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.
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. 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 2023 will impact the amount of cash generated from
operating activities, which will in turn impact our financial position. As of
March 20, 2023 , the NYMEX oil and gas price was $67.64 per Bbl of oil
and $2.22 per Mcf of gas.
During 2022, the NYMEX future price for oil averaged $94.32 per barrel as
compared to $68.11 per barrel in 2021 and the NYMEX future spot price for gas
averaged $6.54 per Mcf compared to $3.73 per Mcf in 2021. Prices closed
on December 31, 2022 at $80.26 per Bbl of oil and $4.48 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. 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, 2022 , our average annual estimated decline rate for our net proved developed producing reserves is 15%, 12% , 10% , 9% and 7% for 2023, 2024, 2025, 2026 and 2027, respectively, 7% annually in the following five years, and approximately 7% annually 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.
Borrowings and Interest. At
Exploration and Development Activity. At
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.
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Results of Operations
Year Ended December 31,
(in thousands)
2021 2022
Operating revenue (1):
Oil sales $ 61,228 $ 39,617
Gas sales 8,656 6,642
NGL sales 8,952 3,456
Other income 22 22
Total revenues $ 78,858 $ 49,737
Operating income $ 30,484 $ 15,677
Oil sales (MBbls) 957 419
Gas sales (MMcf) 3,432 1,569
NGL sales (MBbls) 495 134
Oil equivalents (MBoe) 2,023 814
Average oil sales price (per Bbl)(1) $ 63.98 $ 94.64
Average gas sales price (per Mcf) $ 2.52 $ 4.23
Average NGL price (per Bbl) $ 18.09 $ 25.74 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, 2022 , revenue decreased to$49.7 million from$78.9 million in 2021. Higher commodity prices for all products in 2022 contributed$16.5 million to revenue. Lower sales volumes negatively impacted revenue by$45.7 million . The decline in sales volumes was primarily attributable to the sale of ourNorth Dakota properties onJanuary 3, 2022 . TheNorth Dakota properties contributed 1,150 MBoe and$39.5 million in revenue in 2021. Oil sales volumes decreased to 419 MBbls for the year endedDecember 31, 2022 from 957 MBbls for year endedDecember 31, 2021 . Gas sales volumes decreased to 1,569 MMcf for the year endedDecember 31, 2022 compared to 3,432 MMcf for the year endedDecember 31, 2021 . NGL sales decreased to 134 MBbls for the year endedDecember 31, 2022 compared to 495 MBbls for the year endedDecember 31, 2021 The decrease in oil sales volumes was primarily due to natural field declines and the sale of theNorth Dakota properties inJanuary 2022 . Lease Operating Expenses ("LOE"). LOE for the year endedDecember 31, 2022 decreased to$10.1 million from$17.9 million in 2021. The decrease in LOE was primarily due to the sale of theNorth Dakota properties inJanuary 2022 . LOE per Boe for the year endedDecember 31, 2022 was$12.41 compared to$8.85 for the same period in 2021. The increase in LOE per Boe was attributable to lower sales volumes in 2022 as compared to 2021 as well as higher cost to operate the remainingPermian Basin wells. 22
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Production and Ad Valorem Taxes. Production and ad valorem taxes for the year endedDecember 31, 2022 decreased to$4.5 million from$6.2 million in 2021. The decrease was primarily due to lower sales volumes as a result of the sale of theNorth Dakota properties offset by higher sales prices in 2022 as compared to 2021. Production and ad valorem taxes as a percentage of oil and gas revenue were 9% in 2022 compared to 8% for the same period in 2021. General and Administrative ("G&A") Expense. G&A expense, including stock-based compensation, increased to$12.6 million for the year endedDecember 31, 2022 from$8.1 million in 2021. G&A expense, per Boe was$15.44 for the year endedDecember 31, 2022 compared to$4.01 for the same period in 2021. The increase in total G&A expense was primarily due to higher legal and professional costs, higher stock-based compensation as well increased salaries related to severance paid to employees terminated. 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 increased to$3.3 million for the year endedDecember 31, 2022 compared to$0.9 million for the year endedDecember 31, 2021 . The increase was primarily due to the vesting of restricted stock in connection with the change in control that occurred inJanuary 2022 , which resulted in the recognition of all unamortized costs. Depreciation, Depletion, and Amortization ("DD&A") Expenses. DD&A expense excluding accretion of future site restoration, decreased to$6.3 million for the year endedDecember 31, 2022 from$15.3 million in 2021. The decrease was primarily due to lower future development cost included in theDecember 31, 2022 reserve report, due to the exclusion of the development cost of PUDs. The full cost pool was also reduced by the sale of ourNorth Dakota properties inJanuary 2022 . DD&A expense per Boe for the year endedDecember 31, 2022 was$7.79 compared to$7.57 in the same period in 2021. Interest Expense. Interest expense decreased from$35.8 million for 2021 to$0.1 million in 2022. The decrease was due to lower debt levels in 2022 as compared to 2021. In connection with the restructuring that occurred onJanuary 3, 2022 , our First Lien and Second Lien credit facilities were retired. Our real estate lien note on our office building was paid in full inAugust 2022 .
