Barnwell Industries (BRN) 10-K18 Dec 232023 FY Annual reportFinancial data

Company Profile

Cover Page

Cover Page - USD ($) $ in Thousands	12 Months Ended
Cover Page - USD ($) $ in Thousands	Sep. 30, 2023	Dec. 12, 2023	Mar. 31, 2023
Cover [Abstract]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Sep. 30, 2023
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			$ 10,251
Entity Common Stock, Shares Outstanding		10,000,106
Documents Incorporated by Reference	Proxy statement, to be forwarded to stockholders on or about January 12, 2024, is incorporated by reference in Part III hereof.
Entity Central Index Key	0000010048
Amendment Flag	false
Document Fiscal Year Focus	2023
Document Fiscal Period Focus	FY

Audit Information

Audit Information	12 Months Ended
Audit Information	Sep. 30, 2023
Auditor Information [Abstract]
Auditor Name	WEAVER AND TIDWELL, L.L.P.
Auditor Location	Dallas, Texas
Auditor Firm ID	410

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Sep. 30, 2023	Sep. 30, 2022
Current assets:
Cash and cash equivalents	$ 2,830	$ 12,804
Accounts and other receivables, net of allowance for doubtful accounts of: $284,000 at September 30, 2023; $231,000 at September 30, 2022	3,246	4,361
Income taxes receivable	16	0
Other current assets	2,993	2,932
Total current assets	9,085	20,097
Asset for retirement benefits	4,471	3,385
Operating lease right-of-use assets	54	132
Property and equipment:
Proved oil and natural gas properties, net (full cost method)	21,302	13,232
Drilling rigs and other property and equipment, net	509	369
Total Net Property and Equipment	21,811	13,601
Total assets	35,421	37,215
Current liabilities:
Accounts payable	881	1,462
Accrued capital expenditures	1,099	1,655
Accrued compensation	726	999
Accrued operating and other expenses	1,747	1,576
Current portion of asset retirement obligation	1,536	1,327
Other current liabilities	609	1,908
Total current liabilities	6,598	8,927
Long-term debt	0	44
Operating lease liabilities	47	117
Liability for retirement benefits	1,664	1,649
Asset retirement obligation	8,297	7,129
Deferred income tax liabilities	58	188
Total liabilities	16,664	18,054
Commitments and contingencies (Note 17)
Equity:
Common stock, par value $0.50 per share; authorized, 40,000,000 shares: 10,158,678 issued at September 30, 2023; 10,124,587 issued at September 30, 2022	5,079	5,062
Additional paid-in capital	7,687	7,351
Retained earnings	6,160	7,720
Accumulated other comprehensive income, net	2,104	1,294
Treasury stock, at cost: 167,900 shares at September 30, 2023 and 2022	(2,286)	(2,286)
Total stockholders’ equity	18,744	19,141
Non-controlling interests	13	20
Total equity	18,757	19,161
Total liabilities and equity	$ 35,421	$ 37,215

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	Sep. 30, 2023	Sep. 30, 2022
Statement of Financial Position [Abstract]
Accounts receivable, allowance for doubtful accounts	$ 284	$ 231
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)	10,158,678	10,124,587
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, 2023	Sep. 30, 2022
Revenues:
Revenues	$ 25,269	$ 28,545
Costs and expenses:
General and administrative	6,956	8,044
Depletion, depreciation, and amortization	4,457	2,778
Impairment of assets	0	89
Foreign currency (gain) loss	(76)	484
Interest expense	2	1
Gain on sale of assets	(551)	0
Total costs and expenses	26,891	25,426
(Loss) earnings before equity in income of affiliates and income taxes	(1,622)	3,119
Equity in income of affiliates	758	3,400
(Loss) earnings before income taxes	(864)	6,519
Income tax (benefit) provision	(53)	347
Net (loss) earnings	(811)	6,172
Less: Net earnings attributable to non-controlling interests	150	659
Net (loss) earnings attributable to Barnwell Industries, Inc. stockholders	$ (961)	$ 5,513
Basic net (loss) earnings per common share attributable to Barnwell Industries, Inc. stockholders (in dollars per share)	$ (0.10)	$ 0.57
Diluted net (loss) earnings per common share attributable to Barnwell Industries, Inc. stockholders (in dollars per share)	$ (0.10)	$ 0.57
Weighted-average number of common shares outstanding:
Basic (in shares)	9,969,856	9,732,936
Diluted (in shares)	9,969,856	9,732,936
Oil and natural gas
Revenues:
Revenues	$ 19,376	$ 22,581
Costs and expenses:
Costs and expenses	10,434	9,439
Depletion, depreciation, and amortization	4,269	2,606
Contract drilling
Revenues:
Revenues	5,427	4,540
Costs and expenses:
Costs and expenses	5,669	4,591
Depletion, depreciation, and amortization	186	171
Sale of interest in leasehold land
Revenues:
Revenues	265	1,295
Costs and expenses:
Impairment of assets	0	89
Gas processing and other
Revenues:
Revenues	201	129
Costs and expenses:
Depletion, depreciation, and amortization	$ 2	$ 1

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE (LOSS) INCOME - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2023	Sep. 30, 2022
Statement of Comprehensive Income [Abstract]
Net (loss) earnings	$ (811)	$ 6,172
Other comprehensive (loss) income:
Foreign currency translation adjustments, net of taxes of $0	(2)	(40)
Retirement plans:
Amortization of accumulated other comprehensive gain into net periodic benefit cost, net of taxes of $0	(79)	0
Net actuarial gain arising during the period, net of taxes of $0	891	1,302
Total other comprehensive income	810	1,262
Total comprehensive (loss) income	(1)	7,434
Less: Comprehensive income attributable to non-controlling interests	(150)	(659)
Comprehensive (loss) income attributable to Barnwell Industries, Inc.	$ (151)	$ 6,775

CONSOLIDATED STATEMENTS OF CO_2

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2023	Sep. 30, 2022
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 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, 2021		9,445,625
Balance at Sep. 30, 2021	$ 9,507	$ 4,807	$ 4,590	$ 2,356	$ 32	$ (2,286)	$ 8
Increase (Decrease) in Stockholders' Equity
Net (loss) earnings	6,172			5,513			659
Foreign currency translation adjustments, net of taxes of $0	(40)				(40)
Distributions to non-controlling interests	(647)						(647)
Share-based compensation	657		657
Issuance of common stock, net of costs (in shares)		509,467
Issuance of common stock, net of costs	2,356	$ 255	2,101
Issuance of common stock for services (in shares)		1,595
Issuance of common stock for services	3		3
Dividends declared, cash paid per share	(149)			(149)
Retirement plans:
Amortization of accumulated other comprehensive gain into net periodic benefit cost, net of taxes of $0	0
Net actuarial gain arising during the period, net of taxes of $0	1,302				1,302
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
Issuance of common stock for services (in shares)		34,091
Issuance of common stock for services	90	$ 17	73
Dividends declared, cash paid per share	(599)			(599)
Retirement plans:
Amortization of accumulated other comprehensive gain into net periodic benefit cost, net of taxes of $0	(79)				(79)
Net actuarial 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

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, 2022	Sep. 30, 2023	Sep. 30, 2022
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	$ 0.015	$ 0.060	$ 0.015
Net actuarial gain arising during the period, taxes						$ 0	$ 0
Amortization of accumulated other comprehensive gain into net periodic benefit cost, taxes						$ 0	$ 0

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2023	Sep. 30, 2022
Cash flows from operating activities:
Net (loss) earnings	$ (811)	$ 6,172
Adjustments to reconcile net (loss) earnings to net cash provided by operating activities:
Equity in income of affiliates	(758)	(3,400)
Depletion, depreciation, and amortization	4,457	2,778
Impairment of assets	0	89
Gain on sale of assets	(551)	0
Sale of interest in leasehold land, net of fees paid	(233)	(1,137)
Distributions of income from equity investees	539	3,170
Retirement benefits income	(252)	(272)
Accretion of asset retirement obligation	808	767
Deferred income tax benefit	(130)	(171)
Asset retirement obligation payments	(1,005)	(942)
Share-based compensation expense	263	657
Common stock issued for services	90	3
Non-cash rent income	(25)	(1)
Retirement plan contributions and payments	(3)	(3)
Bad debt expense	38	124
Foreign currency (gain) loss	(76)	484
Gain on debt extinguishment	(15)	0
Decrease from changes in current assets and liabilities	(393)	(1,027)
Net cash provided by operating activities	1,943	7,291
Cash flows from investing activities:
Distributions from equity investees in excess of earnings	219	230
Proceeds from sale of interest in leasehold land, net of fees paid	233	1,137
Proceeds from sale of oil and natural gas assets	0	503
Proceeds from sale of contract drilling assets	0	687
Deposit for sale of contract drilling asset	0	551
Payments to acquire oil and natural gas properties	0	(1,563)
Capital expenditures - oil and natural gas	(11,304)	(8,607)
Capital expenditures - all other	(328)	(50)
Net cash used in investing activities	(11,180)	(7,112)
Cash flows from financing activities:
Repayment of long-term debt	(30)	0
Distributions to non-controlling interests	(157)	(647)
Proceeds from issuance of stock, net of costs	0	2,356
Payment of dividends	(599)	(149)
Net cash (used in) provided by financing activities	(786)	1,560
Effect of exchange rate changes on cash and cash equivalents	49	(214)
Net (decrease) increase in cash and cash equivalents	(9,974)	1,525
Cash and cash equivalents at beginning of year	12,804	11,279
Cash and cash equivalents at end of year	$ 2,830	$ 12,804

SUMMARY OF SIGNIFICANT ACCOUNTI

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	12 Months Ended
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	Sep. 30, 2023
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) investing in 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), a 75%-owned land investment partnership (KD Kona), and a variable interest entity (Teton Barnwell Fund I, LLC) for which the Company is deemed to be the primary beneficiary. 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. Reclassifications Certain reclassifications of prior period amounts have been made in Note 9 to conform to the current period presentations. These reclassifications had no effect on previously reported net earnings, cash flows, total assets, or stockholders' equity. 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 invests in 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 doubtful accounts is Barnwell’s best estimate of the amount of probable credit losses in Barnwell’s existing accounts receivable and is based on historical write-off experience and the application of the specific identification method. 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. Entities that have been determined to be VIEs and for which we have a controlling financial interest and are therefore the VIE’s primary beneficiary are consolidated (see Note 4). Entities that have been determined to be VIEs and for which we do not have a controlling financial interest and are therefore not the VIE’s primary beneficiary are not consolidated. These unconsolidated entities are accounted for under the equity method (see Note 3). 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, 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 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 8. 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 $59,000 based on the assets of the plan at September 30, 2023. 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. Foreign Currency Translations and Transactions Assets and liabilities of foreign subsidiaries are translated at the year-end exchange rate. Operating results of foreign subsidiaries are translated at average exchange rates during the period. Translation adjustments have no effect on net income and are included in “Accumulated other comprehensive income, net” in the accompanying Consolidated Balance Sheets. Foreign currency gains or losses on intercompany loans and advances that are not considered long-term investments in nature because management intends to settle these intercompany balances in the future are included in our statements of operations. Fair Value Measurements Fair value is defined as the amount that would be received from the sale of an asset

(LOSS) EARNINGS PER COMMON SHAR

(LOSS) EARNINGS PER COMMON SHARE	12 Months Ended
(LOSS) EARNINGS PER COMMON SHARE	Sep. 30, 2023
Earnings Per Share [Abstract]
(LOSS) EARNINGS PER COMMON SHARE	(LOSS) EARNINGS PER COMMON SHARE Basic (loss) earnings per share is computed using the weighted-average number of common shares outstanding for the period. Diluted (loss) earnings 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) earnings per share if their effect is 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. Options to purchase 615,000 shares were excluded from the computation of diluted shares for the year ended September 30, 2022, as their inclusion would have been anti-dilutive. Reconciliations between net (loss) earnings attributable to Barnwell stockholders and common shares outstanding of the basic and diluted net (loss) earnings per share computations are detailed in the following tables: Year ended September 30, 2023 Net Loss Shares Per-Share (Numerator) (Denominator) Amount Basic net loss $ (961,000) 9,969,856 $ (0.10) Effect of dilutive securities - common stock options and restricted stock units — — Diluted net loss $ (961,000) 9,969,856 $ (0.10) Year ended September 30, 2022 Net Earnings Shares Per-Share (Numerator) (Denominator) Amount Basic net earnings $ 5,513,000 9,732,936 $ 0.57 Effect of dilutive securities - common stock options — — Diluted net earnings $ 5,513,000 9,732,936 $ 0.57

INVESTMENTS

INVESTMENTS	12 Months Ended
INVESTMENTS	Sep. 30, 2023
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, of which only two lots remain to be sold as of September 30, 2023, as well as from commissions on real estate sales by the real estate sales office and revenues resulting from the sale of private club memberships. 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 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, 2023, Barnwell received cash distributions of $758,000 from the Kukio Resort Land Development Partnership resulting in a net amount of $674,000, after distributing $84,000 to non-controlling interests. During the year ended September 30, 2022, Barnwell received cash distributions of $3,400,000 from the Kukio Resort Land Development Partnerships resulting in a net amount of $3,028,000, after distributing $372,000 to non-controlling interests. Equity in income of affiliates was $758,000 for the year ended September 30, 2023, as compared to equity in income of affiliates of $3,400,000 for the year ended September 30, 2022. Summarized financial information for the Kukio Resort Land Development Partnerships is as follows: Year ended September 30, 2023 2022 Revenue $ 13,055,000 $ 24,577,000 Gross profit $ 7,733,000 $ 16,934,000 Net earnings $ 4,436,000 $ 13,763,000 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 Partnership 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 Partnership’s cumulative earnings in excess of distributions during the suspended period exceeds our share of the Kukio Resort Land Development Partnership’s 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, 2023 was equivalent to the $758,000 of distributions received in that period. Cumulative distributions received from the Kukio Resort Land Development Partnerships in excess of our investment balance was $708,000 at September 30, 2023 and $958,000 at September 30, 2022. Sale of Interest in Leasehold Land Kaupulehu Developments has the right to receive payments from KD I and KD II resulting from the sale of lots and/or residential units within Increment I and Increment II by KD I and KD II (see Note 19). With respect to Increment I, Kaupulehu Developments is 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. One single-family lot was sold during the year ended September 30, 2023 and two single-family lots, of the 80 lots developed within Increment I, remained to be sold as of September 30, 2023. The developer had consolidated these two remaining lots into one large lot but has since split them back into the original two lots. 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, 2023 2022 Sale of interest in leasehold land: Revenues - sale of interest in leasehold land $ 265,000 $ 1,295,000 Fees - included in general and administrative expenses (32,000) (158,000) Sale of interest in leasehold land, net of fees paid $ 233,000 $ 1,137,000 There is no assurance with regards to the amounts of future payments from Increment I or 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
CONSOLIDATED VARIABLE INTEREST ENTITY	Sep. 30, 2023
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 new 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 are split between BOK and Gros Ventre at 98% and 2%, respectively, and as the manager of Teton Barnwell, Gros Ventre is 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 is responsible for 100% of the capital contributions made to Teton Barnwell. The Company has determined that Teton Barnwell is a variable interest entity (“VIE”) as the entity is structured with non-substantive voting rights and that the Company is the primary beneficiary. This is due to the fact that even though Teton Barnwell has a unanimous consent voting structure, BOK is responsible for 100% of the capital contributions required to fund Teton Barnwell’s future oil exploration and development investments pursuant to the Teton Operating Agreement and thus, BOK has the power to steer the decisions that most significantly impact Teton Barnwell’s economic performance and has the obligation to absorb any potential losses that could be significant to Teton Barnwell. As BOK is the primary beneficiary of the VIE, Teton Barnwell’s operating results, assets and liabilities are consolidated by the Company. The following table summarizes the carrying value of the assets and liabilities of Teton Barnwell that are consolidated by the Company. Intercompany balances are eliminated in consolidation and thus, are not reflected in the table below. September 30, September 30, ASSETS Cash and cash equivalents $ 83,000 $ 623,000 Accounts and other receivables 175,000 606,000 Oil and natural gas properties, full cost method of accounting: Proved properties, net 544,000 655,000 Total assets $ 802,000 $ 1,884,000 LIABILITIES Accounts payable $ 10,000 $ 15,000 Accrued operating and other expenses 15,000 26,000 Total liabilities $ 25,000 $ 41,000

ASSETS HELD FOR SALE

ASSETS HELD FOR SALE	12 Months Ended
ASSETS HELD FOR SALE	Sep. 30, 2023
Property, Plant and Equipment Assets Held-for-Sale Disclosure [Abstract]
ASSETS HELD FOR SALE	ASSET HELD FOR SALE In September 2022, the Company entered into a purchase and sale agreement with an independent third party for the sale of a contract drilling segment drilling rig and received a payment of $551,000, net of related costs. At September 30, 2022, the legal title for the drilling rig had not yet transferred to the buyer and therefore, the Company did not record a sale during the year ended September 30, 2022. The proceeds received from the buyer was recognized as a deposit and recorded in “Other Current Liabilities” on the Company's Consolidated Balance Sheet at September 30, 2022. No amount was recorded as assets held for sale at September 30, 2022 as the drilling rig was fully depreciated and therefore had a net book value of zero. In October 2022, the legal title for the drilling rig was transferred to the buyer and as a result, the Company recognized a $551,000 gain on the sale of the drilling rig during the year ended September 30, 2023.

