Document And Entity Information
Document And Entity Information - USD ($) | 12 Months Ended | ||
Dec. 31, 2023 | Apr. 04, 2024 | Jun. 30, 2023 | |
Document Information [Line Items] | |||
Document Type | 10-K | ||
Document Annual Report | true | ||
Document Period End Date | Dec. 31, 2023 | ||
Document Transition Report | false | ||
Entity File Number | 0-7406 | ||
Entity Registrant Name | PrimeEnergy Resources Corporation | ||
Entity Incorporation, State or Country Code | DE | ||
Entity Tax Identification Number | 84-0637348 | ||
Entity Address, Address Line One | 9821 Katy Freeway | ||
Entity Address, City or Town | Houston | ||
Entity Address, State or Province | TX | ||
Entity Address, Postal Zip Code | 77024 | ||
City Area Code | 713 | ||
Local Phone Number | 735-0000 | ||
Title of 12(b) Security | Common Stock, par value $0.10 (per share) | ||
Trading Symbol | PNRG | ||
Security Exchange Name | NASDAQ | ||
Entity Well-known Seasoned Issuer | No | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Interactive Data Current | Yes | ||
Entity Filer Category | Non-accelerated Filer | ||
Entity Small Business | true | ||
Entity Emerging Growth Company | false | ||
ICFR Auditor Attestation Flag | false | ||
Document Financial Statement Error Correction [Flag] | false | ||
Entity Shell Company | false | ||
Auditor Firm ID | 606 | ||
Auditor Name | Grassi | ||
Auditor Location | New York, NY | ||
Entity Public Float | $ 65,081,697 | ||
Entity Common Stock, Shares Outstanding (in shares) | 1,790,245 | ||
Entity Central Index Key | 0000056868 | ||
Current Fiscal Year End Date | --12-31 | ||
Document Fiscal Year Focus | 2023 | ||
Document Fiscal Period Focus | FY | ||
Amendment Flag | false |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Thousands | Dec. 31, 2023 | Dec. 31, 2022 |
Current Assets | ||
Cash and cash equivalents | $ 11,061 | $ 26,543 |
Accounts receivable, net | 20,301 | 12,147 |
Prepaid obligations | 376 | 32,839 |
Derivative asset short-term | 210 | |
Other current assets | 38 | 38 |
Total Current Assets | 31,776 | 72,165 |
Property and Equipment | ||
Oil and gas properties at cost | 659,792 | 555,280 |
Less: Accumulated depletion and depreciation | (406,913) | (385,811) |
Oil and Gas Property, Successful Effort Method, Net | 252,879 | 169,469 |
Field and office equipment at cost | 26,955 | 27,246 |
Less: Accumulated depreciation | (23,715) | (22,728) |
Property, Plant and Equipment, Net | 3,240 | 4,518 |
Total Property and Equipment, Net | 256,119 | 173,987 |
Other assets | 673 | 985 |
Total Assets | 288,568 | 247,137 |
Current Liabilities | ||
Accounts payable | 15,424 | 11,451 |
Accrued liabilities | 48,613 | 25,750 |
Current portion of asset retirement and other long-term obligations | 692 | 2,566 |
Derivative liability short-term | 1,190 | |
Liabilities, Current | 64,809 | 40,957 |
Long-Term Bank Debt | 11,000 | |
Asset Retirement Obligations | 14,707 | 13,525 |
Deferred Income Taxes | 47,236 | 39,968 |
Other Long-Term Obligations | 866 | 1,334 |
Total Liabilities | 127,618 | 106,784 |
Commitments and Contingencies | ||
Equity | ||
Common stock, $.10 par value; 2023 and 2022: Authorized: 2,810,000 shares, outstanding 2023: 1,820,100 shares; outstanding 2022: 1,901,000 shares. | 281 | 281 |
Paid-in capital | 7,555 | 7,555 |
Retained earnings | 205,669 | 177,566 |
Treasury stock, at cost; 2023: 989,900 shares; 2022: 909,000 | 52,555 | 45,049 |
Total Stockholders’ Equity | 160,950 | 140,353 |
Total Liabilities and Equity | 288,568 | 247,137 |
Related Party [Member] | ||
Current Assets | ||
Due from related parties | 388 | |
Current Liabilities | ||
Due to related parties | $ 80 | $ 0 |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parentheticals) - $ / shares | Dec. 31, 2023 | Dec. 31, 2022 |
Common Stock, Par or Stated Value Per Share (in dollars per share) | $ 0.1 | $ 0.1 |
Common Stock, Shares Authorized (in shares) | 2,810,000 | 2,810,000 |
Common Stock, Shares, Outstanding (in shares) | 1,820,100 | 1,901,000 |
Treasury Stock, Common, Shares (in shares) | 989,900 | 909,000 |
Consolidated Statements Of Inco
Consolidated Statements Of Income - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Revenues and other income: | ||
Interest and other income, net | $ 417 | $ 267 |
Gain (loss) on derivative instruments, net | 414 | (12,039) |
Revenues | 132,810 | 157,113 |
Costs and expenses: | ||
Oil and gas production | 31,892 | 30,702 |
Production and advalorem taxes | 7,112 | 7,114 |
Field service | 11,744 | 11,094 |
Depreciation, depletion and amortization | 30,976 | 27,401 |
Accretion of discount on asset retirement obligations | 684 | 667 |
General and administrative | 15,645 | 20,233 |
Interest | 535 | 909 |
Costs and Expenses | 98,588 | 98,120 |
Income Before Income Taxes | 34,222 | 58,993 |
Income Tax Provision | 6,119 | 10,329 |
Net Income attributable to common stockholders | $ 28,103 | $ 48,664 |
Basic (in dollars per share) | $ 15.19 | $ 24.91 |
Diluted (in dollars per share) | $ 10.77 | $ 17.95 |
Basic (in shares) | 1,849,780 | 1,953,916 |
Diluted (in shares) | 2,608,786 | 2,711,170 |
Oil Sales [Member] | ||
Revenues and other income: | ||
Revenues | $ 87,906 | $ 90,803 |
Naturals Gas [Member] | ||
Revenues and other income: | ||
Revenues | 7,935 | 18,428 |
Natural Gas Liquid [Member] | ||
Revenues and other income: | ||
Revenues | 11,901 | 14,887 |
Oil and Gas Service [Member] | ||
Revenues and other income: | ||
Revenues | 15,383 | 12,978 |
Gain on disposition of assets, net | $ 8,854 | $ 31,789 |
Consolidated Statements of Equi
Consolidated Statements of Equity - USD ($) $ in Thousands | Common Stock Shares Outstanding [Member] | Common Stock [Member] | Additional Paid-in Capital [Member] | Retained Earnings [Member] | Treasury Stock, Common [Member] | Total |
Balance (in shares) at Dec. 31, 2021 | 1,992,077 | |||||
Balance at Dec. 31, 2021 | $ 281 | $ 7,555 | $ 128,902 | $ (37,647) | $ 99,091 | |
Purchase of treasury stock (in shares) | (91,077) | |||||
Purchase of treasury stock | 0 | 0 | 0 | (7,402) | (7,402) | |
Net income | 0 | 0 | 48,664 | 0 | 48,664 | |
Balance (in shares) at Dec. 31, 2022 | 1,901,000 | |||||
Balance at Dec. 31, 2022 | 281 | 7,555 | 177,566 | (45,049) | 140,353 | |
Purchase of treasury stock (in shares) | (80,900) | |||||
Purchase of treasury stock | 0 | 0 | 0 | (7,506) | (7,506) | |
Net income | 0 | 0 | 28,103 | 0 | 28,103 | |
Balance (in shares) at Dec. 31, 2023 | 1,820,100 | |||||
Balance at Dec. 31, 2023 | $ 281 | $ 7,555 | $ 205,669 | $ (52,555) | $ 160,950 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Cash Flows from Operating Activities: | ||
Net income | $ 28,103 | $ 48,664 |
Adjustments to reconcile net income to net cash provided by operating activities: | ||
Depreciation, depletion and amortization | 30,976 | 27,401 |
Accretion of discount on asset retirement obligations | 684 | 667 |
Gain on sale and exchange of assets | (8,854) | (31,789) |
Unrealized gain on derivative instruments | (4,605) | |
Realized Gain on derivative instruments, net | (980) | |
Provision for deferred income taxes | 7,268 | 1,225 |
Changes in assets and liabilities: | ||
Accounts receivable | (8,492) | 2,096 |
Allowance for doubtful accounts | 338 | (35) |
Due from related parties | 388 | (388) |
Due to related parties | 80 | (52) |
Prepaid obligations | 32,463 | (32,106) |
Increase (Decrease) in Other Current Assets | 2 | |
Accounts payable | 3,973 | 4,169 |
Accrued liabilities | 22,863 | 17,929 |
Other assets | 673 | 100 |
Other long-term liabilities | (468) | (151) |
Net Cash Provided by Operating Activities | 109,015 | 33,127 |
Cash Flows from Investing Activities: | ||
Capital expenditures, including exploration expense | (113,779) | (15,974) |
Proceeds from sale of properties and equipment | 8,082 | 31,445 |
Net Cash (Used in) Provided by Investing Activities | (105,697) | 15,471 |
Cash Flows from Financing Activities: | ||
Purchase of stock for treasury | (7,506) | (7,402) |
Increase in long-term bank debt and other long-term obligations | 11,000 | |
Repayment of long-term bank debt and other long-term obligations | (11,294) | (36,000) |
Net Cash Used in Financing Activities | (18,800) | (32,402) |
Net (Decrease) Increase in Cash and Cash Equivalents | (15,482) | 16,196 |
Cash and Cash Equivalents at the Beginning of the Year | 26,543 | 10,347 |
Cash and Cash Equivalents at the End of the Year | 11,061 | 26,543 |
Supplemental Disclosures: | 569 | 842 |
Income taxes paid during the year | $ 9,009 | $ 539 |
Insider Trading Arrangements
Insider Trading Arrangements | 12 Months Ended |
Dec. 31, 2023 | |
Insider Trading Arr Line Items | |
Material Terms of Trading Arrangement [Text Block] | Item 9B. OTHER INFORMATION. None. |
Rule 10b5-1 Arrangement Adopted [Flag] | false |
Non-Rule 10b5-1 Arrangement Adopted [Flag] | false |
Rule 10b5-1 Arrangement Terminated [Flag] | false |
Non-Rule 10b5-1 Arrangement Terminated [Flag] | false |
Note 1 - Description of Operati
Note 1 - Description of Operations and Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2023 | |
Notes to Financial Statements | |
Organization, Consolidation and Presentation of Financial Statements Disclosure and Significant Accounting Policies [Text Block] | 1. Description of Operations and Significant Accounting Policies Nature of Operations: PrimeEnergy Resources Corporation (“PERC”), a Delaware corporation, was organized in March 1973 and is engaged in the development, acquisition and production of oil and natural gas properties. PrimeEnergy Resources Corporation and its subsidiaries are herein referred to as the “Company.” The Company owns leasehold, mineral and royalty interests in producing and non-producing oil and gas properties across the United States, primarily in Oklahoma, and Texas. The Company operates approximately 534 active wells and owns non-operating interests and royalties in approximately 952 additional wells. Additionally, the Company provides well-servicing support operations, site-preparation and construction services for oil and gas drilling and reworking operations, both in connection with the Company’s activities and providing contract services for third parties. The Company is publicly traded on the Nasdaq stock market under the symbol “PNRG.” PERC owns Eastern Oil Well Service Company (“EOWSC”) and EOWS Midland Company (“EMID”) which perform oil and gas field servicing. PERC also owns Prime Operating Company (“POC”), which serves as operator for producing oil and gas properties owned by the Company. The markets for the Company’s products are highly competitive, as oil and gas are commodity products and prices depend upon numerous factors beyond the control of the Company, such as economic, political and regulatory developments and competition from alternative energy sources. Consolidation and Presentation The consolidated financial statements include the accounts of PrimeEnergy Resources Corporation, and its subsidiaries. Subsequent Events: Subsequent events have been evaluated through the date that the consolidated financial statements were issued. During this period, there were no material subsequent items requiring disclosure, other than as stated in Footnote 4 and Footnote 5, to these consolidated financial statements. Use of Estimates: The preparation of consolidated financial statements in conformity with U.S. generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Estimates of oil and gas reserves, as determined by independent petroleum engineers, are continually subject to revision based on price, production history and other factors. Depletion expense, which is computed based on the units of production method, could be significantly impacted by changes in such estimates. Additionally, U.S. generally accepted accounting principles require that if the expected future undiscounted cash flows from an asset are less than its carrying cost, that asset must be written down to its fair market value. As the fair market value of an oil and gas property will usually be significantly less than the total undiscounted future net revenues expected from that asset, slight changes in the estimates used to determine future net revenues from an asset could lead to the necessity of recording a significant impairment of that asset. Cash and cash equivalents: The Company's cash and cash equivalents include cash on hand and short-term investments, such as money market deposits or similar type instruments, with a maturity of three months or less when purchased. Accounts receivable, net: The Company's net accounts receivable balance is primarily comprised of oil and gas sales receivables, joint interest receivables and other receivables for which the Company does not require collateral security. The Company's share of oil and gas production is sold to various purchasers and under various joint operating agreements. The Company records allowances for doubtful accounts based on historical collection experience, current and future economic and market conditions, the length of time that the accounts receivables have been outstanding and the financial condition of its purchasers. The Company's credit risk related to collecting accounts receivables is mitigated by using credit and other financial criteria to evaluate the credit standing of the entity obligated to make payment on the accounts receivable, and where appropriate, the Company obtains assurances of payment, such as a guarantee by the parent company of the counterparty, letters