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Table of Contents



UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-Q

 

(Mark One)

 

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED September 30, 2021

 

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

  

COMMISSION FILE NUMBER: 001-16071

  

ABRAXAS PETROLEUM CORPORATION

(Exact name of registrant as specified in its charter)

 

Nevada

 

74-2584033

(State of Incorporation)

 

(I.R.S. Employer Identification No.)

 

18803 Meisner Drive, San Antonio, TX 78258

(Address of principal executive offices) (Zip Code)

 

210-490-4788

(Registrant’s telephone number, including area code)

 

Not Applicable

(Former name, former address and former fiscal year, if changed since last report)

 

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

OTCQX

 

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 the filing requirements for the past 90 days.    Yes ☒  No ☐

 

Indicate by check mark whether 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 whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth 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 Sec 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 ☒

 

The number of shares of the issuer’s common stock outstanding as of  November 12, 2021 was 8,421,910.

 

 
 

The terms “Abraxas,” “Abraxas Petroleum,” “we,” “us,” “our” or the “Company” refer to Abraxas Petroleum Corporation and all of its subsidiaries, including Raven Drilling, LLC.

 

All share and per share data has been retroactively adjusted to reflect the 1-for-20 reverse stock split effective October 19, 2020, as described in Note 2 to our consolidated financial statements.

 

Forward-Looking Information

 

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 “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 facility;

 

 

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 bank credit facility 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 natural 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 become available. Peak production rates are not necessarily indicative or predictive of future production rates, expected ultimate recovery (EUR), or economic rates of return from such wells and should not be relied upon for such purpose. 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, condensate or natural gas liquids.

 

The following definitions 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.

 

Boed or Boepd” – barrels of oil equivalent 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 and 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 a working 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 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 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. 

 

 

 

ABRAXAS PETROLEUM CORPORATION

FORM 10 – Q

INDEX

 

 

PART I

 

 

 

 

ITEM 1 -

Financial Statements

 

 

Condensed Consolidated Balance Sheets - September 30, 2021 (unaudited) and December 31, 2020

6

 

Condensed Consolidated Statements of Operations – (unaudited) Three and Nine Months Ended September 30, 2021 and 2020

8

  Condensed Consolidated Statements of Stockholders' Equity (unaudited) Three and Nine Months Ended September 30, 2021 and 2020

9

 

Condensed Consolidated Statements of Cash Flows – (unaudited) Nine Months Ended September 30, 2021 and 2020

10

 

Notes to Condensed Consolidated Financial Statements - (unaudited)

11

 

 

 

ITEM 2 -

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

27

 

 

 

ITEM 3 -

Quantitative and Qualitative Disclosures about Market Risk

41

 

 

 

ITEM 4 -

Controls and Procedures

41

 

 

 

 

PART II

OTHER INFORMATION

 

ITEM 1 -

Legal Proceedings

42

ITEM 1A -

Risk Factors

42

ITEM 2 -

Unregistered Sales of Equity Securities and Use of Proceeds

42

ITEM 3 -

Defaults Upon Senior Securities

42

ITEM 4 -

Mine Safety Disclosure

42

ITEM 5 -

Other Information

42

ITEM 6 -

Exhibits

42

 

Signatures

43

 

 

 

Part I

FINANCIAL STATEMENTS

 

Item 1. Financial Statements

 

ABRAXAS PETROLEUM CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(in thousands)

 

   

September 30,

   

December 31,

 
   

2021

   

2020

 
   

(Unaudited)

         

Assets

               

Current assets:

               

Cash and cash equivalents

  $ 9,051     $ 2,775  

Accounts receivable:

               

Joint owners, net

    1,250       1,255  

Oil and gas production sales

    13,272       8,794  

Other

    293       -  

Total accounts receivable

    14,815       10,049  
                 

Derivative asset - short-term

    -       9,639  

Other current assets

    993       1,588  

Total current assets

    24,859       24,051  
                 

Property and equipment:

               

Proved oil and gas properties, full cost method

    1,165,232       1,167,333  

Other property and equipment

    39,257       39,456  

Total

    1,204,489       1,206,789  

Less accumulated depreciation, depletion, amortization and impairment

    (1,095,459 )     (1,083,843 )

Total property and equipment, net

    109,030       122,946  
                 

Operating lease right-of-use assets

    184       228  

Derivative asset - long-term

    -       10,281  

Other assets

    255       255  

Total assets

  $ 134,328     $ 157,761  

 

All share and per share data has been retroactively adjusted to reflect the 1-for-20 reverse stock split effective October 19, 2020, as described in Note 2 to our condensed consolidated financial statements. 

 

See accompanying notes to condensed consolidated financial statements (unaudited).

 

 

ABRAXAS PETROLEUM CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS (CONTINUED)

(in thousands, except share and per share data)

 

   

September 30,

   

December 31,

 
   

2021

   

2020

 
   

(Unaudited)

         

Liabilities and Stockholders' Equity

               

Current liabilities:

               

Accounts payable

  $ 2,061     $ 6,074  

Joint interest oil and gas production payable

    12,835       8,795  

Accrued interest

    511       86  

Accrued expenses

    892       230  

Right of use liability

    41       53  

Derivative liabilities - short-term

    2,017       480  

Termination of derivative contracts

    9,178        

Current maturities of long-term debt

    209,434       202,751  

Other current liabilities

    -       850  

Total current liabilities

    236,969       219,319  
                 

Long-term debt – less current maturities

    2,284       2,515  

Operating lease right-of-use liabilities

    118       150  

Paycheck protection program loan

    1,336       1,384  

Future site restoration

    4,748       7,360  

Total liabilities

    245,455       230,728  
                 

Commitments and contingencies (Note 11)

                 
                 

Stockholders’ Equity:

               

Preferred stock, par value $0.01 per share – authorized 1,000,000 shares; -0- shares issued and outstanding

           

Common stock, par value $0.01 per share, authorized 20,000,000 shares; 8,421,910 issued and outstanding at September 30, 2021 and December 31, 2020

    84       84  

Additional paid-in capital

    430,256       429,476  

Accumulated deficit

    (541,467 )     (502,527 )

Total stockholders' deficit

    (111,127 )     (72,967 )

Total liabilities and stockholders’ deficit

  $ 134,328     $ 157,761  

 

See accompanying notes to condensed consolidated financial statements (unaudited).

 

 

 

ABRAXAS PETROLEUM CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(in thousands except per share data)

 

   

Three Months Ended September 30,

   

Nine Months Ended September 30,

 
   

2021

   

2020

   

2021

   

2020

 

Revenues:

                               

Oil and gas production revenues

                               

Oil

  $ 15,506     $ 12,466     $ 45,199     $ 29,971  

Gas

    2,415       75       5,344       183  

Natural gas liquids

    2,933       52       5,416       152  

Other

    11       2       19       8  

Total revenue

    20,865       12,595       55,978       30,314  

Operating costs and expenses:

                               

Lease operating

    4,612       3,935       13,059       12,280  

Production and ad valorem taxes

    1,551       1,520       4,624       3,613  

Rig expense

    119       130       363       669  

Depreciation, depletion, amortization and accretion

    3,812       7,019       11,951       19,053  

Proved property impairment

          54,552             136,109  

General and administrative (including stock-based compensation of $273, $348, $780, and $947, respectively)

    1,942       2,100       6,253       6,506  

Total operating cost and expenses

    12,036       69,256       36,250       178,230  

Operating income (loss)

    8,829       (56,661 )     19,728       (147,916 )
                                 

Other (income) expense:

                               

Interest income

    (4 )     (6 )     (13 )     (24 )

Interest expense

    8,057       5,676       21,742       15,569  

Gain on sale of non-oil and gas assets

                (29 )      

Amortization of deferred financing fees

    1,201       546       3,603       1,067  

Financing expense

    568             1,852        

Debt forgiveness

                (1,384 )      

Loss on debt extinguishment

          4,108             4,108  

Loss (gain) on derivative contracts

    252       6,630       32,897       (53,208 )

Total other expense (income)

    10,074       16,954       58,668       (32,488 )

(Loss) before income tax

    (1,245 )     (73,615 )     (38,940 )     (115,428 )

Income tax (expense) benefit

                       

Net (loss)

  $ (1,245 )   $ (73,615 )   $ (38,940 )   $ (115,428 )
                                 

Net (loss) per common share - basic

  $ (0.15 )   $ (8.80 )   $ (4.63 )   $ (13.80 )

Net (loss) per common share - diluted

  $ (0.15 )   $ (8.80 )   $ (4.63 )   $ (13.80 )
                                 

Weighted average shares outstanding:

                               

Basic

    8,406       8,362       8,406       8,366  

Diluted

    8,406       8,362       8,406       8,366  

 

See accompanying notes to condensed consolidated financial statements (unaudited).

 

 

 

ABRAXAS PETROLEUM CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS EQUITY

(Unaudited)

(in thousands, except share data)

 

                   

Additional

                 
   

Common Stock

   

Paid in

   

Accumulated

         
   

Shares

   

Amount

   

Capital

   

Deficit

   

Total

 

Balance at December 31, 2020

    8,421,910     $ 84     $ 429,476     $ (502,527 )   $ (72,967 )

Net loss

    -       -       -       (38,940 )     (38,940 )

Stock-based compensation

    -       -       780       -       780  

Balance at September 30, 2021

    8,421,910     $ 84     $ 430,256     $ (541,467 )   $ (111,127 )

 

                   

Additional

                 
   

Common Stock

   

Paid in

   

Accumulated

         
   

Shares

   

Amount

   

Capital

   

Deficit

   

Total

 

Balance at December 31, 2019

    8,418,053     $ 84     $ 421,740     $ (318,005 )   $ 103,819  

Net loss

    -       -       -       (115,428 )     (115,428 )

Stock-based compensation

    -       -       947       -       947  

Issuance of warrant

    -       -       6,424       -       6,424  

Restricted stock issued, net of forfeitures

    (14,588 )     -       -       -       -  

Balance at September 30, 2020

    8,403,465     $ 84     $ 429,111     $ (433,433 )   $ (4,238 )

 

                   

Additional

                 
   

Common Stock

   

Paid in

   

Accumulated

         
   

Shares

   

Amount

   

Capital

   

Deficit

   

Total

 

Balance at June 30, 2021

    8,421,910     $ 84     $ 429,983     $ (540,222 )   $ (110,155 )

Net loss

    -       -       -       (1,245 )     (1,245 )

Stock-based compensation

    -       -       273       -       273  

Balance at September 30, 2021

    8,421,910     $ 84     $ 430,256     $ (541,467 )   $ (111,127 )

 

                   

Additional

                 
   

Common Stock

   

Paid in

   

Accumulated

         
   

Shares

   

Amount

   

Capital

   

Deficit

   

Total

 

Balance at June 30, 2020

    8,403,465     $ 84     $ 422,339     $ (359,818 )   $ 62,605  

Net loss

    -       -       -       (73,615 )     (73,615 )

Issuance of warrant

    -       -       6,424       -       6,424  

Stock-based compensation

    -       -       348       -       348  

Balance at September 30, 2020

    8,403,465     $ 84     $ 429,111     $ (433,433 )   $ (4,238 )

 

See accompanying notes to condensed consolidated financial statements (unaudited).

