ABRAXAS PETROLEUM CORPORATION 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 endedDecember 31, 2021 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 endedDecember 31, 2021 filed with theSEC onMarch 31, 2022 . 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
General
We are an independent energy company primarily engaged in the
acquisition, development and production of oil and gas in
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. Restructuring Pursuant to the Exchange Agreement, dated as ofJanuary 3, 2022 , between Abraxas and AGEF and certain other agreements entered into by Abraxas onJanuary 3, 2022 , we effectuated a restructuring of our then-existing indebtedness through a multi-part interdependent de levering transaction consisting of: (i) an Asset Purchase and Sale Agreement pursuant to which Abraxas sold to Lime RockResources V-A, L.P. certain oil, gas, and mineral properties in theWilliston Basin region ofNorth Dakota and other related assets belonging to the Company and its subsidiaries for$87,200,000 in cash ($70.3 million after customary closing adjustments) (the "Sale"), (ii) the pay down of the indebtedness and other obligations of Abraxas and its subsidiaries under the FirstLien Credit Facility, by and among Abraxas, the financial institutions party thereto as lenders, and Société Générale, as "Issuing Lender" and administrative agent and certain specified secured hedges from the proceeds of the Sale and, to the extent necessary, other cash of Abraxas; and (iii), a debt for equity exchange of the indebtedness and other obligations of Abraxas and its subsidiaries under the Second Lien Credit Facility, by and among Abraxas, the financial institutions party thereto as lenders, andAngelo Gordon Energy Servicer, LLC , as administrative agent and all related loan and security documents (the "Exchange" and, together with the transactions referred to in clauses (i) and (ii), the "Restructuring"). AGEF was issued 685,505 shares of Series A Preferred Stock of the Company in the Exchange. The Series A Preferred Stock has the terms set forth in the Company's filed Preferred Stock Certificate of Designation (the "Certificate). Pursuant to the Certificate, any proceeds distributed to the Company's stockholders or otherwise received in respect of the capital stock of the Company in a merger or other liquidity event will be allocated among the Series A Preferred Stock and the Company's common stock as follows: (1) first, 100% to the Series A Preferred Stock until the Series A Preferred Stock has received$100 million of proceeds in the aggregate (the "Tier One Preference Amount"), (2) second, 95% to the Series A Preferred Stock and 5% to the Company's common stock until the Series A Preferred Stock has received$137.1 million , plus a 6.0% annual rate of return thereon from the date of issuance; (3) thereafter, 75% to the Series A Preferred Stock and 25% to the Company's common stock. The Exchange Agreement entered into in connection with the Restructuring also provides for the potential funding by AGEF of an additional amount up to$12.0 million , if agreed to by AGEF and the disinterested members of the Company's Board of Directors. Any such additional amount funded would result in an increase to the Tier One Preference Amount equal to 1.5 x the amount of such additional funding. The shares of Series A Preferred Stock vote together as a single class with the Company's common stock, and each share of Series A Preferred Stock entitles the holder thereof to 69 votes. Accordingly, AGEF's ownership of the Series A Preferred Stock entitle it to approximately 85% of the voting power of the Company's current outstanding capital stock.
See Note 4 " Long-Term Debt - Restructuring" and Note 10 " Disposition of Assets and Restructuring" to the Consolidated Financial Statements.
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; and
• the level and success of exploration and development activity.
Commodity Prices.
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. Factors that influence oil and gas prices include the global demand for
and global supply of oil, NGL and gas; the implementation of and compliance with
production quotas by oil exporting countries; the availability of refining
capacity; the price and availability of transportation and pipeline systems;
weather conditions, natural disasters, and public health threats; the price and
availability of alternative fuel sources; domestic and international drilling
activity; geopolitical tensions; and general economic conditions. 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. In accordance with
historical trends, we expect that the volatility of oil, NGL, and gas pricing
will persist. 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.
