Obligations under the First Lien Credit Facility are secured by a first priority perfected security interest, subject to certain permitted encumbrances, in all of the Company and its subsidiary guarantors’ material property and assets. As of December 31, 2020, the collateral is required to include properties comprising at least 90% of the PV-9 of the Company's proven reserves and 95% of the PV-9 of the Company's PDP reserves.

 
Under the amended First Lien Credit Facility, the Company is subject to customary covenants, including financial covenants and reporting covenants. The amendment to the First Lien Credit Facility dated June 25, 2020 (the "1L Amendment") modified certain provisions of the First Lien Credit Facility, including (i) the addition of monthly mandatory prepayments from excess cash (defined as available cash minus certain cash set-asides and a $3.0 million working capital reserve) with corresponding reductions to the borrowing base; (ii) the elimination of scheduled redeterminations (which were previously made every six months) and interim redeterminations (which were previously made at the request of the lenders no more than once in the six month period between scheduled redeterminations) of the borrowing base; (iii) the replacement of total debt leverage ratio and minimum asset ratio covenants with a first lien debt leverage ratio covenant (comparing the outstanding debt of the First Lien Credit Facility to the consolidated EBITDAX of the Company and requiring that the ratio not exceed 2.75 to 1.00 as of the last day of each fiscal quarter) and a minimum first lien asset coverage ratio covenant (comparing the sum of, without duplication, (A) the PV-15 of producing and developed proven reserves of the Company, (B) the PV-9 of the Company’s hydrocarbon hedge agreements and (C) the PV-15 of proved reserves of the Company classified as “drilled uncompleted” (up to 20% of the sum of (A), (B) and (C)) to the outstanding debt of the First Lien Credit Facility and requiring that the ratio exceed 1.15 to 1.00 as of the last day of each fiscal quarter ending on or before December 31, 2020, and 1.25 to 1.00 for fiscal quarters ending thereafter); (iv) the elimination of current ratio and interest coverage ratio covenants; (v) additional restrictions on (A) capital expenditures (limiting capital expenditures to $3.0 million in any four fiscal quarter period (commencing with the four fiscal quarter period ended June 30, 2020 and calculated on an annualized basis for the 1, 2 and 3 quarter periods ending on June 30, 2020, September 30, 2020 and December 31, 2020, respectively, subject to certain exceptions, including capital expenditures financed with the proceeds of newly permitted, structurally subordinated debt and capital expenditures made when (1) the first lien asset coverage ratio is at least 1.60 to 1.00, (2) the Company is in compliance with the first lien leverage ratio, (3) the amounts outstanding under the First Lien Credit Facility are less $50.0 million, (4) no default exists under the First Lien Credit Facility and (5) and all representations and warranties in the First Lien Credit Facility and the related credit documents are true and correct in all material respects), (B) outstanding accounts payable (limiting all outstanding and undisputed accounts payable to $7.5 million, undisputed accounts payable outstanding for more than 60 days to $2.0 million and undisputed accounts payable outstanding for more than 90 days to $1.0 million and (C) general and administrative expenses (limiting cash general and administrative expenses the Company may make or become legally obligated to make in any four fiscal quarter period to $9.0 million for the four fiscal quarter period ended June 30, 2020, $8.25 million for the four fiscal quarter period ended September 30, 2020, $6.9 million for the four fiscal quarter period ending December 31, 2020, and $6.5 million for the fiscal quarter from March 31, 2021 through December 31, 2021 and $5.0 million thereafter; in all cases, general and administrative expense excludes up to $1.0 million in certain legal and professional fees; and (vi) permission for up to an additional $25.0 million in structurally subordinated debt to finance capital expenditures. Under the 1L Amendment, the borrowing base was adjusted to $102.0 million. The borrowing base will be reduced by any mandatory prepayments from excess cash flow (in an amount equal to such prepayment) and upon the disposition of the Company’s oil and gas properties.

 

 

 

 

 

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The First Lien Credit Facility contains a number of covenants that, among other things, restrict our ability to: 

  incur or guarantee additional indebtedness;
  transfer or sell assets;
  pay dividends or make other distributions on capital stock or make other restricted payments;
  engage in transactions with affiliates other than on an "arm's length" basis;
  make any change in the principal nature of our business; and
  permit a change in control

 

The First Lien Credit Facility also contains customary events of default, including nonpayment of principal or interest, violations of covenants, cross default and cross acceleration to certain other indebtedness, bankruptcy and material judgments and liabilities. 
 

Events of default have occurred, or are reasonably likely to occur, under the First Lien Credit Facility as a result of (i) our failure to timely deliver audited financial statements without a “going concern” or like qualification for the fiscal year ended December 31, 2020, (ii) our inability to comply with the first lien debt to consolidated EBITDAX ratio for the fiscal quarter ended December 31, 2020, (iii) our failure to cause certain deposit accounts to be subject to control agreements in favor of the administrative agent for the First Lien Credit Facility and (iv) certain cross-defaults that have occurred, or may occur, as a result of the events of default under the First Lien Credit Agreement and corresponding cross-defaults under the Second Lien Credit Facility and cross-defaults or similar termination events under our hedging contracts.