of credit or other credit support. The Company considers forward-looking information to estimate expected credit losses. The Company establishes allowances for bad debts equal to the estimable portions of accounts receivable for which failure to collect is expected to occur. The Company estimates uncollectible amounts for joint interest receivables based on the length of time that the accounts receivables have been outstanding, historical collection experience and current and future economic and market conditions. Allowances for doubtful accounts are recorded as reductions to the carrying values of the receivables included in the Company's consolidated balance sheets and are recorded in expense in the consolidated statements of operations in the accounting periods during which failure to collect an estimable portion is determined to be probable. The Company's allowance for doubtful accounts totaled $674 thousand and $336 thousand as of December 31, 2023 and 2022, respectively. In June 2016, the FASB issued ASU 2016-13, Financial Instruments—Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments. The standard’s main goal is to improve financial reporting by requiring earlier recognition of credit losses on financing receivables and other financial assets in scope. This guidance is effective for Smaller Reporting Companies for fiscal years beginning after December 15, 2022, including interim periods within those fiscal periods. The Company adopted this standard effective January 1, 2023. The adoption and implementation of this ASU did not have a material impact on the Company’s financial statements. Oil and gas properties: The Company utilizes the successful efforts method of accounting for its oil and gas properties. Under this method, all costs associated with productive wells and nonproductive development wells are capitalized while nonproductive exploration costs and geological and geophysical expenditures are expensed. Oil and gas leasehold acquisition costs are capitalized when incurred and included as unproved oil and gas properties in the consolidated balance sheets. The Company does not carry the costs of drilling an exploratory well as an asset in its consolidated balance sheets following the completion of drilling unless both of the following conditions are met: (i) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (ii) the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project. The Company’s exploratory wells include extension wells that extend the limits of a known reservoir. Due to the capital intensive nature and the geographical location of certain projects, it may take an extended period of time to evaluate the future potential of an exploration project and the economics associated with making a determination on its commercial viability. In these instances, the project’s feasibility is not contingent upon price improvements or advances in technology, but rather the Company’s ongoing efforts and expenditures related to accurately predicting the hydrocarbon recoverability based on well information, gaining access to other companies’ production data in the area, transportation or processing facilities, and/or getting partner approval to drill additional appraisal wells. These activities are ongoing and being pursued constantly. Consequently, the Company’s assessment of suspended exploratory/extension well costs is continuous until a decision can be made that the project has found sufficient proved reserves to sanction the project or is determined to be noncommercial and is charged to exploration and abandonments expense. As of December 31, 2023, the Company had no such suspended well costs. The capitalized costs of proved properties are depleted using the unit-of-production method based on proved reserves. Costs of significant nonproducing properties, wells in the process of being drilled and in-process development projects are excluded from depletion until the related project is completed and proved reserves are established or, if unsuccessful, abandonments expense is recognized. Proceeds from the sales of individual properties and the capitalized costs of individual properties sold or abandoned are credited and charged, respectively, to accumulated depletion, depreciation and amortization, if doing so does not materially impact the depletion rate of its amortization base. Generally, no gain or loss is recorded until an entire amortization base is sold. However, gain or loss is recorded from the sale of less than an entire amortization base if the disposition is significant enough to materially impact the depletion rate of the remaining properties in the amortization base. Field and Office Equipment: Field and office equipment is carried at cost. Depreciation of all other equipment is determined under the straight-line method using various rates based on useful lives generally ranging from 5 to 10 years. The cost of assets and related accumulated depreciation is removed from the accounts when such assets are disposed of, and any related gains or losses are reflected in current earnings. Leases: The Company enters into operating leases for its office space in Houston and Midland, Texas. The Company recognizes lease expense on a straight-line basis over the lease term. Lease right-of-use assets and liabilities are initially recorded on the lease commencement date based on the present value of lease payments over the lease term. As the Company's lease contracts do not provide an implicit discount rate, the Company uses its incremental borrowing rate, which is determined based on information available at the commencement date of a lease. Leases may include renewal, purchase or termination options that can extend or shorten the term of the lease. The exercise of those options is at the Company's sole discretion and is evaluated at inception and throughout the contract to determine if a modification of the lease term is required. Leases with an initial term of 12 months or less are not recorded as a lease right-of-use asset and liability. See Note 5 for additional information. Capitalization of Interest: Interest costs related to financing major oil and gas projects in progress are capitalized until the projects are evaluated or until the projects are substantially complete and ready for their intended use if the projects are evaluated and successful. Impairment of Long-Lived Assets: The Company reviews long-lived assets, including oil and gas properties, for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recovered. If the carrying amounts are not expected to be recovered by undiscounted cash flows, the assets are impaired, and an impairment loss is recorded. The amount of impairment is based on the estimated fair value of the assets determined by discounting anticipated future net cash flows. Fair Value: The Company follows the authoritative guidance that establishes a formal framework for measuring fair values of assets and liabilities in financial statements that are already required by U.S. generally accepted accounting principles to be measured at fair value. The guidance defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The transaction is based on a hypothetical transaction in the principal or most advantageous market considered from the perspective of the market participant that holds the asset or owes the liability. The Company utilizes market data or assumptions that market participants who are independent, knowledgeable and willing and able to transact would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. The Company attempts to utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The Company is able to classify fair value balances based on the observability of those inputs. The guidance establishes a formal fair value hierarchy based on the inputs used to measure fair value. The hierarchy gives the highest priority to Level 1 inputs, which consist of unadjusted quoted prices for identical instruments in active markets. Level 2 inputs consist of quoted prices for similar instruments. Level 3 valuations are derived from inputs that are significant and unobservable; hence, these valuations have the lowest priority. Revenue recognition: The majority of the Company’s production is operated by third party operators where we elect to market our products under the joint operating agreements. Accordingly, we receive our proportionate share of revenue proceeds for production sold by the operator under the operator’s marketing agreements. The Company recognizes revenue and any costs indicated by the operator in the related production period. The Company recognizes revenue related to production from properties operated by the Company when control of the promised goods or services is transferred to customers at an amount that reflects the consideration to which the Company expects to be entitled in exchange for those goods or services. Oil sales. NGL and gas sales Field service income Asset Retirement Obligation: The asset retirement obligation primarily represents the estimated present value of the amount the Company will incur to plug, abandon and remediate producing properties at the end of their productive lives, in accordance with applicable state laws. The Company determined its asset retirement obligation by calculating the present value of estimated cash flows related to the liability. The asset retirement obligation is recorded as a liability at its estimated present value at its inception, with an offsetting increase to producing properties. Periodic accretion of discount of the estimated liability is recorded as an expense in the statements of income. Income Taxes: The Company follows the asset and liability method of accounting for income taxes. Under this method, deferred tax assets and liabilities are recorded for the estimated future tax consequences attributable to the differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using the tax rate in effect for the year in which those temporary differences are expected to turn around. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in the year of the enacted rate change. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized. As of December 31, 2023 and 2022, the Company had no The Company is required to make judgments, including estimating reserves for potential adverse outcomes regarding tax positions that the Company has taken. The Company accounts for uncertainty in income taxes using a recognition and measurement threshold for tax positions taken or expected to be taken in a tax return. The effective tax rate and the tax basis of assets and liabilities reflect management’s estimates of the ultimate outcome of various tax uncertainties. General and Administrative Expenses: General and administrative expenses represent cost and expenses associated with the operation of the Company. Earnings Per Common Share: Basic earnings per share are computed by dividing earnings available to common stockholders by the weighted average number of common shares outstanding during the period. Diluted earnings per share reflect per share amounts that would have resulted if dilutive potential common stock had been converted to common stock in gain periods. Statements of Cash Flows: For purposes of the consolidated statements of cash flows, the Company considers short-term, highly liquid investments with original maturities of less than ninety days to be cash equivalents. Concentration of Credit Risk: The Company maintains significant banking relationships with financial institutions in the State of Texas. The Company limits its risk by periodically evaluating the relative credit standing of these financial institutions. The Company’s oil and gas production purchasers consist primarily of independent marketers and major gas pipeline companies. Hedging: The Company periodically enters into oil and gas financial instruments to manage its exposure to oil and gas price volatility. The oil and gas reference prices upon which the price hedging instruments are based reflect various market indices that have a high degree of historical correlation with actual prices received by the Company. The financial instruments are accounted for in accordance with applicable accounting standards for derivative instruments and hedging activities. Such standards require that applicable derivative instruments be measured at fair market value and recognized as assets or liabilities in the balance sheet. The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and the resulting designation is generally established at the inception of a derivative. For derivatives designated as cash flow hedges and meeting applicable effectiveness guidelines, changes in fair value, to the extent effective, are recognized in other comprehensive income until the hedged item is recognized in earnings. Hedge effectiveness is measured at least quarterly based on the relative changes in fair value between the derivative contract and the hedged item over time. Any change in fair value of a derivative resulting from ineffectiveness or an excluded component of the gain/loss is recognized immediately in the statements of income. New accounting standards . In December 2023, the FASB issued Accounting Standards Update 2023-09, "Income Taxes (Topic 740): Improvements to Income Tax Disclosures," which is effective for fiscal years beginning after December 15, 2024 with early adoption permitted. The amendments in this Accounting Standards Update are focused on income tax disclosure requirements, primarily related to the income tax rate reconciliation and income taxes paid, with prospective application to a company's consolidated financial statements recommended. The Company is currently assessing the impacts of these new accounting standards on its disclosures. |