Effects of Inflation and Pricing
The oil and gas industry is characterized by its capital-intensive operations, low supply and demand elasticity, and boom-and-bust cyclical nature. An increase in the price of oil and natural gas generally corresponds to an increase in the costs of producing goods and services that are dependent on oil and natural gas. Material changes in the prices we receive for the oil and natural gas that we produce will impact our operating revenues, cash flow, financial condition, estimates of future reserves, borrowing-base calculations, capital-raising capabilities, debt and equity financing opportunities, property value in purchase and sale transactions, ability to retain personnel, rate of future growth, and business operations. As the commodity prices of oil and natural gas increase or decrease, we anticipate correlative increases or decreases in the business costs associated with and the demand for exploration, development, and production services.U.S. inflation has drastically increased over the past year, reaching a new four-decade record peak inJune 2022 . Interventions to combat inflation, such as interest-rate hikes by theFederal Reserve , escalate the risk of recession and economic slowdown. TheU.S. economy experienced negative growth in the first two consecutive quarters of 2022, which by some standards signals a recession. An economic slowdown, or even the perceived risk of an economic slowdown, could cause reductions in the drilling activities of operators and the demand for oil and natural gas. Reduced production or a decline in oil and gas prices could adversely affect our financial condition, results of operations, and cash flows. 24
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During the six months endedJune 30, 2022 , the NYMEX future price for oil averaged$101.83 per Bbl as compared to$62.22 per Bbl in the same period of 2021. During the six months endedJune 30, 2022 , the NYMEX future spot price for gas averaged$6.05 per MMBtu compared to$2.85 per MMBtu in the same period of 2021. Prices closed onJune 30, 2022 at$105.73 per Bbl of oil and$5.24 per MMBtu of gas, compared to closing onJune 30, 2021 at$73.47 per Bbl of oil and$3.65 per MMBtu of gas. OnAugust 8, 2022 , prices closed at$90.76 per Bbl of oil and$7.59 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 six month
periods ended
Oil - NYMEX Gas - NYMEX
2022 2021 2022 2021
Average realized price (1) $ 101.08 $ 57.86 $ 4.55 $ 1.72
Average NYMEX price 101.83 62.22 6.05 2.85
Differential $ (0.75 ) $ (4.36 ) $ (1.50 ) $ (1.13 ) (1) Excludes the impact of derivative activities.
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 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, upon the amount of available funds for acquisition, exploration and development projects. 25
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We had capital expenditures during the six months endedJune 30, 2022 of$0.7 million related to our existing properties. We have not formally established a capital expenditure budget for 2022.
The following table presents historical net production volumes for the three and
six months ended
Three Months Ended June 30, Six Months Ended June 30,
2022 2021 2022 2021
Total production (MBoe) 197 526 392 1,025
Average daily production (Boepd) 2,165 5,785 2,166 5,664
% Oil 56 % 47 % 54 % 50 %
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 six months
ended June 30, 2022 and 2021, by our major operating regions:
Three Months Ended June 30, Six Months Ended June 30,
2022 2021 2022 2021Oil production (MBbls) Rocky Mountain (2) - 119 - 252 Permian/Delaware Basin 103 130 213 261 Total 103 249 213 513 Gas production (MMcf) Rocky Mountain (2) - 456 - 913 Permian/Delaware Basin 372 448 725 790 Total 372 904 725 1,703 NGL production (MBbls) Rocky Mountain (2) - 96 - 176 Permian/Delaware Basin 32 30 58 52 Total 32 126 58 228 Total production (MBoe) (1) 197 526 392 1,025 Average sales price per Bbl of oil (3) Rocky Mountain (2) $ -$ 62.03 $ -$ 56.05 Permian/Delaware Basin 109.25 64.36 101.08 59.60 Composite 109.25 63.25 101.08 57.86 Average sales price per Mcf of gas (2) Rocky Mountain (2) $ -$ 1.12 $ -$ 1.17 Permian/Delaware Basin 5.84 1.67 4.55 2.36 Composite $ 5.84 1.39$ 4.55 1.72 Average sales price per Bbl of NGL Rocky Mountain (2) $ -$ 10.31 $ -$ 10.18 Permian/Delaware Basin 33.87 13.96 31.75 13.28 Composite 33.87 11.18 31.75 10.89 Average sales price per Boe (2)$ 73.74 $ 35.03 $ 68.12 $ 34.24 Average cost of production per Boe produced (4) Rocky Mountain (2) $ -$ 6.34 $ -$ 6.23 Permian/Delaware Basin 12.70 9.56 12.75 10.97 Composite 12.70 7.78 12.75 8.29
(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) Rocky Mountain properties were sold on January 3, 2022 .