 

Second Lien Credit Facility

 

On November 13, 2019, we entered into the Term Loan Credit Agreement, with Angelo Gordon Energy Servicer, LLC, as administrative agent, and certain other lenders party thereto, which we refer to as the Second Lien Credit Facility. The Second Lien Credit facility was amended on June 25, 2020. The Second Lien Credit Facility has a maximum commitment of $100.0 million. On November 13, 2019, $95.0 million of the net proceeds obtained from the Second Lien Credit Facility were used to permanently reduce the borrowings outstanding on the First Lien Credit Facility.  As of December 31,  2020, the outstanding balance on the Second Lien Credit Facility was $122.7 million, which includes a $10.0 million exit fee. 

 

The stated maturity date of the Second Lien Credit Facility is November 13, 2022. Prior to the latest amendments of the Second Lien Credit Facility, accrued interest was payable quarterly on reference rate loans and at the end of each three-month interest period on Eurodollar loans. We are permitted to prepay the loans in whole or in part, in compliance with certain notice and dollar increment requirements.

 
Each of our subsidiaries has guaranteed our obligations under the Second Lien Credit Facility. Obligations under the Second Lien Credit Facility are secured by a first priority perfected security interest, subject to certain permitted liens, including those securing the indebtedness under the First Lien Credit Facility to the extent permitted by the Intercreditor Agreement, of even date with the Second Lien Credit Facility, among us, our subsidiaries, Angelo Gordon Energy Servicer, LLC and Société Générale, in all of our subsidiary guarantors’ material property and assets. As of December 31, 2020, the collateral is required to include properties comprising at least 90% of the PV-9 of the Company's proven reserves and 95% of the PV-9 of the Company's PDP reserves. 

 

 

 

 

 
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Under the amended Second Lien Credit Facility, the Company is subject to customary covenants, including financial covenants and reporting covenants. The amendment to the Second Lien Credit Facility dated June 25, 2020 (the "2L Amendment") modified certain provisions of the Second Lien Credit Facility, including (i) a requirement that, while the obligations under the First Lien Credit Facility are outstanding, scheduled payments of accrued interest under the Second Lien Credit Facility will be paid in the form of capitalized interest; (ii) an increase in the interest rate by 200bps for interest payable in cash and 500bps for interest payable in kind; (iii) modification of the minimum asset ratio covenant to be the sum of, without duplication, (A) the PV-15 of producing and developed proven reserves of the Company, (B) the PV-9 of the Company’s hydrocarbon hedge agreements and (C) the PV-15 of proved reserves of the Company classified as “drilled uncompleted” (up to 20% of the sum of (A), (B) and (C)) to the total outstanding debt of the Company and requiring that the ratio not exceed 1.45 to 1.00 as of the last day of each fiscal quarter ending between September 30, 2021 to December 31, 2021, and 1.55 to 1.00 for fiscal quarters ending thereafter); (iv) modification of the total leverage ratio covenant to set the first test date to occur on September 30, 2021; (v) modification of the current ratio to eliminate the exclusion of certain valuation accounts associated with hedge contracts from current assets and from current liabilities, (vi) additional restrictions on (A) capital expenditures (limiting capital expenditures to those expenditures set forth in a plan of development approved by Angelo Gordon Energy Servicer, LLC, subject to certain exceptions, including capital expenditures financed with the proceeds of newly permitted, structurally subordinated debt), (B) outstanding accounts payable (limiting all outstanding and undisputed accounts payable to $7.5 million, undisputed accounts payable outstanding for more than 60 days to $2.0 million and undisputed accounts payable outstanding for more than 90 days to $1.0 million and (C) general and administrative expenses (limiting cash general and administrative expenses the Company may make or become legally obligated to make in any four fiscal quarter period to $9.0 million for the four fiscal quarter period ended June 30, 2020, $8.25 million for the four fiscal quarter period ended September 30, 2020, $6.5 million for fiscal quarter period from March 31, 2021 through December 31, 2021 and $5.0 million thereafter. 

 

 As of December 31, 2020 we were in compliance with  the financial covenants under the Second Lien Credit Facility, as amended.

 

The Second Lien Credit Facility contains a number of covenants that, among other things, restrict our ability to:

  incur or guarantee additional indebtedness;
  transfer or sell assets;
  create liens on assets;
  pay dividends or make other distributions on capital stock or make other restricted payments; 
  engage in transactions with affiliates other than on an “arm’s length” basis;
  make any change in the principal nature of our business; and
  permit a change of control

 

The Second Lien Credit Facility also contains customary events of default, including nonpayment of principal or interest, violation of covenants, cross default and cross acceleration to certain other indebtedness, bankruptcy and material judgments and liabilities.
 

Events of default have occurred, or are reasonably likely to occur, under the Second Lien Credit Facility as a result of (i) our failure to timely deliver audited financial statements without a “going concern” or like qualification for the fiscal year ended December 31, 2020, (ii) our failure to cause certain deposit accounts to be subject to control agreements in favor of the administrative agent for the Second Lien Credit Facility, (iii) the failure of the Company to meet certain hedging requirements, and (v) certain cross-defaults that have occurred, or may occur, as a result of the occurrence of events of default under the First Lien Credit Facility and the Second Lien Credit Facility and corresponding cross-defaults or similar termination events under our hedging contracts.

 

On April 16, 2021, we received a Notice of Default and Reservation of Rights (the “Notice of Default”) from Angelo Gordon stating that we have defaulted under the Second Lien Credit Facility, and that, as a result, the lenders have accelerated our obligations due thereunder and have reserved their rights to pursue additional remedies in the future.

