BARNWELL INDUSTRIES INC 10-K

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following discussion is intended to assist in the understanding of the Consolidated Balance Sheets of Barnwell Industries, Inc. and subsidiaries (collectively referred to herein as “Barnwell,” “we,” “our,” “us” or the “Company”) as of September 30, 2024 and 2023, and the related Consolidated Statements of Operations, Comprehensive Loss, Equity, and Cash Flows for the years ended September 30, 2024 and 2023. This discussion should be read in conjunction with the consolidated financial statements and related Notes to Consolidated Financial Statements included in this report. Critical Accounting Policies and Estimates The Company considers an accounting estimate to be critical if the accounting estimate requires the Company to make assumptions that are difficult or subjective about matters that were highly uncertain at the time that the accounting estimate was made, and changes in the estimate that are reasonably likely to occur in periods subsequent to the period in which the estimate was made, or use of different estimates that the Company could have used in the current period, would have a material impact on the Company’s financial condition or results of operations. The most critical accounting policies inherent in the preparation of the Company’s consolidated financial statements are described below. We continue to monitor our accounting policies to ensure proper application of current rules and regulations. Oil and Natural Gas Properties - full cost ceiling calculation and depletion Policy Description We use the full cost method of accounting for our oil and natural gas properties under which we are required to conduct quarterly calculations of a “ceiling,” or limitation, on the carrying value of oil and natural gas properties . The ceiling limitation is 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, 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 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. 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. 35 Judgments and Assumptions The estimate of our oil and natural gas reserves is a major component of the ceiling calculation and represents the component that requires the most subjective judgments. Estimates of reserves are forecasts based on engineering data, historical data, projected future rates of production and the timing of future expenditures. The process of estimating oil and natural gas reserves requires substantial judgment, resulting in imprecise determinations, particularly for new discoveries. Our reserve estimates are prepared at least annually by independent petroleum reserve engineers. The passage of time provides more quantitative and qualitative information regarding estimates of reserves, and revisions are made to prior estimates to reflect updated information. A portion of the revisions are attributable to changes in the rolling 12-month average first-day-of-the-month prices, which impact the economics of producible reserves. In the last three fiscal years, annual revisions to our reserve volume estimates have averaged 18% of the previous year’s estimate, due in large part to the impacts of volatile oil and natural gas prices which change the economic viability of producing such reserves and changes in estimated proved undeveloped reserves which can fluctuate from year to year depending upon the Company's plans and ability to fund the capital expenditures necessary to develop such reserves. There can be no assurance that more significant revisions will not be necessary in the future. If future significant revisions are necessary that reduce previously estimated reserve quantities, such revisions could result in a write-down of oil and natural gas properties. If reported reserve volumes were revised downward by 5% at the end of fiscal 2024, the ceiling limitation for Canada would have decreased approximately $906,000 which would not have resulted in a ceiling impairment before income taxes due to sufficient room between the ceiling and the carrying value of Canadian oil and natural gas properties at the end of fiscal 2024 of approximately $4,658,000. However, an additional $197,000 impairment would be recorded for U.S. oil and gas properties at the end of fiscal 2024 as there is no room between the ceiling and the carrying value of U.S. oil and natural gas properties at the end of fiscal 2024. In addition to the impact of the estimates of proved reserves on the calculation of the ceiling, estimated proved reserves are also a significant component of the quarterly calculation of depletion expense. The lower the estimated reserves, the higher the depletion rate per unit of production. Conversely, the higher the estimated reserves, the lower the depletion rate per unit of production. If reported reserve volumes were revised downward by 5% as of the beginning of fiscal 2024, depletion for fiscal 2024 would have increased by approximately $222,000. While the quantities of proved reserves require substantial judgment, the associated prices of oil, natural gas and natural gas liquids reserves are the average first-day-of-the-month prices during the 12-month period ending in the reporting period on a constant basis as prescribed by SEC regulations. Additionally, the applicable discount rate that is used to calculate the discounted present value of the reserves is mandated at 10%. Costs included in future net revenues are determined in a similar manner. As such, the future net revenues associated with the estimated proved reserves are not based on an assessment of future prices or costs. Contract Drilling Revenues and Operating Expenses Policy Description 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 36 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. 