OIL AND NATURAL GAS PROPERTIES

OIL AND NATURAL GAS PROPERTIES	12 Months Ended
OIL AND NATURAL GAS PROPERTIES	Sep. 30, 2023
Oil and Natural Gas Properties [Abstract]
OIL AND NATURAL GAS PROPERTIES	OIL AND NATURAL GAS PROPERTIES Fiscal 2023 Investments and Acquisitions In December 2022, Barnwell Texas, LLC (“Barnwell Texas”), a new 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. 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 has paid $4,293,000 for its share of the costs to drill, complete and equip the wells during the year ended September 30, 2023. The two Texas wells began producing in late April 2023. Additionally, in connection with the entry into this agreement, the Company was obligated to pay a broker’s fee of 5.0% of the capital invested under this arrangement, which expired in November 2023, to Four Pines Exploration LLC - Exploration - Series 1 (“Four Pines”). Four Pines is controlled by Mr. Colin O’Farrell who is an affiliate of Teton Barnwell (see Note 19 for additional details). As of September 30, 2023, the Company has paid $255,000 in broker fees to Four Pines related to this arrangement. Fiscal 2022 Acquisitions and Dispositions In the quarter ended December 31, 2021, Barnwell acquired working interests in oil and natural gas properties located in the Twining area of Alberta, Canada, for cash consideration of $317,000. In the quarter ended March 31, 2022, Barnwell acquired additional working interests in oil and natural gas properties located in the Twining area of Alberta, Canada for consideration of $1,246,000. The purchase price per the agreement was adjusted for customary purchase price adjustments to reflect the economic activity from the effective date to the closing date. Barnwell also assumed $1,500,000 in asset retirement obligations associated with the acquisition. There were no significant oil and natural gas property dispositions during the year ended September 30, 2022. The $503,000 of proceeds from sale of oil and natural gas properties included in the Consolidated Statement of Cash Flows for the year ended September 30, 2022 primarily represents the refund of income taxes previously withheld from what otherwise would have been proceeds on fiscal 2021’s oil and natural gas property sales.

PROPERTY AND EQUIPMENT AND ASSE

PROPERTY AND EQUIPMENT AND ASSET RETIREMENT OBLIGATION	12 Months Ended
PROPERTY AND EQUIPMENT AND ASSET RETIREMENT OBLIGATION	Sep. 30, 2023
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, 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 Estimated Gross Accumulated Net At September 30, 2022: Proved oil and natural gas properties $ 67,883,000 $ (54,651,000) $ 13,232,000 Drilling rigs and equipment 3 – 10 years 6,304,000 (5,943,000) 361,000 Other property and equipment 3 – 10 years 619,000 (611,000) 8,000 Total $ 74,806,000 $ (61,205,000) $ 13,601,000 See Note 6 for discussion of acquisitions and divestitures of oil and natural gas properties in fiscal 2023 and 2022. 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, 2023 2022 Asset retirement obligation as of beginning of year $ 8,456,000 $ 7,053,000 Obligations incurred on new wells drilled or acquired 21,000 1,682,000 Liabilities associated with properties sold — (483,000) Revision of estimated obligation 1,462,000 1,021,000 Accretion expense 808,000 767,000 Payments (1,005,000) (942,000) Foreign currency translation adjustment 91,000 (642,000) Asset retirement obligation as of end of year 9,833,000 8,456,000 Less current portion (1,536,000) (1,327,000) Asset retirement obligation, long-term $ 8,297,000 $ 7,129,000 Asset retirement obligations were reduced by nil and $483,000 in fiscal 2023 and 2022, respectively, for those obligations that were assumed by purchasers of Barnwell's oil and natural gas properties. Asset retirement obligations increased by $1,462,000 and $1,021,000 in fiscal 2023 and 2022, respectively, primarily due to upward revisions from acceleration in the estimated timing of future abandonments as a result of changes in the estimated economic lives and costs of certain wells due to updated information received and changes in management's discretionary timing of abandonment projects due to an increase in estimated funds available. Asset retirement obligations also increased by $21,000 and $1,682,000 in fiscal 2023 and 2022, respectively, due primarily to our wells drilled and acquisitions (see Note 6 for additional details on 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 2024. 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, 2023, the Company recognized a cumulative reduction in the deposit balance of $300,000 for work performed under this program.

RETIREMENT PLANS

RETIREMENT PLANS	12 Months Ended
RETIREMENT PLANS	Sep. 30, 2023
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, 2023 2022 2023 2022 Change in Projected Benefit Obligation: Benefit obligation at beginning of year $ 7,931,000 $ 10,365,000 $ 1,715,000 $ 2,136,000 Interest cost 406,000 290,000 88,000 60,000 Actuarial gain (394,000) (2,418,000) (66,000) (478,000) Benefits paid (432,000) (306,000) (3,000) (3,000) Benefit obligation at end of year 7,511,000 7,931,000 1,734,000 1,715,000 Change in Plan Assets: Fair value of plan assets at beginning of year 11,316,000 12,594,000 — — Actual return on plan assets 1,098,000 (972,000) — — Benefits paid (432,000) (306,000) — — Fair value of plan assets at end of year 11,982,000 11,316,000 — — Funded status $ 4,471,000 $ 3,385,000 $ (1,734,000) $ (1,715,000) Pension Plan SERP September 30, 2023 2022 2023 2022 Amounts recognized in the Consolidated Balance Sheets: Noncurrent assets $ 4,471,000 $ 3,385,000 $ — $ — Current liabilities — — (70,000) (66,000) Noncurrent liabilities — — (1,664,000) (1,649,000) Net amount $ 4,471,000 $ 3,385,000 $ (1,734,000) $ (1,715,000) Amounts recognized in accumulated other comprehensive income before income taxes: Net actuarial gain $ (1,178,000) $ (353,000) $ (330,000) $ (343,000) Accumulated other comprehensive income $ (1,178,000) $ (353,000) $ (330,000) $ (343,000) The accumulated benefit obligation for the Pension Plan was $7,511,000 and $7,931,000 at September 30, 2023 and 2022, respectively. The accumulated benefit obligation for the SERP was $1,734,000 and $1,715,000 at September 30, 2023 and 2022, 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 2024. The SERP plan is unfunded and Barnwell funds benefits when payments are made. Expected payments under the SERP for fiscal 2024 is not material. 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 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 Pension Plan actuarial gains in fiscal 2022 were primarily due to an increase in the discount rate, partially offset by an actuarial loss resulting from actual investment returns that were less than the assumed rate of return. The SERP actuarial gains in fiscal 2022 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, 2023 2022 2023 2022 Assumptions used to determine fiscal year-end benefit obligations: Discount rate 5.62% 5.25% 5.62% 5.25% Rate of compensation increase N/A N/A N/A N/A Assumptions used to determine net benefit costs (years ended): Discount rate 5.25% 2.84% 5.25% 2.84% Expected return on plan assets 6.00% 5.00% 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 available on the ICE Bank of America Merrill Lynch AA-AAA 15+ Index 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, 2023 2022 2023 2022 Net periodic benefit (income) cost for the year: Interest cost $ 406,000 $ 290,000 $ 88,000 $ 60,000 Expected return on plan assets (667,000) (622,000) — — Amortization of net actuarial gain — — (79,000) — Net periodic benefit (income) cost $ (261,000) $ (332,000) $ 9,000 $ 60,000 The benefits expected to be paid under the retirement plans as of September 30, 2023 are as follows: Pension Plan SERP Expected Benefit Payments: Fiscal year ending September 30, 2024 $ 402,000 $ 70,000 Fiscal year ending September 30, 2025 $ 552,000 $ 140,000 Fiscal year ending September 30, 2026 $ 545,000 $ 138,000 Fiscal year ending September 30, 2027 $ 537,000 $ 137,000 Fiscal year ending September 30, 2028 $ 574,000 $ 142,000 Fiscal years ending September 30, 2029 through 2033 $ 2,990,000 $ 712,000 Plan Assets Management communicates periodically with its 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 Company’s investment policy permits investments in a diversified mix of U.S. and international equities, fixed income securities and cash equivalents. Barnwell’s investments in fixed income securities include corporate bonds, U.S. treasury and government securities, preferred securities, and fixed income exchange-traded funds. The Company’s investments in equity securities primarily include domestic and international large-cap companies, as well as, domestic and international equity securities exchange-traded funds. The Company’s year-end target allocation, by asset category, and the actual asset allocations were as follows: Target September 30, Asset Category Allocation 2023 2022 Cash and other 0% - 25% 2% 14% Fixed income securities 15% - 40% 32% 34% Equity securities 45% - 75% 66% 52% 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 are categorized as Level 1 assets, and as such, the actual market value is used to determine the fair value of assets. 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, 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 $ — $ — Fair Value Measurements Using: September 30, 2022 Carrying Quoted Significant Significant Financial Assets: Cash $ 1,539,000 $ 1,539,000 $ — $ — Corporate bonds 1,000 1,000 — — U.S. treasury and government securities 561,000 561,000 — — Fixed income exchange-traded funds 3,223,000 3,223,000 — — Preferred securities 67,000 67,000 — — Equity securities exchange-traded funds 408,000 408,000 — — Equities 5,517,000 5,517,000 — — Total $ 11,316,000 $ 11,316,000 $ — $ —

INCOME TAXES

INCOME TAXES	12 Months Ended
INCOME TAXES	Sep. 30, 2023
Income Tax Disclosure [Abstract]
INCOME TAXES	INCOME TAXES The components of (loss) earnings before income taxes, after adjusting the (loss) earnings for non-controlling interests, are as follows: Year ended September 30, 2023 2022 United States $ (2,414,000) $ 739,000 Canada 1,400,000 5,121,000 $ (1,014,000) $ 5,860,000 The components of the income tax (benefit) provision related to the above (loss) earnings are as follows: Year ended September 30, 2023 2022 Current provision: United States – Federal Before operating loss carryforwards $ — $ 727,000 Benefit of operating loss carryforwards — (665,000) After operating loss carryforwards — 62,000 United States – State Before operating loss carryforwards 47,000 518,000 Benefit of operating loss carryforwards — (62,000) After operating loss carryforwards 47,000 456,000 Canadian Before operating loss carryforwards 274,000 510,000 Benefit of operating loss carryforwards (244,000) (510,000) After operating loss carryforwards 30,000 — Total current 77,000 518,000 Deferred benefit: United States – State (130,000) (171,000) Total deferred (130,000) (171,000) $ (53,000) $ 347,000 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. In addition, Canadian jurisdiction net operating loss carryforwards, the benefit of which had not previously been recognized due to the Company's continuing full valuation allowance, were partially utilized in that jurisdiction in the current year. The net operating loss carryforwards beyond the current year’s utilization continue to have a full valuation allowance as realization of their benefit is not more likely than not. Included in the current income tax provision for the year ended September 30, 2022 is a $62,000 expense for income tax penalties and interest thereon for the non-filing of IRS Form 8858 in each of our U.S. federal income tax returns for fiscal years 2019, 2020 and 2021. The Company prepared amended U.S. federal tax returns for each of these years to include Form 8858 and a statement of reasonable cause. The amended returns were filed in September and October 2023 and the Company 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. No additional expenses related to the potential penalties and interest were included in the current income tax provision for the year ended September 30, 2023. A reconciliation between the reported income tax (benefit) expense and the amount computed by multiplying the (loss) earnings attributable to Barnwell before income taxes by the U.S. federal tax rate of 21% is as follows: Year ended September 30, 2023 2022 Tax (benefit) provision computed by applying statutory rate $ (213,000) $ 1,231,000 Increase (decrease) in the valuation allowance 182,000 (1,450,000) Additional effect of the foreign tax provision on the total tax provision (4,000) 130,000 U.S. state income tax (benefit) provision, net of federal effect (9,000) 330,000 U.S. state provision to tax return adjustments (106,000) (45,000) Uncertain tax positions — 62,000 Other 97,000 89,000 $ (53,000) $ 347,000 The U.S. state provision to tax return adjustments in the table above was treated as a separate item in fiscal 2023 due to the significance of its impact on the fiscal 2023 reconciliation, and the corresponding fiscal 2022 amount was reclassified to conform to the current year presentation. The reclassification had no impact on previously reported net earnings, cash flows, total assets, or stockholders' equity. Additionally, the changes in the valuation allowance shown in the table above exclude 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, 2023 2022 Deferred income tax assets: Foreign tax credit carryover under U.S. tax law $ 928,000 $ 953,000 U.S. federal net operating loss carryover 9,406,000 8,258,000 U.S. state unitary net operating loss carryovers 1,177,000 1,117,000 Canadian net operating loss carryovers 1,025,000 877,000 Tax basis of investment in land in excess of book basis under U.S. tax law 25,000 26,000 Property and equipment accumulated book depreciation and depletion in excess of tax under U.S. tax law 275,000 568,000 Asset retirement obligation accrued for books but not for tax under U.S. tax law 1,084,000 959,000 Asset retirement obligation accrued for books but not for tax under Canadian tax law 2,461,000 2,120,000 Other liabilities accrued for books but not for tax under U.S. tax law 612,000 634,000 Foreign currency loss under U.S. tax law 68,000 102,000 Foreign currency loss under Canadian tax law 81,000 124,000 Other 116,000 278,000 Total gross deferred income tax assets 17,258,000 16,016,000 Less valuation allowance (12,439,000) (12,608,000) Net deferred income tax assets 4,819,000 3,408,000 Deferred income tax liabilities: Property and equipment accumulated tax depreciation and depletion in excess of book under Canadian tax law (926,000) (280,000) Book basis of investment in land development partnerships in excess of tax basis under U.S. tax law (133,000) (545,000) Book basis of investment in land development partnerships in excess of tax basis under U.S. state non-unitary tax law (40,000) (166,000) U.S. oil and gas property and equipment accumulated tax depreciation and depletion in excess of book under U.S. tax law (906,000) (121,000) U.S. oil and gas property and equipment accumulated tax depreciation and depletion in excess of book under U.S. state tax law (19,000) (23,000) U.S. tax law impact of foreign branch deferred tax asset under Canadian tax law (1,655,000) (1,465,000) Retirement plan asset accrued for books but not for tax under U.S. tax law (939,000) (711,000) Other (259,000) (285,000) Total deferred income tax liabilities (4,877,000) (3,596,000) Net deferred income tax liability $ (58,000) $ (188,000) Reported as: Deferred income tax assets — — Deferred income tax liabilities (58,000) (188,000) Net deferred income tax liability $ (58,000) $ (188,000) The asset retirement obligation accrued for books but not for tax under U.S. tax law and the retirement plan asset accrued for books but not for tax under U.S. tax law amounts in the table above were treated as separate items in fiscal 2023 to provide additional specificity as to the nature of the items, and the corresponding fiscal 2022 amounts were reclassified to conform to the current year presentation. The reclassifications had no impact on the previously reported valuation allowance or previously reported net earnings, cash flows, total assets, or stockholders' equity. The total valuation allowance decreased $169,000 for the year ended September 30, 2023. The decrease 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 decrease in the valuation allowance for fiscal 2023, $4,000 was recognized as an income tax benefit and $165,000 was credited to accumulated other comprehensive income. Net deferred tax assets at September 30, 2023 of $4,819,000 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, retirement plan assets accrued for books but not for tax under U.S. tax law, and certain other minor deferred tax liabilities. At September 30, 2023, 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 $928,000, $44,790,000, $18,387,000 and $3,816,000, respectively. All four items were fully offset by valuation allowances at September 30, 2023. 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 2039-2043, and the foreign tax credit carryovers expire in fiscal years 2024-2025. The U.S. federal net operating loss carryovers generated in fiscal years 2019-2023 and the U.S. state net operating loss carryovers generated in fiscal years 2018-2023 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 resolution for an amount less than the amount estimated by Barnwell would be recognized as a decrease in the effective income tax rate in the period of resolution, and unfavorable resolution in excess of the amount estimated by Barnwell would be recognized as an increase in the effective income tax rate in the period of resolution. Below are the changes in unrecognized tax benefits. Year ended September 30, 2023 2022 Balance at beginning of year $ 62,000 $ — Effect of tax positions taken in prior years — 60,000 Accrued interest related to tax positions taken — 2,000 Balance at end of year $ 62,000 $ 62,000 Uncertain tax positions at September 30, 2023 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, 2023: Jurisdiction Fiscal Years Open U.S. federal 2020 – 2022 Various U.S. states 2020 – 2022 Canada federal 2016 – 2022 Various Canadian provinces 2016 – 2022

