What changed in this filing

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Item 7. Management’s Discussion and Analysis

2025-12-23 compared with 2024-12-17 · 162 added, 175 removed, 234 unchanged (59% of the section changed)

3 unchanged sentences

This discussion should be read in conjunction with the consolidated financial statements and related Notes to Consolidated Financial Statements included in this report.

On March 14, 2025, the Company entered into and completed the sale of its wholly-owned subsidiary, Water Resources.

Water Resources drills water wells and installs and repairs water pumping systems in Hawaii and represented our contract drilling segment.

As a result of the sale, the Company has classified the related assets and liabilities and the results of its contract drilling business as discontinued operations in the consolidated financial statements for all periods presented.

Prior to the sale, the Company did not have any assurances that a sale of Water Resources was likely to occur.

Unless otherwise noted, the discussions below pertains only to Barnwell’s continuing operations.

For information on discontinued operations, refer to Note 3 “Discontinued Operations” in the Notes to Consolidated Financial Statements in Item 8 of this report.

Critical Accounting Policies and Estimates

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If reported reserve volumes were revised downward by 5% at the end of fiscal 2025, the ceiling limitation for Canada would have decreased approximately $636,000 which would not have resulted in a ceiling impairment before income taxes due to sufficient room between the ceiling and the carrying value of Canadian oil and natural gas properties at the end of fiscal 2025 of approximately $2,949,000.

However, an additional $197,000 impairment would be recorded for U.S.

oil and gas properties at the end of fiscal 2024 as there is no room between the ceiling and the carrying value of U.S.

oil and natural gas properties at the end of fiscal 2024.

In addition to the impact of the estimates of proved reserves on the calculation of the ceiling, estimated proved reserves are also a significant component of the quarterly calculation of depletion expense.

6 unchanged sentences

As such, the future net revenues associated with the estimated proved reserves are not based on an assessment of future prices or costs.

Contract Drilling Revenues and Operating Expenses

Policy Description

Through contracts which are normally less than twelve months in duration, Barnwell drills water and water monitoring wells and installs and repairs water pumping systems in Hawaii.

recognizes revenue from well drilling or the installation of pumps over time based on total costs incurred on the projects relative to the total expected costs to satisfy the performance obligation as management believes this is an accurate representation of the percentage of completion as control is continuously transferred to the customer.

Uninstalled materials, which typically consists of well casing or pumps, are excluded in the costs-to-costs calculation for the duration of the contract as including these costs would result in a distortion of progress towards satisfaction of the performance obligation due to the resulting cumulative catch-up in margin in a single period.

An equal amount of cost and revenue is recorded when uninstalled materials are controlled by the customer, which is typically when Barnwell has the right to payment for the materials and when the materials are delivered to the customer’s site or location and such materials have been accepted by the customer.

Uninstalled materials are held in inventory and included in “Other current assets” on the Company’s Consolidated Balance Sheets until control is transferred to the customer.

When the estimate on a contract indicates a loss, Barnwell records the entire estimated loss in the period the loss becomes known.

Unexpected significant inefficiencies that were not considered a risk at the time of entering into the contract, such as design or construction execution errors that result in significant wasted resources, are excluded from the measure of progress toward completion and the costs are expensed as incurred.

To the extent a contract is deemed to have multiple performance obligations, the Company allocates the transaction price of the contract to each performance obligation using its best estimate of the standalone selling price of each distinct good or service in the contract.

The contract price may include variable consideration, which includes such items as increases to the transaction price for unapproved change orders and claims for which price has not yet been agreed by the customer.

The Company estimates variable consideration using either the most likely amount or expected value method, whichever is a more appropriate reflection of the amount to which it expects to be entitled based on the characteristics and circumstances of the contract.

Variable consideration is included in the estimated transaction price to the extent it is probable that a significant reversal of cumulative recognized revenue will not occur.

Contracts are sometimes modified for a change in scope or other requirements.

The Company considers contract modifications to exist when the modification either creates new or changes the existing enforceable rights and obligations.

Most of the Company’s contract modifications are for goods and services that are not distinct from the existing performance obligations.

The effect of a contract modification on the transaction price, and the measure of progress for the performance obligation to which it relates, is recognized as an adjustment to revenue (either as an increase or decrease) on a cumulative catchup basis.

Judgments and Assumptions

Management evaluates the performance of contracts on an individual basis.