 

 

 

ABRAXAS PETROLEUM CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(in thousands)

 

   

Nine Months Ended September 30,

 
   

2021

   

2020

 

Operating Activities

               

Net loss

  $ (38,940 )   $ (115,428 )

Adjustments to reconcile net loss to net cash provided by operating activities:

               

Net loss (gain) on derivative contracts

    32,897       (53,208 )

Net cash settlements paid on derivative contracts

    (1,497 )     12,400  

Gain on sale of non-oil and gas properties

    (29 )      

Depreciation, depletion, amortization and accretion of future site restoration

    11,951       19,053  

Proved property impairment

          136,109  

Amortization of deferred financing fees and issuance discount

    5,734       2,226  

Stock-based compensation

    780       947  

Settlements of asset retirement obligations

    336       310  

Debt forgiveness PPP loan

    (1,384 )      

Loss on debt extinguishment

          4,108  

Non-cash interest expense

    14,406       8,323  

Non-cash hedge contract termination

    9,943        

Changes in operating assets and liabilities:

               

Accounts receivable

    (4,766 )     12,158  

Other assets

    (10,186 )     1,459  

Accounts payable and accrued expenses

    631       (17,723 )

Net cash provided by operating activities

    19,876       10,734  
                 

Investing Activities

               

Capital expenditures, including purchases and development of properties

    (856 )     (13,187 )

Proceeds from the sale of oil and gas properties

    117        

Proceeds from the sale of non-oil and gas properties

    256        

Net cash used in investing activities

    (483 )     (13,187 )
                 

Financing Activities

               

Proceeds from long-term borrowings

          8,000  

Proceeds from PPP loan

    1,336        

Payments on long-term borrowings

    (14,296 )     (3,987 )

Deferred financing fees

    (157 )     (977 )

Net cash (used in) provided by financing activities

    (13,117 )     3,036  
                 

Increase in cash and cash equivalents

    6,276       583  

Cash and cash equivalents at beginning of period

    2,775        

Cash and cash equivalents at end of period

  $ 9,051     $ 583  
                 

Supplemental disclosures of cash flow information:

               

Interest paid

  $ 4,667     $ 6,085  
                 

Non-cash investing and financing activities:

               

Non-cash interest paid in kind

  $ 14,406     $ 8,323  

Change in capital expenditures included in accounts payable

  $ 28     $ (6,619 )

Change in future site restoration on properties sold

  $ 2,704     $ -  

Forgiveness of PPP loan

  $ 1,384     $ -  
                 

 

See accompanying notes to condensed consolidated financial statements (unaudited).

 

 

ABRAXAS PETROLEUM CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(tabular amounts in thousands, except per share data)

 

 

1. Basis of Presentation

 

The accounting policies we follow as of January 1, 2021 are set forth in the notes to our audited consolidated financial statements in the Annual Report on Form 10-K for the year ended  December 31, 2020 filed with the SEC on May 6, 2021.  The accompanying interim condensed consolidated financial statements have not been audited by our independent registered public accountants. In the opinion of management, these statements reflect all adjustments necessary for a fair presentation of the financial position and results of operations. Any and all adjustments are of a normal and recurring nature. Although management believes the unaudited interim related disclosures in these condensed consolidated financial statements are adequate to make the information presented not misleading, certain information and footnote disclosures normally included in annual audited consolidated financial statements prepared in accordance with accounting principles generally accepted in the United States of America  (“GAAP”)  have been condensed or omitted pursuant to the rules and regulations of the SEC. The results of operations for the three and nine month periods ended September 30, 2021  and the statement of cash flows for the nine months ended September 30, 2021, are not necessarily indicative of the results to be expected for the full year. The condensed consolidated financial statements included herein should be read in conjunction with the consolidated audited financial statements and the notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2020.

 

COVID-19

 

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 decreased as a direct result of travel restrictions placed by governments in an effort to curtail the spread of COVID-19 and its variant strains. 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 decreased, which affected our liquidity. Since that time, demand and the price of oil and gas have increased, but uncertainty related to the pandemic caused by COVID-19 and its variant strains persists.  

 

In early March 2020, global oil and natural gas prices declined sharply, rising in recent months, but  may decline again.  The full impact of COVID-19 and its variant strains continues to evolve as of the date of this report. As such, it is uncertain as to the full magnitude they 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 took action to reduce general and administrative costs, as well as  shut in production in mid- March 2020.  Subsequently, however the Company started restoring production in mid- June 2020, and a majority of such wells were back on production in early September 2020. We have also suspended our capital expenditures indefinitely. 

 

Going Concern

 

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   September 30, 2021, we had a total of  $81.7  million outstanding under our First Lien Credit Facility, $137.1 million under our Second Lien Credit Facility, including a  $10.0 million exit fee, and total indebtedness of  $221.4  million. Additionally, we have a liability of approximately $9.2 million related to the termination of our hedging agreements. 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,  it was anticipated that we would not maintain compliance with the Second Lien Credit Facility total leverage ratio covenant or the minimum asset coverage ratio (as defined in Note 5) both of which were to be  first tested as of September 30, 2021, for the required twelve month period and, accordingly, the audit report prepared by our auditors with respect to the financial statements in our Form 10-K for the year ended December 31, 2020 included 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 represents 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.

 

The existing defaults at March 31, 2021 were subject to forbearance agreements with our lenders that expired on  May 6, 2021. 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”.

 

The Company has continued its previously announced investigation of strategic alternatives and is in discussions with its creditors in an effort to restructure its balance sheet. Any negotiated transaction with its lenders would likely include a sale of a significant block of assets, the proceeds from which would be applied to reduce debt, the exchange of a significant amount of equity interests in the Company for outstanding indebtedness, and/or other possible negotiated transactions, which in the aggregate could eliminate or substantially reduce the outstanding indebtedness under  its First Lien Credit facility and Second Lien Credit Facility and result in significant dilution of existing stockholder interests and reduction or potentially elimination of value for existing stockholders.  Any such transaction could involve a proceeding under the U.S. Bankruptcy Code.  No assurance can be provided that any such potential transactions can be successfully concluded, in which event the Company’s lenders could commence foreclosure proceedings seeking to liquidate Company assets to repay the outstanding indebtedness.  In any such foreclosure proceedings, it is unlikely that stockholders would recover more than a de minimis amount for their stock, and the stock could become worthless.

11

 

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 $9.2 million. These obligations were added to the outstanding balance under our First Lien Credit Facility and will accrue interest at the default interest rate, currently 8.75%,  until repaid. Our remaining  hedging agreement  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 10 “Events of Default” for current information regarding non-compliance with certain covenants.

 

Consolidation Principles

 

The terms “Abraxas,” “Abraxas Petroleum,” “we,” “us,” “our” or the “Company” refer to Abraxas Petroleum Corporation and all of its subsidiaries, including Raven Drilling, LLC (“Raven Drilling”).

 

Rig Accounting

 

In accordance with SEC Regulation S-X, no income is recognized in connection with contractual drilling services performed in connection with properties in which we or our affiliates hold an ownership, or other economic interest. Any income not recognized as a result of this limitation is credited to the full cost pool and recognized through lower amortization as reserves are produced.

 

Use of Estimates

 

The preparation of financial statements in conformity with US GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the financial statements and reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

 

Stock-Based Compensation, Option Plans and Warrants

 

Stock Options

 

We currently utilize a standard option-pricing model (i.e., Black-Scholes) to measure the fair value of stock options granted to employees and directors.

 

 

The following table summarizes our stock option activity for the nine months ended September 30, 2021, (in thousands):

 

    Number of Shares     Weighted Average Option Exercise Price Per Share     Weighted Average Grant Date Fair Value Per Share  

Outstanding, December 31, 2020

    196     $ 49.69     $ 35.03  

Cancelled/Forfeited

    (125 )   $ 43.38     $ 30.90  

Expired

    (17 )   $ 82.91     $ 62.02  

Balance, September 30, 2021

    54     $ 53.79     $ 36.81  

    

 

 

 

Restricted Stock Awards

 

Restricted stock awards are awards of common stock that are subject to restrictions on transfer and to a risk of forfeiture if the recipient of the award terminates employment with us prior to the lapse of the restrictions. The fair value of such stock was determined using the closing price on the grant date and compensation expense is recorded over the applicable vesting periods.

 

The following table summarizes our restricted stock activity for the nine months ended September 30, 2021

 

   

Number of Shares (thousands)

   

Weighted Average Grant Date Fair Value Per Share

 

Unvested, December 31, 2020

    41     $ 31.37  

Vested/Released

    (24 )     33.23  

Cancelled/Forfeited

    (1 )     26.80  

Unvested, September 30, 2021

    16     $ 26.80  

 

Performance Based Restricted Stock

 

We issue performance-based shares of restricted stock to certain officers and employees under the Abraxas Petroleum Corporation Amended and Restated 2005 Employee Long-Term Equity Incentive Plan. The shares will vest in three years from the grant date upon the achievement of performance goals based on our Total Shareholder Return (“TSR”) as compared to a peer group of companies. The number of shares which would vest depends upon the rank of our TSR as compared to the peer group at the end of the three-year vesting period and can range from zero percent of the initial grant up to 200% of the initial grant.

 

The table below provides a summary of Performance Based Restricted Stock as of the date indicated:

 

   

Number of Shares (thousands)

   

Weighted Average Grant Date Fair Value Per Share

 

Unvested, December 31, 2020

    44     $ 33.73  

Expired

    (16 )   $ 46.35  

Unvested, September 30, 2021

    28     $ 26.80  

 

Compensation expense associated with the performance based restricted stock is based on the grant date fair value of a single share as determined using a Monte Carlo Simulation model which utilizes a stochastic process to create a range of potential future outcomes given a variety of inputs. As the Compensation Committee intends to settle the performance based restricted stock awards with shares of our common stock, the awards are accounted for as equity awards and the expense is calculated on the grant date assuming a 100% target payout and amortized over the life of the awards.

 

The following table summarizes stock-based compensation from the various forms of compensation utilized by the Company (in thousands).

 

 

   

Three Months Ended

   

Nine Months Ended

 
   

September 30,

   

September 30,

 
   

2021

   

2020

   

2021

   

2020

 

Options

  $ 1     $ 11     $ (22 )   $ 73  

Restricted stock

    211       203       527       675  

Performance shares

    61       134       275       403  
    $ 273     $ 348     $ 780     $ 1,151  
                                 
                                 

 

 

As of  September 30, 2021, substantially all expense related to stock based compensation has been amortized.  Options are fully amortized while restricted stock and performance shares have approximately $0.2 million and $0.1 million, respectively, that will be amortized over the remainder of 2021 through April 2022.

