ABRAXAS PETROLEUM CORPORATION The following is a discussion of our consolidated financial condition, results of operations, liquidity and capital resources. This discussion should be read in conjunction with our Consolidated Financial Statements and the Notes thereto. See "Financial Statements and Supplementary Data" in Item 8. General We are an independent energy company primarily engaged in the acquisition, exploration, exploitation, development and production of oil and gas inthe United States . Historically, we have grown through the acquisition and subsequent development and exploitation of producing properties, principally through the redevelopment of old fields utilizing new technologies such as modern log analysis and reservoir modeling techniques as well as 3-D seismic surveys and horizontal drilling. As a result of these activities, we believe that we have a number of development opportunities on our properties. In addition, we intend to expand upon our development activities with complementary acreage acquisitions in our core areas of operation. Success in our development and exploration activities is critical in the maintenance and growth of our current production levels and associated reserves.
Our financial results depend upon many factors which significantly affect our results of operations including the following:
• commodity prices and the effectiveness of our hedging arrangements; • the level of total sales volumes of oil and gas;
• the availability of and our ability to raise additional capital resources and
provide liquidity to meet cash flow needs;
• the level of and interest rates on borrowings; and
• the level and success of exploration and development activity.
Commodity Prices and Hedging Arrangements. The results of our operations are
highly dependent upon the prices received for our oil and gas production. The
prices we receive for our production are dependent upon spot market prices,
differentials and the effectiveness of our derivative contracts, which we
sometimes refer to as hedging arrangements. Substantially all of our sales of
oil and gas are made in the spot market, or pursuant to contracts based on spot
market prices, and not pursuant to long-term, fixed-price contracts.
Accordingly, the prices received for our oil and gas production are dependent
upon numerous factors beyond our control. Significant declines in prices for oil
and gas could have a material adverse effect on our financial condition, results
of operations, cash flows and quantities of reserves recoverable on an economic
basis.
Oil and gas prices have been volatile, and this volatility is expected to
continue. As a result of the many uncertainties associated with the world
political environment, worldwide supplies of oil, NGL and gas, the availability
of other worldwide energy supplies and the relative competitive relationships of
various energy sources in the view of consumers, we are unable to predict what
changes may occur in oil, NGL, and gas prices in the future. The market price
of oil, NGL and gas in 2022 will impact the amount of cash generated from
operating activities, which will in turn impact our financial position. As of
March 18, 2022 , the NYMEX oil and gas price was $104.70 per Bbl of oil
and $4.86 per Mcf of gas, respectively.
During 2021, the NYMEX future price for oil averaged $68.11 per barrel as
compared to $39.57 per barrel in 2020 and the NYMEX future spot price for gas
averaged $3.73 per Mcf compared to $2.13 per Mcf in 2020. Prices closed
on December 31, 2021 at $75.21 per Bbl of oil and $3.73 per Mcf of gas. If
commodity prices decline from these levels, our revenue and cash flows from
operations will also likely decline. In addition, lower commodity prices could
also reduce the amount of oil and gas that we can produce economically. If oil
and gas prices decline, our revenues, profitability and cash flows from
operations will also likely decrease which could cause us to alter our business
plans, including reducing our drilling activities. Such declines will require us
to write down the carrying value of our oil and gas assets which will also cause
a reduction in net income.
The realized prices that we receive for our production differ from NYMEX futures and spot market prices, principally due to:
• basis differentials which are dependent on actual delivery location; • adjustments for BTU content; • quality of the hydrocarbons; and • gathering, processing and transportation costs.
The following table sets forth our average differentials for the years ended
Oil Gas
2020 2021 2020 2021
Average realized price $ 37.05 $ 63.98 $ 0.27 $ 2.52
Average NYMEX price $ 39.57 $ 68.11 $ 2.13 $ 3.73
Differential $ (2.52 ) $ (4.13 ) $ (1.86 ) $ (1.21 )
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(1) Average realized prices are before the impact of hedging activities. The Company's derivative contracts as ofDecember 31, 2020 and during 2021 consisted of NYMEX-based fixed price swaps and basis differential swaps. Under fixed price swaps, we receive a fixed price for our production and pay a variable market price to the contract counter-party. All derivative contracts were cancelled or expired in 2021. 39 --------------------------------------------------------------------------------
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InApril 2021 , we received notice that certain of our hedging agreements were being terminated as a result of events of default under the FirstLien Credit Facility, and we voluntarily terminated most of our other hedging arrangements. As a result of the settlement of the terminated hedges, we had outstanding obligations of$8.0 million . The settlement values of the terminated hedges were determined at various datesbetween April 15 and April 30, 2021 . These obligations were added to the balance of the FirstLien Credit Facility and accrued interest at the default interest rate of 8.75%, until they were repaid. Our remaining hedging agreement expired onDecember 31, 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 ofDecember 31, 2021 , our average annual estimated decline rate for our net proved developed producing reserves is 20%, 15% , 13% , 12% and 11% in 2022, 2023, 2024, 2025 and 2026, respectively, 9% in the following five years, and approximately 10% thereafter. These rates of decline are estimates and actual production declines could be materially higher. While we have had some success in finding, acquiring and developing additional reserves, we have not always been able to fully replace the production volumes lost from natural field declines and property sales. Our ability to acquire or find additional reserves in the future will be dependent, in part, upon the amount of available funds for acquisition, exploration and development projects. In addition to our ability to successfully drill wells, we must also market our production which depends substantially on the availability, proximity and capacity of gathering systems, pipelines and processing facilities, which are also known as midstream facilities, owned and operated by third parties. If adequate midstream facilities and services are not available to us on a timely basis and at acceptable costs, our production and results of operations could be adversely affected. Our principal areas of operation have experienced substantial development in recent years, and this has made it more difficult for providers of midstream infrastructure and services to keep pace with the corresponding increases in field-wide production. The ultimate timing and availability of adequate infrastructure is not within our control and we could experience capacity constraints for extended periods of time that would negatively impact our ability to meet our production targets. Weather, regulatory developments and other factors also affect the adequacy of midstream infrastructure. We had cash capital expenditures during 2021 of approximately$0.9 million . Due to lack of capital we suspended our planned capital expenditures for 2021. This suspension of our capital expenditure budget is subject to change depending upon a number of factors, including the availability and costs of drilling and service equipment and crews, economic and industry conditions at the time of drilling, prevailing and anticipated prices for oil and gas, the availability of sufficient capital resources the results of our exploitation efforts, our financial results and our ability to obtain permits for drilling locations.
