BARNWELL INDUSTRIES INC 10-K

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA Report of Independent Registered Public Accounting Firm To the Board of Stockholders and Board of Directors of Barnwell Industries, Inc. Opinion on the Consolidated Financial Statements We have audited the accompanying consolidated balance sheets of Barnwell Industries, Inc. and subsidiaries (the Company) as of September 30, 2024 and 2023, and the related consolidated statements of operations, comprehensive loss, equity, and cash flows for each of the two years in the period ended September 30, 2024, 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 September 30, 2024 and 2023, and the results of its operations and its cash flows for each of the two years in the period ended September 30, 2024, in conformity with accounting principles generally accepted in the United States of America. Basis for Opinion These financial statements are the responsibility of the entity’s management. Our responsibility is to express an opinion on these financial statements based on our audits. 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 audits 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 audits 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 audits 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 audits 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 audits provide 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 54 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. Estimation of proved reserves impacting the recognition and valuation of depletion expense and impairment of oil and gas properties Critical Accounting Matter Description As described in Note 1 to the financial statements, the Company accounts for its oil and gas properties using the full cost method of accounting which requires management to make estimates of proved reserve volumes and future revenues and expenses to calculate depletion expense and measure its oil and gas properties for potential impairment. To estimate the volume of proved reserves and future revenues, management makes 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. In addition, the estimation of proved reserves is also 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 in the estimation of depletion expense and potential impairment measurements. We identified the estimation of proved reserves of oil and gas properties, due to its impact on depletion expense and impairment evaluation, as a critical audit matter. The principal consideration for our determination that the estimation of proved reserves is a critical audit matter is that changes in certain inputs and assumptions, which require a high degree of subjectivity necessary to estimate the volume and future revenues of the Company’s proved reserves could have a significant impact on the measurement of depletion expense or the impairment assessment. In turn, auditing those inputs and assumptions required subjective and complex auditor judgement. How the Critical Audit Matter was Addressed in the Audit We obtained an understanding of the design and implementation of management’s controls and our audit procedures related to the estimation of proved reserves included the following, among others. • We evaluated the level of knowledge, skill, and ability of the Company’s reservoir engineering specialists and their relationship to the Company, made inquiries of those reservoir engineers regarding the process followed and judgments made to estimate the Company’s proved reserve volumes, and read the reserve report prepared by the Company’s specialists. • To the extent key, sensitive inputs and assumptions used to determine proved reserve volumes and other cash flow inputs and assumptions are derived from Company’s accounting records, such as commodity pricing, historical pricing differentials, operating costs, and working and net revenue interests, we tested management’s process for determining the assumptions, including examining the underlying support, on a sample basis. Specifically, our audit procedures involved testing management’s assumptions, to the extent key, as follows: ◦ Compared the estimated pricing differentials used in the reserve report to realized prices related to revenue transactions recorded in the current year and examined contractual support for the pricing differentials; ◦ Evaluated the forecasted operating costs at year-end compared to historical operating costs; ◦ Evaluated the working and net revenue interests used in the reserve report by inspecting a sample of ownership interests; ◦ Evaluated the Company’s evidence supporting the amount of proved undeveloped properties reflected in the reserve report by examining support for the Company’s or the operator’s ability and intent to develop the proved undeveloped properties; 55 ◦ Applied analytical procedures to the reserve report by comparing to historical actual results and to the prior year reserve report. Revenue recognition based on the percentage of completion method Critical Accounting Matter Description As described further in Note 1 to the financial statements, revenues derived from contract drilling contracts are recognized over time, as performance obligations are satisfied, due to the continuous transfer of control to the customer, using the percentage-of-completion method of accounting, based primarily on contract cost incurred to date compared to total estimated contract cost. Revenue recognition under this method is judgmental, particularly on lump-sum contracts, as it requires the Company to prepare estimates of total contract revenue and total contract costs, including costs to complete in-process contracts. Auditing the Company’s estimates or total contract revenue and costs used to recognize revenue on contract drilling contracts involved significant auditor judgment, as it required the evaluation of subjective factors such as assumptions related to project schedule and completion, forecasted labor, and material and subcontract costs. These assumptions involved significant management judgment, which affects the measurement of revenue recognized by the Company. How the Critical Audit Matter was Addressed in the Audit We obtained an understanding of the design and implementation of management’s controls and our audit procedures related to the estimation of proved reserves included the following, among others. • We obtained an understanding of the Company’s estimation process that affected revenue recognized on engineering and construction contracts. This included controls over management’s monitoring and review of project costs, including the Company’s procedures to validate the completeness and accuracy of data used to determine the estimates; • We selected a sample of projects and, among other procedures, obtained and inspected the contract agreements, amendments and change orders to test the existence of customer arrangements and understand the scope of pricing of the related contracts; • Evaluated the Company’s estimated revenue and costs to complete by obtaining and analyzing supporting documentation of management’s estimates of variable consideration and contract costs; • Compared contract profitability estimates in the current year to historical estimates and actual performance. /s/ WEAVER AND TIDWELL, L.L.P. We have served as the Company’s auditor since 2020. Little Falls, New Jersey December 16, 2024 56 BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS September 30, 2024 2023 ASSETS Current assets: Cash and cash equivalents $ 4,505,000 $ 2,830,000 Accounts and other receivables, net of allowance for credit losses of: $ 375,000 at September 30, 2024; $ 284,000 at September 30, 2023 2,770,000 3,246,000 Assets held for sale 69,000 — Other current assets 1,539,000 3,009,000 Total current assets 8,883,000 9,085,000 Asset for retirement benefits 4,899,000 4,471,000 Operating lease right-of-use assets 39,000 54,000 Property and equipment: Proved oil and natural gas properties, net (full cost method) 16,554,000 21,302,000 Drilling rigs and other property and equipment, net 294,000 509,000 Total property and equipment, net 16,848,000 21,811,000 Total assets $ 30,669,000 $ 35,421,000 LIABILITIES AND EQUITY Current liabilities: Accounts payable $ 1,822,000 $ 881,000 Accrued capital expenditures 2,407,000 1,099,000 Accrued compensation 650,000 726,000 Accrued operating and other expenses 1,834,000 1,747,000 Current portion of asset retirement obligation 798,000 1,536,000 Other current liabilities 301,000 609,000 Total current liabilities 7,812,000 6,598,000 Operating lease liabilities 7,000 47,000 Liability for retirement benefits 1,898,000 1,664,000 Asset retirement obligation 7,790,000 8,297,000 Deferred income tax liabilities 100,000 58,000 Total liabilities 17,607,000 16,664,000 Commitments and contingencies (Note 17) Equity: Common stock, par value $ 0.50 per share; authorized, 40,000,000 shares: 10,195,990 issued at September 30, 2024; 10,158,678 issued at September 30, 2023 5,098,000 5,079,000 Additional paid-in capital 7,690,000 7,687,000 Retained earnings 595,000 6,160,000 Accumulated other comprehensive income, net 1,943,000 2,104,000 Treasury stock, at cost: 167,900 shares at September 30, 2024 and 2023 ( 2,286,000 ) ( 2,286,000 ) Total stockholders’ equity 13,040,000 18,744,000 Non-controlling interests 22,000 13,000 Total equity 13,062,000 18,757,000 Total liabilities and equity $ 30,669,000 $ 35,421,000 See Notes to Consolidated Financial Statements 57 BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS Year ended September 30, 2024 2023 Revenues: Oil and natural gas $ 17,396,000 $ 19,376,000 Contract drilling 3,612,000 5,427,000 Sale of interest in leasehold land 500,000 265,000 Gas processing and other 216,000 201,000 21,724,000 25,269,000 Costs and expenses: Oil and natural gas operating 9,849,000 10,434,000 Contract drilling operating 4,483,000 5,669,000 General and administrative 5,598,000 6,956,000 Depletion, depreciation, and amortization 5,106,000 4,457,000 Impairment of assets 2,885,000 — Foreign currency gain ( 10,000 ) ( 76,000 ) Interest expense 2,000 2,000 Gain on sale of assets — ( 551,000 ) 27,913,000 26,891,000 Loss before equity in income of affiliates and income taxes ( 6,189,000 ) ( 1,622,000 ) Equity in income of affiliates 1,071,000 758,000 Loss before income taxes ( 5,118,000 ) ( 864,000 ) Income tax provision (benefit) 213,000 ( 53,000 ) Net loss ( 5,331,000 ) ( 811,000 ) Less: Net earnings attributable to non-controlling interests 234,000 150,000 Net loss attributable to Barnwell Industries, Inc. stockholders $ ( 5,565,000 ) $ ( 961,000 ) Basic net loss per common share attributable to Barnwell Industries, Inc. stockholders $ ( 0.56 ) $ ( 0.10 ) Diluted net loss per common share attributable to Barnwell Industries, Inc. stockholders $ ( 0.56 ) $ ( 0.10 ) Weighted-average number of common shares outstanding: Basic 10,017,997 9,969,856 Diluted 10,017,997 9,969,856 See Notes to Consolidated Financial Statements 58 BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS Year ended September 30, 2024 2023 Net loss $ ( 5,331,000 ) $ ( 811,000 ) Other comprehensive (loss) income: Foreign currency translation adjustments, net of taxes of $ 0 — ( 2,000 ) Retirement plans: Amortization of accumulated other comprehensive gain into net periodic benefit cost, net of taxes of $ 0 ( 85,000 ) ( 79,000 ) Net actuarial (loss) gain arising during the period, net of taxes of $ 0 ( 76,000 ) 891,000 Total other comprehensive (loss) income ( 161,000 ) 810,000 Total comprehensive loss ( 5,492,000 ) ( 1,000 ) Less: Comprehensive income attributable to non-controlling interests ( 234,000 ) ( 150,000 ) Comprehensive loss attributable to Barnwell Industries, Inc. $ ( 5,726,000 ) $ ( 151,000 ) See Notes to Consolidated Financial Statements 59 BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF EQUITY Years ended September 30, 2024 and 2023 Shares Outstanding Common Stock Additional Paid-In Capital Retained Earnings Accumulated Other Comprehensive Income Treasury Stock Non-controlling Interests Total Equity Balance at September 30, 2022 9,956,687 $ 5,062,000 $ 7,351,000 $ 7,720,000 $ 1,294,000 $ ( 2,286,000 ) $ 20,000 $ 19,161,000 Net (loss) earnings — — — ( 961,000 ) — — 150,000 ( 811,000 ) Foreign currency translation adjustments, net of taxes of $ 0 — — — — ( 2,000 ) — — ( 2,000 ) Distributions to non-controlling interests — — — — — — ( 157,000 ) ( 157,000 ) Share-based compensation — — 263,000 — — — — 263,000 Issuance of common stock for services 34,091 17,000 73,000 — — — — 90,000 Dividends declared, $ 0.060 per share — — — ( 599,000 ) — — — ( 599,000 ) Retirement plans: Amortization of accumulated other comprehensive gain into net periodic benefit cost, net of taxes of $ 0 — — — — ( 79,000 ) — — ( 79,000 ) Net actuarial gain arising during the period, net of taxes of $ 0 — — — — 891,000 — — 891,000 Balance at September 30, 2023 9,990,778 5,079,000 7,687,000 6,160,000 2,104,000 ( 2,286,000 ) 13,000 18,757,000 Net (loss) earnings — — — ( 5,565,000 ) — — 234,000 ( 5,331,000 ) Distributions to non-controlling interests — — — — — — ( 226,000 ) ( 226,000 ) Acquisition of non-controlling interest ( 186,000 ) 1,000 ( 185,000 ) Share-based compensation — — 208,000 — — — — 208,000 Issuance of common stock for restricted stock units vested 37,312 19,000 ( 19,000 ) — — — — — Retirement plans: Amortization of accumulated other comprehensive gain into net periodic benefit cost, net of taxes of $ 0 — — — — ( 85,000 ) — — ( 85,000 ) Net actuarial loss arising during the period, net of taxes of $ 0 — — — — ( 76,000 ) — — ( 76,000 ) Balance at September 30, 2024 10,028,090 $ 5,098,000 $ 7,690,000 $ 595,000 $ 1,943,000 $ ( 2,286,000 ) $ 22,000 $ 13,062,000 See Notes to Consolidated Financial Statements 60 BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS Year ended September 30, 2024 2023 Cash flows from operating activities: Net loss $ ( 5,331,000 ) $ ( 811,000 ) Adjustments to reconcile net loss to net cash provided by operating activities: Equity in income of affiliates ( 1,071,000 ) ( 758,000 ) Depletion, depreciation, and amortization 5,106,000 4,457,000 Impairment of assets 2,885,000 — Gain on sale of assets — ( 551,000 ) Sale of interest in leasehold land, net of fees paid ( 439,000 ) ( 233,000 ) Distributions of income from equity investees 1,071,000 539,000 Retirement benefits income ( 345,000 ) ( 252,000 ) Accretion of asset retirement obligation 900,000 808,000 Deferred income tax expense (benefit) 42,000 ( 130,000 ) Asset retirement obligation payments ( 1,139,000 ) ( 1,005,000 ) Share-based compensation expense 208,000 263,000 Common stock issued for services — 90,000 Non-cash rent income ( 28,000 ) ( 25,000 ) Retirement plan contributions and payments ( 4,000 ) ( 3,000 ) Credit loss expense 85,000 38,000 Foreign currency gain ( 10,000 ) ( 76,000 ) Gain on debt extinguishment — ( 15,000 ) Increase (decrease) from changes in current assets and liabilities 2,780,000 ( 393,000 ) Net cash provided by operating activities 4,710,000 1,943,000 Cash flows from investing activities: Acquisition of non-controlling interest ( 185,000 ) — Distributions from equity investees in excess of earnings — 219,000 Proceeds from sale of interest in leasehold land, net of fees paid 439,000 233,000 Proceeds from the sale of oil and natural gas assets 441,000 — Capital expenditures - oil and natural gas ( 3,514,000 ) ( 11,304,000 ) Capital expenditures - all other ( 13,000 ) ( 328,000 ) Net cash used in investing activities ( 2,832,000 ) ( 11,180,000 ) Cash flows from financing activities: Repayment of long-term debt — ( 30,000 ) Distributions to non-controlling interests ( 226,000 ) ( 157,000 ) Payment of dividends — ( 599,000 ) Net cash used in financing activities ( 226,000 ) ( 786,000 ) Effect of exchange rate changes on cash and cash equivalents 23,000 49,000 Net increase (decrease) in cash and cash equivalents 1,675,000 ( 9,974,000 ) Cash and cash equivalents at beginning of year 2,830,000 12,804,000 Cash and cash equivalents at end of year $ 4,505,000 $ 2,830,000 See Notes to Consolidated Financial Statements 61 BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS YEARS ENDED SEPTEMBER 30, 2024 AND 2023 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Description of Business Barnwell is engaged in the following lines of business: 1) acquiring, developing, producing and selling oil and natural gas in Canada and the U.S., 2) leasehold land interests in Hawaii, and 3) drilling wells and installing and repairing water pumping systems in Hawaii. Principles of Consolidation The consolidated financial statements include the accounts of Barnwell Industries, Inc. and all majority-owned subsidiaries (collectively referred to herein as “Barnwell,” “we,” “our,” “us,” or the “Company”), including a 77.6 %-owned land investment general partnership (Kaupulehu Developments) and a 75 %-owned land investment partnership (KD Kona). All significant intercompany accounts and transactions have been eliminated. Undivided interests in oil and natural gas exploration and production joint ventures are consolidated on a proportionate basis. Barnwell’s investments in both unconsolidated entities in which a significant, but less than controlling, interest is held and in VIEs in which the Company is not deemed to be the primary beneficiary are accounted for by the equity method. Use of Estimates in the Preparation of Consolidated Financial Statements The preparation of the consolidated financial statements in conformity with U.S. GAAP requires management of Barnwell to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Actual results could differ significantly from those estimates. Significant assumptions are required in the valuation of deferred tax assets, asset retirement obligations, contract drilling estimated costs to complete, and proved oil and natural gas reserves, and such assumptions may impact the amount at which such items are recorded. Revenue Recognition Barnwell operates in and derives revenue from the following three principal business segments: • Oil and Natural Gas Segment - Barnwell engages in oil and natural gas development, production, acquisitions and sales in Canada and the U.S. • Land Investment Segment - Barnwell owns land interests in Hawaii. • Contract Drilling Segment - Barnwell provides well drilling services and water pumping system installation and repairs in Hawaii. 