(3) 2021 amounts are before the impact of hedging activities.
(4) Production costs include direct lease operating costs but exclude ad valorem
taxes and production taxes.
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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, and if an appropriate opportunity presents itself, credit facilities, or the sale of debt or equity securities, although we may not be able to complete any asset sales or financings on terms acceptable to us, if at all. Our First Lien Credit Facility was settled and our Second Lien Credit Facility was converted to Class A Preferred Stock in connection with the Restructuring that took place onJanuary 3, 2022 . See Note 4 "Long-Term Debt - Restructuring" and Note 10. "Disposition of Assets and Restructuring" to the Consolidated Financial Statements. We do not currently have a credit facility in place and have not formally established a capital budget for 2022.
Borrowings and Interest. At
Exploration and Development Activity. 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. AtDecember 31, 2021 , 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. Alternatively, given our high quality asset base, we may find attractive opportunities to enter into sale transactions that permit the Company to realize value for the assets that might affect the risks of additional borrowing and uncertain exploration success. 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 our current lack of liquidity, all of our proved undeveloped reserves are required to be and have been removed from our asset base. 27
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Selected Operating Data. The following table sets forth operating data from continuing operations for the periods presented.
Three Months Ended June 30, Six Months Ended June 30,
2022 2021 2022 2021Operating revenue (1):(2) Oil sales$ 11,283 $ 15,768 $ 21,574 $ 29,693 Gas sales 2,168 1,259 3,299 2,929 NGL sales 1,078 1,414 1,836 2,483 Other 7 2 12 8 Total operating revenues$ 14,536 $ 18,443 $ 26,721 $ 35,113 Operating income$ 7,277 $ 6,056 $ 12,146 $ 10,899 Oil sales (MBbls) 103 249 213 513 Gas sales (MMcf) 372 904 725 1,703 NGL sales (MBbls) 32 126 58 228 Oil equivalents (MBoe) 197 526 392 1,025 Average oil sales price (per Bbl)(1)$ 109.25 $ 63.25 $ 101.08 $ 57.86 Average gas sales price (per Mcf)(1) $ 5.84 $ 1.39$ 4.55 $ 1.72 Average NGL sales price (per Bbl)$ 33.87 $ 11.18 $ 31.75 $ 10.89 Average oil equivalent sales price (Boe) (1)$ 73.74 $ 35.03 $ 68.12 $ 34.24 ___________________
(1) 2021 revenue and average sales prices are before the impact of hedging
activities.