The following table presents historical net production volumes for the years
ended
2020 2021
Total Production (Mboe) 1,801 2,023
Average daily production (Boepd) 4,922 5,545
% Oil 63 % 47 %
Availability of Capital. As described more fully under "Liquidity and Capital
Resources" below, our sources of capital are cash flows from operating
activities, cash on hand, proceeds from the sale of properties, monetizing of
derivative instruments, and if an appropriate opportunity presents itself, the
sale of debt or equity securities, although we may not be able to complete any
financing on terms acceptable to us, if at all.
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Borrowings and Interest. AtDecember 31, 2021 , we had a total of$71.4 million outstanding under our First Lien Credit Facility,$134.9 million under our Second Lien Credit Facility, and total indebtedness of$218.8 million , including a$10.0 million exit fee. Our First Lien Credit Facility was settled inJanuary 2022 with proceeds from a property sale of the same date. OnJanuary 3, 2022 our Second Lien Credit Facility and exit fee were converted to preferred stock, resulting in the Company having no debt, except the Real Estate Lien note on our headquarters building Exploration and Development Activity. We believe that our asset base, high degree of operational control and inventory of drilling projects position us for future growth. AtDecember 31, 2021 , we operated properties comprising approximately 97% of the Boe's of our estimated net proved reserves, giving us substantial control over the timing and incurrence of operating and capital expenditures. We have identified numerous additional drilling locations on our existing leaseholds, the successful development of which we believe could significantly increase our production and proved reserves. Over the five years endedDecember 31, 2021 , we drilled or participated in 92 gross (42.8 net) wells all of which were commercially productive. Our future oil and gas production, and therefore our success, is highly dependent upon our ability to find, finance, acquire and develop additional reserves that are profitable to produce. The rate of production from our oil and gas properties and our proved reserves will decline as our reserves are produced unless we acquire additional properties containing proved reserves, conduct successful development and exploration activities or, through engineering studies identify additional behind-pipe zones or secondary recovery reserves. We cannot assure you that our exploration and development activities will result in increases in our proved reserves. If our proved reserves decline in the future, our production may also decline and, consequently, our cash flows from operations will decline. We may be unable to acquire or develop additional reserves, in which case our results of operations and financial condition could be adversely affected. Results of Operations Year Ended December 31, (in thousands) 2020 2021 Operating revenue (1): Oil sales$ 41,969 $ 61,228 Gas sales 586 8,656 NGL sales 429 8,952 Other income 59 22 Total revenues$ 43,043 $ 78,858 Operating (loss) income$ (199,418 ) $ 30,484 Oil sales (MBbls) 1,133 957 Gas sales (MMcf) 2,134 3,432 NGL sales (MBbls) 313 495 Oil equivalents (MBoe) 1,801 2,023 Average oil sales price (per Bbl)(1)$ 37.05 $ 63.98 Average gas sales price (per Mcf) $ 0.27$ 2.52 Average NGL price (per Bbl) $ 1.37$ 18.09
Average oil equivalent sales price (per Boe)
(1) Revenue and average sales prices are before the impact of hedging activities,
if applicable.