 

 

Warrants for Common Stock

 

As of September 30, 2021, outstanding warrants to purchase shares of common stock were as follows:

 

Issuance Date

Exercisable for

Expiration Date

 

Exercise Price

   

Number of Shares

 
                     

August 11, 2020

Common Stock

August 11, 2025

  $ 0.20       1,672,290  

 

In connection with the amended Second Lien Credit Agreement, on August 11, 2020, 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. As a result of the  October 19, 2020 reverse stock split of the Company’s  authorized, issued and outstanding shares of common stock at a ratio of 1-for-20, 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, at any time on or before five years from the issuance date. The fair value of the warrant was recorded as debt issuance costs, presented in the consolidated balance sheets as a deduction from the carrying amount of the note payable, and is being amortized over the loan term. 

 

Oil and Gas Properties

 

We follow the full cost method of accounting for oil and gas properties.  Under this method, all direct costs and certain indirect costs associated with the acquisition of properties and successful and unsuccessful exploration and development activities are capitalized. Depreciation, depletion, and amortization of capitalized oil and gas properties and estimated future development costs, excluding unproved properties, are based on the unit-of-production method based on proved reserves.  Net capitalized costs of oil and gas properties, less related deferred taxes, are limited by country, to the lower of unamortized cost or the cost ceiling, defined as the sum of the present value of estimated future net revenues from proved reserves based on unescalated prices 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. Costs in excess of the present value of estimated net revenue from proved reserves discounted at 10% are charged to proved property impairment expense.  No gain or loss is recognized upon sale or disposition of oil and gas properties for full cost accounting companies with proceeds accounted for as an adjustment of capitalized cost. An exception to this rule occurs when the adjustment to the full cost pool results in a significant alteration of the relationship between capitalized cost and proved reserves. We apply the full cost ceiling test on a quarterly basis on the date of the latest balance sheet presented.  At September 30, 2020, the net capital cost of oil and gas properties exceeded the cost ceiling of our estimated proved reserves  resulting in an impairment of $54.6 million and $136.1  million for the three and nine months ended September 30, 2020, respectively.  At September 30, 2021, the net capitalized costs of oil and gas properties did not exceed the cost ceiling of our estimated proved reserves.

 

Restoration, Removal and Environmental Liabilities

 

We are subject to extensive federal, state and local environmental laws and regulations. These laws regulate the discharge of materials into the environment and may require us to remove or mitigate the environmental effects of the disposal or release of petroleum substances at various sites.  Environmental expenditures are expensed or capitalized depending on their future economic benefit.  Expenditures that relate to an existing condition caused by past operations and that have no future economic benefit are expensed.

 

Liabilities for expenditures of a non-capital nature are recorded when environmental assessments and/or remediation is probable, and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments for the liability or component is fixed or reliably determinable.

 

We account for future site restoration obligations based on the guidance of ASC 410 which addresses accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. ASC 410 requires that the fair value of a liability for an asset’s retirement obligation be recorded in the period in which it is incurred and the corresponding cost 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 estimated 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 amortize these costs as a component of our depletion expense in the accompanying condensed consolidated financial statements.

 

The following table summarizes our future site restoration obligation transactions for the nine months ended September 30, 2021 and the year ended December 31, 2020 (in thousands):

   

September 30, 2021

   

December 31, 2020

 

Beginning future site restoration obligation

  $ 7,360     $ 7,420  

New wells placed on production and other

    1       43  

Deletions related to property sales

    (2,845 )     (216 )

Deletions related to plugging costs

    (336 )     (235 )

Accretion expense

    255       414  

Revisions and other

    313       (66 )

Ending future site restoration obligation

  $ 4,748     $ 7,360  

 

 

In April 2021, the Company divested various non-Bakken properties in North Dakota and Montana, primarily for plugging liability. The result of the transaction was a decrease of approximately $2.7 million in future site development liability, with a corresponding reduction in the full cost pool.

 

 

Recently Adopted 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.

 

Recently Issued Accounting Standards

 

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.

 

 

2. Reverse Stock Split

 

On  October 19, 2020, the Company effected a 1-for-20 reverse stock split of its issued and outstanding shares of common stock, $0.01 par value. The Company effected the reverse stock split pursuant to the Company’s filing of a Certificate of Change  with the Secretary of State of the State of Nevada on September 29, 2020. Under Nevada law, no amendment to the Company’s  Articles of Incorporation was required in connection with the reverse stock split. The Company was authorized to issue 400,000,000 shares of common stock. As a result of the reverse stock split, the Company is authorized to issue 20,000,000 shares of common stock.  As a result of the reverse split, 168,069,305 outstanding shares of the Company’s  common stock were exchanged for approximately 8,421,910 shares of the Company’s  common stock (subject to adjustment due to the effect of rounding fractional shares into whole shares). The reverse stock split did not have any effect on the stated par value of the common stock.   All per share amounts and number of shares in the condensed consolidated financial statements and related notes have been retroactively restated to reflect the reverse stock split.

 

Additionally on October 19, 2020, all options, warrants and other convertible securities of the Company outstanding immediately prior to the reverse stock split were adjusted by dividing by 20 the number of shares of common stock into which the options, warrants and other convertible securities are exercisable or convertible, and multiplying the exercise or conversion price thereof by 20, all in accordance with the terms of the plans, agreements or arrangements governing such options, warrants and other convertible securities and subject to rounding to the nearest whole share.

 

The common stock began trading on a split-adjusted basis on the NASDAQ at the market open on October 19, 2020. The trading symbol for the common stock remains “AXAS”. On July 26, 2021, the Company received a notice from the Nasdaq Stock Market LLC that the Company's common stock would be suspended. The Company's securities were subsequently suspended from trading on NASDAQ on August 4, 2021 and removed from listing and registration on  September 17, 2021, and are currently listed on the OTCQX market place.

 

 

3. Revenue from Contracts with Customers

 

Revenue Recognition

 

Sales of oil, gas and natural gas liquids (“NGL”) are recognized at the point in time when control of the product is transferred to the customer and collectability is reasonably assured. Our contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, physical location, quality of the oil or gas, and prevailing supply and demand conditions. As a result, the price of the oil, gas and NGL fluctuates to remain competitive with other available oil, gas and NGL supplies in the market. We believe that the pricing provisions of our oil, gas and NGL contracts are customary in the industry.

 

Oil sales

 

Our oil sales contracts are generally structured such that we sell our oil production to a purchaser at a contractually specified delivery point at or near the wellhead. The crude oil production is priced on the delivery date based upon prevailing index prices less certain deductions related to oil quality, physical location and transportation costs incurred by the purchaser subsequent to delivery. We recognize revenue when control transfers to the purchaser upon delivery at or near the wellhead at the net price received from the purchaser.

 

Gas and NGL Sales

 

Under our gas processing contracts, we deliver wet gas to a midstream processing entity at the wellhead or the inlet of the midstream processing entity’s system. The midstream processing entity processes the natural gas and remits proceeds to us based upon either (i) the resulting sales price of NGL and residue gas received by the midstream processing entity from third party customers, or (ii) the prevailing index prices for NGL and residue gas in the month of delivery to the midstream processing entity. Gathering, processing, transportation and other expenses incurred by the midstream processing entity are typically deducted from the proceeds that we receive.

 

In these scenarios, we evaluate whether the midstream processing entity is the principal or the agent in the transaction. In our gas purchase contracts, we have concluded that the midstream processing entity is the agent, and thus, the midstream processing entity is our customer. Accordingly, we recognize revenue upon delivery to the midstream processing entity based on the net amount of the proceeds received from the midstream processing entity.

 

 

Disaggregation of Revenue

 

We are focused on the development of oil and natural gas properties primarily located in the following two operating regions in the United States: (i) the Permian/Delaware Basin, and (ii) Rocky Mountain. Revenue attributable to each of those regions is disaggregated in the tables below.

 

   

Three Months Ended September 30,

 
   

2021

   

2020

 
   

Oil

   

Gas

   

NGL

   

Oil

   

Gas

   

NGL

 

Operating Regions:

                                               

Permian/Delaware Basin

  $ 8,341     $ 1,232     $ 724     $ 7,676     $ 77     $ 52  

Rocky Mountain

  $ 7,165     $ 1,183     $ 2,209     $ 4,790     $ (2 )   $ -  

 

   

Nine Months Ended September 30,

 
   

2021

   

2020

 
   

Oil

   

Gas

   

NGL

   

Oil

   

Gas

   

NGL

 

Operating Regions:

                                               

Permian/Delaware Basin

  $ 23,906     $ 3,096     $ 1,412     $ 16,748     $ 111     $ 62  

Rocky Mountain

  $ 21,293     $ 2,248     $ 4,004     $ 13,223     $ 72     $ 90  

 

Significant Judgments

 

Principal versus agent

 

We engage in various types of transactions in which midstream entities process our gas and subsequently market resulting NGL and residue gas to third-party customers on our behalf, such as our percentage-of-proceeds and gas purchase contracts. These types of transactions require judgment to determine whether we are the principal or the agent in the contract and, as a result, whether revenues are recorded gross or net.

 

Transaction price allocated to remaining performance obligations

 

A significant number of our product sales are short-term in nature with a contract term of one year or less. For those contracts, we have utilized the practical expedient in ASC Topic 606-10-50-14 exempting us from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less.

 

For product sales that have a contract term greater than one year, we have utilized the practical expedient in ASC Topic 606-10-50-14(a) which states we are not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally represents a separate performance obligation; therefore, future volumes are wholly unsatisfied, and disclosure of the transaction price allocated to remaining performance obligations is not required.

 

 

Contract balances

 

Under our product sales contracts, we are entitled to payment from purchasers once our performance obligations have been satisfied upon delivery of the product, at which point payment is unconditional. We record invoiced amounts as “Accounts receivable - Oil and gas production sales” in the accompanying condensed consolidated balance sheet.

 

To the extent actual volumes and prices of oil and natural gas are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and prices for those properties are estimated and also recorded as “Accounts receivable - Oil and gas production sales” in the accompanying condensed consolidated balance sheets. In this scenario, payment is also unconditional, as we have satisfied our performance obligations through delivery of the relevant product. As a result, we have concluded that our product sales do not give rise to contract assets or liabilities under ASU 2014-09. At September 30, 2021 and December 31, 2020, our receivables from contracts with customers were $13.3 million and $8.8 million, respectively.

 

Prior-period performance obligations

 

We record revenue in the month production is delivered to the purchaser. However, settlement statements for certain gas and NGL sales may not be received for 30 to 60 days after the date production is delivered, and as a result, we are required to estimate the amount of production that was delivered to the midstream purchaser and the price that will be received for the sale of the product. Additionally, to the extent actual volumes and prices of oil are unavailable for a given reporting period because of timing or information not received from third party purchasers, the expected sales volumes and prices for those barrels of oil are also estimated.

 

We record the differences between our estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. Any identified differences between our revenue estimates and actual revenue received historically have not been significant. For the three and nine months ended September 30, 2021 and 2020, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.