REVENUE FROM CONTRACTS WITH CUS

REVENUE FROM CONTRACTS WITH CUSTOMERS	12 Months Ended
REVENUE FROM CONTRACTS WITH CUSTOMERS	Sep. 30, 2023
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, 2023 and 2022. 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 Year ended September 30, 2022 Oil and natural gas Contract drilling Land investment Other Total Revenue streams: Oil $ 15,747,000 $ — $ — $ — $ 15,747,000 Natural gas 4,527,000 — — — 4,527,000 Natural gas liquids 2,307,000 — — — 2,307,000 Drilling and pump — 4,540,000 — — 4,540,000 Contingent residual payments — — 1,295,000 — 1,295,000 Other — — — 111,000 111,000 Total revenues before interest income $ 22,581,000 $ 4,540,000 $ 1,295,000 $ 111,000 $ 28,527,000 Geographical regions: United States $ 3,496,000 $ 4,540,000 $ 1,295,000 $ 9,000 $ 9,340,000 Canada 19,085,000 — — 102,000 19,187,000 Total revenues before interest income $ 22,581,000 $ 4,540,000 $ 1,295,000 $ 111,000 $ 28,527,000 Timing of revenue recognition: Goods transferred at a point in time $ 22,581,000 $ — $ 1,295,000 $ 111,000 $ 23,987,000 Services transferred over time — 4,540,000 — — 4,540,000 Total revenues before interest income $ 22,581,000 $ 4,540,000 $ 1,295,000 $ 111,000 $ 28,527,000 Contract Balances The following table provides information about accounts receivables, contract assets and contract liabilities from contracts with customers: September 30, 2023 2022 2021 Accounts receivables from contracts with customers $ 2,931,000 $ 4,038,000 $ 2,797,000 Contract assets 958,000 580,000 581,000 Contract liabilities 377,000 1,087,000 455,000 Accounts receivables from contracts with customers are included in “Accounts and other receivables, net of allowance for doubtful accounts,” 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, 2023 and 2022, the Company had $377,000 and $1,087,000, 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, 2023 and 2022, the amount of revenue recognized that was previously included in contract liabilities as of the beginning of the respective period was $1,015,000 and $394,000, 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, 2023, the Company had five contract drilling jobs with original expected durations of greater than one year. For these contracts, 100% of the remaining performance obligation of $3,587,000 is expected to be recognized in the next twelve months. 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, 2023 and 2022, the Company had $504,000 and $689,000, respectively, in unamortized preconstruction costs related to contracts that were not completed. During the years ended September 30, 2023 and 2022, the amortization of preconstruction costs related to contracts was $326,000 and $296,000, 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, 2023 and 2022. 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, 2023 and 2022, uninstalled materials was $348,000 and $351,000, 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
SEGMENT AND GEOGRAPHIC INFORMATION	Sep. 30, 2023
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) investing in 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, 2023 2022 Revenues: Oil and natural gas $ 19,376,000 $ 22,581,000 Contract drilling 5,427,000 4,540,000 Land investment 265,000 1,295,000 Other 114,000 111,000 Total before interest income 25,182,000 28,527,000 Interest income 87,000 18,000 Total revenues $ 25,269,000 $ 28,545,000 Depletion, depreciation, and amortization: Oil and natural gas $ 4,269,000 $ 2,606,000 Contract drilling 186,000 171,000 Other 2,000 1,000 Total depletion, depreciation, and amortization $ 4,457,000 $ 2,778,000 Impairment: Land investment $ — $ 89,000 Total impairment $ — $ 89,000 Operating profit (loss) (before general and administrative expenses): Oil and natural gas $ 4,673,000 $ 10,536,000 Contract drilling (428,000) (222,000) Land investment 265,000 1,206,000 Other 112,000 110,000 Gain on sale of assets 551,000 — Total operating profit 5,173,000 11,630,000 Equity in income of affiliates: Land investment 758,000 3,400,000 General and administrative expenses (6,956,000) (8,044,000) Foreign currency gain (loss) 76,000 (484,000) Interest expense (2,000) (1,000) Interest income 87,000 18,000 (Loss) earnings before income taxes $ (864,000) $ 6,519,000 Capital Expenditures: Year ended September 30, 2023 2022 Oil and natural gas $ 12,212,000 $ 13,755,000 Contract drilling 314,000 45,000 Other 14,000 5,000 Total $ 12,540,000 $ 13,805,000 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 7 for additional details). Assets By Segment: September 30, 2023 2022 Oil and natural gas: Canada $ 18,855,000 $ 16,216,000 United States 5,917,000 1,261,000 Contract drilling (1) 3,100,000 3,260,000 Other: Cash and cash equivalents 2,830,000 12,804,000 Asset for retirement benefits 4,471,000 3,385,000 Corporate and other 248,000 289,000 Total $ 35,421,000 $ 37,215,000 ______________ (1) L ocated in Hawaii. Long-Lived Assets By Geographic Area: September 30, 2023 2022 United States $ 10,373,000 $ 4,540,000 Canada 15,963,000 12,578,000 Total $ 26,336,000 $ 17,118,000 Revenue By Geographic Area: Year ended September 30, 2023 2022 United States $ 8,448,000 $ 9,340,000 Canada 16,734,000 19,187,000 Total (excluding interest income) $ 25,182,000 $ 28,527,000

ACCUMULATED OTHER COMPREHENSIVE

ACCUMULATED OTHER COMPREHENSIVE INCOME	12 Months Ended
ACCUMULATED OTHER COMPREHENSIVE INCOME	Sep. 30, 2023
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, 2023 2022 Foreign currency translation: Beginning accumulated foreign currency translation $ 222,000 $ 262,000 Change in cumulative translation adjustment before reclassifications (2,000) (40,000) Income taxes — — Net current period other comprehensive loss (2,000) (40,000) Ending accumulated foreign currency translation 220,000 222,000 Retirement plans: Beginning accumulated retirement plans benefit cost 1,072,000 (230,000) Amortization of net actuarial gain (79,000) — Net actuarial gain arising during the period 891,000 1,302,000 Income taxes — — Net current period other comprehensive income 812,000 1,302,000 Ending accumulated retirement plans benefit income 1,884,000 1,072,000 Accumulated other comprehensive income, net of taxes $ 2,104,000 $ 1,294,000 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 8 for additional details).

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS	12 Months Ended
FAIR VALUE MEASUREMENTS	Sep. 30, 2023
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 significant Level 3 assumptions used in the calculation of estimated discounted cash flows 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 6 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 7, 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.

DEBT

DEBT	12 Months Ended
DEBT	Sep. 30, 2023
Debt Disclosure [Abstract]
DEBT	DEBT Canada Emergency Business Account Loan In the quarter ended December 31, 2020, the Company’s Canadian subsidiary, Barnwell of Canada, received an interest-free loan of CAD$40,000 (in Canadian dollars) under the Canada Emergency Business Account (“CEBA”) loan program for small businesses. In the quarter ended March 31, 2021, the Company applied for an increase to our CEBA loan and received an additional CAD$20,000 for a total loan amount received of CAD$60,000 ($45,000) under the program. The CEBA loan was interest-free with no principal payments required until December 31, 2023 and if the Company repaid 66.7% of the principal amount prior to December 31, 2023, 33.3% of the loan would be forgiven. In September 2023, the Company repaid the loan balance of CAD$40,000 and the remaining loan balance of CAD$20,000 was forgiven per the terms of the CEBA loan agreement. Accordingly, as a result of the loan forgiveness, the Company recognized a gain on debt extinguishment of $15,000 during the year ended September 30, 2023, which was included in the “Gas processing and other” line item in the accompanying Consolidated Statements of Operations.

LEASES

LEASES	12 Months Ended
LEASES	Sep. 30, 2023
Leases [Abstract]
LEASES	LEASES The Company’s right-of-use (“ROU”) assets and lease liabilities at September 30, 2023, 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. In fiscal 2022, the Company determined that the right-of-use asset related to the operating lease for the Lot 4C leasehold land zoned conservation held by Kaupulehu Developments was fully impaired as of September 30, 2022. As a result, the Company recognized an $89,000 right-of-use asset impairment expense in the year ended September 30, 2022. Leases recorded on the balance sheet consist of the following: September 30, 2023 2022 Assets: Operating lease right-of-use assets $ 54,000 $ 132,000 Total right-of-use assets $ 54,000 $ 132,000 Liabilities: Current portion of operating lease liabilities (1) $ 71,000 $ 105,000 Operating lease liabilities 47,000 117,000 Total lease liabilities $ 118,000 $ 222,000 ______________ (1) Amount included in “Other Current Liabilities” in the Consolidated Balance Sheets . The components of lease expense are as follows: Year ended September 30, 2023 2022 Operating lease cost $ 88,000 $ 108,000 Short-term lease cost 347,000 327,000 Variable lease cost 136,000 154,000 Total lease cost $ 571,000 $ 589,000 Supplemental information related to leases is as follows: September 30, 2023 2022 Cash paid related to operating lease liabilities $ 114,000 $ 108,000 Operating leases: Weighted-average remaining lease term (in years) 1.7 2.4 Weighted-average discount rate 5.53% 5.30% The remaining lease payments for our operating leases as of September 30, 2023, are as follows: Fiscal year ending: 2024 $ 75,000 2025 41,000 2026 8,000 2027 — 2028 — Thereafter — Total lease payments 124,000 Less: amounts representing interest (6,000) Present value of lease liabilities $ 118,000 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
STOCKHOLDERS' EQUITY	Sep. 30, 2023
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, 2023, a total of 1,095,000 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. 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, 2022 through September 30, 2023: Options Shares Weighted- Weighted- Aggregate Outstanding at October 1, 2022 615,000 $ 3.36 Granted — — Exercised — — Expired/Forfeited (150,000) 3.33 Outstanding at September 30, 2023 465,000 $ 3.37 6.7 $ — Exercisable at September 30, 2023 310,000 $ 3.37 6.7 $ — 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, 2023 and 2022, the Company recognized share-based compensation expense related to stock options of $164,000 and $657,000, respectively. There was no impact on income taxes for the years ended September 30, 2023 and 2022 due to a full valuation allowance on the related deferred tax asset. As of September 30, 2023, the total remaining unrecognized compensation cost related to nonvested stock options was $50,000, which is expected to be recognized over the weighted-average remaining requisite service period of 0.4 years. Restricted Stock Units On June 9, 2023, the Board of Directors of the Company granted a total of 37,312 restricted stock units to the independent directors of the Board as partial payment of fiscal 2023 director fees for their service as members of the Board from the period of April 1, 2023 to September 30, 2023. The restricted stock units vested and became nonforfeitable on September 30, 2023. The following table summarizes Barnwell’s restricted stock units activity from October 1, 2022 through September 30, 2023: Restricted Stock Units Shares Weighted-Average Nonvested at October 1, 2022 — $ — Granted 37,312 2.65 Vested (1) (37,312) 2.65 Forfeited — — Nonvested at September 30, 2023 — $ — ______________ (1) The underlying common stock for these vested restricted stock units were not yet issued as of September 30, 2023; in November 2023, the Company issued 9,328 shares of common stock for a portion of 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 year ended September 30, 2023, the Company recognized share-based compensation expense related to vested restricted stock units of $99,000. There was no share-based compensation expense related to restricted stock units recognized during the year ended September 30, 2022. There was no impact on income taxes for the year ended September 30, 2023 due to a net operating loss and net operating loss carryforwards with a full valuation allowance in the relevant taxing jurisdiction. 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 The following table sets forth the cash dividends paid per share of common stock during fiscal 2023 and 2022. 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 August 23, 2022 September 6, 2022 $0.015 The Tax Benefits Preservation Plan On October 17, 2022, the Board of Directors of the Company adopted a Tax Benefits Preservation Plan (the “Tax Plan”) designed to protect the availability of the Company’s existing net operating loss carryforwards and certain other tax attributes. To implement the Tax Plan, the Board of Directors declared a dividend of one right (a “Right”) for each outstanding share of the Company's common stock. On January 25, 2023, the Tax Plan was terminated by the Board of Directors and as a result, all Rights distributed to holders of the Company's common stock expired at the time of termination. At The Market Offering On March 16, 2021, the Company entered into a Sales Agreement (the “Sales Agreement”) with A.G.P./Alliance Global Partners (“A.G.P,”), with respect to an at-the-market offering program (“ATM”) pursuant to which the Company may offer and sell, from time to time, shares of its common stock, par value $0.50 per share, having an aggregate sales price of up to $25 million (subject to certain limitations set forth in the Sales Agreement and applicable securities laws, rules and regulations), through or to A.G.P as the Company’s sales agent or as principal. Sales of our common stock under the ATM, if any, will be made by any methods deemed to be “at the market offerings” as defined in Rule 415(a)(4) under the Securities Act, including sales made directly on the NYSE American, on any other existing trading market for our Common Stock, or to or through a market maker. Shares of common stock sold under the ATM are offered pursuant to the Company’s Registration Statement on Form S-3 (File No. 333-254365), filed with the Securities and Exchange Commission on March 16, 2021, and declared effective on March 26, 2021 (the "Registration Statement”), and the prospectus dated March 26, 2021, included in the Registration Statement.

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	12 Months Ended
COMMITMENTS AND CONTINGENCIES	Sep. 30, 2023
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, 2023, 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, 2023. 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 the quarter ended December 31, 2021, it was determined that a contract drilling segment well completed in the period did not meet the contract specifications for plumbness under a gyroscopic plumbness test which the contract required. While the well did pass the cage plumbness test, the contract uses the gyroscopic test as the measure of plumbness. Barnwell and the customer currently have an arrangement where Barnwell will provide for centralizers, armored cabling and a pump installation and removal test to confirm that plumbness is satisfactory. The pump installation and removal test was successfully completed. Barnwell’s management believes the plumbness deviation is not impactful to the performance of the submersible pumps that will be installed in the well. Accordingly, while costs for the centralizers, armored cabling and the pump installation and removal test have been accrued, no accrual has been recorded as of September 30, 2023 for any further costs related to this contract as there is no related probable or estimable contingent liability. 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, and no subsequent revision to the accrual has been recorded as of September 30, 2023. During the year ended September 30, 2023, one of our water well drilling jobs encountered an unusually hard geological formation, and the drilling has taken longer than previously anticipated which required an increase in estimated costs and resulted in the job becoming a loss job for which the Company recorded a $180,000 liability as of September 30, 2023. Other Matters 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. The fees represent 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 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, 2023
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, 2023 2022 Increase (decrease) from changes in: Receivables $ 1,103,000 $ (1,763,000) Income tax receivable (16,000) 15,000 Other current assets (51,000) (531,000) Accounts payable (595,000) 110,000 Accrued compensation (278,000) (48,000) Other current liabilities (556,000) 1,190,000 Decrease from changes in current assets and liabilities $ (393,000) $ (1,027,000) Supplemental disclosure of cash flow information: Cash paid (received) during the year for: Income taxes paid (refunded), net $ 100,000 $ (98,000)

RELATED PARTY TRANSACTIONS

RELATED PARTY TRANSACTIONS	12 Months Ended
RELATED PARTY TRANSACTIONS	Sep. 30, 2023
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 3. During the year ended September 30, 2023, Barnwell received $265,000 in percentage of sales payments from KD I from the sale of one lot within Increment I. During the year ended September 30, 2022, Barnwell received $1,295,000 in percentage of sales payments from KD I from the sale of six lots within Increment I. Mr. Colin R. O'Farrell, formerly a member of the Board of Directors of the Company from July 7, 2021 to March 7, 2022, is the sole member of Four Pines Operating LLC which owns a 25% interest in Gros Ventre. In February 2021, Gros Ventre and BOK, a wholly-owned subsidiary of Barnwell, entered into the Teton Operating Agreement of Teton Barnwell, an entity formed for the purpose of directly investing in oil and natural gas exploration and development in Oklahoma. Under the terms of the Teton Operating Agreement, Gros Ventre makes no capital contributions and receives 2% of the profits of Teton Barnwell. Additionally, as the manager of Teton Barnwell, Gros Venture is paid an annual asset management fee equal to 1% of the cumulative capital contributions made to Teton Barnwell as compensation for its management services. Furthermore, as discussed above, Mr. O'Farrell controls Four Pines, which, as of September 30, 2023, was paid $255,000 in broker fees in connection with the oil and natural gas investment discussed in Note 6. Cooperation and Support Agreement In January 2023, the Company entered into a cooperation and support agreement (the “Cooperation Agreement”) with Alexander C. Kinzler , the Company’s CEO and President in his capacity as a stockholder , MRMP-Managers LLC, the Ned L. Sherwood Revocable Trust, NLS Advisory Group, Inc. and Ned L. Sherwood (collectively, the “MRMP Stockholders”), with respect to a potential proxy contest pertaining to the election of directors to our Board of Directors (the “Board”). The Cooperation Agreement extended for two years the standstill terms of the previous agreement entered into with the MRMP Stockholders in 2021, which ended the potential of a proxy contest at the 2023 annual meeting of stockholders (the “2023 Annual Meeting”), which was held on April 17, 2023. Pursuant to the terms of the Cooperation Agreement, among other things, the Company agreed to promptly appoint Joshua S. Horowitz and Laurance Narbut, effective February 9, 2023, to serve on the Board. In addition, the Company agreed to nominate a five-person board comprised of Mr. Kinzler, Kenneth Grossman, Douglas Woodrum, and Messrs. Horowitz and Narbut as candidates for election to the Board at the 2023 Annual Meeting and the 2024 annual meeting of stockholders (the “2024 Annual Meeting”) and Mr. Kinzler and the MRMP Stockholders agreed to vote their respective shares of common stock of the Company in favor of the election of the Company’s slate at the 2023 Annual Meeting and the 2024 Annual Meeting. Additionally, pursuant to the terms of the Cooperation Agreement, the Company terminated the previously adopted Tax Benefits Preservation Plan, although the MRMP Stockholders have agreed to limit their beneficial and economic ownership of the Company to 28% of the outstanding common stock of the Company for the next 12 months and 30% for the subsequent 12-month period. In exchange for this arrangement, the Company agreed to reimburse the MRMP Stockholders and Mr. Kinzler for their reasonable, documented out-of-pocket fees and expenses (including legal expenses) in connection with the negotiation and execution of the Cooperation Agreement and the transactions contemplated hereby and the proposed nomination of directors at the 2023 Annual Meeting. During the year ended September 30, 2023 , $202,000 and $149,000 in expenses were recorded for reimbursements to MRMP Stockholders and Mr. Kinzler, respectively, under the Cooperation Agreement. In May 2023, the Company’s Board of Directors approved and ratified the payment of one-time special director fees to directors Messrs. Grossman and Woodrum for their services on behalf of the Company and the Board pertaining to the negotiations of the Cooperation Agreement and the settlement of