 

The Notice of Default describes certain events of default that occurred under the Second Lien Credit Facility as a result of (i) our failure to file timely our Form 10-K for the fiscal year ended December 31, 2020, (ii) our failure to timely deliver audited financial statements without a “going concern” or like qualification for the fiscal year ended December 31, 2020, and (iii) other defaults under our revolving credit facility.

 

The Notice of Default declares that our obligations under the Second Lien Credit Facility are immediately due and payable, in each case without presentment, demand, protest or other requirements of any kind, and have begun to bear interest at the rate applicable to such amount under the Second Lien Credit Facility, plus an additional 3%. Additionally, the administrative agent and the lenders have reserved their right to exercise further rights, powers and remedies under the Second Lien Credit Facility, at any time or from time to time, with respect to any of the events of default described above. Angelo Gordon has agreed to forbear from exercising remedies available to it until May 6, 2021.

 

In connection with the amendment to the Second Lien Credit Facility on June 25, 2020, the Company entered into an Exit Fee and Warrant Agreement subject to NASDAQ approval for the issuance of the issuance of certain warrants. This agreement was finalized on August 11, 2020 at which time the Company issued a warrant to the lender to purchase a total of 33,445,792 shares of common stock at an exercise price of $0.01 per share. On October 19, 2020, the Company effected a reverse stock split of the Company’s authorized, issued and outstanding shares of common stock at a ratio of 1-for-20, thus the warrant was adjusted to provide that the lender may purchase a total of 1,672,290 shares of common stock at an exercise price of $0.20 per share. The warrant is exercisable immediately in whole or in part, on or before five years from the issuance date. The fair value of the warrant and exit fee were recorded as debt issuance costs, presented in the consolidated balance sheets as a deduction from the carrying amount of the note payable, and are being amortized over the loan term. The Exit Fee shall be due and payable in cash on the earliest to occur of maturity of the obligation under the Second Lien Credit Agreement or the earlier acceleration or payment in full of the same. The 2L Amendment, including the impact of the Exit Fee and Warrant Agreement finalized on August 11, 2020, resulted in the 2L Amendment meeting the criteria of debt extinguishment under the guidance of ASC 470: Debt. Accordingly, all debt issuance cost, including the original discount, of the original Second Lien Credit Facility, were charged to debt extinguishment loss in the accompanying Condensed Consolidated Statement of Operation in the amount of $4.1 million.

 

Real Estate Lien Note

We have a real estate lien note secured by a first lien deed of trust on the property and improvements which serves as our corporate headquarters. The outstanding principal accrues interest at a fixed rate of 4.9%. The note is payable in monthly installments of principal and interest in the amount of $35,672.  The maturity date of the note is July 20, 2023. As of  December 31, 2019, and 2020, $3.1 million and $2.8 million, respectively, were outstanding on the note.

 

Net Operating Loss Carryforwards

 

At December 31, 2020, we had, subject to the limitation discussed below, $245.20 million of pre 2020 NOLs for U.S. tax purposes and a $140.0 million NOL for 2020.  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. Any 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 and  can generally be carried forward indefinitely and can offset up to 80% of future taxable income for regular tax purposes, (the alternative minimum tax no longer applies to corporations after January 1, 2018).

 

Uncertainties exist as to the future utilization of the operating loss carryforwards under the criteria set forth under ASC 740-10 “Income Taxes”. Therefore, we have established a valuation allowance of $117.27 million for deferred tax assets at December 31, 2020.

 

Related Party Transactions

 

We have adopted a policy that transactions between us and our officers, directors, principal stockholders, or affiliates of any of them, will be on terms no less favorable to us than can be obtained on an arm’s length basis in transactions with third parties and must be approved by our audit committee. There were no related party transactions in  2019 or 2020.

 

 

 Critical Accounting Policies

 

The preparation of financial statements in conformity with U.S. generally accepted accounting principles (“GAAP”) requires that management apply accounting policies and make estimates and assumptions that affect results of operations and the reported amounts of assets and liabilities in the financial statements. The following represents those policies that management believes are particularly important to the financial statements and that require the use of estimates and assumptions to describe matters that are inherently uncertain.

 

Full Cost Method of Accounting for Oil and Gas Activities. SEC Regulation S-X Rule 4-10 and ASC 932 defines the financial accounting and reporting standards for companies engaged in oil and gas activities. Two methods are prescribed: the successful efforts method and the full cost method. We have chosen to follow the full cost method under which all costs associated with property acquisition, exploration and development are capitalized. We also capitalize internal costs that can be directly identified with our acquisition, exploration and development activities but do not include any costs related to production, general corporate overhead or similar activities. Sales of oil and gas properties are treated as a reduction of the full cost pool with no gain or loss being recognized, except under certain circumstances. Under the successful efforts method, geological and geophysical costs and costs of carrying and retaining undeveloped properties are charged to expense as incurred. Costs of drilling exploratory wells that do not result in proved reserves are charged to expense. Depreciation, depletion, amortization and impairment of oil and gas properties are generally calculated on a well by well or lease or field basis versus the “full cost” pool basis. Additionally, gain or loss may be recognized on sales of oil and gas properties under the successful efforts method. As a result, our financial statements will differ from those of companies that apply the successful efforts method since we will generally reflect a higher level of capitalized costs as well as a higher depreciation, depletion and amortization rate on our oil and gas properties.