Income Taxes. Due to losses in the periods and loss carry forwards, we did not
recognize any income tax expense for the years ended
Loss on Derivative Contracts. Derivative gains or losses are determined by
actual derivative settlements during the period and by periodic mark to market
valuation of derivative contracts in place. We have elected not to apply hedge
accounting to our derivative contracts as prescribed by Accounting Standards
Codification 815, Derivatives and Hedging ("ASC 815"). Therefore, fluctuations
in the market value of the derivative contracts are recognized in earnings
during the current period. Our derivative contracts consisted of fixed price
swaps and basis differential swaps in 2021. For the year ended December 31,
2021 , we recognized a loss on our derivative contracts of $33.0 million . We did
not have any derivative contracts in 2022.
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 ended December 31, 2021 and 2022, the net capitalized cost of our oil and
gas properties did not exceed the future net revenues from our estimated proved
reserves.
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Working Capital (Deficit). AtDecember 31, 2022 , our current assets of$11.2 million exceeded our current liabilities of$6.4 million resulting in a working capital surplus of$4.8 million , compared to a working capital deficit of$216.0 million atDecember 31, 2021 . Current assets atDecember 31, 2022 primarily consisted of cash of$2.9 million , accounts receivable of$5.0 million , assets held for sale of$3.0 million , and other current assets of$0.4 million . Current liabilities atDecember 31, 2022 primarily consisted of trade payables of$4.2 million , revenues due to third parties of$2.0 million , and accrued expenses of$0.1 million . Capital Expenditures. Capital expenditures in 2021 and 2022 were$1.3 million and$1.5 million , respectively. The table below sets forth the components of these capital expenditures: Years Ended December 31, 2021 2022 (in thousands) Expenditure category: Exploration/Development$ 1,145 $ 1,509 Acquisitions - - Facilities and other 180 35$ 1,325 $ 1,544 During 2021 and 2022, capital expenditures were primarily expenditures on our existing properties. The level of capital expenditures will vary during future periods depending on economic and industry conditions and commodity prices. Should the prices of oil and gas decline and if our costs of operations increase or if our production volumes decrease, our cash flows from operations will decrease which may result in a reduction of capital expenditure. We did not have a capital drilling budget for 2022.
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,
2021 2022
(in thousands)
Net cash provided by operating activities $ 32,419 $ 20,312
Net cash (used in) provided by investing activities (518 )
51,298
Net cash used in financing activities (24,642 ) (78,768 )
$ 7,259 $ (7,158 )
Operating activities for the year ended December 31, 2022 provided $20.3 million
in cash compared to $32.4 million in 2021. The decrease was primarily due to
lower net income from operations due to lower sales volumes partially offset by
higher commodity prices. Investing activities provided $51.3 million in 2022
primarily from the sale of oil and gas properties in 2022. Cash expenditures for
the year ended December 31, 2022 included a decrease of $1.8 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 $72.3 million and
a decrease in accounts payable related to capital expenditures of $0.1 million
resulting in accrual based capital expenditures incurred during the
period of $1.6 million . The Company also invested $19.5 million in the Lion Fund
II, L.P. in 2022.
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Liquidity and 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.
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,
(In thousands) Total December 31, 2023 2024-2025 2026-2027 Thereafter
Lease obligations $ 1 $ 1 $ - $ - $ -
Total $ 1 $ 1 $ - $ - $ -
___________________________
We maintain a reserve for costs associated with the retirement of tangible
long-lived assets. At December 31, 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 Consolidated
Financial Statements.