(2) 2021 amounts include activity from our
sold on January 3, 2022 Comparison of Three Months Ended
Operating Revenue. During the three months endedJune 30, 2022 , operating revenue decreased to$14.5 million from$18.4 million for the same period of 2021. The decrease in revenue was primarily due to lower sales volumes offset by higher commodity prices. Higher realized prices for all products added$7.1 million to operating revenue for the three months endedJune 30, 2022 . Lower sales volumes negatively impacted revenue by$11.0 million . Lower sales volumes were primarily due to the sale of our Bakken properties inNorth Dakota onJanuary 3, 2022 . Sales from the Bakken properties contributed 291 MBoe and$8.9 million to revenue in the second quarter of 2021. Oil sales volumes decreased to 103 MBbl during the three months endedJune 30, 2022 from 249 MBbl for the same period of 2021. The decrease in oil sales volume was primarily due to the sale of our Bakken properties onJanuary 3, 2022 , which contributed 119 MBbls. Gas sales volumes decreased to 372 MMcf for the three months endedJune 30, 2022 from 904 MMcf for the same period of 2021. The decrease in gas volumes was primarily due to the sale of our Bakken properties onJanuary 3, 2022 , which contributed 456 MMcf in the second quarter of 2021. Lease Operating Expenses ("LOE"). LOE for the three months endedJune 30, 2022 decreased to$2.5 million from$4.1 million for the same period of 2021. The decrease in LOE was primarily due to sale of our Bakken properties onJanuary 3, 2022 , which incurred$1.8 million in LOE in the second quarter of 2021. LOE per Boe for the three months endedJune 30, 2022 was$12.78 compared to$7.72 for the same period of 2021. The increase per Boe was due primarily to higher cost of services in 2022 as compared to 2021. Production and Ad Valorem Taxes. Production and ad valorem taxes for the three months endedJune 30, 2022 decreased to$1.2 million from$1.7 million for the same period of 2021. Production and ad valorem taxes for the three months endedJune 30, 2022 were 8% of total oil, gas and NGL sales compared to 9% for the same period of 2021. The decrease in percentage was due to all 2022 production being inTexas , which has a lower tax rate. 28
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General and Administrative ("G&A") Expense. G&A expenses, excluding stock-based
compensation, decreased to $1.8 million for the three months ended June 30,
2022 from $2.1 million for the same period of 2021. G&A per Boe, excluding
stock-based compensation, was $8.94 for the quarter ended June 30, 2022 compared
to $3.92 for the same period of 2021. The increase in G&A per Boe, excluding
stock based compensation, was primarily due to lower sale volumes for the three
months ended June 30, 2022 compared to the same period of 2021.
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 June 30, 2022 , stock-based compensation
was $0.1 million compared to $0.2 million for the period ended June 30, 2021 .
As of
Depreciation, Depletion and Amortization ("DD&A") Expense. DD&A expense,
excluding accretion of future site restoration, for the three months ended June
30, 2022 decreased to $1.5 million from $4.2 million for the same period of
2021. The decrease was primarily due to lower production volumes offset by a
lower full cost pool as a result of the impairments recorded in 2020, the sale
of the Bakken assets as well as lower future development cost included in
the June 30, 2022 internal reserve report. DD&A expense per Boe for the three
months ended June 30, 2022 was $7.74 compared to $7.91 in the same period
of 2021.
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 June 30,
2022 and June 30, 2021 , our net capitalized costs of oil and gas properties
did not exceed the cost ceiling of our estimated proved reserves.
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 June 30,
2022 decreased to $0.03 million compared to $7.7 million for the same period of
2021. The decrease in interest expense in 2022 was due to the settlement of our
First Lien Credit Facility and the conversion of our Second Lien Credit Facility
into preferred stock on January 3, 2022 . See Note 5 Long-Term Debt -
Restructuring and Note 10. " Disposition of Assets and Restructuring" to the
Consolidated Financial Statements.
Loss (Gain) on Derivative Contracts. As of January 1, 2022 we are not party to
any derivative agreements. Derivative gains or losses were 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 June 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 June 30,
2021 , we recognized a loss on our commodity derivative contracts of $9.9
million , including a loss of $7.1 million upon the termination of existing
contracts.
Income Tax Expense. For the three months ended June 30, 2022 and June 30, 2021
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.