 

 

4.  Income Taxes

 

Deferred tax assets and liabilities are determined based on differences between financial reporting and tax basis of assets and liabilities and are measured using the tax rates and laws expected to be in effect when the differences are expected to reverse.

 

For the three and nine months ended September 30, 2021, and 2020, there was no income tax benefit due to net operating loss carryforwards (“NOLs”) and we recorded a full valuation allowance against our net deferred tax asset. 

 

At December 31, 2020, we had, subject to the limitation discussed below, $245.2 million of pre-2018 NOLs and $137.8 million of post 2018 NOL carryforwards for U.S. tax purposes.  Our pre-2018 NOLs will expire in varying amounts from 2022 through 2037, if not utilized. Any NOLs arising in 2018, 2019, and 2020 can generally be carried back five years, carried forward indefinitely and can offset 100% of taxable income for tax years 2020 and up to 80% of future taxable income for tax years after December 31, 2020. Any NOLs arising on or after January 1, 2021 can generally be carried forward indefinitely and can offset up to 80% of future taxable income. The use of our NOLs will be limited if there is an “ownership change” in our common stock, generally a cumulative ownership change exceeding 50% during a three year period, as determined under Section 382 of the Internal Revenue Code. As of September 30, 2021, we have not had an ownership change as defined by Section 382.

 

Given historical losses, uncertainties exist as to the future utilization of the NOL carryforwards. Therefore, we established a valuation allowance of $117.3 million for deferred tax assets at  December 31, 2020.

 

As of September 30, 2021, we did not have any accrued interest or penalties related to uncertain tax positions. The tax years 2015 through 2020 remain open to examination by the tax jurisdictions to which we are subject.

 

The Coronavirus Aid, Relief, and Economic Security Act  that was enacted March 27, 2020 includes income tax provisions that allow NOLs to be carried back, allow interest expense to be deducted up to a higher percentage of adjusted taxable income, and modify tax depreciation of qualified improvement property, among other provisions.  These provisions have no material impact on the Company.

 

 

 

5. Long-Term Debt
 

The following sections regarding the First Lien Credit Facility and Second Lien Credit Facility are qualified in their entirety by the disclosure contained in Note 1. Going Concern.  Due to certain covenant violations under our credit facilities 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.

 

The following is a description of our debt as of September 30, 2021 and December 31, 2020 (in thousands):

 

   

September 30, 2021

   

December 31, 2020

 
                 

First Lien Credit Facility

  $ 81,689     $ 95,000  

Second Lien Credit Facility

    127,101       112,695  

Exit fee - Second Lien Credit Facility

    10,000       10,000  

Real estate lien note

    2,590       2,810  
      221,380       220,505  

Less current maturities

    (209,434 )     (202,751 )
      11,946       17,754  

Deferred financing fees and debt issuance cost, net

    (9,662 )     (15,239 )

Total long-term debt, net of deferred financing fees and debt issuance costs

  $ 2,284     $ 2,515  

 

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 September 30, 2021, $81.7 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 (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.

 However, at any time an event of default exists, the default rate is 3.0% plus the amounts set forth above. At September 30, 2021, the interest rate on the First Lien Credit Facility was approximately 8.75%.

 

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  September 30, 2021, 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 hedging 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 ended 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 ended 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 than $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 ended  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. At September 30, 2021, the Company’s borrowing base was $81.7 million, the amount outstanding on the First Lien Credit Facility, and thus the Company had no further borrowings available.

 

 

 

As of September 30, 2021, we were not in compliance with the financial covenants under the First Lien Credit Facility, as amended. See Note 10 “Events of Default” for details.

 

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;

 

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 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 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. See Note 10 “Events of Default” for details.

 

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. As of   September 30, 2021, the outstanding balance on the Second Lien Credit Facility was $137.1 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   September 30, 2021, 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 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 hedging 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 which occurred on September 30, 2021; (v) modification of the current ratio to eliminate the exclusion of certain valuation accounts associated with hedging agreements 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  September 30, 2021, we were not in compliance with the financial covenants under the Second Lien Credit Facility, as amended. See Note 10 “Events of Default” for details.

 

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 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 (iv) 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. Additional events of default have occurred as of September 30, 2021, as a result of our failure to comply with certain financial covenants under the Second Lien Credit Facility, as amended. See Note 10 ”Events of Default” for details

 

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 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 agreed to forbear from exercising remedies available to it until May 6, 2021. We are in discussions with Angelo Gordon regarding further forbearance, but no assurance can be provided that we will be able to enter into any additional forbearance agreements.

 

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 accrued interest in the amount of $35,672. The maturity date of the note is July 20, 2023. As of  September 30, 2021 and   December 31, 2020,  $2.6  million and $2.8 million, respectively, were outstanding on the note.

 

Pending Discussions Regarding Debt Restructurings

 

The Company is in discussions with its creditors in an effort to restructure its balance sheet and eliminate or substantially reduce the outstanding indebtedness under its First Lien Credit Facility and Second Lien Credit Facility.  Any negotiated transaction with its lenders would likely include the possible sale of a significant block of assets, the proceeds from which would be applied to reduce debt, the exchange of a significant amount of equity interests in the Company for outstanding indebtedness, and/or other possible negotiated transactions, which in the aggregate would likely result in significant dilution of existing stockholder interests and reduction or potentially elimination of value for existing stockholders.  Any such transaction could involve a proceeding under the U.S. Bankruptcy Code.  No assurance can be provided that any such transaction can be successfully concluded, in which event the Company’s lenders may commence foreclosure proceedings seeking to liquidate Company assets to repay the outstanding indebtedness.  In any such proceeding, it is unlikely that stockholders would recover any more than a de minimis amount for their stock, and the stock may become worthless.

 

 

 

 

 

6. Earnings per Share

 

The following table sets forth the computation of basic and diluted earnings per share:

 

   

Three Months Ended September 30,

   

Nine Months Ended September 30,

 
   

2021

   

2020

   

2021

   

2020

 

Numerator:

                               

Net loss

  $ (1,245 )   $ (73,615 )   $ (38,940 )   $ (115,428 )

Denominator:

                               

Denominator for basic earnings per share – weighted-average common shares outstanding

    8,406       8,362       8,406       8,366  

Effect of dilutive securities:

                               

Stock options, restricted shares and warrants

    -       -       -       -  

Denominator for diluted earnings per share – adjusted weighted-average shares and assumed exercise of options and restricted shares

    8,406       8,362       8,406       8,366  
                                 

Net loss per common share - basic

  $ (0.15 )   $ (8.80 )   $ (4.63 )   $ (13.80 )
                                 

Net loss per common share - diluted

  $ (0.15 )   $ (8.80 )   $ (4.63 )   $ (13.80 )

 

Basic earnings per share, excluding any dilutive effects of stock options and unvested restricted stock, is computed by dividing net income available to common stockholders by the weighted average number of common shares outstanding for the period. Diluted net income per share is computed similar to basic; however diluted income per share reflects the assumed conversion of all potentially dilutive securities. For the three and nine month periods ended  September 30, 2021 there were no dilutive potential shares relating to stock options and restricted stock due to our depressed stock price and losses in the period. 

 

 

7.  Hedging Program and Derivatives

 

The derivative contracts we utilize are based on index prices that may and often differ from the actual oil and gas prices realized in our operations.  Our derivative contracts do not qualify for hedge accounting; therefore, fluctuations in the market value of the derivative contracts are recognized in earnings during the current period. There are no netting agreements relating to these derivative contracts and there is no policy to offset. 

 

The following table sets forth the summary position of our derivative contracts as of September 30, 2021:

 

   

Oil - WTI

 

Contract Periods

 

Daily Volume (Bbl)

   

Swap Price (per Bbl)

 

Fixed Swaps

               

2021 October - December

    750     $ 52.50  

 

Substantially all of our hedges were terminated in April 2021.

 

The following table illustrates the impact of derivative contracts on our balance sheet:

 

Fair Value of Derivative Contracts as of September 30, 2021

 
   

Asset Derivatives

 

Liability Derivatives

 

Derivatives not designated as hedging instruments

 

Balance Sheet Location

 

Fair Value

 

Balance Sheet Location

 

Fair Value

 

Commodity price derivatives

 

Derivatives – current

  $ -  

Derivatives – current

  $ 2,017  

Commodity price derivatives

 

Derivatives – long-term

    -  

Derivatives – long-term

    -  
        $ -       $ 2,017  

 

Fair Value of Derivative Contracts as December 31, 2020

 
   

Asset Derivatives

 

Liability Derivatives

 

Derivatives not designated as hedging instruments

 

Balance Sheet Location

 

Fair Value

 

Balance Sheet Location

 

Fair Value

 

Commodity price derivatives

 

Derivatives – current

  $ 9,639  

Derivatives – current

  $ 480  

Commodity price derivatives

 

Derivatives – long-term

    10,281  

Derivatives – long-term

    -  
        $ 19,920       $ 480  

 

 

 

8. Financial Instruments

 

Assets and liabilities measured at fair value are categorized into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows:

 

 

Level 1 – inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabilities in active markets.

 

Level 2 - inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument.

 

Level 3 - inputs to the valuation methodology are unobservable and significant to the fair value measurement.

 

A financial instrument’s categorization within the valuation hierarchy is based upon the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability. We are further required to assess the creditworthiness of the counter-party to the derivative contract. The results of the assessment of non-performance risk, based on the counter-party’s credit risk, could result in an adjustment of the carrying value of the derivative instrument. The following tables sets forth information about our assets and liabilities measured at fair value on a recurring basis as of September 30, 2021 and December 31, 2020, and indicate the fair value hierarchy of the valuation techniques utilized by us to determine such fair value:

 

    Quoted Prices in Active Markets for Identical Assets (Level 1)     Significant Other Observable Inputs (Level 2)    

Significant Unobservable Inputs (Level 3)

   

Balance as of September 30, 2021

 

Assets:

                               

NYMEX fixed price derivative contracts

  $     $     $     $  

Total Assets

  $     $     $     $  
                                 

Liabilities:

                               

NYMEX fixed price derivative contracts

  $     $ 2,017     $     $ 2,017  

Total Liabilities

  $     $ 2,017     $     $ 2,017  

 

    Quoted Prices in Active Markets for Identical Assets (Level 1)     Significant Other Observable Inputs (Level 2)    

Significant Unobservable Inputs (Level 3)

    Balance as of December 31, 2020  

Assets:

                               

NYMEX fixed price derivative contracts

  $     $ 19,920     $     $ 19,920  

Total Assets

  $     $ 19,920     $     $ 19,920  
                                 

Liabilities:

                               

NYMEX fixed price derivative contracts

  $     $ 480     $     $ 480  

Total Liabilities

  $     $ 480     $ -     $ 480  

 

As of   September 30, 2021, our derivative contracts consisted of NYMEX-based fixed price swaps. At December 31, 2020 our derivative contracts 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 counterparty. Under basis swaps, if the market price is above the fixed price, we pay the counter-party, if the market price is below the fixed price, the counter-party pays us. The NYMEX-based fixed price derivative swaps and basis differential swap contracts are indexed to NYMEX futures contracts, which are actively traded, for the underlying commodity and are commonly used in the energy industry. A number of financial institutions and large energy companies act as counter-parties to these types of derivative contracts. As the fair value of NYMEX-based fixed price swaps are based on a number of inputs, including contractual volumes and prices stated in each derivative contract, current and future NYMEX commodity prices, and quantitative models that are based upon readily observable market parameters that are actively quoted and can be validated through external sources, we have characterized these derivative contracts as Level 2. In order to verify the third party valuation, we enter the various inputs into a model and compare our results to the third party for reasonableness. We did not have any Level 3 contracts at December 31, 2020 or September 30, 2021.

