Barnwell Industries (BRN) 10-K 16 Dec 24 2024 FY Annual report Financial data

Cover Page

Cover Page - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2024	Dec. 13, 2024	Mar. 31, 2024
Cover [Abstract]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Sep. 30, 2024
Current Fiscal Year End Date	--09-30
Document Transition Report	false
Entity File Number	1-5103
Entity Registrant Name	BARNWELL INDUSTRIES, INC.
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	72-0496921
Entity Address, Address Line One	1100 Alakea Street
Entity Address, Address Line Two	Suite 500
Entity Address, City or Town	Honolulu
Entity Address, State or Province	HI
Entity Address, Postal Zip Code	96813-2840
City Area Code	808
Local Phone Number	531-8400
Title of 12(b) Security	Common Stock, $0.50 par value
Trading Symbol	BRN
Security Exchange Name	NYSEAMER
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Non-accelerated Filer
Entity Small Business	true
Entity Emerging Growth Company	false
ICFR Auditor Attestation Flag	false
Document Financial Statement Error Correction [Flag]	false
Entity Shell Company	false
Entity Public Float			$ 8,474
Entity Common Stock, Shares Outstanding		10,053,534
Documents Incorporated by Reference	Proxy statement, to be forwarded to stockholders on or about January 10, 2025, is incorporated by reference in Part III hereof.
Entity Central Index Key	0000010048
Amendment Flag	false
Document Fiscal Year Focus	2024
Document Fiscal Period Focus	FY

Audit Information

Audit Information	12 Months Ended
	Sep. 30, 2024
Auditor Information [Abstract]
Auditor Name	WEAVER AND TIDWELL, L.L.P.
Auditor Location	Little Falls, New Jersey
Auditor Firm ID	410

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Sep. 30, 2024	Sep. 30, 2023
Current assets:
Cash and cash equivalents	$ 4,505	$ 2,830
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	3,246
Assets held for sale	69	0
Other current assets	1,539	3,009
Total current assets	8,883	9,085
Asset for retirement benefits	4,899	4,471
Operating lease right-of-use assets	39	54
Property and equipment:
Proved oil and natural gas properties, net (full cost method)	16,554	21,302
Drilling rigs and other property and equipment, net	294	509
Total Net Property and Equipment	16,848	21,811
Total assets	30,669	35,421
Current liabilities:
Accounts payable	1,822	881
Accrued capital expenditures	2,407	1,099
Accrued compensation	650	726
Accrued operating and other expenses	1,834	1,747
Current portion of asset retirement obligation	798	1,536
Other current liabilities	301	609
Total current liabilities	7,812	6,598
Operating lease liabilities	7	47
Liability for retirement benefits	1,898	1,664
Asset retirement obligation	7,790	8,297
Deferred income tax liabilities	100	58
Total liabilities	17,607	16,664
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	5,079
Additional paid-in capital	7,690	7,687
Retained earnings	595	6,160
Accumulated other comprehensive income, net	1,943	2,104
Treasury stock, at cost: 167,900 shares at September 30, 2024 and 2023	(2,286)	(2,286)
Total stockholders’ equity	13,040	18,744
Non-controlling interests	22	13
Total equity	13,062	18,757
Total liabilities and equity	$ 30,669	$ 35,421

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	Sep. 30, 2024	Sep. 30, 2023
Statement of Financial Position [Abstract]
Accounts receivable, allowance for credit losses	$ 375	$ 284
Common stock, par value (in dollars per share)	$ 0.50
Common stock, authorized shares (in shares)	40,000,000
Common stock, issued shares (in shares)	10,195,990	10,158,678
Treasury stock, shares (in shares)	167,900	167,900

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2024	Sep. 30, 2023
Revenues:
Revenues	$ 21,724	$ 25,269
Costs and expenses:
General and administrative	5,598	6,956
Depletion, depreciation, and amortization	5,106	4,457
Impairment of assets	2,885	0
Foreign currency gain	(10)	(76)
Interest expense	2	2
Gain on sale of assets	0	(551)
Total costs and expenses	27,913	26,891
Loss before equity in income of affiliates and income taxes	(6,189)	(1,622)
Equity in income of affiliates	1,071	758
Loss before income taxes	(5,118)	(864)
Income tax provision (benefit)	213	(53)
Net loss	(5,331)	(811)
Less: Net earnings attributable to non-controlling interests	234	150
Net loss attributable to Barnwell Industries, Inc. stockholders	$ (5,565)	$ (961)
Basic net loss per common share attributable to Barnwell Industries, Inc. stockholders (in dollars per share)	$ (0.56)	$ (0.10)
Diluted net loss per common share attributable to Barnwell Industries, Inc. stockholders (in dollars per share)	$ (0.56)	$ (0.10)
Weighted-average number of common shares outstanding:
Basic (in shares)	10,017,997	9,969,856
Diluted (in shares)	10,017,997	9,969,856
Oil and natural gas
Revenues:
Revenues	$ 17,396	$ 19,376
Costs and expenses:
Costs and expenses	9,849	10,434
Depletion, depreciation, and amortization	4,947	4,269
Impairment of assets	2,885	0
Contract drilling
Revenues:
Revenues	3,612	5,427
Costs and expenses:
Costs and expenses	4,483	5,669
Depletion, depreciation, and amortization	156	186
Sale of interest in leasehold land
Revenues:
Revenues	500	265
Gas processing and other
Revenues:
Revenues	216	201
Costs and expenses:
Depletion, depreciation, and amortization	$ 3	$ 2

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2024	Sep. 30, 2023
Statement of Comprehensive Income [Abstract]
Net loss	$ (5,331)	$ (811)
Other comprehensive (loss) income:
Foreign currency translation adjustments, net of taxes of $0	0	(2)
Retirement plans:
Amortization of accumulated other comprehensive gain into net periodic benefit cost, net of taxes of $0	(85)	(79)
Net actuarial (loss) gain arising during the period, net of taxes of $0	(76)	891
Total other comprehensive (loss) income	(161)	810
Total comprehensive loss	(5,492)	(1)
Less: Comprehensive income attributable to non-controlling interests	(234)	(150)
Comprehensive loss attributable to Barnwell Industries, Inc.	$ (5,726)	$ (151)

CONSOLIDATED STATEMENTS OF CO_2

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2024	Sep. 30, 2023
Statement of Comprehensive Income [Abstract]
Foreign currency translation adjustments, taxes	$ 0	$ 0
Amortization of accumulated other comprehensive gain into net periodic benefit cost, taxes	0	0
Net actuarial (loss) gain arising during the period, taxes	$ 0	$ 0

CONSOLIDATED STATEMENTS OF EQUI

CONSOLIDATED STATEMENTS OF EQUITY - USD ($) $ in Thousands	Total	Common Stock	Additional Paid-In Capital	Retained Earnings	Accumulated Other Comprehensive Income	Treasury Stock	Non-controlling Interests
Balance (in shares) at Sep. 30, 2022		9,956,687
Balance at Sep. 30, 2022	$ 19,161	$ 5,062	$ 7,351	$ 7,720	$ 1,294	$ (2,286)	$ 20
Increase (Decrease) in Stockholders' Equity
Net (loss) earnings	(811)			(961)			150
Foreign currency translation adjustments, net of taxes of $0	(2)				(2)
Distributions to non-controlling interests	(157)						(157)
Share-based compensation	263		263
Dividends declared, cash paid per share	(599)			(599)
Issuance of common stock for services (in shares)		34,091
Issuance of common stock for services	90	$ 17	73
Retirement plans:
Amortization of accumulated other comprehensive gain into net periodic benefit cost, net of taxes of $0	(79)				(79)
Net actuarial (loss) gain arising during the period, net of taxes of $0	891				891
Balance (in shares) at Sep. 30, 2023		9,990,778
Balance at Sep. 30, 2023	18,757	$ 5,079	7,687	6,160	2,104	(2,286)	13
Increase (Decrease) in Stockholders' Equity
Net (loss) earnings	(5,331)			(5,565)			234
Foreign currency translation adjustments, net of taxes of $0	0
Distributions to non-controlling interests	(226)						(226)
Acquisition of non-controlling interest	(185)		(186)				1
Share-based compensation	208		208
Issuance of common stock for restricted stock units vested (in shares)		37,312
Issuance of common stock for restricted stock units vested	0	$ 19	(19)
Retirement plans:
Amortization of accumulated other comprehensive gain into net periodic benefit cost, net of taxes of $0	(85)				(85)
Net actuarial (loss) gain arising during the period, net of taxes of $0	(76)				(76)
Balance (in shares) at Sep. 30, 2024		10,028,090
Balance at Sep. 30, 2024	$ 13,062	$ 5,098	$ 7,690	$ 595	$ 1,943	$ (2,286)	$ 22

CONSOLIDATED STATEMENTS OF EQ_2

CONSOLIDATED STATEMENTS OF EQUITY (Parenthetical) - USD ($) $ in Thousands	3 Months Ended				12 Months Ended
	Sep. 30, 2023	Jun. 30, 2023	Mar. 31, 2023	Dec. 31, 2022	Sep. 30, 2024	Sep. 30, 2023
Statement of Stockholders' Equity [Abstract]
Foreign currency translation adjustments, taxes					$ 0	$ 0
Dividends declared, cash paid per share	$ 0.015	$ 0.015	$ 0.015	$ 0.015	$ 0	$ 0.060
Amortization of accumulated other comprehensive gain into net periodic benefit cost, taxes					$ 0	$ 0
Net actuarial (loss) gain arising during the period, taxes					$ 0	$ 0

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2024	Sep. 30, 2023
Cash flows from operating activities:
Net loss	$ (5,331)	$ (811)
Adjustments to reconcile net loss to net cash provided by operating activities:
Equity in income of affiliates	(1,071)	(758)
Depletion, depreciation, and amortization	5,106	4,457
Impairment of assets	2,885	0
Gain on sale of assets	0	(551)
Sale of interest in leasehold land, net of fees paid	(439)	(233)
Distributions of income from equity investees	1,071	539
Retirement benefits income	(345)	(252)
Accretion of asset retirement obligation	900	808
Deferred income tax expense (benefit)	42	(130)
Asset retirement obligation payments	(1,139)	(1,005)
Share-based compensation expense	208	263
Common stock issued for services	0	90
Non-cash rent income	(28)	(25)
Retirement plan contributions and payments	(4)	(3)
Credit loss expense	85	38
Foreign currency gain	(10)	(76)
Gain on debt extinguishment	0	(15)
Increase (decrease) from changes in current assets and liabilities	2,780	(393)
Net cash provided by operating activities	4,710	1,943
Cash flows from investing activities:
Acquisition of non-controlling interest	(185)	0
Distributions from equity investees in excess of earnings	0	219
Proceeds from sale of interest in leasehold land, net of fees paid	439	233
Proceeds from the sale of oil and natural gas assets	441	0
Capital expenditures - oil and natural gas	(3,514)	(11,304)
Capital expenditures - all other	(13)	(328)
Net cash used in investing activities	(2,832)	(11,180)
Cash flows from financing activities:
Repayment of long-term debt	0	(30)
Distributions to non-controlling interests	(226)	(157)
Payment of dividends	0	(599)
Net cash used in financing activities	(226)	(786)
Effect of exchange rate changes on cash and cash equivalents	23	49
Net increase (decrease) in cash and cash equivalents	1,675	(9,974)
Cash and cash equivalents at beginning of year	2,830	12,804
Cash and cash equivalents at end of year	$ 4,505	$ 2,830

SUMMARY OF SIGNIFICANT ACCOUNTI

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	12 Months Ended
	Sep. 30, 2024
Organization, Consolidation and Presentation of Financial Statements [Abstract]
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	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. 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 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. 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. 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 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 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. 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 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. 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

LOSS PER COMMON SHARE

LOSS PER COMMON SHARE	12 Months Ended
	Sep. 30, 2024
Earnings Per Share [Abstract]
LOSS PER COMMON SHARE	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. 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)

ALLOWANCE FOR CREDIT LOSSES

ALLOWANCE FOR CREDIT LOSSES	12 Months Ended
	Sep. 30, 2024
Allowance for Credit Loss [Abstract]
ALLOWANCE FOR CREDIT LOSSES	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

INVESTMENTS

INVESTMENTS	12 Months Ended
	Sep. 30, 2024
Investments, All Other Investments [Abstract]
INVESTMENTS	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. 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 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 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.