SUBSEQUENT EVENTS

SUBSEQUENT EVENTS	12 Months Ended
SUBSEQUENT EVENTS	Sep. 30, 2023
Subsequent Events [Abstract]
SUBSEQUENT EVENTS	SUBSEQUENT EVENTS Restricted Stock Units In November 2023, the Board of Directors of the Company granted a total of 76,366 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. Natural Gas and Oil Contracts In November 2023, the Company amended certain of its Canadian purchase and sales contracts to change the sales price on a portion of the natural gas it sells to a fixed price during the period from April 1, 2024 to October 31, 2024. With these changes, the Company anticipates that during that period approximately 25% of its Canadian natural gas production will be sold at fixed prices while the remaining 75% of such production will continue to be sold at spot prices. In December 2023, the Company amended certain of its Canadian purchase and sales contract to change the sales price on a portion of the oil it sells to a fixed price during the period from January 1, 2024 to June 30, 2024. With these changes, the Company anticipates that during that period approximately 40% of its Canadian oil production will be sold at fixed prices while the remaining 60% of such production will continue to be sold at spot prices. Sale of Water Resources

SUMMARY OF SELECTED QUARTERLY F

SUMMARY OF SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)	12 Months Ended
SUMMARY OF SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)	Sep. 30, 2023
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
SUPPLEMENTARY OIL AND NATURAL GAS INFORMATION (UNAUDITED)	Sep. 30, 2023
Oil and Gas Exploration and Production Industries Disclosures [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 reports of our independent petroleum reserve engineers, Ryder Scott, and are included as Exhibits 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. 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 & NGL Canada United States Total Proved reserves: Balance at September 30, 2021 640,000 — 640,000 Revisions of previous estimates 154,000 — 154,000 Extensions, discoveries and other additions 285,000 132,000 417,000 Acquisitions of reserves 99,000 — 99,000 Less production (188,000) (42,000) (230,000) Balance at September 30, 2022 990,000 90,000 1,080,000 Revisions of previous estimates (42,000) 48,000 6,000 Extensions, discoveries and other additions 199,000 197,000 396,000 Less production (210,000) (46,000) (256,000) Proved Reserves, September 30, 2023 937,000 289,000 1,226,000 Proved Developed Reserves, September 30, 2023 827,000 289,000 1,116,000 Proved Undeveloped Reserves, September 30, 2023 110,000 — 110,000 Natural Gas Canada United States Total Proved reserves: Balance at September 30, 2021 2,913,000 — 2,913,000 Revisions of previous estimates 968,000 — 968,000 Extensions, discoveries and other additions 1,200,000 658,000 1,858,000 Acquisitions of reserves 223,000 — 223,000 Less sales of reserves (13,000) — (13,000) Less production (772,000) (192,000) (964,000) 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) Proved Reserves, September 30, 2023 5,010,000 1,691,000 6,701,000 Proved Developed Reserves, September 30, 2023 4,402,000 1,691,000 6,093,000 Proved Undeveloped Reserves, September 30, 2023 608,000 — 608,000 Total Equivalent Reserves Canada United States Total Proved reserves: Balance at September 30, 2021 1,142,000 — 1,142,000 Revisions of previous estimates 321,000 — 321,000 Extensions, discoveries and other additions 492,000 245,000 737,000 Acquisitions of reserves 137,000 — 137,000 Less sales of reserves (2,000) — (2,000) Less production (321,000) (75,000) (396,000) 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) Proved Reserves, September 30, 2023 1,772,000 571,000 2,343,000 Proved Developed Reserves, September 30, 2023 1,561,000 571,000 2,132,000 Proved Undeveloped Reserves, September 30, 2023 211,000 — 211,000 (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, 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 September 30, 2022 Canada United States Total Proved properties $ 66,825,000 $ 1,058,000 $ 67,883,000 Unproved properties — — — Total capitalized costs 66,825,000 1,058,000 67,883,000 Accumulated depletion, depreciation, and impairment 54,248,000 403,000 54,651,000 Net capitalized costs $ 12,577,000 $ 655,000 $ 13,232,000 (C) Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development 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 Year ended September 30, 2022 Canada United States Total Acquisition of properties: Proved $ 3,247,000 $ — $ 3,247,000 Unproved — — — Exploration costs 55,000 — 55,000 Development costs 10,574,000 (121,000) 10,453,000 Total $ 13,876,000 $ (121,000) $ 13,755,000 Costs incurred in the tables above include additions and revisions to Barnwell’s asset retirement obligation of $1,483,000 and $2,703,000 for the years ended September 30, 2023 and 2022, respectively. (D) Results of Operations for Oil and Natural Gas Producing Activities 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 Year ended September 30, 2022 Canada United States Total Net revenues $ 19,085,000 $ 3,496,000 $ 22,581,000 Production costs (8,999,000) (440,000) (9,439,000) Depletion (2,217,000) (389,000) (2,606,000) Pre-tax results of operations (1) 7,869,000 2,667,000 10,536,000 Estimated income tax expense (2) — 107,000 107,000 Results of operations (1) $ 7,869,000 $ 2,560,000 $ 10,429,000 _________________ (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, 2023 and 2022 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, 2023 and 2022 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, 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 Year ended September 30, 2022 Canada United States Total Future cash inflows $ 93,658,000 $ 6,676,000 $ 100,334,000 Future production costs (44,523,000) (832,000) (45,355,000) Future development costs (274,000) — (274,000) Future income tax expenses (6,908,000) (233,000) (7,141,000) Future net cash flows excluding abandonment, decommissioning and reclamation 41,953,000 5,611,000 47,564,000 Future abandonment, decommissioning and reclamation (16,719,000) (11,000) (16,730,000) Future net cash flows 25,234,000 5,600,000 30,834,000 10% annual discount for timing of cash flows (1,144,000) (1,812,000) (2,956,000) Standardized measure of discounted future net cash flows $ 24,090,000 $ 3,788,000 $ 27,878,000 Changes in the Standardized Measure of Discounted Future Net Cash Flows Year ended September 30, 2023 2022 Beginning of year $ 27,878,000 $ 2,645,000 Sales of oil and natural gas produced, net of production costs (8,942,000) (13,142,000) Net changes in prices and production costs, net of royalties and wellhead taxes (11,913,000) 27,828,000 Extensions and discoveries 10,767,000 8,889,000 Net change due to purchases and sales of minerals in place — 2,451,000 Changes in future development costs (2,959,000) — Revisions of previous quantity estimates 2,227,000 4,270,000 Net change in income taxes 2,868,000 (4,774,000) Accretion of discount 905,000 (1,566,000) Other - changes in the timing of future production and other (1,202,000) 801,000 Other - net change in Canadian dollar translation rate 284,000 476,000 Net change (7,965,000) 25,233,000 End of year $ 19,913,000 $ 27,878,000

SUMMARY OF SIGNIFICANT ACCOUN_2

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	12 Months Ended
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	Sep. 30, 2023
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), a 75%-owned land investment partnership (KD Kona), and a variable interest entity (Teton Barnwell Fund I, LLC) for which the Company is deemed to be the primary beneficiary. 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.
Reclassifications	Reclassifications Certain reclassifications of prior period amounts have been made in Note 9 to conform to the current period presentations. These reclassifications had no effect on previously reported net earnings, cash flows, total assets, or stockholders' equity.
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 invests in 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 doubtful accounts is Barnwell’s best estimate of the amount of probable credit losses in Barnwell’s existing accounts receivable and is based on historical write-off experience and the application of the specific identification method. 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. Entities that have been determined to be VIEs and for which we have a controlling financial interest and are therefore the VIE’s primary beneficiary are consolidated (see Note 4). Entities that have been determined to be VIEs and for which we do not have a controlling financial interest and are therefore not the VIE’s primary beneficiary are not consolidated. These unconsolidated entities are accounted for under the equity method (see Note 3).
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.
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, 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 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
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 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 8. 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 $59,000 based on the assets of the plan at September 30, 2023.
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.
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.

(LOSS) EARNINGS PER COMMON SH_2

(LOSS) EARNINGS PER COMMON SHARE (Tables)	12 Months Ended
(LOSS) EARNINGS PER COMMON SHARE (Tables)	Sep. 30, 2023
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) earnings attributable to Barnwell stockholders and common shares outstanding of the basic and diluted net (loss) earnings per share computations are detailed in the following tables: Year ended September 30, 2023 Net Loss Shares Per-Share (Numerator) (Denominator) Amount Basic net loss $ (961,000) 9,969,856 $ (0.10) Effect of dilutive securities - common stock options and restricted stock units — — Diluted net loss $ (961,000) 9,969,856 $ (0.10) Year ended September 30, 2022 Net Earnings Shares Per-Share (Numerator) (Denominator) Amount Basic net earnings $ 5,513,000 9,732,936 $ 0.57 Effect of dilutive securities - common stock options — — Diluted net earnings $ 5,513,000 9,732,936 $ 0.57

INVESTMENTS (Tables)

INVESTMENTS (Tables)	12 Months Ended
INVESTMENTS (Tables)	Sep. 30, 2023
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, 2023 2022 Revenue $ 13,055,000 $ 24,577,000 Gross profit $ 7,733,000 $ 16,934,000 Net earnings $ 4,436,000 $ 13,763,000
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, 2023 2022 Sale of interest in leasehold land: Revenues - sale of interest in leasehold land $ 265,000 $ 1,295,000 Fees - included in general and administrative expenses (32,000) (158,000) Sale of interest in leasehold land, net of fees paid $ 233,000 $ 1,137,000

CONSOLIDATED VARIABLE INTERES_2

CONSOLIDATED VARIABLE INTEREST ENTITY (Tables)	12 Months Ended
CONSOLIDATED VARIABLE INTEREST ENTITY (Tables)	Sep. 30, 2023
Variable Interest Entity, Primary Beneficiary, Does Not Hold Majority Voting Interest, Disclosures [Abstract]
Schedule of assets and liabilities of variable interest entity	The following table summarizes the carrying value of the assets and liabilities of Teton Barnwell that are consolidated by the Company. Intercompany balances are eliminated in consolidation and thus, are not reflected in the table below. September 30, September 30, ASSETS Cash and cash equivalents $ 83,000 $ 623,000 Accounts and other receivables 175,000 606,000 Oil and natural gas properties, full cost method of accounting: Proved properties, net 544,000 655,000 Total assets $ 802,000 $ 1,884,000 LIABILITIES Accounts payable $ 10,000 $ 15,000 Accrued operating and other expenses 15,000 26,000 Total liabilities $ 25,000 $ 41,000

PROPERTY AND EQUIPMENT AND AS_2

PROPERTY AND EQUIPMENT AND ASSET RETIREMENT OBLIGATION (Tables)	12 Months Ended
	Sep. 30, 2023
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, 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 Estimated Gross Accumulated Net At September 30, 2022: Proved oil and natural gas properties $ 67,883,000 $ (54,651,000) $ 13,232,000 Drilling rigs and equipment 3 – 10 years 6,304,000 (5,943,000) 361,000 Other property and equipment 3 – 10 years 619,000 (611,000) 8,000 Total $ 74,806,000 $ (61,205,000) $ 13,601,000
Schedule of reconciliation of the asset retirement obligation	The following is a reconciliation of the asset retirement obligation: Year ended September 30, 2023 2022 Asset retirement obligation as of beginning of year $ 8,456,000 $ 7,053,000 Obligations incurred on new wells drilled or acquired 21,000 1,682,000 Liabilities associated with properties sold — (483,000) Revision of estimated obligation 1,462,000 1,021,000 Accretion expense 808,000 767,000 Payments (1,005,000) (942,000) Foreign currency translation adjustment 91,000 (642,000) Asset retirement obligation as of end of year 9,833,000 8,456,000 Less current portion (1,536,000) (1,327,000) Asset retirement obligation, long-term $ 8,297,000 $ 7,129,000

RETIREMENT PLANS (Tables)

RETIREMENT PLANS (Tables)	12 Months Ended
RETIREMENT PLANS (Tables)	Sep. 30, 2023
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, 2023 2022 2023 2022 Change in Projected Benefit Obligation: Benefit obligation at beginning of year $ 7,931,000 $ 10,365,000 $ 1,715,000 $ 2,136,000 Interest cost 406,000 290,000 88,000 60,000 Actuarial gain (394,000) (2,418,000) (66,000) (478,000) Benefits paid (432,000) (306,000) (3,000) (3,000) Benefit obligation at end of year 7,511,000 7,931,000 1,734,000 1,715,000 Change in Plan Assets: Fair value of plan assets at beginning of year 11,316,000 12,594,000 — — Actual return on plan assets 1,098,000 (972,000) — — Benefits paid (432,000) (306,000) — — Fair value of plan assets at end of year 11,982,000 11,316,000 — — Funded status $ 4,471,000 $ 3,385,000 $ (1,734,000) $ (1,715,000)
Schedule of amounts recognized in the consolidated balance sheets	Pension Plan SERP September 30, 2023 2022 2023 2022 Amounts recognized in the Consolidated Balance Sheets: Noncurrent assets $ 4,471,000 $ 3,385,000 $ — $ — Current liabilities — — (70,000) (66,000) Noncurrent liabilities — — (1,664,000) (1,649,000) Net amount $ 4,471,000 $ 3,385,000 $ (1,734,000) $ (1,715,000) Amounts recognized in accumulated other comprehensive income before income taxes: Net actuarial gain $ (1,178,000) $ (353,000) $ (330,000) $ (343,000) Accumulated other comprehensive income $ (1,178,000) $ (353,000) $ (330,000) $ (343,000)
Schedule of amounts recognized in accumulated other comprehensive (loss) income	Pension Plan SERP September 30, 2023 2022 2023 2022 Amounts recognized in the Consolidated Balance Sheets: Noncurrent assets $ 4,471,000 $ 3,385,000 $ — $ — Current liabilities — — (70,000) (66,000) Noncurrent liabilities — — (1,664,000) (1,649,000) Net amount $ 4,471,000 $ 3,385,000 $ (1,734,000) $ (1,715,000) Amounts recognized in accumulated other comprehensive income before income taxes: Net actuarial gain $ (1,178,000) $ (353,000) $ (330,000) $ (343,000) Accumulated other comprehensive income $ (1,178,000) $ (353,000) $ (330,000) $ (343,000)
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, 2023 2022 2023 2022 Assumptions used to determine fiscal year-end benefit obligations: Discount rate 5.62% 5.25% 5.62% 5.25% Rate of compensation increase N/A N/A N/A N/A Assumptions used to determine net benefit costs (years ended): Discount rate 5.25% 2.84% 5.25% 2.84% Expected return on plan assets 6.00% 5.00% 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, 2023 2022 2023 2022 Net periodic benefit (income) cost for the year: Interest cost $ 406,000 $ 290,000 $ 88,000 $ 60,000 Expected return on plan assets (667,000) (622,000) — — Amortization of net actuarial gain — — (79,000) — Net periodic benefit (income) cost $ (261,000) $ (332,000) $ 9,000 $ 60,000
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, 2023 are as follows: Pension Plan SERP Expected Benefit Payments: Fiscal year ending September 30, 2024 $ 402,000 $ 70,000 Fiscal year ending September 30, 2025 $ 552,000 $ 140,000 Fiscal year ending September 30, 2026 $ 545,000 $ 138,000 Fiscal year ending September 30, 2027 $ 537,000 $ 137,000 Fiscal year ending September 30, 2028 $ 574,000 $ 142,000 Fiscal years ending September 30, 2029 through 2033 $ 2,990,000 $ 712,000
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 2023 2022 Cash and other 0% - 25% 2% 14% Fixed income securities 15% - 40% 32% 34% Equity securities 45% - 75% 66% 52%
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, 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 $ — $ — Fair Value Measurements Using: September 30, 2022 Carrying Quoted Significant Significant Financial Assets: Cash $ 1,539,000 $ 1,539,000 $ — $ — Corporate bonds 1,000 1,000 — — U.S. treasury and government securities 561,000 561,000 — — Fixed income exchange-traded funds 3,223,000 3,223,000 — — Preferred securities 67,000 67,000 — — Equity securities exchange-traded funds 408,000 408,000 — — Equities 5,517,000 5,517,000 — — Total $ 11,316,000 $ 11,316,000 $ — $ —

INCOME TAXES (Tables)