 

 

Nonrecurring Fair Value Measurements

 

Non-financial assets and liabilities measured at fair value on a nonrecurring basis included certain non-financial assets and liabilities as may be acquired in a business combination and thereby measured at fair value and the initial recognition of asset retirement obligations for which fair value is used. Unproved oil and gas properties are assessed periodically, at least annually, to determine whether impairment has occurred. The assessment considers the following factors, among others: intent to drill, remaining lease term, geological and geophysical evaluations, drilling results and activity, the assignment of proved reserves, the economic viability of development if proved reserves were assigned and other current market conditions. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization.

 

The asset retirement obligation estimates are derived from historical costs as well as management’s expectation of future cost environments. As there is no corroborating market activity to support the assumptions used, the Company has designated these liabilities as Level 3. A reconciliation of the beginning and ending balances of the Company’s  asset retirement obligation is presented in Note 1.

 

Other Financial Instruments

 

The carrying amounts of our cash, cash equivalents, restricted cash, accounts receivable and accounts payable approximate fair value because of the short-term maturities and/or liquid nature of these assets and liabilities. The carrying value of our debt approximates fair value as the interest rates are market rates and this debt is considered Level 2.

 

 

9. Leases

 

Nature of Leases

 

We lease certain real estate, field equipment and other equipment under cancelable and non-cancelable leases to support our operations. A more detailed description of our significant lease types is included below.

 

Field Equipment

 

We rent various field equipment from third parties in order to facilitate the downstream movement of our production from our drilling operations to market. Our compressor and cooler arrangements are typically structured with a non-cancelable primary term of one  year and continue thereafter on a month-to-month basis subject to termination by either party with thirty days’  notice. These leases are considered short term and  are not capitalized. We have a small number of  compressor leases that are longer than  twelve months. We have concluded that our equipment rental agreements represent operating leases with a lease term that equals the primary non-cancelable contract term. Upon completion of the primary term, both parties have substantive rights to terminate the lease. As a result, enforceable rights and obligations do not exist under the rental agreement subsequent to the primary term. We enter into daywork contracts for drilling rigs with third parties to support our drilling activities. Our drilling rig arrangements are typically structured with a term that is in effect until drilling operations are completed on a contractually specified well or well pad. Upon mutual agreement with the contractor, we typically have the option to extend the contract term for additional wells or well pads by providing thirty days notice prior to the end of the original contract term. We have concluded that our drilling rig arrangements represent short-term operating leases. The accounting guidance requires us to make an assessment at contract commencement if we are reasonably certain that we will exercise the option to extend the term. Due to the continuously evolving nature of our drilling schedules and the potential volatility in commodity prices in an annual period, our strategy to enter into shorter term drilling rig arrangements allows us the flexibility to respond to changes in our operating and economic environment. We exercise our discretion in choosing to extend or not extend contracts on a rig by rig basis depending on the conditions present at the time the contract expires. At the time of contract commencement, we have determined we cannot conclude with reasonable certainty if we will choose to extend the contract beyond its original term. Pursuant to the full cost method, these costs are capitalized as part of natural gas and oil properties on our balance sheet when paid.

 

Discount Rate

 

Our leases typically do not provide an implicit rate. Accordingly, we are required to use our incremental borrowing rate in determining the present value of lease payments based on the information available at commencement date. Our incremental borrowing rate reflects the estimated rate of interest that we would pay to borrow on a collateralized basis over a similar term an amount equal to the lease payments in a similar economic environment. We use the implicit rate in the limited circumstances in which that rate is readily determinable.

 

 

Practical Expedients and Accounting Policy Elections

 

Certain of our lease agreements include lease and non-lease components. For all existing asset classes with multiple component types, we have utilized the practical expedient that exempts us from separating lease components from non-lease components. Accordingly, we account for the lease and non-lease components in an arrangement as a single lease component. In addition, for all of our existing asset classes, we have made an accounting policy election not to apply the lease recognition requirements to our short-term leases (that is, a lease that, at commencement, has a lease term of 12 months or less and does not include an option to purchase the underlying asset that we are reasonably certain to exercise). Accordingly, we recognize lease payments related to our short-term leases in our statement of operations on a straight-line basis over the lease term which has not changed from our prior recognition. To the extent that there are variable lease payments, we recognize those payments in our statement of operations in the period in which the obligation for those payments is incurred. None of our current leases contain variable payments.  Refer to 'Nature of Leases”   above for further information regarding those asset classes that include material short-term leases.

 

The components of our total lease expense for the three and nine months ended September 30, 2021, the majority of which is included in lease operating expense, are as follows:

 

   

Three Months Ended September 30, 2021

   

Nine Months Ended September 30, 2021

 

Operating lease cost

  $ 13     $ 52  

Short-term lease expense (1)

  $ 465     $ 1,456  

Total lease expense

  $ 478     $ 1,508  
                 

Short-term lease costs (2)

  $ -     $ -  

 

(1)

Short-term lease expense represents expense related to leases with a contract term of 12 months or less.

  (2) These short-term lease costs are related to leases with a contract term of 12 months or less which are related to drilling rigs and are capitalized as part of natural gas and oil properties on our balance sheet.

 

Supplemental balance sheet information related to our operating leases is included in the table below:
 

   

September 30, 2021

 

Operating lease ROU assets

  $ 184  

Operating lease liability - current

  $ 41  

Operating lease liabilities - long-term

  $ 118  

 

Our weighted average remaining lease term and weighted average discount rate for our operating leases are as follows:

 

   

September 30, 2021

 

Weighted Average Remaining Lease Term (in years)

    12.0  

Weighted Average Discount Rate

    6 %

 

Our lease liabilities with enforceable contract terms that are greater than one year mature as follows:

 

   

Operating Leases

 

Remainder of 2021

  $ 49  

2022

    42  

2023

    37  

2024

    4  

2025

    4  

Thereafter

    94  

Total lease payments

    230  

Less imputed interest

    (71 )

Total lease liability

  $ 159  

 

At September 30, 2021, we had only a lease on office equipment, with minimum lease payments with commitments that had initial or remaining lease terms in excess of one year. 

 

 

 

 

 

10.  Events of Default

 

 

In connection with the completion of our financial statements for the year ended December 31, 2020, the Company tested its financial ratios for the fiscal quarter ended December 31, 2020 and determined that it was not in compliance the first lien debt to consolidated EBITDAX ratio covenant under the First Lien Credit Facility.  Our failure to comply with such covenant contributed to our independent accountant’s including an explanatory paragraph with regard to the Company’s  ability to continue as a “going concern”  in issuing their opinion on our financial statements for the year ended December 31, 2020.  The "going  concern" opinion resulted in an additional event of default under the First Lien Credit Facility and the Second Lien Credit Facility. Additional events of default have occurred as of September 30, 2021, as a result of our failure to comply with certain financial covenants under the Second Lien Credit Facility, as amended.  A discussion of the events of default follows.

 

First Lien Credit Facility

 

Events of default have occurred under the First Lien Credit Facility as a result of (i) the Company’s failure to timely deliver audited financial statements without a “going concern” or like qualification for the fiscal year ended December 31, 2020, (ii) its 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

 

Events of default have occurred under the Second Lien Credit Facility as a result of (i) the Company’s failure to timely deliver audited financial statements without a “going concern”  or like qualification for the fiscal year ended December 31, 2020, (ii) its failure to cause certain deposit accounts to be subject to control agreements in favor of the administrative agent for the Second Lien Credit Facility and (iii) the failure of the Company to meet certain hedging requirements, (iv) the Company’s inability to comply with the total leverage ratio for the fiscal quarter ended September 30, 2021, (v) the Company’s inability to comply with minimum asset coverage ratio for the fiscal quarter ended September 30, 2021, and (vi) 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 corresponding cross-defaults or similar termination events under our hedging contracts. Additional events of default have occurred as of September 30, 2021, as a result of our failure to comply with certain financial covenants under the Second Lien Credit Facility, as amended.

 

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 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 agreed to forbear from exercising remedies available to it until May 6, 2021. We are in discussions with Angelo Gordon regarding further forbearance, but no assurance can be provided that we will be able to enter into any additional forbearance agreements.

 

Hedging Contracts

 

Effective April 12, 2021, Morgan Stanley Capital Group, Inc. (“Morgan Stanley”), a hedge counterparty to several of our hedging contracts sent us notice of events of default and early termination with respect to the hedging contracts to which they are a counterparty.  The notice indicates Morgan Stanley’s election to exercise termination rights under the hedge contract, which Morgan Stanley asserts have arisen as a result of the occurrence of events of default under the First Lien Credit Facility, of which Morgan Stanley is a lender, holding approximately 3.7% of the outstanding obligations under the First Lien Credit Facility.  The termination value of the hedging agreements with Morgan Stanley as of the effective date of the notice was approximately $9.2 million.  We subsequently voluntarily terminated most of our other hedging arrangements. As a result of the settlement of the terminated hedges, we have outstanding obligations of $9.2 million, including the $8.4 million to Morgan Stanley. These obligations will be added to the outstanding balance of the First Lien Credit Facility and accrue interest at the default rate, currently 8.75%, until repaid. Other hedging agreements may also be terminated as a result of the events of default. The termination of additional hedging agreements  may result in losses and limit our ability to reduce exposure to adverse fluctuations in oil and gas prices. Amounts that we may owe as a result of terminated hedging agreements will accrue interest for so long as such amounts remain unpaid.

 

Forbearance Discussions

 

The existing events of default under the credit facilities were subject to forbearance agreements with our lenders that expired on May 6, 2021.  We are in discussions with our lenders regarding further forbearance, but no assurance can be provided that we will be able to enter into any additional forbearance agreements.  

 

 

11. Commitments and 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 September 30, 2021, we were not involved in any legal proceedings that are expected, individually or in the aggregate, to have a material adverse effect on our financial position or results of operations.

 

 

 

12. Subsequent Events

 

As noted in Note 10 above, defaults under our First Lien Credit Facility and Second Lien Credit Facility, and constraints imposed by the lenders in the most recent amendments to those facilities, have deprived us of capital resources necessary to continue to develop our assets and generate cash. As a result, we have virtually no excess cash flow or available capital. While we have sought additional forbearances from our lenders, to date no additional relief has been forthcoming. However, increased energy prices have made the climate more favorable for discussions regarding possible negotiated transactions that would reduce or eliminate our existing long-term indebtedness.