CONSOLIDATED VARIABLE INTEREST

CONSOLIDATED VARIABLE INTEREST ENTITY	12 Months Ended
	Sep. 30, 2024
Variable Interest Entity, Primary Beneficiary, Does Not Hold Majority Voting Interest, Disclosures [Abstract]
CONSOLIDATED VARIABLE INTEREST ENTITY	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.

ASSETS HELD FOR SALE

ASSETS HELD FOR SALE	12 Months Ended
	Sep. 30, 2024
Property, Plant and Equipment Assets Held-for-Sale Disclosure [Abstract]
ASSETS HELD FOR SALE	ASSETS HELD FOR SALE Contract Drilling Segment Property and Equipment

OIL AND NATURAL GAS PROPERTIES

OIL AND NATURAL GAS PROPERTIES	12 Months Ended
	Sep. 30, 2024
Oil and Natural Gas Properties [Abstract]
OIL AND NATURAL GAS PROPERTIES	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. 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.

PROPERTY AND EQUIPMENT AND ASSE

PROPERTY AND EQUIPMENT AND ASSET RETIREMENT OBLIGATION	12 Months Ended
	Sep. 30, 2024
PROPERTY AND EQUIPMENT AND ASSET RETIREMENT OBLIGATION
PROPERTY AND EQUIPMENT AND ASSET RETIREMENT OBLIGATION	PROPERTY AND EQUIPMENT AND ASSET RETIREMENT OBLIGATION Barnwell’s property and equipment is detailed as follows: Estimated Gross Accumulated Net At September 30, 2024: Proved oil and natural gas properties $ 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 Gross Accumulated Net At September 30, 2023: Proved oil and natural gas properties $ 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. 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. 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.

RETIREMENT PLANS

RETIREMENT PLANS	12 Months Ended
	Sep. 30, 2024
Retirement Benefits [Abstract]
RETIREMENT PLANS	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) 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. 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 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. 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 Quoted Significant Significant 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 Quoted Significant Significant 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 $ —

INCOME TAXES

INCOME TAXES	12 Months Ended
	Sep. 30, 2024
Income Tax Disclosure [Abstract]
INCOME TAXES	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. 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. 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) 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. 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

REVENUE FROM CONTRACTS WITH CUS

REVENUE FROM CONTRACTS WITH CUSTOMERS	12 Months Ended
	Sep. 30, 2024
Revenue from Contract with Customer [Abstract]
REVENUE FROM CONTRACTS WITH CUSTOMERS	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 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. 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.

SEGMENT AND GEOGRAPHIC INFORMAT

SEGMENT AND GEOGRAPHIC INFORMATION	12 Months Ended
	Sep. 30, 2024
Segment Reporting [Abstract]
SEGMENT AND GEOGRAPHIC INFORMATION	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) 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

ACCUMULATED OTHER COMPREHENSIVE

ACCUMULATED OTHER COMPREHENSIVE INCOME	12 Months Ended
	Sep. 30, 2024
Equity [Abstract]
ACCUMULATED OTHER COMPREHENSIVE INCOME	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).

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS	12 Months Ended
	Sep. 30, 2024
Fair Value Disclosures [Abstract]
FAIR VALUE MEASUREMENTS	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 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.

LEASES

LEASES	12 Months Ended
	Sep. 30, 2024
Leases [Abstract]
LEASES	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 . 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.

STOCKHOLDERS' EQUITY

STOCKHOLDERS' EQUITY	12 Months Ended
	Sep. 30, 2024
Equity [Abstract]
STOCKHOLDERS' EQUITY	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 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. The following table summarizes Barnwell’s equity-classified stock options activity from October 1, 2023 through September 30, 2024: Options Shares Weighted- Weighted- Aggregate 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. The following table summarizes Barnwell’s restricted stock units activity from October 1, 2023 through September 30, 2024: Restricted Stock Units Shares Weighted-Average 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

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	12 Months Ended
	Sep. 30, 2024
Commitments and Contingencies Disclosure [Abstract]
COMMITMENTS AND CONTINGENCIES	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. 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.

INFORMATION RELATING TO THE CON

INFORMATION RELATING TO THE CONSOLIDATED STATEMENTS OF CASH FLOWS	12 Months Ended
	Sep. 30, 2024
Supplemental Cash Flow Elements [Abstract]
INFORMATION RELATING TO THE CONSOLIDATED STATEMENTS OF CASH FLOWS	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

RELATED PARTY TRANSACTIONS

RELATED PARTY TRANSACTIONS	12 Months Ended
	Sep. 30, 2024
Related Party Transactions [Abstract]
RELATED PARTY TRANSACTIONS	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.

SUBSEQUENT EVENTS

SUBSEQUENT EVENTS	12 Months Ended
	Sep. 30, 2024
Subsequent Events [Abstract]
SUBSEQUENT EVENTS	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.

SUMMARY OF SELECTED QUARTERLY F

SUMMARY OF SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)	12 Months Ended
	Sep. 30, 2024
Quarterly Financial Information Disclosure [Abstract]
SUMMARY OF SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)	SUMMARY OF SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED) Disclosure is not required as Barnwell qualifies as a smaller reporting company.

SUPPLEMENTARY OIL AND NATURAL G

SUPPLEMENTARY OIL AND NATURAL GAS INFORMATION (UNAUDITED)	12 Months Ended
	Sep. 30, 2024
Oil and Gas Disclosure [Abstract]
SUPPLEMENTARY OIL AND NATURAL GAS INFORMATION (UNAUDITED)	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 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 NGL 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 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 Total Equivalent Reserves 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 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 NGL 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 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 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 (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 (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. 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 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

Pay vs Performance Disclosure

Pay vs Performance Disclosure - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2024	Sep. 30, 2023
Pay vs Performance Disclosure
Net Income (Loss) Attributable to Parent	$ (5,565)	$ (961)

Insider Trading Arrangements

Insider Trading Arrangements	3 Months Ended
	Sep. 30, 2024
Trading Arrangements, by Individual
Rule 10b5-1 Arrangement Adopted	false
Non-Rule 10b5-1 Arrangement Adopted	false
Rule 10b5-1 Arrangement Terminated	false
Non-Rule 10b5-1 Arrangement Terminated	false

Insider Trading Policies and Pr

Insider Trading Policies and Procedures	12 Months Ended
	Sep. 30, 2024
Insider Trading Policies and Procedures [Line Items]
Insider Trading Policies and Procedures Adopted	true

SUMMARY OF SIGNIFICANT ACCOUN_2

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	12 Months Ended
	Sep. 30, 2024
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Principles of Consolidation	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.
Use of Estimates in the Preparation of Financial Statements	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	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. 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 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 Cash and cash equivalents include cash on hand and short-term investments with original maturities of three months or less.
Concentration of Credit Risk	Concentration of Credit Risk
Accounts and Other Receivables	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.
Investments in Real Estate	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	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
Oil and Natural Gas Properties	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 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	Acquisitions
Long-lived Assets	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.
Share-based Compensation	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	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 on assets assumption would increase (decrease) pension expense by approximately $64,000 based on the assets of the plan at September 30, 2024.
Asset Retirement Obligation	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 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. Our operations in Texas are subject to a franchise tax assessed by the state of Texas which is presented as income tax expense.
Environmental	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.
Derivative Instruments	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	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.
Fair Value Measurements	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	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.

LOSS PER COMMON SHARE (Tables)

LOSS PER COMMON SHARE (Tables)	12 Months Ended
	Sep. 30, 2024
Earnings Per Share [Abstract]
Reconciliations between net (loss) earnings attributable to stockholders and common shares outstanding of the basic and diluted net (loss) earnings per share computations	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)

ALLOWANCE FOR CREDIT LOSSES (Ta

ALLOWANCE FOR CREDIT LOSSES (Tables)	12 Months Ended
	Sep. 30, 2024
Allowance for Credit Loss [Abstract]
Summary of the activity in the 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

INVESTMENTS (Tables)

INVESTMENTS (Tables)	12 Months Ended
	Sep. 30, 2024
Investments, All Other Investments [Abstract]
Summarized financial information for the land development partnerships	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
Summary of Increment I and Increment II percentage of sales payment revenues received	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

PROPERTY AND EQUIPMENT AND AS_2

PROPERTY AND EQUIPMENT AND ASSET RETIREMENT OBLIGATION (Tables)	12 Months Ended
	Sep. 30, 2024
PROPERTY AND EQUIPMENT AND ASSET RETIREMENT OBLIGATION
Schedule of property and equipment	Barnwell’s property and equipment is detailed as follows: Estimated Gross Accumulated Net At September 30, 2024: Proved oil and natural gas properties $ 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 Gross Accumulated Net At September 30, 2023: Proved oil and natural gas properties $ 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
Schedule of reconciliation of the asset retirement obligation	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

RETIREMENT PLANS (Tables)

RETIREMENT PLANS (Tables)	12 Months Ended
	Sep. 30, 2024
Retirement Benefits [Abstract]
Schedule of changes in benefit obligations, fair values of plan assets and reconciliations of the funded status of the retirement plans	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)
Schedule of amounts recognized in the consolidated balance sheets	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)
Schedule of amounts recognized in accumulated other comprehensive (loss) income	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)
Schedule of weighted-average assumptions used to determine benefit obligations and net periodic benefit (income) costs	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
Schedule of components of net periodic benefit (income) cost	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
Schedule of benefits expected to be paid under the retirement plans	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
Schedule of year-end target allocation, by asset category, and the actual asset allocations	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% —%
Schedule of pension plan assets at fair value	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 Quoted Significant Significant 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 Quoted Significant Significant 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 $ — $ —
Summary of changes in the fair value of the pension plan Level 3 asset	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 $ —

INCOME TAXES (Tables)

INCOME TAXES (Tables)	12 Months Ended
	Sep. 30, 2024
Income Tax Disclosure [Abstract]
Components of income (loss) before income taxes, after adjusting the income (loss) for non-controlling interests	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)
Schedule of components of the income tax provision (benefit)	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)
Summary of reconciliation between the reported income tax expense (benefit) and the amount computed by multiplying the earnings (loss) by the U.S. federal tax rate	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)
Schedule of tax effects of temporary differences that give rise to significant portions of the deferred tax assets and liabilities	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)
Schedule of unrecognized tax benefits	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
Summary of tax years, by jurisdiction, that remain subject to examination by taxing authorities	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

REVENUE FROM CONTRACTS WITH C_2

REVENUE FROM CONTRACTS WITH CUSTOMERS (Tables)	12 Months Ended
	Sep. 30, 2024
Revenue from Contract with Customer [Abstract]
Summary of 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
Summary of contract with customer, asset and liability	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

SEGMENT AND GEOGRAPHIC INFORM_2

SEGMENT AND GEOGRAPHIC INFORMATION (Tables)	12 Months Ended
	Sep. 30, 2024
Segment Reporting [Abstract]
Schedule of financial information related to reporting segments	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) 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.
Schedule of long-lived assets and revenue by geographic area	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

ACCUMULATED OTHER COMPREHENSI_2

ACCUMULATED OTHER COMPREHENSIVE INCOME (Tables)	12 Months Ended
	Sep. 30, 2024
Equity [Abstract]
Schedule of components of accumulated other comprehensive (loss) income, net of taxes	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

LEASES (Tables)

LEASES (Tables)	12 Months Ended
	Sep. 30, 2024
Leases [Abstract]
Lease asset and liabilities	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 .
Lease costs	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 lease information	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%
Operating lease maturity schedule	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

STOCKHOLDERS' EQUITY (Tables)

STOCKHOLDERS' EQUITY (Tables)	12 Months Ended
	Sep. 30, 2024
Share-based compensation
Summary of the activity in share options	The following table summarizes Barnwell’s equity-classified stock options activity from October 1, 2023 through September 30, 2024: Options Shares Weighted- Weighted- Aggregate 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 $ —
Summary of the activity in restricted stock units	The following table summarizes Barnwell’s restricted stock units activity from October 1, 2023 through September 30, 2024: Restricted Stock Units Shares Weighted-Average 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)
Summary of cash dividends paid per share of common stock	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
Equity-classified share options
Share-based compensation
Schedule of assumptions used in estimating fair value	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