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. 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. 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. Judgments and Assumptions 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. Increases or decreases in the estimated costs to complete a performance obligation without a change to the contract price has the impact to decrease or increase, respectively, the contract completion percentage applied to the contract price to calculate the cumulative contract revenue to be recognized to date. Changes in the cost estimates can have a material impact on our contract revenue and are reflected in the results of operations when they become known. 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 37 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 work to be performed, and unexpected construction execution errors, among others. Any revisions to estimated costs to complete the performance obligation from period to period as a result of changes in these factors can materially affect revenue and operating results in the period such revisions are necessary. In addition, many contracts give the customer a unilateral right to cancel for convenience or other than for cause. In accordance with FASB ASC 606-10-32-4, our estimates are based on the assumption that the existing contract will not be cancelled. Any unforeseen cancellation of a contract may result in a material revision to our estimates. We have a long history of working with multiple types of projects and preparing cost estimates, and we rely on the expertise of key personnel to prepare what we believe are reasonable best estimates given available facts and circumstances. Due to the nature of the work involved, however, judgment is involved to estimate the costs to complete and the amounts estimated could have a material impact on the revenue we recognize in each accounting period. We can not estimate unforeseen events and circumstances which may result in actual results being materially different from previous estimates. Income Taxes Policy Description 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. Deferred income tax assets are routinely assessed for realizability. 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. Barnwell recognizes the financial statement effects of tax positions when it is more likely than not that the position will be sustained by a taxing authority. Judgments and Assumptions We make estimates and judgments in determining our income tax expense for each reporting period. Significant changes to these estimates could result in an increase or decrease in our tax provision in future periods. We are also required to make judgments about the recoverability of deferred tax assets and when it is more likely than not that all or a portion of deferred tax assets will not be realized, a valuation allowance is provided. We consider available positive and negative evidence and available tax planning strategies when assessing the realizability of deferred tax assets. Accordingly, changes in our business performance and unforeseen events could require a further increase in the valuation allowance or a reversal in the valuation allowance in future periods. This could result in a charge to, or an increase in, income in the period such determination is made, and the impact of these changes could be material. 38 In addition, Barnwell operates within the U.S. and Canada and is subject to audit by taxing authorities in these jurisdictions. Barnwell records accruals for the estimated outcomes of these audits, and the accruals may change in the future due to new developments in each matter. Tax benefits are recognized when we determine that it is more likely than not that such benefits will be realized. Management evaluates its potential exposures from tax positions taken that have 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. Where uncertainty exists due to the complexity of income tax statutes and where the potential tax amounts are significant, we generally seek independent tax opinions to support our positions. If our evaluation of the likelihood of the realization of benefits is inaccurate, we could incur additional income tax and interest expense that would adversely impact earnings, or we could receive tax benefits greater than anticipated which would positively impact earnings, either of which could be material. Overview 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. (oil and natural gas segment), 2) leasehold land interests in Hawaii (land investment segment), and 3) drilling wells and installing and repairing water pumping systems in Hawaii (contract drilling segment). Oil and Natural Gas Segment Barnwell is involved in the acquisition and development of oil and natural gas properties primarily in the Twining area of Alberta, Canada, where we initiate and participate in acquisition and developmental operations for oil and natural gas on properties in which we have an interest, and evaluate proposals by third parties with regard to participation in such exploratory and developmental operations