INCOME TAXES (Tables)	12 Months Ended
INCOME TAXES (Tables)	Sep. 30, 2023
Income Tax Disclosure [Abstract]
Components of income (loss) before income taxes, after adjusting the income (loss) for non-controlling interests	The components of (loss) earnings before income taxes, after adjusting the (loss) earnings for non-controlling interests, are as follows: Year ended September 30, 2023 2022 United States $ (2,414,000) $ 739,000 Canada 1,400,000 5,121,000 $ (1,014,000) $ 5,860,000
Schedule of components of the income tax provision (benefit)	The components of the income tax (benefit) provision related to the above (loss) earnings are as follows: Year ended September 30, 2023 2022 Current provision: United States – Federal Before operating loss carryforwards $ — $ 727,000 Benefit of operating loss carryforwards — (665,000) After operating loss carryforwards — 62,000 United States – State Before operating loss carryforwards 47,000 518,000 Benefit of operating loss carryforwards — (62,000) After operating loss carryforwards 47,000 456,000 Canadian Before operating loss carryforwards 274,000 510,000 Benefit of operating loss carryforwards (244,000) (510,000) After operating loss carryforwards 30,000 — Total current 77,000 518,000 Deferred benefit: United States – State (130,000) (171,000) Total deferred (130,000) (171,000) $ (53,000) $ 347,000
Summary of reconciliation between the reported income tax provision (benefit) and the amount computed by multiplying the loss by the U.S. federal tax rate	A reconciliation between the reported income tax (benefit) expense and the amount computed by multiplying the (loss) earnings attributable to Barnwell before income taxes by the U.S. federal tax rate of 21% is as follows: Year ended September 30, 2023 2022 Tax (benefit) provision computed by applying statutory rate $ (213,000) $ 1,231,000 Increase (decrease) in the valuation allowance 182,000 (1,450,000) Additional effect of the foreign tax provision on the total tax provision (4,000) 130,000 U.S. state income tax (benefit) provision, net of federal effect (9,000) 330,000 U.S. state provision to tax return adjustments (106,000) (45,000) Uncertain tax positions — 62,000 Other 97,000 89,000 $ (53,000) $ 347,000
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, 2023 2022 Deferred income tax assets: Foreign tax credit carryover under U.S. tax law $ 928,000 $ 953,000 U.S. federal net operating loss carryover 9,406,000 8,258,000 U.S. state unitary net operating loss carryovers 1,177,000 1,117,000 Canadian net operating loss carryovers 1,025,000 877,000 Tax basis of investment in land in excess of book basis under U.S. tax law 25,000 26,000 Property and equipment accumulated book depreciation and depletion in excess of tax under U.S. tax law 275,000 568,000 Asset retirement obligation accrued for books but not for tax under U.S. tax law 1,084,000 959,000 Asset retirement obligation accrued for books but not for tax under Canadian tax law 2,461,000 2,120,000 Other liabilities accrued for books but not for tax under U.S. tax law 612,000 634,000 Foreign currency loss under U.S. tax law 68,000 102,000 Foreign currency loss under Canadian tax law 81,000 124,000 Other 116,000 278,000 Total gross deferred income tax assets 17,258,000 16,016,000 Less valuation allowance (12,439,000) (12,608,000) Net deferred income tax assets 4,819,000 3,408,000 Deferred income tax liabilities: Property and equipment accumulated tax depreciation and depletion in excess of book under Canadian tax law (926,000) (280,000) Book basis of investment in land development partnerships in excess of tax basis under U.S. tax law (133,000) (545,000) Book basis of investment in land development partnerships in excess of tax basis under U.S. state non-unitary tax law (40,000) (166,000) U.S. oil and gas property and equipment accumulated tax depreciation and depletion in excess of book under U.S. tax law (906,000) (121,000) U.S. oil and gas property and equipment accumulated tax depreciation and depletion in excess of book under U.S. state tax law (19,000) (23,000) U.S. tax law impact of foreign branch deferred tax asset under Canadian tax law (1,655,000) (1,465,000) Retirement plan asset accrued for books but not for tax under U.S. tax law (939,000) (711,000) Other (259,000) (285,000) Total deferred income tax liabilities (4,877,000) (3,596,000) Net deferred income tax liability $ (58,000) $ (188,000) Reported as: Deferred income tax assets — — Deferred income tax liabilities (58,000) (188,000) Net deferred income tax liability $ (58,000) $ (188,000)
Schedule of unrecognized tax benefits	Below are the changes in unrecognized tax benefits. Year ended September 30, 2023 2022 Balance at beginning of year $ 62,000 $ — Effect of tax positions taken in prior years — 60,000 Accrued interest related to tax positions taken — 2,000 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, 2023: Jurisdiction Fiscal Years Open U.S. federal 2020 – 2022 Various U.S. states 2020 – 2022 Canada federal 2016 – 2022 Various Canadian provinces 2016 – 2022

REVENUE FROM CONTRACTS WITH C_2

REVENUE FROM CONTRACTS WITH CUSTOMERS (Tables)	12 Months Ended
REVENUE FROM CONTRACTS WITH CUSTOMERS (Tables)	Sep. 30, 2023
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, 2023 and 2022. 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 Year ended September 30, 2022 Oil and natural gas Contract drilling Land investment Other Total Revenue streams: Oil $ 15,747,000 $ — $ — $ — $ 15,747,000 Natural gas 4,527,000 — — — 4,527,000 Natural gas liquids 2,307,000 — — — 2,307,000 Drilling and pump — 4,540,000 — — 4,540,000 Contingent residual payments — — 1,295,000 — 1,295,000 Other — — — 111,000 111,000 Total revenues before interest income $ 22,581,000 $ 4,540,000 $ 1,295,000 $ 111,000 $ 28,527,000 Geographical regions: United States $ 3,496,000 $ 4,540,000 $ 1,295,000 $ 9,000 $ 9,340,000 Canada 19,085,000 — — 102,000 19,187,000 Total revenues before interest income $ 22,581,000 $ 4,540,000 $ 1,295,000 $ 111,000 $ 28,527,000 Timing of revenue recognition: Goods transferred at a point in time $ 22,581,000 $ — $ 1,295,000 $ 111,000 $ 23,987,000 Services transferred over time — 4,540,000 — — 4,540,000 Total revenues before interest income $ 22,581,000 $ 4,540,000 $ 1,295,000 $ 111,000 $ 28,527,000
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, 2023 2022 2021 Accounts receivables from contracts with customers $ 2,931,000 $ 4,038,000 $ 2,797,000 Contract assets 958,000 580,000 581,000 Contract liabilities 377,000 1,087,000 455,000

SEGMENT AND GEOGRAPHIC INFORM_2

SEGMENT AND GEOGRAPHIC INFORMATION (Tables)	12 Months Ended
SEGMENT AND GEOGRAPHIC INFORMATION (Tables)	Sep. 30, 2023
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, 2023 2022 Revenues: Oil and natural gas $ 19,376,000 $ 22,581,000 Contract drilling 5,427,000 4,540,000 Land investment 265,000 1,295,000 Other 114,000 111,000 Total before interest income 25,182,000 28,527,000 Interest income 87,000 18,000 Total revenues $ 25,269,000 $ 28,545,000 Depletion, depreciation, and amortization: Oil and natural gas $ 4,269,000 $ 2,606,000 Contract drilling 186,000 171,000 Other 2,000 1,000 Total depletion, depreciation, and amortization $ 4,457,000 $ 2,778,000 Impairment: Land investment $ — $ 89,000 Total impairment $ — $ 89,000 Operating profit (loss) (before general and administrative expenses): Oil and natural gas $ 4,673,000 $ 10,536,000 Contract drilling (428,000) (222,000) Land investment 265,000 1,206,000 Other 112,000 110,000 Gain on sale of assets 551,000 — Total operating profit 5,173,000 11,630,000 Equity in income of affiliates: Land investment 758,000 3,400,000 General and administrative expenses (6,956,000) (8,044,000) Foreign currency gain (loss) 76,000 (484,000) Interest expense (2,000) (1,000) Interest income 87,000 18,000 (Loss) earnings before income taxes $ (864,000) $ 6,519,000 Capital Expenditures: Year ended September 30, 2023 2022 Oil and natural gas $ 12,212,000 $ 13,755,000 Contract drilling 314,000 45,000 Other 14,000 5,000 Total $ 12,540,000 $ 13,805,000 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 7 for additional details). Assets By Segment: September 30, 2023 2022 Oil and natural gas: Canada $ 18,855,000 $ 16,216,000 United States 5,917,000 1,261,000 Contract drilling (1) 3,100,000 3,260,000 Other: Cash and cash equivalents 2,830,000 12,804,000 Asset for retirement benefits 4,471,000 3,385,000 Corporate and other 248,000 289,000 Total $ 35,421,000 $ 37,215,000 ______________ (1) L ocated in Hawaii.
Schedule of long-lived assets and revenue by geographic area	Long-Lived Assets By Geographic Area: September 30, 2023 2022 United States $ 10,373,000 $ 4,540,000 Canada 15,963,000 12,578,000 Total $ 26,336,000 $ 17,118,000 Revenue By Geographic Area: Year ended September 30, 2023 2022 United States $ 8,448,000 $ 9,340,000 Canada 16,734,000 19,187,000 Total (excluding interest income) $ 25,182,000 $ 28,527,000

ACCUMULATED OTHER COMPREHENSI_2

ACCUMULATED OTHER COMPREHENSIVE INCOME (Tables)	12 Months Ended
ACCUMULATED OTHER COMPREHENSIVE INCOME (Tables)	Sep. 30, 2023
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, 2023 2022 Foreign currency translation: Beginning accumulated foreign currency translation $ 222,000 $ 262,000 Change in cumulative translation adjustment before reclassifications (2,000) (40,000) Income taxes — — Net current period other comprehensive loss (2,000) (40,000) Ending accumulated foreign currency translation 220,000 222,000 Retirement plans: Beginning accumulated retirement plans benefit cost 1,072,000 (230,000) Amortization of net actuarial gain (79,000) — Net actuarial gain arising during the period 891,000 1,302,000 Income taxes — — Net current period other comprehensive income 812,000 1,302,000 Ending accumulated retirement plans benefit income 1,884,000 1,072,000 Accumulated other comprehensive income, net of taxes $ 2,104,000 $ 1,294,000

LEASES (Tables)

LEASES (Tables)	12 Months Ended
LEASES (Tables)	Sep. 30, 2023
Leases [Abstract]
Lease asset and liabilities	Leases recorded on the balance sheet consist of the following: September 30, 2023 2022 Assets: Operating lease right-of-use assets $ 54,000 $ 132,000 Total right-of-use assets $ 54,000 $ 132,000 Liabilities: Current portion of operating lease liabilities (1) $ 71,000 $ 105,000 Operating lease liabilities 47,000 117,000 Total lease liabilities $ 118,000 $ 222,000 ______________ (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, 2023 2022 Operating lease cost $ 88,000 $ 108,000 Short-term lease cost 347,000 327,000 Variable lease cost 136,000 154,000 Total lease cost $ 571,000 $ 589,000
Supplemental lease information	Supplemental information related to leases is as follows: September 30, 2023 2022 Cash paid related to operating lease liabilities $ 114,000 $ 108,000 Operating leases: Weighted-average remaining lease term (in years) 1.7 2.4 Weighted-average discount rate 5.53% 5.30%
Operating lease maturity schedule	The remaining lease payments for our operating leases as of September 30, 2023, are as follows: Fiscal year ending: 2024 $ 75,000 2025 41,000 2026 8,000 2027 — 2028 — Thereafter — Total lease payments 124,000 Less: amounts representing interest (6,000) Present value of lease liabilities $ 118,000

STOCKHOLDERS' EQUITY (Tables)

STOCKHOLDERS' EQUITY (Tables)	12 Months Ended
STOCKHOLDERS' EQUITY (Tables)	Sep. 30, 2023
Share-based compensation
Summary of the activity in share options	The following table summarizes Barnwell’s equity-classified stock options activity from October 1, 2022 through September 30, 2023: Options Shares Weighted- Weighted- Aggregate Outstanding at October 1, 2022 615,000 $ 3.36 Granted — — Exercised — — Expired/Forfeited (150,000) 3.33 Outstanding at September 30, 2023 465,000 $ 3.37 6.7 $ — Exercisable at September 30, 2023 310,000 $ 3.37 6.7 $ —
Summary of the activity in restricted stock units	The following table summarizes Barnwell’s restricted stock units activity from October 1, 2022 through September 30, 2023: Restricted Stock Units Shares Weighted-Average Nonvested at October 1, 2022 — $ — Granted 37,312 2.65 Vested (1) (37,312) 2.65 Forfeited — — Nonvested at September 30, 2023 — $ — ______________ (1)
Summary of cash dividends paid per share of common stock	The following table sets forth the cash dividends paid per share of common stock during fiscal 2023 and 2022. 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 August 23, 2022 September 6, 2022 $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, 2023
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, 2023 2022 Increase (decrease) from changes in: Receivables $ 1,103,000 $ (1,763,000) Income tax receivable (16,000) 15,000 Other current assets (51,000) (531,000) Accounts payable (595,000) 110,000 Accrued compensation (278,000) (48,000) Other current liabilities (556,000) 1,190,000 Decrease from changes in current assets and liabilities $ (393,000) $ (1,027,000) Supplemental disclosure of cash flow information: Cash paid (received) during the year for: Income taxes paid (refunded), net $ 100,000 $ (98,000)

SUPPLEMENTARY OIL AND NATURAL_2

SUPPLEMENTARY OIL AND NATURAL GAS INFORMATION (UNAUDITED) (Tables)	12 Months Ended
	Sep. 30, 2023
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Summary of changes in the estimates of net interests in total proved developed reserves of oil and natural gas liquids and natural gas	Oil & NGL Canada United States Total Proved reserves: Balance at September 30, 2021 640,000 — 640,000 Revisions of previous estimates 154,000 — 154,000 Extensions, discoveries and other additions 285,000 132,000 417,000 Acquisitions of reserves 99,000 — 99,000 Less production (188,000) (42,000) (230,000) Balance at September 30, 2022 990,000 90,000 1,080,000 Revisions of previous estimates (42,000) 48,000 6,000 Extensions, discoveries and other additions 199,000 197,000 396,000 Less production (210,000) (46,000) (256,000) Proved Reserves, September 30, 2023 937,000 289,000 1,226,000 Proved Developed Reserves, September 30, 2023 827,000 289,000 1,116,000 Proved Undeveloped Reserves, September 30, 2023 110,000 — 110,000 Natural Gas Canada United States Total Proved reserves: Balance at September 30, 2021 2,913,000 — 2,913,000 Revisions of previous estimates 968,000 — 968,000 Extensions, discoveries and other additions 1,200,000 658,000 1,858,000 Acquisitions of reserves 223,000 — 223,000 Less sales of reserves (13,000) — (13,000) Less production (772,000) (192,000) (964,000) 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) Proved Reserves, September 30, 2023 5,010,000 1,691,000 6,701,000 Proved Developed Reserves, September 30, 2023 4,402,000 1,691,000 6,093,000 Proved Undeveloped Reserves, September 30, 2023 608,000 — 608,000 Total Equivalent Reserves Canada United States Total Proved reserves: Balance at September 30, 2021 1,142,000 — 1,142,000 Revisions of previous estimates 321,000 — 321,000 Extensions, discoveries and other additions 492,000 245,000 737,000 Acquisitions of reserves 137,000 — 137,000 Less sales of reserves (2,000) — (2,000) Less production (321,000) (75,000) (396,000) 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) Proved Reserves, September 30, 2023 1,772,000 571,000 2,343,000 Proved Developed Reserves, September 30, 2023 1,561,000 571,000 2,132,000 Proved Undeveloped Reserves, September 30, 2023 211,000 — 211,000
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, 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 September 30, 2022 Canada United States Total Proved properties $ 66,825,000 $ 1,058,000 $ 67,883,000 Unproved properties — — — Total capitalized costs 66,825,000 1,058,000 67,883,000 Accumulated depletion, depreciation, and impairment 54,248,000 403,000 54,651,000 Net capitalized costs $ 12,577,000 $ 655,000 $ 13,232,000
Schedule of costs incurred in oil and natural gas property acquisition, exploration and development	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 Year ended September 30, 2022 Canada United States Total Acquisition of properties: Proved $ 3,247,000 $ — $ 3,247,000 Unproved — — — Exploration costs 55,000 — 55,000 Development costs 10,574,000 (121,000) 10,453,000 Total $ 13,876,000 $ (121,000) $ 13,755,000
Schedule of results of operations for oil and natural gas producing activities	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 Year ended September 30, 2022 Canada United States Total Net revenues $ 19,085,000 $ 3,496,000 $ 22,581,000 Production costs (8,999,000) (440,000) (9,439,000) Depletion (2,217,000) (389,000) (2,606,000) Pre-tax results of operations (1) 7,869,000 2,667,000 10,536,000 Estimated income tax expense (2) — 107,000 107,000 Results of operations (1) $ 7,869,000 $ 2,560,000 $ 10,429,000 _________________ (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, 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 Year ended September 30, 2022 Canada United States Total Future cash inflows $ 93,658,000 $ 6,676,000 $ 100,334,000 Future production costs (44,523,000) (832,000) (45,355,000) Future development costs (274,000) — (274,000) Future income tax expenses (6,908,000) (233,000) (7,141,000) Future net cash flows excluding abandonment, decommissioning and reclamation 41,953,000 5,611,000 47,564,000 Future abandonment, decommissioning and reclamation (16,719,000) (11,000) (16,730,000) Future net cash flows 25,234,000 5,600,000 30,834,000 10% annual discount for timing of cash flows (1,144,000) (1,812,000) (2,956,000) Standardized measure of discounted future net cash flows $ 24,090,000 $ 3,788,000 $ 27,878,000
Schedule of changes in standardized measure of discounted future net cash flows	Year ended September 30, 2023 2022 Beginning of year $ 27,878,000 $ 2,645,000 Sales of oil and natural gas produced, net of production costs (8,942,000) (13,142,000) Net changes in prices and production costs, net of royalties and wellhead taxes (11,913,000) 27,828,000 Extensions and discoveries 10,767,000 8,889,000 Net change due to purchases and sales of minerals in place — 2,451,000 Changes in future development costs (2,959,000) — Revisions of previous quantity estimates 2,227,000 4,270,000 Net change in income taxes 2,868,000 (4,774,000) Accretion of discount 905,000 (1,566,000) Other - changes in the timing of future production and other (1,202,000) 801,000 Other - net change in Canadian dollar translation rate 284,000 476,000 Net change (7,965,000) 25,233,000 End of year $ 19,913,000 $ 27,878,000

SUMMARY OF SIGNIFICANT ACCOUN_3

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) $ in Thousands	12 Months Ended
	Sep. 30, 2023 USD ($) segment
Principles of Consolidation
Number of operating segments \| segment	3
Retirement Plans
Increase (decrease) pension expense \| $	$ 59
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) EARNINGS PER COMMON SH_3