Comparison of Year Ended
Revenue. During the year endedDecember 31, 2021 , revenue increased to$78.9 million from$43.0 million in 2020. Higher commodity prices for all products in 2021 contributed$41.8 million to revenue. Lower oil sales volumes negatively impacted revenue by$6.5 million , partially offset by higher gas and NGL volumes which contributed$0.6 million to revenue. Oil sales volumes decreased to 957 MBbls for the year endedDecember 31, 2021 from 1,133 MBbls for the same period of 2020. The decrease in oil sales volumes was primarily due to natural field declines and the sale of various non-operated properties in 2021, partially offset by wells that were shut-in in early 2020 due to low prices being back on production in 2021. No new wells were brought on line in 2021. Gas sales volumes increased to 3,432 MMcf for the year endedDecember 31, 2021 compared to 2,134 MMcf for the year endedDecember 31, 2020 . NGL sales increased to 495 MBbls for the year endedDecember 31, 2021 compared to 313 MBbls for the same period of 2020. The increase in gas and NGL volumes was primarily due to wells that were shut in during early 2020 being back on production in 2021. Lease Operating Expenses ("LOE"). LOE for the year endedDecember 31, 2021 increased to$17.9 million from$16.5 million in 2020. The increase in LOE was primarily due to the increased cost of wells brought back on production that were shut in during the first part of 2020. LOE per Boe for the year endedDecember 31, 2021 was$8.85 compared to$9.14 for the same period of 2020. The decrease in LOE per Boe was attributable to higher sales volumes in 2021 as compared to 2020. 41 --------------------------------------------------------------------------------
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Production and Ad Valorem Taxes. Production and ad valorem taxes for the year endedDecember 31, 2021 increased to$6.2 million from$4.6 million in 2020. The increase was primarily due to higher realized prices and sales volumes in 2021 as compared to 2020. Production and ad valorem taxes as a percentage of oil and gas revenue were 8% in 2021 compared to 11% for the same period of 2020. The decrease in ad valorem taxes as a percentage of revenue was primarily due increased production inTexas , which has a lower tax rate. General and Administrative ("G&A") Expense. G&A expense, excluding stock-based compensation, decreased to$7.2 million for the year endedDecember 31, 2021 from$7.5 million in 2020. G&A expense per Boe was$3.54 for the year endedDecember 31, 2021 compared to$4.15 for the same period of 2020. The reduction in total G&A expense was primarily due to a reduction in personnel in the corporate office, as well as reductions in salaries. Officer salaries were reduced by 20% effectiveMarch 1, 2020 , and our CEO took an additional 20% reduction in salary effectiveApril 1, 2020 . The decrease per Boe was primarily due to higher sales volumes. Stock-Based Compensation. Restricted stock, stock options and performance based restricted stock granted to employees and directors are valued at the date of grant and expense is recognized over the securities vesting period. Stock-based compensation decreased to$0.9 million for the year endedDecember 31, 2021 compared to$1.3 million for the same period of 2020. The decrease was primarily due to the cancellation, forfeiture, and expiration of stock options as well as a significant portion of stock grants having been fully amortized with no awards having been granted in 2020 or 2021. Depreciation, Depletion, and Amortization ("DD&A") Expenses. DD&A expense excluding accretion of future site restoration, decreased to$15.3 million for the year endedDecember 31, 2021 from$24.4 million in 2020. The decrease was primarily due to lower future development cost included in theDecember 31, 2021 reserve report, due to the exclusion of the development cost of PUDs. The full cost pool was also reduced by significant impairments in 2020. DD&A expense per Boe for the year endedDecember 31, 2021 was$7.57 compared to$13.56 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 as ofDecember 31, 2019 and in 2020. Interest Expense. Interest expense increased to$35.8 million in 2021 from$21.3 million for 2020. The increase was primarily due to higher debt levels in 2021 as compared to 2020, as well as higher overall interest rates in 2021 as compared to 2020. In 2021, the interest rate on our FirstLien Credit facility averaged 6.2% as compared to 3.6% in 2020. The average interest rate on the Second Lien Credit Facility for the year endedDecember 31, 2021 was 16.4% as compared to 15.8% in 2020.$22.2 million of interest on the SecondLien Credit Facility was paid in kind in 2021 compared to$12.7 million in 2020. Default interest was charged on both the First Lien and Second Lien Credit Facilities beginning inApril 2021 as a result of the default that occurred.