Note 2 - Acquisitions and Dispo
Note 2 - Acquisitions and Dispositions | 12 Months Ended |
Dec. 31, 2023 | |
Notes to Financial Statements | |
Mergers, Acquisitions and Dispositions Disclosures [Text Block] | 2. Acquisitions and Dispositions 2023 Transactions: In the first quarter of 2023, the Company sold 7.8 surface acres in Midland County, Texas receiving gross proceeds of $436,050 and recognizing a gain of $47,000. In the second quarter of 2023, the Company acquired 55 net acres in the South Stiles area of Reagan County, Texas for $605,000, and in a separate agreement also in Reagan County, the Company sold 320 non-core acres for proceeds of $6,000,000. In addition, the Company sold 36.51% interest in one well in Midland County, Texas for proceeds of $60,000. In the third quarter of 2023, the Company sold a non-core 38.25-acre leasehold tract in Martin County, Texas for proceeds of $899,000 and sold 3 surface acres in Liberty County, Texas for net proceeds of $37,053. Also in the third quarter, in various counties of Oklahoma, the Company divested its interest in 39 wells, reducing its future plugging liability by approximately $1.5 million. Effective July 1, 2023, the Company acquired the operations of 36 wells from DE Permian and 50% of DE Permian’s original ownership in such wells. In addition, in Reagan County, Texas, the Company acquired 114.52 net acres from DE Permian for $1,700,853 and assigned to them 203.23 net acres. In the fourth quarter of 2023, the Company sold 136 surface acres in Oklahoma for net proceeds of $306,000 and in Midland Texas sold 9.35 net acres for proceeds of $280,423. 2022 Transactions : In the first quarter of 2022, the Company sold 1,809 net leasehold acres in Reagan and Midland Counties, Texas through two separate transactions receiving gross proceeds of $14.0 million. In the second quarter of 2022, the Company sold 241 net acres in Canadian County, Oklahoma for $845,000. In the third quarter of 2022, the Company sold an additional 113 net acres in Canadian County, Oklahoma for $423,700. On November 14, 2022, the Company completed an acreage exchange of approximately 725 net acres in the Midland Basin creating a block of 1,200 contiguous acres. The Company entered into an agreement, including this acreage, to create a 2,560-acre AMI for the joint development of horizontal wells. As part of the agreement, the Company sold a portion of its interest in this acreage to the joint development partner for proceeds of $16.1 million. |
Note 3 - Additional Balance She
Note 3 - Additional Balance Sheet Information | 12 Months Ended |
Dec. 31, 2023 | |
Notes to Financial Statements | |
Supplemental Balance Sheet Disclosures [Text Block] | 3. Additional Balance Sheet Information Accounts receivable, net at December 31, 2023 and 2022 consisted of the following: December 31, (Thousands of dollars) 2023 2022 Joint interest billings $ 2,560 $ 1,806 Trade receivables 2,345 1,762 Oil and gas sales 14,457 8,894 Taxes 1,458 -- Other 155 21 20,975 12,483 Less: Allowance for credit losses (674 ) (336 ) Total $ 20,301 $ 12,147 Accounts payable at December 31, 2023 and 2022 consisted of the following: December 31, (Thousands of dollars) 2024 2022 Trade $ 9,847 $ 5,142 Royalty and other owners 4,405 3,600 Partner advances 946 1,111 Other 226 1,598 Total $ 15,424 $ 11,451 Accrued liabilities at December 31, 2023 and 2022 consisted of the following: December 31, (Thousands of dollars) 2023 2022 Compensation and related expenses $ 10,324 $ 9,743 Property costs 33,264 6,413 Taxes 929 9,352 Lease operating costs 3,898 1,695 Other 198 242 Total $ 48,613 $ 25,750 |
Note 4 - Long-Term Debt
Note 4 - Long-Term Debt | 12 Months Ended |
Dec. 31, 2023 | |
Notes to Financial Statements | |
Long-Term Debt [Text Block] | 4. Long-Term Debt Bank Debt: On July 5, 2022, the Company and its lenders entered into a Fourth Amended and Restated Credit Agreement (the “2022 Credit Agreement”) with a maturity date of June 1, 2026. Under the 2022 Credit Agreement, the Company has a revolving line of credit and letter of credit facility of up to $300 million subject to a borrowing base that is determined semi-annually by the lenders based upon the Company’s consolidated financial statements and the estimated value of the Company’s oil and gas properties, in accordance with the Lenders’ customary practices for oil and gas loans. The initial borrowing base of the agreement is $75 million. The credit facility is secured by substantially all of the Company’s oil and gas properties. The 2022 Credit Agreement includes terms and covenants that require the Company to maintain a minimum current ratio and total indebtedness to EBITDAX (earnings before depreciation, depletion, amortization, taxes, interest expense and exploration costs) ratio, as defined, and restrictions are placed on the payment of dividends, the amount of treasury stock the Company may purchase, and commodity hedge agreements. On December 31, 2022, the Company had a total of $11 million of borrowings outstanding under its revolving credit facility and $64 million was available for future borrowings. Effective January 20, 2023, in lieu of a formal amendment, a borrowing base letter authorized by all lenders and the Company of the 2022 Credit Agreement resulted in an adjustment to decrease the amount of the Borrowing Base available from $75 million to $60 million until such time as the next redetermination date as required by the agreement. Effective July 24, 2023, in lieu of a formal amendment, a borrowing base letter authorized by all lenders and the Company of the 2022 Credit Agreement resulted in an adjustment to increase the amount of the Borrowing Base available from $60 million to $65 million until such time as the next redetermination date as required by the agreement. As of December 31, 2023, the borrowing base was $65 million and the Company had no outstanding borrowings under the Credit Facility. Effective February 9, 2024, the Company and its lenders entered into the Second Amendment to the 2022 Credit Agreement. This amendment included an increase of the Borrowing Base from $65 million to $85 million and will remain in effect until the next scheduled redetermination date in accordance with the Credit Agreement. As of March 31, 2024 the Company had $4 million of outstanding borrowings and $81 million available under the credit facility. |
Note 5 - Other Long-Term Obliga
Note 5 - Other Long-Term Obligations and Commitments | 12 Months Ended |
Dec. 31, 2023 | |
Notes to Financial Statements | |
Other Long Term Obligations And Commitments Disclosure [Text Block] | 5. Other Long-Term Obligations and Commitments: Operating Leases: The Company leases office facilities under operating leases and recognizes lease expense on a straight-line basis over the lease term. Lease assets and liabilities are initially recorded at commencement date based on the present value of lease payments over the lease term. As most of the Company’s lease contracts do not provide an implicit discount rate, the Company uses its incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments. The weighted average discount rate used was 6.96%. Certain leases may contain variable costs above the minimum required payments and are not included in the right-of-use assets or liabilities. Leases may include renewal, purchase or termination options that can extend or shorten the term of the lease. The exercise of those options is at the Company’s sole discretion and is evaluated at inception and throughout the contract to determine if a modification of the lease term is required. Leases with an initial term of 12 months or less are not recorded on the balance sheet. Operating lease costs for the years ended December 31, 2023 and 2022 were $700 thousand and $628 thousand, respectively. Cash payments included in the operating lease cost for years ended December 31, 2023 and 2022 were $739 thousand and $673 thousand, respectively. The weighted-average remaining operating lease terms for the years ended December 31, 2023 and 2022 were 11 months and 11 months, respectively. As of 2023, the Company had certain leases for office space in Texas which included future payments of $275,000 in 2024 and $45,000 in 2025. On March 4, 2024 the Company entered into a twelve-month lease extension agreement, effective March 1, 2024, with the landlord of the Company's Houston office. Rent expense for office space for the years ended December 31, 2023 and 2022 was $767,000 and $755,000, respectively. The payment schedule for the Company’s operating lease obligations as of December 31, 2023 is as follows: (Thousands of dollars) Operating 2024 275 2025 45 Total undiscounted lease payments $ 320 Less: Amount associated with discounting (36 ) Total net operating lease liabilities $ 284 Less: Current portion included in Current portion of Asset Retirement and Other Long-Term Obligations 246 Non-current portion included in Other Long-Term Obligations $ 38 Asset Retirement Obligation: A reconciliation of the liability for plugging and abandonment costs for the years ended December 31, 2023 and 2022 is as follows: Years Ended (Thousands of dollars) 2023 2022 Asset retirement obligation at beginning of period $ 15,443 $ 14,295 Net wells placed on production 254 11 Liabilities settled (2,706 ) (1,407 ) Dispositions (1,161 ) (344 ) Accretion expense 684 667 Revisions in estimated liabilities 2,639 2,221 Asset retirement obligation at end of period $ 15,153 $ 15,443 Less: Current portion included in Current portion of asset retirement and other long-term obligations 446 1,918 Long-term Asset Retirement Obligations included in Asset Retirement Obligations $ 14,707 $ 13,525 The Company’s liability is determined using significant assumptions, including current estimates of plugging and abandonment costs, annual inflation of these costs, the productive life of wells and a risk-adjusted interest rate. Changes in any of these assumptions can result in significant revisions to the estimated asset retirement obligation. Revisions to the asset retirement obligation are recorded with an offsetting change to producing properties, resulting in prospective changes to depreciation, depletion and amortization expense and accretion of discount. Because of the subjectivity of assumptions and the relatively long life of most of the Company’s wells, the costs to ultimately retire the wells may vary significantly from previous estimates. |
Note 6 - Contingent Liabilities
Note 6 - Contingent Liabilities | 12 Months Ended |
Dec. 31, 2023 | |
Notes to Financial Statements | |
Contingencies Disclosure [Text Block] | 6. Contingent Liabilities The Company is subject to environmental laws and regulations. Management believes that future expenses, before recoveries from third parties, if any, will not have a material effect on the Company’s financial condition. This opinion is based on expenses incurred to date for remediation and compliance with laws and regulations, which have not been material to the Company’s results of operations. From time to time, the Company is party to certain legal actions arising in the ordinary course of business. While the outcome of these events cannot be predicted with certainty, management does not expect these matters to have a materially adverse effect on the financial position or results of operations of the Company. |
Note 7 - Stock Options and Othe
Note 7 - Stock Options and Other Compensation | 12 Months Ended |
Dec. 31, 2023 | |
Notes to Financial Statements | |
Share-Based Payment Arrangement [Text Block] | 7. Stock Options and Other Compensation In May 1989, non-statutory stock options were granted by the Company to four |
Note 8 - Income Taxes
Note 8 - Income Taxes | 12 Months Ended |
Dec. 31, 2023 | |
Notes to Financial Statements | |