(LOSS) EARNINGS PER COMMON SHARE (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Sep. 30, 2023	Sep. 30, 2022
Net (Loss) Earnings (Numerator)
Basic	$ (961)	$ 5,513
Effect of dilutive securities - common stock options and restricted stock units	0	0
Diluted	$ (961)	$ 5,513
Shares (Denominator)
Basic (in shares)	9,969,856	9,732,936
Effect of dilutive securities-common stock options and restricted stock units (in shares)	0	0
Diluted (in shares)	9,969,856	9,732,936
Per-Share Amount
Basic net (loss) earnings per common share attributable to Barnwell Industries, Inc. stockholders (in dollars per share)	$ (0.10)	$ 0.57
Diluted net (loss) earnings per common share attributable to Barnwell Industries, Inc. stockholders (in dollars per share)	$ (0.10)	$ 0.57
Options
Antidilutive shares of common stock excluded from the computation of diluted shares
Antidilutive shares excluded from computation of (loss) earnings per share (in shares)	546,781	615,000
Restricted Stock Units (RSUs)
Antidilutive shares of common stock excluded from the computation of diluted shares
Antidilutive shares excluded from computation of (loss) earnings per share (in shares)	18,605

INVESTMENTS - INVESTMENT IN KUK

INVESTMENTS - INVESTMENT IN KUKIO RESORT LAND DEVELOPMENT PARTNERSHIPS (Details) $ in Thousands		12 Months Ended
	Nov. 27, 2013 USD ($) partnership	Sep. 30, 2023 USD ($) lot	Sep. 30, 2022 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		$ 758	$ 3,400
Cash distribution from equity method investment, net		674	3,028
Equity in income of affiliates		758	3,400
Investment in Kukio Resort Land Development Partnerships				$ 0
Cumulative cash distributions from Kukio Resort Land Development Partnerships in excess of our investment balance		$ 708	958
KD Kukio Resorts LLLP
Investment Holdings [Line Items]
Ownership interest acquired	19.60%
KD Maniniowali, LLLP
Investment Holdings [Line Items]
Ownership interest acquired	19.60%
KD Kaupulehu, 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%
KD Kaupulehu LLLP Increment I
Investment Holdings [Line Items]
Number of residential lots remaining to be sold \| lot		2
Non-controlling Interests
Investment Holdings [Line Items]
Cash distribution from equity method investment, net		$ 84	$ 372

INVESTMENTS - SUMMARIZED FINANC

INVESTMENTS - SUMMARIZED FINANCIAL INFORMATION (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2023	Sep. 30, 2022
Investment Holdings [Line Items]
Revenues	$ 25,269	$ 28,545
Net earnings	(811)	6,172
Investments in land development partnerships
Investment Holdings [Line Items]
Revenues	13,055	24,577
Gross Profit	7,733	16,934
Net earnings	$ 4,436	$ 13,763

INVESTMENTS - SALE OF INTEREST

INVESTMENTS - SALE OF INTEREST IN LEASEHOLD LAND (Details) $ in Thousands	12 Months Ended
	Sep. 30, 2023 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	1
Number of lots remaining to be sold	2
Number of lots developed	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, 2023	Sep. 30, 2022
Investment Holdings [Line Items]
Revenues - sale of interest in leasehold land	$ 265	$ 1,295
Fees - included in general and administrative expenses	(32)	(158)
Sale of interest in leasehold land, net of fees paid	$ 233	$ 1,137

INVESTMENTS - INVESTMENTS IN LE

INVESTMENTS - INVESTMENTS IN LEASEHOLD LAND INTERESTS - LOT 4C (Details) a in Thousands	Sep. 30, 2023 a
Investments, All Other Investments [Abstract]
Area of land (in acres)	1

CONSOLIDATED VARIABLE INTERES_3

CONSOLIDATED VARIABLE INTEREST ENTITY - NARRATIVE (Details)	Sep. 30, 2023
Variable Interest Entity [Line Items]
Percentage of capital contributions to variable interest entity	100%
Gros Ventre Partners, LLC
Variable Interest Entity [Line Items]
Profit sharing ratio of variable interest entity	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%

CONSOLIDATED VARIABLE INTERES_4

CONSOLIDATED VARIABLE INTEREST ENTITY - CARRYING VALUE OF ASSETS AND LIABILITIES (Details) - USD ($) $ in Thousands	Sep. 30, 2023	Sep. 30, 2022
ASSETS
Cash and cash equivalents	$ 2,830	$ 12,804
Accounts and other receivables	3,246	4,361
Total assets	35,421	37,215
Liabilities [Abstract]
Accounts payable	881	1,462
Accrued operating and other expenses	1,747	1,576
Total liabilities	16,664	18,054
Variable Interest Entity, Primary Beneficiary
ASSETS
Cash and cash equivalents	83	623
Accounts and other receivables	175	606
Proved oil and natural gas properties, net (full cost method)	544	655
Total assets	802	1,884
Liabilities [Abstract]
Accounts payable	10	15
Accrued operating and other expenses	15	26
Total liabilities	$ 25	$ 41

ASSET HELD FOR SALE (Details)

ASSET HELD FOR SALE (Details) - USD ($) $ in Thousands	1 Months Ended	3 Months Ended	12 Months Ended
ASSET HELD FOR SALE (Details) - USD ($) $ in Thousands	Sep. 30, 2022	Dec. 31, 2022	Sep. 30, 2023	Sep. 30, 2022
Long Lived Assets Held-for-sale [Line Items]
Proceeds recorded as other current liabilities			$ 0	$ 551
Drilling rigs and equipment
Long Lived Assets Held-for-sale [Line Items]
Proceeds recorded as other current liabilities	$ 551
Gain on sale of drilling rig		$ 551

OIL AND NATURAL GAS PROPERTIES

OIL AND NATURAL GAS PROPERTIES (Details) - USD ($) $ in Thousands	1 Months Ended	3 Months Ended		12 Months Ended
	Dec. 31, 2022	Mar. 31, 2022	Dec. 31, 2021	Sep. 30, 2023	Sep. 30, 2022	Dec. 01, 2022
Oil and Natural Gas Properties [Line Items]
Costs incurred				$ 11,430	$ 10,453
Broker's fee paid				11,304	8,607
Payments to acquire oil and natural gas properties				0	1,563
Asset retirement obligation assumed				21	1,682
Proceeds from sale of oil and natural gas assets				0	$ 503
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
Broker's fee percent				5%
Barnwell Texas, LLC \| Four Pines Exploration LLC - Exploration - Series 1
Oil and Natural Gas Properties [Line Items]
Broker's fee paid				$ 255
Barnwell Industries Inc \| Twining, Alberta, Canada
Oil and Natural Gas Properties [Line Items]
Payments to acquire oil and natural gas properties		$ 1,246	$ 317
Asset retirement obligation assumed		$ 1,500

PROPERTY AND EQUIPMENT AND AS_3

PROPERTY AND EQUIPMENT AND ASSET RETIREMENT OBLIGATION (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2023	Sep. 30, 2022
Property and equipment
Proved Properties, Net Property and Equipment	$ 21,302	$ 13,232
Net drilling rigs and other property and equipment	509	369
Total Gross Property and Equipment	88,074	74,806
Total Accumulated Depletion, Depreciation, Amortization, and Impairment	(66,263)	(61,205)
Total Net Property and Equipment	21,811	13,601
Change in the asset retirement obligation
Balance at the beginning of the year	8,456	7,053
Obligations incurred on new wells drilled or acquired	21	1,682
Liabilities associated with properties sold	0	(483)
Revision of estimated obligation	1,462	1,021
Accretion expense	808	767
Payments	(1,005)	(942)
Foreign currency translation adjustment	91	(642)
Balance at the end of the year	9,833	8,456
Less current portion	(1,536)	(1,327)
Asset retirement obligation, long-term	8,297	7,129
Oil and natural gas properties
Property and equipment
Proved Properties, Gross Property and Equipment	80,851	67,883
Proved Properties, Accumulated Depletion, Depreciation, Amortization, and Impairment	(59,549)	(54,651)
Proved Properties, Net Property and Equipment	21,302	13,232
Drilling rigs and equipment
Property and equipment
Gross Property and Equipment	6,618	6,304
Property, Plant and Equipment, Other, Accumulated Depletion, Depreciation, Amortization, And Impairment	(6,127)	(5,943)
Net drilling rigs and other property and equipment	$ 491	$ 361
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	$ 605	$ 619
Property, Plant and Equipment, Other, Accumulated Depletion, Depreciation, Amortization, And Impairment	(587)	(611)
Net drilling rigs and other property and equipment	$ 18	$ 8
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 - NARRATIVE (Details) - USD ($) $ in Thousands	1 Months Ended		12 Months Ended
	Aug. 31, 2024	Jul. 31, 2021	Sep. 30, 2023	Sep. 30, 2022
Property and equipment
Asset retirement obligation			$ 0	$ (483)
Revision of estimated obligation			1,462	1,021
Obligations incurred on new wells drilled or acquired			21	1,682
Abandonment and reclamation cost, cash deposit		$ 888		$ 1,525
Abandonment and reclamation cost, cumulative cash deposit reduction			$ (300)
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, 2023	Sep. 30, 2022
Pension Plan
Retirement plans
Period of employee's highest average earnings on which benefits are based	5 years
Accumulated benefit obligation	$ 7,511	$ 7,931
Expected future contributions	0
SERP
Retirement plans
Accumulated benefit obligation	$ 1,734	$ 1,715

RETIREMENT PLANS - CHANGES IN B

RETIREMENT PLANS - CHANGES IN BENEFIT OBLIGATIONS (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2023	Sep. 30, 2022
Change in Plan Assets:
Fair value of plan assets at beginning of year	$ 11,316
Fair value of plan assets at end of year	11,982	$ 11,316
Amounts recognized in the Consolidated Balance Sheets:
Noncurrent assets	4,471	3,385
Noncurrent liabilities	(1,664)	(1,649)
Pension Plan
Change in Projected Benefit Obligation:
Benefit obligation at beginning of year	7,931	10,365
Interest cost	406	290
Actuarial gain	(394)	(2,418)
Benefits paid	(432)	(306)
Benefit obligation at end of year	7,511	7,931
Change in Plan Assets:
Fair value of plan assets at beginning of year	11,316	12,594
Actual return on plan assets	1,098	(972)
Benefits paid	(432)	(306)
Fair value of plan assets at end of year	11,982	11,316
Funded status	4,471	3,385
Amounts recognized in the Consolidated Balance Sheets:
Noncurrent assets	4,471	3,385
Current liabilities	0	0
Noncurrent liabilities	0	0
Net amount	4,471	3,385
Amounts recognized in accumulated other comprehensive income before income taxes:
Net actuarial gain	(1,178)	(353)
Accumulated other comprehensive income	(1,178)	(353)
SERP
Change in Projected Benefit Obligation:
Benefit obligation at beginning of year	1,715	2,136
Interest cost	88	60
Actuarial gain	(66)	(478)
Benefits paid	(3)	(3)
Benefit obligation at end of year	1,734	1,715
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	(1,734)	(1,715)
Amounts recognized in the Consolidated Balance Sheets:
Noncurrent assets	0	0
Current liabilities	(70)	(66)
Noncurrent liabilities	(1,664)	(1,649)
Net amount	(1,734)	(1,715)
Amounts recognized in accumulated other comprehensive income before income taxes:
Net actuarial gain	(330)	(343)
Accumulated other comprehensive income	$ (330)	$ (343)

RETIREMENT PLANS - WEIGHTED AVE

RETIREMENT PLANS - WEIGHTED AVEARAGE BENEFIT OBLIGATIONS AND NET BENEFIT (INCOME) COST (Details)	12 Months Ended
	Sep. 30, 2023	Sep. 30, 2022
Pension Plan
Assumptions used to determine fiscal year-end benefit obligations:
Discount rate	5.62%	5.25%
Assumptions used to determine net benefit costs (years ended):
Discount rate	5.25%	2.84%
Expected return on plan assets	6%	5%
SERP
Assumptions used to determine fiscal year-end benefit obligations:
Discount rate	5.62%	5.25%
Assumptions used to determine net benefit costs (years ended):
Discount rate	5.25%	2.84%

RETIREMENT PLANS - NET PERIODIC

RETIREMENT PLANS - NET PERIODIC BENEFIT (INCOME) COST (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2023	Sep. 30, 2022
Pension Plan
Net periodic benefit (income) cost for the year:
Interest cost	$ 406	$ 290
Expected return on plan assets	(667)	(622)
Amortization of net actuarial gain	0	0
Net periodic benefit (income) cost	(261)	(332)
SERP
Net periodic benefit (income) cost for the year:
Interest cost	88	60
Expected return on plan assets	0	0
Amortization of net actuarial gain	(79)	0
Net periodic benefit (income) cost	$ 9	$ 60

RETIREMENT PLANS - EXPECTED BEN

RETIREMENT PLANS - EXPECTED BENEFIT PAYMENTS (Details) $ in Thousands	Sep. 30, 2023 USD ($)
Pension Plan
Expected Benefit Payments:
Fiscal year ending September 30, 2024	$ 402
Fiscal year ending September 30, 2025	552
Fiscal year ending September 30, 2026	545
Fiscal year ending September 30, 2027	537
Fiscal year ending September 30, 2028	574
Fiscal years ending September 30, 2029 through 2033	2,990
SERP
Expected Benefit Payments:
Fiscal year ending September 30, 2024	70
Fiscal year ending September 30, 2025	140
Fiscal year ending September 30, 2026	138
Fiscal year ending September 30, 2027	137
Fiscal year ending September 30, 2028	142
Fiscal years ending September 30, 2029 through 2033	$ 712

RETIREMENT PLANS - ASSET CATERG

RETIREMENT PLANS - ASSET CATERGORY ALLOCATION (Details)	Sep. 30, 2023	Sep. 30, 2022
Cash and other
Entity's year-end target allocation, by asset category, and the actual asset allocations
Actual asset allocation	2%	14%
Fixed income securities
Entity's year-end target allocation, by asset category, and the actual asset allocations
Actual asset allocation	32%	34%
Equity securities
Entity's year-end target allocation, by asset category, and the actual asset allocations
Actual asset allocation	66%	52%
Minimum \| Cash and other
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%
Maximum \| Cash and other
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%

RETIREMENT PLANS - FAIR VALUE (

RETIREMENT PLANS - FAIR VALUE (Details) - USD ($) $ in Thousands	Sep. 30, 2023	Sep. 30, 2022
Pension plan assets at the fair value
Fair value measurements	$ 11,982	$ 11,316
Quoted Prices in Active Markets (Level 1)
Pension plan assets at the fair value
Fair value measurements	11,982	11,316
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	0	0
Cash
Pension plan assets at the fair value
Fair value measurements	263	1,539
Cash \| Quoted Prices in Active Markets (Level 1)
Pension plan assets at the fair value
Fair value measurements	263	1,539
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
Corporate bonds
Pension plan assets at the fair value
Fair value measurements		1
Corporate bonds \| Quoted Prices in Active Markets (Level 1)
Pension plan assets at the fair value
Fair value measurements		1
Corporate bonds \| Significant Other Observable Inputs (Level 2)
Pension plan assets at the fair value
Fair value measurements		0
Corporate bonds \| Significant Unobservable Inputs (Level 3)
Pension plan assets at the fair value
Fair value measurements		0
U.S. treasury and government securities
Pension plan assets at the fair value
Fair value measurements	709	561
U.S. treasury and government securities \| Quoted Prices in Active Markets (Level 1)
Pension plan assets at the fair value
Fair value measurements	709	561
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	3,102	3,223
Fixed income exchange-traded funds \| Quoted Prices in Active Markets (Level 1)
Pension plan assets at the fair value
Fair value measurements	3,102	3,223
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	47	67
Preferred securities \| Quoted Prices in Active Markets (Level 1)
Pension plan assets at the fair value
Fair value measurements	47	67
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
Equity securities exchange-traded funds
Pension plan assets at the fair value
Fair value measurements		408
Equity securities exchange-traded funds \| Quoted Prices in Active Markets (Level 1)
Pension plan assets at the fair value
Fair value measurements		408
Equity securities exchange-traded funds \| Significant Other Observable Inputs (Level 2)
Pension plan assets at the fair value
Fair value measurements		0
Equity securities exchange-traded funds \| Significant Unobservable Inputs (Level 3)
Pension plan assets at the fair value
Fair value measurements		0
Equities
Pension plan assets at the fair value
Fair value measurements	7,861	5,517
Equities \| Quoted Prices in Active Markets (Level 1)
Pension plan assets at the fair value
Fair value measurements	7,861	5,517
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

INCOME TAXES (Details)