elsewhere. Additionally, through its wholly-owned subsidiaries BOK and Barnwell Texas, Barnwell is involved in non-operated oil and natural gas investments in Oklahoma and Texas, respectively. Barnwell sells all of its Canadian and U.S. oil and natural gas under short-term contracts with marketers based on prices indexed to market prices. The price of natural gas, oil and natural gas liquids is freely negotiated between the buyers and sellers. Oil and natural gas prices are determined by many factors that are outside of our control. Market prices for oil and natural gas products are dependent upon factors such as, but not limited to, changes in market supply and demand, which are impacted by overall economic activity, changes in weather, pipeline capacity constraints, inventory storage levels, and output. Oil and natural gas prices are very difficult to predict and fluctuate significantly. Natural gas prices tend to be higher in the winter than in the summer due to increased demand, although this trend has become less pronounced due to the increased use of natural gas to generate electricity for air conditioning in the summer and increased natural gas storage capacity in North America. Oil and natural gas exploration, development and operating costs generally follow trends in product market prices, thus in times of higher product prices the cost of exploring, developing and operating the oil and natural gas properties will tend to escalate as well. Capital expenditures are required to fund the exploration, development, and production of oil and natural gas. Cash outlays for capital expenditures are largely discretionary, however, a minimum level of capital expenditures is required to replace depleting reserves. Due to the nature of oil and natural gas exploration and development, significant uncertainty exists as to the ultimate success of any drilling effort. 39 Land Investment Segment Through Barnwell’s 77.6% interest in Kaupulehu Developments, 75% interest in KD Kona, and 34.45% non-controlling interest in KKM Makai, the Company’s land investment interests include the following: • The right to receive percentage of sales payments from KD I resulting from the sale of single-family residential lots by KD I, within Increment I of the Kaupulehu Lot 4A area located in the North Kona District of the island of Hawaii. However, in the quarter ended March 31, 2024, the last two remaining single-family lots in Increment I were sold and there are no more lots available for sale in Increment I. Kaupulehu Developments was entitled to receive payments from KD I based on 10% of the gross receipts from KD I’s sales at Increment I. Increment I is an area zoned for approximately 80 single-family lots. • The right to receive 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. Such interests are limited to distributions or net profits interests and Barnwell does not have any partnership interest in KD II or KDK through its interest in Kaupulehu Developments. Barnwell also has 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, LLC and a pool of various individuals, respectively, all of whom are partners of KKM and are unrelated to Barnwell. The remaining acreage within 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. • An indirect 19.6% non-controlling ownership interest in KD Kukio Resorts, LLLP, KD Maniniowali, LLLP and KD I and an indirect 10.8% non-controlling ownership interest in KD II through KDK. These entities 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 was the developer of Kaupulehu Lot 4A Increments I and II. 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 private club memberships, a few of which remain available for sale. The Kukio Resort Land Development Partnerships have remaining Increment I obligations to complete project amenities, infrastructure, beautification, and restoration of certain areas and therefore has yet to fully recognize its deferred profit on the Increment I project as a whole. The Increment I deferred profit at September 30, 2024 for the Kukio Resort Land 40 Development Partnerships as a whole was approximately $4,500,000; the recognition of which is dependent upon the completion of the Increment I obligations. The Kukio Resort Land Development Partnerships have accrued estimated costs of these obligations of approximately $3,000,000. The Kukio Resort Land Development Partnerships currently appears to have the ability to fund those obligations but there are no assurances that it can ultimately do so in the future if unforeseen events occur. The Kukio Resort Land Development Partnerships will recognize the Increment I deferred revenue and costs of sales on a percentage completion basis as the cash outlays to complete the remaining project obligations are made. The Kukio Resort Land Development Partnerships’ deferred profit and accrued costs to complete are not reflected in Barnwell’s Condensed Consolidated Balance Sheets as we account for our investment in the Kukio Resort Land Development Partnerships under the equity method of accounting. No percentage of sales payments will be earned by Barnwell on any future recognition of Increment I deferred profit as such payments were already fully earned and received based on cash received by the Kukio Resort Land Development Partnerships as the Increment I lots were sold. • Approximately 1,000 acres of vacant leasehold land zoned conservation in the Kaupulehu Lot 4C area, which currently has no