In the ordinary course of business, but at least quarterly, we prepare updated estimates that may impact the cost and profit or loss for each contract based on actual results to date plus management’s best estimate of costs to be incurred to complete each performance obligation.

Increases or decreases in the estimated costs to complete a performance obligation without a change to the contract price has the impact to decrease or increase, respectively, the contract completion percentage applied to the contract price to calculate the cumulative contract revenue to be recognized to date.

Changes in the cost estimates can have a material impact on our contract revenue and are reflected in the results of operations when they become known.

The nature of accounting for these contracts is such that refinements of the estimated costs to complete may occur and are characteristic of the estimation process due to changing conditions and new developments.

Many factors and assumptions can and do change during a contract performance obligation period which can

result in a change to contract profitability including unforeseen underground geological conditions (to the extent that contract remedies are unavailable), the availability and costs of skilled contract labor, the performance of major material suppliers, the performance of major subcontractors, unusual weather conditions and unexpected changes in material costs, changes in the scope and nature of work to be performed, and unexpected construction execution errors, among others.

Any revisions to estimated costs to complete the performance obligation from period to period as a result of changes in these factors can materially affect revenue and operating results in the period such revisions are necessary.

In addition, many contracts give the customer a unilateral right to cancel for convenience or other than for cause.

In accordance with FASB ASC 606-10-32-4, our estimates are based on the assumption that the existing contract will not be cancelled.

Any unforeseen cancellation of a contract may result in a material revision to our estimates.

We have a long history of working with multiple types of projects and preparing cost estimates, and we rely on the expertise of key personnel to prepare what we believe are reasonable best estimates given available facts and circumstances.

Due to the nature of the work involved, however, judgment is involved to estimate the costs to complete and the amounts estimated could have a material impact on the revenue we recognize in each accounting period.

We can not estimate unforeseen events and circumstances which may result in actual results being materially different from previous estimates.

Policy Description

Income taxes are determined using the asset and liability method.

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1) acquiring, developing, producing and selling oil and natural gas in Canada and the U.S.

(oil and natural gas segment), 2) leasehold land interests in Hawaii (land investment segment), and 3) drilling wells and installing and repairing water pumping systems in Hawaii (contract drilling segment).

(oil and natural gas segment) and 2) leasehold land interests in Hawaii (land investment segment).

Oil and Natural Gas Segment

Barnwell is involved in the acquisition and development of oil and natural gas properties primarily in the Twining area of Alberta, Canada, where we initiate and participate in acquisition and developmental operations for oil and natural gas on properties in which we have an interest, and evaluate proposals by third parties with regard to participation in such exploratory and developmental operations elsewhere.

Additionally, through its wholly-owned subsidiaries BOK and Barnwell Texas, Barnwell is involved in non-operated oil and natural gas investments in Oklahoma and Texas, respectively.

Additionally, through its wholly-owned subsidiaries BOK and Barnwell Texas, Barnwell was, until August 8, 2025, involved in non-operated oil and natural gas investments in Oklahoma and Texas, respectively.

Barnwell sells all of its Canadian and U.S.

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Barnwell is committed to commence construction of improvements within 90 days of the transfer of the four lots in the phases subsequent to Phase 2A as a condition of the transfer of such lots.

Also, in addition to Barnwell's existing obligations to pay professional fees to certain parties based on percentages of its gross receipts, Kaupulehu Developments is also obligated to pay an amount equal to 0.72% and 0.20% of the cumulative net profits of KD II to KD Development, LLC and a pool of various individuals, respectively, all of whom are partners of KKM and are unrelated to Barnwell.

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 obligated to pay an amount equal to 0.72% and 0.20% of the cumulative net profits of KD II to KD Development, LLC and a pool of various individuals, respectively, all of whom are partners of KKM and are unrelated to Barnwell.

The remaining acreage within Increment II is not yet under development, and there is no assurance that development of such acreage will in fact occur.

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The Kukio Resort Land Development Partnerships have remaining Increment I obligations to complete project amenities, infrastructure, beautification, and restoration of certain areas and therefore has yet to fully recognize its deferred profit on the Increment I project as a whole.

The Increment I deferred profit at September 30, 2024 for the Kukio Resort Land

Development Partnerships as a whole was approximately $4,500,000;

The Increment I deferred profit at September 30, 2025 for the Kukio Resort Land Development Partnerships as a whole was approximately $4,500,000;

the recognition of which is dependent upon the completion of the Increment I obligations.