INCOME TAXES (Details) - USD ($)	12 Months Ended
INCOME TAXES (Details) - USD ($)	Sep. 30, 2023	Sep. 30, 2022
Components of earnings (loss) before income taxes, after adjusting the earnings (loss) for non-controlling interests
United States	$ (2,414,000)	$ 739,000
Canada	1,400,000	5,121,000
Total	(1,014,000)	5,860,000
Current provision (benefit): United States - Federal
Before operating loss carryforwards	0	727,000
Benefit of operating loss carryforwards	0	(665,000)
After operating loss carryforwards	0	62,000
Current provision (benefit): United States - State
Before operating loss carryforwards	47,000	518,000
Benefit of operating loss carryforwards	0	(62,000)
After operating loss carryforwards	47,000	456,000
Current provision (benefit): Canadian
Before operating loss carryforwards	274,000	510,000
Benefit of operating loss carryforwards	(244,000)	(510,000)
After operating loss carryforwards	30,000	0
Total current	77,000	518,000
Deferred benefit:
United States – State	(130,000)	(171,000)
Total deferred	(130,000)	(171,000)
Total	$ (53,000)	347,000
Income Tax Uncertainties [Abstract]
Income tax penalties and interest expense		62,000
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) provision computed by applying statutory rate	$ (213,000)	1,231,000
Increase (decrease) in the valuation allowance	182,000	(1,450,000)
Additional effect of the foreign tax provision on the total tax provision	(4,000)	130,000
U.S. state income tax (benefit) provision, net of federal effect	(9,000)	330,000
U.S. state provision to tax return adjustments	(106,000)	(45,000)
Uncertain tax positions	0	62,000
Other	97,000	89,000
Total	(53,000)	347,000
Deferred income tax assets:
Foreign tax credit carryover under U.S. tax law	928,000	953,000
U.S. federal net operating loss carryover	9,406,000	8,258,000
U.S. state unitary net operating loss carryovers	1,177,000	1,117,000
Canadian net operating loss carryovers	1,025,000	877,000
Tax basis of investment in land in excess of book basis under U.S. tax law	25,000	26,000
Property and equipment accumulated book depreciation and depletion in excess of tax under U.S. tax law	275,000	568,000
Asset retirement obligation accrued for books but not for tax under U.S. tax law	1,084,000	959,000
Asset retirement obligation accrued for books but not for tax under Canadian tax law	2,461,000	2,120,000
Other liabilities accrued for books but not for tax under U.S. tax law	612,000	634,000
Foreign currency loss under U.S. tax law	68,000	102,000
Foreign currency loss under Canadian tax law	81,000	124,000
Other	116,000	278,000
Total gross deferred income tax assets	17,258,000	16,016,000
Less Valuation allowance	(12,439,000)	(12,608,000)
Net deferred income tax assets	4,819,000	3,408,000
Deferred income tax liabilities:
Property and equipment accumulated tax depreciation and depletion in excess of book under Canadian tax law	(926,000)	(280,000)
Book basis of investment in land development partnerships in excess of tax basis under U.S. tax law	(133,000)	(545,000)
Book basis of investment in land development partnerships in excess of tax basis under U.S. state non-unitary tax law	(40,000)	(166,000)
U.S. oil and gas property and equipment accumulated tax depreciation and depletion in excess of book under U.S. tax law	(906,000)	(121,000)
U.S. oil and gas property and equipment accumulated tax depreciation and depletion in excess of book under U.S. state tax law	(19,000)	(23,000)
U.S. tax law impact of foreign branch deferred tax asset under Canadian tax law	(1,655,000)	(1,465,000)
Retirement plan asset accrued for books but not for tax under U.S. tax law	(939,000)	(711,000)
Other	(259,000)	(285,000)
Total deferred income tax liabilities	(4,877,000)	(3,596,000)
Net deferred income tax liability	(58,000)	(188,000)
Net deferred income tax liability included in Consolidated Balance Sheets:
Deferred income tax assets	0	0
Deferred income tax liabilities	(58,000)	(188,000)
Net deferred income tax liability	(58,000)	(188,000)
Valuation allowance, other disclosures
Decrease in valuation allowance	(169,000)
Income tax (benefit) expense recognized in valuation allowance change	(4,000)
Change in valuation allowance charged to accumulated other comprehensive income	(165,000)
Changes in unrecognized tax benefits
Balance at the beginning of year	62,000	0
Effect of tax positions taken in prior years	0	60,000
Accrued interest related to tax positions taken	0	2,000
Balance at the end of year	62,000	$ 62,000
Federal
Tax carryovers
Tax credit carryovers	928,000
Operating loss carryovers	44,790,000
State and Local Jurisdiction
Tax carryovers
Operating loss carryovers	18,387,000
Foreign
Tax carryovers
Operating loss carryovers	$ 3,816,000

REVENUE FROM CONTRACTS WITH C_3

REVENUE FROM CONTRACTS WITH CUSTOMERS - DISAGGREGATION OF REVENUE (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2023	Sep. 30, 2022
Disaggregation of Revenue [Line Items]
Revenue before interest income	$ 25,182	$ 28,527
United States
Disaggregation of Revenue [Line Items]
Revenue before interest income	8,448	9,340
Canada
Disaggregation of Revenue [Line Items]
Revenue before interest income	16,734	19,187
Oil
Disaggregation of Revenue [Line Items]
Revenue before interest income	14,259	15,747
Natural gas
Disaggregation of Revenue [Line Items]
Revenue before interest income	3,441	4,527
Natural gas liquids
Disaggregation of Revenue [Line Items]
Revenue before interest income	1,676	2,307
Drilling and pump
Disaggregation of Revenue [Line Items]
Revenue before interest income	5,427	4,540
Contingent residual payments
Disaggregation of Revenue [Line Items]
Revenue before interest income	265	1,295
Other
Disaggregation of Revenue [Line Items]
Revenue before interest income	114	111
Oil and natural gas
Disaggregation of Revenue [Line Items]
Revenue before interest income	19,376	22,581
Oil and natural gas \| United States
Disaggregation of Revenue [Line Items]
Revenue before interest income	2,746	3,496
Oil and natural gas \| Canada
Disaggregation of Revenue [Line Items]
Revenue before interest income	16,630	19,085
Oil and natural gas \| Oil
Disaggregation of Revenue [Line Items]
Revenue before interest income	14,259	15,747
Oil and natural gas \| Natural gas
Disaggregation of Revenue [Line Items]
Revenue before interest income	3,441	4,527
Oil and natural gas \| Natural gas liquids
Disaggregation of Revenue [Line Items]
Revenue before interest income	1,676	2,307
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	5,427	4,540
Contract drilling \| United States
Disaggregation of Revenue [Line Items]
Revenue before interest income	5,427	4,540
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	5,427	4,540
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	265	1,295
Land investment \| United States
Disaggregation of Revenue [Line Items]
Revenue before interest income	265	1,295
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	265	1,295
Land investment \| Other
Disaggregation of Revenue [Line Items]
Revenue before interest income	0	0
Other
Disaggregation of Revenue [Line Items]
Revenue before interest income	114	111
Other \| United States
Disaggregation of Revenue [Line Items]
Revenue before interest income	10	9
Other \| Canada
Disaggregation of Revenue [Line Items]
Revenue before interest income	104	102
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	114	111
Goods transferred at a point in time
Disaggregation of Revenue [Line Items]
Revenue before interest income	19,755	23,987
Goods transferred at a point in time \| Oil and natural gas
Disaggregation of Revenue [Line Items]
Revenue before interest income	19,376	22,581
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	265	1,295
Goods transferred at a point in time \| Other
Disaggregation of Revenue [Line Items]
Revenue before interest income	114	111
Services transferred over time
Disaggregation of Revenue [Line Items]
Revenue before interest income	5,427	4,540
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	5,427	4,540
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, 2023	Sep. 30, 2022	Sep. 30, 2021
Revenue from Contract with Customer [Abstract]
Accounts receivables from contracts with customers	$ 2,931	$ 4,038	$ 2,797
Contract assets	958	580	581
Contract liabilities	$ 377	$ 1,087	$ 455

REVENUE FROM CONTRACTS WITH C_5

REVENUE FROM CONTRACTS WITH CUSTOMERS - NARRATIVE (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2023	Sep. 30, 2022
Disaggregation of Revenue [Line Items]
Contract with customer, liability, current	$ 377	$ 1,087
Contract with customer, liability, revenue recognized	1,015	394
Revenue, remaining performance obligation (backlog)	$ 3,587
Percentage anticipated to be recognized in next 12 months	100%
Capitalized contract cost net, preconstruction	$ 504	689
Capitalized contract cost, amortization of preconstruction	326	296
Capitalized contract cost, impairment loss	0	0
Uninstalled materials, current	$ 348	$ 351
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 (Details) - USD ($)	12 Months Ended
SEGMENT AND GEOGRAPHIC INFORMATION (Details) - USD ($)	Sep. 30, 2023	Sep. 30, 2022
Revenues:
Revenue before interest income	$ 25,182,000	$ 28,527,000
Interest income	87,000	18,000
Total revenues	25,269,000	28,545,000
Depletion, depreciation, and amortization:
Depletion, depreciation, and amortization	4,457,000	2,778,000
Impairment:
Impairment of assets	0	89,000
Operating profit (loss) (before general and administrative expenses):
Operating profit (loss) (before general and administrative expenses)	5,173,000	11,630,000
Equity in income (loss) of affiliates:
Equity in income of affiliates	758,000	3,400,000
General and administrative expenses	(6,956,000)	(8,044,000)
Foreign currency (gain) loss	76,000	(484,000)
Interest expense	(2,000)	(1,000)
Interest income	87,000	18,000
(Loss) earnings before income taxes	(864,000)	6,519,000
Capital Expenditures:
Capital Expenditure	12,540,000	13,805,000
Assets By Segment:
Total assets	35,421,000	37,215,000
Canada
Revenues:
Revenue before interest income	16,734,000	19,187,000
United States
Revenues:
Revenue before interest income	8,448,000	9,340,000
Intersegment eliminations \| External Customer
Revenues:
Total revenues	0	0
Corporate and other
Capital Expenditures:
Capital Expenditure	14,000	5,000
Segment Reconciling Items, Cash And Cash Equivalents
Assets By Segment:
Total assets	2,830,000	12,804,000
Segment Reconciling Items, Asset For Retirement Benefits
Assets By Segment:
Total assets	4,471,000	3,385,000
Corporate, Non-Segment
Assets By Segment:
Total assets	248,000	289,000
Oil and natural gas
Revenues:
Revenue before interest income	19,376,000	22,581,000
Total revenues	19,376,000	22,581,000
Depletion, depreciation, and amortization:
Depletion, depreciation, and amortization	4,269,000	2,606,000
Operating profit (loss) (before general and administrative expenses):
Operating profit (loss) (before general and administrative expenses)	4,673,000	10,536,000
Oil and natural gas \| Canada
Revenues:
Revenue before interest income	16,630,000	19,085,000
Oil and natural gas \| United States
Revenues:
Revenue before interest income	2,746,000	3,496,000
Oil and natural gas \| Operating segments
Capital Expenditures:
Capital Expenditure	12,212,000	13,755,000
Oil and natural gas \| Operating segments \| Canada
Assets By Segment:
Total assets	18,855,000	16,216,000
Oil and natural gas \| Operating segments \| United States
Assets By Segment:
Total assets	5,917,000	1,261,000
Contract drilling
Revenues:
Revenue before interest income	5,427,000	4,540,000
Total revenues	5,427,000	4,540,000
Depletion, depreciation, and amortization:
Depletion, depreciation, and amortization	186,000	171,000
Operating profit (loss) (before general and administrative expenses):
Operating profit (loss) (before general and administrative expenses)	(428,000)	(222,000)
Contract drilling \| Canada
Revenues:
Revenue before interest income	0	0
Contract drilling \| United States
Revenues:
Revenue before interest income	5,427,000	4,540,000
Contract drilling \| Operating segments
Capital Expenditures:
Capital Expenditure	314,000	45,000
Assets By Segment:
Total assets	3,100,000	3,260,000
Land investment
Revenues:
Revenue before interest income	265,000	1,295,000
Total revenues	265,000	1,295,000
Impairment:
Impairment of assets	0	89,000
Operating profit (loss) (before general and administrative expenses):
Operating profit (loss) (before general and administrative expenses)	265,000	1,206,000
Land investment \| Canada
Revenues:
Revenue before interest income	0	0
Land investment \| United States
Revenues:
Revenue before interest income	265,000	1,295,000
Other
Revenues:
Revenue before interest income	114,000	111,000
Total revenues	201,000	129,000
Depletion, depreciation, and amortization:
Depletion, depreciation, and amortization	2,000	1,000
Operating profit (loss) (before general and administrative expenses):
Operating profit (loss) (before general and administrative expenses)	112,000	110,000
Other \| Canada
Revenues:
Revenue before interest income	104,000	102,000
Other \| United States
Revenues:
Revenue before interest income	10,000	9,000
Gain on sale of assets
Operating profit (loss) (before general and administrative expenses):
Operating profit (loss) (before general and administrative expenses)	$ 551,000	$ 0

SEGMENT AND GEOGRAPHIC INFORM_4

SEGMENT AND GEOGRAPHIC INFORMATION - GEOGRAPHIC AREAS (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2023	Sep. 30, 2022
Geographic information
Long-lived assets	$ 26,336	$ 17,118
Total (excluding interest income)	25,182	28,527
United States
Geographic information
Long-lived assets	10,373	4,540
Total (excluding interest income)	8,448	9,340
Canada
Geographic information
Long-lived assets	15,963	12,578
Total (excluding interest income)	$ 16,734	$ 19,187

ACCUMULATED OTHER COMPREHENSI_3

ACCUMULATED OTHER COMPREHENSIVE INCOME (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2023	Sep. 30, 2022
Foreign currency translation:
Balance at beginning of period	$ 222	$ 262
Change in cumulative translation adjustment before reclassifications	(2)	(40)
Foreign currency translation adjustments, taxes	0	0
Net current period other comprehensive loss	(2)	(40)
Balance at end of the period	220	222
Retirement plans:
Balance at beginning of period	1,072	(230)
Amortization of net actuarial gain	(79)	0
Net actuarial gain arising during the period	891	1,302
Amortization of accumulated other comprehensive loss into net periodic benefit costs, taxes	0	0
Net current period other comprehensive income	812	1,302
Balance at end of the period	1,884	1,072
Accumulated other comprehensive income, net	$ 2,104	$ 1,294

DEBT (Details)

DEBT (Details) $ in Thousands, $ in Thousands	3 Months Ended	12 Months Ended
DEBT (Details) $ in Thousands, $ in Thousands	Mar. 31, 2021 CAD ($)	Sep. 30, 2023 USD ($)	Sep. 30, 2023 CAD ($)	Sep. 30, 2022 USD ($)	Sep. 30, 2023 CAD ($)	Dec. 31, 2021 CAD ($)
Debt Instrument [Line Items]
Gain on debt extinguishment		$ 15		$ 0
Canada Emergency Business Account Loan
Debt Instrument [Line Items]
Debt face amount		$ 45			$ 60	$ 40
Debt instrument, net increase	$ 20
Percentage of loan to be repaid for debt forgiveness		66.70%	66.70%
Percentage of debt forgiveness		33.30%	33.30%
Repayment of debt			$ 40
Debt balance forgiven			$ 20
Gain on debt extinguishment		$ 15

LEASES - NARRATIVE (Details)

LEASES - NARRATIVE (Details) $ in Thousands	12 Months Ended
LEASES - NARRATIVE (Details) $ in Thousands	Sep. 30, 2023 USD ($)
Leases [Abstract]
Right-of-use asset impairment	$ 89

LEASES - ASSETS AND LIABILITIES

LEASES - ASSETS AND LIABILITIES (Details) - USD ($) $ in Thousands	Sep. 30, 2023	Sep. 30, 2022
Leases [Abstract]
Operating lease right-of-use assets	$ 54	$ 132
Total right-of-use assets	54	132
Current portion of operating lease liabilities	71	105
Operating lease liabilities	47	117
Lease Liability	$ 118	$ 222
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
LEASES - LEASE COSTS (Details) - USD ($) $ in Thousands	Sep. 30, 2023	Sep. 30, 2022
Leases [Abstract]
Operating lease cost	$ 88	$ 108
Short-term lease cost	347	327
Variable lease, cost	136	154
Total lease cost	$ 571	$ 589

LEASES - SUPPLEMENTAL LEASE INF

LEASES - SUPPLEMENTAL LEASE INFORMATION (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2023	Sep. 30, 2022
Leases [Abstract]
Cash paid related to operating lease liabilities	$ 114	$ 108
Operating lease, weighted average remaining lease term (in years)	1 year 8 months 12 days	2 years 4 months 24 days
Operating lease, weighted average discount rate	5.53%	5.30%

LEASES - OPEARTING LEASE MATURI

LEASES - OPEARTING LEASE MATURITY SCHEDULE (Details) $ in Thousands	Sep. 30, 2023 USD ($)
Leases [Abstract]
2024	$ 75
2025	41
2026	8
2027	0
2028	0
Thereafter	0
Total lease payments	124
Less: amounts representing interest	(6)
Operating lease liabilities	$ 118

STOCKHOLDERS' EQUITY - SHARE-BA

STOCKHOLDERS' EQUITY - SHARE-BASED COMPENSATION (Details) - USD ($) $ / shares in Units, $ in Thousands				1 Months Ended		12 Months Ended
	Jun. 09, 2023	May 11, 2023	Feb. 09, 2021	Nov. 30, 2023	May 31, 2023	Sep. 30, 2023	Sep. 30, 2022	Nov. 01, 2023
Share-based compensation arrangement by share-based payment award [Line Items]
Common stock, issued shares (in shares)						10,158,678	10,124,587
Value of common stock issued for services						$ 90	$ 3
Subsequent Event
Share-based compensation arrangement by share-based payment award [Line Items]
Common stock, issued shares (in shares)								9,328
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
Share-based compensation expense						$ 164	657
Income tax effect related to share-based compensation expense						0	$ 0
Total unrecognized compensation cost						$ 50
Period over which unrecognized compensation cost is expected to be recognized						4 months 24 days
Restricted Stock Units (RSUs)
Share-based compensation arrangement by share-based payment award [Line Items]
Share-based compensation expense						$ 99
Income tax effect related to share-based compensation expense						$ 0
Number of restricted stock units granted (in shares)						37,312
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
Share-based Payment Arrangement, Independent Director \| Restricted Stock Units (RSUs)
Share-based compensation arrangement by share-based payment award [Line Items]
Number of restricted stock units granted (in shares)	37,312
Share-based Payment Arrangement, Independent Director \| Restricted Stock Units (RSUs) \| Subsequent Event
Share-based compensation arrangement by share-based payment award [Line Items]
Number of restricted stock units granted (in shares)				76,366
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
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
Number of shares available for grant (in shares)						1,095,000