62 Oil and Natural Gas - Barnwell’s investments in oil and natural gas properties are located in Alberta, Canada, Oklahoma, and Texas. These property interests are principally held under governmental leases or licenses. Barnwell sells the large majority of its oil, natural gas and natural gas liquids production under short-term contracts between itself and marketers based on prices indexed to market prices and recognizes revenue at a point in time when the oil, natural gas and natural gas liquids are delivered, as this is where Barnwell’s performance obligation is satisfied and title has passed to the customer. Land Investment - Barnwell is entitled to receive contingent residual payments from the entities that previously purchased Barnwell’s land investment interests under contracts entered into in prior years. The residual payments under those contracts become due when the entities sell lots and/or residential units in the areas that were previously sold under the aforementioned contracts or when a preferred payment threshold is achieved. The residual payments received by Barnwell are recognized as revenue when it is probable that a significant reversal in the amount of cumulative revenue recognized will not occur. Contract Drilling - Through contracts which are normally less than twelve months in duration, Barnwell drills water and water monitoring wells and installs and repairs water pumping systems in Hawaii. Barnwell recognizes revenue from well drilling or the installation of pumps over time based on total costs incurred on the projects relative to the total expected costs to satisfy the performance obligation as management believes this is an accurate representation of the percentage of completion as control is continuously transferred to the customer. Uninstalled materials, which typically consists of well casing or pumps, are excluded in the costs-to-costs calculation for the duration of the contract as including these costs would result in a distortion of progress towards satisfaction of the performance obligation due to the resulting cumulative catch-up in margin in a single period. An equal amount of cost and revenue is recorded when uninstalled materials are controlled by the customer, which is typically when Barnwell has the right to payment for the materials and when the materials are delivered to the customer’s site or location and such materials have been accepted by the customer. Uninstalled materials are held in inventory and included in “Other current assets” on the Company’s Consolidated Balance Sheets until control is transferred to the customer. When the estimate on a contract indicates a loss, Barnwell records the entire estimated loss in the period the loss becomes known. The contract price may include variable consideration, which includes such items as increases to the transaction price for unapproved change orders and claims for which price has not yet been agreed by the customer. The Company estimates variable consideration using either the most likely amount or expected value method, whichever is a more appropriate reflection of the amount to which it expects to be entitled based on the characteristics and circumstances of the contract. Variable consideration is included in the estimated transaction price to the extent it is probable that a significant reversal of cumulative recognized revenue will not occur. Contract price and cost estimates are reviewed periodically as work progresses and adjustments proportionate to the costs incurred to date to total estimated costs at completion are reflected in contract revenues in the reporting period when such estimates are revised. The nature of accounting for these contracts is such that refinements of the estimated costs to complete may occur and are characteristic of the estimation process due to changing conditions and new developments. Many factors and assumptions can and do change during a contract performance obligation period which can result in a change to contract profitability including unforeseen underground geological conditions (to the extent that contract remedies are unavailable), the availability and costs of skilled contract labor, the performance of major material suppliers, the performance of major subcontractors, unusual weather conditions and unexpected changes in material costs, changes in the scope and nature of the work to be performed, and unexpected construction execution errors, among others. These factors may result in revisions to costs and income and 63 are recognized in the period in which the revisions become known. Revenue and profit in future periods of contract performance are recognized using the adjusted estimate. Management evaluates the performance of contracts on an individual basis. In the ordinary course of business, but at least quarterly, we prepare updated estimates that may impact the cost and profit or loss for each contract based on actual results to date plus management's best estimate of costs to be incurred to complete each performance obligation. The cumulative effect of revisions in estimates of the total forecasted revenue and costs, including any unapproved change orders and claims, during the course of the contract is reflected in the accounting period in which the facts that caused the revision become known. Changes in the cost estimates can have a material impact on our consolidated financial statements and are reflected in the results of operations when they become known. Unexpected significant inefficiencies that were not considered a risk at the time of entering into the contract, such as design or construction execution errors that result in significant wasted resources, are excluded from the measure of progress toward completion and the costs are expensed as incurred. To the extent a contract is deemed to have multiple performance obligations, the Company allocates the transaction price of the contract to each performance obligation using its best estimate of the standalone selling price of each distinct good or service in the contract. When the Company receives consideration, or such consideration is unconditionally due, from a customer prior to transferring goods or services to the customer under the terms of a sales contract, the Company records deferred revenue, which represents a contract liability. Such deferred revenue typically results from billings in excess of costs and estimated earnings on uncompleted contracts. Contract liabilities are included in “Other current liabilities” on the Company’s Consolidated Balance Sheets. Costs and estimated earnings in excess of billings represent certain amounts under customer contracts that were earned and billable, but yet not invoiced, and are included in contract assets and reported in “Other current assets” on the Company’s Consolidated Balance Sheets. Cash and Cash Equivalents Cash and cash equivalents include cash on hand and short-term investments with original maturities of three months or less. Concentration of Credit Risk Financial instruments that potentially subject the Company to concentrations of credit risk consist primarily of cash and cash equivalents. We maintain bank account balances with high quality financial institutions which often exceed insured limits. We have not experienced any losses with these accounts and believe that we are not exposed to any significant credit risk on cash. Accounts and Other Receivables Accounts receivable are recorded at the invoiced amount and do not bear interest. The allowance for credit losses is Barnwell’s best estimate of the amount of current expected credit losses in Barnwell’s existing accounts receivable and is based on the aging of the receivable balances, analysis of historical credit loss rates, and current and future economic conditions affecting collectability. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote. Barnwell does not have any off-balance sheet credit exposure related to its customers. 64 Investments in Real Estate Barnwell accounts for sales of Increment I and Increment II leasehold land interests under the full accrual method. Gains from such sales were recognized when the buyer’s investments were adequate to demonstrate a commitment to pay for the property, risks and rewards of ownership transferred to the buyer, and Barnwell did not have a substantial continuing involvement with the property sold. With regard to payments Kaupulehu Developments is entitled to receive from KD I and KD II, the percentage of sales payments from KD I and KD II and percentage of distributions from KD II are contingent future profits which will be recognized when they are realized. All costs of the sales of Increment I and Increment II leasehold land interests were recognized at the time of sale and were not deferred to future periods when any contingent profits will be recognized. Variable Interest Entities The consolidation of VIEs is required when an enterprise has a controlling financial interest and is therefore the VIE’s primary beneficiary. A controlling financial interest will have both of the following characteristics: (a) the power to direct the activities of a VIE that most significantly impact the VIE’s economic performance and (b) the obligation to absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE. The determination of whether an entity is a VIE and, if so, whether the Company is the primary beneficiary, may require significant judgment. Barnwell analyzes its entities in which it has a variable interest to determine whether the entities are VIEs and, if so, whether the Company is the primary beneficiary. This analysis includes a qualitative review based on an evaluation of the design of the entity, its organizational structure, including decision making ability and financial agreements, as well as a quantitative review. Our unconsolidated affiliates that have been determined to be VIEs are accounted under the equity method because we do not have a controlling financial interest and are therefore not the VIE’s primary beneficiary (see Note 4). Equity Method Investments Affiliated companies, which are limited partnerships or similar entities, in which Barnwell holds more than a 3 % to 5 % ownership interest and does not control, are accounted for as equity method investments. Equity method investment adjustments include Barnwell’s proportionate share of investee income or loss, adjustments to recognize certain differences between Barnwell’s carrying value and Barnwell’s equity in net assets of the investee at the date of investment, impairments and other adjustments required by the equity method. Gains or losses are realized when such investments are sold. Barnwell classifies distributions received from equity method investments using the cumulative earnings approach in the Consolidated Statements of Cash Flows. Under the cumulative earnings approach, distributions received up to the amount of cumulative equity in earnings recognized are treated as returns on investment and are classified within operating cash flows and those in excess of that amount are treated as returns of investment and are classified within investing cash flows. Investments in equity method investees are evaluated for impairment as events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If the carrying amounts of the assets exceed their respective fair values, additional impairment tests are performed to measure the amounts of the impairment losses, if any. When an impairment test demonstrates that the fair value of an investment is less than its carrying value, management will determine whether the impairment 65 is either temporary or other-than-temporary. Examples of factors which may be indicative of an other-than-temporary impairment include (a) the length of time and extent to which fair value has been less than carrying value, (b) the financial condition and near-term prospects of the investee, and (c) the intent and ability to retain the investment in the investee for a period of time sufficient to allow for any anticipated recovery in fair value. If the decline in fair value is determined by management to be other-than-temporary, the carrying value of the investment is written down to its estimated fair value as of the balance sheet date of the reporting period in which the assessment is made. Oil and Natural Gas Properties Barnwell uses the full cost method of accounting under which all costs incurred in the acquisition, exploration and development of oil and natural gas reserves, including costs related to unsuccessful wells and estimated future site restoration and abandonment, are capitalized. We capitalize internal costs that can be directly identified with our acquisition, exploration and development activities and do not include any costs related to production, general corporate overhead or similar activities. The capitalized costs of oil and gas properties, excluding unevaluated and unproved properties, are amortized as depreciation, depletion and amortization expense using the units-of-production method based on estimated proved recoverable oil and gas reserves. Costs associated with unevaluated and unproved properties, initially excluded from the amortization base, relate to unproved leasehold acreage, wells and production facilities in progress and wells pending determination of the existence of proved reserves. Unproved leasehold costs are transferred to the amortization base with the costs of drilling the related well once a determination of the existence of proved reserves has been made or upon impairment of a lease. Costs associated with wells in progress and completed wells that have yet to be evaluated are transferred to the amortization base once a determination is made whether or not proved reserves can be assigned to the property. Costs of dry wells are transferred to the amortization base immediately upon determination that the well is unsuccessful. All items classified as unevaluated and unproved properties are assessed on a quarterly basis for possible impairment or reduction in value. Properties are assessed on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of various factors, including, but not limited to, the following: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; assignment of proved reserves; and economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and become subject to amortization. Under the full cost method of accounting, we review the carrying value of our oil and natural gas properties, on a country-by-country basis, each quarter in what is commonly referred to as the ceiling test. Under the ceiling test, capitalized costs, net of accumulated depletion and oil and natural gas related deferred income taxes, may not exceed an amount equal to the sum of 1) the discounted present value (at 10 %), using average first-day-of-the-month prices during the 12-month period ending as of the balance sheet date held constant over the life of the reserves (except where prices are defined by contractual arrangements), of Barnwell’s estimated future net cash flows from estimated production of proved oil and natural gas reserves as determined by independent petroleum reserve engineers, less estimated future expenditures to be incurred in developing and producing the proved reserves but excluding future cash outflows associated with settling asset retirement obligations with the exception of those associated with proved undeveloped reserves from wells that are to be drilled in the future; plus 2) the cost of major 66 development projects and unproven properties not subject to depletion, if any; plus 3) the lower of cost or estimated fair value of unproven properties included in costs subject to depletion; less 4) related income tax effects. If net capitalized costs exceed this limit, the excess is expensed. Depletion is computed using the units-of-production method whereby capitalized costs, net of estimated salvage values, plus estimated future costs to develop proved reserves and satisfy asset retirement obligations, are amortized over the total estimated proved reserves on a country-by-country basis. Investments in major development projects are not depleted until either proved reserves are associated with the projects or impairment has been determined. Proceeds from the disposition of oil and natural gas properties are credited to the full cost pool, with no gain or loss recognized, unless such a sale would significantly alter the relationship between capitalized costs and the proved reserves in a particular country. Given the volatility of oil and gas prices, it is reasonably possible that the estimate of discounted future net cash flows from proved oil and gas reserves could change in the near term. If oil and gas prices decline in the future, even if only for a short period of time, it is possible that impairments of oil and gas properties could occur. In addition, it is reasonably possible that impairments could occur if costs are incurred in excess of any increases in the present value of future net cash flows from proved oil and gas reserves, or if properties are sold for proceeds less than the discounted present value of the related proved oil and gas reserves. Barnwell’s sales reflect its working interest share after royalties. Barnwell’s production is generally delivered and sold at the plant gate. Barnwell does not have transportation volume commitments with pipelines and does not have natural gas imbalances related to natural gas balancing arrangements with its partners. Acquisitions In accordance with the guidance for business combinations, Barnwell determines whether an acquisition is a business combination, which requires that the assets acquired and liabilities assumed constitute a business. Each business combination is then accounted for by applying the acquisition method of accounting. If the assets acquired are not a business, the Company accounts for the transaction as an asset acquisition. Under both methods purchase prices are allocated to acquired assets and assumed liabilities based on their estimated fair value at the time of the acquisition. For transactions that are business combinations, the Company evaluates the existence of goodwill or a gain from a bargain purchase. The Company capitalizes acquisition-related costs and fees associated with asset acquisitions and immediately expenses acquisition-related costs and fees associated with business combinations. Long-lived Assets Long-lived assets to be held and used, other than oil and natural gas properties, are evaluated for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be fully recoverable. Recoverability is measured by comparing the carrying amount of the asset to the future net cash flows expected to result from use of the asset (undiscounted and without interest charges). If it is determined that the asset may not be recoverable, impairment loss is measured as the amount by which the carrying amount of the asset exceeds the fair value of the asset. Long-lived assets to be disposed of by sale are classified as held for sale and are reported at the lower of the asset carrying value or fair value, less cost to sell. Water well drilling rigs, office and other property and equipment are depreciated using the straight-line method based on estimated useful lives. 