 

At the time it was adopted, management believed that the full cost method would be preferable, as earnings tend to be less volatile than under the successful efforts method. However, the full cost method makes us susceptible to significant non-cash charges during times of volatile commodity prices because the full cost pool may be impaired when prices are low. These charges are not recoverable when prices return to higher levels. We have experienced this situation several times over the years, including a $51.3 million and  $187.0 million impairment recorded as of December 31, 2019 and December 31, 2020, respectively.  Our oil and gas reserves have a relatively long life. However, temporary drops in commodity prices can have a material impact on our business including impact from impairment testing procedures associated with the full cost method of accounting as discussed below.

 

Under full cost accounting rules, the net capitalized cost of oil and gas properties, less related deferred taxes, may not exceed a “ceiling limit” which is based upon the present value of estimated future net cash flows from proved reserves on a pool by pool basis, discounted at 10%, plus the lower of cost or fair market value of unproved properties and the cost of properties not being amortized, less income taxes. If net capitalized costs of 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 does reduce our stockholders’ equity and reported earnings. The risk that we will be required to write down the carrying value of oil and gas properties increases when oil and gas prices are depressed. 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 higher oil and gas prices may have increased the ceiling applicable to the subsequent period. We apply the full cost ceiling test on a quarterly basis on the date of the latest balance sheet presented. Given the recent decline in oil prices, it is likely that we will incur future impairments. 

 

Estimates of Proved Oil and Gas Reserves. Estimates of our proved reserves included in this report are prepared in accordance with GAAP and SEC guidelines. The accuracy of a reserve estimate is a function of:

 

 

the quality and quantity of available data;

 

 

the interpretation of that data;

 

 

the accuracy of various mandated economic assumptions; and

 

 

the judgment of the persons preparing the estimate.

 

Our proved oil and gas reserves have been estimated by our independent petroleum engineering firm, DeGolyer & MacNaughton, as of December 31, 2019 and 2020,  Estimates prepared by other third parties may be higher or lower than those included herein. Because these estimates depend on many assumptions, all of which may substantially differ from future actual results, reserve estimates will be different from the quantities of oil and gas that are ultimately recovered. In addition, results of drilling, testing and production after the date of an estimate may justify material revisions to the estimate.

 

You should not assume that the present value of future net cash flows is the current market value of our estimated proved reserves. In accordance with SEC requirements, we based the estimated discounted future net cash flows from proved reserves on costs on the date of the estimate and for the years ended December 31, 2019 and 2020 oil and gas prices were based on the average 12-month first-day-of-the-month pricing.  Actual future prices and costs may be materially higher or lower than the prices and costs used in the estimate.

 

The estimates of proved reserves materially impact DD&A expense and the ceiling test calculation. If the estimates of proved reserves decline, the rate at which we record DD&A expense will increase and we may be required to record future impairments of the full cost pool, reducing future net income. Such a decline may result from lower market prices, which may make it uneconomic to drill for and produce higher cost fields.

 

Asset Retirement Obligations. The estimated costs of restoration and removal of facilities are accrued. The fair value of a liability for an asset’s retirement obligation is recorded in the period in which it is incurred and the corresponding cost is capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depreciated over the useful life of the related asset. For all periods presented, we have included estimated future costs of abandonment and dismantlement in our full cost amortization base and we amortize these costs as a component of our depletion expense.

 

Accounting for Derivatives. Gains or losses are determined by actual derivative settlements during the period and on the periodic mark to market valuation of derivative contracts in place. The derivative instruments we utilize are based on index prices that may and often do differ from the actual oil and gas prices realized in our operations.  We have elected not to apply hedge accounting to our derivative contracts. As a result, fluctuations in the market value of the derivative contract are recognized in earnings during the current period. In 2019 and 2020 derivative contracts consisted of fixed price swaps and basis differential swaps. Due to the volatility of oil and gas prices, our financial condition and results of operations can be significantly impacted by changes in the market value of our derivative instruments. As of December 31, 2019, and 2020, the net market value of our commodity derivatives was a net liability of $7.4 million and a net asset of  $19.4 million, respectively. The recent drop in oil prices has resulted in a significant increase in the value of our derivative contracts.

 

 

Recently Issued Accounting Standards 

 

Effective January 1, 2020, the Company adopted Accounting Standards Update ("ASU") 2016-13 and its related amendments.  This ASU primarily applies to the Company’s accounts receivable, of which the majority are due within 30 days. The Company monitors the credit quality of its counterparties through review of collections, credit ratings, and other analysis. The Company develops its estimated allowance for credit losses primarily using an aging method and analysis of historical loss rates as well as consideration of current and future conditions that could impact its counterparties’ credit quality and liquidity. The adoption and implementation of this ASU did not have a material impact on the Company’s financial statements.

 

In November 2019, the FASB issued ASU 2019-12 – Income Taxes (“Topic 740”): Simplifying the Accounting for Income Taxes. The amendments in ASU 2019-12 are part of an initiative to reduce complexity in accounting standards and simplify the accounting for income taxes by removing certain exceptions from Topic 740 and making minor improvements to the codification. ASU 2019-12 and its related amendments will be effective for public entities for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2020. The provisions of this update are not expected to have a material impact on the Company’s financial position or results of operations.