 

No assurances can be provided that a transaction or transactions can be concluded that will successfully address our outstanding borrowings.  However, discussions are currently underway regarding a possible sale of assets to permit payment of the First Lien Credit Facility indebtedness, and a possible debt/equity exchange to extinguish the Second Lien Credit Facility indebtedness in return for the issuance of substantial equity ownership in the Company to the Second Lien Credit Facility lender.

 

If successfully concluded, these transactions could discharge the Company’s long-term indebtedness and permit us to resume development of locations that we believe are highly likely to generate additional production oil and gas.

 

The amount of outstanding indebtedness under our Second Lien Credit Facility is in excess of $137 million, and if a transaction could be successfully concluded, it would result in substantial dilution of existing stockholder interests, and possibly elimination of value for existing stockholders. No terms have been finalized regarding these possible transactions, and no assurance can be provided that the negotiations will be successful.

 

In the event a negotiated transaction cannot be concluded, the First Lien Credit Facility Lender may seek to foreclose its liens on the Company’s assets, and the Second Lien Credit Facility Lender may seek to foreclose its liens on any remaining assets. If the lenders initiate procedures to seize and sell the Company’s assets, the Company would consider initiating a proceeding under the U.S. Bankruptcy Code to give us the opportunity to propose a restructuring plan designed to permit payment of lenders over time and development of the Company’s resources for the benefit of the lenders and, if possible, the Company’s stockholders. No assurance can be provided regarding the outcome of any contested bankruptcy proceeding, but it is possible, if not likely, that stockholders would recognize no value for their shares.

 

 

 

  

 

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

 

The following is a discussion and analysis of our financial condition, results of operations, liquidity and capital resources and should be read in conjunction with our consolidated financial statements and the notes thereto, included in this Quarterly Report on Form 10-Q and the consolidated financial statements and notes thereto as of and for the year ended December 31, 2020 and the related Management’s Discussion and Analysis of Financial Condition and Results of Operations, both of which are contained in our Annual Report on Form 10-K for the year ended December 31, 2020 filed with the SEC on May 6, 2021. Please see “Forward Looking Information” above.

 

Except as otherwise noted, all tabular amounts are in thousands, except per unit values.

 

Critical Accounting Policies

 

There have been no changes from the Critical Accounting Policies described in our Annual Report on Form 10-K for the year ended December 31, 2020, except for the adoption of Accounting Standards Update 2016-13, Financial Instruments - Credit Losses which was effective January 1, 2020. See “Recently Issued Accounting Standards” for more information.

 

General

 

We are an independent energy company primarily engaged in the acquisition, development and production of oil and gas in the United States. Historically, we have grown through the acquisition and subsequent development  of producing properties, principally through the development of shale or tight oil reservoirs in areas known to be productive of oil and gas utilizing new technologies such as modern log analysis and reservoir modeling techniques as well as 3-D seismic surveys and horizontal drilling and stage fracturing. As a result of these activities, we believe that we have a number of development opportunities on our properties. 

 

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 decreased as a direct result of travel restrictions placed by governments in an effort to curtail the spread of COVID-19 and its variants. 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 decreased, which has affected our liquidity. Since that time, demand and the price of oil and gas have increased, but uncertainty related to the pandemic caused by COVID-19 and its variant strains persists. 

 

In early March 2020, global oil and natural gas prices declined sharply, rising in recent months, but may decline again. The full impact of COVID-19 and its variants 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. Principally as a result of restrictions imposed by our lenders, we have also suspended our capital expenditures indefinitely. 

 

Factors Affecting Our Financial Results

 

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. 

 

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 the 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 and condensate, NGL and gas largely determines the amount of cash generated from operating activities, which will in turn impact our financial position.

 

 

During the nine months ended September 30, 2021, the NYMEX future price for oil averaged $65.04 per Bbl as compared to $37.26 per Bbl in the same period of 2020. During the nine months ended September 30, 2021, the NYMEX future spot price for gas averaged $3.35 per MMBtu compared to $1.81 per MMBtu in the same period of 2020. Prices closed on September 30, 2021 at $75.03 per Bbl of oil and $5.87 per MMBtu of gas, compared to closing on September 30, 2020 at $20.48 per Bbl of oil and $1.64 per MMBtu of gas.  On November 11, 2021, prices closed at $81.59 per Bbl of oil and $5.15 per MMBtu of gas.  If commodity prices decline, our revenue and cash flow 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 flow from operations will also likely decrease which could cause us to alter our business plans, including reducing any then existing drilling activities. Such declines have required, and in future periods could also require us to write down the carrying value of our oil and gas assets which would also cause a reduction in net income. The prices that we receive are also impacted by basis differentials, which can be significant, and are dependent on actual delivery points. Finally, low commodity prices will likely cause a reduction of our proved reserves.

 

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 nine month periods ended September 30, 2021 and 2020:

 

   

Oil - NYMEX

   

Gas - NYMEX

 
   

2021

   

2020

   

2021

   

2020

 

Average realized price (1)

  $ 60.82     $ 36.88     $ 2.06     $ 0.13  

Average NYMEX price

    65.04       38.51       3.35       1.92  

Differential

  $ (4.22 )   $ (1.63 )   $ (1.29 )   $ (1.79 )

                                                                                

(1) Excludes the impact of derivative activities.

 

At September 30, 2021, our remaining derivative contract is a NYMEX-based fixed price swaps. Under fixed price swaps, we receive a fixed price for our production and pay a variable market price to the contract counter-party. 

 

The majority of our derivative contracts were terminated in April 2021. Our remaining derivative contract equates to approximately 33% of the estimated oil production from our net proved developed producing reserves (based on reserve estimates at September 30, 2021  from October 1, 2021 through December 31, 2021. None of our production subsequent to 2021 is covered by derivative contracts.  When prevailing market prices are higher than our contract prices, we will not realize increased cash flow. We have in the past and will in the future sustain losses on our 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 gains on our commodity derivative contracts. For the nine months ended September 30, 2021, we realized a loss of $18.7  million on our derivative contracts, including a loss of $7.1 million resulting from the termination of our derivative contracts in April 2021. For the nine months ended September 30, 2020, we realized a gain of $53.2 million on our derivative contracts.  We have not designated any of these derivative contracts as hedges as prescribed by applicable accounting rules. Substantially all of our derivative contracts were terminated in April 2021, as a result of our default on our credit facilities.  See Note 10 “Events of Default”. 

 

The following table sets forth our derivative contracts at September 30, 2021:

 

   

Oil - WTI

 

Contract Periods

 

Daily Volume (Bbl)

   

Swap Price (per Bbl)

 

Fixed Swaps

               

2021 October - December

    750     $ 52.50  

 

At September 30, 2021, the aggregate fair market value of our commodity derivative contracts was a net liability of approximately $2.0 million.

 

Most of our derivative contracts were terminated in April  2021.

 

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 different.  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. In addition, the 1L Amendment limits capex to $3.0 million over any four consecutive quarters beginning with the quarter ended June 30, 2020. This limit is effective until the First Lien Credit Facility is paid down to $50.0 million, which will limit our ability to replace production volumes until the First Lien Credit Facility is substantially reduced or repaid.  

 

We had capital expenditures during the nine months ended September 30, 2021 of $856,000 related to our existing properties.   We have not established a capital expenditure budget for 2021 due to restraints imposed by our credit facility, as amended. Management and the board of directors are also considering additional operating and overhead cost efficiencies that could be realized in connection with the 2021 budget. The amendments to our credit facilities, described in the “Liquidity and Capital Resources” section below, limit our capital expenditures to $3.0 million in any four consecutive quarters, beginning with the quarter ended June 30, 2020.  Our capital expenditures will not be able to offset oil and gas production decreases caused by natural field declines.

 

The following table presents historical net production volumes for the three and nine months ended September 30, 2021, and 2020:

 

   

Three Months Ended September 30,

   

Nine Months Ended September 30,

 
   

2021

   

2020

   

2021

   

2020

 

Total production (MBoe)

    516       492       1,541       1,265  

Average daily production (Boepd)

    5,605       5,346       5,644       4,616  

% Oil

    45 %     71 %     48 %     64 %

 

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 three and nine months ended September 30, 2021 and 2020, by our major operating regions:

 

   

Three Months Ended September 30,

   

Nine Months Ended September 30,

 
   

2021

   

2020

   

2021

   

2020

 

Oil production (MBbls)

                               

Rocky Mountain

    108       138       360       376  

Permian/Delaware Basin

    122       209       383       437  

Total

    230       347       743       813  

Gas production (MMcf)

                               

Rocky Mountain

    477       331       1,391       966  

Permian/Delaware Basin

    415       123       1,204       438  

Total

    892       454       2,595       1,404  

NGL production (MBbls)

                               

Rocky Mountain

    107       55       283       168  

Permian/Delaware Basin

    30       14       82       50  

Total

    137       69       365       218  

Total production (MBoe) (1)

    516       492       1,541       1,265  

Average sales price per Bbl of oil (2)

                               

Rocky Mountain

  $ 66.08     $ 34.76     $ 59.07     $ 35.13  

Permian/Delaware Basin

    68.66       36.68       62.48       38.38  

Composite

    67.44       35.92       60.82       36.88  

Average sales price per Mcf of gas (2)

                               

Rocky Mountain

  $ 2.48     $ (0.01 )   $ 1.62     $ 0.07  

Permian/Delaware Basin

    2.97       0.63       2.57       0.25  

Composite

  $ 2.71       0.17     $ 2.06       0.13  

Average sales price per Bbl of NGL

                               

Rocky Mountain

  $ 20.70     $ -     $ 14.14     $ 0.54  

Permian/Delaware Basin

    23.80       3.74       17.17       1.23  

Composite

    21.39       0.76       14.83       0.70  

Average sales price per Boe (2)

  $ 40.44     $ 25.60     $ 36.32     $ 23.96  

Average cost of production per Boe produced (3)

                               

Rocky Mountain

  $ 8.16     $ 8.36     $ 6.88     $ 7.52  

Permian/Delaware Basin

    9.87       7.63       10.61       12.60  

Composite

    8.87       7.99       8.48       9.78  

 

 

(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.

 

 

Availability of Capital.  As described more fully under “Liquidity and Capital Resources” below, our sources of capital are cash flow from operating activities, 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 asset sales or financing on terms acceptable to us, if at all.  Our credit facilities were amended in June 2020, resulting in no available borrowing base under our First Lien Credit Facility. Additionally, any excess cash, as defined in the First Lien Credit Facility, is required to be applied to the outstanding balance on a monthly basis, and the borrowing base will be reduced to the new outstanding balance. As a result, with the exception of $3.0 million of funds available for working capital purposes, we have no availability to borrow funds, and except in connection with asset sales or other transaction approved by our lenders, no access to capital in excess of the $3.0 million monthly working capital allowance.