67 Share-based Compensation Share-based compensation cost for Barnwell’s equity-classified stock options, restricted stock units, and common stock issued for services is measured at fair value and is recognized as an expense over the requisite service period. For stock options, Barnwell utilizes a closed-form valuation model to determine the fair value of each option award. Expected volatilities are based on the historical volatility of Barnwell’s stock over a period consistent with that of the expected terms of the options. The expected terms of the options represent expectations of future employee exercise and are estimated based on factors such as vesting periods, contractual expiration dates, historical trends in Barnwell’s stock price, and historical exercise behavior. If the Company does not have sufficient historical data regarding employee exercise behavior, the “simplified method” as permitted by the SEC’s Staff Accounting Bulletin No. 110, Share-Based Payment is utilized to estimate the expected terms of the options. The risk-free rates for periods within the contractual life of the options are based on the yields of U.S. Treasury instruments with terms comparable to the estimated option terms. Expected dividends are based on historical dividend payments. For restricted stock units, Barnwell utilizes the closing market price of the Company’s common stock on the grant date reduced by the present value of the dividends expected to be paid on the underlying shares of common stock during the requisite service period (as these awards are not entitled to receive dividends until vested) to determine the fair value of each restricted stock unit award. For common stock issued for services, Barnwell utilizes the closing market price of the Company’s common stock on the grant date to determine the fair value of the common stock issued for services. The Company's policy is to recognize forfeitures as they occur. Retirement Plans Barnwell accounts for its defined benefit pension plan and Supplemental Executive Retirement Plan by recognizing the over-funded or under-funded status as an asset or liability in its Consolidated Balance Sheets and recognizes changes in that funded status in the year in which the changes occur through comprehensive income. See further discussion at Note 9. The estimation of Barnwell’s retirement plan obligations, costs and liabilities requires management to estimate the amount and timing of cash outflows for projected future payments and cash inflows for maturities and expected returns on plan assets. These assumptions may have an effect on the amount and timing of future contributions. At the end of each year, Barnwell determines the discount rate to be used to calculate the present value of plan liabilities and the net periodic benefit cost. The discount rate is an estimate of the current interest rate at which the retirement plan liabilities could be effectively settled at the end of the year. In estimating this rate, Barnwell performs a cash-flow matching discount rate analysis developed using high-quality corporate bonds yield. The discount rate used to value the future benefit obligation as of each year-end is the rate used to determine the periodic benefit cost in the following year. The expected long-term return on assets assumption for the pension plans represents the average rate of return to be earned on plan assets over the period the benefits included in the benefit obligation are to be paid. The actual fair value of plan assets and estimated rate of return is used to determine the expected investment return during the year. The estimated rate of return on plan assets is based on an estimate of future experience for plan asset returns, the mix of plan assets, current market conditions, and expectations for future market conditions. A decrease (increase) of 50 basis points in the expected return 68 on assets assumption would increase (decrease) pension expense by approximately $ 64,000 based on the assets of the plan at September 30, 2024. The effects of changing assumptions are included in unamortized net gains and losses, which directly affect accumulated other comprehensive income. These unamortized gains and losses in excess of certain thresholds are amortized and reclassified to (loss) income over the average remaining service life of active employees. Asset Retirement Obligation Barnwell accounts for asset retirement obligations by recognizing the fair value of a liability for an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made. Barnwell estimates the fair value of asset retirement obligations based on the projected discounted future cash outflows required to settle abandonment and restoration liabilities. Such an estimate requires assumptions and judgments regarding the existence of liabilities, the amount and timing of cash outflows required to settle the liability, what constitutes adequate restoration, inflation factors, credit adjusted discount rates, and consideration of changes in legal, regulatory, environmental and political environments. Abandonment and restoration cost estimates are determined in conjunction with Barnwell’s reserve engineers based on historical information regarding costs incurred to abandon and restore similar well sites, information regarding current market conditions and costs, and knowledge of subject well sites and properties. These assumptions represent Level 3 inputs. Barnwell’s estimated site restoration and abandonment costs of its oil and natural gas properties are capitalized as part of the carrying amount of oil and natural gas properties and depleted over the life of the related reserves. When the assumptions used to estimate a recorded asset retirement obligation change, a revision is recorded to both the asset retirement obligation and the capitalized cost of asset retirements. The liability is accreted at the end of each period through charges to oil and natural gas operating expense. Income Taxes Income taxes are determined using the asset and liability method. Deferred tax assets and liabilities are recognized for the estimated future tax impacts of differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the year in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. A valuation allowance is provided when it is more likely than not that some portion or all of the deferred tax asset will not be realized. Management evaluates its potential exposures from tax positions taken that have been or could be challenged by taxing authorities. These potential exposures result because taxing authorities may take positions that differ from those taken by management in the interpretation and application of statutes, regulations and rules. Management considers the possibility of alternative outcomes based upon past experience, previous actions by taxing authorities (e.g., actions taken in other jurisdictions) and advice from tax experts. Recognized tax positions are initially and subsequently measured as the largest amount of tax benefit that is more likely than not of being realized upon ultimate settlement with a taxing authority on a jurisdiction-by-jurisdiction basis. Liabilities for unrecognized tax benefits related to such tax positions are included in long-term liabilities unless the tax position is expected to be settled within the upcoming year, in which case the liabilities are included in current liabilities. Interest and penalties related to uncertain tax positions are included in income tax expense. 69 Our operations in Texas are subject to a franchise tax assessed by the state of Texas which is presented as income tax expense. Environmental Barnwell is subject to extensive environmental laws and regulations. These laws, which are constantly changing, regulate the discharge of materials into the environment and maintenance of surface conditions and may require Barnwell to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefit are expensed. Liabilities for expenditures of a noncapital nature are recorded when environmental assessment and/or remediation is probable, and the costs can be reasonably estimated. Barnwell recognizes an insurance receivable related to environmental expenditures when collection of the receivable is deemed probable. Any recognition of an insurance receivable is recorded by crediting and offsetting the original charge. Any differential arising between insurance recoveries and insurance receivables is expensed or capitalized, consistent with the original treatment. Derivative Instruments Barnwell may utilize physical forward commodity contracts to mitigate market price risk on its oil and natural gas output when deemed appropriate. Purchase and sale contracts with a fixed price determined at inception are recorded on the Consolidated Balance Sheets as derivative financial instruments if such contracts are readily convertible to cash - unless the contracts are eligible for and elected as the normal purchases and normal sales exception (“NPNS”); in which case, the contracts are recorded on an accrual basis and the Company recognizes the amounts relating to such transactions during the period when the commodities are physically delivered. The Company generally applies the NPNS exception to eligible oil and natural gas contracts to purchase or sell quantities it expects to use or sell in the normal course of business. The Company has not traded in any derivative contracts other than where the NPNS exception is applied, and it does not apply hedge accounting. Foreign Currency Translations and Transactions Assets and liabilities of foreign subsidiaries are translated at the year-end exchange rate. Operating results of foreign subsidiaries are translated at average exchange rates during the period. Translation adjustments have no effect on net income and are included in “Accumulated other comprehensive income, net” in the accompanying Consolidated Balance Sheets. Foreign currency gains or losses on intercompany loans and advances that are not considered long-term investments in nature because management intends to settle these intercompany balances in the future are included in our statements of operations. 70 Fair Value Measurements Fair value is defined as the amount that would be received from the sale of an asset or paid for the transfer of a liability in an orderly transaction between market participants at the measurement date. Fair value measurements are classified and disclosed in one of the following categories: • Level 1: Unadjusted quoted prices in active markets for identical assets and liabilities in active markets and have the highest priority. • Level 2: Inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. • Level 3: Unobservable inputs for the financial asset or liability and have the lowest priority. Recently Adopted Accounting Pronouncements In June 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2016-13, “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments,” which replaces the incurred loss model with an expected loss model referred to as the current expected credit loss (“CECL”) model. The CECL model is applicable to the measurement of credit losses on financial assets measured at amortized cost, including but not limited to trade receivables. The FASB has subsequently issued other related ASUs which amend ASU 2016-13 to provide clarification and additional guidance. The Company adopted the provisions of this ASU effective October 1, 2023. The adoption of this update did not have an impact on Barnwell’s consolidated financial statements. 2. LOSS PER COMMON SHARE Basic loss per share is computed using the weighted-average number of common shares outstanding for the period. Diluted loss per share is calculated using the treasury stock method to reflect the assumed issuance of common shares for all potentially dilutive securities, which consist of outstanding stock options and nonvested restricted stock units. Potentially dilutive shares are excluded from the computation of diluted loss per share if their effect is anti-dilutive. Options to purchase 465,000 shares of common stock and 98,795 restricted stock units were excluded from the computation of diluted shares for the year ended September 30, 2024, as their inclusion would have been anti-dilutive. Options to purchase 546,781 shares of common stock and 18,605 restricted stock units were excluded from the computation of diluted shares for the year ended September 30, 2023, as their inclusion would have been anti-dilutive. 71 Reconciliations between net loss attributable to Barnwell stockholders and common shares outstanding of the basic and diluted net loss per share computations are detailed in the following tables: Year ended September 30, 2024 Net Loss Shares Per-Share (Numerator) (Denominator) Amount Basic $ ( 5,565,000 ) 10,017,997 $ ( 0.56 ) Effect of dilutive securities - common stock options and restricted stock units — — Diluted $ ( 5,565,000 ) 10,017,997 $ ( 0.56 ) Year ended September 30, 2023 Net Loss Shares Per-Share (Numerator) (Denominator) Amount Basic $ ( 961,000 ) 9,969,856 $ ( 0.10 ) Effect of dilutive securities - common stock options and restricted stock units — — Diluted $ ( 961,000 ) 9,969,856 $ ( 0.10 ) 3. ALLOWANCE FOR CREDIT LOSSES The following table summarizes the activity in the balance of allowance for credit losses related to accounts and other receivables: Year ended September 30, 2024 2023 Allowance for credit losses as of beginning of year $ 284,000 $ 231,000 Provision for expected losses 85,000 38,000 Write-offs charged against the allowance ( 10,000 ) ( 20,000 ) Recoveries of amounts previously written off 16,000 34,000 Foreign currency translation adjustment — 1,000 Allowance for credit losses as of end of year $ 375,000 $ 284,000 4. INVESTMENTS Investment in Kukio Resort Land Development Partnerships On November 27, 2013, Barnwell, through a wholly-owned subsidiary, entered into two limited liability limited partnerships, KD Kona and KKM, and indirectly acquired a 19.6 % non-controlling ownership interest in each of KD Kukio Resorts, KD Maniniowali, and KDK for $ 5,140,000 . The Kukio Resort Land Development Partnerships own certain real estate and development rights interests in the Kukio, Maniniowali and Kaupulehu portions of Kukio Resort, a private residential community on the Kona coast of the island of Hawaii, as well as Kukio Resort’s real estate sales office operations. KDK holds interests in KD I and KD II. KD I is the developer of Increment I and KD II is the developer of Increment II. Barnwell's ownership interests in the Kukio Resort Land Development Partnerships is accounted for using the equity method of accounting. 