development potential without both a development agreement with the lessor and zoning reclassification. The lease terminates in December 2025. Contract Drilling Segment Barnwell drills water and water monitoring wells and installs and repairs water pumping systems in Hawaii. Contract drilling results are highly dependent upon the quantity, dollar value and timing of contracts awarded by governmental and private entities and can fluctuate significantly. Business Environment Our operations are located in Canada and in the states of Hawaii, Oklahoma, and Texas. Accordingly, our business performance is directly affected by macroeconomic conditions in those areas, as well as general economic conditions of the U.S. domestic and world economies. Oil and Natural Gas Segment Barnwell realized an average price for oil of $66.49 per barrel during the year ended September 30, 2024, a decrease of 5% from $69.77 per barrel realized during the prior year and realized an average price for natural gas of $1.41 per Mcf during the year ended September 30, 2024, a decrease of 47% from $2.64 per Mcf realized during the prior year. Oil and natural gas prices continue to be volatile over time and thus, the Company is unable to reasonably predict future prices and the impacts future prices will have on the Company. Land Investment Segment Future revenues from the sale of interest in leasehold land and any future cash distributions from our investment in the Kukio Resort Land Development Partnerships are dependent upon the potential future development or sale of the remaining portion of Increment II by KD II of Kaupulehu Lot 4A. The amount and timing of future land investment segment proceeds from percentage of sales payments and cash distributions from the Kukio Resort Land Development Partnerships are highly uncertain and out of 41 our control, and 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. Contract Drilling Segment Demand for water well drilling and/or pump installation and repair services is volatile and dependent upon land development activities within the state of Hawaii. Results of Operations Summary Net loss attributable to Barnwell for fiscal 2024 totaled $5,565,000, a $4,604,000 increase in net loss from a net loss of $961,000 in fiscal 2023. The following factors affected the results of operations for the current fiscal year as compared to the prior fiscal year: • A $4,958,000 decrease in oil and natural gas segment operating results, before income taxes, primarily attributable to a $2,885,000 non-cash ceiling test impairment in the current year and due to decreases in natural gas, oil, and natural gas prices in the current year period as compared to the same period in the prior year; • A $599,000 decrease in contract drilling segment operating results, before income taxes, primarily resulting from decreased activity and an increase in drilling difficulties and labor costs as compared to the same period in the prior year; • A $551,000 gain recognized in the prior year period from the sale of a contract drilling segment drilling rig, whereas there was no such gain in the current year period; and • Results improved as general and administrative expenses decreased $1,358,000 primarily due to decreases in stockholder costs and professional fees in the current year period as compared to the same period in the prior year. General Barnwell conducts operations in the U.S. and Canada. Consequently, Barnwell is subject to foreign currency translation and transaction gains and losses due to fluctuations of the exchange rates between the Canadian dollar and the U.S. dollar. Barnwell cannot accurately predict future fluctuations of the exchange rates and the impact of such fluctuations may be material from period to period. To date, we have not entered into foreign currency hedging transactions. 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. The average exchange rate of the Canadian dollar to the U.S. dollar decreased 1% in fiscal 2024, as compared to fiscal 2023 and the exchange rate of the Canadian dollar to the U.S. dollar remained unchanged at September 30, 2024, as compared to September 30, 2023. Accordingly, the assets, liabilities, stockholders’ equity and revenues and expenses of Barnwell’s subsidiaries operating in Canada have been 42 adjusted to reflect the change in the exchange rates. Other comprehensive income and losses are not included in net earnings and net loss. Other comprehensive loss due to foreign currency translation adjustments, net of taxes, for fiscal 2024 was nil, a $2,000 change from other comprehensive loss due to foreign currency translation adjustments, net of taxes, of $2,000 in fiscal 2023. There were no taxes on other comprehensive loss due to foreign currency translation adjustments in fiscal 2024 and 2023 due to a full valuation allowance on the related deferred tax assets. Oil and natural gas Selected Operating Statistics The following tables set forth Barnwell’s annual average prices per unit of production and annual net production volumes for fiscal 2024 as compared to fiscal 2023. Production amounts reported are net of royalties. Annual Average Price Per Unit Increase (Decrease) 2024 2023 $ % Natural gas (Mcf)* $ 1.41 $ 2.64 $ (1.23) (47)% Oil (Bbls) $ 66.49 $ 69.77 $ (3.28) (5)% Natural gas liquids (Bbls) $ 29.38 $ 32.24 $ (2.86) (9)% Annual Net Production Increase (Decrease) 2024 2023 Units % Natural gas (Mcf) 1,344,000 1,263,000 81,000 6% Oil (Bbls) 203,000 204,000 (1,000) —% Natural gas liquids (Bbls) 64,000 52,000 12,000 23% _________________________________________________ * Natural gas price per unit is net of pipeline charges. The oil and natural gas segment generated a $285,000 operating loss in fiscal 2024 before general and administrative expenses, a decrease in operating results of $4,958,000 as compared to $4,673,000 of operating profit in fiscal 2023. 