 

New accounting pronouncements issued but not yet adopted. 

 

In March 2020, the FASB issued ASU No. 2020-04, “Reference Rate Reform (Topic 840): Facilitation of the Effects of Reference Rate Reform on Financial Reporting” (“ASU 2020-04”), which provides companies with optional guidance to ease the potential accounting burden associated with transitioning away from reference rates (e.g., London Interbank Offered Rate (“LIBOR”)) that are expected to be discontinued. ASU 2020-04 allows, among other things, certain contract modifications, such as those within the scope of Topic 470 on debt, to be accounted as a continuation of the existing contract. This ASU was effective upon the issuance and its optional relief can be applied through December 31, 2022. The Company will consider this optional guidance prospectively, if applicable.

 

In May 2020, the SEC adopted final rules that amend the financial statement requirements for significant business acquisitions and dispositions. Among other changes, the final rules modify the significance tests and improve the disclosure requirements for acquired or to be acquired businesses and related pro forma financial information, the periods those financial statements must cover, and the form and content of the pro forma financial information. The final rules do not modify requirements for the acquisition and disposition of significant amounts of assets that do not constitute a business. The final rules are effective January 1, 2021, but earlier compliance is permitted. The Company will consider these final rules and update its disclosures, as applicable.

 

Item 7A. Quantitative and Qualitative Disclosures about Market Risk

 

Commodity Price Risk

 

As an independent oil and gas producer, our revenue, cash flows from operations, other income and profitability, reserve values, access to capital and future rate of growth are substantially dependent upon the prevailing prices of oil and gas. Declines in commodity prices will adversely affect our financial condition, liquidity, ability to obtain financing and operating results. Lower commodity prices may reduce the amount of oil and gas that we can produce economically. Prevailing prices for such commodities are subject to wide fluctuation in response to relatively minor changes in supply and demand and a variety of additional factors beyond our control, such as global, political and economic conditions. Historically, prices received for our oil and gas production have been volatile and unpredictable, and such volatility is expected to continue. Most of our production is sold at market prices. Generally, if the commodity indices fall, the price that we receive for our production will also decline. Therefore, the amount of revenue that we realize is partially determined by factors beyond our control. Assuming the production levels we attained during the year ended December 31, 2020, a 10% decline in oil and gas prices would have reduced our operating revenue and cash flows by approximately $4.3 million for the year. If commodity prices remain at their current levels the impact on operating revenues and cash flows, could be much more significant. However, we do have derivative contracts in place that will mitigate the impact of low commodity prices.

 

Derivative Instrument Sensitivity

 

At December 31, 2020, the aggregate fair market value of our commodity derivative contracts was an asset of  approximately $19.4 million. The fair market value of our commodity derivative contracts is sensitive to changes in the market price for oil and gas. When our derivative contract prices are higher than prevailing market prices, we recognize gains and conversely, when our derivative contract prices are lower than prevailing market prices, we incur losses.

 

 

Interest Rate Risk

 

We are subject to interest rate risk associated with borrowings under our First Lien Credit Facility and our Second Lien Credit facility.  As of December 31, 2020, we had $95.0 million of outstanding indebtedness under our First Lien Credit Facility and $112.7 of outstanding indebtedness under our Second Lien Credit Facility, each with a variable interest rate. At December 31, 2020, the interest rate on the First Lien Credit Facility was approximately 3.6% based on 1-month LIBOR borrowings and level of utilization. An increase in the interest rate of 1% would increase our interest expense by $1.0 million on an annual basis, based on the outstanding balance at December 31, 2020. At December 31, 2020 the interest rate on the Second Lien Credit Facility was 15.8% based on 3-month LIBOR borrowings. An increase of 1% would increase our interest expense by $1.1 million on an annual basis, based on the outstanding balance at December 31, 2020.

 

Item 8. Financial Statements and Supplementary Data

 

For the financial statements and supplementary data required by this Item 8, see the Index to Consolidated Financial Statements.

 

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

 

On July 20, 2020, the Company's Board of Directors engaged the accounting firm of ADKF, as the Company’s certifying accountants. The decision to approve the dismissal of BDO USA, LLP and engagement of ADKF was approved by the Board's Audit Committee and the Company's Board of Directors.  BDO USA, LLP was notified of their dismissal on July 21, 2020.

 

In connection with the audit of the Company’s financial statements for the fiscal year ended December 31, 2019, there were no disagreements with BDO USA, LLP on any matters of accounting principles, financial statement disclosure or audit scope and procedures which, if not resolved to the satisfaction of BDO USA, LLP, would have caused the firm to make reference to the matter in their report.

 

Item 9A. Controls and Procedures

 

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

 

Under the supervision and with the participation of our management, including our Chief Executive Officer (our principal executive officer) and our Chief Financial Officer (our principal financial officer), we evaluated the effectiveness of our disclosure controls and procedures (as defined under Rule 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”)). Based on this evaluation, the Chief Executive Officer and our Chief Financial Officer concluded that disclosure controls and procedures as of December 31, 2020 were effective, as of the end of the reporting period covered by this report, our disclosure controls over financial reporting are effective.