 

Borrowings and Interest.  At September 30, 2021, we had a total of $81.7 million outstanding under our First Lien Credit Facility, $137.1 million under our Second Lien Credit facility, including a  $10.0  million exit fee, and total indebtedness of  $221.4 million (including the current portion). Additionally, we have an obligation of approximately $9.1 million related to terminated hedging agreements. 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 noted above, under the terms of the amended Second Lien Credit Facility, interest under the 2nd Lien Notes is now paid-in-kind by the allocation of additional shares of common stock to our Second Lien Credit Facility lender. We are in default on both of our credit facilities, see Note 10 “Events of Default” for further explanation.

 

Exploration and Development Activity. If our defaults under existing borrowings can be resolved by repayment or other settlement, then we believe we could access capital to resume development of our assets. We believe that our high quality asset base, high degree of operational control and inventory of drilling projects position us for future growth. At December 31, 2020, we operated properties accounting for virtually all of our PV-10, 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. However, the amendments to our First Lien Credit Facility and Second Lien Credit facility place severe restrictions on our capital expenditures and we have very little planned activity for 2021.

 

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 we will have any significant exploration and development activities in the near term or that they 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 flow from operations will decline. If cash flow declines and we have no access to additional capital, we will be unable to acquire or develop additional reserves or develop our existing undeveloped reserves, in which case our results of operations and financial condition will be adversely affected. Additionally, due to uncertainty regarding our ability to remain a “going concern” and our lack of liquidity, all of our proved undeveloped reserves have been removed from our books. 

 

 

Results of Operations

 

Selected Operating Data. The following table sets forth operating data from continuing operations for the periods presented.

 

   

Three Months Ended September 30,

   

Nine Months Ended September 30,

 
   

2021

   

2020

   

2021

   

2020

 

Operating revenue (1):

                               

Oil sales

  $ 15,506     $ 12,466     $ 45,199     $ 29,971  

Gas sales

    2,415       75       5,344       183  

NGL sales

    2,933       52       5,416       152  

Other

    11       2       19       8  

Total operating revenues

  $ 20,865     $ 12,595     $ 55,978     $ 30,314  

Operating income (loss)

  $ 8,829     $ (56,661 )   $ 19,728     $ (147,916 )

Oil sales (MBbls)

    230       347       743       813  

Gas sales (MMcf)

    892       454       2,595       1,404  

NGL sales (MBbls)

    137       69       365       218  

Oil equivalents (MBoe)

    516       492       1,541       1,265  

Average oil sales price (per Bbl)(1)

  $ 67.44     $ 35.92     $ 60.82     $ 36.88  

Average gas sales price (per Mcf)(1)

  $ 2.71     $ 0.17     $ 2.06     $ 0.13  

Average NGL sales price (per Bbl)

  $ 21.39     $ 0.76     $ 14.83     $ 0.70  

Average oil equivalent sales price (Boe) (1)

  $ 40.44     $ 25.60     $ 36.32     $ 23.96  

___________________

 

(1)

Revenue and average sales prices are before the impact of hedging activities.

 

Comparison of Three Months Ended September 30, 2021 to Three Months Ended September 30, 2020

 

Operating Revenue. During the three months ended September 30, 2021, operating revenue increased to $20.9 million from $12.6 million for the same period of 2020. The increase in revenue was primarily due to higher commodity prices. Higher realized prices for all products added $12.3 million.to operating revenue for the three months ended September 30, 2021.  Lower oil sales volumes negatively impacted revenue by $4.2 million, partially offset by higher gas and NGL sales volumes. Higher sales volumes for gas and NGL added $0.1 million to revenue during the three months ended September 30, 2021  compared to the same period of 2020.  

 

Oil sales volumes decreased to 230 MBbl during the three months ended September 30, 2021 from 347 MBbl for the same period of 2020. The decrease in oil sales volume was primarily due to natural field declines and not bringing any new production on line in 2021. Gas sales volumes increased to 892 MMcf for the three months ended September 30, 2021 from 454 MMcf for the same period of 2020. The increase in gas volumes was the result of bringing deep gas wells back on production that had been shut in since 2019 due to low gas prices.

 

Lease Operating Expenses (“LOE”). LOE for the three months ended September 30, 2021  increased to $4.6 million from $3.9 million for the same period of 2020. The increase in LOE was primarily due to additional field expense associated with bringing shut in wells back on production as well as an overall increase in the cost of services.  We had cost savings  as a result of reducing our work force in North Dakota in May 2020 and eliminated substantially all field overtime. LOE per Boe for the three months ended September 30, 2021 was $8.94 compared to $8.00 for the same period of 2020. The increase per Boe was due primarily to lower  sales volumes, offset by higher total costs for the three months ended September 30, 2021  compared to the same period of 2020. 

 

Production and Ad Valorem Taxes. Production and ad valorem taxes for the three months ended September 30, 2021 increased to $1.6  million from $1.5 million for the same period of 2020.  Production and ad valorem taxes for the three months ended September 30, 2021 were 7% of total oil, gas and NGL sales  compared to 12% for the same period of 2020.  The higher percentage for 2020 was primarily due to Ad Valorem taxes that do not vary with production volumes.  

 

 

General and Administrative (“G&A”) Expense. G&A expenses, excluding stock-based compensation,  decreased to $1.7 million for the three months ended September 30, 2021  compared to $1.8 million in the same period of  2020. G&A per Boe, excluding stock-based compensation, was $3.24 for the quarter ended September 30, 2021 compared to $3.56 for the same period of 2020.  The decrease in G&A per Boe, excluding stock based compensation, was primarily due to lower cost and higher sales volumes for the three months ended September 30, 2021  compared to the same period of 2020.

 

Stock-Based Compensation. Options granted to employees and directors are valued at the date of grant and expense is recognized over the options' vesting period. In addition to options, restricted shares of our common stock have been granted and are valued at the date of grant and expense is recognized over their vesting period. For the three months ended September 30, 2021, and September 30, 2020 stock-based compensation expense was $0.3 million. The majority of our stock based compensation has been fully amortized and no new grants were issued during the three month period ended September 30, 2021.

 

Depreciation, Depletion and Amortization (“DD&A”) Expense. DD&A expense, including accretion of future site restoration, for the three months ended September 30, 2021  decreased to $3.8 million from $6.9 million for the same period of 2020. The decrease was primarily due to higher production volumes offset by  a lower full cost pool as a result of the impairments recorded in 2020 as well as lower  future development cost included in the September 30, 2021 internal reserve report given the removal of proved undeveloped reserves. Proved  undeveloped reserves were removed due to the uncertainty of the Company’s ability to be a “going concern”  and the lack of available liquidity to develop the reserves.    DD&A expense per Boe for the three months ended September 30, 2021 was $7.39 compared to $14.06 in the same period of  2020. The decrease in DD&A expense per Boe was primarily due to a lower full cost pool as the result of the impairment incurred in 2020.

 

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 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 flow from operating activities. However, such write-downs do impact the amount of our stockholders’ equity and reported earnings. As of September 30, 2021, our net capitalized costs of oil and gas properties did not exceed the cost ceiling of our estimated proved reserves. As of  September 30, 2020, our net capitalized costs of oil and gas properties exceeded the cost ceiling of our estimated proved reserves ,resulting in the recognition of an impairment of $54.6  million for the three months ended September 30, 2020.

 

The risk that we will be required to write-down the carrying value of our oil and gas assets increases when oil and gas prices are depressed or volatile. In addition, write-downs may occur if we have substantial downward revisions in our estimated proved reserves. We cannot assure you that we will not experience additional write-downs in the future. 

 

Interest Expense. Interest expense for the three months ended September 30, 2021 increased to $8.1 million compared to $5.7 million for the same period of 2020. The increase in interest expense in 2021 was due to higher levels of debt and higher interest rates than during the three months ended September 30, 2021  compared to the same period of  2020. The increase in debt levels was primarily due to interest paid in kind on our Second Lien Credit Facility. For the three months ended September 30, 2021, the interest rate on our First Lien Credit Facility averaged 8.8%  compared to 4.7%  for the same period of 2020. The increase in the average rate on the First Lien Credit Facility was the result of a default interest rate of 8.75% beginning April 22, 2021. The interest rate on our Second Lien Credit Facility averaged  15.8%  for the three months ended September 30, 2021 and 2020.  We anticipate higher interest rates and increased interest expense in the future as a result of the amendments to our credit facilities. For the three months ended September 30, 2021, approximately $5.0 million in interest expense on our Second Lien Credit Facility was paid in kind. 

 

Loss (Gain) on Derivative Contracts. Derivative 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 at period end. We have elected not to apply hedge accounting to our derivative contracts; therefore, fluctuations in the market value of the derivative contracts are recognized in earnings during the current period. Our derivative contracts consisted of NYMEX-based fixed price swaps and basis differential swaps as of September 30, 2021 and September 30, 2020. The net estimated value of our commodity derivative contracts was a net liability of approximately $2.0 million as of September 30, 2021. When our derivative contract prices are higher than prevailing market prices, we incur gains and, conversely, when our derivative contract prices are lower than prevailing market prices, we incur losses. For the three months ended September 30, 2021, we recognized a loss on our commodity derivative contracts of $0.3 million. For the three months ended September 30, 2020, we recognized a loss on our commodity derivative contracts of  $6.6 million.

 

Income Tax Expense. For the three months ended September 30, 2021 and September 30, 2020 there was no income tax expense recognized due to our NOL carryforwards. The Coronavirus Aid, Relief, and Economic Security Act (the “CARES Act”),  that was enacted March 27, 2020, includes income tax provisions that allow net operating losses (“NOLs”) to be carried back, allows interest expense to be deducted up to a higher percentage of adjusted taxable income, and modifies tax depreciation of qualified improvement property, among other provisions.  These provisions did not have a material impact on the Company.

 

 

Comparison of Nine Months Ended September 30, 2021 to Nine Months Ended September 30, 2020

 

Operating Revenue. During the nine months ended September 30, 2021, operating revenue increased to $56.0 million from $30.3 million for the same period of 2020. The increase in revenue was primarily due to higher commodity prices as well as higher sales volumes during the nine months ended September 30, 2021 compared to the same period of 2020. Higher realized commodity prices for all products contributed  $23.6 million in operating revenue,  and higher sales volumes for gas and NGL added $4.6 million to operating revenue offset by lower oil sales volumes. Lower oil sales volumes had a negative impact on revenue of  $2.6 for the nine months ended September 30, 2021. 