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Comparison of Six Months Ended
Operating Revenue. During the six months endedJune 30, 2022 , operating revenue decreased to$26.7 million from$35.1 million for the same period of 2021. The decrease in revenue was primarily due to lower sales volumes offset by higher commodity prices. Higher realized prices for all products added$18.8 million to operating revenue for the six months endedJune 30, 2022 . Lower sales volumes negatively impacted revenue by$27.2 million . Lower sales volumes were primarily due to the sale of our Bakken properties inNorth Dakota onJanuary 3, 2022 . Sales from the Bakken properties contributed 581 MBoe and$17.0 million to revenue in the first half of 2021. Oil sales volumes decreased to 213 MBbl during the six months endedJune 30, 2022 from 513 MBbl for the same period of 2021. The decrease in oil sales volume was primarily due to the sale of our Bakken properties onJanuary 3, 2022 , which contributed 252 MBbls during the first half of 2022, as well as natural field declines and no new production during the first half of 2022. Gas sales volumes decreased to 725 MMcf for the six months endedJune 30, 2022 from 1,703 MMcf for the same period of 2021. The decrease in gas volumes was primarily due to the sale of our Bakken properties onJanuary 3, 2022 , which contributed 914 MMcf in the first half of 2021. Lease Operating Expenses ("LOE"). LOE for the six months endedJune 30, 2022 decreased to$5.1 million from$8.5 million for the same period of 2021. The decrease in LOE was primarily due to the sale of our Bakken properties onJanuary 3, 2022 , which incurred$3.6 million in LOE in the first half of 2021. LOE per Boe for the six months endedJune 30, 2022 was$12.98 compared to$8.24 for the same period of 2021. The increase per Boe was due primarily to higher cost of services in 2022 as compared to 2021, as well as lower sales volumes in 2022. Production and Ad Valorem Taxes. Production and ad valorem taxes for the six months endedJune 30, 2022 decreased to$2.3 million from$3.1 million for the same period of 2021. Production and ad valorem taxes for the six months endedJune 30, 2022 were 9% of total oil, gas and NGL sales for the six months endedJune 30, 2021 and 2022. 30
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General and Administrative ("G&A") Expense. G&A expenses, excluding stock-based
compensation, was $3.5 million for the six months ended June 30, 2022 compared
to $3.8 for the same period of 2021. G&A per Boe, excluding stock-based
compensation, was $8.91 for the six months ended June 30, 2022 compared
to $3.71 for the same period of 2021. The increase in G&A per Boe, excluding
stock based compensation, was primarily due to lower sales volumes for the six
months ended June 30, 2022 compared to the same period of 2021.
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 six months ended June 30, 2022 , stock-based compensation
was $0.3 million compared to $0.5 million for the period ended June 30, 2021 .
As of
Depreciation, Depletion and Amortization ("DD&A") Expense. DD&A expense,
excluding accretion of future site restoration, for the six months ended June
30, 2022 decreased to $3.1 million from $8.0 million for the same period of
2021. The decrease was primarily due to lower production volumes offset by a
lower full cost pool as a result of the impairments recorded in 2020, the sale
of our Bakken assets on January 3, 2022 as well as lower future development cost
included in the June 30, 2022 internal reserve report. DD&A expense per Boe for
the six months ended June 30, 2022 was $7.81 compared to $7.76 in the same
period of 2021.
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 June 30,
2022 and June 30, 2021 , our net capitalized costs of oil and gas properties
did not exceed the cost ceiling of our estimated proved reserves.
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 six months ended June 30,
2022 decreased to $0.1 million compared to $13.7 million for the same period of
2021. The decrease in interest expense in 2022 was due to the settlement of our
First Lien Credit Facility and the conversion of our Second Lien Credit Facility
into preferred stock on January 3, 2022 . See Note 4 " Long-Term Debt -
Restructuring and Note 10. " Disposition of Assets and Restructuring" to the
Consolidated Financial Statements.
Loss (Gain) on Derivative Contracts. As of January 1, 2022 we are not party to
any derivative agreements. Derivative gains or losses were 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 June 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 six months ended June 30,
2021 , we recognized a loss on our commodity derivative contracts
of $32.6 million , including a loss of $7.1 million related to the termination of
existing contracts during the second quarter of 2021.