72 In March 2019, KD II admitted a new development partner, Replay, a party unrelated to Barnwell, in an effort to move forward with development of the remainder of Increment II at Kaupulehu. KDK and Replay hold ownership interests of 55 % and 45 %, respectively, of KD II and Barnwell has a 10.8 % indirect non-controlling ownership interest in KD II through KDK, which is accounted for using the equity method of accounting. Barnwell continues to have an indirect 19.6 % non-controlling ownership interest in KD Kukio Resorts, KD Maniniowali, and KD I. The partnerships derive income from the sale of residential parcels in Increment I, which is now completely sold, as well as from commissions on real estate resales by the real estate sales office and revenues resulting from the sale of a few remaining private club memberships. In the quarter ended March 31, 2024, the last two remaining single-family lots of the 80 lots developed within Increment I were sold. Increment II is not yet under development, and there is no assurance that development of such acreage will in fact occur. No definitive development plans have been made by KD II, the developer of Increment II, as of the date of this report. Barnwell has the right to receive distributions from the Kukio Resort Land Development Partnerships via its non-controlling interests in KD Kona and KKM, based on its respective partnership sharing ratios of 75 % and 34.45 %, respectively. During the year ended September 30, 2024, Barnwell received cash distributions of $ 1,071,000 (resulting in a net amount of $ 953,000 , after distributing $ 118,000 to non-controlling interests) from the Kukio Resort Land Development Partnerships. During the year ended September 30, 2023, Barnwell received cash distributions of $ 758,000 from the Kukio Resort Land Development Partnerships resulting in a net amount of $ 674,000 , after distributing $ 84,000 to non-controlling interests. Equity in income of affiliates was $ 1,071,000 for the year ended September 30, 2024, as compared to equity in income of affiliates of $ 758,000 for the year ended September 30, 2023. Summarized financial information for the Kukio Resort Land Development Partnerships is as follows: Year ended September 30, 2024 2023 Revenue $ 13,555,000 $ 13,055,000 Gross profit $ 8,651,000 $ 7,733,000 Net earnings $ 6,437,000 $ 4,436,000 In the quarter ended June 30, 2021, the Company received cumulative distributions from the Kukio Resort Land Development Partnerships in excess of our investment balance and in accordance with applicable accounting guidance, the Company suspended its equity method earnings recognition and the Kukio Resort Land Development Partnerships’ investment balance was reduced to zero with the distributions received in excess of our investment balance recorded as equity in income of affiliates because the distributions are not refundable by agreement or by law and the Company is not liable for the obligations of or otherwise committed to provide financial support to the Kukio Resort Land Development Partnerships. The Company will record future equity method earnings only after our share of the Kukio Resort Land Development Partnerships’ cumulative earnings in excess of distributions during the suspended period exceeds our share of the Kukio Resort Land Development Partnerships’ income recognized for the excess distributions, and during this suspended period any distributions received will be recorded as equity in income of affiliates. Accordingly, the amount of equity in income of affiliates 73 recognized in the year ended September 30, 2024 was equivalent to the $ 1,071,000 of distributions received in that period. Cumulative distributions received from the Kukio Resort Land Development Partnerships in excess of our investment balance was $ 373,000 at September 30, 2024 and $ 708,000 at September 30, 2023. Sale of Interest in Leasehold Land Kaupulehu Developments holds rights to receive payments from KD I and KD II resulting from the sale of lots and/or residential units within Increment I, which is now fully sold, and within Increment II, which is not yet developed (see Note 19). With respect to Increment I, Kaupulehu Developments was entitled to receive payments from KD I based on 10 % of the gross receipts from KD I’s sales of single-family residential lots in Increment I. In the quarter ended March 31, 2024, the last two single-family lots of the 80 lots developed within Increment I were sold. Under the terms of the Increment II agreement with KD II, Kaupulehu Developments is entitled to 15 % of the distributions of KD II, the cost of which is to be solely borne by KDK out of its 55 % ownership interest in KD II, plus a priority payout of 10 % of KDK’s cumulative net profits derived from Increment II sales subsequent to Phase 2A, up to a maximum of $ 3,000,000 as to the priority payout. Such interests are limited to distributions or net profits interests and Barnwell does not have any partnership interests in KD II or KDK through its interest in Kaupulehu Developments. The arrangement also gives Barnwell rights to three single-family residential lots in Phase 2A of Increment II, and four single-family residential lots in phases subsequent to Phase 2A when such lots are developed by KD II, all at no cost to Barnwell. Barnwell is committed to commence construction of improvements within 90 days of the transfer of the four lots in the phases subsequent to Phase 2A as a condition of the transfer of such lots. Also, in addition to Barnwell’s existing obligations to pay professional fees to certain parties based on percentages of its gross receipts, Kaupulehu Developments is also obligated to pay an amount equal to 0.72 % and 0.20 % of the cumulative net profits of KD II to KD Development and a pool of various individuals, respectively, all of whom are partners of KKM and are unrelated to Barnwell, in compensation for the agreement of these parties to admit the new development partner for Increment II. Such compensation will be reflected as the obligation becomes probable and the amount of the obligation can be reasonably estimated. The following table summarizes the Increment I revenues from KD I and the amount of fees directly related to such revenues (see Note 17 “Commitments and Contingencies - Other Matters”): Year ended September 30, 2024 2023 Sale of interest in leasehold land: Revenues - sale of interest in leasehold land $ 500,000 $ 265,000 Fees - included in general and administrative expenses ( 61,000 ) ( 32,000 ) Sale of interest in leasehold land, net of fees paid $ 439,000 $ 233,000 74 There is no assurance with regards to the amounts of future payments from Increment II to be received or that the remaining acreage within Increment II will be developed. No definitive development plans have been made by KD II, the developer of Increment II, as of the date of this report. Investment in Leasehold Land Interest – Lot 4C Kaupulehu Developments holds an interest in an area of approximately 1,000 acres of vacant leasehold land zoned conservation located adjacent to Lot 4A, which currently has no development potential without both a development agreement with the lessor and zoning reclassification. The lease terminates in December 2025. 5. CONSOLIDATED VARIABLE INTEREST ENTITY In February 2021, Barnwell Industries, Inc. established a wholly-owned subsidiary named BOK Drilling, LLC (“BOK”) for the purpose of indirectly investing in oil and natural gas exploration and development in Oklahoma. BOK and Gros Ventre Partners, LLC (“Gros Ventre”) entered into the Limited Liability Agreement (the “Teton Operating Agreement”) of Teton Barnwell Fund I, LLC (“Teton Barnwell”), an entity formed for the purpose of directly entering into such oil and natural gas investments. Under the terms of the Teton Operating Agreement, the profits of Teton Barnwell were split between BOK and Gros Ventre at 98 % and 2 %, respectively, and as the manager of Teton Barnwell, Gros Ventre was paid an annual asset management fee equal to 1 % of the cumulative capital contributions made to Teton Barnwell as compensation for its management services. BOK was responsible for 100 % of the capital contributions made to Teton Barnwell. Teton Barnwell was a variable interest entity for which the Company was deemed the primary beneficiary and thus, was consolidated by the Company. In the quarter ended June 30, 2024, BOK acquired Gros Ventre’s 2 % non-controlling interest in Teton Barnwell for $ 185,000 and following the acquisition, BOK now owns 100 % interest in Teton Barnwell. As such, although Teton Barnwell is no longer a variable interest entity as of the acquisition date, it will continue to be consolidated by the Company. This transaction was accounted for as an equity transaction with no gain or loss recognized and the difference between the carrying amount of Gros Ventre’s non-controlling interest and the consideration given for the acquisition of the additional equity interest was recorded as a reduction in additional paid-in capital in the accompanying Consolidated Balance Sheets and Consolidated Statements of Equity. 6. ASSETS HELD FOR SALE Contract Drilling Segment Property and Equipment In the quarter ended March 31, 2024, the Company commenced the marketing of a portion of the contract drilling segment's property and equipment, the majority of which was already fully depreciated. There was no impairment related to the classification change from held and used to held for sale as the fair value, less estimated selling costs, of the disposal group exceeded its carrying value. The property and equipment deemed necessary to complete the contract drilling segment's contracts in backlog continue to be classified as held and used as of September 30, 2024. At September 30, 2024, a sale of the remainder of the contract drilling segment's property and equipment or the contract drilling segment as a whole was not estimated to be probable due to the lack of any definitive sale opportunities at that date. 75 7. OIL AND NATURAL GAS PROPERTIES Oil and Natural Gas Property Dispositions In the quarter ended June 30, 2024, Barnwell entered into and completed a purchase and sale agreement with an independent third party and sold its interests in certain oil and natural gas properties located in the Kaybob area of Alberta, Canada. The sales price per the agreement was adjusted for customary purchase price adjustments to $ 441,000 in order to, among other things, reflect an economic effective date of May 1, 2024. The final determination of the customary adjustments to the purchase price has not yet been made; however, it is not expected to result in a material adjustment. The proceeds were credited to the full cost pool, with no gain or loss recognized, as the sale did not result in a significant alteration of the relationship between capitalized costs and proved reserves. In July 2024, Barnwell entered into and completed an agreement with an independent third party to convey interests in certain oil and natural gas properties located in the Bonanza and Balsam areas of Alberta, Canada. In consideration for the sale of the working interests in these properties, Barnwell retained a 4 % overriding royalty on these properties and the buyer assumed the asset retirement obligations associated with these properties. There were no cash proceeds from the sale and no gain or loss was recognized on this conveyance as this did not result in a significant alteration of the relationship between capitalized costs and proved reserves. With the disposition of the working interest, Barnwell reduced the full cost pool and abandonment liabilities associated with the working interests conveyed by approximately $ 153,000 . In September 2024, Barnwell entered into and completed a purchase and sale agreement with an independent third party and sold its interests in certain oil and natural gas properties located in the Wood River area of Alberta, Canada. The sales price per the agreement was adjusted for customary purchase price adjustments to $ 292,000 in order to, among other things, reflect an economic effective closing date of September 30, 2024. The final determination of the customary adjustments to the purchase price has not yet been made, however, it is not expected to result in a material adjustment. From the sales proceeds, $ 38,000 was remitted directly to the Canada Revenue Agency by the buyers for potential amounts due for Barnwell’s Canadian income taxes related to the sale. The proceeds from the sale was credited to our cash in October 2024 and will be reflected in the Statement of Cash Flows for the first quarter of fiscal 2025 ending December 31, 2024. No gain or loss was recognized on this disposition as the sale proceeds were credited to the full cost pool and did not result in a significant alteration of the relationship between capitalized costs and proved reserves. Investments and Acquisitions In December 2022, Barnwell Texas, LLC (“Barnwell Texas”), a wholly-owned subsidiary of the Company, entered into a purchase and sale agreement with an independent third party whereby Barnwell Texas acquired a 22.3 % non-operated working interest in oil and natural gas leasehold acreage in the Permian Basin in Texas for cash consideration of $ 806,000 . Additionally, in connection with the purchase of such leasehold interests, Barnwell Texas acquired a 15.4 % non-operated working interest in two oil wells in the Wolfcamp Formation in Loving and Ward Counties, Texas and paid $ 4,293,000 for its share of the costs to drill, complete and equip the wells during the year ended September 30, 2023. 76 Impairment of Oil and Natural Gas Properties Under the full cost method of accounting, the Company performs quarterly oil and natural gas ceiling test calculations. Changes in the 12-month rolling average first-day-of-the-month prices for oil, natural gas and natural gas liquids prices (except where prices are defined by contractual arrangements), the value of reserve additions as compared to the amount of capital expenditures to obtain them, and changes in production rates and estimated levels of reserves, future development costs and the market value of unproved properties, impact the determination of the maximum carrying value of oil and natural gas properties. During the year ended September 30, 2024, the Company incurred a non-cash ceiling test impairment of $ 2,885,000 , which included impairments for our U.S. and Canadian oil and natural gas properties of $ 721,000 and $ 2,164,000 , respectively. The impairment to our U.S. and Canadian oil and natural gas properties were primarily due to a decline in the historical 12-month rolling average first-day-of-the-month prices. There was no ceiling test impairment during the year ended September 30, 2023. As discussed above, the ceiling test uses a 12-month historical rolling average first-day-of-the-month prices. As such, declines in the 12-month historical rolling average first-day-of-the-month prices used in our ceiling test calculation in future periods could result in impairment write-downs in future periods in the absence of any offsetting factors that are not currently known or projected. Based on the oil and gas prices for October 1, November 1 and December 1 of 2024, the oil prices and natural gas prices used in the 12-month historical rolling first-day-of-the-month average oil price for the ceiling test at December 31, 2024 will be lower than at September 30, 2024. Whereas we believe our Canadian full cost pool is sufficiently below the ceiling limit, our U.S. full cost pool had no ceiling excess at September 30, 2024, and thus a further impairment charge is more likely than not for our U.S full cost pool for the first quarter of fiscal 2025 ending December 31, 2024. The Company is currently unable to estimate a range of the amount of any potential future impairment write-downs as variables that impact the ceiling limitation are dependent upon actual results of activity through the end of December 2024. 77 8. PROPERTY AND EQUIPMENT AND ASSET RETIREMENT OBLIGATION Barnwell’s property and equipment is detailed as follows: Estimated Useful Lives Gross Property and Equipment Accumulated Depletion, Depreciation, Amortization, and Impairment Net Property and Equipment At September 30, 2024: Proved oil and natural gas properties (full cost method) $ 83,557,000 $ ( 67,003,000 ) $ 16,554,000 Drilling rigs and equipment 3 – 10 years 3,103,000 ( 2,823,000 ) 280,000 Other property and equipment 3 – 10 years 576,000 ( 562,000 ) 14,000 Total $ 87,236,000 $ ( 70,388,000 ) $ 16,848,000 Estimated Useful Lives Gross Property and Equipment Accumulated Depletion, Depreciation, Amortization, and Impairment Net Property and Equipment At September 30, 2023: Proved oil and natural gas properties (full cost method) $ 80,851,000 $ ( 59,549,000 ) $ 21,302,000 Drilling rigs and equipment 3 – 10 years 6,618,000 ( 6,127,000 ) 491,000 Other property and equipment 3 – 10 years 605,000 ( 587,000 ) 18,000 Total $ 88,074,000 $ ( 66,263,000 ) $ 21,811,000 See Note 7 for discussion of acquisitions and divestitures of oil and natural gas properties in fiscal 2024 and 2023. 