INFORMATION RELATING TO THE C_2

INFORMATION RELATING TO THE CONSOLIDATED STATEMENTS OF CASH FLOWS (Tables)	12 Months Ended
	Sep. 30, 2024
Supplemental Cash Flow Elements [Abstract]
Schedule of supplemental cash flow information	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

SUPPLEMENTARY OIL AND NATURAL_2

SUPPLEMENTARY OIL AND NATURAL GAS INFORMATION (UNAUDITED) (Tables)	12 Months Ended
	Sep. 30, 2024
Oil and Gas Disclosure [Abstract]
Summary of changes in the estimates of net interests in total proved developed and total proved undeveloped reserves of oil, natural gas liquids and natural gas	Oil 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 NGL 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 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 Total Equivalent Reserves 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 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 NGL 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 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 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
Schedule of 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
Schedule of 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
Schedule of 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.
Schedule of 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
Schedule of changes in 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

SUMMARY OF SIGNIFICANT ACCOUN_3

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) $ in Thousands	12 Months Ended
	Sep. 30, 2024 USD ($) segment
Principles of Consolidation
Number of operating segments | segment	3
Retirement Plans
Increase (decrease) pension expense | $	$ 64
Measurement input, discount rate
Oil and Natural Gas Properties
Discount rate	0.10
Minimum
Equity Method Investments
Ownership interest in affiliated companies required to account for investments under equity method investments (more than)	3%
Maximum
Equity Method Investments
Ownership interest in affiliated companies required to account for investments under equity method investments (more than)	5%
Retirement Plans
Decrease (increase) in the expected return on plan assets assumption	0.50%
Kaupulehu Developments
Principles of Consolidation
Ownership interest in subsidiaries	77.60%
KD Kona 2013 LLLP
Principles of Consolidation
Ownership interest in subsidiaries	75%

LOSS PER COMMON SHARE - NARRATI

LOSS PER COMMON SHARE - NARRATIVE (Details) - shares	12 Months Ended
	Sep. 30, 2024	Sep. 30, 2023
Options
Antidilutive shares excluded from the computation of diluted shares
Antidilutive shares excluded from computation of loss per share (in shares)	465,000	546,781
Restricted Stock Units (RSUs)
Antidilutive shares excluded from the computation of diluted shares
Antidilutive shares excluded from computation of loss per share (in shares)	98,795	18,605

LOSS PER COMMON SHARE - RECONCI

LOSS PER COMMON SHARE - RECONCILIATIONS BETWEEN NET LOSS ATTRIBUTABLE TO STOCKHOLDERS AND COMMON SHARES OUTSTANDING (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Sep. 30, 2024	Sep. 30, 2023
Net Loss (Numerator)
Basic	$ (5,565)	$ (961)
Effect of dilutive securities - common stock options and restricted stock units	0	0
Diluted	$ (5,565)	$ (961)
Shares (Denominator)
Basic (in shares)	10,017,997	9,969,856
Effect of dilutive securities - common stock options and restricted stock units (in shares)	0	0
Diluted (in shares)	10,017,997	9,969,856
Per-Share Amount
Basic net loss per common share attributable to Barnwell Industries, Inc. stockholders (in dollars per share)	$ (0.56)	$ (0.10)
Diluted net loss per common share attributable to Barnwell Industries, Inc. stockholders (in dollars per share)	$ (0.56)	$ (0.10)

ALLOWANCE FOR CREDIT LOSSES (De

ALLOWANCE FOR CREDIT LOSSES (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2024	Sep. 30, 2023
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Allowance for credit losses as of beginning of year	$ 284	$ 231
Provision for expected losses	85	38
Write-offs charged against the allowance	(10)	(20)
Recoveries of amounts previously written off	16	34
Foreign currency translation adjustment	0	1
Allowance for credit losses as of end of year	$ 375	$ 284

INVESTMENTS - INVESTMENT IN KUK

INVESTMENTS - INVESTMENT IN KUKIO RESORT LAND DEVELOPMENT PARTNERSHIPS (Details) $ in Thousands		3 Months Ended	12 Months Ended
	Nov. 27, 2013 USD ($) partnership	Mar. 31, 2024 lot	Sep. 30, 2024 USD ($) lot	Sep. 30, 2023 USD ($)	Jun. 30, 2021 USD ($)	Mar. 07, 2019
Investment Holdings [Line Items]
Number of limited liability limited partnerships formed | partnership	2
Cash distribution from equity method investment, gross			$ 1,071	$ 758
Cash distribution from equity method investment, net			953	674
Equity in income of affiliates			1,071	758
Investment in Kukio Resort Land Development Partnerships					$ 0
Cumulative cash distributions from Kukio Resort Land Development Partnerships in excess of our investment balance			$ 373	708
KD Kukio Resorts LLLP
Investment Holdings [Line Items]
Ownership interest acquired	19.60%
KD Kaupulehu, LLLP
Investment Holdings [Line Items]
Ownership interest acquired	19.60%
KD Maniniowali, LLLP
Investment Holdings [Line Items]
Ownership interest acquired	19.60%
Indirectly Acquired Interest
Investment Holdings [Line Items]
Aggregate cost	$ 5,140
KD Acquisition, LLLP
Investment Holdings [Line Items]
Ownership interest acquired			19.60%
KD Kona 2013 LLLP
Investment Holdings [Line Items]
Ownership interest acquired	75%
KKM Makai LLLP
Investment Holdings [Line Items]
Ownership interest acquired	34.45%
KD Kaupulehu, LLLP | KD Acquisition II, LP
Investment Holdings [Line Items]
Ownership interest acquired						55%
Replay | KD Acquisition II, LP
Investment Holdings [Line Items]
Ownership interest acquired						45%
Barnwell Industries Inc | KD Acquisition II, LP
Investment Holdings [Line Items]
Ownership interest acquired			10.80%
Kaupulehu Developments | KD Kaupulehu LLLP Increment I
Investment Holdings [Line Items]
Number of single family lots sold | lot		2
Number of lots developed | lot			80
Non-controlling Interests
Investment Holdings [Line Items]
Cash distribution from equity method investment, net			$ 118	$ 84

INVESTMENTS - SUMMARIZED FINANC

INVESTMENTS - SUMMARIZED FINANCIAL INFORMATION (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2024	Sep. 30, 2023
Investment Holdings [Line Items]
Revenues	$ 21,724	$ 25,269
Net earnings	(5,331)	(811)
Investments in land development partnerships
Investment Holdings [Line Items]
Revenues	13,555	13,055
Gross Profit	8,651	7,733
Net earnings	$ 6,437	$ 4,436

INVESTMENTS - SALE OF INTEREST

INVESTMENTS - SALE OF INTEREST IN LEASEHOLD LAND (Details) $ in Thousands	3 Months Ended	12 Months Ended
	Mar. 31, 2024 lot	Sep. 30, 2024 lot	Mar. 07, 2019 USD ($) singleFamilyResidentialLot day
KD Kaupulehu LLLP Increment I | Kaupulehu Developments
Investment Holdings [Line Items]
Payments entitled to be received as percentage of gross proceeds from sale of single family lots		10%
Number of single family lots sold | lot	2
Number of lots developed | lot		80
KD Acquisition II, LP
Investment Holdings [Line Items]
Collaborative agreement, percentage of distributions			15%
Collaborative agreement, percentage of cumulative net profits, priority payment			10%
Collaborative agreement, percentage of cumulative net profits, priority payment, maximum amount | $			$ 3,000
KD Acquisition II, LP | KD Kaupulehu, LLLP
Investment Holdings [Line Items]
Ownership interest acquired			55%
KD Kaupulehu LLLP Increment II Phase 2A
Investment Holdings [Line Items]
Number of single family lots, rights to | singleFamilyResidentialLot			3
KD Kaupulehu LLLP Increment II Phase 2A, lots completed subsequent to Phase 2A
Investment Holdings [Line Items]
Number of single family lots, rights to | singleFamilyResidentialLot			4
Collaborative agreement, commitment to construct improvements term | day			90
KD Development, LLC
Investment Holdings [Line Items]
Collaborative agreement, fees, percentage of cumulative net profits			0.72%
Pool Of Various Individuals
Investment Holdings [Line Items]
Collaborative agreement, fees, percentage of cumulative net profits			0.20%

INVESTMENTS - SUMMARY OF REVENU

INVESTMENTS - SUMMARY OF REVENUES (Details) - Kaupulehu Developments - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2024	Sep. 30, 2023
Investment Holdings [Line Items]
Revenues - sale of interest in leasehold land	$ 500	$ 265
Fees - included in general and administrative expenses	(61)	(32)
Sale of interest in leasehold land, net of fees paid	$ 439	$ 233

INVESTMENTS - INVESTMENT IN LEA

INVESTMENTS - INVESTMENT IN LEASEHOLD LAND INTEREST - LOT 4C (Details) a in Thousands	Sep. 30, 2024 a
Investments, All Other Investments [Abstract]
Area of land (in acres)	1

CONSOLIDATED VARIABLE INTERES_2

CONSOLIDATED VARIABLE INTEREST ENTITY - NARRATIVE (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Jun. 30, 2024	Sep. 30, 2024	Sep. 30, 2023	Mar. 31, 2024
Variable Interest Entity [Line Items]
Percentage of capital contributions to variable interest entity				100%
Acquisition of non-controlling interest	$ 185	$ 185	$ 0
BOK Drilling, LLC
Variable Interest Entity [Line Items]
Ownership percentage of Teton Barnwell		100%
Gros Ventre Partners, LLC
Variable Interest Entity [Line Items]
Profit sharing ratio of variable interest entity	2%			2%
Asset management fee, percent fee of cumulative capital contributions				1%
BOK Drilling, LLC
Variable Interest Entity [Line Items]
Profit sharing ratio of variable interest entity				98%

OIL AND NATURAL GAS PROPERTIES

OIL AND NATURAL GAS PROPERTIES (Details) - USD ($) $ in Thousands	1 Months Ended			3 Months Ended	12 Months Ended
	Sep. 30, 2024	Jul. 31, 2024	Dec. 31, 2022	Jun. 30, 2024	Sep. 30, 2024	Sep. 30, 2023	Dec. 01, 2022
Oil and Natural Gas Properties [Line Items]
Proceeds from the sale of oil and natural gas assets					$ 441	$ 0
Costs incurred					4,048	11,430
Impairment of assets					2,885	0
United States
Oil and Natural Gas Properties [Line Items]
Costs incurred					183	5,099
Canada
Oil and Natural Gas Properties [Line Items]
Costs incurred					3,865	6,331
Oil and natural gas
Oil and Natural Gas Properties [Line Items]
Impairment of assets					2,885	0
Oil and natural gas | United States
Oil and Natural Gas Properties [Line Items]
Impairment of assets					721
Oil and natural gas | Canada
Oil and Natural Gas Properties [Line Items]
Impairment of assets					2,164
Barnwell Industries Inc | Kaybob, Alberta, Canada
Oil and Natural Gas Properties [Line Items]
Proceeds from the sale of oil and natural gas assets				$ 441
Barnwell Industries Inc | Bonanza and Balsam, Alberta, Canada
Oil and Natural Gas Properties [Line Items]
Overriding royalty percentage		4%
Amount of the full cost pool and abandonment liabilities reduced		$ 153
Barnwell Industries Inc | Wood River, Alberta, Canada
Oil and Natural Gas Properties [Line Items]
Proceeds from the sale of oil and natural gas assets	$ 292
Income taxes receivable	$ 38				$ 38
Barnwell Texas, LLC
Oil and Natural Gas Properties [Line Items]
Working interest in oil and gas leasehold acreage							22.30%
Cash paid to acquire working interest in oil and gas leasehold acreage			$ 806
Working interest in oil wells							15.40%
Costs incurred						$ 4,293