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The Kukio Resort Land Development Partnerships will recognize the Increment I deferred revenue and costs of sales on a percentage completion basis as the cash outlays to complete the remaining project obligations are made.

The Kukio Resort Land Development Partnerships’ deferred profit and accrued costs to complete are not reflected in Barnwell’s Condensed Consolidated Balance Sheets as we account for our investment in the Kukio Resort Land Development Partnerships under the equity method of accounting.

The Kukio Resort Land Development Partnerships’ deferred profit and accrued costs to complete are not reflected in Barnwell’s Consolidated Balance Sheets as we account for our investment in the Kukio Resort Land Development Partnerships under the equity method of accounting.

No percentage of sales payments will be earned by Barnwell on any future recognition of Increment I deferred profit as such payments were already fully earned and received based on cash received by the Kukio Resort Land Development Partnerships as the Increment I lots were sold.

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The lease terminates in December 2025.

Contract Drilling Segment

Barnwell drills water and water monitoring wells and installs and repairs water pumping systems in Hawaii.

Contract drilling results are highly dependent upon the quantity, dollar value and timing of contracts awarded by governmental and private entities and can fluctuate significantly.

In November 2025, Kaupulehu Developments entered into an agreement with Mr.

David Johnston, the son of Mr.

Terry Johnston, a partner in Kaupulehu Developments, to surrender any and all remaining rights for Increment II for $2,000,000 of which $70,000 was received.

Additionally, the purchaser has the right to extend the closing by up to two years by making a $70,000 payment in each of the next two years, with those payments applied against the $2,000,000 purchase price.

The closing of this transaction is entirely dependent on the purchaser and therefore may not happen.

Subsequent to fiscal 2025, pursuant to a unit purchase agreement KDK, of which Barnwell holds a 19.6% interest, agreed to sell KDK’s interests in Increment II to Mr.

David Johnston for $2,109,000.

The unit purchase agreement is subject to due diligence, and there is no certainty that the transaction will close.

Furthermore, there is also no assurance on the timing or amounts that the general partner of KDK would distribute upon a closing.

Business Environment

Our operations are located in Canada and in the states of Hawaii, Oklahoma, and Texas.

Our operations are located in Canada and in the state of Hawaii and Texas.

Accordingly, our business performance is directly affected by macroeconomic conditions in those areas, as well as general economic conditions of the U.S.

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Future revenues from the sale of interest in leasehold land and any future cash distributions from our investment in the Kukio Resort Land Development Partnerships are dependent upon the potential future development or sale of the remaining portion of Increment II by KD II of Kaupulehu Lot 4A.

our control, and there is no assurance with regards to the amounts of future payments from Increment II to be received or that the remaining acreage within Increment II will be developed.

The amount and timing of future land investment segment proceeds from percentage of sales payments and cash distributions from the Kukio Resort Land Development Partnerships are highly uncertain and out of our control, and there is no assurance with regards to the amounts of future payments from Increment II to be received or that the remaining acreage within Increment II will be developed.

No definitive development plans have been made by KD II, the developer of Increment II, as of the date of this report.

Contract Drilling Segment

Demand for water well drilling and/or pump installation and repair services is volatile and dependent upon land development activities within the state of Hawaii.

Results of Operations

Net loss attributable to Barnwell for fiscal 2024 totaled $5,565,000, a $4,604,000 increase in net loss from a net loss of $961,000 in fiscal 2023.

Summary of Results From Continuing Operations

The net loss from continuing operations attributable to Barnwell for fiscal 2025 totaled $7,115,000, a $3,010,000 increase from a net loss from continuing operations attributable to Barnwell of $4,105,000 in fiscal 2024.

The following factors affected the results of operations for the current fiscal year as compared to the prior fiscal year:

• A $4,958,000 decrease in oil and natural gas segment operating results, before income taxes, primarily attributable to a $2,885,000 non-cash ceiling test impairment in the current year and due to decreases in natural gas, oil, and natural gas prices in the current year period as compared to the same period in the prior year;

• A $599,000 decrease in contract drilling segment operating results, before income taxes, primarily resulting from decreased activity and an increase in drilling difficulties and labor costs as compared to the same period in the prior year;

• A $551,000 gain recognized in the prior year period from the sale of a contract drilling segment drilling rig, whereas there was no such gain in the current year period;

• Results improved as general and administrative expenses decreased $1,358,000 primarily due to decreases in stockholder costs and professional fees in the current year period as compared to the same period in the prior year.