43 The following table sets forth Barnwell’s oil and natural gas segment operating (loss) profit before general and administrative expenses by geographic location: Year ended September 30, 2024 2023 Operating (loss) profit (before general and administrative expenses) Canada (1) $ (440,000) $ 3,171,000 United States (2) 155,000 1,502,000 Total operating (loss) profit $ (285,000) $ 4,673,000 ________________________ (1) The operating loss for Canada for the year ended September 30, 2024 includes a non-cash ceiling test impairment of $2,164,000. (2) The operating profit for the United States for year ended September 30, 2024 includes a non-cash ceiling test impairment of $721,000. Oil and natural gas revenues decreased $1,980,000 (10%) from $19,376,000 in fiscal 2023 to $17,396,000 in fiscal 2024, primarily due to significant decreases in natural gas, oil, and natural gas liquid prices, which decreased 47%, 5%, and 9%, respectively, as compared to the same period in the prior year. The decrease was partially offset by 6% and 23% increases in natural gas and natural gas liquid production, respectively, as compared to the same period in the prior year. In the quarter ended December 31, 2023, the Company amended certain of its Canadian purchase and sales contracts to change the sales price on 1,055 gross Mcf per day of the Canadian natural gas that it sells during the period from April 1, 2024 to October 31, 2024 to a fixed index price before differentials of $2.55 Canadian dollars per Mcf, with remaining volumes continuing to be sold at spot prices. This per day volume of natural gas under fixed index price contract is equivalent to approximately 33% of Canadian natural gas gross production per day for the year ended September 30, 2024. In July 2024, the Company amended the sales price on 1,055 gross Mcf per day of the Canadian natural gas it will sell during the period from November 1, 2024 to March 31, 2025 to a fixed index price before differentials of $2.64 Canadian dollars per Mcf, with remaining volumes continuing to be sold at spot prices. This per day volume of natural gas under this fixed index price contract is equivalent to approximately 33% of Canadian natural gas gross production per day for the year ended September 30, 2024. These natural gas contracts were eligible for and elected as normal purchase and normal sales exception contracts and were thus excluded from derivative accounting. In the quarter ended December 31, 2023, the Company amended certain of its Canadian purchase and sales contracts to change the sales price on 225 gross barrels per day of the Canadian oil for sale for the period from January 1, 2024 to June 30, 2024 to a fixed index price before differentials of $69.46 per net barrel, with remaining volumes continuing to be sold at spot prices. This per day volume of oil under this fixed index price contract was equivalent to approximately 35% of Canadian oil gross production per day for the year ended September 30, 2024. In July 2024, the Company amended the sales price on 100 gross barrels per day of the Canadian oil that it sells during the period from August 1, 2024 to December 31, 2024 to a fixed index price before differentials of $79.00 per net barrel, with remaining volumes continuing to be sold at spot prices. This per day volume of oil under this fixed index price contract is equivalent to approximately 16% of Canadian oil gross production per day for the year ended September 30, 2024. These oil contracts were eligible for and elected as normal purchase and normal sales exception contracts and were thus excluded from derivative accounting. Oil and natural gas operating expenses decreased $585,000 (6%) from $10,434,000 in fiscal 2023 to $9,849,000 in fiscal 2024, primarily due to decreases in repairs, electricity and chemical costs in the current year period as compared to the same period in the prior year and due to optimization as a result of 44 certain capital expenditures made earlier in the current year. The decrease in oil and natural gas operating expenses was partially offset by an increase in costs due to higher production and an increase in workovers and maintenance costs in the current year period as compared to the same period in the prior year. Oil and natural gas segment depletion increased $678,000 (16%) from $4,269,000 in fiscal 2023 to $4,947,000 in fiscal 2024, primarily due to an increase in the depletion rate for Canadian properties and also increased production from those properties, both of which were the result of the wells drilled in fiscal 2023 and late fiscal 2024, and facilities expansion and upgrade costs, all in the Twining area. The increase in oil and natural gas segment depletion was also due to increased depletion from production in Texas, whereas there was only a minor amount of such depletion in the prior year period. Sale of interest in leasehold land Kaupulehu Developments was entitled to receive a percentage of the gross receipts from the sales of lots and/or residential units in Increment I by KD I. The