PROPERTY AND EQUIPMENT AND AS_3

PROPERTY AND EQUIPMENT AND ASSET RETIREMENT OBLIGATION - PROPERTY AND EQUIPMENT (Details) - USD ($) $ in Thousands	Sep. 30, 2024	Sep. 30, 2023
Property and equipment
Proved Properties, Net Property and Equipment	$ 16,554	$ 21,302
Net drilling rigs and other property and equipment	294	509
Total Gross Property and Equipment	87,236	88,074
Total Accumulated Depletion, Depreciation, Amortization, and Impairment	(70,388)	(66,263)
Total Net Property and Equipment	16,848	21,811
Oil and natural gas properties
Property and equipment
Proved Properties, Gross Property and Equipment	83,557	80,851
Proved Properties, Accumulated Depletion, Depreciation, Amortization, and Impairment	(67,003)	(59,549)
Proved Properties, Net Property and Equipment	16,554	21,302
Drilling rigs and equipment
Property and equipment
Gross Property and Equipment	3,103	6,618
Property, Plant and Equipment, Other, Accumulated Depletion, Depreciation, Amortization, And Impairment	(2,823)	(6,127)
Net drilling rigs and other property and equipment	$ 280	$ 491
Drilling rigs and equipment | Minimum
Property and equipment
Estimated useful lives	3 years	3 years
Drilling rigs and equipment | Maximum
Property and equipment
Estimated useful lives	10 years	10 years
Other property and equipment
Property and equipment
Gross Property and Equipment	$ 576	$ 605
Property, Plant and Equipment, Other, Accumulated Depletion, Depreciation, Amortization, And Impairment	(562)	(587)
Net drilling rigs and other property and equipment	$ 14	$ 18
Other property and equipment | Minimum
Property and equipment
Estimated useful lives	3 years	3 years
Other property and equipment | Maximum
Property and equipment
Estimated useful lives	10 years	10 years

PROPERTY AND EQUIPMENT AND AS_4

PROPERTY AND EQUIPMENT AND ASSET RETIREMENT OBLIGATION - ASSET RETIREMENT OBLIGATION (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2024	Sep. 30, 2023
Change in the asset retirement obligation
Balance at the beginning of the year	$ 9,833	$ 8,456
Obligations incurred on new wells drilled or acquired	37	21
Liabilities associated with properties sold	(442)	0
Revision of estimated obligation	(614)	1,462
Accretion expense	900	808
Payments	(1,139)	(1,005)
Foreign currency translation adjustment	13	91
Balance at the end of the year	8,588	9,833
Less current portion	(798)	(1,536)
Asset retirement obligation, long-term	$ 7,790	$ 8,297

PROPERTY AND EQUIPMENT AND AS_5

PROPERTY AND EQUIPMENT AND ASSET RETIREMENT OBLIGATION - NARRATIVE (Details) - USD ($) $ in Thousands	1 Months Ended		12 Months Ended
	Aug. 31, 2025	Jul. 31, 2021	Sep. 30, 2024	Sep. 30, 2023	Sep. 30, 2021
Property and equipment
Asset retirement obligation			$ 442	$ 0
Revision of estimated obligation			(614)	1,462
Obligations incurred on new wells drilled or acquired			37	$ 21
Abandonment and reclamation cost, cash deposit		$ 888			$ 1,525
Abandonment and reclamation cost, cumulative cash deposit reduction			$ (353)
Minimum
Property and equipment
Discount rate for ARO			6%
Maximum
Property and equipment
Discount rate for ARO			13.50%
Forecast
Property and equipment
Abandonment and reclamation cost, cash deposit	$ 637

RETIREMENT PLANS - NARRATIVE (D

RETIREMENT PLANS - NARRATIVE (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2024	Sep. 30, 2023
Defined Benefit Plan, Equity Securities, Micro Cap
Retirement plans
Market capitalization, percentage of equity securities	47%
Defined Benefit Plan, Equity Securities, Small Cap
Retirement plans
Market capitalization, percentage of equity securities	20%
Defined Benefit Plan, Equity Securities, Mid Cap
Retirement plans
Market capitalization, percentage of equity securities	15%
Defined Benefit Plan, Equity Securities, Large Cap
Retirement plans
Market capitalization, percentage of equity securities	18%
Pension Plan
Retirement plans
Period of employee's highest average earnings on which benefits are based	5 years
Accumulated benefit obligation	$ 8,195	$ 7,511
Expected future contributions	0
SERP
Retirement plans
Accumulated benefit obligation	1,974	$ 1,734
Expected future contributions	$ 76

RETIREMENT PLANS - CHANGES IN B

RETIREMENT PLANS - CHANGES IN BENEFIT OBLIGATIONS (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2024	Sep. 30, 2023
Change in Plan Assets:
Fair value of plan assets at beginning of year	$ 11,982
Fair value of plan assets at end of year	13,094	$ 11,982
Amounts recognized in the Consolidated Balance Sheets:
Noncurrent assets	4,899	4,471
Noncurrent liabilities	(1,898)	(1,664)
Pension Plan
Change in Projected Benefit Obligation:
Benefit obligation at beginning of year	7,511	7,931
Interest cost	411	406
Actuarial loss (gain)	520	(394)
Benefits paid	(247)	(432)
Benefit obligation at end of year	8,195	7,511
Change in Plan Assets:
Fair value of plan assets at beginning of year	11,982	11,316
Actual return on plan assets	1,359	1,098
Benefits paid	(247)	(432)
Fair value of plan assets at end of year	13,094	11,982
Funded status	4,899	4,471
Amounts recognized in the Consolidated Balance Sheets:
Noncurrent assets	4,899	4,471
Current liabilities	0	0
Noncurrent liabilities	0	0
Net amount	4,899	4,471
Amounts recognized in accumulated other comprehensive income before income taxes:
Net actuarial gain	(1,251)	(1,178)
Accumulated other comprehensive income	(1,251)	(1,178)
SERP
Change in Projected Benefit Obligation:
Benefit obligation at beginning of year	1,734	1,715
Interest cost	95	88
Actuarial loss (gain)	149	(66)
Benefits paid	(4)	(3)
Benefit obligation at end of year	1,974	1,734
Change in Plan Assets:
Fair value of plan assets at beginning of year	0	0
Actual return on plan assets	0	0
Benefits paid	0	0
Fair value of plan assets at end of year	0	0
Funded status	(1,974)	(1,734)
Amounts recognized in the Consolidated Balance Sheets:
Noncurrent assets	0	0
Current liabilities	(76)	(70)
Noncurrent liabilities	(1,898)	(1,664)
Net amount	(1,974)	(1,734)
Amounts recognized in accumulated other comprehensive income before income taxes:
Net actuarial gain	(96)	(330)
Accumulated other comprehensive income	$ (96)	$ (330)

RETIREMENT PLANS - WEIGHTED AVE

RETIREMENT PLANS - WEIGHTED AVERAGE BENEFIT OBLIGATIONS AND NET BENEFIT (INCOME) COST (Details)	12 Months Ended
	Sep. 30, 2024	Sep. 30, 2023
Pension Plan
Assumptions used to determine fiscal year-end benefit obligations:
Discount rate	4.88%	5.62%
Assumptions used to determine net benefit costs (years ended):
Discount rate	5.62%	5.25%
Expected return on plan assets	6.50%	6%
SERP
Assumptions used to determine fiscal year-end benefit obligations:
Discount rate	4.88%	5.62%
Assumptions used to determine net benefit costs (years ended):
Discount rate	5.62%	5.25%

RETIREMENT PLANS - NET PERIODIC

RETIREMENT PLANS - NET PERIODIC BENEFIT (INCOME) COST (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2024	Sep. 30, 2023
Pension Plan
Net periodic benefit (income) cost for the year:
Interest cost	$ 411	$ 406
Expected return on plan assets	(766)	(667)
Amortization of net actuarial gain	0	0
Net periodic benefit (income) cost	(355)	(261)
SERP
Net periodic benefit (income) cost for the year:
Interest cost	95	88
Expected return on plan assets	0	0
Amortization of net actuarial gain	(85)	(79)
Net periodic benefit (income) cost	$ 10	$ 9

RETIREMENT PLANS - EXPECTED BEN

RETIREMENT PLANS - EXPECTED BENEFIT PAYMENTS (Details) $ in Thousands	Sep. 30, 2024 USD ($)
Pension Plan
Expected Benefit Payments:
Fiscal year ending September 30, 2025	$ 396
Fiscal year ending September 30, 2026	562
Fiscal year ending September 30, 2027	555
Fiscal year ending September 30, 2028	593
Fiscal year ending September 30, 2029	630
Fiscal years ending September 30, 2030 through 2034	3,075
SERP
Expected Benefit Payments:
Fiscal year ending September 30, 2025	76
Fiscal year ending September 30, 2026	152
Fiscal year ending September 30, 2027	150
Fiscal year ending September 30, 2028	155
Fiscal year ending September 30, 2029	160
Fiscal years ending September 30, 2030 through 2034	$ 764

RETIREMENT PLANS - ASSET CATERG

RETIREMENT PLANS - ASSET CATERGORY ALLOCATION (Details)	Sep. 30, 2024	Sep. 30, 2023
Cash and cash equivalents
Entity's year-end target allocation, by asset category, and the actual asset allocations
Actual asset allocation	4%	2%
Fixed income securities
Entity's year-end target allocation, by asset category, and the actual asset allocations
Actual asset allocation	19%	32%
Equity securities
Entity's year-end target allocation, by asset category, and the actual asset allocations
Actual asset allocation	73%	66%
Other investment
Entity's year-end target allocation, by asset category, and the actual asset allocations
Actual asset allocation	4%	0%
Minimum | Cash and cash equivalents
Entity's year-end target allocation, by asset category, and the actual asset allocations
Target allocation	0%
Minimum | Fixed income securities
Entity's year-end target allocation, by asset category, and the actual asset allocations
Target allocation	15%
Minimum | Equity securities
Entity's year-end target allocation, by asset category, and the actual asset allocations
Target allocation	45%
Minimum | Other investment
Entity's year-end target allocation, by asset category, and the actual asset allocations
Target allocation	0%
Maximum | Cash and cash equivalents
Entity's year-end target allocation, by asset category, and the actual asset allocations
Target allocation	25%
Maximum | Fixed income securities
Entity's year-end target allocation, by asset category, and the actual asset allocations
Target allocation	40%
Maximum | Equity securities
Entity's year-end target allocation, by asset category, and the actual asset allocations
Target allocation	75%
Maximum | Other investment
Entity's year-end target allocation, by asset category, and the actual asset allocations
Target allocation	10%

RETIREMENT PLANS - FAIR VALUE (

RETIREMENT PLANS - FAIR VALUE (Details) - USD ($) $ in Thousands	Sep. 30, 2024	Sep. 30, 2023	Sep. 30, 2022
Pension plan assets at the fair value
Fair value measurements	$ 13,094	$ 11,982
Quoted Prices in Active Markets (Level 1)
Pension plan assets at the fair value
Fair value measurements	12,523	11,982
Significant Other Observable Inputs (Level 2)
Pension plan assets at the fair value
Fair value measurements	0	0
Significant Unobservable Inputs (Level 3)
Pension plan assets at the fair value
Fair value measurements	571	0	$ 0
Cash
Pension plan assets at the fair value
Fair value measurements	531	263
Cash | Quoted Prices in Active Markets (Level 1)
Pension plan assets at the fair value
Fair value measurements	531	263
Cash | Significant Other Observable Inputs (Level 2)
Pension plan assets at the fair value
Fair value measurements	0	0
Cash | Significant Unobservable Inputs (Level 3)
Pension plan assets at the fair value
Fair value measurements	0	0
U.S. treasury and government securities
Pension plan assets at the fair value
Fair value measurements	516	709
U.S. treasury and government securities | Quoted Prices in Active Markets (Level 1)
Pension plan assets at the fair value
Fair value measurements	516	709
U.S. treasury and government securities | Significant Other Observable Inputs (Level 2)
Pension plan assets at the fair value
Fair value measurements	0	0
U.S. treasury and government securities | Significant Unobservable Inputs (Level 3)
Pension plan assets at the fair value
Fair value measurements	0	0
Fixed income exchange-traded funds
Pension plan assets at the fair value
Fair value measurements	1,872	3,102
Fixed income exchange-traded funds | Quoted Prices in Active Markets (Level 1)
Pension plan assets at the fair value
Fair value measurements	1,872	3,102
Fixed income exchange-traded funds | Significant Other Observable Inputs (Level 2)
Pension plan assets at the fair value
Fair value measurements	0	0
Fixed income exchange-traded funds | Significant Unobservable Inputs (Level 3)
Pension plan assets at the fair value
Fair value measurements	0	0
Preferred securities
Pension plan assets at the fair value
Fair value measurements	88	47
Preferred securities | Quoted Prices in Active Markets (Level 1)
Pension plan assets at the fair value
Fair value measurements	88	47
Preferred securities | Significant Other Observable Inputs (Level 2)
Pension plan assets at the fair value
Fair value measurements	0	0
Preferred securities | Significant Unobservable Inputs (Level 3)
Pension plan assets at the fair value
Fair value measurements	0	0
Equities
Pension plan assets at the fair value
Fair value measurements	9,516	7,861
Equities | Quoted Prices in Active Markets (Level 1)
Pension plan assets at the fair value
Fair value measurements	9,516	7,861
Equities | Significant Other Observable Inputs (Level 2)
Pension plan assets at the fair value
Fair value measurements	0	0
Equities | Significant Unobservable Inputs (Level 3)
Pension plan assets at the fair value
Fair value measurements	0	$ 0
Note receivable from an unrelated private company
Pension plan assets at the fair value
Fair value measurements	571
Note receivable from an unrelated private company | Quoted Prices in Active Markets (Level 1)
Pension plan assets at the fair value
Fair value measurements	0
Note receivable from an unrelated private company | Significant Other Observable Inputs (Level 2)
Pension plan assets at the fair value
Fair value measurements	0
Note receivable from an unrelated private company | Significant Unobservable Inputs (Level 3)
Pension plan assets at the fair value
Fair value measurements	$ 571