Income Tax Expense. For the six months ended June 30, 2022 and June 30, 2021
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 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.
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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 grow the business through the development of existing
properties and the acquisition of new properties.
Our principal sources of capital are cash flows from operations, proceeds from
the sale of properties, and if an opportunity presents itself, credit
facilities, or the sale of debt or equity securities, although we may not be
able to sell properties or complete sales or 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.
Working Capital (Deficit). At June 30, 2022 , our current assets of $27.3 exceed
our current liabilities of $12.9 million , resulting in a working capital
surplus of $14.4 million . This compares to a working capital deficit
of $216.0 million at December 31, 2021 . Current assets as of June 30,
2022 primarily consisted of cash of $18.5 million , accounts receivable of
$7.8 million and other current assets of $1.0 million . Current liabilities at
June 30, 2022 primarily consisted of trade payables of $7.9 million , including
$5.9 million in post closing costs related to the sale of our North Dakota
Bakken properties on January 3, 2022 , revenues due third parties
of $4.1 million , current maturities of long-term debt of $0.3 million , and other
accrued expenses of $0.5 million .
Capital Expenditures. Capital expenditures for the six months ended
The table below sets forth the components of these capital expenditures:
Six Months Ended June 30,
2022 2021
(In thousands)
Expenditure category:
Exploration/Development $ 706 $ 387
Facilities and other 24 6
Total $ 730 $ 393 During the six months ended
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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:
Six Months Ended June 30,
2022 2021
(In thousands)
Net cash provided by operating activities $ 13,322 $ 10,646
Net cash provided by (used in) investing activities 71,954 (24 )
Net cash used in financing activities (76,807 ) (5,433 )
Total $ 8,469 $ 5,189
Operating activities for the six months ended June 30, 2022 provided $13.3
million in cash compared to providing $10.6 million in the same period of 2021.
Higher net income and changes in operating assets and liabilities accounted for
most of these funds. Investing activities provided $72.0 million during the six
months ended June 30, 2022 , primarily from sales of oil and gas properties in
North Dakota as well as various non-oil and gas assets on January 3,
2022 . Investing activities used $0.02 million during the six months ended June
30, 2021 , primarily for the development of our existing properties. Financing
activities used $76.8 million for the six months ended June 30, 2022 primarily
for the settlement of the First Lien Credit Facility in connection with the
Restructuring, compared to using $5.4 million for the same period of
2021,primarily for the reduction of long-term debt. See Note 4 "Long-Term Debt -
Restructuring" and Note 10 "Disposition of Assets and Restructuring" to the
Consolidated Financial Statements.