following table summarizes the revenues received from KD I and the amount of fees directly related to such revenues: 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 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. There is an Increment II owned by KD II in which the Company has a 10.8% indirect non-controlling ownership interest. There is no assurance with regards to the amounts of future sales from Increment II 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. Contract drilling Contract drilling revenues and costs are associated with well drilling and water pump installation, replacement and repair in Hawaii. Contract drilling revenues decreased $1,815,000 (33%) to $3,612,000 in fiscal 2024, as compared to $5,427,000 in fiscal 2023 and contract drilling costs decreased $1,186,000 (21%) to $4,483,000 in fiscal 2024, as compared to $5,669,000 in fiscal 2023. The contract drilling segment generated a $1,027,000 operating loss before general and administrative expenses during fiscal 2024, a decrease in operating results of $599,000 as compared to an operating loss before general and administrative expenses of $428,000 in fiscal 2023. The decreases in contract drilling revenues and contract drilling costs for the current year period as compared to the same period in the prior year were primarily due to decreased activity and a decrease in 45 revenues and costs recognized from materials deliveries and installations as compared to the same period in the prior year. Also, during the current year period, unforeseen drilling difficulties were encountered on a job where costs were spent to retrieve a portion of the drill string that twisted off and slower drilling was required to ensure plumbness of the hole. In addition, the Company commenced compensation adjustments for contract drilling segment personnel to decrease potential attrition of workers and enable the Company to complete its drilling obligations. These factors resulted in contract drilling expenses decreasing less than the decrease in contract drilling revenues. On December 13, 2023, the Company entered into a stock purchase agreement with a construction company for the sale of Water Resources. On December 27, 2023, the stock purchase agreement was terminated by the buyer prior to closing. In January 2024, a significant well drilling contract, which previously had an estimated contract drilling revenue backlog of $2,400,000 and which had not yet started, was cancelled by mutual agreement of Water Resources and the counterparty. At September 30, 2024, there was a backlog of one well drilling and two pump installation and repair contracts and all of the contracts were in progress as of September 30, 2024. The backlog of contract drilling revenues as of December 1, 2024 was approximately $1,100,000, all of which is expected to be realized in fiscal 2025. Based on these contracts in backlog, contract drilling segment operating results for fiscal 2025 is estimated to be significantly less than fiscal 2024. The Company continues to investigate strategies regarding Water Resources' future including, but not limited to, other potential opportunities for a sale of its stock or assets. If no sale of its stock or assets along with contract backlog can be secured, Water Resources will likely be wound down after all contracts in backlog are completed and any remaining drilling rigs and equipment will be liquidated. Management estimates that its three remaining contracts in backlog at September 30, 2024 will be completed in March 2025 or soon thereafter, however it is uncertain as to when the contingent liability related to the required drilling of a monitoring well in satisfaction of a regulatory assessment will be settled (see Note 17 in the “Notes to Consolidated Financial Statements” in Item 8 of this report). General and administrative expenses General and administrative expenses decreased $1,358,000 (20%) to $5,598,000 in fiscal 2024, as compared to $6,956,000 in fiscal 2023. The decrease was primarily due to decreases of $962,000 in professional fees primarily related to legal and consulting services and $533,000 in stockholders costs primarily attributed to the cooperation and support agreement and associated fees to certain directors in the prior year period as compared to the same period in the current year. Depletion, depreciation, and amortization Depletion, depreciation, and amortization increased $649,000 (15%) from $4,457,000 in fiscal 2023 to $5,106,000 in fiscal 2024, primarily due to increases in the depletion rate for Canadian properties and also new production from those properties and due to depletion attributable to production in Texas as discussed in the “Oil and natural gas” section above. 