RETIREMENT PLANS - FAIR VALUE L

RETIREMENT PLANS - FAIR VALUE LEVEL 3 (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2024	Sep. 30, 2023
Change in Plan Assets:
Fair value of plan assets at beginning of year	$ 11,982
Fair value of plan assets at end of year	13,094	$ 11,982
Significant Unobservable Inputs (Level 3)
Change in Plan Assets:
Fair value of plan assets at beginning of year	0	0
Issuance of note receivable from an unrelated private company	571	0
Fair value of plan assets at end of year	$ 571	$ 0

INCOME TAXES - COMPONENTS OF EA

INCOME TAXES - COMPONENTS OF EARNINGS (LOSS) BEFORE INCOME TAXES, AFTER ADJUSTING EARNINGS (LOSS) FOR NON-CONTROLLING INTERESTS (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2024	Sep. 30, 2023
Income Tax Disclosure [Abstract]
United States	$ (2,820)	$ (2,414)
Canada	(2,532)	1,400
Total	$ (5,352)	$ (1,014)

INCOME TAXES - COMPONENTS OF TH

INCOME TAXES - COMPONENTS OF THE INCOME TAX PROVISION (BENEFIT) (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2024	Sep. 30, 2023
Current provision (benefit): United States - State
Before operating loss carryforwards	$ 23	$ 47
Benefit of operating loss carryforwards	0	0
After operating loss carryforwards	23	47
Current provision (benefit): Canadian
Before operating loss carryforwards	148	274
Benefit of operating loss carryforwards	0	(244)
After operating loss carryforwards	148	30
Total current	171	77
Deferred provision (benefit):
United States – State	42	(130)
Total deferred	42	(130)
Total	$ 213	$ (53)

INCOME TAXES - RECONCILIATION B

INCOME TAXES - RECONCILIATION BETWEEN REPORTED INCOME TAX EXPENSE (BENEFIT) AND AMOUNT COMPUTED BY MULTIPLYING EARNINGS (LOSS) BY THE U.S. FEDERAL TAX RATE (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2024	Sep. 30, 2023
Reconciliation between the reported income tax provision (benefit) and the amount computed by multiplying the earnings (loss) attributable to the entity by the U.S. federal tax rate
U.S. federal tax rate	21%
Tax benefit computed by applying statutory rate	$ (1,124)	$ (213)
Increase in the valuation allowance	1,383	182
Additional effect of the foreign tax provision on the total tax provision	(129)	(4)
U.S. state income tax provision (benefit), net of federal effect	70	(9)
U.S. state provision to tax return adjustments	(12)	(106)
Other	25	97
Total	$ 213	$ (53)

INCOME TAXES - TAX EFFECTS OF T

INCOME TAXES - TAX EFFECTS OF TEMPORARY DIFFERENCES (Details) - USD ($)	Sep. 30, 2024	Sep. 30, 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)
Net deferred income tax liability included in Consolidated Balance Sheets:
Deferred income tax assets	0	0
Deferred income tax liabilities	(100,000)	(58,000)
Net deferred income tax liability	$ (100,000)	$ (58,000)

INCOME TAXES - NARRATIVE (Detai

INCOME TAXES - NARRATIVE (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2024	Sep. 30, 2023
Valuation allowance, other disclosures
Increase in valuation allowance	$ 1,457
Income tax (benefit) expense recognized in valuation allowance change	1,392
Change in valuation allowance charged to accumulated other comprehensive income	65
Net deferred tax assets	4,658	$ 4,819
Federal
Tax carryovers
Tax credit carryovers	916
Operating loss carryovers	49,439
State and Local Jurisdiction
Tax carryovers
Operating loss carryovers	20,848
Foreign
Tax carryovers
Operating loss carryovers	$ 4,958

INCOME TAXES - CHANGES IN UNREC

INCOME TAXES - CHANGES IN UNRECOGNIZED TAX BENEFITS (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2024	Sep. 30, 2023
Changes in unrecognized tax benefits
Balance at the beginning of year	$ 62	$ 62
Effect of tax positions taken in prior years	0	0
Accrued interest related to tax positions taken	0	0
Balance at the end of year	$ 62	$ 62

REVENUE FROM CONTRACTS WITH C_3

REVENUE FROM CONTRACTS WITH CUSTOMERS - DISAGGREGATION OF REVENUE (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2024	Sep. 30, 2023
Disaggregation of Revenue [Line Items]
Revenue before interest income	$ 21,636	$ 25,182
United States
Disaggregation of Revenue [Line Items]
Revenue before interest income	6,452	8,448
Canada
Disaggregation of Revenue [Line Items]
Revenue before interest income	15,184	16,734
Oil
Disaggregation of Revenue [Line Items]
Revenue before interest income	13,509	14,259
Natural gas
Disaggregation of Revenue [Line Items]
Revenue before interest income	2,007	3,441
Natural gas liquids
Disaggregation of Revenue [Line Items]
Revenue before interest income	1,880	1,676
Drilling and pump
Disaggregation of Revenue [Line Items]
Revenue before interest income	3,612	5,427
Contingent residual payments
Disaggregation of Revenue [Line Items]
Revenue before interest income	500	265
Other
Disaggregation of Revenue [Line Items]
Revenue before interest income	128	114
Oil and natural gas
Disaggregation of Revenue [Line Items]
Revenue before interest income	17,396	19,376
Oil and natural gas | United States
Disaggregation of Revenue [Line Items]
Revenue before interest income	2,303	2,746
Oil and natural gas | Canada
Disaggregation of Revenue [Line Items]
Revenue before interest income	15,093	16,630
Oil and natural gas | Oil
Disaggregation of Revenue [Line Items]
Revenue before interest income	13,509	14,259
Oil and natural gas | Natural gas
Disaggregation of Revenue [Line Items]
Revenue before interest income	2,007	3,441
Oil and natural gas | Natural gas liquids
Disaggregation of Revenue [Line Items]
Revenue before interest income	1,880	1,676
Oil and natural gas | Drilling and pump
Disaggregation of Revenue [Line Items]
Revenue before interest income	0	0
Oil and natural gas | Contingent residual payments
Disaggregation of Revenue [Line Items]
Revenue before interest income	0	0
Oil and natural gas | Other
Disaggregation of Revenue [Line Items]
Revenue before interest income	0	0
Contract drilling
Disaggregation of Revenue [Line Items]
Revenue before interest income	3,612	5,427
Contract drilling | United States
Disaggregation of Revenue [Line Items]
Revenue before interest income	3,612	5,427
Contract drilling | Canada
Disaggregation of Revenue [Line Items]
Revenue before interest income	0	0
Contract drilling | Oil
Disaggregation of Revenue [Line Items]
Revenue before interest income	0	0
Contract drilling | Natural gas
Disaggregation of Revenue [Line Items]
Revenue before interest income	0	0
Contract drilling | Natural gas liquids
Disaggregation of Revenue [Line Items]
Revenue before interest income	0	0
Contract drilling | Drilling and pump
Disaggregation of Revenue [Line Items]
Revenue before interest income	3,612	5,427
Contract drilling | Contingent residual payments
Disaggregation of Revenue [Line Items]
Revenue before interest income	0	0
Contract drilling | Other
Disaggregation of Revenue [Line Items]
Revenue before interest income	0	0
Land investment
Disaggregation of Revenue [Line Items]
Revenue before interest income	500	265
Land investment | United States
Disaggregation of Revenue [Line Items]
Revenue before interest income	500	265
Land investment | Canada
Disaggregation of Revenue [Line Items]
Revenue before interest income	0	0
Land investment | Oil
Disaggregation of Revenue [Line Items]
Revenue before interest income	0	0
Land investment | Natural gas
Disaggregation of Revenue [Line Items]
Revenue before interest income	0	0
Land investment | Natural gas liquids
Disaggregation of Revenue [Line Items]
Revenue before interest income	0	0
Land investment | Drilling and pump
Disaggregation of Revenue [Line Items]
Revenue before interest income	0	0
Land investment | Contingent residual payments
Disaggregation of Revenue [Line Items]
Revenue before interest income	500	265
Land investment | Other
Disaggregation of Revenue [Line Items]
Revenue before interest income	0	0
Other
Disaggregation of Revenue [Line Items]
Revenue before interest income	128	114
Other | United States
Disaggregation of Revenue [Line Items]
Revenue before interest income	37	10
Other | Canada
Disaggregation of Revenue [Line Items]
Revenue before interest income	91	104
Other | Oil
Disaggregation of Revenue [Line Items]
Revenue before interest income	0	0
Other | Natural gas
Disaggregation of Revenue [Line Items]
Revenue before interest income	0	0
Other | Natural gas liquids
Disaggregation of Revenue [Line Items]
Revenue before interest income	0	0
Other | Drilling and pump
Disaggregation of Revenue [Line Items]
Revenue before interest income	0	0
Other | Contingent residual payments
Disaggregation of Revenue [Line Items]
Revenue before interest income	0	0
Other | Other
Disaggregation of Revenue [Line Items]
Revenue before interest income	128	114
Goods transferred at a point in time
Disaggregation of Revenue [Line Items]
Revenue before interest income	18,024	19,755
Goods transferred at a point in time | Oil and natural gas
Disaggregation of Revenue [Line Items]
Revenue before interest income	17,396	19,376
Goods transferred at a point in time | Contract drilling
Disaggregation of Revenue [Line Items]
Revenue before interest income	0	0
Goods transferred at a point in time | Land investment
Disaggregation of Revenue [Line Items]
Revenue before interest income	500	265
Goods transferred at a point in time | Other
Disaggregation of Revenue [Line Items]
Revenue before interest income	128	114
Services transferred over time
Disaggregation of Revenue [Line Items]
Revenue before interest income	3,612	5,427
Services transferred over time | Oil and natural gas
Disaggregation of Revenue [Line Items]
Revenue before interest income	0	0
Services transferred over time | Contract drilling
Disaggregation of Revenue [Line Items]
Revenue before interest income	3,612	5,427
Services transferred over time | Land investment
Disaggregation of Revenue [Line Items]
Revenue before interest income	0	0
Services transferred over time | Other
Disaggregation of Revenue [Line Items]
Revenue before interest income	$ 0	$ 0

REVENUE FROM CONTRACTS WITH C_4

REVENUE FROM CONTRACTS WITH CUSTOMERS -CONTRACT BALANCES (Details) - USD ($) $ in Thousands	Sep. 30, 2024	Sep. 30, 2023	Sep. 30, 2022
Revenue from Contract with Customer [Abstract]
Accounts receivables from contracts with customers	$ 2,031	$ 2,931	$ 4,038
Contract assets	267	958	580
Contract liabilities	$ 0	$ 377	$ 1,087