 

Changes in Internal Controls

 

There were no changes in our internal control over financial reporting during the fourth quarter of 2020 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

 

Management’s Annual Report on Internal Control Over Financial Reporting

 

Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting is a process designed by, or under the supervision of, the Company’s principal executive and principal financial officers and implemented by the Company’s Board of Directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles and includes those policies and procedures that: (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

 

Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal ControlIntegrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation, our management concluded that our internal control over financial reporting was effective as of December 31, 2020.

 

The effectiveness of our internal control over financial reporting as of December 31, 2020 has not been audited

 

Item 9B. Other Information

 

None.

 

 

 

 

 

PART III

 

Item 10. Directors, Executive Officers and Corporate Governance

 

 

Board of Directors

 

The following table sets forth the names, ages, and positions of the directors of Abraxas. The term of the Class I directors expires in 2021, but if re-elected will expire in 2024, the term of the Class II directors expires in 2023, and the term of the Class III directors expires in 2022.

 

 

 

Name and Municipality of Residence

 

Age

 

Office

Class

Robert L.G.Watson............................................................................................................................................

San Antonio, Texas

    70  

Chairman of the Board, President and Chief Executive Officer

II

             

Ralph F. Cox.......................................................................................................................................................

Fort Worth, Texas

    89  

Director

I

             

Brian L. Melton..................................................................................................................................................

Oklahoma City, Oklahoma

    51  

Director

III

             

Angela A. Steffen Meyer.....................................................................................................................................

Denton, Texas

    60  

Director

III

             
           

II

 

 

Robert L.G. Watson has served as Chairman of the Board, President, Chief Executive Officer and a director of Abraxas since 1977. Prior to forming Abraxas, Mr. Watson held petroleum engineering positions with Tesoro Petroleum Corporation and DeGolyer and MacNaughton. Mr. Watson received a Bachelor of Science degree in Mechanical Engineering from Southern Methodist University in 1972 and a Master of Business Administration degree from the University of Texas at San Antonio in 1974. Mr. Watson has been involved in the oil and gas industry for his entire business career and is the founder of Abraxas. He has developed a wide network of personal and business relationships within the oil and gas industry. His strong engineering and financial background combined with his many years of operational experience throughout changing conditions in the market and industry provide him with the ability to successfully lead the Company.

 

Ralph F. Cox, a director of Abraxas since December 1999, has over 50 years of oil and gas industry experience, over 30 of which were with Atlantic Richfield Company (ARCO). Mr. Cox retired from ARCO in 1985 after serving as Vice Chairman. Mr. Cox then joined Union Pacific Resources, retiring in 1989 as President and Chief Operating Officer. Mr. Cox then joined Greenhill Petroleum Corporation as President until leaving in 1994 to pursue a consulting business. Mr. Cox currently serves as a trustee for Fidelity Mutual Funds. Mr. Cox previously served as a director of Abraxas General Partner, LLC, the general partner of Abraxas Energy Partners, L.P., as a director of CH2M Hill Companies, an engineering and construction firm, as a director of World GTL Inc., a gas-to-liquids production facility, and as an advisory director of Impact Petroleum, an oil and gas exploration and production company. Mr. Cox received Bachelor of Science degrees in Petroleum Engineering and Mechanical Engineering from Texas A&M University in 1954 and completed advanced studies at Emory University.

 

Mr. Cox has many years of prior experience with major oil and gas companies. Mr. Cox continues his involvement in the industry through his other directorship positions. His executive-level perspective and decision making abilities continue to prove beneficial to the Company.

 

Brian L. Melton has served as the Senior Vice President – Commercial & Business Development of NorthStar Midstream (a private portfolio company of OakTree Capital) since September 2019. Prior to joining NorthStar, Mr. Melton worked as Chief Commercial Officer for Blueknight Energy Partners (Nasdaq: “BKEP”, or “Blueknight”), a publicly traded master limited partnership (MLP) that specializes in providing crude oil and asphalt terminalling from December 2013 until September 2019. Prior to joining Blueknight, Mr. Melton served as Vice-President of Business Development / Corporate Strategy for Crestwood Equity Partners, L.P. (NYSE: CEQP), Crestwood Midstream Energy Partners, L.P. (NYSE: CMLP), and Inergy, L.P. (NYSE: NRGY) from September 2008 until December 2013. Crestwood and Inergy are publicly-traded MLP’s that specialize in providing midstream crude oil, natural gas and natural gas liquids services to producers and midstream providers in many of the major U.S. shale plays including the Bakken, Eagle Ford, Marcellus / Utica, Barnett, Fayetteville, Haynesville and Niobrara U.S. shale regions. Prior to joining Inergy in 2008, Mr. Melton was a Director in the Energy Corporate Investment Banking groups of Wachovia Securities and A.G. Edwards, prior to its merger with Wachovia Securities in October of 2007. Mr. Melton joined A.G. Edwards in July 2000 and was a senior member of the energy corporate finance team. From November 1995 until July 2000, Mr. Melton served as Director of Finance & Corporate Planning with TransMontaigne Inc., a downstream refined products supply, transportation and logistics company. Mr. Melton has served on the Board of Directors of San Antonio, TX based exploration and production company Abraxas Petroleum Corporation (Nasdaq: AXAS) since October of 2009. Mr. Melton received a Bachelor of Science degree in Management and a Master of Business Administration degree from Arkansas State University.

 

We believe that Mr. Melton’s operational and business experience (particularly in the U.S. shale plays in which the Company operates), as well as Mr. Melton’s prior oil and gas investment banking experience help him bring unique insight to our Board and that his financial experience is beneficial to our audit committee.