46 Impairment of assets 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 impairments 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. Foreign currency gain Foreign currency gain was $10,000 and $76,000 during the years ended September 30, 2024 and 2023, respectively, due to the effects of foreign exchange rate changes on intercompany loans and advances as a result of changes in the U.S. dollar against the Canadian dollar. The foreign currency gains from intercompany balances are included in our consolidated statement of operations as the intercompany balances were not considered long-term in nature because management estimates that these intercompany balances will be settled in the future. Gain on sale of assets In October 2022, the Company completed the sale of a contract drilling segment drilling rig to an independent third party for proceeds of $551,000, net of related costs. The drilling rig was fully depreciated and had a net book value of zero and as a result of the sale, the Company recognized a $551,000 gain during the year ended September 30, 2023. Equity in income of affiliates Barnwell’s investment in the Kukio Resort Land Development Partnerships is accounted for using the equity method of accounting. Barnwell recognized equity in income of affiliates of $1,071,000 for the 47 year ended September 30, 2024, as compared to equity in income of affiliates of $758,000 for the year ended September 30, 2023. The increase in partnership income is primarily due to the Kukio Resort Land Development Partnerships' sale of the last two lots in Increment I during the current year period, as compared to one lot sale in the prior year period. During the year ended September 30, 2024, Barnwell received cash distributions of $1,071,000 from the Kukio Resort Land Development Partnerships resulting in a net amount of $953,000, after distributing $118,000 to non-controlling interests. 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. 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 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. 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) Barnwell’s effective consolidated income tax rate for fiscal 2024, after adjusting loss before income taxes for non-controlling interests, was (4)%, as compared to an effective consolidated income tax benefit rate of 5% for fiscal 2023. 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 48 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. Net earnings attributable to non-controlling interests Earnings and losses attributable to non-controlling interests represent the non-controlling interests’ share of revenues and expenses related to the various partnerships and joint ventures in which Barnwell has controlling interests and consolidates. Net earnings attributable to non-controlling interests totaled $234,000 in fiscal 2024, as compared to net earnings attributable to non-controlling interests of $150,000 in fiscal 2023. The $84,000 (56%) increase is primarily due to increases in the amount of equity in income of affiliates and percentage of sales revenue received in the current year period as compared to the same period in the prior year. Inflation The effect of inflation on Barnwell has generally been to increase its cost of operations, general and administrative costs and direct costs associated with oil and natural gas production and contract drilling operations. Oil and natural gas prices realized by Barnwell are essentially determined by world prices for oil and western Canadian/Midwestern U.S. prices for natural gas. Impact of Recently Issued Accounting Standards on Future Filings In November 2023, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2023-07 “Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures”, which expands reportable segment disclosure requirements on an annual and interim basis, primarily through enhanced disclosures about significant segment expenses. This ASU is effective for annual reporting periods beginning after December 15, 2023 and interim periods within fiscal years beginning after December 15, 2024, with early adoption permitted. The Company is currently evaluating the impact of this standard on Barnwell’s consolidated financial statements but does not expect that the adoption of this update will have a material impact on Barnwell's consolidated financial statements. In December 2023, the FASB issued ASU No. 2023-09 “Income Taxes (Topic 740): Improvements to Income Tax Disclosures”, which requires disclosure of incremental income tax information within the tax rate reconciliation and expanded disclosures of income taxes paid both in the U.S. and foreign jurisdiction, among other disclosure requirements. This ASU is effective for annual reporting periods beginning after December 15, 2024, with early adoption permitted. The Company is currently evaluating the impact of this standard on Barnwell’s consolidated financial statements . In November 2024, the FASB issued ASU No. 2024-03 “Income Statement - Reporting Comprehensive Income - Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of 49 Income Statement Expenses”, which requires public companies to disclose specified information about certain costs and expenses in the notes to the financial statements at interim and annual reporting periods. This ASU is effective for annual reporting periods beginning after December 15, 2026 and interim reporting periods beginning after December 15, 2027, with early adoption permitted. The Company is currently evaluating the impact of this standard on Barnwell’s consolidated financial statements. Liquidity and Capital Resources At September 30, 2024, Barnwell had $1,071,000 in working capital. Barnwell’s primary sources of liquidity are cash on hand and cash flow generated by our oil and natural gas operations, as cash flow from our land investment segment, if any, is expected to be minimal. In recent years, the Company generated a significant amount of cash inflows from its land investment segment, however, the last lots at Increment I were sold in the quarter ended March 31, 2024 and there are no more lots available for sale in Increment I. In addition, no definitive development