Income Taxes. Due to losses in the periods and loss carry forwards, we did not
recognize any income tax expense for the years ended
(Gain) loss on Derivative Contracts. Derivative gains or losses are determined by actual derivative settle"ments during the period and by periodic mark to market valuation of derivative contracts in place. We have elected not to apply hedge accounting to our derivative contracts as prescribed by Accounting Standards Codification 815, Derivatives and Hedging "ASC 815", therefore, fluctuations in the market value of the derivative contracts are recognized in earnings during the current period. Our derivative contracts consisted of fixed price swaps and basis differential swaps in 2021 and 2020. The net estimated value of our commodity derivative contracts was a liability of approximately$0.4 million as ofDecember 31, 2021 . When our derivative contract prices are higher than prevailing market prices, we recognize gains and conversely, when our derivative contract prices are lower than prevailing market prices, we incur losses. For the year endedDecember 31, 2021 , we incurred a loss of$33.0 million , including a loss of$7.1 million related to cancelled contracts. For the year endedDecember 31, 2020 , we recognized a gain on our derivative contracts of$42.9 million . Ceiling Limitation Write-Down. We record the carrying value of our oil and gas properties using the full cost method of accounting for oil and gas properties. Under this method, we capitalize the cost to acquire, explore for and develop oil and gas properties. Under the full cost accounting rules, the net capitalized cost of oil and gas properties less related deferred taxes, are limited by country, to the lower of the unamortized cost or the cost ceiling, defined as the sum of the present value of estimated unescalated future net revenues from proved reserves, discounted at 10%, plus the cost of properties not being amortized, if any, plus the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any, less related income taxes. If the net capitalized cost of oil and gas properties exceeds the ceiling limit, we are subject to a ceiling limitation write-down to the extent of such excess. A ceiling limitation write-down is a charge to earnings which does not impact cash flows from operating activities. However, such write-downs do impact the amount of our stockholders' equity and reported earnings. For the year endedDecember 31, 2021 , the net capitalized cost of our oil and gas properties did not exceed the future net revenues from our estimated proved reserves. For the year endedDecember 31, 2020 , the net capitalized cost of our oil and gas properties exceeded the future net revenues from our estimated proved reserves resulting in the recording of an impairment of$187.0 million during 2020. The year-end amounts were calculated in accordance withSEC rules utilizing the twelve month first-day-of-the-month average oil and gas prices utilized for the year ended 2021 which were$62.00 per Bbl of oil and$1.56 per Mcf of gas as adjusted to reflect the expected realized prices for our oil and gas reserves. The twelve month first-day-of-the-month average oil and gas prices utilized for the year ended 2020 were$39.54 per Bbl of oil and$2.03 per Mcf of gas as adjusted to reflect the expected realized prices for our oil and gas reserves. 42
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Working Capital (Deficit). AtDecember 31, 2021 , our current liabilities of$240.0 million exceeded our current assets of$24.1 million resulting in a working capital deficit of$216.0 million . This compares to a working capital deficit of$195.3 million atDecember 31, 2020 . Current assets atDecember 31, 2021 primarily consisted of cash of$10.0 , accounts receivable of$13.5 million , and other current assets of$0.5 million . Current liabilities atDecember 31, 2021 primarily consisted of trade payables of$4.7 million , revenues due third parties of$13.3 million , current maturities of long-term debt of$212.7 million , the then-current amount of our derivative liability of$0.4 million and termination fee for derivative contracts of$8.0 million , and accrued expenses of$0.8 million . Capital Expenditures. Capital expenditures in 2020 and 2021 were$5.4 million and$1.3 million , respectively. The table below sets forth the components of these capital expenditures: Years Ended December 31, 2020 2021 (in thousands) Expenditure category: Exploration/Development$ 5,238 $ 1,145 Acquisitions - - Facilities and other 162 180$ 5,400 $ 1,325 During 2020 and 2021 capital expenditures were primarily expenditures on our existing properties. We also performed extensive workovers on several wells in 2020. The level of capital expenditures will vary during future periods depending on economic and industry conditions and commodity prices. Should the prices of oil and gas decline and if our costs of operations increase or if our production volumes decrease, our cash flows from operations will decrease which may result in a reduction of capital expenditure. Due to capital expenditure limits imposed by our credit facilities, we have not adopted a capital drilling budget for 2022. If we cannot incur significant capital expenditure, we will not be able to offset oil and gas production decreases caused by natural field declines.
Sources and Uses of Capital. The net funds provided by and/or used in each of the operating, investing and financing activities are summarized in the following table and discussed in further detail below:
Years Ended December 31,
2020 2021
(in thousands)
Net cash provided by operating activities $ 15,985 $ 32,419
Net cash (used in) investing activities (12,557 ) (518 )
Net cash (used in) provided by financing activities (653 ) (24,642 )
$ 2,775 $ 7,259
Operating activities for the year ended December 31, 2021 provided $32.4 million
in cash compared to $16.0 million in 2020. The increase was primarily due to
lower net loss due to higher commodity prices and production volumes. Investing
activities used $0.5 million in 2021 primarily for the development of our
existing properties. Cash expenditures for the year ended December 31, 2021
included a decrease of $2.2 million in the future site restoration
account related to properties sold, and proceeds from sales on non-oil and gas
and oil and gas properties of $0.9 million and an increase in accounts payable
related to capital expenditures of $0.05 million resulting in accrual
based capital expenditures incurred during the period of $1.3 million .
Operating activities for the year ended December 31, 2020 provided $16.0 million
in cash. The reduction from 2019 was primarily due to lower net income due to
lower commodity prices and lower production volumes. Investing activities
used $12.6 million in 2020, primarily for the development of our existing
properties. Cash expenditures for the year ended December 31, 2020
included a decrease in the accounts payable balance related to capital
expenditures of $7.2 million , resulting in accrual based capital expenditures
incurred during the period of $5.4 million .
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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
Below is a schedule of the future payments that we are obligated to make based
on agreements in place as of
Payments due in the twelve month periods ended:
Contractual Obligations December 31, December 31, December 31,
(In thousands) Total 2022 2023-2024 2025-2026 Thereafter
Long-term debt (1),(4) $ 226,844 $ 224,639 $ 2,205 $ - $ -
Interest on long-term
debt (2), (4) 2,781 2,723 58 - -
Paid in kind interest on
long-term debt (3) 22,133 22,133 - - -
Lease obligations 218 48 68 8 94
Total $ 251,976 $ 249,543 $ 2,331 $ 8 $ 94
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(1) These amounts represent the balances outstanding under our credit
facilities and the real estate lien note. These payments assume that we will
not borrow additional funds.