78 Asset Retirement Obligation Barnwell recognizes the fair value of a liability for an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made. The following is a reconciliation of the asset retirement obligation: Year ended September 30, 2024 2023 Asset retirement obligation as of beginning of year $ 9,833,000 $ 8,456,000 Obligations incurred on new wells drilled or acquired 37,000 21,000 Liabilities associated with properties sold ( 442,000 ) — Revision of estimated obligation ( 614,000 ) 1,462,000 Accretion expense 900,000 808,000 Payments ( 1,139,000 ) ( 1,005,000 ) Foreign currency translation adjustment 13,000 91,000 Asset retirement obligation as of end of year 8,588,000 9,833,000 Less current portion ( 798,000 ) ( 1,536,000 ) Asset retirement obligation, long-term $ 7,790,000 $ 8,297,000 Asset retirement obligations were reduced by $ 442,000 and nil in fiscal 2024 and 2023, respectively, for those obligations that were assumed by purchasers of Barnwell's oil and natural gas properties (see Note 7 for additional details on dispositions). Asset retirement obligations were also reduced by $ 614,000 in fiscal 2024 as compared to an increase of $ 1,462,000 in fiscal 2023 primarily due to downward revisions related to deferrals in the estimated timing of future abandonments as a result of changes in the estimated economic lives of certain wells due to improved production performance of many wells in the Twining area as a result of focused attention and investment in optimization to improve well performance and reduce operating costs. Asset retirement obligations also increased by $ 37,000 and $ 21,000 in fiscal 2024 and 2023, respectively, due primarily to our wells drilled and acquisitions. The asset retirement obligation reflects the estimated present value of the amount of dismantlement, removal, site reclamation, and similar activities associated with Barnwell's oil and natural gas properties. Barnwell estimates the ultimate productive life of the properties, a credit-adjusted risk-free rate, and an inflation factor in order to determine the current present value of this obligation. The credit-adjusted risk-free rate for the entire asset retirement obligation is a blended rate which ranges from 6 % to 13.5 %. In September 2019, the AER issued an abandonment/closure order for all wells and facilities in the Manyberries area which had been largely operated by LGX, an operating company that went into receivership in 2016. The estimated asset retirement obligation for the Company's interest in the wells and facilities in the Manyberries area is included in “Asset retirement obligation” in the Consolidated Balance Sheets. After the abandonment/closure order was issued for Manyberries, the OWA created a WIP program for specific areas where there are a significant number of orphaned wells to abandon. The OWA has the ability and expertise to abandon wells using its internal resources and network of service providers resulting in efficiencies that companies such as Barnwell would not be able to obtain on its own. Under the WIP program, the Company would be required to provide payment for only Barnwell’s working interest share, however, all WIP’s would have to participate in the program for the OWA to begin its work. In March 2021, the Company was notified by the OWA that Barnwell’s Manyberries wells were confirmed to be in the WIP program. 79 Under the agreement with the OWA, the Company is required to pay the abandonment and reclamation costs in advance through a cash deposit. The total cash deposit amount was calculated to be approximately $ 1,525,000 and the Company paid $ 888,000 of the total deposit in July and August 2021 and may need to pay the remaining balance of $ 637,000 by August 2025. The Company revised its Manyberries ARO liability based on the OWA’s revised abandonment and reclamation estimates. Based on a review of the details of the cash deposit calculation provided by the OWA, which includes amounts added for possible contingencies, the Company believes the required cash deposit amount by the OWA is higher than the actual costs of the asset retirement obligation for the Manyberries wells and that any excess of the deposit over actual asset retirement costs for the first phase of the work would be credited toward the second phase of the work. A remaining excess deposit, if any, would ultimately be refunded to the Company upon completion of all of the work. As of September 30, 2024, the Company recognized a cumulative reduction in the deposit balance of $ 353,000 for work performed under this program. 9. RETIREMENT PLANS Barnwell sponsors a noncontributory defined benefit pension plan (“Pension Plan”) covering substantially all of its U.S. employees, with benefits based on years of service and the employee’s highest consecutive 5 years average earnings. Barnwell’s funding policy is intended to provide for both benefits attributed to service to date and for those expected to be earned in the future. In addition, Barnwell sponsors a Supplemental Executive Retirement Plan (“SERP”), a noncontributory supplemental retirement benefit plan which covers certain current and former employees of Barnwell for amounts exceeding the limits allowed under the Pension Plan. Effective December 31, 2019, the accrual of benefits for all participants in the Pension Plan and SERP was frozen and the plans were closed to new participants from that point forward. The following tables detail the changes in benefit obligations, fair values of plan assets and reconciliations of the funded status of the retirement plans: Pension Plan SERP September 30, 2024 2023 2024 2023 Change in Projected Benefit Obligation: Benefit obligation at beginning of year $ 7,511,000 $ 7,931,000 $ 1,734,000 $ 1,715,000 Interest cost 411,000 406,000 95,000 88,000 Actuarial loss (gain) 520,000 ( 394,000 ) 149,000 ( 66,000 ) Benefits paid ( 247,000 ) ( 432,000 ) ( 4,000 ) ( 3,000 ) Benefit obligation at end of year 8,195,000 7,511,000 1,974,000 1,734,000 Change in Plan Assets: Fair value of plan assets at beginning of year 11,982,000 11,316,000 — — Actual return on plan assets 1,359,000 1,098,000 — — Benefits paid ( 247,000 ) ( 432,000 ) — — Fair value of plan assets at end of year 13,094,000 11,982,000 — — Funded status $ 4,899,000 $ 4,471,000 $ ( 1,974,000 ) $ ( 1,734,000 ) 80 Pension Plan SERP September 30, 2024 2023 2024 2023 Amounts recognized in the Consolidated Balance Sheets: Noncurrent assets $ 4,899,000 $ 4,471,000 $ — $ — Current liabilities — — ( 76,000 ) ( 70,000 ) Noncurrent liabilities — — ( 1,898,000 ) ( 1,664,000 ) Net amount $ 4,899,000 $ 4,471,000 $ ( 1,974,000 ) $ ( 1,734,000 ) Amounts recognized in accumulated other comprehensive income before income taxes: Net actuarial gain $ ( 1,251,000 ) $ ( 1,178,000 ) $ ( 96,000 ) $ ( 330,000 ) Accumulated other comprehensive income $ ( 1,251,000 ) $ ( 1,178,000 ) $ ( 96,000 ) $ ( 330,000 ) The accumulated benefit obligation for the Pension Plan was $ 8,195,000 and $ 7,511,000 at September 30, 2024 and 2023, respectively. The accumulated benefit obligation for the SERP was $ 1,974,000 and $ 1,734,000 at September 30, 2024 and 2023, respectively. The accumulated benefit obligations are the same as the projected benefit obligations due to the Pension Plan and SERP being frozen as of December 31, 2019. Currently, no contributions are planned to be made to the Pension Plan during fiscal 2025. The SERP plan is unfunded and Barnwell funds benefits when payments are made. Expected payments under the SERP for fiscal 2025 are expected to be $ 76,000 . Fluctuations in actual market returns as well as changes in general interest rates will result in changes in the market value of plan assets and may result in increased or decreased retirement benefits costs and contributions in future periods. The Pension Plan actuarial losses in fiscal 2024 were primarily due to a decrease in the discount rate, partially offset by an actuarial gain resulting from actual investment returns that were greater than the assumed rate of return. The SERP actuarial losses in fiscal 2024 were primarily due to a decrease in the discount rate. The Pension Plan actuarial gains in fiscal 2023 were primarily due to an increase in the discount rate and actual investment returns that were greater than the assumed rate of return. The SERP actuarial gains in fiscal 2023 were primarily due to an increase in the discount rate. 81 The following table presents the weighted-average assumptions used to determine benefit obligations and net benefit (income) costs: Pension Plan SERP Year ended September 30, 2024 2023 2024 2023 Assumptions used to determine fiscal year-end benefit obligations: Discount rate 4.88 % 5.62 % 4.88 % 5.62 % Rate of compensation increase N/A N/A N/A N/A Assumptions used to determine net benefit costs (years ended): Discount rate 5.62 % 5.25 % 5.62 % 5.25 % Expected return on plan assets 6.50 % 6.00 % N/A N/A Rate of compensation increase N/A N/A N/A N/A We select a discount rate by reference to yields from the Willis Towers Watson RATE:Link 10-90 yield curve at our consolidated balance sheet date. The expected return on plan assets is based on an actuarial model which takes into consideration our investment mix and market conditions. The components of net periodic benefit (income) cost are as follows: Pension Plan SERP Year ended September 30, 2024 2023 2024 2023 Net periodic benefit (income) cost for the year: Interest cost $ 411,000 $ 406,000 $ 95,000 $ 88,000 Expected return on plan assets ( 766,000 ) ( 667,000 ) — — Amortization of net actuarial gain — — ( 85,000 ) ( 79,000 ) Net periodic benefit (income) cost $ ( 355,000 ) $ ( 261,000 ) $ 10,000 $ 9,000 The benefits expected to be paid under the retirement plans as of September 30, 2024 are as follows: Pension Plan SERP Expected Benefit Payments: Fiscal year ending September 30, 2025 $ 396,000 $ 76,000 Fiscal year ending September 30, 2026 $ 562,000 $ 152,000 Fiscal year ending September 30, 2027 $ 555,000 $ 150,000 Fiscal year ending September 30, 2028 $ 593,000 $ 155,000 Fiscal year ending September 30, 2029 $ 630,000 $ 160,000 Fiscal years ending September 30, 2030 through 2034 $ 3,075,000 $ 764,000 Plan Assets The trustees of the Pension Plan communicate periodically with the Pension Plan’s professional investment advisors to establish investment policies, direct investments and select investment options. The overall investment objective of the Pension Plan is to attain a diversified combination of investments that provides long-term growth in the assets of the plan to fund future benefit obligations while managing risk 82 in order to meet current benefit obligations. Generally, interest and dividends received provide cash flows to fund current benefit obligations. Longer-term obligations are generally estimated to be provided for by growth in equity securities. The Pension Plan’s investment policy permits investments in a diversified mix of U.S. and international equities, fixed income securities, other investments, and cash equivalents. The Pension Plan’s investments in fixed income securities include corporate bonds, U.S. treasury and government securities, preferred securities, and fixed income exchange-traded funds. The Pension Plan’s investments in equity securities primarily include domestic companies and is comprised of companies with market capitalization categorized as follows: 47 % micro-cap; 20 % small-cap; 15 % mid-cap; and 18 % large-cap. The Pension Plan’s other investment is a short-term note receivable from an unrelated private company. The Company’s year-end target allocation, by asset category, and the actual asset allocations were as follows: Target September 30, Asset Category Allocation 2024 2023 Cash and cash equivalents 0 % - 25 % 4 % 2 % Fixed income securities 15 % - 40 % 19 % 32 % Equity securities 45 % - 75 % 73 % 66 % Other investment 0 % - 10 % 4 % — % Actual investment allocations may vary from our target allocations from time to time due to prevailing market conditions. We periodically review our actual investment allocations and rebalance our investments to our target allocations as dictated by current and anticipated market conditions and required cash flows. We categorize plan assets into three levels based upon the assumptions used to price the assets. Level 1 provides the most reliable measure of fair value, whereas Level 3 requires significant management judgment in determining the fair value. Equity securities and exchange-traded funds are valued by obtaining quoted prices on recognized and highly liquid exchanges. Fixed income securities are valued based upon the closing price reported in the active market in which the security is traded. All of our plan assets, except for the note receivable from a private company, are categorized as Level 1 assets, and as such, the actual market value is used to determine the fair value of assets. The fair value of the note receivable from an unrelated private company is valued based upon the terms of the note receivable’s agreement and unobservable inputs such as management’s consideration of the counterparty’s credit risk and as such, is categorized as a Level 3 asset. 83 The following tables set forth by level, within the fair value hierarchy, pension plan assets at their fair value: Fair Value Measurements Using: September 30, 2024 Carrying Amount Quoted Prices in Active Markets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Financial Assets: Cash $ 531,000 $ 531,000 $ — $ — U.S. treasury and government securities 516,000 516,000 — — Fixed income exchange-traded funds 1,872,000 1,872,000 — — Preferred securities 88,000 88,000 — — Equities 9,516,000 9,516,000 — — Note receivable from an unrelated private company 571,000 — — 571,000 Total $ 13,094,000 $ 12,523,000 $ — $ 571,000 Fair Value Measurements Using: September 30, 2023 Carrying Amount Quoted Prices in Active Markets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Financial Assets: Cash $ 263,000 $ 263,000 $ — $ — U.S. treasury and government securities 709,000 709,000 — — Fixed income exchange-traded funds 3,102,000 3,102,000 — — Preferred securities 47,000 47,000 — — Equities 7,861,000 7,861,000 — — Total $ 11,982,000 $ 11,982,000 $ — $ — The following sets forth a summary of changes in the fair value of the pension plan Level 3 asset: Year ended September 30, 2024 2023 Balance at beginning of year $ — $ — Issuance of note receivable from an unrelated private company 571,000 — Balance at end of year $ 571,000 $ — 84 10. INCOME TAXES The components of loss before income taxes, after adjusting the loss for non-controlling interests, are as follows: Year ended September 30, 2024 2023 United States $ ( 2,820,000 ) $ ( 2,414,000 ) Canada ( 2,532,000 ) 1,400,000 $ ( 5,352,000 ) $ ( 1,014,000 ) The components of the income tax provision (benefit) related to the above losses are as follows: Year ended September 30, 2024 2023 Current provision: United States – State Before operating loss carryforwards $ 23,000 $ 47,000 Benefit of operating loss carryforwards — — After operating loss carryforwards 23,000 47,000 Canadian Before operating loss carryforwards 148,000 274,000 Benefit of operating loss carryforwards — ( 244,000 ) After operating loss carryforwards 148,000 30,000 Total current 171,000 77,000 Deferred provision (benefit): United States – State 42,000 ( 130,000 ) Total deferred 42,000 ( 130,000 ) $ 213,000 $ ( 53,000 ) Consolidated taxes do not bear a customary relationship to pretax results due primarily to the fact that the Company is taxed separately in Canada based on Canadian source operations and in the U.S. based on consolidated operations, and essentially all deferred tax assets, net of relevant offsetting deferred tax liabilities, are not estimated to have a future benefit as tax credits or deductions. The Company operates two subsidiaries in Canada, one of which is a U.S. corporation operating as a branch in Canada that is treated as a non-resident for Canadian tax purposes and thus has operating results that cannot be offset against or combined with the other Canadian subsidiary that files as a resident for Canadian tax purposes. Income from our non-controlling interest in the Kukio Resort Land Development Partnerships is treated as non-unitary for state of Hawaii unitary filing purposes, thus unitary Hawaii losses provide limited sheltering of such non-unitary income. Income from our investment in the Oklahoma oil venture is 100% allocable to Oklahoma. As such, Barnwell receives no benefit from consolidated or unitary losses and, therefore, is subject to Oklahoma state taxes. Consolidated taxes also include the impacts of favorable state jurisdiction provision to tax return true-ups. Our operations in Texas are subject to a franchise tax assessed by the state of Texas, however no significant amounts have been incurred to date. 85 A reconciliation between the reported income tax expense (benefit) and the amount computed by multiplying the loss attributable to Barnwell before income taxes by the U.S. federal tax rate of 21 % is as follows: Year ended September 30, 2024 2023 Tax benefit computed by applying statutory rate $ ( 1,124,000 ) $ ( 213,000 ) Increase in the valuation allowance 1,383,000 182,000 Additional effect of the foreign tax provision on the total tax provision ( 129,000 ) ( 4,000 ) U.S. state income tax provision (benefit), net of federal effect 70,000 ( 9,000 ) U.S. state provision to tax return adjustments ( 12,000 ) ( 106,000 ) Other 25,000 97,000 $ 213,000 $ ( 53,000 ) The change in the valuation allowance shown in the table above excludes the impact of changes in the valuation allowance of items that are incorporated within the respective reconciliation line items elsewhere in the table. 