 

Angela A. Steffen Meyer, a director of Abraxas since May 2019, currently serves as a Corporate Vice President of Exponent, Inc. (NASDAQ: “EXPO”, or “Exponent”), a science and engineering consulting firm. From June 2018 to October 2019, Dr. Meyer was President and CEO of the Product Liability Advisory Council, a specialized legal association of more than 80 multinational corporations and 350 outside defense counsel. From 1990 through May 2018, Dr. Meyer worked at Exponent (formerly Failure Analysis Associates) in a variety of engineering and corporate roles and served as Vice President, Client Services (2002-2018) where she was the chief business development, marketing and client relations officer. She served on the firm’s operating and development committees. Dr. Meyer also serves on the External Advisory Board of Summit Consulting, LLC (August 2018-present) and the External Advisory Board of SMU Lyle School of Engineering (2006 – present). Dr. Meyer received a BS in Mechanical Engineering, a MS in Mechanical Engineering, and a PhD in Mechanical Engineering, from Southern Methodist University. She is a registered professional mechanical engineer in the State of California.

 

Committees of the Board of Directors

 

Abraxas has standing Audit, Compensation and Nominating and Corporate Governance Committees.

 

The Audit Committee is a separately-designated standing audit committee established in accordance with Section 3(a)(58)(A) of the Exchange Act. During 2020, the Audit Committee consisted of Messrs. Melton (Chairman), Cox and Dr. Meyer. The Board of Directors has determined that Mr. Melton is an audit committee financial expert as defined by SEC rules. The Audit Committee Report, which appears on page 31, more fully describes the activities and responsibilities of the Audit Committee. Steven P. Harris, the Company’s Chief Financial Officer, Mr. Krog and representatives from ADKF, PC, the Company’s independent registered public accounting firm, along with all four members of the Company’s Audit Committee attended each meeting of the Audit Committee. In addition, the representatives from ADKF, PC and the Audit Committee met in executive session at each meeting.

 

The Compensation Committee consist of Messrs. Cox (Chairman), Melton and Dr. Meyer. The Compensation Committee’s role is to establish and oversee Abraxas’ compensation and benefit plans and policies, to administer its stock option plans, and to annually review and approve all compensation decisions relating to Abraxas’ executive officers. The Compensation Discussion & Analysis, as set forth in Item 11, more fully describes the activities and responsibilities of the Compensation Committee. The Compensation Committee submits its decisions regarding executive compensation to the independent members of the Board for approval. The agenda for meetings of the Compensation Committee is determined by its Chairman and the meetings are regularly attended by Mr. Watson. At each meeting, the Compensation Committee also meets in executive session. Mr. Cox reports the committee’s recommendations on executive compensation to the Board. The Company’s personnel support the Compensation Committee in its duties and, along with Mr. Watson, may be delegated authority to fulfill certain administrative duties regarding the Company’s compensation programs. The Compensation Committee has authority under its charter to retain, approve fees for and terminate advisors, consultants and agents as it deems necessary to assist in the fulfillment of its responsibilities. In May 2017, the Compensation Committee engaged Longnecker and Associates, which we refer to as “L&A” or the “Compensation Consultant”, as its independent compensation consultant. The Committee did not engage any outside compensation consultants in 2019 and 2020. For more information on the Compensation Committee’s processes and procedures, please see “Executive Compensation – Compensation Discussion & Analysis – Our Compensation Committee” and – “Elements of Executive Compensation.”

 

The Nominating Committee consist of Dr. Meyer (Chairman), and Messrs. Cox and Melton. The primary function of the Nominating and Corporate Governance Committee is to develop and maintain the corporate governance policies of Abraxas and to assist the Board in identifying, screening and recruiting qualified individuals to become Board members and determining the composition of the Board and its committees, including recommending nominees for the election at the annual meeting of stockholders or to fill vacancies on the Board.

 

Each of the Board’s committees has a written charter and copies of the charters are available for review on the Company’s website at www.abraxaspetroleum.com.

 

Audit Committee and Audit Committee Financial Expert

 

The Audit Committee of our board of directors consists of Brian L. Melton (Chairman), Ralph R. Cox and Angela Meyer. The board of directors has determined that each of the members of the Audit Committee is independent as determined in accordance with the listing standards of The NASDAQ Stock Market and Item 407(a) of Regulation S-K. In addition, the board of directors has determined that Brian L. Melton, as defined by SEC rules, is an audit committee financial expert.

 

Code of Ethics

 

In April 2004, the Board of Directors unanimously approved Abraxas’ Code of Ethics. This Code is a statement of Abraxas’ high standards for ethical behavior, legal compliance and financial disclosure, and is applicable to all directors, officers, and employees. Abraxas’ Code of Ethics is periodically reviewed by the Board of Directors and was last updated in 2018. A copy of the Code of Ethics can be found in its entirety on Abraxas’ website at www.abraxaspetroleum.com. Additionally, should there be any changes to, or waivers from, Abraxas’ Code of Ethics, those changes or waivers will be posted immediately on our website at the address noted above.

 

Executive Officers

 

The following table sets forth the names, ages and positions of the executive officers of Abraxas.

 

 

Name and Municipality of Residence

Age 

Office

Robert L.G. Watson.........................................................................