REVENUE FROM CONTRACTS WITH C_5

REVENUE FROM CONTRACTS WITH CUSTOMERS - NARRATIVE (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2024	Sep. 30, 2023
Disaggregation of Revenue [Line Items]
Contract with customer, liability, current	$ 0	$ 377
Contract with customer, liability, revenue recognized	377	1,015
Capitalized contract cost net, preconstruction	173	504
Capitalized contract cost, amortization of preconstruction	306	326
Capitalized contract cost, impairment loss	0	0
Uninstalled materials, current	$ 65	$ 348
Minimum
Disaggregation of Revenue [Line Items]
Contract receivable retainage percentage	5%
Maximum
Disaggregation of Revenue [Line Items]
Contract receivable retainage percentage	10%

SEGMENT AND GEOGRAPHIC INFORM_3

SEGMENT AND GEOGRAPHIC INFORMATION - REPORTING SEGMENTS (Details) - USD ($)	12 Months Ended
	Sep. 30, 2024	Sep. 30, 2023
Revenues:
Revenue 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:
Depletion, depreciation, and amortization	5,106,000	4,457,000
Impairment:
Impairment of assets	2,885,000	0
Operating (loss) profit (before general and administrative expenses):
Operating profit (loss) (before general and administrative expenses)	(687,000)	5,173,000
Equity in income of affiliates:
Equity in income of affiliates	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)
Intersegment eliminations | External Customer
Revenues:
Total revenues	0	0
Oil and natural gas
Revenues:
Revenue before interest income	17,396,000	19,376,000
Total revenues	17,396,000	19,376,000
Depletion, depreciation, and amortization:
Depletion, depreciation, and amortization	4,947,000	4,269,000
Impairment:
Impairment of assets	2,885,000	0
Operating (loss) profit (before general and administrative expenses):
Operating profit (loss) (before general and administrative expenses)	(285,000)	4,673,000
Contract drilling
Revenues:
Revenue before interest income	3,612,000	5,427,000
Total revenues	3,612,000	5,427,000
Depletion, depreciation, and amortization:
Depletion, depreciation, and amortization	156,000	186,000
Operating (loss) profit (before general and administrative expenses):
Operating profit (loss) (before general and administrative expenses)	(1,027,000)	(428,000)
Land investment
Revenues:
Revenue before interest income	500,000	265,000
Total revenues	500,000	265,000
Operating (loss) profit (before general and administrative expenses):
Operating profit (loss) (before general and administrative expenses)	500,000	265,000
Other
Revenues:
Revenue before interest income	128,000	114,000
Total revenues	216,000	201,000
Depletion, depreciation, and amortization:
Depletion, depreciation, and amortization	3,000	2,000
Operating (loss) profit (before general and administrative expenses):
Operating profit (loss) (before general and administrative expenses)	125,000	112,000
Gain on sale of assets
Operating (loss) profit (before general and administrative expenses):
Operating profit (loss) (before general and administrative expenses)	$ 0	$ 551,000

SEGMENT AND GEOGRAPHIC INFORM_4

SEGMENT AND GEOGRAPHIC INFORMATION - CAPITAL EXPENDITURES (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2024	Sep. 30, 2023
Capital Expenditures:
Capital Expenditure	$ 4,241	$ 12,540
Corporate and other
Capital Expenditures:
Capital Expenditure	1	14
Oil and natural gas | Operating segments
Capital Expenditures:
Capital Expenditure	4,228	12,212
Contract drilling | Operating segments
Capital Expenditures:
Capital Expenditure	$ 12	$ 314

SEGMENT AND GEOGRAPHIC INFORM_5

SEGMENT AND GEOGRAPHIC INFORMATION - ASSETS BY SEGMENT (Details) - USD ($) $ in Thousands	Sep. 30, 2024	Sep. 30, 2023
Assets By Segment:
Total assets	$ 30,669	$ 35,421
Cash and cash equivalents
Assets By Segment:
Total assets	4,505	2,830
Asset for retirement benefits
Assets By Segment:
Total assets	4,899	4,471
Corporate and other
Assets By Segment:
Total assets	260	248
Oil and natural gas | Operating segments | Canada
Assets By Segment:
Total assets	15,218	18,855
Oil and natural gas | Operating segments | United States
Assets By Segment:
Total assets	4,190	5,917
Contract drilling | Operating segments
Assets By Segment:
Total assets	$ 1,597	$ 3,100

SEGMENT AND GEOGRAPHIC INFORM_6

SEGMENT AND GEOGRAPHIC INFORMATION - GEOGRAPHIC AREAS (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2024	Sep. 30, 2023
Geographic information
Long-lived assets	$ 21,786	$ 26,336
Revenue (before interest income)	21,636	25,182
United States
Geographic information
Long-lived assets	9,214	10,373
Revenue (before interest income)	6,452	8,448
Canada
Geographic information
Long-lived assets	12,572	15,963
Revenue (before interest income)	$ 15,184	$ 16,734

ACCUMULATED OTHER COMPREHENSI_3

ACCUMULATED OTHER COMPREHENSIVE INCOME (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2024	Sep. 30, 2023
Foreign currency translation:
Balance at beginning of period	$ 220	$ 222
Change in cumulative translation adjustment before reclassifications	0	(2)
Income taxes	0	0
Net current period other comprehensive loss	0	(2)
Balance at end of the period	220	220
Retirement plans:
Balance at beginning of period	1,884	1,072
Amortization of net actuarial gain	(85)	(79)
Net actuarial (loss) gain arising during the period	(76)	891
Income taxes	0	0
Net current period other comprehensive (loss) income	(161)	812
Balance at end of the period	1,723	1,884
Accumulated other comprehensive income, net	$ 1,943	$ 2,104

LEASES - ASSETS AND LIABILITIES

LEASES - ASSETS AND LIABILITIES (Details) - USD ($) $ in Thousands	Sep. 30, 2024	Sep. 30, 2023
Leases [Abstract]
Operating lease right-of-use assets	$ 39	$ 54
Total right-of-use assets	39	54
Current portion of operating lease liabilities	68	71
Operating lease liabilities	7	47
Total lease liabilities	$ 75	$ 118
Operating Lease, Liability, Current, Statement of Financial Position [Extensible List]	Other current liabilities	Other current liabilities

LEASES - LEASE COSTS (Details)

LEASES - LEASE COSTS (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2024	Sep. 30, 2023
Leases [Abstract]
Operating lease cost	$ 87	$ 88
Short-term lease cost	358	347
Variable lease cost	142	136
Total lease cost	$ 587	$ 571

LEASES - SUPPLEMENTAL LEASE INF

LEASES - SUPPLEMENTAL LEASE INFORMATION (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2024	Sep. 30, 2023
Leases [Abstract]
Cash paid related to operating lease liabilities	$ 114	$ 114
Operating lease, weighted average remaining lease term (in years)	10 months 24 days	1 year 8 months 12 days
Operating lease, weighted average discount rate	6.99%	5.53%

LEASES - OPEARTING LEASE MATURI

LEASES - OPEARTING LEASE MATURITY SCHEDULE (Details) $ in Thousands	Sep. 30, 2024 USD ($)
Leases [Abstract]
2025	$ 70
2026	7
2027	0
2028	0
2029	0
Thereafter	0
Total lease payments	77
Less: amounts representing interest	(2)
Operating lease liabilities	$ 75

STOCKHOLDERS' EQUITY - SHARE-BA

STOCKHOLDERS' EQUITY - SHARE-BASED COMPENSATION (Details) - USD ($) $ / shares in Units, $ in Thousands					1 Months Ended		12 Months Ended		44 Months Ended
	May 16, 2024	Nov. 02, 2023	May 11, 2023	Feb. 09, 2021	Oct. 31, 2024	May 31, 2023	Sep. 30, 2024	Sep. 30, 2023	Sep. 30, 2024
Share-based compensation arrangement by share-based payment award [Line Items]
Value of common stock issued for services								$ 90
Equity-classified share options
Share-based compensation arrangement by share-based payment award [Line Items]
Number of shares granted (in shares)				665,000			0
Shares exercise price							$ 0
Shares forfeited due to director departures							0
Share-based compensation expense							$ 50	164
Restricted Stock Units (RSUs)
Share-based compensation arrangement by share-based payment award [Line Items]
Share-based compensation expense							$ 158	$ 99
Number of restricted stock units granted (in shares)							136,336
Total unrecognized compensation cost							$ 200		$ 200
Period over which unrecognized compensation cost is expected to be recognized							1 year 8 months 12 days
Share-based Payment Arrangement, Tranche One | Equity-classified share options
Share-based compensation arrangement by share-based payment award [Line Items]
Number of shares granted (in shares)				605,000
Shares exercise price				$ 3.33
Shares vesting period				3 years
Shares expiration period				10 years
Share-based Payment Arrangement, Tranche Two | Equity-classified share options
Share-based compensation arrangement by share-based payment award [Line Items]
Number of shares granted (in shares)				60,000
Shares exercise price				$ 3.66
Shares vesting period				3 years
Shares expiration period				5 years
Share-based Payment Arrangement, Independent Director
Share-based compensation arrangement by share-based payment award [Line Items]
Issuance of common stock for services (in shares)						34,091
Value of common stock issued for services			$ 90
Share-based Payment Arrangement, Independent Director | Equity-classified share options
Share-based compensation arrangement by share-based payment award [Line Items]
Number of shares granted (in shares)				310,000
Shares expired due to director departures									100,000
Shares forfeited due to director departures									100,000
Share-based Payment Arrangement, Independent Director | Restricted Stock Units (RSUs)
Share-based compensation arrangement by share-based payment award [Line Items]
Shares vesting period		3 years
Number of restricted stock units granted (in shares)		76,336
Share-based Payment Arrangement, Independent Director | Restricted Stock Units (RSUs) | Subsequent Event
Share-based compensation arrangement by share-based payment award [Line Items]
Shares vesting period					3 years
Number of restricted stock units granted (in shares)					105,820
Share-based Payment Arrangement, Employee | Equity-classified share options
Share-based compensation arrangement by share-based payment award [Line Items]
Number of shares granted (in shares)				355,000
Share-based Payment Arrangement, Employee | Restricted Stock Units (RSUs)
Share-based compensation arrangement by share-based payment award [Line Items]
Shares vesting period	3 years
Number of restricted stock units granted (in shares)	60,000
2018 Equity Incentive Plan
Share-based compensation arrangement by share-based payment award [Line Items]
Shares authorized and reserved for issuance (in shares)							1,600,000		1,600,000
Number of shares available for grant (in shares)							925,188		925,188

STOCKHOLDERS' EQUITY - ESTIMATE

STOCKHOLDERS' EQUITY - ESTIMATED FAIR VALUE OF EQUITY-CLASSIFIED AWARDS - STOCK OPTIONS (Details) - Equity-classified share options - $ / shares		12 Months Ended
	Feb. 09, 2021	Sep. 30, 2024
Share-based compensation
Number of shares granted (in shares)	665,000	0
Share-based Payment Arrangement, >10% Owner-Employee
Share-based compensation
Number of shares granted (in shares)		60,000
Expected volatility		127.40%
Expected dividends		0%
Expected term (in years)		3 years 6 months
Risk-free interest rate		0.19%
Expected forfeitures		0%
Fair value per share (in dollars per share)		$ 2.51
Share-based Payment Arrangement, Others
Share-based compensation
Number of shares granted (in shares)		605,000
Expected volatility		105.80%
Expected dividends		0%
Expected term (in years)		6 years
Risk-free interest rate		0.82%
Expected forfeitures		0%
Fair value per share (in dollars per share)		$ 2.70