(2) Interest expense assumes the balances of long-term debt at
current effective interest rates at that time.
Represents interest expense paid in kind on our Second Lien Credit Facility.
(3) Accrued interest was added to the outstanding balance and was payable at
maturity.
Our First Lien Credit Facility was retired, and our Second
(4) Facility was converted to Series A Preferred Stock on
connection with the restructuring and change in control that occurred on the
same date.
We maintain a reserve for costs associated with the retirement of tangible
long-lived assets. At December 31, 2021 , our reserve for these obligations
totaled $4.7 million for which no contractual commitments exist. For additional
information relating to this obligation, see Note 1 of the Notes to Consolidated
Financial Statements.
Off-Balance Sheet Arrangements. At December 31, 2021 , we had no existing
off-balance sheet arrangements, as defined under SEC regulations, that have, or
are reasonably likely to have a current or future material effect on our
financial condition, revenues or expenses, results of operations, liquidity,
capital expenditures or capital resources that are material to investors.
Contingencies. From time to time, we are involved in litigation relating to
claims arising out of our operations in the normal course of business. At
Long-Term Indebtedness.
Long-term debt consisted of the following:
Years Ended December 31,
2020 2021
(In thousands)
First Lien Credit Facility $ 95,000 $ 71,400
Second Lien Credit Facility 112,695 134,907
Exit fee - Second Lien Credit Facility 10,000 10,000
Real estate lien note 2,810 2,515
220,505 218,822
Less current maturities (202,751 ) (212,688 )
17,754 6,134
Deferred financing fees and debt issuance cost - net (15,239 ) (3,929 )
Total long-term debt, net of deferred financing fees and
debt issuance costs $ 2,515 $ 2,205
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The following sections regarding the First Lien Credit Facility and Second Lien Credit Facility are qualified in their entirety by the disclosure contained in Item 1. Business, Recent Activity, which is expressly incorporated in the sections below. Due to certain covenant violations as ofDecember 31, 2020 , and the then-potential for future violations, all of the debt related to our credit facilities has been classified as current liabilities. In connection with the restructuring that was completed onJanuary 3, 2022 , our FirstLien Credit Facility was retired and our Second Lien Credit Facility was converted to Series A Preferred Stock. See Note 14 "Subsequent Events."
First Lien Credit Facility
Prior toJanuary 3, 2022 the Company had a senior secured FirstLien Credit Facility with Société Générale, as administrative agent and issuing lender, and certain other lenders. As ofDecember 31, 2021 ,$71.4 million was outstanding under the First Lien Credit Facility. Outstanding amounts under the First Lien Credit Facility accrued interest at a rate per annum equal to (a)(i) for borrowings that we elected 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 elected to accrue interest at the Eurodollar rate, LIBOR plus 2.5%-3.5% depending on the utilization of the borrowing base, and (b) at any time an event of default existed, 3.0% plus the amounts set forth above. AtDecember 31, 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 wasMay 16, 2022 . Interest was payable quarterly on reference rate advances and not less than quarterly on LIBOR advances. The Company was permitted to terminate the First Lien Credit Facility and was 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 guaranteed our obligations under the First Lien Credit Facility on a senior secured basis. Obligations under the First Lien Credit Facility were 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 ofDecember 31, 2020 , the collateral was 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 was subject to customary covenants, including financial covenants and reporting covenants. The amendment to the First Lien Credit Facility datedJune 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 theCompany, (B) the PV-9 of the Company's hydrocarbon hedge agreements and (C) the PV-15 of proved reserves of the Company classified as "drilled uncompleted" (up to 20% of the sum of (A), (B) and (C)) to the outstanding debt of the First Lien Credit Facility and requiring that the ratio exceed 1.15 to 1.00 as of the last day of each fiscal quarter ending on or beforeDecember 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 endedJune 30, 2020 and calculated on an annualized basis for the 1, 2 and 3 quarter periods ending onJune 30, 2020 ,September 30, 2020 andDecember 31, 2020 , respectively, subject to certain exceptions, including capital expenditures financed with the proceeds of newly permitted, structurally subordinated debt and capital expenditures made when (1) the first lien asset coverage ratio is at least 1.60 to 1.00, (2) the Company is in compliance with the first lien leverage ratio, (3) the amounts outstanding under the First Lien Credit Facility are less$50.0 million , (4) no default exists under the FirstLien Credit Facility and (5) and all representations and warranties in the FirstLien 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 could make or become legally obligated to make in any four fiscal quarter period to$9.0 million for the four fiscal quarter period endedJune 30, 2020 ,$8.25 million for the four fiscal quarter period endedSeptember 30, 2020 ,$6.9 million for the four fiscal quarter period endedDecember 31, 2020 , and$6.5 million for the fiscal quarter fromMarch 31, 2021 throughDecember 31, 2021 and$5.0 million thereafter; in all cases, general and administrative expense excluded 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 . Prior to retirement, the borrowing base was reduced by any mandatory prepayments from excess cash flow. 45
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As ofDecember 31, 2021 , we were not in compliance with the financial covenants under the First Lien Credit Facility, as amended. In connection with the restructuring that was completed onJanuary 3, 2022 , our FirstLien Credit Facility was retired and our Second Lien Credit Facility was converted to Series A Preferred Stock. See Note 14 "Subsequent Events."