 

Oil sales volumes decreased to 743 MBbl during the nine months ended September 30, 2021, from 813 MBbl for the same period of 2020. Oil volumes were lower primarily due to field declines and no new production being brought on line in 2021. Overall production on a BOE basis was higher in 2021, as a result of bringing wells back on production that were shut in during most of the second quarter of 2020 as  a result of the COVID-19 virus and other geopolitical issues affecting the supply and demand for oil and natural gas, and accordingly the prices we received. We made the decision to begin shutting in wells in mid-March 2020. The majority of our oil production was shut in from mid-March through mid-June, 2020 when prices had recovered somewhat. We began bringing wells back on production in mid-June, and had a significant amount of our oil production back on line in July 2020. The increase in gas production was primarily due to shut in wells, as discussed above.  Additionally, we have brought  a number of dry gas wells in west Texas back on production that had been shut in since approximately April 2019 due to negative gas prices.

 

Lease Operating Expenses (LOE). LOE for the nine months ended September 30, 2021 increased to $13.1 million from $12.3 million for the same period of  2020. The increase was primarily due to expenses related to having wells back on production that were shut in, as discussed above, as well as higher cost of services in 2021  compared to 2020. LOE per Boe for the nine months ended September 30, 2021 was $8.48 compared to $9.71 for the same period of 2020. The decrease per Boe was due primarily to higher sales volumes, partially offset by higher total costs for the nine months ended September 30, 2021,  compared to the same period of 2020. 

 

Production and Ad Valorem Taxes. Production and ad valorem taxes for the nine months ended September 30, 2021 increased to $4.6  million from $3.6 million for the same period of 2020.  Production and ad valorem taxes for the nine months ended September 30, 2021 were.8% of total oil, gas and NGL sales compared to 12% for the same period of 2020. The higher percentage of revenue in 2020 was due to ad valorem taxes that do not fluctuate with production volumes. the decrease for the nine months ended September 30, 2021 was primarily due to higher commodity prices compared to the same period in 2020 and increased production in Texas which has a lower tax rate..

 

General and Administrative (G&A) Expense. G&A expenses, excluding stock-based compensation, was essentially flat at approximately  $5.5 million for the nine months ended September 30, 2021  and  2020. G&A expense per Boe, excluding stock-based compensation, was $3.55 for the quarter ended September 30, 2021 compared to $4.39 for the same period of  2020. The decrease per Boe was primarily due to  higher sales volumes. 

 

Stock-Based Compensation. Options granted to employees and directors are valued at the date of grant and expense is recognized over the options' vesting period. In addition to options, restricted shares of our common stock have been granted and are valued at the date of grant and expense is recognized over their vesting period. For the nine months ended September 30, 2021, stock-based compensation expense was $0.8 million compared to $0.9 million for the same period of 2020. The decrease was primarily due to the cancellation, forfeiture of restricted stock and options. Substantially all expense related to stock options, restricted stock and performance based shares has been  fully amortized with no new grants having been issued during the nine months ended September 30, 2021.

 

 

Depreciation, Depletion and Amortization (DD&A) Expense. DD&A expense, excluding accretion of future site development, for the nine months ended September 30, 2021  decreased to $11.7 million from  $18.7 million for the same period of 2020. The decrease was primarily due to lower future development cost included in the September 30, 2021 internal reserve report.  DD&A expense per Boe for the nine months ended September 30, 2021 was $7.59 compared to $14.82 in the same period of  2020. The decrease in DD&A expense per Boe was primarily due to a lower full cost pool as the result of the impairment incurred during 2020. 

 

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 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 flow from operating activities. However, such write-downs do impact the amount of our stockholders' equity and reported earnings. As of September 30, 2021, our net capitalized costs of oil and gas properties did not exceed the cost ceiling of our estimated proved reserves.  As of  September 30, 2020, our net capitalized costs of oil and gas properties exceeded the cost ceiling of our estimated proved reserves, resulting in the recognition of an impairment of $136.1  million for the nine months ended September 30, 2020.

 

The risk that we will be required to write-down the carrying value of our oil and gas assets increases when oil and gas prices are depressed or volatile. In addition, write-downs may occur if we have substantial downward revisions in our estimated proved reserves. We cannot assure you that we will not experience additional write-downs in the future. The volatility in commodity prices due to COVID-19 and geopolitical issues affecting supply and demand, may result in our proved reserves being revised downward, requiring  further write-down of the carrying value of our oil and gas properties during the remainder of 2021.

 

Interest Expense. Interest expense for the nine months ended September 30, 2021 increased to $21.7 million compared to $15.5 million for the same period of 2020. The increase in interest expense in 2021 was due to higher levels of debt during the nine months ended September 30, 2021,  compared to the same period in 2020, as well as higher overall interest rates in 2021 compared to 2020. For the nine months ended September 30, 2021, the interest rate on our First Lien Credit Facility averaged 5.8%  compared to 4.3%  for the same period of 2020. For the nine months ended September 30, 2021, and September 30, 2020 the interest rate on our Second Lien Credit Facility averaged  15.8%, We anticipate higher interest rates and increased interest expense in the future as a result of the amendments to our credit facilities. For the nine months ended September 30, 2021, approximately $14.4 million of the interest paid on the Second Lien Credit Facility was paid in kind.

 

Loss (Gain) on Derivative Contracts. Derivative 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 at period end. We have elected not to apply hedge accounting to our derivative contracts; therefore, fluctuations in the market value of the derivative contracts are recognized in earnings during the current period. Our derivative contracts consisted of NYMEX-based fixed price swaps and basis differential swaps as of September 30, 2021, and September 30, 2020. The net estimated value of our commodity derivative contracts was a liability of approximately $2.0 million as of September 30, 2021. When our derivative contract prices are higher than prevailing market prices, we incur gains and, conversely, when our derivative contract prices are lower than prevailing market prices, we incur losses. For the nine months ended September 30, 2021, we recognized a loss on our commodity derivative contracts of $18.7  million including a loss of  $7.1 million as a result of the termination of our derivative contracts in April 2021. For the nine months ended September 30, 2020, we recognized a gain on our commodity derivative contracts of $53.2 million.

 

Income Tax Expense. For the nine months ended September 30, 2021 and September 30, 2020, there was no income tax expense recognized due to our NOL carryforwards. The CARES Act, that was enacted March 27, 2020 includes income tax provisions that allow net operating losses (NOLs) to be carried back, allows interest expense to be deducted up to a higher percentage of adjusted taxable income, and modifies tax depreciation of qualified improvement property, among other provisions.  These provisions did not have a material impact on the Company.

 

 

Liquidity and Capital Resources

 

General. The oil and gas industry is a highly capital intensive and cyclical business. Our capital requirements are driven principally by our obligations to service debt and to fund the following:

 

 

the development and exploration of existing properties, including drilling and completion costs of wells;

 

•  

acquisition of interests in additional oil and gas properties; and

 

production and transportation facilities.

 

The amount of capital expenditures we are able to make has a direct impact on our ability to increase cash flow from operations and, thereby, will directly affect our ability to service our debt obligations and to grow the business through the development of existing properties and the acquisition of new properties. Due to the drastic decrease in oil prices that began in early March 2020  as a result of  the OPEC price war and the COVID-19 pandemic, we suspended capital expenditures for 2020 and 2021. Additionally, our amended credit facilities limit capital expenditures to an aggregate of  $3.0 million for the trailing four quarters.

 

Our principal sources of capital are cash flows from operations, proceeds from the sale of properties, and if an opportunity presents itself, the sale of debt or equity securities, although we may not be able to sell properties or complete any financings on terms acceptable to us, if at all. We believe that our cash flow from these sources going forward, will be adequate to fund our operations. In June 2020, our First Lien Credit Facility was amended and has no further 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. 

 

Working Capital (Deficit). At September 30, 2021, our current liabilities of  $237.0 million exceeded our current assets $24.9  million, resulting in a working capital deficit of $212.1 million. This compares to a working capital deficit of $195.3 million at December 31, 2020. Current assets as of September 30, 2021 primarily consisted of cash of $9.1 million, accounts receivable of $14.8 million and other current assets of $1.0 million. Current liabilities at September 30, 2021 primarily consisted of trade payables of $2.1 million, revenues due third parties of $12.8 million, current maturities of long-term debt of $209.4 million, the current portion of our derivative liability of $2.0 million, accrued interest of  $0.5 million, hedge liability resulting from termination of derivative contracts of  $9.2 million and other accrued expenses of $0.9 million. 

 

Capital Expenditures. Capital expenditures for the nine months ended September 30, 2021 and 2020 were $0.9 million and $6.6 million, respectively.

 

The table below sets forth the components of these capital expenditures:

 

   

Nine Months Ended September 30,

 
   

2021

   

2020

 
   

(In thousands)

 

Expenditure category:

               

Exploration/Development

  $ 850     $ 6,410  

Facilities and other

    6       158  

Total

  $ 856     $ 6,568  

 

During the nine months ended September 30, 2021 and 2020, our capital expenditures were primarily on our existing properties.  Cash basis capital expenditures for the nine months ended September 30, 2021 of $856,000 includes $28,000 for a decrease in capital expenditures in accounts payable, and a decrease in future site restoration of $2.7 million, resulting in net accrual basis capital expenditures of ($1.9)  million.  As previously described, our amended credit facilities limit capital expenditures to $3.0 million for any four consecutive quarters beginning with the quarter ended June 30, 2020.  Based on our  capital expenditure limits,  the Company will not be able to offset oil and gas production decreases caused by natural field declines.

 

 

Sources 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: 

 

   

Nine Months Ended September 30,

 
   

2021

   

2020

 
   

(In thousands)

 

Net cash provided by operating activities

  $ 19,876     $ 10,734  

Net cash used in investing activities

    (483 )     (13,187 )

Net cash (used in) provided by financing activities

    (13,117 )     3,036  

Total

  $ 6,276     $ 583  

 

Operating activities for the nine months ended September 30, 2021 provided  $19.9 million in cash compared to providing $10.7 million in the same period of 2020.  Losses on derivatives, non-cash interest expense, non-cash termination of hedge liability, and changes in operating assets and liabilities accounted for most of these funds. Investing activities used $483,000 during the nine months ended September 30, 2021, primarily on our existing properties. Investing activities also included a reduction in future site restoration of  related to assets sold of $2.7 million and a reduction in accounts payable related to capital expenditures of $0.03 million. Investing activities used $13.2 million during the nine months ended September 30, 2020, primarily for the development of our existing properties. Financing activities used $13.1 million for the nine months ended September 30, 2021 compared to providing $3.0 million for the same period of 2020. Funds used during the three months ended  September 30, 2021 were payments on long term debt. Funds provided during the nine months ended September 30, 2020  were primarily net proceeds from borrowings under our credit facility. 

  

Future Capital Resources.

 

 Our principal sources of capital going forward, are cash flows from operations, proceeds from the sale of properties 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, and

 

Operating leases.

 

Below is a schedule of the future payments that we are obligated to make based on agreements in place as of September 30, 2021:

 

   

Payments due in twelve month periods ending:

 

Contractual Obligations

 

Total

   

September 30, 2022

   

September 30, 2023-2024

   

September 30, 2025-2026

   

Thereafter

 

Long-term debt (1)

  $ 230,558     $ 228,274     $ 2,284     $ -     $