Income Tax Disclosure [Text Block] | 8. Income Taxes The components of the provision for income taxes for the years ended December 31, 2023 and 2022 are as follows: Years Ended (Thousands of dollars) 2023 2022 Current: Federal $ (891 ) $ 8,330 State (258 ) 774 Total current (1,149 ) 9,104 Deferred: Federal 6,544 886 State 724 339 Total deferred 7,268 1,225 Total income tax provision $ 6,119 $ 10,329 The components of net deferred tax assets and liabilities are as follows: At December 31, (Thousands of dollars) 2023 2022 Deferred Tax Assets: Accrued liabilities $ 349 $ 353 Allowance for doubtful accounts 154 77 Derivative Contracts - 223 Partnership basis difference 106 90 State Net operating loss carry-forwards 278 283 Total deferred tax assets 887 1,026 Deferred Tax Liabilities: Depletion and depreciation 48,123 40,994 Total deferred tax liabilities 48,123 40,994 Net deferred tax liabilities $ 47,236 $ 39,968 The total provision for income taxes for the years ended December 31, 2023 and 2022 varies from the federal statutory tax rate as a result of the following: Years Ended (Thousands of dollars) 2023 2022 Expected tax expense $ 7,187 $ 12,389 Permanent differences 221 870 State income tax, net of federal benefit 204 612 Provision to return adjustment (1,534 ) (3,540 ) Other, net 41 (2 ) Total income tax provision $ 6,119 $ 10,329 Deferred income taxes reflect the impact of temporary differences between the amount of assets and liabilities recognized for financial reporting purposes and such amounts recognized for tax purposes. The Company is entitled to percentage depletion on certain of its wells, which is calculated without reference to the basis of the property. To the extent that such depletion exceeds a property’s basis, it creates a permanent difference, which lowers the Company’s effective rate. The availability of the percentage depletion deduction is phased out as an entity’s production exceeds certain levels, and based on the Company’s increasing production the percentage depletion deduction is becoming less significant. The Company is allowed a credit against the Texas Franchise Tax based on net operating losses incurred in prior periods. The credits allowed are $89 thousand in the years 2023 through 2026. Any credits not utilized in a given year due to the allowable credit exceeding the tax liability may be carried forward. No credit may be carried forward past 2026. The value of the credit is calculated net of the federal income tax effect. The Company has not recorded any provision for uncertain tax positions. The Company files income tax returns in the U.S. federal jurisdiction and various state and local jurisdictions. The 2004, 2005, 2006, 2009 and 2017 federal income tax returns have been audited by the Internal Revenue Service. Returns for unexamined earlier years may be examined and adjustments made to the amount of percentage depletion and AMT credit carryforwards flowing from those years into an open tax year, although in general no assessment of income tax may be made for those years on which the statute has closed. Federal and State returns for the years 2020 through 2022 remain open for examination by the relevant taxing authorities. Enactment of the Inflation Reduction Act of 2022. On August 16, 2022, President Biden signed into law the Inflation Reduction Act of 2022 (the “IRA”), which includes, among other things, a corporate alternative minimum tax (the “CAMT”). Under the CAMT, a 15 percent minimum tax will be imposed on certain adjusted financial statement income of “applicable corporations,” which is effective for tax years beginning after December 31, 2022. The CAMT generally treats a corporation as an “applicable corporation” in any taxable year in which the “average annual adjusted financial statement income” of the corporation and certain of its subsidiaries and affiliates for a three taxable-year period ending prior to such taxable year exceeds $1 billion. The IRA also establishes a one percent excise tax on stock repurchases made by publicly traded U.S. corporations. The excise tax is effective for any stock repurchases after December 31, 2022. The value of share repurchases subject to the excise tax is reduced by the fair market value of any shares issued during the tax year, including the fair market value of any shares issued or provided to employees or specified affiliates. During the year ended December 31, 2023, the Company recorded $74 thousand related to the IRA excise tax payable on share repurchases. |
Note 9 - Segment Information an
Note 9 - Segment Information and Major Customers | 12 Months Ended |
Dec. 31, 2023 | |
Notes to Financial Statements | |
Segment Reporting Disclosure [Text Block] | 9. Segment Information and Major Customers The Company operates in one industry – oil and gas exploration, development, operation and servicing. The Company’s oil and gas activities are entirely in the United States. The Company sells its oil and natural gas and liquids production to a number of direct purcchasers under direct contracts or through other operators under joint operating agreements. Listed below are the purchasers of the Company’s production which represented more than 10% of the Company’s sales for the years ended 2023 and 2022. 2023 2022 Oil: APA Corporation 22 % 55 % Civitas Resources Inc. 20 % -- % Plains All American Inc. 19 % 16 % DE IV Operating, LLC. 14 % -- % Natural gas and liquids: APA Corporation 17 % 58 % Civitas Resources Inc. 10 % -- % Targa Pipeline Mid-Continent West Tex, LLC -- % 11 % Although there are no long-term oil and gas purchasing agreements with these purchasers, the Company believes that they will continue to purchase its oil and gas products and, if not, could be replaced by other purchasers. |
Note 10 - Financial Instruments
Note 10 - Financial Instruments | 12 Months Ended |
Dec. 31, 2023 | |
Notes to Financial Statements | |
Financial Instruments Disclosure [Text Block] | 10. Financial Instruments Fair Value Measurements: Authoritative guidance on fair value measurements defines fair value, establishes a framework for measuring fair value and stipulates the related disclosure requirements. The Company follows a three-level hierarchy, prioritizing and defining the types of inputs used to measure fair value. The fair values of the Company’s interest rate swaps, natural gas and crude oil price collars and swaps are designated as Level 3. The following fair value hierarchy table presents information about the Company’s assets and liabilities measured at fair value on a recurring basis at December 31, 2022: December 31, 2022 Quoted Prices in Significant Significant Balance at (Thousands of dollars) Assets Commodity derivative contracts $ — $ — $ 210 $ 210 Total assets $ — $ — $ 210 $ 210 Liabilities Commodity derivative contract $ — $ — $ (1,190 ) $ (1,190 ) Total liabilities $ — $ — $ (1,190 ) $ (1,190 ) The derivative contracts were measured based on quotes from the Company’s counterparties. Such quotes have been derived using valuation models that consider various inputs including current market and contractual prices for the underlying instruments, quoted forward prices for natural gas and crude oil, volatility factors and interest rates, such as a LIBOR curve for a similar length of time as the derivative contract term as applicable. These estimates are verified using comparable NYMEX futures contracts or are compared to multiple quotes obtained from counterparties for reasonableness. The significant unobservable inputs for Level 3 derivative contracts include basis differentials and volatility factors. An increase (decrease) in these unobservable inputs would result in an increase (decrease) in fair value, respectively. The Company does not have access to the specific assumptions used in its counterparties’ valuation models. Consequently, additional disclosures regarding significant Level 3 unobservable inputs were not provided. The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the year ended December 2023. (Thousands of dollars) Net Liabilities – December 31, 2022 $ (980 ) Total realized and unrealized gains 980 Net Liabilities – December 31, 2023 $ — (a) Derivative instruments are reported in revenues as realized gain/loss and on a separately reported line item captioned unrealized gain/loss on derivative instruments. Derivative Instruments: The Company is exposed to commodity price and interest rate risk, and management considers periodically the Company’s exposure to cash flow variability resulting from the commodity price changes and interest rate fluctuations. Futures, swaps and options are used to manage the Company’s exposure to commodity price risk inherent in the Company’s oil and gas production operations. The Company does not apply hedge accounting to any of its commodity-based derivatives. Both realized and unrealized gains and losses associated with commodity derivative instruments are recognized in earnings. The following table sets forth the effect of derivative instruments on the consolidated balance sheets at December 31, 2023 and 2022: Fair Value (Thousands of dollars) Balance Sheet Location December 31, December 31, Asset Derivatives: Derivatives not designated as cash-flow hedging instruments: Crude oil commodity contract Other current assets $ — $ 162 Natural gas commodity contract Other current assets — 48 Total $ — $ 210 Liability Derivatives: Derivatives not designated as cash-flow hedging instruments: Crude oil commodity contracts Derivative liability short-term $ — $ (931 ) Natural gas commodity contracts Derivative liability short-term — (259 ) Total $ — $ (1,190 ) Total derivative instruments $ — $ (980 ) The following table sets forth the effect of derivative instruments on the consolidated statements of income for the years ended December 31, 2023 and 2022: Amount of gain/loss (Thousands of dollars) Location of gain/loss recognized in income 2023 2022 Derivatives not designated as cash-flow hedge instruments: Natural gas commodity contracts Unrealized gain on derivative instruments, net — 892 Crude oil commodity contracts Unrealized gain on derivative instruments, net — 3,713 Natural gas commodity contracts Realized gain (loss) on derivative instruments, net 235 (4,543 ) Crude oil commodity contracts Realized gain (loss) on derivative instruments, net 179 (12,101 ) $ 414 $ (12,039 ) |
Note 11 - Related Party Transac
Note 11 - Related Party Transactions | 12 Months Ended |
Dec. 31, 2023 | |
Notes to Financial Statements | |
Related Party Transactions Disclosure [Text Block] | 11. Related Party Transactions Amounts due to or from related parties primarily represent receipts or expenses, related to oil and gas properties, collected or paid by the Company as agent for the joint venture partners, which may include members of the Company’s Board of Directors. |
Note 12 - Salary Deferral Plan
Note 12 - Salary Deferral Plan | 12 Months Ended |
Dec. 31, 2023 | |
Notes to Financial Statements | |
Retirement Benefits [Text Block] | 12. Salary Deferral Plan The Company maintains a salary deferral plan (the “Plan”) in accordance with Internal Revenue Code Section 401(k), as amended. The Plan provides for matching contributions, of which $362,756 and $301,837 were made in 2023 and 2022, respectively. |
Note 13 - Earnings Per Share
Note 13 - Earnings Per Share | 12 Months Ended |
Dec. 31, 2023 | |
Notes to Financial Statements | |
Earnings Per Share [Text Block] | 13. Earnings per Share Basic earnings per share are computed by dividing earnings available to common stockholders by the weighted average number of common shares outstanding during the period. Diluted earnings per share reflect per share amounts that would have resulted if dilutive potential common stock had been converted to common stock in gain periods. The following reconciles amounts reported in the consolidated financial statements: Years Ended December 31, 2023 2022 Net Income Weighted Per Share Net Income Weighted Per Share Basic $ 28,103 1,849,780 $ 15.19 $ 48,664 1,953,916 $ 24.91 Effect of dilutive securities: Options — 759,006 — 757,254 Diluted $ 28,103 2,608,786 $ 10.77 $ 48,664 2,711,170 $ 17.95 |
Supplementary Information
Supplementary Information | 12 Months Ended |
Dec. 31, 2023 | |
Notes to Financial Statements | |
Additional Financial Information Disclosure [Text Block] | PRIMEENERGY RESOURCES CORPORATION AND SUBSIDIARIES SUPPLEMENTARY INFORMATION CAPITALIZED COSTS RELATING TO OIL AND GAS PRODUCING ACTIVITIES (Unaudited) As of December 31, (Thousands of dollars) 2023 2022 Proved Developed oil and gas properties $ 659,792 $ 555,280 Proved Undeveloped oil and gas properties — — Total Capitalized Costs 659,792 555,280 Accumulated depreciation, depletion and valuation allowance (406,913 ) (385,811 ) Net Capitalized Costs $ 252,879 $ 169,469 COSTS INCURRED IN OIL AND GAS PROPERTY ACQUISITION, EXPLORATION AND DEVELOPMENT ACTIVITIES (Unaudited) Years Ended December 31, (Thousands of dollars) 2023 2022 Development Costs $ 110,700 $ 13,598 STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVES (Unaudited) As of December 31, (Thousands of dollars) 2023 2022 Future cash inflows $ 1,219,605 $ 994,842 Future production costs (437,408 ) (378,160 ) Future development costs (213,823 ) (95,746 ) Future income tax expenses (119,359 ) (110,439 ) Future Net Cash Flows 449,015 410,497 10% annual discount for estimated timing of cash flows (170,967 ) (165,961 ) Standardized Measure of Discounted Future Net Cash Flows $ 278,048 $ 244,536 See accompanying Notes to Supplementary Information PRIMEENERGY RESOURES CORPORATION AND SUBSIDIARIES SUPPLEMENTARY INFORMATION STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS AND CHANGES THEREIN RELATING TO PROVED OIL AND GAS RESERVES (Unaudited) The following are the principal sources of change in the standardized measure of discounted future net cash flows during 2023 and 2022: Years Ended (Thousands of dollars) 2023 2022 Sales of oil and gas produced, net of production costs $ (107,742 ) $ (86,302 ) Net changes in prices and production costs (98,132 ) 72,640 Extensions, discoveries and improved recovery 178,960 126,029 Revisions of previous quantity estimates (3,877 ) (10,902 ) Net change in development costs 66,552 (2,814 ) Reserves sold (398 ) (818 ) Reserves purchased — — Accretion of discount 24,454 13,581 Net change in income taxes 4,532 (8,435 ) Changes in production rates (timing) and other (30,836 ) 5,751 Net change 33,512 108,730 Standardized measure of discounted future net cash flow: Beginning of year 244,536 135,806 End of year $ 278,048 $ 244,536 See accompanying Notes to Supplementary Information PRIMEENERGY RESOURCES CORPORATION AND SUBSIDIARIES SUPPLEMENTARY INFORMATION RESERVE QUANTITY INFORMATION Years Ended December 31, 2023 and 2022 (Unaudited) As of December 31, 2023 2022 Oil NGL’s Gas Oil NGLs Gas Proved Developed Reserves: Beginning of year 4,143 2,497 22,277 5,386 2,882 23,902 Extensions, discoveries and improved recovery 843 467 2,391 99 74 464 Revisions of previous estimates (1,101 ) (515 ) (4,796 ) (375 ) (37 ) 1,309 Converted from undeveloped reserves 3,028 1,833 9,030 — — — Reserves sold (12 ) — (26 ) (28 ) (5 ) (73 ) Reserve purchased — — — — — — Production (1,144 ) (606 ) (4,127 ) (939 ) (417 ) (3,325 ) End of year 5,757 3,676 24,749 4,143 2,497 22,277 Proved Undeveloped Reserves: Beginning of year 3,028 1,833 9,030 — — — Extensions, discoveries and improved recovery 6,254 5,156 24,470 3,028 1,833 9,030 Revisions of previous estimates — — — — — — Converted to developed reserves (3,028 ) (1,833 ) (9,030 ) — — — Reserves Sold — — — — — — End of year 6,254 5,156 24,470 3,028 1,833 9,030 Total Proved Reserves at the End of the Year 12,011 8,832 49,219 7,171 4,330 31,307 RESULTS OF OPERATIONS FROM OIL AND GAS PRODUCING ACTIVITIES Years Ended December 31, 2023 and 2022 (Unaudited) Years Ended December 31, (Thousands of dollars) 2023 2022 Revenue: Oil and gas sales $ 107,742 $ 124,118 Costs and Expenses: Lease operating expenses 39,004 37,816 Depreciation, depletion and accretion 31,660 28,068 Income tax expense 5,797 10,329 Total Costs and Expenses 76,461 76,213 Results of Operations from Producing Activities (excluding corporate overhead and interest costs) $ 31,281 $ 47,905 See accompanying Notes to Supplementary Information PRIMEENERGY RESOURCES CORPORATION AND SUBSIDIARIES NOTES TO SUPPLEMENTARY INFORMATION (Unaudited) 1. Presentation of Reserve Disclosure Information Reserve disclosure information is presented in accordance with U.S. generally accepted accounting principles. The Company’s reserves include amounts attributable to non-controlling interests in the Partnerships. These interests represent less than 10% of the Company’s reserves. 