The First Lien Credit Facility contained a number of covenants that, among other things, restricted our ability to:
• incur or guarantee additional indebtedness; • transfer or sell assets;
• pay dividends or make other distributions on capital stock or make other
restricted payments;
• engage in transactions with affiliates other than on an " arm's length" basis;
• make any change in the principal nature of our business; and • permit a change in control The First Lien Credit Facility also contained 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 occurred, or were reasonably likely to occur, under the First Lien Credit Facility as a result of (i) our failure to timely deliver audited financial statements without a "going concern" or like qualification for the fiscal year endedDecember 31, 2020 , (ii) our inability to comply with the first lien debt to consolidated EBITDAX ratio for the fiscal quarter endedDecember 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 could have occurred, as a result of the events of default under the FirstLien 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 OnNovember 13, 2019 , we entered into the Term Loan Credit Agreement, withAngelo Gordon Energy Servicer, LLC , as administrative agent, and certain other lenders party thereto, which we refer to as the Second Lien Credit Facility. The SecondLien Credit facility was amended onJune 25, 2020 . Prior toJanuary 3, 2022 , the Second Lien Credit Facility had a maximum commitment of$100.0 million . OnNovember 13, 2019 ,$95.0 million of the net proceeds obtained from the Second Lien Credit Facility were used to permanently reduce the borrowings outstanding on the First Lien Credit Facility. As ofDecember 31, 2021 , the outstanding balance on the Second Lien Credit Facility was$144.9 million , which included a$10.0 million exit fee. In connection with the restructuring that was completed onJanuary 3, 2022 , our First Lien Credit Facility was retired and our Second Lien Credit Facility was converted to Series A Preferred Stock. See Note 14 "Subsequent Events." The stated maturity date of the Second Lien Credit Facility wasNovember 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 were permitted to prepay the loans in whole or in part, in compliance with certain notice and dollar increment requirements. Each of our subsidiaries had guaranteed our obligations under the Second Lien Credit Facility. Obligations under the Second Lien Credit Facility were secured by a first priority perfected security interest, subject to certain permitted liens, including those securing the indebtedness under the FirstLien 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 ofDecember 31, 2020 , the collateral was 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. 46
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Under the amended Second Lien Credit Facility, the Company was subject to customary covenants, including financial covenants and reporting covenants. The amendment to the Second Lien Credit Facility datedJune 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 were outstanding, scheduled payments of accrued interest under the Second Lien Credit Facility would 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 theCompany, (B) the PV-9 of the Company's hydrocarbon hedge agreements and (C) the PV-15 of proved reserves of the Company classified as "drilled uncompleted" (up to 20% of the sum of (A), (B) and (C)) to the total outstanding debt of the Company and requiring that the ratio not exceed 1.45 to 1.00 as of the last day of each fiscal quarter ending betweenSeptember 30, 2021 toDecember 31, 2021 , and 1.55 to 1.00 for fiscal quarters ending thereafter); (iv) modification of the total leverage ratio covenant to set the first test date to occur onSeptember 30, 2021 ; (v) modification of the then-current ratio to eliminate the exclusion of certain valuation accounts associated with hedge contracts from current assets and from current liabilities, (vi) additional restrictions on (A) capital expenditures (limiting capital expenditures to those expenditures set forth in a plan of development approved byAngelo 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 could make or become legally obligated to make in any four fiscal quarter period to$9.0 million for the four fiscal quarter period endedJune 30, 2020 ,$8.25 million for the four fiscal quarter period endedSeptember 30, 2020 ,$6.5 million for fiscal quarter period fromMarch 31, 2021 throughDecember 31, 2021 and$5.0 million thereafter. As ofDecember 31, 2021 , we were not in compliance with the financial covenants under the Second Lien Credit Facility, as amended. However, in connection with the restructuring that was completed onJanuary 3, 2022 our FirstLien Credit Facility was retired and our Second Lien Credit Facility was converted to Series A Preferred Stock. See Note 14 "Subsequent Events."