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, 2023
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		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		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 - USD ($)		12 Months Ended
	Feb. 09, 2021	Sep. 30, 2023
Shares
Outstanding at the beginning of the period (in shares)		615,000
Granted (in shares)	665,000	0
Exercised (in shares)		0
Expired/Forfeited (in shares)		(150,000)
Outstanding at the end of the period (in shares)		465,000
Exercisable at the end of period (in shares)		310,000
Weighted-Average Exercise Price
Outstanding at the beginning of the period (in dollars per share)		$ 3.36
Granted (in dollars per share)		0
Exercised (in dollars per share)		0
Expired/Forfeited (in dollars per share)		3.33
Outstanding at the end of the period (in dollars per share)		3.37
Exercisable at the end of period (in dollars per share)		$ 3.37
Weighted-Average Remaining Contractual Term
Options outstanding, weighted average remaining contractual life		6 years 8 months 12 days
Options exercisable, weighted average contractual life		6 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) - Restricted Stock Units (RSUs)	12 Months Ended
	Sep. 30, 2023 $ / shares shares
Shares
Nonvested at the beginning of the period (in shares) \| shares	0
Granted (in shares) \| shares	37,312
Vested (in shares) \| shares	(37,312)
Forfeited (in shares) \| shares	0
Nonvested at the end of the period (in shares) \| shares	0
Weighted-Average Grant Date Fair Value
Nonvested at the beginning of the period (in dollars per share) \| $ / shares	$ 0
Granted (in dollars per share) \| $ / shares	2.65
Vested (in dollars per share) \| $ / shares	2.65
Forfeited (in dollars per share) \| $ / shares	0
Nonvested at the end of the period (in dollars per share) \| $ / shares	$ 0

STOCKHOLDERS' EQUITY - AT THE M

STOCKHOLDERS' EQUITY - AT THE MARKET OFFERING (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended					12 Months Ended
	Sep. 30, 2023	Jun. 30, 2023	Mar. 31, 2023	Dec. 31, 2022	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022	Oct. 17, 2022	Mar. 16, 2021
Sale of Stock [Line Items]
Dividends declared, cash paid per share	$ 0.015	$ 0.015	$ 0.015	$ 0.015	$ 0.015	$ 0.060	$ 0.015
Common stock, par value (in dollars per share)	$ 0.50					$ 0.50
The Tax Benefits Preservation Plan
Sale of Stock [Line Items]
Number of rights for each outstanding common stock (in shares)								1
At The Market Offering
Sale of Stock [Line Items]
Common stock, par value (in dollars per share)									$ 0.50
Sale of stock, maximum aggregate sales price	$ 25,000					$ 25,000
Common shares sold (in shares)							509,467
Proceeds from sale of common stock							$ 2,356
At The Market Offering \| Commissions And Fees
Sale of Stock [Line Items]
Stock issuance costs, commissions, fees, and ATM-related professional services							75
At The Market Offering \| At The Market Related Professional Services
Sale of Stock [Line Items]
Stock issuance costs, commissions, fees, and ATM-related professional services							$ 22

COMMITMENTS AND CONTINGENCIES (

COMMITMENTS AND CONTINGENCIES (Detail) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2023	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	$ 180
Unfavorable Regulatory Action \| Contract drilling
Commitments and contingencies
Loss contingency accrual		$ 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 counsel 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 (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2023	Sep. 30, 2022
Increase (decrease) from changes in:
Receivables	$ 1,103	$ (1,763)
Income tax receivable	(16)	15
Other current assets	(51)	(531)
Accounts payable	(595)	110
Accrued compensation	(278)	(48)
Other current liabilities	(556)	1,190
Decrease from changes in current assets and liabilities	(393)	(1,027)
Supplemental disclosure of cash flow information:
Income taxes paid (refunded), net	100	(98)
Supplemental disclosures of cash flow information:
Increase (decrease) in capital expenditure accruals related to oil and natural gas asset retirement obligations	1,483	2,703
Oil and natural gas
Supplemental disclosures of cash flow information:
Increase (decrease) in capital expenditure accruals related to oil and natural gas exploration and development	(575)	882
Increase (decrease) in capital expenditure accruals related to oil and natural gas asset retirement obligations	$ 1,483	$ 2,703

RELATED PARTY TRANSACTIONS (Det

RELATED PARTY TRANSACTIONS (Details) $ in Thousands		1 Months Ended	12 Months Ended
RELATED PARTY TRANSACTIONS (Details) $ in Thousands	May 11, 2023 USD ($) shares	May 31, 2023 USD ($)	Dec. 31, 2024	Dec. 31, 2023	Sep. 30, 2023 USD ($) lot	Sep. 30, 2022 USD ($) lot
Related party transactions
Broker's fee paid					$ 11,304	$ 8,607
Value of common stock issued for services					$ 90	3
Forecast
Related party transactions
Percent of ownership in outstanding common stock			30%	28%
Gros Ventre Partners, LLC
Related party transactions
Profit sharing ratio of variable interest entity					2%
Asset management fee, percent fee of cumulative capital contributions					1%
MRMP Stockholders
Related party transactions
Expenses incurred from transactions with related parties					$ 202
Mr. Alex Kinzler
Related party transactions
Expenses incurred from transactions with related parties					149
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					265	1,295
Kaupulehu Developments \| KD Kaupulehu, LLLP \| Increment I
Related party transactions
Revenues - sale of interest in leasehold land					$ 265	$ 1,295
Number of single family lots sold \| lot					1	6
Four Pines Operating LLC \| Gros Ventre Partners, LLC
Related party transactions
Interest owned by former member of Board of Directors					25%
Barnwell Texas, LLC \| Four Pines Exploration LLC - Exploration - Series 1
Related party transactions
Broker's fee paid					$ 255
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) - USD ($) $ in Thousands		1 Months Ended		12 Months Ended
SUBSEQUENT EVENTS (Details) - USD ($) $ in Thousands	Jun. 09, 2023	Dec. 18, 2023	Nov. 30, 2023	Sep. 30, 2023
Restricted Stock Units (RSUs)
Subsequent Event [Line Items]
Number of restricted stock units granted (in shares)				37,312
Restricted Stock Units (RSUs) \| Share-based Payment Arrangement, Independent Director
Subsequent Event [Line Items]
Number of restricted stock units granted (in shares)	37,312
Subsequent Event \| Discontinued Operations, Held-for-Sale or Disposed of by Sale \| Water Resources International, Inc.
Subsequent Event [Line Items]
Proceeds from sale of Water Resources International, Inc.		$ 2,000
Subsequent Event \| Canada
Subsequent Event [Line Items]
Natural gas production sold at a fixed price			25%
Natural gas production sold at a spot price			75%
Oil production sold at a fixed price		40%
Oil production sold at a spot price		60%
Subsequent Event \| Restricted Stock Units (RSUs) \| Share-based Payment Arrangement, Independent Director
Subsequent Event [Line Items]
Number of restricted stock units granted (in shares)			76,366

SUPPLEMENTARY OIL AND NATURAL_3

SUPPLEMENTARY OIL AND NATURAL GAS INFORMATION (UNAUDITED) (Details) bbl in Thousands, Mcf in Thousands, Boe in Thousands, $ in Thousands	12 Months Ended
	Sep. 30, 2023 USD ($) Boe Mcf bbl	Sep. 30, 2022 USD ($) Boe bbl Mcf
Changes in the estimates of net interests in total proved reserves of oil and natural gas liquids and natural gas
Balance at the beginning of the period \| Boe	1,939	1,142
Revisions of previous estimates \| Boe	115	321
Extensions, discoveries and other additions \| Boe	756	737
Acquisitions of reserves \| Boe		137
Less sales of reserves \| Boe		(2)
Less production \| Boe	(467)	(396)
Balance at the end of the period \| Boe	2,343	1,939
Proved developed reserves - total \| Boe	2,132
Proved undeveloped reserves - total \| Boe	211
Capitalized Costs Relating to Oil and Natural Gas Producing Activities
Proved properties	$ 80,851	$ 67,883
Unproved properties	0	0
Total capitalized costs	80,851	67,883
Accumulated depletion, depreciation, and impairment	59,549	54,651
Net capitalized costs	21,302	13,232
Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development
Acquisition of proved properties	66	3,247
Acquisition of unproved properties	0	0
Exploration Costs	716	55
Development costs	11,430	10,453
Total	12,212	13,755
Additions and revisions to asset retirement obligation included in total costs incurred	1,483	2,703
Results of Operations for Oil and Natural Gas Producing Activities
Net revenues	19,376	22,581
Production costs	(10,434)	(9,439)
Depletion	(4,269)	(2,606)
Pre-tax results of operations	4,673	10,536
Estimated income tax expense	151	107
Results of operations	4,522	10,429
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Abstract]
Future cash inflows	89,424	100,334
Future production costs	(46,103)	(45,355)
Future development costs	(2,958)	(274)
Future income tax expenses	(1,776)	(7,141)
Future net cash flows excluding abandonment, decommissioning and reclamation	38,587	47,564
Future abandonment, decommissioning and reclamation	(18,627)	(16,730)
Future net cash flows	19,960	30,834
10% annual discount for timing of cash flows	(47)	(2,956)
Standardized measure of discounted future net cash flows	19,913	27,878
Changes in the Standardized Measure of Discounted Future Net Cash Flows
Beginning of year	27,878	2,645
Sales of oil and natural gas produced, net of production costs	(8,942)	(13,142)
Net changes in prices and production costs, net of royalties and wellhead taxes	(11,913)	27,828
Extensions and discoveries	10,767	8,889
Net change due to purchases and sales of minerals in place	0	2,451
Changes in future development costs	(2,959)	0
Revisions of previous quantity estimates	2,227	4,270
Net change in income taxes	2,868	(4,774)
Accretion of discount	905	(1,566)
Other - changes in the timing of future production and other	(1,202)	801
Other - net change in Canadian dollar translation rate	284	476
Net change	(7,965)	25,233
End of year	$ 19,913	$ 27,878
Canada
Changes in the estimates of net interests in total proved reserves of oil and natural gas liquids and natural gas
Balance at the beginning of the period \| Boe	1,769	1,142
Revisions of previous estimates \| Boe	5	321
Extensions, discoveries and other additions \| Boe	379	492
Acquisitions of reserves \| Boe		137
Less sales of reserves \| Boe		(2)
Less production \| Boe	(381)	(321)
Balance at the end of the period \| Boe	1,772	1,769
Proved developed reserves - total \| Boe	1,561
Proved undeveloped reserves - total \| Boe	211
Capitalized Costs Relating to Oil and Natural Gas Producing Activities
Proved properties	$ 74,440	$ 66,825
Unproved properties	0	0
Total capitalized costs	74,440	66,825
Accumulated depletion, depreciation, and impairment	58,477	54,248
Net capitalized costs	15,963	12,577
Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development
Acquisition of proved properties	66	3,247
Acquisition of unproved properties	0	0
Exploration Costs	461	55
Development costs	6,331	10,574
Total	6,858	13,876
Results of Operations for Oil and Natural Gas Producing Activities
Net revenues	16,630	19,085
Production costs	(9,859)	(8,999)
Depletion	(3,600)	(2,217)
Pre-tax results of operations	3,171	7,869
Estimated income tax expense	107	0
Results of operations	3,064	7,869
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Abstract]
Future cash inflows	73,429	93,658
Future production costs	(41,935)	(44,523)
Future development costs	(2,958)	(274)
Future income tax expenses	(1,512)	(6,908)
Future net cash flows excluding abandonment, decommissioning and reclamation	27,024	41,953
Future abandonment, decommissioning and reclamation	(18,585)	(16,719)
Future net cash flows	8,439	25,234
10% annual discount for timing of cash flows	4,790	(1,144)
Standardized measure of discounted future net cash flows	13,229	24,090
Changes in the Standardized Measure of Discounted Future Net Cash Flows
Beginning of year	24,090
End of year	$ 13,229	$ 24,090
United States
Changes in the estimates of net interests in total proved reserves of oil and natural gas liquids and natural gas
Balance at the beginning of the period \| Boe	170	0
Revisions of previous estimates \| Boe	110	0
Extensions, discoveries and other additions \| Boe	377	245
Acquisitions of reserves \| Boe		0
Less sales of reserves \| Boe		0
Less production \| Boe	(86)	(75)
Balance at the end of the period \| Boe	571	170
Proved developed reserves - total \| Boe	571
Proved undeveloped reserves - total \| Boe	0
Capitalized Costs Relating to Oil and Natural Gas Producing Activities
Proved properties	$ 6,411	$ 1,058
Unproved properties	0	0
Total capitalized costs	6,411	1,058
Accumulated depletion, depreciation, and impairment	1,072	403
Net capitalized costs	5,339	655
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	255	0
Development costs	5,099	(121)
Total	5,354	(121)
Results of Operations for Oil and Natural Gas Producing Activities
Net revenues	2,746	3,496
Production costs	(575)	(440)
Depletion	(669)	(389)
Pre-tax results of operations	1,502	2,667
Estimated income tax expense	44	107
Results of operations	1,458	2,560
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Abstract]
Future cash inflows	15,995	6,676
Future production costs	(4,168)	(832)
Future development costs	0	0
Future income tax expenses	(264)	(233)
Future net cash flows excluding abandonment, decommissioning and reclamation	11,563	5,611
Future abandonment, decommissioning and reclamation	(42)	(11)
Future net cash flows	11,521	5,600
10% annual discount for timing of cash flows	(4,837)	(1,812)
Standardized measure of discounted future net cash flows	6,684	3,788
Changes in the Standardized Measure of Discounted Future Net Cash Flows
Beginning of year	3,788
End of year	$ 6,684	$ 3,788
OIL & NGL (Bbls)
Changes in the estimates of net interests in total proved reserves of oil and natural gas liquids and natural gas
Balance at the beginning of the period \| bbl	1,080	640
Revisions of previous estimates \| bbl	6	154
Extensions, discoveries and other additions \| bbl	396	417
Acquisitions of reserves \| bbl		99
Less production \| bbl	(256)	(230)
Balance at the end of the period \| bbl	1,226	1,080
Proved developed reserves - volume \| bbl	1,116
Proved undeveloped reserves - volume \| bbl	110
OIL & NGL (Bbls) \| Canada
Changes in the estimates of net interests in total proved reserves of oil and natural gas liquids and natural gas
Balance at the beginning of the period \| bbl	990	640
Revisions of previous estimates \| bbl	(42)	154
Extensions, discoveries and other additions \| bbl	199	285
Acquisitions of reserves \| bbl		99
Less production \| bbl	(210)	(188)
Balance at the end of the period \| bbl	937	990
Proved developed reserves - volume \| bbl	827
Proved undeveloped reserves - volume \| bbl	110
OIL & NGL (Bbls) \| United States
Changes in the estimates of net interests in total proved reserves of oil and natural gas liquids and natural gas
Balance at the beginning of the period \| bbl	90	0
Revisions of previous estimates \| bbl	48	0
Extensions, discoveries and other additions \| bbl	197	132
Acquisitions of reserves \| bbl		0
Less production \| bbl	(46)	(42)
Balance at the end of the period \| bbl	289	90
Proved developed reserves - volume \| bbl	289
Proved undeveloped reserves - volume \| bbl	0
Natural gas
Changes in the estimates of net interests in total proved reserves of oil and natural gas liquids and natural gas
Balance at the beginning of the period \| Mcf	4,985	2,913
Revisions of previous estimates \| Mcf	822	968
Extensions, discoveries and other additions \| Mcf	2,157	1,858
Acquisitions of reserves \| Mcf		223
Less sales of reserves \| Mcf		(13)
Less production \| Mcf	(1,263)	(964)
Balance at the end of the period \| Mcf	6,701	4,985
Proved developed reserves - volume \| Mcf	6,093
Proved undeveloped reserves - volume \| Mcf	608
Natural gas \| Canada
Changes in the estimates of net interests in total proved reserves of oil and natural gas liquids and natural gas
Balance at the beginning of the period \| Mcf	4,519	2,913
Revisions of previous estimates \| Mcf	435	968
Extensions, discoveries and other additions \| Mcf	1,079	1,200
Acquisitions of reserves \| Mcf		223
Less sales of reserves \| Mcf		(13)
Less production \| Mcf	(1,023)	(772)
Balance at the end of the period \| Mcf	5,010	4,519
Proved developed reserves - volume \| Mcf	4,402
Proved undeveloped reserves - volume \| Mcf	608
Natural gas \| United States
Changes in the estimates of net interests in total proved reserves of oil and natural gas liquids and natural gas
Balance at the beginning of the period \| Mcf	466	0
Revisions of previous estimates \| Mcf	387	0
Extensions, discoveries and other additions \| Mcf	1,078	658
Acquisitions of reserves \| Mcf		0
Less sales of reserves \| Mcf		0
Less production \| Mcf	(240)	(192)
Balance at the end of the period \| Mcf	1,691	466
Proved developed reserves - volume \| Mcf	1,691
Proved undeveloped reserves - volume \| Mcf	0