2. Determination of Proved Reserves The estimates of the Company’s proved reserves were determined by an independent petroleum engineer in accordance with U.S. generally accepted accounting principles. The estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development and other factors. Estimated future net revenues were computed by reserves, less estimated future development and production costs based on current costs. Proved reserve quantity estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. The accuracy of such estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of subsequent drilling, testing and production may cause either upward or downward revision of previous estimates. Further, the volumes considered to be commercially recoverable fluctuate with changes in prices and operating costs. The Company emphasizes that proved reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of currently producing oil and gas properties. Accordingly, these estimates are expected to change as additional information becomes available in the future. 3. Results of Operations from Oil and Gas Producing Activities The results of operations from oil and gas producing activities were prepared in accordance with U.S. generally accepted accounting principles. General and administrative expenses, interest costs and other unrelated costs are not deducted in computing results of operations from oil and gas activities. 4. Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Gas Reserves The standardized measure of discounted future net cash flows relating to proved oil and gas reserves and the changes of standardized measure of discounted future net cash flows relating to proved oil and gas reserves were prepared in accordance with U.S. generally accepted accounting principles. Future cash inflows are computed as described in Note 2 by applying current prices to year-end quantities of proved reserves. Future production and development costs are computed estimating the expenditures to be incurred in developing and producing the oil and gas reserves at year-end, based on year-end costs and assuming continuation of existing economic conditions. Future income tax expenses are calculated by applying the U.S. tax rate to future pre-tax cash inflows relating to proved oil and gas reserves, less the tax basis of properties involved. Future income tax expenses give effect to permanent differences and tax credits and allowances relating to the proved oil and gas reserves. Future net cash flows are discounted at a rate of 10% annually (pursuant to applicable guidance) to derive the standardized measure of discounted future net cash flows. This calculation does not necessarily represent an estimate of fair market value or the present value of such cash flows since future prices and costs can vary substantially from year-end and the use of a 10% discount figure is arbitrary. 5. Changes in Reserves The 2023 and 2022 extensions and discoveries reflect the drilling activity in the Company’s West Texas and Mid-Continent areas. The Company is employing technologies to establish proved reserves that have been demonstrated to provide consistent results capable of repetition. The technologies and economic data being used in the estimation of its proved reserves include, but are not limited to, electrical logs, radioactivity logs, geologic maps, production data and well test data. The estimated reserves of wells with sufficient production history are estimated using appropriate decline curves. Estimated reserves of producing wells with limited production history and for undeveloped locations are estimated using performance data from analogous wells in the area. These wells are considered analogous based on production performance from the same formation and with similar completion techniques. Future development plans are reflective of the current commodity prices and have been established based on an expectation of available cash flows from operations and availability under our revolving credit facility. |
Significant Accounting Policies
Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2023 | |
Accounting Policies [Abstract] | |
Consolidation, Policy [Policy Text Block] | Consolidation and Presentation The consolidated financial statements include the accounts of PrimeEnergy Resources Corporation, and its subsidiaries. |
Reclassification, Comparability Adjustment [Policy Text Block] | |
Subsequent Events, Policy [Policy Text Block] | Subsequent Events: Subsequent events have been evaluated through the date that the consolidated financial statements were issued. During this period, there were no material subsequent items requiring disclosure, other than as stated in Footnote 4 and Footnote 5, to these consolidated financial statements. |
Use of Estimates, Policy [Policy Text Block] | Use of Estimates: The preparation of consolidated financial statements in conformity with U.S. generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Estimates of oil and gas reserves, as determined by independent petroleum engineers, are continually subject to revision based on price, production history and other factors. Depletion expense, which is computed based on the units of production method, could be significantly impacted by changes in such estimates. Additionally, U.S. generally accepted accounting principles require that if the expected future undiscounted cash flows from an asset are less than its carrying cost, that asset must be written down to its fair market value. As the fair market value of an oil and gas property will usually be significantly less than the total undiscounted future net revenues expected from that asset, slight changes in the estimates used to determine future net revenues from an asset could lead to the necessity of recording a significant impairment of that asset. |
Cash and Cash Equivalents, Policy [Policy Text Block] | Cash and cash equivalents: The Company's cash and cash equivalents include cash on hand and short-term investments, such as money market deposits or similar type instruments, with a maturity of three months or less when purchased. |
Accounts Receivable [Policy Text Block] | Accounts receivable, net: The Company's net accounts receivable balance is primarily comprised of oil and gas sales receivables, joint interest receivables and other receivables for which the Company does not require collateral security. The Company's share of oil and gas production is sold to various purchasers and under various joint operating agreements. The Company records allowances for doubtful accounts based on historical collection experience, current and future economic and market conditions, the length of time that the accounts receivables have been outstanding and the financial condition of its purchasers. The Company's credit risk related to collecting accounts receivables is mitigated by using credit and other financial criteria to evaluate the credit standing of the entity obligated to make payment on the accounts receivable, and where appropriate, the Company obtains assurances of payment, such as a guarantee by the parent company of the counterparty, letters of credit or other credit support. The Company considers forward-looking information to estimate expected credit losses. The Company establishes allowances for bad debts equal to the estimable portions of accounts receivable for which failure to collect is expected to occur. The Company estimates uncollectible amounts for joint interest receivables based on the length of time that the accounts receivables have been outstanding, historical collection experience and current and future economic and market conditions. Allowances for doubtful accounts are recorded as reductions to the carrying values of the receivables included in the Company's consolidated balance sheets and are recorded in expense in the consolidated statements of operations in the accounting periods during which failure to collect an estimable portion is determined to be probable. The Company's allowance for doubtful accounts totaled $674 thousand and $336 thousand as of December 31, 2023 and 2022, respectively. In June 2016, the FASB issued ASU 2016-13, Financial Instruments—Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments. The standard’s main goal is to improve financial reporting by requiring earlier recognition of credit losses on financing receivables and other financial assets in scope. This guidance is effective for Smaller Reporting Companies for fiscal years beginning after December 15, 2022, including interim periods within those fiscal periods. The Company adopted this standard effective January 1, 2023. The adoption and implementation of this ASU did not have a material impact on the Company’s financial statements. |
Oil and Gas Properties Policy [Policy Text Block] | Oil and gas properties: The Company utilizes the successful efforts method of accounting for its oil and gas properties. Under this method, all costs associated with productive wells and nonproductive development wells are capitalized while nonproductive exploration costs and geological and geophysical expenditures are expensed. Oil and gas leasehold acquisition costs are capitalized when incurred and included as unproved oil and gas properties in the consolidated balance sheets. The Company does not carry the costs of drilling an exploratory well as an asset in its consolidated balance sheets following the completion of drilling unless both of the following conditions are met: (i) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (ii) the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project. The Company’s exploratory wells include extension wells that extend the limits of a known reservoir. Due to the capital intensive nature and the geographical location of certain projects, it may take an extended period of time to evaluate the future potential of an exploration project and the economics associated with making a determination on its commercial viability. In these instances, the project’s feasibility is not contingent upon price improvements or advances in technology, but rather the Company’s ongoing efforts and expenditures related to accurately predicting the hydrocarbon recoverability based on well information, gaining access to other companies’ production data in the area, transportation or processing facilities, and/or getting partner approval to drill additional appraisal wells. These activities are ongoing and being pursued constantly. Consequently, the Company’s assessment of suspended exploratory/extension well costs is continuous until a decision can be made that the project has found sufficient proved reserves to sanction the project or is determined to be noncommercial and is charged to exploration and abandonments expense. As of December 31, 2023, the Company had no such suspended well costs. The capitalized costs of proved properties are depleted using the unit-of-production method based on proved reserves. Costs of significant nonproducing properties, wells in the process of being drilled and in-process development projects are excluded from depletion until the related project is completed and proved reserves are established or, if unsuccessful, abandonments expense is recognized. Proceeds from the sales of individual properties and the capitalized costs of individual properties sold or abandoned are credited and charged, respectively, to accumulated depletion, depreciation and amortization, if doing so does not materially impact the depletion rate of its amortization base. Generally, no gain or loss is recorded until an entire amortization base is sold. However, gain or loss is recorded from the sale of less than an entire amortization base if the disposition is significant enough to materially impact the depletion rate of the remaining properties in the amortization base. |
Property, Plant and Equipment, Policy [Policy Text Block] | Field and Office Equipment: Field and office equipment is carried at cost. Depreciation of all other equipment is determined under the straight-line method using various rates based on useful lives generally ranging from 5 to 10 years. The cost of assets and related accumulated depreciation is removed from the accounts when such assets are disposed of, and any related gains or losses are reflected in current earnings. |
Lessee, Leases [Policy Text Block] | Leases: The Company enters into operating leases for its office space in Houston and Midland, Texas. The Company recognizes lease expense on a straight-line basis over the lease term. Lease right-of-use assets and liabilities are initially recorded on the lease commencement date based on the present value of lease payments over the lease term. As the Company's lease contracts do not provide an implicit discount rate, the Company uses its incremental borrowing rate, which is determined based on information available at the commencement date of a lease. Leases may include renewal, purchase or termination options that can extend or shorten the term of the lease. The exercise of those options is at the Company's sole discretion and is evaluated at inception and throughout the contract to determine if a modification of the lease term is required. Leases with an initial term of 12 months or less are not recorded as a lease right-of-use asset and liability. See Note 5 for additional information. |
Interest Capitalization, Policy [Policy Text Block] | Capitalization of Interest: Interest costs related to financing major oil and gas projects in progress are capitalized until the projects are evaluated or until the projects are substantially complete and ready for their intended use if the projects are evaluated and successful. |
Impairment or Disposal of Long-Lived Assets, Policy [Policy Text Block] | Impairment of Long-Lived Assets: The Company reviews long-lived assets, including oil and gas properties, for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recovered. If the carrying amounts are not expected to be recovered by undiscounted cash flows, the assets are impaired, and an impairment loss is recorded. The amount of impairment is based on the estimated fair value of the assets determined by discounting anticipated future net cash flows. |
Fair Value Measurement, Policy [Policy Text Block] | Fair Value: The Company follows the authoritative guidance that establishes a formal framework for measuring fair values of assets and liabilities in financial statements that are already required by U.S. generally accepted accounting principles to be measured at fair value. The guidance defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The transaction is based on a hypothetical transaction in the principal or most advantageous market considered from the perspective of the market participant that holds the asset or owes the liability. The Company utilizes market data or assumptions that market participants who are independent, knowledgeable and willing and able to transact would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. The Company attempts to utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The Company is able to classify fair value balances based on the observability of those inputs. The guidance establishes a formal fair value hierarchy based on the inputs used to measure fair value. The hierarchy gives the highest priority to Level 1 inputs, which consist of unadjusted quoted prices for identical instruments in active markets. Level 2 inputs consist of quoted prices for similar instruments. Level 3 valuations are derived from inputs that are significant and unobservable; hence, these valuations have the lowest priority. |
Revenue [Policy Text Block] | Revenue recognition: The majority of the Company’s production is operated by third party operators where we elect to market our products under the joint operating agreements. Accordingly, we receive our proportionate share of revenue proceeds for production sold by the operator under the operator’s marketing agreements. The Company recognizes revenue and any costs indicated by the operator in the related production period. The Company recognizes revenue related to production from properties operated by the Company when control of the promised goods or services is transferred to customers at an amount that reflects the consideration to which the Company expects to be entitled in exchange for those goods or services. Oil sales. NGL and gas sales Field service income |
Asset Retirement Obligation [Policy Text Block] | Asset Retirement Obligation: The asset retirement obligation primarily represents the estimated present value of the amount the Company will incur to plug, abandon and remediate producing properties at the end of their productive lives, in accordance with applicable state laws. The Company determined its asset retirement obligation by calculating the present value of estimated cash flows related to the liability. The asset retirement obligation is recorded as a liability at its estimated present value at its inception, with an offsetting increase to producing properties. Periodic accretion of discount of the estimated liability is recorded as an expense in the statements of income. |
Income Tax, Policy [Policy Text Block] | Income Taxes: The Company follows the asset and liability method of accounting for income taxes. Under this method, deferred tax assets and liabilities are recorded for the estimated future tax consequences attributable to the differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using the tax rate in effect for the year in which those temporary differences are expected to turn around. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in the year of the enacted rate change. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized. As of December 31, 2023 and 2022, the Company had no The Company is required to make judgments, including estimating reserves for potential adverse outcomes regarding tax positions that the Company has taken. The Company accounts for uncertainty in income taxes using a recognition and measurement threshold for tax positions taken or expected to be taken in a tax return. The effective tax rate and the tax basis of assets and liabilities reflect management’s estimates of the ultimate outcome of various tax uncertainties. |
Selling, General and Administrative Expenses, Policy [Policy Text Block] | General and Administrative Expenses: General and administrative expenses represent cost and expenses associated with the operation of the Company. |
Earnings Per Share, Policy [Policy Text Block] | Earnings Per Common Share: Basic earnings per share are computed by dividing earnings available to common stockholders by the weighted average number of common shares outstanding during the period. Diluted earnings per share reflect per share amounts that would have resulted if dilutive potential common stock had been converted to common stock in gain periods. |
Cash Equivalents [Policy Text Block] | Statements of Cash Flows: For purposes of the consolidated statements of cash flows, the Company considers short-term, highly liquid investments with original maturities of less than ninety days to be cash equivalents. |
Concentration Risk, Credit Risk, Policy [Policy Text Block] | Concentration of Credit Risk: The Company maintains significant banking relationships with financial institutions in the State of Texas. The Company limits its risk by periodically evaluating the relative credit standing of these financial institutions. The Company’s oil and gas production purchasers consist primarily of independent marketers and major gas pipeline companies. |
Derivatives, Policy [Policy Text Block] | Hedging: The Company periodically enters into oil and gas financial instruments to manage its exposure to oil and gas price volatility. The oil and gas reference prices upon which the price hedging instruments are based reflect various market indices that have a high degree of historical correlation with actual prices received by the Company. The financial instruments are accounted for in accordance with applicable accounting standards for derivative instruments and hedging activities. Such standards require that applicable derivative instruments be measured at fair market value and recognized as assets or liabilities in the balance sheet. The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and the resulting designation is generally established at the inception of a derivative. For derivatives designated as cash flow hedges and meeting applicable effectiveness guidelines, changes in fair value, to the extent effective, are recognized in other comprehensive income until the hedged item is recognized in earnings. Hedge effectiveness is measured at least quarterly based on the relative changes in fair value between the derivative contract and the hedged item over time. Any change in fair value of a derivative resulting from ineffectiveness or an excluded component of the gain/loss is recognized immediately in the statements of income. |
New Accounting Pronouncements, Policy [Policy Text Block] | New accounting standards . In December 2023, the FASB issued Accounting Standards Update 2023-09, "Income Taxes (Topic 740): Improvements to Income Tax Disclosures," which is effective for fiscal years beginning after December 15, 2024 with early adoption permitted. The amendments in this Accounting Standards Update are focused on income tax disclosure requirements, primarily related to the income tax rate reconciliation and income taxes paid, with prospective application to a company's consolidated financial statements recommended. The Company is currently assessing the impacts of these new accounting standards on its disclosures. |
Note 3 - Additional Balance S_2
Note 3 - Additional Balance Sheet Information (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Notes Tables | |
Condensed Balance Sheet [Table Text Block] | December 31, (Thousands of dollars) 2023 2022 Joint interest billings $ 2,560 $ 1,806 Trade receivables 2,345 1,762 Oil and gas sales 14,457 8,894 Taxes 1,458 -- Other 155 21 20,975 12,483 Less: Allowance for credit losses (674 ) (336 ) Total $ 20,301 $ 12,147 December 31, (Thousands of dollars) 2024 2022 Trade $ 9,847 $ 5,142 Royalty and other owners 4,405 3,600 Partner advances 946 1,111 Other 226 1,598 Total $ 15,424 $ 11,451 December 31, (Thousands of dollars) 2023 2022 Compensation and related expenses $ 10,324 $ 9,743 Property costs 33,264 6,413 Taxes 929 9,352 Lease operating costs 3,898 1,695 Other 198 242 Total $ 48,613 $ 25,750 |
Note 5 - Other Long-Term Obli_2
Note 5 - Other Long-Term Obligations and Commitments (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Notes Tables | |
Lessee, Operating Lease, Liability, to be Paid, Maturity [Table Text Block] | (Thousands of dollars) Operating 2024 275 2025 45 Total undiscounted lease payments $ 320 Less: Amount associated with discounting (36 ) Total net operating lease liabilities $ 284 Less: Current portion included in Current portion of Asset Retirement and Other Long-Term Obligations 246 Non-current portion included in Other Long-Term Obligations $ 38 |
Schedule of Change in Asset Retirement Obligation [Table Text Block] | Years Ended (Thousands of dollars) 2023 2022 Asset retirement obligation at beginning of period $ 15,443 $ 14,295 Net wells placed on production 254 11 Liabilities settled (2,706 ) (1,407 ) Dispositions (1,161 ) (344 ) Accretion expense 684 667 Revisions in estimated liabilities 2,639 2,221 Asset retirement obligation at end of period $ 15,153 $ 15,443 Less: Current portion included in Current portion of asset retirement and other long-term obligations 446 1,918 Long-term Asset Retirement Obligations included in Asset Retirement Obligations $ 14,707 $ 13,525 |
Note 8 - Income Taxes (Tables)
Note 8 - Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Notes Tables | |
Schedule of Components of Income Tax Expense (Benefit) [Table Text Block] | Years Ended (Thousands of dollars) 2023 2022 Current: Federal $ (891 ) $ 8,330 State (258 ) 774 Total current (1,149 ) 9,104 Deferred: Federal 6,544 886 State 724 339 Total deferred 7,268 1,225 Total income tax provision $ 6,119 $ 10,329 |
Schedule of Deferred Tax Assets and Liabilities [Table Text Block] | At December 31, (Thousands of dollars) 2023 2022 Deferred Tax Assets: Accrued liabilities $ 349 $ 353 Allowance for doubtful accounts 154 77 Derivative Contracts - 223 Partnership basis difference 106 90 State Net operating loss carry-forwards 278 283 Total deferred tax assets 887 1,026 Deferred Tax Liabilities: Depletion and depreciation 48,123 40,994 Total deferred tax liabilities 48,123 40,994 Net deferred tax liabilities $ 47,236 $ 39,968 |
Schedule of Effective Income Tax Rate Reconciliation [Table Text Block] | Years Ended (Thousands of dollars) 2023 2022 Expected tax expense $ 7,187 $ 12,389 Permanent differences 221 870 State income tax, net of federal benefit 204 612 Provision to return adjustment (1,534 ) (3,540 ) Other, net 41 (2 ) Total income tax provision $ 6,119 $ 10,329 |
Note 9 - Segment Information _2
Note 9 - Segment Information and Major Customers (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Notes Tables | |
Schedule of Revenue by Major Customers by Reporting Segments [Table Text Block] | 2023 2022 Oil: APA Corporation 22 % 55 % Civitas Resources Inc. 20 % -- % Plains All American Inc. 19 % 16 % DE IV Operating, LLC. 14 % -- % Natural gas and liquids: APA Corporation 17 % 58 % Civitas Resources Inc. 10 % -- % Targa Pipeline Mid-Continent West Tex, LLC -- % 11 % |
Note 10 - Financial Instrumen_2
Note 10 - Financial Instruments (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Notes Tables | |
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block] | December 31, 2022 Quoted Prices in Significant Significant Balance at (Thousands of dollars) Assets Commodity derivative contracts $ — $ — $ 210 $ 210 Total assets $ — $ — $ 210 $ 210 Liabilities Commodity derivative contract $ — $ — $ (1,190 ) $ (1,190 ) Total liabilities $ — $ — $ (1,190 ) $ (1,190 ) |
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Table Text Block] | (Thousands of dollars) Net Liabilities – December 31, 2022 $ (980 ) Total realized and unrealized gains 980 Net Liabilities – December 31, 2023 $ — |
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Table Text Block] | Fair Value (Thousands of dollars) Balance Sheet Location December 31, December 31, Asset Derivatives: Derivatives not designated as cash-flow hedging instruments: Crude oil commodity contract Other current assets $ — $ 162 Natural gas commodity contract Other current assets — 48 Total $ — $ 210 Liability Derivatives: Derivatives not designated as cash-flow hedging instruments: Crude oil commodity contracts Derivative liability short-term $ — $ (931 ) Natural gas commodity contracts Derivative liability short-term — (259 ) Total $ — $ (1,190 ) Total derivative instruments $ — $ (980 ) |
Derivative Instruments, Gain (Loss) [Table Text Block] | Amount of gain/loss (Thousands of dollars) Location of gain/loss recognized in income 2023 2022 Derivatives not designated as cash-flow hedge instruments: Natural gas commodity contracts Unrealized gain on derivative instruments, net — 892 Crude oil commodity contracts Unrealized gain on derivative instruments, net — 3,713 Natural gas commodity contracts Realized gain (loss) on derivative instruments, net 235 (4,543 ) Crude oil commodity contracts Realized gain (loss) on derivative instruments, net 179 (12,101 ) $ 414 $ (12,039 ) |
Note 13 - Earnings Per Share (T
Note 13 - Earnings Per Share (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Notes Tables | |
Schedule of Earnings Per Share, Basic and Diluted [Table Text Block] | Years Ended December 31, 2023 2022 Net Income Weighted Per Share Net Income Weighted Per Share Basic $ 28,103 1,849,780 $ 15.19 $ 48,664 1,953,916 $ 24.91 Effect of dilutive securities: Options — 759,006 — 757,254 Diluted $ 28,103 2,608,786 $ 10.77 $ 48,664 2,711,170 $ 17.95 |
Supplementary Information (Tabl
Supplementary Information (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Notes Tables | |
Capitalized Costs Relating to Oil and Gas Producing Activities Disclosure [Table Text Block] | As of December 31, (Thousands of dollars) 2023 2022 Proved Developed oil and gas properties $ 659,792 $ 555,280 Proved Undeveloped oil and gas properties — — Total Capitalized Costs 659,792 555,280 Accumulated depreciation, depletion and valuation allowance (406,913 ) (385,811 ) Net Capitalized Costs $ 252,879 $ 169,469 |
Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure [Table Text Block] | Years Ended December 31, (Thousands of dollars) 2023 2022 Development Costs $ 110,700 $ 13,598 |
Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure [Table Text Block] | As of December 31, (Thousands of dollars) 2023 2022 Future cash inflows $ 1,219,605 $ 994,842 Future production costs (437,408 ) (378,160 ) Future development costs (213,823 ) (95,746 ) Future income tax expenses (119,359 ) (110,439 ) Future Net Cash Flows 449,015 410,497 10% annual discount for estimated timing of cash flows (170,967 ) (165,961 ) Standardized Measure of Discounted Future Net Cash Flows $ 278,048 $ 244,536 |
Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows [Table Text Block] | Years Ended (Thousands of dollars) 2023 2022 Sales of oil and gas produced, net of production costs $ (107,742 ) $ (86,302 ) Net changes in prices and production costs (98,132 ) 72,640 Extensions, discoveries and improved recovery 178,960 126,029 Revisions of previous quantity estimates (3,877 ) (10,902 ) Net change in development costs 66,552 (2,814 ) Reserves sold (398 ) (818 ) Reserves purchased — — Accretion of discount 24,454 13,581 Net change in income taxes 4,532 (8,435 ) Changes in production rates (timing) and other (30,836 ) 5,751 Net change 33,512 108,730 Standardized measure of discounted future net cash flow: Beginning of year 244,536 135,806 End of year $ 278,048 $ 244,536 |
Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities [Table Text Block] | As of December 31, 2023 2022 Oil NGL’s Gas Oil NGLs Gas Proved Developed Reserves: Beginning of year 4,143 2,497 22,277 5,386 2,882 23,902 Extensions, discoveries and improved recovery 843 467 2,391 99 74 464 Revisions of previous estimates (1,101 ) (515 ) (4,796 ) (375 ) (37 ) 1,309 Converted from undeveloped reserves 3,028 1,833 9,030 — — — Reserves sold (12 ) — (26 ) (28 ) (5 ) (73 ) Reserve purchased — — — — — — Production (1,144 ) (606 ) (4,127 ) (939 ) (417 ) (3,325 ) End of year 5,757 3,676 24,749 4,143 2,497 22,277 Proved Undeveloped Reserves: Beginning of year 3,028 1,833 9,030 — — — Extensions, discoveries and improved recovery 6,254 5,156 24,470 3,028 1,833 9,030 Revisions of previous estimates — — — — — — Converted to developed reserves (3,028 ) (1,833 ) (9,030 ) — — — Reserves Sold — — — — — — End of year 6,254 5,156 24,470 3,028 1,833 9,030 Total Proved Reserves at the End of the Year 12,011 8,832 49,219 7,171 4,330 31,307 |
Results of Operations for Oil and Gas Producing Activities Disclosure [Table Text Block] | Years Ended December 31, (Thousands of dollars) 2023 2022 Revenue: Oil and gas sales $ 107,742 $ 124,118 Costs and Expenses: Lease operating expenses 39,004 37,816 Depreciation, depletion and accretion 31,660 28,068 Income tax expense 5,797 10,329 Total Costs and Expenses 76,461 76,213 Results of Operations from Producing Activities (excluding corporate overhead and interest costs) $ 31,281 $ 47,905 |
Note 1 - Description of Opera_2
Note 1 - Description of Operations and Significant Accounting Policies (Details Textual) $ in Thousands | Dec. 31, 2023 | Dec. 31, 2022 USD ($) | Dec. 31, 2021 USD ($) |
Oil, Productive Well, Number of Wells, Net | 952 | ||
Deferred Tax Assets, Valuation Allowance | $ 0 | $ 0 | |
Minimum [Member] | |||
Oil, Productive Well, Number of Wells, Gross | 534 | ||
Property, Plant and Equipment, Useful Life | 5 years | ||
Maximum [Member] | |||
Property, Plant and Equipment, Useful Life | 10 years |
Note 2 - Acquisitions and Dis_2
Note 2 - Acquisitions and Dispositions (Details Textual) | 3 Months Ended | 6 Months Ended | |||||||
Jul. 01, 2023 USD ($) a | Nov. 14, 2022 USD ($) a | Dec. 31, 2023 USD ($) a | Sep. 30, 2023 USD ($) a | Jun. 30, 2023 USD ($) a | Mar. 31, 2023 USD ($) a | Sep. 30, 2022 USD ($) a | Mar. 31, 2022 USD ($) a | Jun. 30, 2022 USD ($) a | |
Number Of Acres Sold | 3 | ||||||||
Proceeds from Divestiture of Businesses | $ | $ 16,100,000 | $ 37,053 | |||||||
Area of Land | 203.23 | ||||||||
Percentage Of Ownership In Divestiture Of Businesses | 50% | ||||||||
Number Of Acres Exchanged | 725 | ||||||||
Number Of Contiguous Acres Block Created | 1,200 | ||||||||
Number Of Acre Created | 2,560 | ||||||||
TEXAS | |||||||||
Number Of Acres Sold | 9.35 | 38.25 | 320 | 7.8 | 1,809 | ||||
Proceeds from Divestiture of Businesses | $ | $ 280,423 | $ 899,000 | $ 60,000 | $ 436,050 | $ 14,000,000 | ||||
Gain (Loss) on Disposition of Business | $ | $ 47,000 | ||||||||
Area of Land | 114.52 | 55 | |||||||
Payment for Acquisition, Land, Held-for-Use | $ | $ 605,000 | ||||||||
Proceeds from Sale, Land, Held-for-Use | $ | $ 6,000,000 | ||||||||
Percentage Of Interest In Divestiture Of Businesses | 36.51% | ||||||||
Cash Acquired from Acquisition | $ | $ 1,700,853 | ||||||||
OKLAHOMA | |||||||||
Number Of Acres Sold | 136 | ||||||||
Proceeds from Divestiture of Businesses | $ | $ 306,000 | $ 423,700 | $ 845,000 | ||||||
Business Combination, Consideration Transferred, Liabilities Incurred | $ | $ 1,500,000 | ||||||||
CALIFORNIA | |||||||||
Number Of Acres Sold | 113 | 241 |
Note 3 - Additional Balance S_3
Note 3 - Additional Balance Sheet Information -Components of Balance Sheet Amounts (Details) - USD ($) | Dec. 31, 2023 | Dec. 31, 2022 |
Joint interest billings | $ 2,560,000 | $ 1,806,000 |
Trade | 9,847,000 | 5,142,000 |
Compensation and related expenses | 10,324,000 | 9,743,000 |
Trade receivables | 2,345,000 | 1,762,000 |
Royalty and other owners | 4,405,000 | 3,600,000 |
Property costs | 33,264,000 | 6,413,000 |
Oil and gas sales | 14,457,000 | 8,894,000 |
Partner advances | 946,000 | 1,111,000 |
Taxes | 929,000 | 9,352,000 |
Taxes | 1,458 | |
Other | 226,000 | 1,598,000 |
Lease operating costs | 3,898,000 | 1,695,000 |
Other | 155,000 | 21,000 |
Total | 15,424,000 | 11,451,000 |
Other | 198,000 | 242,000 |
Accounts Receivable, before Allowance for Credit Loss, Current | 20,975,000 | 12,483,000 |
Total | 48,613,000 | 25,750,000 |
Less: Allowance for credit losses | (674,000) | (336,000) |
Total | $ 20,301,000 | $ 12,147,000 |
Note 4 - Long-Term Debt (Detail
Note 4 - Long-Term Debt (Details Textual) - USD ($) $ in Millions | Jan. 20, 2023 | Mar. 31, 2024 | Feb. 09, 2024 | Dec. 31, 2023 | Jul. 24, 2023 | Jul. 05, 2022 |
Line of Credit Facility, Maximum Borrowing Capacity | $ 300 | |||||
Line of Credit Facility, Secured Borrowing Base | $ 75 | |||||
Maximum [Member] | ||||||
Line of Credit Facility, Increase (Decrease), Net | $ 75 | |||||
Minimum [Member] | ||||||
Line of Credit Facility, Increase (Decrease), Net | $ 60 | |||||
Revolving Credit Facility [Member] | ||||||
Line of Credit Facility, Maximum Borrowing Capacity | $ 65 | $ 65 | ||||
Long-Term Line of Credit | 11 | |||||
Line of Credit Facility, Remaining Borrowing Capacity | $ 64 | |||||
Revolving Credit Facility [Member] | Subsequent Event [Member] | ||||||
Line of Credit Facility, Maximum Borrowing Capacity | $ 85 | |||||
Long-Term Line of Credit | $ 4 | |||||
Line of Credit Facility, Remaining Borrowing Capacity | $ 81 |
Note 5 - Other Long-Term Obli_3
Note 5 - Other Long-Term Obligations and Commitments (Details Textual) - USD ($) | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Operating Lease, Cost | $ 700,000 | $ 628,000 |
Operating Lease, Payments | $ 739,000 | $ 673,000 |
Operating Lease, Weighted Average Remaining Lease Term | 11 months | 11 months |
Lessee, Operating Lease, Liability Extra Payment, Year Three | $ 275,000 | |
Lessee, Operating Lease, Additional Payments, Year Four | 45,000 | |
Rent Expenses | $ 767,000 | $ 755,000 |
Note 5 - Other Long-Term Obli_4
Note 5 - Other Long-Term Obligations and Commitments - Schedule of Operating Lease Obligations (Details) $ in Thousands | Dec. 31, 2023 USD ($) |
Lessee, Operating Lease, Liability, to be Paid, Year One | $ 275 |
Lessee, Operating Lease, Liability, to be Paid, Year Two | 45 |
Total undiscounted lease payments | 320 |
Less: Amount associated with discounting | (36) |
Other Liabilities [Member] | |
Total net operating lease liabilities | 284 |
Less: Current portion included in Other current liabilities | 246 |
Non-current portion included in Other liabilities | $ 38 |
Note 5 - Other Long-Term Obli_5
Note 5 - Other Long-Term Obligations and Commitments - Reconciliation of Liability of Plugging and Abandonment Costs (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Asset retirement obligation at beginning of period | $ 15,443 | $ 14,295 |
Net wells placed on production | 254 | 11 |
Liabilities settled | (2,706) | (1,407) |
Dispositions | (1,161) | (344) |
Accretion of discount on asset retirement obligations | 684 | 667 |
Revisions in estimated liabilities | 2,639 | 2,221 |
Asset retirement obligation at end of period | 15,153 | 15,443 |
Less: Current portion included in Current portion of asset retirement and other long-term obligations | 446 | 1,918 |
Asset Retirement Obligations | $ 14,707 | $ 13,525 |
Note 7 - Stock Options and Ot_2
Note 7 - Stock Options and Other Compensation (Details Textual) | May 31, 2089 | Dec. 31, 2023 $ / shares shares | Dec. 31, 2022 $ / shares shares |
Number Of Key Executive Officer To Whom Non Statutory Stock Option Granted | 4 | ||
Share-Based Compensation Arrangement by Share-Based Payment Award, Options, Outstanding, Number | shares | 767,500 | 767,500 | |
Minimum [Member] | |||
Share-Based Compensation Arrangement by Share-Based Payment Award, Options, Exercisable, Weighted Average Exercise Price | $ 1 | $ 1 | |
Maximum [Member] | |||
Share-Based Compensation Arrangement by Share-Based Payment Award, Options, Exercisable, Weighted Average Exercise Price | $ 1.25 | $ 1.25 |
Note 8 - Income Taxes (Details
Note 8 - Income Taxes (Details Textual) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2020 | |
IRA Excise Taxes Payable on Share Repurchases | $ 74 | |