The Second Lien Credit Facility contained a number of covenants that, among other things, restricted 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 contained 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 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 endedDecember 31, 2020 , (ii) the Company's 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, (iv) the Company's inability to comply with the total leverage ratio for the fiscal quarter endedSeptember 30, 2021 , (v) the Company's inability to comply with minimum asset coverage ratio for the fiscal quarter endedSeptember 30, 2021 , and (vi) certain cross-defaults that occurred, or could have occurred, 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 occurred as ofSeptember 30, 2021 , as a result of our failure to comply with certain financial covenants under the Second Lien Credit Facility, as amended. 47
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OnApril 16, 2021 , we received a Notice of Default and Reservation of Rights (the "Notice of Default") from Angelo Gordon stating that we defaulted under the Second Lien Credit Facility, and that, as a result, the lenders accelerated our obligations due thereunder and reserved their rights to pursue additional remedies in the future. The Notice of Default described certain events of default that occurred under the Second Lien Credit Facility as a result of (i) our failure to file timely our Form 10-K for the fiscal year endedDecember 31, 2020 , (ii) our failure to timely deliver audited financial statements without a "going concern" or like qualification for the fiscal year endedDecember 31, 2020 , and (iii) other defaults under our revolving credit facility. The Notice of Default declared that our obligations under the SecondLien Credit Facility were immediately due and payable, in each case without presentment, demand, protest or other requirements of any kind, and began 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 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. In connection with the amendment to the Second Lien Credit Facility onJune 25, 2020 , the Company entered into an Exit Fee and Warrant Agreement subject to NASDAQ approval for the issuance of the issuance of certain warrants. This agreement was finalized onAugust 11, 2020 at which time the Company issued a warrant to the lender to purchase a total of 33,445,792 shares of common stock at an exercise price of$0.01 per share. OnOctober 19, 2020 , the Company effected a reverse stock split of the Company's authorized, issued and outstanding shares of common stock at a ratio of 1-for-20, thus the warrant was adjusted to provide that the lender may purchase a total of 1,672,290 shares of common stock at an exercise price of$0.20 per share. The warrant was exercisable immediately in whole or in part, on or before five years from the issuance date. The fair value of the warrant and exit fee were recorded as debt issuance costs, presented in the consolidated balance sheets as a deduction from the carrying amount of the note payable, and were being amortized over the loan term. The Exit Fee was due and payable in cash on the earliest to occur of maturity of the obligation under the Second Lien Credit Agreement or the earlier acceleration or payment in full of the same. The 2L Amendment, including the impact of the Exit Fee and Warrant Agreement finalized onAugust 11, 2020 , resulted in the 2L Amendment meeting the criteria of debt extinguishment under the guidance of ASC 470: Debt. Accordingly, all debt issuance cost, including the original discount, of the original Second Lien Credit Facility, were charged to debt extinguishment loss in the accompanying Condensed Consolidated Statement of Operation in the amount of$4.1 million . Subsequently, pursuant to a waiver letter datedNovember 22, 2021 from AGEF to Abraxas, AGEF waived, relinquished, and abandoned all of its rights, title, and interest to the Warrant and any Common Stock underlying the Warrant for no consideration. Real EstateLien Note We have a real estate lien note secured by a first lien deed of trust on the property and improvements which serves as our corporate headquarters. The outstanding principal accrues interest at a fixed rate of 4.9%. The note is payable in monthly installments of principal and interest in the amount of$35,672 . The maturity date of the note isJuly 20, 2023 . As ofDecember 31, 2020 , and 2021,$2.8 million and$2.5 million , respectively, were outstanding on the note.
Net Operating Loss Carryforwards
AtDecember 31, 2021 , we had, subject to the limitation discussed below,$245.20 million of pre 2021 NOLs forU.S. tax purposes and a$190.8 million NOL for 2021. Our pre-2018 NOLs will expire in varying amounts from 2023 through 2037, if not utilized; and can offset 100% of future taxable income for regular tax purposes. Any NOLs arising in 2018, 2019 and 2020 can generally be carried back five years, carried forward indefinitely and can offset 100% of future taxable income for tax years beforeJanuary 1, 2021 and up to 80% of future taxable income for tax years afterDecember 31, 2020 . Any NOLs arising on or afterJanuary 1, 2021 , cannot be carried back and can generally be carried forward indefinitely and can offset up to 80% of future taxable income for regular tax purposes, (the alternative minimum tax no longer applies to corporations afterJanuary 1, 2018 ).
Uncertainties exist as to the future utilization of the operating loss
carryforwards under the criteria set forth under ASC 740-10 "Income Taxes".
Therefore, we have established a valuation allowance of
Related Party Transactions
We have adopted a policy that transactions between us and our officers,
directors, principal stockholders, or affiliates of any of them, will be on
terms no less favorable to us than can be obtained on an arm's length basis in
transactions with third parties and must be approved by our audit committee.
There were no related party transactions in 2020 or 2021.