plans have been made by the developer of Increment II as of the date of this report and thus future cash inflows from the land investment segment are uncertain. Management estimates that cash flows from the sale of the contract drilling segment business or its operating assets may also provide some level of liquidity in the near-term. The Company will primarily be reliant upon sufficient operating cash inflows from its oil and natural gas segment, which in turn will be largely determined by prices and production levels. A certain level of oil and natural gas capital expenditures will be necessary to grow reserves and production or at a minimum replace declining production from aging wells. Such a level of oil and natural gas capital expenditures may require funding from external debt or equity sources that are not currently in place. Management estimates that, barring any significant unforeseen events, it is more likely than not that there is sufficient cash on hand, cash flows from contract drilling segment asset sales and cash flows from oil and natural gas segment operations to continue as a going concern for the twelve months from the filing of this report. However, the aforementioned factors will influence the Company’s liquidity beyond that twelve month period. Cash Flows Cash flows provided by operating activities totaled $4,710,000 for fiscal 2024, as compared to cash flows provided by operating activities of $1,943,000 for fiscal 2023. This $2,767,000 change in operating cash flows was due to fluctuations in working capital in the current year period as compared to the prior year period. The adjustment in operating cash flows due to the effect of changes in current assets and liabilities was an increase of $2,780,000 in the current year period as compared to a decrease of $393,000 in the prior year period. The change was also due to an increase in distributions of income from the Kukio Resort Land Development Partnerships and a decrease in general and administrative costs in the current year period as compared to the prior year period, partially offset by lower operating results for the oil and natural gas and contract drilling segments in the current year period as compared to the same period in the prior year. Cash flows used in investing activities totaled $2,832,000 for fiscal 2024, as compared to cash flows used in investing activities of $11,180,000 for fiscal 2023. This $8,348,000 change in investing cash flows was primarily due to a decrease of $7,790,000 in cash paid for investments in oil and natural gas properties in the current year period as compared to the same period in the prior year and a $441,000 increase in proceeds from the sale of oil and natural gas properties in the current year period as compared to the prior year period. 50 Cash flows used in financing activities totaled $226,000 for fiscal 2024, as compared to cash flows used in financing activities of $786,000 for fiscal 2023. The $560,000 change in financing cash flows was due to a decrease of $599,000 in payment of dividends, partially offset by an increase of $69,000 in distributions to non-controlling interests in the current year period as compared to the same period in the prior year. 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 Oil and Natural Gas Capital Expenditures Barnwell’s oil and natural gas capital expenditures, including accrued capital expenditures and acquisitions of oil and natural gas properties and excluding additions and revisions to estimated asset retirement obligations, decreased $5,924,000 from $10,729,000 in fiscal 2023 to $4,805,000 in fiscal 2024. During the year ended September 30, 2024, the Company participated in the drilling of one gross (1.0 net) operated development oil well in the Twining area. Capital expenditures incurred for the drilling of this well during the year ended September 30, 2024 totaled approximately $3,183,000. In fiscal 2023, the Company participated in the drilling of three gross (0.9 net) non-operated wells in the Twining area of Alberta, Canada. Capital expenditures incurred for the drilling of these wells and Twining facilities during the year ended September 30, 2023 totaled approximately $4,770,000. Additionally, the Company participated in the drilling of two gross (0.3 net) non-operated development oil wells in Texas. Capital expenditures incurred for the drilling of these two wells totaled approximately $4,293,00 during the year ended September 30, 2023. 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 natural gas and oil 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. In July 2024, Barnwell entered into and completed an agreement with an independent third party to convey interests in certain natural gas and oil 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 51 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 natural gas and oil 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. Asset Retirement Obligation 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. 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. 52 Contractual Obligations Disclosure is not required as Barnwell qualifies as a smaller reporting company. Contingencies For a detailed discussion of contingencies, see Note 17 in the “Notes to Consolidated Financial Statements” in Item 8 of this report. ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Disclosure is not required as Barnwell qualifies as a smaller reporting company. 53