86 The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities are as follows: September 30, 2024 2023 Deferred income tax assets: Foreign tax credit carryover under U.S. tax law $ 916,000 $ 928,000 U.S. federal net operating loss carryover 10,382,000 9,406,000 U.S. state unitary net operating loss carryovers 1,334,000 1,177,000 Canadian net operating loss carryovers 1,331,000 1,025,000 Tax basis of investment in land in excess of book basis under U.S. tax law 11,000 25,000 Property and equipment accumulated book depreciation and depletion in excess of tax under U.S. tax law 548,000 275,000 Asset retirement obligation accrued for books but not for tax under U.S. tax law 907,000 1,084,000 Asset retirement obligation accrued for books but not for tax under Canadian tax law 2,141,000 2,461,000 Other liabilities accrued for books but not for tax under U.S. tax law 669,000 612,000 Foreign currency loss under U.S. tax law 68,000 68,000 Foreign currency loss under Canadian tax law 79,000 81,000 Other 168,000 116,000 Total gross deferred income tax assets 18,554,000 17,258,000 Less valuation allowance ( 13,896,000 ) ( 12,439,000 ) Net deferred income tax assets 4,658,000 4,819,000 Deferred income tax liabilities: Property and equipment accumulated tax depreciation and depletion in excess of book under Canadian tax law ( 117,000 ) ( 926,000 ) Book basis of investment in land development partnerships in excess of tax basis under U.S. tax law ( 282,000 ) ( 133,000 ) Book basis of investment in land development partnerships in excess of tax basis under U.S. state non-unitary tax law ( 86,000 ) ( 40,000 ) U.S. oil and gas property and equipment accumulated tax depreciation and depletion in excess of book under U.S. tax law ( 698,000 ) ( 906,000 ) U.S. oil and gas property and equipment accumulated tax depreciation and depletion in excess of book under U.S. state tax law ( 16,000 ) ( 19,000 ) U.S. tax law impact of foreign branch deferred tax asset under Canadian tax law ( 2,215,000 ) ( 1,655,000 ) Asset for retirement benefits ( 1,029,000 ) ( 939,000 ) Other ( 315,000 ) ( 259,000 ) Total deferred income tax liabilities ( 4,758,000 ) ( 4,877,000 ) Net deferred income tax liability $ ( 100,000 ) $ ( 58,000 ) Reported as: Deferred income tax assets $ — $ — Deferred income tax liabilities ( 100,000 ) ( 58,000 ) Net deferred income tax liability $ ( 100,000 ) $ ( 58,000 ) 87 The total valuation allowance increased $ 1,457,000 for the year ended September 30, 2024. The increase was due to current fiscal year operational activity that resulted in changes in deferred tax asset and liability balances, and there were no changes in judgment about the realizability of related deferred tax assets in future years. Of the total net increase in the valuation allowance for fiscal 2024, $ 1,392,000 was recognized as an income tax expense and $ 65,000 was charged to accumulated other comprehensive income. Net deferred tax assets at September 30, 2024 of $ 4,658,000 consists of the portion of deferred tax assets that are estimated to be partially realized through corresponding concurrent reversals of deferred tax liabilities related to the Kukio Resort Land Development Partnerships' excess of book income over taxable income, the book basis of property and equipment in excess of tax basis, foreign branch deferred taxes, asset for retirement benefits accrued for books but not for tax under U.S. tax law, and certain other minor deferred tax liabilities. At September 30, 2024, Barnwell had U.S. federal foreign tax credit carryovers, U.S. federal net operating loss carryovers, U.S. state net operating loss carryovers and Canadian net operating loss carryovers totaling $ 916,000 , $ 49,439,000 , $ 20,848,000 and $ 4,958,000 , respectively. The U.S. federal net operating loss carryovers generated through September 30, 2018 expire in fiscal years 2032-2038, the U.S. state unitary net operating loss carryovers generated through September 30, 2017 expire in fiscal years 2033-2037, the Canadian net operating loss carryovers expire in fiscal years 2039-2044, and the foreign tax credit carryover expires in fiscal year 2025. The U.S. federal net operating loss carryovers generated in fiscal years 2019-2024 and the U.S. state net operating loss carryovers generated in fiscal years 2018-2024 have no expiry, however utilization of the U.S. state and U.S. federal net operating loss carryovers generated in these and future years are limited to 80% of taxable income. FASB ASC Topic 740, Income Taxes, prescribes a threshold for recognizing the financial statement effects of a tax position when it is more likely than not, based on the technical merits, that the position will be sustained upon examination by a taxing authority. Barnwell files U.S. federal income tax returns, income tax returns in various U.S. states, and Canadian federal and provincial tax returns. A number of years may elapse before an uncertain tax position, for which we have unrecognized tax benefits, is audited and finally resolved. We believe that our unrecognized tax benefits are reflected on a more likely than not basis. We evaluate uncertain tax positions based on ongoing facts and circumstances. Any change in judgment related to the expected resolution of uncertain tax positions is recognized in earnings in the period in which such change occurs. Interest and penalties, if any, related to unrecognized tax benefits are recorded as a component of income tax expense. Settlement of any particular position could require the use of cash. Favorable or unfavorable resolution for an amount less than or greater than the amount estimated by Barnwell will result in a decrease or increase to income tax expense in the period of resolution. 88 There were no changes in unrecognized tax benefits during the years ended September 30, 2024 or 2023. Year ended September 30, 2024 2023 Balance at beginning of year $ 62,000 $ 62,000 Effect of tax positions taken in prior years — — Accrued interest related to tax positions taken — — Balance at end of year $ 62,000 $ 62,000 Uncertain tax positions at September 30, 2024 are related to the potential assessment of penalties and interest for the failure to file a certain foreign information form with each of our U.S. federal income tax returns for fiscal years 2019, 2020 and 2021. The Company filed amended U.S. federal income tax returns which included the missing form and statement of reasonable cause for these years in September and October 2023 and requested abatement of any potential penalties and interest which could subsequently be assessed. The Company is awaiting a response from the IRS and the probability of success of the abatement request remains uncertain. Included below is a summary of the tax years, by jurisdiction, that remain subject to examination by taxing authorities at September 30, 2024: Jurisdiction Fiscal Years Open U.S. federal 2019 – 2023 Various U.S. states 2021 – 2023 Canada federal 2017 – 2023 Various Canadian provinces 2017 – 2023 89 11. REVENUE FROM CONTRACTS WITH CUSTOMERS Disaggregation of Revenue The following tables provide information about disaggregated revenue by revenue streams, reportable segments, geographical region, and timing of revenue recognition for the years ended September 30, 2024 and 2023. Year ended September 30, 2024 Oil and natural gas Contract drilling Land investment Other Total Revenue streams: Oil $ 13,509,000 $ — $ — $ — $ 13,509,000 Natural gas 2,007,000 — — — 2,007,000 Natural gas liquids 1,880,000 — — — 1,880,000 Drilling and pump — 3,612,000 — — 3,612,000 Contingent residual payments — — 500,000 — 500,000 Other — — — 128,000 128,000 Total revenues before interest income $ 17,396,000 $ 3,612,000 $ 500,000 $ 128,000 $ 21,636,000 Geographical regions: United States $ 2,303,000 $ 3,612,000 $ 500,000 $ 37,000 $ 6,452,000 Canada 15,093,000 — — 91,000 15,184,000 Total revenues before interest income $ 17,396,000 $ 3,612,000 $ 500,000 $ 128,000 $ 21,636,000 Timing of revenue recognition: Goods transferred at a point in time $ 17,396,000 $ — $ 500,000 $ 128,000 $ 18,024,000 Services transferred over time — 3,612,000 — — 3,612,000 Total revenues before interest income $ 17,396,000 $ 3,612,000 $ 500,000 $ 128,000 $ 21,636,000 Year ended September 30, 2023 Oil and natural gas Contract drilling Land investment Other Total Revenue streams: Oil $ 14,259,000 $ — $ — $ — $ 14,259,000 Natural gas 3,441,000 — — — 3,441,000 Natural gas liquids 1,676,000 — — — 1,676,000 Drilling and pump — 5,427,000 — — 5,427,000 Contingent residual payments — — 265,000 — 265,000 Other — — — 114,000 114,000 Total revenues before interest income $ 19,376,000 $ 5,427,000 $ 265,000 $ 114,000 $ 25,182,000 Geographical regions: United States $ 2,746,000 $ 5,427,000 $ 265,000 $ 10,000 $ 8,448,000 Canada 16,630,000 — — 104,000 16,734,000 Total revenues before interest income $ 19,376,000 $ 5,427,000 $ 265,000 $ 114,000 $ 25,182,000 Timing of revenue recognition: Goods transferred at a point in time $ 19,376,000 $ — $ 265,000 $ 114,000 $ 19,755,000 Services transferred over time — 5,427,000 — — 5,427,000 Total revenues before interest income $ 19,376,000 $ 5,427,000 $ 265,000 $ 114,000 $ 25,182,000 90 Contract Balances The following table provides information about accounts receivables, contract assets and contract liabilities from contracts with customers: September 30, 2024 2023 2022 Accounts receivables from contracts with customers $ 2,031,000 $ 2,931,000 $ 4,038,000 Contract assets 267,000 958,000 580,000 Contract liabilities — 377,000 1,087,000 Accounts receivables from contracts with customers are included in “Accounts and other receivables, net of allowance for credit losses,” in the accompanying Consolidated Balance Sheets and contract assets, which includes costs and estimated earnings in excess of billings and retainage, are included in “Other current assets” in the accompanying Consolidated Balance Sheets. Contract liabilities, which includes billings in excess of costs and estimated earnings are included in “Other current liabilities” in the accompanying Consolidated Balance Sheets. Retainage, included in contract assets, represents amounts due from customers, but where payments are withheld contractually until certain construction milestones are met. Amounts retained typically range from 5 % to 10 % of the total invoice, up to contractually-specified maximums. The Company classifies as a current asset those retainages that are expected to be collected in the next twelve months. Contract assets represent the Company’s rights to consideration in exchange for services transferred to a customer that have not been billed as of the reporting date. The Company’s rights are generally unconditional at the time its performance obligations are satisfied. When the Company receives consideration, or such consideration is unconditionally due, from a customer prior to transferring goods or services to the customer under the terms of a sales contract, the Company records deferred revenue, which represents a contract liability. Such deferred revenue typically results from billings in excess of costs and estimated earnings on uncompleted contracts. As of September 30, 2024 and 2023, the Company had nil and $ 377,000 , respectively, included in “Other current liabilities” on the Consolidated Balance Sheets for those performance obligations expected to be completed in the next twelve months. During the years ended September 30, 2024 and 2023, the amount of revenue recognized that was previously included in contract liabilities as of the beginning of the respective period was $ 377,000 and $ 1,015,000 , respectively. Contracts are sometimes modified for a change in scope or other requirements. The Company considers contract modifications to exist when the modification either creates new or changes the existing enforceable rights and obligations. Most of the Company’s contract modifications are for goods and services that are not distinct from the existing performance obligations. The effect of a contract modification on the transaction price, and the measure of progress for the performance obligation to which it relates, is recognized as an adjustment to revenue (either as an increase or decrease) on a cumulative catchup basis. 91 Performance Obligations The Company’s remaining performance obligations for drilling and pump installation contracts (hereafter referred to as “backlog”) represent the unrecognized revenue value of the Company’s contract commitments. The Company’s backlog may vary significantly each reporting period based on the timing of major new contract commitments. In addition, our customers have the right, under some infrequent circumstances, to terminate contracts or defer the timing of the Company’s services and their payments to us. Nearly all of the Company's contract drilling segment contracts have original expected durations of one year or less. At September 30, 2024, the remaining performance obligation for contract drilling jobs with original expected durations greater than one year was not material. Contract Fulfillment Costs Preconstruction costs, which include costs such as set-up and mobilization, are capitalized and allocated across all performance obligations and deferred and amortized over the contract term on a progress towards completion basis. As of September 30, 2024 and 2023, the Company had $ 173,000 and $ 504,000 , respectively, in unamortized preconstruction costs related to contracts that were not completed. During the years ended September 30, 2024 and 2023, the amortization of preconstruction costs related to contracts was $ 306,000 and $ 326,000 , respectively. These amounts have been included in “Contract drilling operating” costs and expenses in the accompanying Consolidated Statements of Operations. Additionally, no impairment charges in connection with the Company’s preconstruction costs were recorded during the years ended September 30, 2024 and 2023. Uninstalled Materials Uninstalled materials, which typically consists of well casing or pumps, are excluded in the costs-to-costs calculation for the duration of the contract as including these costs would result in a distortion of progress towards satisfaction of the performance obligation due to the resulting cumulative catch-up in margin in a single period. An equal amount of cost and revenue is recorded when uninstalled materials are controlled by the customer, which is typically when Barnwell has the right to payment for the materials and when the materials are delivered to the customer’s site or location and such materials have been accepted by the customer. As of of September 30, 2024 and 2023, uninstalled materials was $ 65,000 and $ 348,000 , respectively. Uninstalled materials are held in inventory and included in “Other current assets” on the Company’s Consolidated Balance Sheets. 92 12. SEGMENT AND GEOGRAPHIC INFORMATION Barnwell operates the following segments: 1) acquiring, developing, producing and selling oil and natural gas in Canada and the U.S. (oil and natural gas); 2) leasehold land interests in Hawaii (land investment); and 3) drilling wells and installing and repairing water pumping systems in Hawaii (contract drilling). The following table presents certain financial information related to Barnwell’s reporting segments. All revenues reported are from external customers with no intersegment sales or transfers. Year ended September 30, 2024 2023 Revenues: Oil and natural gas $ 17,396,000 $ 19,376,000 Contract drilling 3,612,000 5,427,000 Land investment 500,000 265,000 Other 128,000 114,000 Total before interest income 21,636,000 25,182,000 Interest income 88,000 87,000 Total revenues $ 21,724,000 $ 25,269,000 Depletion, depreciation, and amortization: Oil and natural gas $ 4,947,000 $ 4,269,000 Contract drilling 156,000 186,000 Other 3,000 2,000 Total depletion, depreciation, and amortization $ 5,106,000 $ 4,457,000 Impairment: Oil and natural gas $ 2,885,000 $ — Total impairment $ 2,885,000 $ — Operating (loss) profit (before general and administrative expenses): Oil and natural gas $ ( 285,000 ) $ 4,673,000 Contract drilling ( 1,027,000 ) ( 428,000 ) Land investment 500,000 265,000 Other 125,000 112,000 Gain on sale of assets — 551,000 Total operating (loss) profit ( 687,000 ) 5,173,000 Equity in income of affiliates: Land investment 1,071,000 758,000 General and administrative expenses ( 5,598,000 ) ( 6,956,000 ) Foreign currency gain 10,000 76,000 Interest expense ( 2,000 ) ( 2,000 ) Interest income 88,000 87,000 Loss before income taxes $ ( 5,118,000 ) $ ( 864,000 ) 93 Capital Expenditures: Year ended September 30, 2024 2023 Oil and natural gas $ 4,228,000 $ 12,212,000 Contract drilling 12,000 314,000 Other 1,000 14,000 Total $ 4,241,000 $ 12,540,000 Oil and natural gas capital expenditures include acquisitions as well as changes to capitalized asset retirement obligations, including revisions of asset retirement obligations (see Note 8 for additional details). Assets By Segment: September 30, 2024 2023 Oil and natural gas: Canada $ 15,218,000 $ 18,855,000 United States 4,190,000 5,917,000 Contract drilling (1) 1,597,000 3,100,000 Other: Cash and cash equivalents 4,505,000 2,830,000 Asset for retirement benefits 4,899,000 4,471,000 Corporate and other 260,000 248,000 Total $ 30,669,000 $ 35,421,000 ______________ (1) L ocated in Hawaii. Long-Lived Assets By Geographic Area: September 30, 2024 2023 United States $ 9,214,000 $ 10,373,000 Canada 12,572,000 15,963,000 Total $ 21,786,000 $ 26,336,000 Revenue By Geographic Area: Year ended September 30, 2024 2023 United States $ 6,452,000 $ 8,448,000 Canada 15,184,000 16,734,000 Total (before interest income) $ 21,636,000 $ 25,182,000 94 13. ACCUMULATED OTHER COMPREHENSIVE INCOME Components of accumulated other comprehensive income, net of taxes, are as follows: Year ended September 30, 2024 2023 Foreign currency translation: Beginning accumulated foreign currency translation $ 220,000 $ 222,000 Change in cumulative translation adjustment before reclassifications — ( 2,000 ) Income taxes — — Net current period other comprehensive loss — ( 2,000 ) Ending accumulated foreign currency translation 220,000 220,000 Retirement plans: Beginning accumulated retirement plans benefit income 1,884,000 1,072,000 Amortization of net actuarial gain ( 85,000 ) ( 79,000 ) Net actuarial (loss) gain arising during the period ( 76,000 ) 891,000 Income taxes — — Net current period other comprehensive (loss) income ( 161,000 ) 812,000 Ending accumulated retirement plans benefit income 1,723,000 1,884,000 Accumulated other comprehensive income, net of taxes $ 1,943,000 $ 2,104,000 The amortization of net actuarial gain for the retirement plans are included in the computation of net periodic benefit (income) cost which is a component of “General and administrative” expenses on the accompanying Consolidated Statements of Operations (see Note 9 for additional details). 14. FAIR VALUE MEASUREMENTS Fair Value of Financial Instruments The carrying values of cash and cash equivalents, accounts and other receivables, accounts payable and accrued current liabilities approximate their fair values due to the short-term nature of the instruments. Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis The estimated fair values of oil and natural gas properties and the asset retirement obligation incurred in the drilling of oil and natural gas wells or assumed in the acquisitions of additional oil and natural gas working interests are based on an estimated discounted cash flow model and market assumptions. The assumptions used in the calculation of estimated discounted cash flows were primarily Level 3 assumptions; assumptions included future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development, operating and asset retirement costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates. See Note 7 for additional information regarding oil and natural gas property acquisitions. Barnwell estimates the fair value of asset retirement obligations based on the projected discounted future cash outflows required to settle abandonment and restoration liabilities. Such an estimate requires assumptions and judgments regarding the existence of liabilities, the amount and timing of cash outflows required to settle the liability, what constitutes adequate restoration, inflation factors, credit adjusted discount rates, and consideration of changes in legal, regulatory, environmental and political 95 environments. Abandonment and restoration cost estimates are determined in conjunction with Barnwell’s reserve engineers based on historical information regarding costs incurred to abandon and restore similar well sites, information regarding current market conditions and costs, and knowledge of subject well sites and properties. Asset retirement obligation fair value measurements in the current period were Level 3 fair value measurements. As further described in Note 8, the Company recognizes the fair value of a liability for an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made. Asset retirement obligations are not measured at fair value subsequent to initial recognition. 15. LEASES The Company’s right-of-use (“ROU”) assets and lease liabilities at September 30, 2024, primarily relate to non-cancelable operating leases for our Hawaii corporate and Canadian office spaces and our leasehold land interest for Lot 4C held by Kaupulehu Developments. Management determines if a contract is or contains a lease at inception of the contract or modification of the contract. A contract is or contains a lease if the contract conveys the right to control the use of the asset for a period in exchange for consideration. Operating lease ROU assets and liabilities are recognized based on the present value of future minimum lease payments over the expected lease term at commencement date. The Company’s leases do not provide a readily determinable implicit rate; therefore, management uses the Company’s incremental borrowing rate to discount lease payments based on information available at lease commencement. Our lease terms may include options to extend or terminate the lease when it is reasonably certain we will exercise that option. Lease expense for minimum lease payments is recognized on a straight-line basis over the expected lease terms. The Company has lease agreements with lease and non-lease components and the non-lease components are excluded in the calculation of the ROU asset and lease liability and expensed as incurred. None of the Company’s lease agreements contain material residual value guarantees or material restrictions or covenants. A ROU asset and corresponding lease liability is not recorded for leases with an initial term of 12 months or less (short-term leases) as the Company recognizes lease expense for these leases as incurred over the lease term. Leases recorded on the balance sheet consist of the following: September 30, 2024 2023 Assets: Operating lease right-of-use assets $ 39,000 $ 54,000 Total right-of-use assets $ 39,000 $ 54,000 Liabilities: Current portion of operating lease liabilities (1) $ 68,000 $ 71,000 Operating lease liabilities 7,000 47,000 Total lease liabilities $ 75,000 $ 118,000 ______________ (1) Amount included in “Other Current Liabilities” in the Consolidated Balance Sheets . 96 The components of lease expense are as follows: Year ended September 30, 2024 2023 Operating lease cost $ 87,000 $ 88,000 Short-term lease cost 358,000 347,000 Variable lease cost 142,000 136,000 Total lease cost $ 587,000 $ 571,000 Supplemental information related to leases is as follows: September 30, 2024 2023 Cash paid related to operating lease liabilities $ 114,000 $ 114,000 Operating leases: Weighted-average remaining lease term (in years) 0.9 1.7 Weighted-average discount rate 6.99 % 5.53 % The remaining lease payments for our operating leases as of September 30, 2024, are as follows: Fiscal year ending: 2025 $ 70,000 2026 7,000 2027 — 2028 — 2029 — Thereafter — Total lease payments 77,000 Less: amounts representing interest ( 2,000 ) Present value of lease liabilities $ 75,000 The lease payments for the Lot 4C leasehold land zoned conservation were subject to renegotiation as of January 1, 2006. Per the lease agreement, the lease payments will remain unchanged pending an appraisal, whereupon the lease rent could be adjusted to fair market value. Barnwell does not know the amount of the new lease payments which could be effective upon performance of the appraisal; they may remain unchanged or increase, and Barnwell currently expects the adjustment, if any, to not be material. The future lease payment disclosures above assume the minimum lease payments for leasehold land in effect at December 31, 2005 remain unchanged through December 2025, the end of the lease term. 16. STOCKHOLDERS' EQUITY Share-based Payment Arrangements 2018 Equity Incentive Plan The stockholder-approved 2018 Equity Incentive Plan is administered by the Compensation Committee of the Board of Directors and provides for the issuance of incentive stock options, nonstatutory stock options, stock options with stock appreciation rights, restricted stock, restricted stock units and performance units, qualified performance-based awards, and stock grants to employees, consultants and 97 non-employee members of the Board of Directors. 1,600,000 shares of Barnwell common stock have been reserved for issuance and as of September 30, 2024, a total of 925,188 share options remain available for grant. Barnwell currently has a policy of issuing new shares to satisfy share option exercises when the optionee requests shares. Stock Options In February 2021, the Board of Directors of the Company granted options to purchase 665,000 shares of common stock, 310,000 shares to independent directors and 355,000 shares to employees. 605,000 shares of the stock options granted have an exercise price equal to the closing market price of Barnwell’s stock on the date of grant of $ 3.33 , vest annually over three years , and expire in ten years from the date of grant. 60,000 shares of the stock options granted have an exercise price of $ 3.66 (110% of the closing market price on the date of grant for options granted to affiliates), vest annually over three years , and expire in five years from the date of grant. Of the 665,000 shares of common stock granted, 100,000 vested stock options expired and 100,000 shares were forfeited, both of which were as a result of director departures since the date of grant. The following assumptions were used in estimating the fair value for equity-classified stock options granted in the year ended September 30, 2021: > 10% Owner-Employee Others Number of shares 60,000 605,000 Expected volatility 127.4 % 105.8 % Expected dividends None None Expected term (in years) 3.5 6.0 Risk-free interest rate 0.19 % 0.82 % Expected forfeitures None None Fair value per share $ 2.51 $ 2.70 The application of alternative assumptions could produce significantly different estimates of the fair value of share-based compensation, and consequently, the related costs reported in the “General and administrative” expenses in the Consolidated Statements of Operations. 98 The following table summarizes Barnwell’s equity-classified stock options activity from October 1, 2023 through September 30, 2024: Options Shares Weighted- Average Exercise Price Weighted- Average Remaining Contractual Term Aggregate Intrinsic Value Outstanding at October 1, 2023 465,000 $ 3.37 Granted — — Exercised — — Expired/Forfeited — — Outstanding at September 30, 2024 465,000 $ 3.37 5.7 $ — Exercisable at September 30, 2024 465,000 $ 3.37 5.7 $ — Compensation cost for stock option awards is measured at the grant date based on the fair value of the award and is recognized as an expense over the requisite service period. During the years ended September 30, 2024 and 2023, the Company recognized share-based compensation expense related to stock options of $ 50,000 and $ 164,000 , respectively. There was no impact on income taxes for the years ended September 30, 2024 and 2023 due to a full valuation allowance on the related deferred tax asset. There is no remaining unrecognized compensation cost related to stock options as of September 30, 2024. Restricted Stock Units On November 2, 2023, the Board of Directors of the Company granted a total of 76,336 restricted stock units to the independent directors of the Board as partial payment of director fees for their service as members of the Board. The restricted stock units vest ratably over a three-year period, subject to the director’s continued service through the applicable vesting dates; provided that, any unvested restricted stock would vest upon a director’s death, disability, a change in control of the Company resulting in the director not continuing as a director or the director not being renominated for election even though he was willing to stand for re-election. On May 16, 2024, the Board of Directors of the Company granted 60,000 restricted stock units to the Company’s President and Chief Executive Officer. The restricted stock units vest ratably over a three-year period, subject to the employee’s continued service through the applicable vesting dates. 99 The following table summarizes Barnwell’s restricted stock units activity from October 1, 2023 through September 30, 2024: Restricted Stock Units Shares Weighted-Average Grant Date Fair Value Nonvested at October 1, 2023 — $ — Granted 136,336 2.62 Vested (1) ( 25,444 ) 2.62 Forfeited — — Nonvested at September 30, 2024 110,892 $ 2.63 ______________ (1) The underlying common stock for these vested restricted stock units were not yet issued as of September 30, 2024; in October 2024, the Company issued 25,444 shares of common stock for these vested restricted stock units. Compensation cost for restricted stock unit awards is measured at fair value and is recognized as an expense over the requisite service period. During the years ended September 30, 2024 and 2023, the Company recognized share-based compensation expense related to vested restricted stock units of $ 158,000 and $ 99,000 , respectively. There was no impact on income taxes for the years ended September 30, 2024 and 2023 due to a net operating loss and net operating loss carryforwards with a full valuation allowance in the relevant taxing jurisdiction. As of September 30, 2024, the total remaining unrecognized compensation cost related to nonvested restricted stock units was $ 200,000 , which is expected to be recognized over the weighted-average remaining requisite service period of 1.7 years. Common Stock Issued for Services In May 2023, the Company issued a total of 34,091 shares of Barnwell common stock to certain independent directors for their services on behalf of the Company and the Board of Directors pertaining to the negotiations of the Cooperation Agreement and the settlement of the potential proxy contest (see Note 19 for additional details). The total value of the shares issued was $ 90,000 which was valued using the closing price of Barnwell's common stock on May 11, 2023, the date of grant. There was no impact on income taxes for the year ended September 30, 2023 related to the common stock issued for services due to a net operating loss and net operating loss carryforwards with a full valuation allowance in the relevant taxing jurisdiction. Cash Dividends No dividends were declared or paid during the year ended September 30, 2024. The following table sets forth the cash dividends paid per share of common stock during the year ended September 30, 2023. Record Date Date of Payment Dividend Paid August 24, 2023 September 11, 2023 $ 0.015 May 25, 2023 June 12, 2023 $ 0.015 February 23, 2023 March 13, 2023 $ 0.015 December 27, 2022 January 11, 2023 $ 0.015 100 17. COMMITMENTS AND CONTINGENCIES Incentive compensation plan Barnwell established incentive compensation plans to compensate the four oil and natural gas segment Canadian executive officers. The value of the plans are directly related to our oil and natural gas segment's free cash flows from Canadian properties and the divestiture of Canadian oil and natural gas assets. As of September 30, 2024, Barnwell has accrued approximately $ 286,000 in bonus compensation under these plans and the amount is reported in “Accrued compensation” on the Consolidated Balance Sheet at September 30, 2024. Environmental Matters Because of the inherent uncertainties associated with environmental assessment and remediation activities, future expenses to remediate sites identified in the future, if any, could be incurred. Barnwell's management is not currently aware of any significant environmental contingent liabilities requiring disclosure or accrual. Legal and Regulatory Matters Barnwell is routinely involved in disputes with third parties that occasionally require litigation. In addition, Barnwell is required to maintain compliance with all current governmental controls and regulations in the ordinary course of business. Barnwell’s management is not aware of any claims or litigation involving Barnwell that are likely to have a material adverse effect on its results of operations, financial position or liquidity. In fiscal 2020, the Staff of the State of Hawaii’s Commission on Water Resource Management (“Commission”) circulated a draft of a proposed recommendation to the Commission under which the Company, the water utility, the water utility's independent hydrologist firm and the owner of the land on which two water wells were drilled would be assessed penalty fines because each of the wells were calculated to have been drilled beyond the depth permitted by the permit. The wells were drilled to a depth to penetrate certain layers of impermeable rock necessary to access the aquifer at the instructions and on the advice of the hydrologist hired by the owner of the well. Subsequently, the Staff of the Commission acknowledged that one well had not been drilled to a depth beyond its permitted depth and the fines on that well were eliminated. Additionally, the fines applicable to the depth of the second well were dropped in lieu of the parties entering into an agreement to perform a water quality study and repurpose a current well into a monitoring well. Accordingly, the Company recorded a liability of $ 300,000 to accrue for the costs to drill the monitoring well in the year ended September 30, 2020. During the year ended September 30, 2024, the liability was reduced to $ 200,000 due to a decrease in the estimated cost of the monitoring well due to reductions in the scope of work from what had been previously estimated. Other Matters During the year ended September 30, 2024, one of our water well drilling jobs encountered numerous unforeseen difficulties causing an increase in costs which led to the water well drilling contract becoming a loss job for which the Company had a $ 141,000 remaining loss accrual liability as of September 30, 2024. 101 Barnwell is obligated to pay Nearco Enterprises Ltd. 10.4 %, net of non-controlling interests' share, of Kaupulehu Developments’ gross receipts from real estate transactions. This fee represents compensation for promotion and marketing of Kaupulehu Developments’ property and were determined based on the estimated fair value of such services. These fees are included in general and administrative expenses. Barnwell is obligated to pay its external real estate legal counsel’s estate 1.2 %, net of non-controlling interests' share, of all Increment II payments received by Kaupulehu Developments for services provided by its external real estate legal counsel in the negotiation and closing of the Increment II transaction. These fees are included in general and administrative expenses. Kaupulehu Developments is also obligated to pay an amount equal to 0.72 % and 0.20 % of the cumulative net profits of KD II to KD Development and a pool of various individuals, respectively, all of whom are partners of KKM and are unrelated to Barnwell, in compensation for the agreement of these parties to admit the new development partner for Increment II. Such compensation will be reflected as the obligation becomes probable and the amount of the obligation can be reasonably estimated. 18. INFORMATION RELATING TO THE CONSOLIDATED STATEMENTS OF CASH FLOWS The following table details the effect of changes in current assets and liabilities on the Consolidated Statements of Cash Flows, and presents supplemental cash flow information: Year ended September 30, 2024 2023 Increase (decrease) from changes in: Receivables $ 650,000 $ 1,103,000 Income tax receivable ( 3,000 ) ( 16,000 ) Other current assets 1,475,000 ( 51,000 ) Accounts payable 928,000 ( 595,000 ) Accrued compensation ( 79,000 ) ( 278,000 ) Other current liabilities ( 191,000 ) ( 556,000 ) Increase (decrease) from changes in current assets and liabilities $ 2,780,000 $ ( 393,000 ) Supplemental disclosure of cash flow information: Cash paid during the year for: Income taxes paid $ 71,000 $ 100,000 Capital expenditure accruals related to oil and natural gas acquisition and development increased $ 1,291,000 during the year ended September 30, 2024 and decreased $ 575,000 during the year ended September 30, 2023. Additionally, capital expenditure accruals related to oil and natural gas asset retirement obligations decreased $ 577,000 during the year ended September 30, 2024 and increased $ 1,483,000 during the year ended September 30, 2023. 