San Antonio, Texas

70

Chairman of the Board, President and Chief Executive Officer

     

Steven P. Harris................................................................................

San Antonio, Texas

47

Vice President – Chief Financial Officer

     

Peter A. Bommer..............................................................................

San Antonio, Texas

64

Vice President – Engineering

     

Tod A. Clarke....................................................................................

San Antonio, Texas

61

Vice President – Land

     

G. William Krog, Jr.........................................................................

San Antonio, Texas

67

Vice President – Chief Accounting Officer

     

Kenneth W. Johnson........................................................................

San Antonio, Texas

63

Vice President – Operations

     

 

 

Robert L.G. Watson has served as Chairman of the Board, President, Chief Executive Officer and a director of Abraxas since 1977. See page 57 for more information.

 

 

Steven P. Harris has served as Vice President – Chief Financial Officer since November 2018. Mr. Harris joined Abraxas in June 2018 as Director, Finance and Capital Markets. Prior to joining Abraxas, from June 2017 to May 2018, Mr. Harris was with Sundance Energy where he assisted Sundance’s Business Development and Investor Relations efforts. From 2008 through 2017, Mr. Harris was a Managing Director and headed the U.S. Energy Investment Banking division of Canaccord Genuity in Houston, Texas. Prior to joining Canaccord Genuity, Mr. Harris served in the Business Development Group at El Paso Exploration and Production. Mr. Harris earned his Bachelor of Business Administration from the University of Texas at Austin and a Master of Business Administration from the Rice University Jesse H. Jones Graduate School of Management.

 

 Peter A. Bommer has served as Vice President – Engineering since 2012 and as Manager of Special Projects since 2007. Prior to joining Abraxas, Mr. Bommer owned and ran the day-to-day operations of Bommer Engineering, a privately held engineering firm, for over 25 years. Mr. Bommer received a Bachelor of Science in Petroleum Engineering degree from the University of Texas in 1978 and a Master of Theology degree from Dallas Theological Seminary in 1999. Mr. Bommer also holds the Professional Engineer designation.

 

Tod A. Clarke has served as Vice President – Land since August 2017. Mr. Clarke joined Abraxas in 2000 as Land Manager. Prior to joining Abraxas, Mr. Clarke worked at Exxon USA for 15 years. Mr. Clarke received a Bachelor of Science – Land Management degree from the University of Houston in 1984. Mr. Clarke also is a Certified Petroleum Landman.

 

Kenneth W. Johnson has served as Vice President – Operations since September 2018. Mr. Johnson joined Abraxas in 2000 and most recently served as Regional Operations Manager. Prior to joining Abraxas, Mr. Johnson served as a consultant to various operators in supervisory and operations management roles across the US including the Mid-Continent, Rockies, and Gulf Coast regions.

 

G. William Krog, Jr. has served as Chief Accounting Officer since 2011 and Vice President – Chief Accounting Officer since November 2017. Mr. Krog joined Abraxas in 1995 and most previously served as Information Systems / Financial Reporting Director prior to being appointed Chief Accounting Officer. Prior to joining Abraxas, Mr. Krog was an independent accountant in private practice. Mr. Krog received a Bachelor of Business Administration degree from the University of Texas at Austin in 1976 and is a Certified Public Accountant.

51

 

 

Delinquent Section 16(a) Reports

 

Section 16(a) of the Exchange Act requires our directors and executive officers and persons who own more than 10% of a registered class of Abraxas equity securities to file with the SEC and The NASDAQ initial reports of ownership and reports of changes in ownership of Abraxas common stock. Officers, directors and greater than 10% stockholders are required by SEC regulations to furnish us with copies of all such forms they file. Based solely on a review of the copies of such reports furnished to us and written representations that no other reports were required, we believe that all our directors and executive officers complied on a timely basis with all applicable filing requirements under Section 16(a) of the Exchange Act during 2020.

 

Item 11. Executive Compensation

 

Compensation Discussion & Analysis

 

We compensate our executive officers through a combination of base salary, annual incentive bonuses and long-term equity based awards. The compensation is designed to be competitive with those of a peer group, which in 2019 was a group of exploration and production companies originally provided by Longnecker & Associates, or L&A or the Compensation Consultant, in 2014 and subsequently updated by the Compensation Committee due to bankruptcies and other corporate events.

 

This section discusses the principles underlying our executive compensation policies and decisions, and the most important factors relevant to an analysis of these policies and decisions. It provides qualitative information regarding the manner and context in which compensation is awarded to and earned by our executive officers and places in perspective the data presented in the tables and narrative that follow.

 

Our Compensation Committee

 

Our Compensation Committee approves, implements and monitors all compensation and awards to executive officers including the Chief Executive Officer, the Chief Financial Officer and the other executive officers named in the Summary Compensation Table below, whom we refer to as the named executive officers or NEOs. The Committee’s membership is determined by the Board of Directors and is composed of three independent directors. The Committee, in its sole discretion, has the authority to delegate any of its responsibilities to subcommittees as it deems appropriate. During 2017, the Compensation Committee engaged L&A to assist in providing a comprehensive assessment of our executive compensation programs. The Compensation Committee retains the sole authority to select, retain, terminate, and approve fees and other retention terms of the relationship with L&A.

 

During 2017, the Compensation Consultant performed the following services for the Committee: