PRIMEENERGY RESOURCES CORP

None.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized, on the 15 th day of April, 2026.

Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below by the following persons on behalf of the Registrant and in the capacities indicated and on the 15 th day of April, 2026.

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

The Board of Directors and Stockholders

PrimeEnergy Resources Corporation and Subsidiaries

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheet of PrimeEnergy Resources Corporation and subsidiaries (the “Company”) as of December 31, 2025, and the related consolidated statements of income, equity and cash flows for the year ended December 31, 2025, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2025 and the results of its operations and its cash flows for the year ended December 31, 2025, in conformity with accounting principles generally accepted in the United States of America.

Basis of Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audit. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) ("PCAOB") and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audit, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audit included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audit also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audit provides a reasonable basis for our opinion.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of the critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

The Impact of Proved Oil and Natural Gas Reserves on Depletion, Depreciation, and Amortization (“DD&A”) and Impairment Calculation

At December 31, 2025, the carrying value of the Company’s oil and gas properties was $293.8 million, and depreciation, depletion and amortization (“DD&A”) expense was $75.7 million for the year then ended. As described in Note 1, under the successful efforts method of accounting, capitalized costs of proved properties are depleted using the units of production method based on total proved, and proved producing reserves, as estimated by independent petroleum engineers. The Company’s proved oil and natural gas properties are evaluated for impairment utilizing the Company’s proved oil and natural gas reserves in accordance with accounting principles generally accepted in the United States of America.

The Company engages an independent petroleum reservoir engineering firm and an independent petroleum engineer to serve as a management specialist and to assist with the estimation of proved oil and natural gas reserves. To estimate the volume of proved oil and natural gas reserves and associated future net cash flows, management and their specialists make significant estimates and assumptions including forecasting the production decline rate of producing properties and forecasting the timing and volume of production associated with the Company’s development plan for proved undeveloped properties (“PUDs”). Proved reserve estimates are impacted by various inputs, including historical production, oil and gas price assumptions, and future operating and capital cost assumptions, among other factors. Proved oil and natural gas reserves are impacted by management’s judgments and estimates regarding the financial performance of wells associated with proved reserves to determine if wells are expected, with reasonable certainty, to be economical under the appropriate pricing assumptions required. Changes in significant assumptions or engineering data could have a significant impact on the amount of DD&A and impairment recorded for the Company’s proved oil and natural gas properties. Because of the complexity involved in estimating oil and gas reserves, the Company utilized independent petroleum engineers for the year ended December 31, 2025.

We identified the impact of proved oil and natural gas reserves on DD&A and the impairment assessment as a critical audit matter due to use of significant judgment by management, including the use of independent petroleum engineers as specialists, when developing the estimates of proved oil and natural gas reserves. This in turn led to a high degree of auditor judgment, determination of the inputs described above used by the petroleum engineers in estimating proved oil and gas reserves, subjectivity, and effort in performing procedures and evaluating audit evidence related to the significant assumptions used in developing those estimates of proved oil and natural gas reserves.

Our audit procedures related to the evaluation of DD&A of oil and gas properties included the following, among others:

Other Matter

The consolidated financial statements of the Company, including the accompanying consolidated balance sheet, as of December 31, 2024, and the related consolidated statements of income, changes of equity, and cash flows for the year ended December 31, 2024 and the related notes were audited by Grassi & Co., CPAs, P.C., and rendered their opinion on such statements on April 15, 2025.

/s/WithumSmith+Brown, PC

Houston, Texas United States

April 15, 2026

PCAOB ID 100

We have served as the Company's auditor since 2025.

To The Board of Directors and Stockholders of

PrimeEnergy Resources Corporation and Subsidiaries

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheet of PrimeEnergy Resources Corporation and Subsidiaries (the “Company”) as of December 31, 2024, the related consolidated statements of income, equity and cash flows for the year then ended, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2024, and the results of its operations and its cash flows for the year then ended, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audit. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audit, we are required to obtain an understanding of internal control over financial reporting, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audit included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audit also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audit provides a reasonable basis for our opinion.

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

Depreciation, Depletion and Amortization of Oil and Gas Properties

At December 31, 2024, the carrying value of the Company’s oil and gas properties was $293.9 million, and depreciation, depletion and amortization (“DD&A”) expense was $76.5 million for the year then ended. As described in Note 1, under the successful efforts method of accounting, capitalized costs of proved properties are depleted using the units of production method based on proved reserves, as estimated by independent petroleum engineers. Proved reserve estimates are impacted by various inputs, including historical production, oil and gas price assumptions, and future operating and capital cost assumptions, among other factors. Because of the complexity involved in estimating oil and gas reserves, the Company utilized independent petroleum engineers for the year ended December 31, 2024.

Auditing the Company’s DD&A calculations is complex because of the use of independent petroleum engineers and the evaluation of management’s determination of the inputs described above used by the engineers in estimating oil and gas reserves.

Our audit procedures related to the evaluation of DD&A of oil and gas properties included the following, among others:

Accounting for Asset Retirement Obligations

At December 31, 2024, the asset retirement obligation (“ARO”) balance totaled $13.9 million. As further described in Note 1, the Company’s ARO 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’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. 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.

Auditing the Company’s ARO is complex and highly judgmental because of the significant estimation by management in determining the obligation. In particular, the estimate was sensitive to significant subjective assumptions such as retirement cost estimates and the estimated timing of settlements, which are both affected by expectations about future market and economic conditions.

Our audit procedures related to the evaluation of the accounting for the ARO included the following, among others:

/s/ GRASSI & CO., CPAs, P.C.

We have served as the Company's auditor from 1989 to 2025.

Jericho, New York

April 15, 2025

(Thousands of dollars, except share data)

(Thousands of dollars, except per share amounts)

CONSOLIDATED STATEMENTS OF EQUITY

(Thousands of dollars, except share amounts)

(Thousands of dollars)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 508 active wells and owns non-operating interests and royalties in approximately 1,128 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 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. All significant intercompany balances and transactions are eliminated in preparing the consolidated financial statements.

Segment Reporting:

The Company operates asone operating segment andone reportable segment which is engaged in the exploration, development, and production of oil, gas, and NGLs in Texas and Oklahoma, from which all of its revenues are derived and expenses incurred. All financial results are reviewed by the Chief Executive Officer (“CEO”), the Company’s Chief Operating Decision Maker (“CODM”), on a consolidated basis to evaluate performance of the Company. The single segment constitutes all the consolidated entity and the accompanying consolidated financial statements and the notes to the accompanying consolidated financial statements are representative of such amounts.

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 notes 4 and 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 credit losses 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 credit losses 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 credit losses 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.

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, 2025 and 2024, 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 net of any costs incurred by the operator or its purchasers in the related period of production. Revenues are also received net of production taxes which are recorded separately in other production and ad valorem taxes.

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. Revenues are recorded net to our interest and subject to royalties. Each unit of production typically represents a separate performance obligation; therefore, future volumes are wholly unsatisfied therefore the transaction price allocated to a remaining performance obligation is not required. The Company believes that the disaggregation of revenue into these three products as presented in the consolidated financial statements of income appropriately depicts how the nature, amount, timing and uncertainty of revenue and cashflows are affected by economic factors based on its geographic location.

Oil sales. The Company recognizes oil sales revenue when (i) control/custody transfers to the purchaser and (ii) the agreed-upon index price, net of any price differentials, is fixed and determinable. Any costs incurred prior to the transfer of control to the customer, such as gathering and transportation costs, are recognized as oil and gas production costs.

NGL and gas sales. Under the majority of the Company’s gas processing contracts, gas is delivered to a midstream processing entity and the Company recognizes revenue when the products are delivered to the midstream gathering or processing entity at a specified index price, net of downstream gathering and processing fees.

Field service income. The majority of the Company’s services are performed under Master Service Agreements. The Company recognizes revenue when the products and services are provided to the customer.

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 consolidated 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, 2025 and 2024, the Company hadno valuation allowance.

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 the weighted average number of common shares outstanding adjusted for the weighted average effect of dilutive common stock equivalents using the treasury share method.

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.

Recent Accounting Pronouncements:

In December 2023, the Financial Accounting Standards Board (FASB) issued ASU 2023-09 “Income Taxes (Topic 740): Improvements to Income Tax Disclosures” to expand the disclosure requirements for income taxes, specifically related to the rate reconciliation and income taxes paid. ASU 2023-09 is effective for annual periods beginning January 1, 2025, with early adoption permitted. The Company adopted ASU 2023-09 as of January 1, 2025, with retrospective application. The adoption did not have a material impact on the Company’s consolidated financial statements.

In November 2024, the Financial Accounting Standards Board (FASB) issued ASU 2024-03 “Income Statement—Reporting Comprehensive Income—Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses” requiring disclosure of specified information about certain costs and expenses. ASU 2024-03 is effective for annual periods beginning January 1, 2027, with early adoption permitted. The Company is currently evaluating the potential effect that the updated standard will have on its consolidated financial statement disclosures.

2. Acquisitions and Dispositions

2025 Transactions:* *

In the third quarter of 2025, the Company sold 76 net acres in Glasscock County, Texas, receiving gross proceeds of $950,000.

2024 Transactions:* *

In the first quarter of 2024, the Company sold 48 net acres in Lea County, New Mexico, along with minor working interest in 23 non-operated wells, receiving gross proceeds of $375,600, and in the second quarter of 2024, sold an additional 12 net acres in Lea County for proceeds of $150,600 and sold 2.29 surface acres in Odessa, Texas for $68,036. Also in the second quarter of 2024, we farmed out certain acreage in east Texas for $55,000.

In the third quarter of 2024, acreage transactions included the acquisition of 100.27 net acres in Reagan County, Texas for a purchase price of $1,109,785 and another purchase of 281 net acres in Reagan County for $2,774,025. Also in the second quarter of 2024, we sold 7.8 surface acres in Midland County, Texas for proceeds of $427,760 and sold 44.58 net acres of leasehold interest in Roger Mills County Oklahoma for proceeds of $89,159. In New Mexico, we sold our remaining working interests in seven properties in Lea and Eddy Counties for $220,000. Effective September 1, 2024, the Company sold its interest in Eastern Oil Well Service Company, a south Texas well-servicing business, for net proceeds of $2,800,000, recognizing a gain on sale of $1,921,000.

3. Additional Balance Sheet Information

Accounts receivable at December 31, 2025 and 2024 consisted of the following:

Accounts payable at December 31, 2025 and 2024 consisted of the following:

Accrued liabilities at December 31, 2025 and 2024 consisted of the following:

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 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.

In 2023 , in lieu of formal amendments, a series of letter agreements authorized by all lenders of the 2022 Credit Agreement and the Company resulted in changes to the amount of the Borrowing Base available throughout the year. The Borrowing Base availability at December 31, 2023 was $65 million .

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.

Effective July 29, 2024, the Company and its lenders entered into the Third Amendment to the 2022 Credit Agreement, increasing the Borrowing Base from $85 million to $115 million.

Effective December 20, 2024, the Company and its lenders entered into the Fourth Amendment to the 2022 Credit Agreement, reaffirming the credit agreement at $115 million. The Borrowing base remained in effect until the next Redetermination Date, June 2025, or the date the Borrowing Base is next adjusted in accordance with the Credit Agreement. As of December 31, 2024, the Company had $4 million in outstanding borrowings and $111 million in availability. Theprime rate in effect for December 2024, was 7.50%. The $4 million in outstanding borrowings was considered prime rate borrowings, and were subject to utilization percentage of 2.25%. The effective rate for this borrowing balance at December 31, 2024, was 9.75%.

Theprime rate in effect for December 2025, was 6.75%. Any borrowings the Company entered into would be subject to effective rates that are equal to the current prime rate plus a utilization percentage as required by the 2022 Credit Agreement. As of December 31, 2025, the Company hadno outstanding borrowings and $115 million in availability under the credit facility.

Effective February 24, 2026, the Company and its lenders entered into a Fifth Amendment to the 2022 Credit Agreement. All parties agreed to the reaffirmation of the Borrowing base of $115 million and the agreed amount will remain in effect until the next schedule redetermination or the date the Borrowing base is next adjusted in accordance with the credit agreement. The agreement also lowers the borrowing base utilization percentages and any term adjustment rates applied to SOFR or ABR loans as applicable.

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 9.50%. 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.

On February 10, 2026, the Company entered into a twelve-month lease extension agreement, effective March 1, 2026, with the landlord of the Company’s Houston office. Additional future payments due for this new lease for the years ending December 31, 2026 and 2027 will be $538 thousand and $107 thousand, respectively.

The payment schedule for the Company’s operating lease obligations as of December 31, 2025 is as follows:

Asset Retirement Obligation:

A reconciliation of the liability for plugging and abandonment costs for the years ended December 31, 2025 and 2024 is as follows:

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.

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.

7. Stock Options and Other Compensation

In May 1989, non-statutory stock options were granted by the Company tofour key executive officers for the purchase of shares of common stock. At December 31, 2025 and 2024, options on 767,500 shares were outstanding and exercisable at prices ranging from $1.00 to $1.25. According to their terms, the options have no expiration date.

8. Income Taxes

The components of the provision for income taxes for the years ended December 31, 2025 and 2024 are as follows:

The components of net deferred tax assets and liabilities are as follows:

The total provision for income taxes for the years ended December 31, 2025 and 2024 varies from the federal statutory tax rate as a result of the following:

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 2025 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 2022 through 2024 remain open for examination by the relevant taxing authorities.

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 purchasers 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 2025 and 2024.