Off-Balance Sheet Arrangements. At December 31, 2022 , 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,
2021 2022
(In thousands)
First Lien Credit Facility $ 71,400 $ -
Second Lien Credit Facility 134,907 -
Exit fee - Second Lien Credit Facility 10,000 -
Real estate lien note 2,515 -
218,822 -
Less current maturities (212,688 ) -
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 $ 2,205 $ -
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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. Subsequently, onSeptember 13, 2022 ,AGEF and Biglari Holdings, entered into a preferred stock purchase agreement (the "Preferred Purchase Agreement"), and an assignment and assumption agreement pursuant to which AGEF agreed to sell and assign to Biglari Holdings (the "Sales And Assignment"), and Biglari Holdings agreed to purchase, acquire, and assume from AGEF, the Preferred Shares and all of AGEF's rights, title, and interests in, and duties and obligations under, the Exchange Agreement. Following Biglari Holdings' acquisition of the Preferred Shares, a change in control of the Company occurred. Biglari Holdings' ownership of the Preferred Shares resulted in its beneficial ownership, both directly and indirectly, of the approximately 85% of the Company's voting securities that AGEF owned prior to effecting the Sale and Assignment. Subsequent to the Sale and Assignment, Biglari Holdings proposed an exchange of the Preferred Shares for shares of the Company's common stock pursuant to which the Company would issue Biglari Holdings 90,631,287 shares of the Company's common stock in exchange for the Preferred Shares (such transaction, the "Second Exchange").
To issue the Stock Consideration to Biglari Holdings as contemplated by the Second Exchange, an amendment to Articles of Incorporation, as amended, was needed to increase the number of shares of common stock authorized for the Company's issuance from 20,000,000 shares to 150,000,000 shares.
OnSeptember 23, 2022 , the Board approved the Company's entry into the Second Exchange Agreement. The Company and Biglari Holdings entered into the Second Exchange Agreement onSeptember 27, 2022 , with the consummation of the Second Exchange subject to the approval by the Company's stockholders of the Amendment and the acceptance of the Amendment by theNevada Secretary of State. OnOctober 24, 2022 , the Company's stockholders approved the Amendment, and the Company caused the Amendment to be filed with theNevada Secretary of State that same day. TheNevada Secretary of State accepted the Amendment onOctober 25, 2022 , and onOctober 26, 2022 , the Second Exchange Agreement was consummated by the following transactions: (i) the Company caused 90,631,287 shares of common stock to be registered in the name of Biglari Holdings with the Company's transfer agent in book-entry form, and (ii) Biglari Holdings assigned and transferred the Preferred Shares to the Company, constituting all of the Preferred Shares of the Company then outstanding, by delivering aStock Power and Assignment to the Company. The Company cancelled the Series A Preferred Stock and the Preferred Stock Certificate of Designation, such that only common stock of the Company remains outstanding. As a result of the Sale and Assignment and Second Exchange, the Company is a consolidated subsidiary of Biglari Holdings, and Biglari Holdings has the power to exert significant control over the Company by controlling both 90% of the voting power of the Company's outstanding capital stock and a majority of the Company's Board Real EstateLien Note We had 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 accrued interest at a fixed rate of 4.9%. The note was payable in monthly installments of principal and interest in the amount of$35,672 . The maturity date of the note wasJuly 20, 2023 . As ofDecember 31, 2021 ,$2.5 million was outstanding on the note. The note was paid in full inAugust 2022
Net Operating Loss Carryforwards
AtDecember 31, 2022 , we had, subject to the limitation discussed below,$20.0 million of pre-2018 NOLs and a$186.7 million post 2017 NOL forU.S. tax purposes. Our pre-2018 NOLs will expire in varying amounts 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 ).
On
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 During November andDecember 2022 , the Company invested$19,500 in theLion Fund II, L.P. , as a limited partner.The Lion Fund II, L.P. is an investment partnership affiliated withSardar Biglari , a director ofAbraxas and Biglari Holdings Inc. There were no related party transactions in 2021. 26
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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. Prior management chose 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, 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,Netherland Sewell & Associates Inc. as ofDecember 31, 2022 and byDeGolyer and MacNaughton as ofDecember 31, 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, 2021 and 2022, 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 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, 2022 , the Company did not have any derivative contracts. 27
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Recently Issued Accounting Standards
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