STOCKHOLDERS' EQUITY - EQUITY-C

STOCKHOLDERS' EQUITY - EQUITY-CLASSIFIED AWARDS - STOCK OPTIONS (Details) - Equity-classified share options		12 Months Ended
	Feb. 09, 2021 shares	Sep. 30, 2024 USD ($) $ / shares shares
Shares
Outstanding at the beginning of the period (in shares) | shares		465,000
Granted (in shares) | shares	665,000	0
Exercised (in shares) | shares		0
Expired/Forfeited (in shares) | shares		0
Outstanding at the end of the period (in shares) | shares		465,000
Exercisable at the end of period (in shares) | shares		465,000
Weighted-Average Exercise Price
Outstanding at the beginning of the period (in dollars per share) | $ / shares		$ 3.37
Granted (in dollars per share) | $ / shares		0
Exercised (in dollars per share) | $ / shares		0
Expired/Forfeited (in dollars per share) | $ / shares		0
Outstanding at the end of the period (in dollars per share) | $ / shares		3.37
Exercisable at the end of period (in dollars per share) | $ / shares		$ 3.37
Weighted-Average Remaining Contractual Term
Options outstanding, weighted average remaining contractual life		5 years 8 months 12 days
Options exercisable, weighted average contractual life		5 years 8 months 12 days
Aggregate Intrinsic Value
Options outstanding, aggregate intrinsic value | $		$ 0
Options exercisable, aggregate intrinsic value | $		$ 0

STOCKHOLDERS' EQUITY - EQUITY_2

STOCKHOLDERS' EQUITY - EQUITY-CLASSIFIED AWARDS - RESTRICTED STOCK UNITS (Details) - $ / shares	12 Months Ended
	Sep. 30, 2024	Oct. 01, 2024	Sep. 30, 2023
Weighted-Average Grant Date Fair Value
Common stock, issued shares (in shares)	10,195,990		10,158,678
Subsequent Event
Weighted-Average Grant Date Fair Value
Common stock, issued shares (in shares)		25,444
Restricted Stock Units (RSUs)
Shares
Nonvested at the beginning of the period (in shares)	0
Granted (in shares)	136,336
Vested (in shares)	(25,444)
Forfeited (in shares)	0
Nonvested at the end of the period (in shares)	110,892
Weighted-Average Grant Date Fair Value
Nonvested at the beginning of the period (in dollars per share)	$ 0
Granted (in dollars per share)	2.62
Vested (in dollars per share)	2.62
Forfeited (in dollars per share)	0
Nonvested at the end of the period (in dollars per share)	$ 2.63

STOCKHOLDERS' EQUITY - CASH DIV

STOCKHOLDERS' EQUITY - CASH DIVIDENDS (Details) - $ / shares	3 Months Ended				12 Months Ended
	Sep. 30, 2023	Jun. 30, 2023	Mar. 31, 2023	Dec. 31, 2022	Sep. 30, 2024	Sep. 30, 2023
Equity [Abstract]
Dividends declared, cash paid per share	$ 0.015	$ 0.015	$ 0.015	$ 0.015	$ 0	$ 0.060

COMMITMENTS AND CONTINGENCIES (

COMMITMENTS AND CONTINGENCIES (Detail) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2024	Sep. 30, 2020	Mar. 07, 2019
Commitments and contingencies
Amounts accrued under the incentive compensation plan	$ 286
Contract drilling
Commitments and contingencies
Loss contingency accrual	141
Unfavorable Regulatory Action | Contract drilling
Commitments and contingencies
Loss contingency accrual	$ 200	$ 300
KD Development, LLC
Commitments and contingencies
Collaborative agreement, fees, percentage of cumulative net profits			0.72%
Pool Of Various Individuals
Commitments and contingencies
Collaborative agreement, fees, percentage of cumulative net profits			0.20%
Kaupulehu Developments
Commitments and contingencies
Fees to be paid to Nearco	10.40%
Percentage of Increment II receipts to be paid to external real estate legal counsel's estate for services provided in the negotiation and closing of the Increment II transaction	1.20%

INFORMATION RELATING TO THE C_3

INFORMATION RELATING TO THE CONSOLIDATED STATEMENTS OF CASH FLOWS - EFFECT OF CHANGES IN CURRENT ASSETS AND LIABILITIES ON THE CONSOLIDATED STATEMENTS OF CASH FLOWS (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2024	Sep. 30, 2023
Increase (decrease) from changes in:
Receivables	$ 650	$ 1,103
Income tax receivable	(3)	(16)
Other current assets	1,475	(51)
Accounts payable	928	(595)
Accrued compensation	(79)	(278)
Other current liabilities	(191)	(556)
Increase (decrease) from changes in current assets and liabilities	2,780	(393)
Supplemental disclosure of cash flow information:
Income taxes paid	$ 71	$ 100

INFORMATION RELATING TO THE C_4

INFORMATION RELATING TO THE CONSOLIDATED STATEMENTS OF CASH FLOWS - NARRATIVE (Details) - Oil and natural gas - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2024	Sep. 30, 2023
Supplemental disclosures of cash flow information:
Increase (decrease) in capital expenditure accruals related to oil and natural gas exploration and development	$ 1,291	$ (575)
Increase (decrease) in capital expenditure accruals related to oil and natural gas asset retirement obligations	$ (577)	$ 1,483

RELATED PARTY TRANSACTIONS (Det

RELATED PARTY TRANSACTIONS (Details) $ in Thousands		1 Months Ended	12 Months Ended
	May 11, 2023 USD ($) shares	May 31, 2023 USD ($)	Sep. 30, 2024 USD ($) lot	Sep. 30, 2023 USD ($) lot
Related party transactions
Value of common stock issued for services				$ 90
Mr. Kenneth Grossman
Related party transactions
Expenses incurred from transactions with related parties		$ 100
One-time special director fee paid in cash		40
Issuance of common stock for services (in shares) | shares	22,728
Value of common stock issued for services	$ 60
Mr. Douglas Woodrum
Related party transactions
Expenses incurred from transactions with related parties		50
One-time special director fee paid in cash		$ 20
Issuance of common stock for services (in shares) | shares	11,363
Value of common stock issued for services	$ 30
Kaupulehu Developments
Related party transactions
Revenues - sale of interest in leasehold land			$ 500	265
Kaupulehu Developments | KD Kaupulehu, LLLP | Increment I
Related party transactions
Revenues - sale of interest in leasehold land			$ 500	$ 265
Number of single family lots sold | lot			2	1
KD Acquisition, LLLP
Related party transactions
Ownership interest acquired			19.60%
KD Acquisition II, LP | Barnwell Industries Inc
Related party transactions
Ownership interest acquired			10.80%

SUBSEQUENT EVENTS (Details)

SUBSEQUENT EVENTS (Details) - Restricted Stock Units (RSUs) - shares		1 Months Ended	12 Months Ended
	Nov. 02, 2023	Oct. 31, 2024	Sep. 30, 2024
Subsequent Event [Line Items]
Number of restricted stock units granted (in shares)			136,336
Share-based Payment Arrangement, Independent Director
Subsequent Event [Line Items]
Number of restricted stock units granted (in shares)	76,336
Shares vesting period	3 years
Subsequent Event | Share-based Payment Arrangement, Independent Director
Subsequent Event [Line Items]
Number of restricted stock units granted (in shares)		105,820
Shares vesting period		3 years

SUPPLEMENTARY OIL AND NATURAL_3

SUPPLEMENTARY OIL AND NATURAL GAS INFORMATION (UNAUDITED) - PROVED RESERVES (Details) bbl in Thousands, Mcf in Thousands, Boe in Thousands	12 Months Ended
	Sep. 30, 2024 Boe bbl Mcf	Sep. 30, 2023 Boe bbl Mcf
Changes in the estimates of net interests in total proved reserves of oil, natural gas liquids and natural gas
Balance at the beginning of the period | Boe	2,343	1,939
Revisions of previous estimates | Boe	457	115
Extensions, discoveries and other additions | Boe	184	756
Acquisitions of reserves | Boe	9
Less sales of reserves | Boe	(79)
Less production | Boe	(491)	(467)
Balance at the end of the period | Boe	2,423	2,343
Canada
Changes in the estimates of net interests in total proved reserves of oil, natural gas liquids and natural gas
Balance at the beginning of the period | Boe	1,772	1,769
Revisions of previous estimates | Boe	430	5
Extensions, discoveries and other additions | Boe	184	379
Acquisitions of reserves | Boe	9
Less sales of reserves | Boe	(79)
Less production | Boe	(401)	(381)
Balance at the end of the period | Boe	1,915	1,772
United States
Changes in the estimates of net interests in total proved reserves of oil, natural gas liquids and natural gas
Balance at the beginning of the period | Boe	571	170
Revisions of previous estimates | Boe	27	110
Extensions, discoveries and other additions | Boe	0	377
Acquisitions of reserves | Boe	0
Less sales of reserves | Boe	0
Less production | Boe	(90)	(86)
Balance at the end of the period | Boe	508	571
Oil
Changes in the estimates of net interests in total proved reserves of oil, natural gas liquids and natural gas
Balance at the beginning of the period	899	875
Revisions of previous estimates	219	(24)
Extensions, discoveries and other additions	117	252
Acquisitions of reserves	4
Less sales of reserves	(54)
Less production	(203)	(204)
Balance at the end of the period	982	899
Oil | Canada
Changes in the estimates of net interests in total proved reserves of oil, natural gas liquids and natural gas
Balance at the beginning of the period	787	846
Revisions of previous estimates	222	(43)
Extensions, discoveries and other additions	117	167
Acquisitions of reserves	4
Less sales of reserves	(54)
Less production	(184)	(183)
Balance at the end of the period	892	787
Oil | United States
Changes in the estimates of net interests in total proved reserves of oil, natural gas liquids and natural gas
Balance at the beginning of the period	112	29
Revisions of previous estimates	(3)	19
Extensions, discoveries and other additions	0	85
Acquisitions of reserves	0
Less sales of reserves	0
Less production	(19)	(21)
Balance at the end of the period	90	112
Natural gas liquids
Changes in the estimates of net interests in total proved reserves of oil, natural gas liquids and natural gas
Balance at the beginning of the period	327	205
Revisions of previous estimates	85	30
Extensions, discoveries and other additions	15	144
Acquisitions of reserves	2
Less sales of reserves	(2)
Less production	(64)	(52)
Balance at the end of the period	363	327
Natural gas liquids | Canada
Changes in the estimates of net interests in total proved reserves of oil, natural gas liquids and natural gas
Balance at the beginning of the period	150	144
Revisions of previous estimates	70	1
Extensions, discoveries and other additions	15	32
Acquisitions of reserves	2
Less sales of reserves	(2)
Less production	(36)	(27)
Balance at the end of the period	199	150
Natural gas liquids | United States
Changes in the estimates of net interests in total proved reserves of oil, natural gas liquids and natural gas
Balance at the beginning of the period	177	61
Revisions of previous estimates	15	29
Extensions, discoveries and other additions	0	112
Acquisitions of reserves	0
Less sales of reserves	0
Less production	(28)	(25)
Balance at the end of the period	164	177
Natural gas
Changes in the estimates of net interests in total proved reserves of oil, natural gas liquids and natural gas
Balance at the beginning of the period | Mcf	6,701	4,985
Revisions of previous estimates | Mcf	908	822
Extensions, discoveries and other additions | Mcf	313	2,157
Acquisitions of reserves | Mcf	16
Less sales of reserves | Mcf	(139)
Less production | Mcf	(1,344)	(1,263)
Balance at the end of the period | Mcf	6,455	6,701
Natural gas | Canada
Changes in the estimates of net interests in total proved reserves of oil, natural gas liquids and natural gas
Balance at the beginning of the period | Mcf	5,010	4,519
Revisions of previous estimates | Mcf	826	435
Extensions, discoveries and other additions | Mcf	313	1,079
Acquisitions of reserves | Mcf	16
Less sales of reserves | Mcf	(139)
Less production | Mcf	(1,085)	(1,023)
Balance at the end of the period | Mcf	4,941	5,010
Natural gas | United States
Changes in the estimates of net interests in total proved reserves of oil, natural gas liquids and natural gas
Balance at the beginning of the period | Mcf	1,691	466
Revisions of previous estimates | Mcf	82	387
Extensions, discoveries and other additions | Mcf	0	1,078
Acquisitions of reserves | Mcf	0
Less sales of reserves | Mcf	0
Less production | Mcf	(259)	(240)
Balance at the end of the period | Mcf	1,514	1,691