Net income (loss) before income taxes is the measure reported to the chief operating decision maker (CODM) for purposes of making decisions about allocating resources and assessing performance. This measure allows our management to effectively evaluate our operating performance and compare the results between periods. The CODM is our Chief Executive Officer.

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.

10. 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. Amounts due to related party were $17 thousand and $34 thousand, at December 31, 2025 and 2024, respectively.

11. 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 $320,916 and $349,554 were made in 2025 and 2024, respectively.

12. 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:

UNAUDITED SUPPLEMENTARY INFORMATION

Net Proved Oil, NGL and Natural Gas Reserves

The reserves engineers for Prime Energy Resources for the years ended December 31, 2025 and 2024, was Ryder Scott Company.

In accordance with SEC regulations, the reserves as of December 31, 2025 and 2024 were estimated using benchmark prices, which reflect adjustments to the benchmark prices for quality, certain transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the delivery point. Prime Energy Resources reports reserves in three streams; crude oil, natural gas and NGLs.

The SEC has defined proved reserves as the estimated quantities of crude oil, natural gas, and NGLs that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. The process of estimating crude oil, natural gas and NGLs reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, material revisions to existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various properties increase the likelihood of significant changes in these estimates. If such changes are material, they could significantly affect future amortization of capitalized costs and result in impairment of assets that may be material.

The following tables provide an analysis of the changes in estimated proved reserve quantities of crude oil, natural gas and NGLs for the years ended December 31, 2025 and 2024, all of which are located within the United States (in thousands):

UNAUDITED SUPPLEMENTARY INFORMATION

For the year ended December 31, 2025, Prime Energy Resources had positive revisions of previous estimates of 1.9 million BOE, primarily attributable to the netted positive gas and NGL volumes that contributed 3.0 million BOE and $36 million of PV 10 value. This was offset by 1.1 million BOE of netted negative oil that removed $18 million of PV 10. Known positive and known negative amounts were not significant.

For the year ended December 31, 2025, extensions, discoveries and other additions resulted primarily from 37 new proved undeveloped locations adding 5.0 million BOE. The remaining volumes added from proved producing wells was 563,401 BOE. The 2025 and 2024 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.

Standardized measure of discounted future net cash flows relating to proved crude oil and natural gas reserves

The standardized measure of discounted future net cash flows does not purport to be, nor should it be interpreted to present, the fair value of the oil, NGL and natural gas reserves of the property. An estimate of fair value would take into account, among other things, the recovery of reserves not presently classified as proved, the value of proved properties and consideration of expected future economic and operating conditions.

The estimates of future cash flows and future production and development costs as of December 31, 2025 and 2024 are based on realized prices, which reflect adjustments to the benchmark prices for quality, certain transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the delivery point. All prices are held flat over the forecast period for all reserve categories in calculating the discounted future net cash flows. Any effect from the commodity hedges is excluded. In accordance with SEC regulations, the proved reserves were anticipated to be economically producible from the "as of date" forward based on existing economic conditions, including prices and costs at which economic producibility from a reservoir was determined. These costs, held flat over the forecast period, include development costs, operating costs, ad valorem and production taxes and abandonment costs after salvage. Future income tax expenses would have been computed using the appropriate year-end statutory tax rates applied to the future pretax net cash flows from proved oil, NGL and natural gas reserves, less the tax basis of the oil and natural gas properties of Prime Energy Resources. The estimated future net cash flows are then discounted at a rate of 10%.

NOTES TO SUPPLEMENTARY INFORMATION

(Unaudited)

The following table presents the standardized measure of discounted future net cash flows relating to proved oil, NGL and natural gas reserves for the periods presented (in thousands):

It is not intended that the FASB's standardized measure of discounted future net cash flows represent the fair market value of the proved reserves of Prime Energy Resources. Prime Energy Resources cautions that the disclosures shown are based on estimates of proved reserve quantities and future production schedules which are inherently imprecise and subject to revision, and the 10% discount rate is arbitrary. In addition, prices and costs as of the measurement date are used in the determinations, and no value may be assigned to probable or possible reserves.

The following table presents the changes in the standardized measure of discounted future net cash flows relating to proved oil, NGL and natural gas reserves for the periods presented (in thousands):

Estimates of economically recoverable oil, NGL and natural gas reserves and of future net cash flows are based upon a number of variable factors and assumptions, all of which are, to some degree, subjective and may vary considerably from actual results. Therefore, actual production, revenues, development and operating expenditures may not occur as estimated. The reserve data are estimates only, are subject to many uncertainties and are based on data gained from production histories and on assumptions as to geologic formations and other matters. Actual quantities of oil, NGL and natural gas may differ materially from the amounts estimated.