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,
credit facilities, or the sale of debt or equity securities, although we may not
be able to complete sales of financings 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
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
that we have numerous drilling opportunities that would allow us to increase
our production volumes; however, our current capital constraints impair our
ability to drill. 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
Payments due in twelve month periods ending:
June 30,
Contractual Obligations Total June 30, 2023
2024-2025
$ 2,362 $ 318$ 2,044 $ - $ - Interest on long-term debt (2) 115 110 5 - Lease obligations 4 4 - - - Total$ 2,481 $ 432$ 2,049 $ - $ -
(1) These amounts represent the balance outstanding under our real estate lien
note. The real estate loan was paid in full on
(2) Interest expense based on amortization schedule of our real estate lien note
We maintain a reserve for costs associated with future site restoration related to the retirement of tangible long-lived assets. AtJune 30, 2022 , our reserve for these obligations totaled$3.0 million for which no contractual commitments exist. For additional information relating to this obligation, see Note 1 of the Notes to Condensed Consolidated Financial Statements. 33
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Off-Balance Sheet Arrangements. AtJune 30, 2022 , we had no existing off-balance sheet arrangements, as defined underSEC 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 (in thousands):
June 30, 2022 December 31, 2021
First Lien Credit Facility $ - $ 71,400
Second Lien Credit Facility - 134,907
Exit fee - Second Lien Credit Facility - 10,000
Real estate lien note 2,362 2,515
Total long term debt 2,362 218,822
Less current maturities (318 ) (212,688 )
2,044 6,134
Deferred financing fees and debt issuance cost, net - (3,929 )
Total long-term debt, net of deferred financing fees
and debt issuance costs $ 2,044 $ 2,205
Restructuring
Pursuant to the Exchange Agreement, dated as of January 3, 2022 , between Abraxas
and AGEF and certain other agreements entered into by Abraxas on January 3,
2022 , we effectuated a restructuring of our then-existing indebtedness through a
multi-part interdependent de levering transaction consisting of: (i) an Asset
Purchase and Sale Agreement pursuant to which Abraxas sold to Lime Rock
Resources V-A, L.P. certain oil, gas, and mineral properties in the Williston
Basin region of North Dakota and other related assets belonging to the Company
and its subsidiaries for $87,200,000 in cash ($70.3 million after customary
closing adjustments) (the "Sale"), (ii) the pay down of the indebtedness and
other obligations of Abraxas and its subsidiaries under the First Lien Credit
Facility, by and among Abraxas, the financial institutions party thereto as
lenders, and Société Générale, as "Issuing Lender" and administrative agent and
certain specified secured hedges from the proceeds of the Sale and, to the
extent necessary, other cash of Abraxas; and (iii), a debt for equity exchange
of the indebtedness and other obligations of Abraxas and its subsidiaries under
the Second Lien Credit Facility, by and among Abraxas, the financial
institutions party thereto as lenders, and Angelo Gordon Energy Servicer, LLC ,
as administrative agent and all related loan and security documents (the
"Exchange" and, together with the transactions referred to in clauses (i) and
(ii), the "Restructuring").
AGEF was issued 685,505 shares of Series A Preferred Stock of the Company in the
Exchange. The Series A Preferred Stock has the terms set forth in the Company's
filed Preferred Stock Certificate of Designation (the "Certificate). Pursuant
to the Certificate, any proceeds distributed to the Company's stockholders or
otherwise received in respect of the capital stock of the Company in a merger or
other liquidity event will be allocated among the Series A Preferred Stock and
the Company's common stock as follows: (1) first, 100% to the Series A Preferred
Stock until the Series A Preferred Stock has received $100 million of proceeds
in the aggregate (the "Tier One Preference Amount"), (2) second, 95% to the
Series A Preferred Stock and 5% to the Company's common stock until the Series A
Preferred Stock has received $137.1 million , plus a 6.0% annual rate of return
thereon from the date of issuance; (3) thereafter, 75% to the Series A Preferred
Stock and 25% to the Company's common stock. The Exchange Agreement entered into
in connection with the Restructuring also provides for the potential funding by
AGEF of an additional amount up to $12.0 million , if agreed to by AGEF and the
disinterested members of the Company's Board of Directors. Any such additional
amount funded would result in an increase to the Tier One Preference Amount
equal to 1.5 x the amount of such additional funding. The shares of Series A
Preferred Stock vote together as a single class with the Company's common stock,
and each share of Series A Preferred Stock entitles the holder thereof to 69
votes. Accordingly, AGEF's ownership of the Series A Preferred Stock entitle it
to approximately 85% of the voting power of the Company's current outstanding
capital stock.
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Table of Contents 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 note was modified onJune 20, 2018 to a fixed rate of 4.9% and is payable in monthly installments of$35,672 . The maturity date of the note isJuly 20, 2023 . As ofJune 30, 2022 , andDecember 31, 2021 ,$2.4 million and$2.5 million , respectively, were outstanding on the note. The real estate lien note was paid in full onAugust 3, 2022 . 35
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