SUPPLEMENTARY OIL AND NATURAL_4

SUPPLEMENTARY OIL AND NATURAL GAS INFORMATION (UNAUDITED) - PROVED UNDEVELOPED RESERVES (Details) bbl in Thousands, Mcf in Thousands, Boe in Thousands	12 Months Ended
	Sep. 30, 2024 Boe Mcf bbl
Changes in the estimates of net interests in total proved undeveloped reserves of oil, natural gas liquids and natural gas
Balance at the beginning of the period | Boe	211
Conversion to proved developed reserves | Boe	(155)
Revisions of previous estimates | Boe	(56)
Additions due to a new well | Boe	239
Balance at the end of the period | Boe	239
Proved developed reserves - total, balance at the beginning of the period | Boe	2,132
Proved developed reserves - total, balance at the end of the period | Boe	2,184
Canada
Changes in the estimates of net interests in total proved undeveloped reserves of oil, natural gas liquids and natural gas
Balance at the beginning of the period | Boe	211
Conversion to proved developed reserves | Boe	(155)
Revisions of previous estimates | Boe	(56)
Additions due to a new well | Boe	239
Balance at the end of the period | Boe	239
Proved developed reserves - total, balance at the beginning of the period | Boe	1,561
Proved developed reserves - total, balance at the end of the period | Boe	1,676
United States
Changes in the estimates of net interests in total proved undeveloped reserves of oil, natural gas liquids and natural gas
Balance at the beginning of the period | Boe	0
Conversion to proved developed reserves | Boe	0
Revisions of previous estimates | Boe	0
Additions due to a new well | Boe	0
Balance at the end of the period | Boe	0
Proved developed reserves - total, balance at the beginning of the period | Boe	571
Proved developed reserves - total, balance at the end of the period | Boe	508
Oil
Changes in the estimates of net interests in total proved undeveloped reserves of oil, natural gas liquids and natural gas
Balance at the beginning of the period	92
Conversion to proved developed reserves	(98)
Revisions of previous estimates	6
Additions due to a new well	109
Balance at the end of the period	109
Proved developed reserves - volume, balance at the beginning of the period	807
Proved developed reserves - volume, balance at the end of the period	873
Oil | Canada
Changes in the estimates of net interests in total proved undeveloped reserves of oil, natural gas liquids and natural gas
Balance at the beginning of the period	92
Conversion to proved developed reserves	(98)
Revisions of previous estimates	6
Additions due to a new well	109
Balance at the end of the period	109
Proved developed reserves - volume, balance at the beginning of the period	695
Proved developed reserves - volume, balance at the end of the period	783
Oil | United States
Changes in the estimates of net interests in total proved undeveloped reserves of oil, natural gas liquids and natural gas
Balance at the beginning of the period	0
Conversion to proved developed reserves	0
Revisions of previous estimates	0
Additions due to a new well	0
Balance at the end of the period	0
Proved developed reserves - volume, balance at the beginning of the period	112
Proved developed reserves - volume, balance at the end of the period	90
Natural gas liquids
Changes in the estimates of net interests in total proved undeveloped reserves of oil, natural gas liquids and natural gas
Balance at the beginning of the period	18
Conversion to proved developed reserves	(10)
Revisions of previous estimates	(8)
Additions due to a new well	23
Balance at the end of the period	23
Proved developed reserves - volume, balance at the beginning of the period	309
Proved developed reserves - volume, balance at the end of the period	340
Natural gas liquids | Canada
Changes in the estimates of net interests in total proved undeveloped reserves of oil, natural gas liquids and natural gas
Balance at the beginning of the period	18
Conversion to proved developed reserves	(10)
Revisions of previous estimates	(8)
Additions due to a new well	23
Balance at the end of the period	23
Proved developed reserves - volume, balance at the beginning of the period	132
Proved developed reserves - volume, balance at the end of the period	176
Natural gas liquids | United States
Changes in the estimates of net interests in total proved undeveloped reserves of oil, natural gas liquids and natural gas
Balance at the beginning of the period	0
Conversion to proved developed reserves	0
Revisions of previous estimates	0
Additions due to a new well	0
Balance at the end of the period	0
Proved developed reserves - volume, balance at the beginning of the period	177
Proved developed reserves - volume, balance at the end of the period	164
Natural gas
Changes in the estimates of net interests in total proved undeveloped reserves of oil, natural gas liquids and natural gas
Balance at the beginning of the period | Mcf	608
Conversion to proved developed reserves | Mcf	(279)
Revisions of previous estimates | Mcf	(330)
Additions due to a new well | Mcf	641
Balance at the end of the period | Mcf	640
Proved developed reserves - volume, balance at the beginning of the period | Mcf	6,093
Proved developed reserves - volume, balance at the end of the period | Mcf	5,815
Natural gas | Canada
Changes in the estimates of net interests in total proved undeveloped reserves of oil, natural gas liquids and natural gas
Balance at the beginning of the period | Mcf	608
Conversion to proved developed reserves | Mcf	(279)
Revisions of previous estimates | Mcf	(330)
Additions due to a new well | Mcf	641
Balance at the end of the period | Mcf	640
Proved developed reserves - volume, balance at the beginning of the period | Mcf	4,402
Proved developed reserves - volume, balance at the end of the period | Mcf	4,301
Natural gas | United States
Changes in the estimates of net interests in total proved undeveloped reserves of oil, natural gas liquids and natural gas
Balance at the beginning of the period | Mcf	0
Conversion to proved developed reserves | Mcf	0
Revisions of previous estimates | Mcf	0
Additions due to a new well | Mcf	0
Balance at the end of the period | Mcf	0
Proved developed reserves - volume, balance at the beginning of the period | Mcf	1,691
Proved developed reserves - volume, balance at the end of the period | Mcf	1,514

SUPPLEMENTARY OIL AND NATURAL_5

SUPPLEMENTARY OIL AND NATURAL GAS INFORMATION (UNAUDITED) - CAPITALIZED COSTS RELATING TO OIL AND NATURAL GAS PRODUCING ACTIVITIES (Details) - USD ($) $ in Thousands	Sep. 30, 2024	Sep. 30, 2023
Capitalized Costs Relating to Oil and Natural Gas Producing Activities
Proved properties	$ 83,557	$ 80,851
Unproved properties	0	0
Total capitalized costs	83,557	80,851
Accumulated depletion, depreciation, and impairment	67,003	59,549
Net capitalized costs	16,554	21,302
Canada
Capitalized Costs Relating to Oil and Natural Gas Producing Activities
Proved properties	76,963	74,440
Unproved properties	0	0
Total capitalized costs	76,963	74,440
Accumulated depletion, depreciation, and impairment	64,402	58,477
Net capitalized costs	12,561	15,963
United States
Capitalized Costs Relating to Oil and Natural Gas Producing Activities
Proved properties	6,594	6,411
Unproved properties	0	0
Total capitalized costs	6,594	6,411
Accumulated depletion, depreciation, and impairment	2,601	1,072
Net capitalized costs	$ 3,993	$ 5,339

SUPPLEMENTARY OIL AND NATURAL_6

SUPPLEMENTARY OIL AND NATURAL GAS INFORMATION (UNAUDITED) - COSTS INCURRED IN OIL AND NATURAL GAS PROPERTY ACQUISITION, EXPLORATION AND DEVELOPMENT (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2024	Sep. 30, 2023
Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development
Acquisition of proved properties	$ 146	$ 66
Acquisition of unproved properties	0	0
Exploration costs	34	716
Development costs	4,048	11,430
Total	4,228	12,212
Canada
Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development
Acquisition of proved properties	146	66
Acquisition of unproved properties	0	0
Exploration costs	34	461
Development costs	3,865	6,331
Total	4,045	6,858
United States
Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development
Acquisition of proved properties	0	0
Acquisition of unproved properties	0	0
Exploration costs	0	255
Development costs	183	5,099
Total	$ 183	$ 5,354

SUPPLEMENTARY OIL AND NATURAL_7

SUPPLEMENTARY OIL AND NATURAL GAS INFORMATION (UNAUDITED) - RESULTS OF OPERATIONS FOR OIL AND NATURAL GAS PRODUCING ACTIVITIES (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2024	Sep. 30, 2023
Results of Operations for Oil and Natural Gas Producing Activities
Net revenues	$ 17,396	$ 19,376
Production costs	(9,849)	(10,434)
Depletion	(4,947)	(4,269)
Impairment of assets	(2,885)
Pre-tax results of operations	(285)	4,673
Estimated income tax expense	340	151
Results of operations	(625)	4,522
Canada
Results of Operations for Oil and Natural Gas Producing Activities
Net revenues	15,093	16,630
Production costs	(9,230)	(9,859)
Depletion	(4,139)	(3,600)
Impairment of assets	(2,164)
Pre-tax results of operations	(440)	3,171
Estimated income tax expense	320	107
Results of operations	(760)	3,064
United States
Results of Operations for Oil and Natural Gas Producing Activities
Net revenues	2,303	2,746
Production costs	(619)	(575)
Depletion	(808)	(669)
Impairment of assets	(721)
Pre-tax results of operations	155	1,502
Estimated income tax expense	20	44
Results of operations	$ 135	$ 1,458

SUPPLEMENTARY OIL AND NATURAL_8

SUPPLEMENTARY OIL AND NATURAL GAS INFORMATION (UNAUDITED) - STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS (Details) - USD ($) $ in Thousands	Sep. 30, 2024	Sep. 30, 2023	Sep. 30, 2022
Oil and Gas, Standardized Measure, Discounted Future Net Cash Flow, Future Net Cash Flow after Discount [Abstract]
Future cash inflows	$ 87,336	$ 89,424
Future production costs	(47,681)	(46,103)
Future development costs	(2,795)	(2,958)
Future income tax expenses	(2,827)	(1,776)
Future net cash flows excluding abandonment, decommissioning and reclamation	34,033	38,587
Future abandonment, decommissioning and reclamation	(18,076)	(18,627)
Future net cash flows	15,957	19,960
10% annual discount for timing of cash flows	(107)	(47)
Standardized measure of discounted future net cash flows	15,850	19,913	$ 27,878
Canada
Oil and Gas, Standardized Measure, Discounted Future Net Cash Flow, Future Net Cash Flow after Discount [Abstract]
Future cash inflows	75,293	73,429
Future production costs	(42,601)	(41,935)
Future development costs	(2,795)	(2,958)
Future income tax expenses	(2,666)	(1,512)
Future net cash flows excluding abandonment, decommissioning and reclamation	27,231	27,024
Future abandonment, decommissioning and reclamation	(18,026)	(18,585)
Future net cash flows	9,205	8,439
10% annual discount for timing of cash flows	2,697	4,790
Standardized measure of discounted future net cash flows	11,902	13,229
United States
Oil and Gas, Standardized Measure, Discounted Future Net Cash Flow, Future Net Cash Flow after Discount [Abstract]
Future cash inflows	12,043	15,995
Future production costs	(5,080)	(4,168)
Future development costs	0	0
Future income tax expenses	(161)	(264)
Future net cash flows excluding abandonment, decommissioning and reclamation	6,802	11,563
Future abandonment, decommissioning and reclamation	(50)	(42)
Future net cash flows	6,752	11,521
10% annual discount for timing of cash flows	(2,804)	(4,837)
Standardized measure of discounted future net cash flows	$ 3,948	$ 6,684

SUPPLEMENTARY OIL AND NATURAL_9

SUPPLEMENTARY OIL AND NATURAL GAS INFORMATION (UNAUDITED) - CHANGES IN THE STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2024	Sep. 30, 2023
Changes in the Standardized Measure of Discounted Future Net Cash Flows
Beginning of year	$ 19,913	$ 27,878
Sales of oil and natural gas produced, net of production costs	(7,547)	(8,942)
Net changes in prices and production costs, net of royalties and wellhead taxes	(12,201)	(11,913)
Extensions and discoveries	1,725	10,767
Net change due to purchases and sales of minerals in place	(895)	0
Changes in future development costs	170	(2,959)
Revisions of previous quantity estimates	9,478	2,227
Net change in income taxes	1,786	2,868
Accretion of discount	3,359	905
Other - changes in the timing of future production and other	76	(1,202)
Other - net change in Canadian dollar translation rate	(14)	284
Net change	(4,063)	(7,965)
End of year	$ 15,850	$ 19,913