102 19. RELATED PARTY TRANSACTIONS Kaupulehu Developments is entitled to receive payments from the sales of lots and/or residential units by KD I and KD II. KD I and KD II are part of the Kukio Resort Land Development Partnerships in which Barnwell holds indirect 19.6 % and 10.8 % non-controlling ownership interests, respectively, accounted for under the equity method of investment. The percentage of sales payments are part of transactions which took place in 2004 and 2006 where Kaupulehu Developments sold its leasehold interests in Increment I and Increment II to KD I's and KD II's predecessors in interest, respectively, which was prior to Barnwell’s affiliation with KD I and KD II which commenced on November 27, 2013, the acquisition date of our ownership interest in the Kukio Resort Land Development Partnerships. Changes to the arrangement above, effective March 7, 2019, are discussed in Note 4. During the year ended September 30, 2024, Barnwell received $ 500,000 in percentage of sales payments from KD I from the sale of the last two single-family lots within Increment I. During the year ended September 30, 2023, Barnwell received $ 265,000 in percentage of sales payments from KD I from the sale of one single-family lot within Increment I. In May 2023, the Company’s Board of Directors approved and ratified the payment of one-time special director fees to directors Kenneth Grossman and Doug Woodrum for their services on behalf of the Company and the Board of Directors pertaining to the negotiations of the cooperation and support agreement and the settlement of the potential proxy contest at the 2023 annual meeting of stockholders. Mr. Grossman received a one-time special director fee of $ 100,000 , which was paid in $ 40,000 cash and a stock grant of 22,728 shares of Barnwell common stock (valued at $ 60,000 using the closing price of Barnwell's common stock on May 11, 2023, the date of grant). Mr. Woodrum received a one-time special director fee of $ 50,000 , which was paid in $ 20,000 cash and a stock grant of 11,363 shares of Barnwell common stock (valued at $ 30,000 using the closing price of Barnwell's common stock on May 11, 2023, the date of grant). 20. SUBSEQUENT EVENTS Restricted Stock Units In October 2024, the Board of Directors of the Company granted a total of 105,820 restricted stock units to the independent directors of the Board as partial payment of director fees for their service as members of the Board. The restricted stock units vest ratably over a three-year period, subject to the director’s continued service through the applicable vesting date. Contract Drilling Segment Drilling Rig In December 2024, the Company entered into a purchase agreement with an independent third party for the sale of a contract drilling segment drilling rig and related ancillary equipment. The sale of these assets will close upon the buyer’s acceptance of the drilling rig and transfer of the legal title at delivery which is expected to occur in our second quarter of fiscal 2025. 21. SUMMARY OF SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED) Disclosure is not required as Barnwell qualifies as a smaller reporting company. 103 22. SUPPLEMENTARY OIL AND NATURAL GAS INFORMATION (UNAUDITED) The following tables summarize information relative to Barnwell’s oil and natural gas operations, which are conducted in Canada and in the U.S. states of Oklahoma and Texas. Proved reserves are the estimated quantities of oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved producing oil and natural gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. The estimated net interests in total proved and proved producing reserves are based upon subjective engineering judgments and may be affected by the limitations inherent in such estimations. The process of estimating reserves is subject to continual revision as additional information becomes available as a result of drilling, testing, reservoir studies and production history. There can be no assurance that such estimates will not be materially revised in subsequent periods. (A) Oil and Natural Gas Reserves The following tables summarizes changes in the estimates of Barnwell’s net interests in total proved reserves of oil and natural gas liquids and natural gas, which are located in Canada and the U.S. states of Oklahoma and Texas. All of the information regarding Canadian reserves in this Form 10-K is derived from the report of our independent petroleum reserve engineers, InSite, and is included as an Exhibit to this Form 10-K. All of the information regarding U.S. reserves in this Form 10-K is derived from the report of our independent petroleum reserve engineers, Ryder Scott, and is included as an Exhibit to this Form 10-K. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimates of established proved producing oil and natural gas properties. Accordingly, these estimates are expected to change as future information becomes available. Proved oil and natural gas reserves are the estimated quantities of oil and natural gas that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions (i.e., prices and costs) existing at the time the estimate is made. Oil (Bbls) Canada United States Total Proved reserves: Balance at September 30, 2022 846,000 29,000 875,000 Revisions of previous estimates ( 43,000 ) 19,000 ( 24,000 ) Extensions, discoveries and other additions 167,000 85,000 252,000 Less production ( 183,000 ) ( 21,000 ) ( 204,000 ) Balance at September 30, 2023 787,000 112,000 899,000 Revisions of previous estimates 222,000 ( 3,000 ) 219,000 Extensions, discoveries and other additions 117,000 — 117,000 Acquisitions of reserves 4,000 — 4,000 Less sales of reserves ( 54,000 ) — ( 54,000 ) Less production ( 184,000 ) ( 19,000 ) ( 203,000 ) Proved Reserves, September 30, 2024 892,000 90,000 982,000 104 NGL (Bbls) Canada United States Total Proved reserves: Balance at September 30, 2022 144,000 61,000 205,000 Revisions of previous estimates 1,000 29,000 30,000 Extensions, discoveries and other additions 32,000 112,000 144,000 Less production ( 27,000 ) ( 25,000 ) ( 52,000 ) Balance at September 30, 2023 150,000 177,000 327,000 Revisions of previous estimates 70,000 15,000 85,000 Extensions, discoveries and other additions 15,000 — 15,000 Acquisitions of reserves 2,000 — 2,000 Less sales of reserves ( 2,000 ) — ( 2,000 ) Less production ( 36,000 ) ( 28,000 ) ( 64,000 ) Proved Reserves, September 30, 2024 199,000 164,000 363,000 Natural Gas (Mcf) Canada United States Total Proved reserves: Balance at September 30, 2022 4,519,000 466,000 4,985,000 Revisions of previous estimates 435,000 387,000 822,000 Extensions, discoveries and other additions 1,079,000 1,078,000 2,157,000 Less production ( 1,023,000 ) ( 240,000 ) ( 1,263,000 ) Balance at September 30, 2023 5,010,000 1,691,000 6,701,000 Revisions of previous estimates 826,000 82,000 908,000 Extensions, discoveries and other additions 313,000 — 313,000 Acquisitions of reserves 16,000 — 16,000 Less sales of reserves ( 139,000 ) — ( 139,000 ) Less production ( 1,085,000 ) ( 259,000 ) ( 1,344,000 ) Proved Reserves, September 30, 2024 4,941,000 1,514,000 6,455,000 105 Total Equivalent Reserves (Boe) Canada United States Total Proved reserves: Balance at September 30, 2022 1,769,000 170,000 1,939,000 Revisions of previous estimates 5,000 110,000 115,000 Extensions, discoveries and other additions 379,000 377,000 756,000 Less production ( 381,000 ) ( 86,000 ) ( 467,000 ) Balance at September 30, 2023 1,772,000 571,000 2,343,000 Revisions of previous estimates 430,000 27,000 457,000 Extensions, discoveries and other additions 184,000 — 184,000 Acquisitions of reserves 9,000 — 9,000 Less sales of reserves ( 79,000 ) — ( 79,000 ) Less production ( 401,000 ) ( 90,000 ) ( 491,000 ) Proved Reserves, September 30, 2024 1,915,000 508,000 2,423,000 The following tables summarize changes in the estimates of Barnwell’s net interests in total proved undeveloped reserves and presents the balances of total proved developed reserves of oil and natural gas liquids and natural gas, which are located in Canada and the U.S. states of Oklahoma and Texas. Proved developed oil and natural gas reserves are proved reserves that can be expected to be recovered through existing wells and equipment in place and under operating methods being utilized at the time the estimates were made. Oil (Bbls) Canada United States Total Proved undeveloped reserves: Balance at September 30, 2023 92,000 — 92,000 Conversion to proved developed reserves ( 98,000 ) — ( 98,000 ) Revisions of previous estimates 6,000 — 6,000 Additions due to a new well 109,000 — 109,000 Proved Undeveloped Reserves, September 30, 2024 109,000 — 109,000 Proved Developed Reserves, September 30, 2023 695,000 112,000 807,000 Proved Developed Reserves, September 30, 2024 783,000 90,000 873,000 106 NGL (Bbls) Canada United States Total Proved undeveloped reserves: Balance at September 30, 2023 18,000 — 18,000 Conversion to proved developed reserves ( 10,000 ) — ( 10,000 ) Revisions of previous estimates ( 8,000 ) — ( 8,000 ) Additions due to a new well 23,000 — 23,000 Proved Undeveloped Reserves, September 30, 2024 23,000 — 23,000 Proved Developed Reserves, September 30, 2023 132,000 177,000 309,000 Proved Developed Reserves, September 30, 2024 176,000 164,000 340,000 Natural Gas (Mcf) Canada United States Total Proved undeveloped reserves: Balance at September 30, 2023 608,000 — 608,000 Conversion to proved developed reserves ( 279,000 ) — ( 279,000 ) Revisions of previous estimates ( 330,000 ) — ( 330,000 ) Additions due to a new well 641,000 — 641,000 Proved Undeveloped Reserves, September 30, 2024 640,000 — 640,000 Proved Developed Reserves, September 30, 2023 4,402,000 1,691,000 6,093,000 Proved Developed Reserves, September 30, 2024 4,301,000 1,514,000 5,815,000 Total Equivalent Reserves (Boe) Canada United States Total Proved undeveloped reserves: Balance at September 30, 2023 211,000 — 211,000 Conversion to proved developed reserves ( 155,000 ) — ( 155,000 ) Revisions of previous estimates ( 56,000 ) — ( 56,000 ) Additions due to a new well 239,000 — 239,000 Proved Undeveloped Reserves, September 30, 2024 239,000 — 239,000 Proved Developed Reserves, September 30, 2023 1,561,000 571,000 2,132,000 Proved Developed Reserves, September 30, 2024 1,676,000 508,000 2,184,000 107 (B) Capitalized Costs Relating to Oil and Natural Gas Producing Activities All capitalized costs relating to oil and natural gas producing activities in Canada and the U.S. are summarized as follows: September 30, 2024 Canada United States Total Proved properties $ 76,963,000 $ 6,594,000 $ 83,557,000 Unproved properties — — — Total capitalized costs 76,963,000 6,594,000 83,557,000 Accumulated depletion, depreciation, and impairment 64,402,000 2,601,000 67,003,000 Net capitalized costs $ 12,561,000 $ 3,993,000 $ 16,554,000 September 30, 2023 Canada United States Total Proved properties $ 74,440,000 $ 6,411,000 $ 80,851,000 Unproved properties — — — Total capitalized costs 74,440,000 6,411,000 80,851,000 Accumulated depletion, depreciation, and impairment 58,477,000 1,072,000 59,549,000 Net capitalized costs $ 15,963,000 $ 5,339,000 $ 21,302,000 (C) Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Year ended September 30, 2024 Canada United States Total Acquisition of properties: Proved $ 146,000 $ — $ 146,000 Unproved — — — Exploration costs 34,000 — 34,000 Development costs 3,865,000 183,000 4,048,000 Total $ 4,045,000 $ 183,000 $ 4,228,000 Year ended September 30, 2023 Canada United States Total Acquisition of properties: Proved $ 66,000 $ — $ 66,000 Unproved — — — Exploration costs 461,000 255,000 716,000 Development costs 6,331,000 5,099,000 11,430,000 Total $ 6,858,000 $ 5,354,000 $ 12,212,000 108 (D) Results of Operations for Oil and Natural Gas Producing Activities Year ended September 30, 2024 Canada United States Total Net revenues $ 15,093,000 $ 2,303,000 $ 17,396,000 Production costs ( 9,230,000 ) ( 619,000 ) ( 9,849,000 ) Depletion ( 4,139,000 ) ( 808,000 ) ( 4,947,000 ) Impairment of assets ( 2,164,000 ) ( 721,000 ) ( 2,885,000 ) Pre-tax results of operations (1) ( 440,000 ) 155,000 ( 285,000 ) Estimated income tax expense (2) 320,000 20,000 340,000 Results of operations (1) $ ( 760,000 ) $ 135,000 $ ( 625,000 ) Year ended September 30, 2023 Canada United States Total Net revenues $ 16,630,000 $ 2,746,000 $ 19,376,000 Production costs ( 9,859,000 ) ( 575,000 ) ( 10,434,000 ) Depletion ( 3,600,000 ) ( 669,000 ) ( 4,269,000 ) Pre-tax results of operations (1) 3,171,000 1,502,000 4,673,000 Estimated income tax expense (2) 107,000 44,000 151,000 Results of operations (1) $ 3,064,000 $ 1,458,000 $ 4,522,000 _________________ (1) Before general and administrative expenses, interest expense, and foreign exchange gains and losses. (2) Estimated income tax expense includes changes to the deferred income tax valuation allowance necessary for the portion of Canadian and U.S. federal tax law deferred tax assets that may not be realizable. (E) Standardized Measure, Including Year-to-Year Changes Therein, of Estimated Discounted Future Net Cash Flows The following tables utilize reserve and production data estimated by independent petroleum reserve engineers. The information may be useful for certain comparison purposes but should not be solely relied upon in evaluating Barnwell or its performance. Moreover, the projections should not be construed as realistic estimates of future cash flows, nor should the standardized measure be viewed as representing current value. The estimated future cash flows at September 30, 2024 and 2023 were based on average sales prices in effect on the first day of the month for the preceding twelve month period in accordance with SEC Release No. 33-8995. The future production and development costs represent the estimated future expenditures that we will incur to develop and produce the proved reserves, assuming continuation of existing economic conditions. The future income tax expenses were computed by applying statutory income tax rates in existence at September 30, 2024 and 2023 to the future pre-tax net cash flows relating to proved reserves, net of the tax basis of the properties involved. Material revisions to reserve estimates may occur in the future, development and production of the oil and natural gas reserves may not occur in the periods assumed and actual prices realized and actual costs incurred are expected to vary significantly from those used. Management does not rely upon this information in making investment and operating decisions; rather, those decisions are based upon a wide range of factors, including estimates of probable reserves as well as proved reserves and price and cost assumptions different than those reflected herein. 109 Barnwell has included all abandonment, decommissioning and reclamation costs and inactive well costs in accordance with best practice recommendations into the Company’s reserve reports. Standardized Measure of Discounted Future Net Cash Flows Year ended September 30, 2024 Canada United States Total Future cash inflows $ 75,293,000 $ 12,043,000 $ 87,336,000 Future production costs ( 42,601,000 ) ( 5,080,000 ) ( 47,681,000 ) Future development costs ( 2,795,000 ) — ( 2,795,000 ) Future income tax expenses ( 2,666,000 ) ( 161,000 ) ( 2,827,000 ) Future net cash flows excluding abandonment, decommissioning and reclamation 27,231,000 6,802,000 34,033,000 Future abandonment, decommissioning and reclamation ( 18,026,000 ) ( 50,000 ) ( 18,076,000 ) Future net cash flows 9,205,000 6,752,000 15,957,000 10% annual discount for timing of cash flows 2,697,000 ( 2,804,000 ) ( 107,000 ) Standardized measure of discounted future net cash flows $ 11,902,000 $ 3,948,000 $ 15,850,000 Year ended September 30, 2023 Canada United States Total Future cash inflows $ 73,429,000 $ 15,995,000 $ 89,424,000 Future production costs ( 41,935,000 ) ( 4,168,000 ) ( 46,103,000 ) Future development costs ( 2,958,000 ) — ( 2,958,000 ) Future income tax expenses ( 1,512,000 ) ( 264,000 ) ( 1,776,000 ) Future net cash flows excluding abandonment, decommissioning and reclamation 27,024,000 11,563,000 38,587,000 Future abandonment, decommissioning and reclamation ( 18,585,000 ) ( 42,000 ) ( 18,627,000 ) Future net cash flows 8,439,000 11,521,000 19,960,000 10% annual discount for timing of cash flows 4,790,000 ( 4,837,000 ) ( 47,000 ) Standardized measure of discounted future net cash flows $ 13,229,000 $ 6,684,000 $ 19,913,000 110 Changes in the Standardized Measure of Discounted Future Net Cash Flows Year ended September 30, 2024 2023 Beginning of year $ 19,913,000 $ 27,878,000 Sales of oil and natural gas produced, net of production costs ( 7,547,000 ) ( 8,942,000 ) Net changes in prices and production costs, net of royalties and wellhead taxes ( 12,201,000 ) ( 11,913,000 ) Extensions and discoveries 1,725,000 10,767,000 Net change due to purchases and sales of minerals in place ( 895,000 ) — Changes in future development costs 170,000 ( 2,959,000 ) Revisions of previous quantity estimates 9,478,000 2,227,000 Net change in income taxes 1,786,000 2,868,000 Accretion of discount 3,359,000 905,000 Other - changes in the timing of future production and other 76,000 ( 1,202,000 ) Other - net change in Canadian dollar translation rate ( 14,000 ) 284,000 Net change ( 4,063,000 ) ( 7,965,000 ) End of year $ 15,850,000 $ 19,913,000 111 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None.