Two Thousand Nineteen Through Two Thousand Twenty Six [Member] | Texas Franchise Tax [Member] | ||
Income Tax Examination, Liability (Refund) Adjustment from Settlement with Taxing Authority | $ 89 |
Note 8 - Income Taxes - Compone
Note 8 - Income Taxes - Components of Provision For Income Taxes (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Current: | ||
Federal | $ (891) | $ 8,330 |
Current State and Local Tax Expense (Benefit) | (258) | 774 |
Total current | (1,149) | 9,104 |
Deferred: | ||
Deferred Federal Income Tax Expense (Benefit) | 6,544 | 886 |
Deferred State and Local Income Tax Expense (Benefit) | 724 | 339 |
Total deferred | 7,268 | 1,225 |
Total income tax provision | $ 6,119 | $ 10,329 |
Note 8 - Income Taxes - Compo_2
Note 8 - Income Taxes - Components of Net Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Thousands | Dec. 31, 2023 | Dec. 31, 2022 |
Deferred Tax Assets: | ||
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals, Accrued Liabilities | $ 349 | $ 353 |
Allowance for doubtful accounts | 154 | 77 |
Derivative Contracts | 0 | 223 |
Partnership basis difference | 106 | 90 |
State Net operating loss carry-forwards | 278 | 283 |
Total deferred tax assets | 887 | 1,026 |
Deferred Tax Liabilities: | ||
Depletion and depreciation | 48,123 | 40,994 |
Total deferred tax liabilities | 48,123 | 40,994 |
Net deferred tax liabilities | $ 47,236 | $ 39,968 |
Note 8 - Income Taxes - Provisi
Note 8 - Income Taxes - Provision for Income Taxes Varies from Federal Statutory Tax Rate (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Expected tax expense | $ 7,187 | $ 12,389 |
Permanent differences | 221 | 870 |
State income tax, net of federal benefit | 204 | 612 |
Provision to return adjustment | (1,534) | (3,540) |
Other, net | 41 | (2) |
Total income tax provision | $ 6,119 | $ 10,329 |
Note 9 - Segment Information _3
Note 9 - Segment Information and Major Customers (Details Textual) | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Revenue Benchmark [Member] | Minimum [Member] | Customer Concentration Risk [Member] | ||
Concentration Risk, Percentage | 10% | 10% |
Note 9 - Segment Information _4
Note 9 - Segment Information and Major Customers - Segment Information by Major Customers (Details) - Customer Concentration Risk [Member] - Revenue Benchmark [Member] | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Oil Purchasers [Member] | Apa Corporation [Member] | ||
APA Corporation | 22% | 55% |
Oil Purchasers [Member] | Civita Resources Inc. [Member] | ||
APA Corporation | 20% | |
Oil Purchasers [Member] | Plains All American Inc [Member] | ||
APA Corporation | 19% | 16% |
Oil Purchasers [Member] | DE IV Operating LLC. [Member] | ||
APA Corporation | 14% | |
Natural Gas And Liquids [Member] | Apa Corporation [Member] | ||
APA Corporation | 17% | 58% |
Natural Gas And Liquids [Member] | Civita Resources Inc. [Member] | ||
APA Corporation | 10% | |
Natural Gas And Liquids [Member] | Targa Pipeline Mid Continent West Tex L L C [Member] | ||
APA Corporation | 11% |
Note 10 - Financial Instrumen_3
Note 10 - Financial Instruments - Schedule of Assets and Liabilities Measured at Fair Value on recurring Basis (Details) - USD ($) $ in Thousands | Dec. 31, 2023 | Dec. 31, 2022 |
Assets | ||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral | $ 0 | $ 210 |
Liabilities | ||
Derivative Liability, Fair Value, Amount Not Offset Against Collateral | $ 0 | 1,190 |
Fair Value, Recurring [Member] | Commodity Contract [Member] | ||
Assets | ||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral | 210 | |
Liabilities | ||
Derivative Liability, Fair Value, Amount Not Offset Against Collateral | 1,190 | |
Fair Value, Inputs, Level 3 [Member] | Fair Value, Recurring [Member] | Commodity Contract [Member] | ||
Assets | ||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral | 210 | |
Liabilities | ||
Derivative Liability, Fair Value, Amount Not Offset Against Collateral | $ 1,190 |
Note 10 - Financial Instrumen_4
Note 10 - Financial Instruments - Schedule of Changes In Fair Value of Financial Assets and Liabilities Classified as Level 3 (Details) $ in Thousands | 12 Months Ended | |
Dec. 31, 2023 USD ($) | ||
Total realized and unrealized gains | $ 980 | [1] |
Fair Value, Inputs, Level 3 [Member] | ||
Net Liabilities | (980) | |
Net Liabilities | $ 0 | |
[1]Derivative instruments are reported in revenues as realized gain/loss and on a separately reported line item captioned unrealized gain/loss on derivative instruments. |
Note 10 - Financial Instrumen_5
Note 10 - Financial Instruments - Effect of Derivative Instruments on Consolidated Balance Sheets (Details) - USD ($) $ in Thousands | Dec. 31, 2023 | Dec. 31, 2022 |
Derivative Asset, Fair Value, Amount Not Offset Against Collateral | $ 0 | $ 210 |
Derivative Liability, Fair Value, Amount Not Offset Against Collateral | 0 | 1,190 |
Total | 0 | (1,190) |
Total derivative instruments | 0 | (980) |
Not Designated as Hedging Instrument [Member] | Other Current Assets [Member] | Crude Oil Commodity Contracts [Member] | ||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral | 0 | 162 |
Not Designated as Hedging Instrument [Member] | Other Current Assets [Member] | Natural Gas Commodity Contracts [Member] | ||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral | 0 | 48 |
Not Designated as Hedging Instrument [Member] | Derivative Liability Short Term [Member] | Crude Oil Commodity Contracts [Member] | ||
Derivative Liability, Fair Value, Amount Not Offset Against Collateral | 0 | (931) |
Total | 0 | 931 |
Not Designated as Hedging Instrument [Member] | Derivative Liability Short Term [Member] | Natural Gas Commodity Contracts [Member] | ||
Derivative Liability, Fair Value, Amount Not Offset Against Collateral | 0 | (259) |
Total | $ 0 | $ 259 |
Note 10 - Financial Instrumen_6
Note 10 - Financial Instruments - Effect of Derivative Instruments on Consolidated Statements of Operations (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Commodity Contracts | $ 414 | $ (12,039) |
Unrealized Loss Gain On Derivative Instruments Net [Member] | Natural Gas Commodity Contracts [Member] | Not Designated as Hedging Instrument [Member] | ||
Commodity Contracts | 0 | 892 |
Unrealized Loss Gain On Derivative Instruments Net [Member] | Crude Oil Commodity Contracts [Member] | Not Designated as Hedging Instrument [Member] | ||
Commodity Contracts | 0 | 3,713 |
Realized Loss On Derivative Instruments Net [Member] | Natural Gas Commodity Contracts [Member] | Not Designated as Hedging Instrument [Member] | ||
Commodity Contracts | 235 | (4,543) |
Realized Loss Gain On Derivative Instruments Net [Member] | Crude Oil Commodity Contracts [Member] | Not Designated as Hedging Instrument [Member] | ||
Commodity Contracts | $ 179 | $ (12,101) |
Note 12 - Salary Deferral Plan
Note 12 - Salary Deferral Plan (Details Textual) - USD ($) | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Defined Contribution Plan, Employer Discretionary Contribution Amount | $ 362,756 | $ 301,837 |
Note 13 - Earnings Per Share -
Note 13 - Earnings Per Share - Computation of Basic and Diluted Earnings (Details) - USD ($) $ / shares in Units, $ in Thousands | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Basic | $ 28,103 | $ 48,664 |
Basic (in shares) | 1,849,780 | 1,953,916 |
Basic (in dollars per share) | $ 15.19 | $ 24.91 |
Options (in shares) | 759,006 | 757,254 |
Diluted | $ 28,103 | $ 48,664 |
Diluted (in shares) | 2,608,786 | 2,711,170 |
Diluted (in dollars per share) | $ 10.77 | $ 17.95 |
Supplementary Information - Cap
Supplementary Information - Capitalized Costs Relating to Oil and Gas Producing Activities (Details) - USD ($) $ in Thousands | Dec. 31, 2023 | Dec. 31, 2022 |
Proved Developed oil and gas properties | $ 659,792 | $ 555,280 |
Proved Undeveloped oil and gas properties | 0 | 0 |
Total Capitalized Costs | 659,792 | 555,280 |
Accumulated depreciation, depletion and valuation allowance | (406,913) | (385,811) |
Net Capitalized Costs | $ 252,879 | $ 169,469 |
Supplementary Information - Cos
Supplementary Information - Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Development Costs | $ 110,700 | $ 13,598 |
Supplementary Information - Sta
Supplementary Information - Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (Details) - USD ($) $ in Thousands | Dec. 31, 2023 | Dec. 31, 2022 |
Future cash inflows | $ 1,219,605 | $ 994,842 |
Future production costs | (437,408) | (378,160) |
Future development costs | (213,823) | (95,746) |
Future income tax expenses | 119,359 | 110,439 |
Future Net Cash Flows | 449,015 | 410,497 |
10% annual discount for estimated timing of cash flows | (170,967) | (165,961) |
Standardized Measure of Discounted Future Net Cash Flows | $ 278,048 | $ 244,536 |
Supplementary Information - S_2
Supplementary Information - Standardized Measure of Discounted Future Net Cash Flow and Changes therein Relating to Proved Oil and Gas Reserves (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Sales of oil and gas produced, net of production costs | $ (107,742) | $ (86,302) |
Net changes in prices and production costs | (98,132) | 72,640 |
Extensions, discoveries and improved recovery | 178,960 | 126,029 |
Revisions of previous quantity estimates | (3,877) | (10,902) |
Net change in development costs | 66,552 | (2,814) |
Reserves sold | (398) | (818) |
Reserves purchased | 0 | 0 |
Accretion of discount | 24,454 | 13,581 |
Net change in income taxes | 4,532 | (8,435) |
Changes in production rates (timing) and other | (30,836) | 5,751 |
Net change | 33,512 | 108,730 |
Standardized measure of discounted future net cash flow: | ||
Beginning of year | 244,536 | 135,806 |
End of year | $ 278,048 | $ 244,536 |
Supplementary Information - Res
Supplementary Information - Reserve Quantity Information (Details) - bbl | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Oil [Member] | ||
Beginning of year (Barrel of Oil) | 4,143 | 5,386 |
Proved Developed Reserves Extensions Discoveries And Additions (Barrel of Oil) | 843 | 99 |
Proved Developed Reserves Revisions Of Previous Estimates Increase Decrease (Barrel of Oil) | (1,101) | (375) |
Converted from undeveloped reserves (Barrel of Oil) | 3,028 | 0 |
Reserves sold (Barrel of Oil) | (12) | (28) |
Production (Barrel of Oil) | (1,144) | (939) |
End of year (Barrel of Oil) | 5,757 | 4,143 |
Beginning of year (Barrel of Oil) | 3,028 | 0 |
Proved Undeveloped Reserves Extensions Discoveries And Additions (Barrel of Oil) | 6,254 | 3,028 |
Proved Undeveloped Reserves Revisions Of Previous Estimates Increase Decrease (Barrel of Oil) | 0 | 0 |
Converted to developed reserves (Barrel of Oil) | (3,028) | 0 |
Reserves Sold (Barrel of Oil) | 0 | 0 |
End of year (Barrel of Oil) | 6,254 | 3,028 |
Total Proved Reserves at the End of the Year (Barrel of Oil) | 12,011 | 7,171 |
Natural Gas Liquids [Member] | ||
Beginning of year (Barrel of Oil) | 2,497 | 2,882 |
Proved Developed Reserves Extensions Discoveries And Additions (Barrel of Oil) | 467 | 74 |
Proved Developed Reserves Revisions Of Previous Estimates Increase Decrease (Barrel of Oil) | (515) | (37) |
Converted from undeveloped reserves (Barrel of Oil) | 1,833 | 0 |
Reserves sold (Barrel of Oil) | 0 | (5) |
Production (Barrel of Oil) | (606) | (417) |
End of year (Barrel of Oil) | 3,676 | 2,497 |
Beginning of year (Barrel of Oil) | 1,833 | 0 |
Proved Undeveloped Reserves Extensions Discoveries And Additions (Barrel of Oil) | 5,156 | 1,833 |
Proved Undeveloped Reserves Revisions Of Previous Estimates Increase Decrease (Barrel of Oil) | 0 | 0 |
Converted to developed reserves (Barrel of Oil) | (1,833) | 0 |
Reserves Sold (Barrel of Oil) | 0 | 0 |
End of year (Barrel of Oil) | 5,156 | 1,833 |
Total Proved Reserves at the End of the Year (Barrel of Oil) | 8,832 | 4,330 |
Natural Gas [Member] | ||
Beginning of year (Barrel of Oil) | 22,277 | 23,902 |
Proved Developed Reserves Extensions Discoveries And Additions (Barrel of Oil) | 2,391 | 464 |
Proved Developed Reserves Revisions Of Previous Estimates Increase Decrease (Barrel of Oil) | (4,796) | 1,309 |
Converted from undeveloped reserves (Barrel of Oil) | 9,030 | 0 |
Reserves sold (Barrel of Oil) | (26) | (73) |
Production (Barrel of Oil) | (4,127) | (3,325) |
End of year (Barrel of Oil) | 24,749 | 22,277 |
Beginning of year (Barrel of Oil) | 9,030 | 0 |
Proved Undeveloped Reserves Extensions Discoveries And Additions (Barrel of Oil) | 24,470 | 9,030 |
Proved Undeveloped Reserves Revisions Of Previous Estimates Increase Decrease (Barrel of Oil) | 0 | 0 |
Converted to developed reserves (Barrel of Oil) | (9,030) | 0 |
Reserves Sold (Barrel of Oil) | 0 | 0 |
End of year (Barrel of Oil) | 24,470 | 9,030 |
Total Proved Reserves at the End of the Year (Barrel of Oil) | 49,219 | 31,307 |
Supplementary Information - R_2
Supplementary Information - Results of Operations from Oil and Gas Producing Activities (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Revenue: | ||
Results of Operations, Revenue from Oil and Gas Producing Activities | $ 107,742 | $ 124,118 |
Costs and Expenses: | ||
Results of Operations, Production or Lifting Costs | 39,004 | 37,816 |
Results of Operations, Depreciation, Depletion and Amortization, and Valuation Provisions | 31,660 | 28,068 |
Results of Operations, Income Tax Expense | 5,797 | 10,329 |
Total Costs and Expenses | 76,461 | 76,213 |
Results of Operations from Producing Activities (excluding corporate overhead and interest costs) | $ 31,281 | $ 47,905 |