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--------------------------------------------------------------------------------Table of Contents Critical Accounting Policies The preparation of financial statements in conformity withU.S. generally accepted accounting principles ("GAAP") requires that management apply accounting policies and make estimates and assumptions that affect results of operations and the reported amounts of assets and liabilities in the financial statements. The following represents those policies that management believes are particularly important to the financial statements and that require the use of estimates and assumptions to describe matters that are inherently uncertain. Full Cost Method of Accounting for Oil and Gas Activities. SEC Regulation S-X Rule 4-10 and ASC 932 defines the financial accounting and reporting standards for companies engaged in oil and gas activities. Two methods are prescribed: the successful efforts method and the full cost method. We have chosen to follow the full cost method under which all costs associated with property acquisition, exploration and development are capitalized. We also capitalize internal costs that can be directly identified with our acquisition, exploration and development activities but do not include any costs related to production, general corporate overhead or similar activities. Sales of oil and gas properties are treated as a reduction of the full cost pool with no gain or loss being recognized, except under certain circumstances. Under the successful efforts method, geological and geophysical costs and costs of carrying and retaining undeveloped properties are charged to expense as incurred. Costs of drilling exploratory wells that do not result in proved reserves are charged to expense. Depreciation, depletion, amortization and impairment of oil and gas properties are generally calculated on a well by well or lease or field basis versus the "full cost" pool basis. Additionally, gain or loss may be recognized on sales of oil and gas properties under the successful efforts method. As a result, our financial statements will differ from those of companies that apply the successful efforts method since we will generally reflect a higher level of capitalized costs as well as a higher depreciation, depletion and amortization rate on our oil and gas properties. At the time it was adopted, management believed that the full cost method would be preferable, as earnings tend to be less volatile than under the successful efforts method. However, the full cost method makes us susceptible to significant non-cash charges during times of volatile commodity prices because the full cost pool may be impaired when prices are low. These charges are not recoverable when prices return to higher levels. We have experienced this situation several times over the years, including a$187.0 million impairment recorded as ofDecember 31, 2020 . Our oil and gas reserves have a relatively long life. However, temporary drops in commodity prices can have a material impact on our business including impact from impairment testing procedures associated with the full cost method of accounting as discussed below. Under full cost accounting rules, the net capitalized cost of oil and gas properties, less related deferred taxes, may not exceed a "ceiling limit" which is based upon the present value of estimated future net cash flows from proved reserves on a pool by pool basis, discounted at 10%, plus the lower of cost or fair market value of unproved properties and the cost of properties not being amortized, less income taxes. If net capitalized costs of oil and gas properties exceed the ceiling limit, we must charge the amount of the excess to earnings. This is called a "ceiling limitation write-down." This charge does not impact cash flows from operating activities, but does reduce our stockholders' equity and reported earnings. The risk that we will be required to write down the carrying value of oil and gas properties increases when oil and gas prices are depressed. In addition, write-downs may occur if we experience substantial downward adjustments to our estimated proved reserves. An expense recorded in one period may not be reversed in a subsequent period even though higher oil and gas prices may have increased the ceiling applicable to the subsequent period. We apply the full cost ceiling test on a quarterly basis on the date of the latest balance sheet presented. Given the recent decline in oil prices, it is likely that we will incur future impairments.
Estimates of Proved Oil and Gas Reserves. Estimates of our proved reserves
included in this report are prepared in accordance with GAAP and
• the quality and quantity of available data; • the interpretation of that data; • the accuracy of various mandated economic assumptions; and • the judgment of the persons preparing the estimate. Our proved oil and gas reserves have been estimated by our independent petroleum engineering firm,DeGolyer & MacNaughton , as ofDecember 31, 2020 and 2021, estimates prepared by other third parties may be higher or lower than those included herein. Because these estimates depend on many assumptions, all of which may substantially differ from future actual results, reserve estimates will be different from the quantities of oil and gas that are ultimately recovered. In addition, results of drilling, testing and production after the date of an estimate may justify material revisions to the estimate. You should not assume that the present value of future net cash flows is the current market value of our estimated proved reserves. In accordance withSEC requirements, we based the estimated discounted future net cash flows from proved reserves on costs on the date of the estimate and for the years endedDecember 31, 2020 and 2021 oil and gas prices were based on the average 12-month first-day-of-the-month pricing. Actual future prices and costs may be materially higher or lower than the prices and costs used in the estimate. The estimates of proved reserves materially impact DD&A expense and the ceiling test calculation. If the estimates of proved reserves decline, the rate at which we record DD&A expense will increase and we may be required to record future impairments of the full cost pool, reducing future net income. Such a decline may result from lower market prices, which may make it uneconomic to drill for and produce higher cost fields. Asset Retirement Obligations. The estimated costs of restoration and removal of facilities are accrued. The fair value of a liability for an asset's retirement obligation is recorded in the period in which it is incurred and the corresponding cost is capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depreciated over the useful life of the related asset. For all periods presented, we have included estimated future costs of abandonment and dismantlement in our full cost amortization base and we amortize these costs as a component of our depletion expense. Accounting for Derivatives. Gains or losses are determined by actual derivative settlements during the period and on the periodic mark to market valuation of derivative contracts in place. The derivative instruments we utilize are based on index prices that may and often do differ from the actual oil and gas prices realized in our operations. We have elected not to apply hedge accounting to our derivative contracts. As a result, fluctuations in the market value of the derivative contract are recognized in earnings during the current period. In 2020 and 2021 derivative contracts consisted of fixed price swaps and basis differential swaps. Due to the volatility of oil and gas prices, our financial condition and results of operations can be significantly impacted by changes in the market value of our derivative instruments. As ofDecember 31, 2020 , and 2021, the net market value of our commodity derivatives was a net asset of$ 19.4 million and a net liability of$0.4 million , respectively. All of the Company's derivative contracts were terminated or expired during 2021. 49 --------------------------------------------------------------------------------
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Recently Issued Accounting Standards
InMarch 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 throughDecember 31, 2022 . The Company will consider this optional guidance prospectively, if applicable. InMay 2020 , theSEC 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 effectiveJanuary 1, 2021 , but earlier compliance is permitted. The Company will consider these final rules and update its disclosures, as applicable.
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