• General and administrative expenses increased $1,807,000 due to $1,958,000 in new fees and costs incurred, net of $348,000 of estimated accrued insurance recoveries, related to a shareholder consent solicitation, various legal actions between the Sherwood Group and the Company and certain of its directors, and a proxy contest in the current year period as compared to the same period in the prior year;

• Equity in income from affiliates decreased $1,071,000 and land investment segment operating results, before non-controlling interests’ share of such profits, decreased $500,000 due to the Kukio Resort Land Development Partnerships' sale of two lots in the prior year period, whereas there was no lots sold in the current year period;

• A $636,000 loss recognized in the current year period from the sale of all of the U.S.

oil and natural gas properties, whereas there was no such loss in the prior year period;

• A $192,000 foreign currency loss recorded in the current year period due to the effects of the foreign exchange rate changes on intercompany loans and advances as a result of the strengthening of the U.S.

dollar against the Canadian dollar.

Barnwell conducts operations in the U.S.

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dollar decreased 3% in fiscal 2025, as compared to fiscal 2024 and the exchange rate of the Canadian dollar to the U.S.

dollar remained unchanged at September 30, 2024, as compared to September 30, 2023.

Accordingly, the assets, liabilities, stockholders’ equity and revenues and expenses of Barnwell’s subsidiaries operating in Canada have been

adjusted to reflect the change in the exchange rates.

dollar decreased 3% at September 30, 2025, as compared to September 30, 2024.

Accordingly, the assets, liabilities, stockholders’ equity and revenues and expenses of Barnwell’s subsidiaries operating in Canada have been adjusted to reflect the change in the exchange rates.

Other comprehensive income and losses are not included in net earnings and net loss.

Other comprehensive loss due to foreign currency translation adjustments, net of taxes, for fiscal 2024 was nil, a $2,000 change from other comprehensive loss due to foreign currency translation adjustments, net of taxes, of $2,000 in fiscal 2023.

There were no taxes on other comprehensive loss due to foreign currency translation adjustments in fiscal 2024 and 2023 due to a full valuation allowance on the related deferred tax assets.

Other comprehensive income due to foreign currency translation adjustments, net of taxes, for fiscal 2025 was $75,000, a $75,000 change from other comprehensive loss due to foreign currency translation adjustments, net of taxes, of nil in fiscal 2024.

There were no taxes on other comprehensive

income due to foreign currency translation adjustments in fiscal 2025 and 2024 due to a full valuation allowance on the related deferred tax assets.

Oil and natural gas

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* Natural gas price per unit is net of pipeline charges.

The oil and natural gas segment generated a $285,000 operating loss in fiscal 2024 before general and administrative expenses, a decrease in operating results of $4,958,000 as compared to $4,673,000 of operating profit in fiscal 2023.

The following table sets forth Barnwell’s oil and natural gas segment operating (loss) profit before general and administrative expenses by geographic location:

The oil and natural gas segment generated a $588,000 operating profit in fiscal 2025 before general and administrative expenses, an increase in operating results of $873,000 as compared to a $285,000 operating loss in fiscal 2024.

The following table sets forth Barnwell’s oil and natural gas segment operating profit (loss) before general and administrative expenses by geographic location:

Year ended September 30,

Operating (loss) profit (before general and administrative expenses)

Operating profit (loss) (before general and administrative expenses)

$ 1,045,000 $ (440,000)

1 unchanged sentence

(457,000) 155,000

Total operating (loss) profit $ (285,000) $ 4,673,000

Total operating profit (loss) $ 588,000 $ (285,000)

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(1) The operating loss for Canada for the year ended September 30, 2024 includes a non-cash ceiling test impairment of $2,164,000.

(2) The operating profit for the United States for year ended September 30, 2024 includes a non-cash ceiling test impairment of $721,000.

Oil and natural gas revenues decreased $1,980,000 (10%) from $19,376,000 in fiscal 2023 to $17,396,000 in fiscal 2024, primarily due to significant decreases in natural gas, oil, and natural gas liquid prices, which decreased 47%, 5%, and 9%, respectively, as compared to the same period in the prior year.

The decrease was partially offset by 6% and 23% increases in natural gas and natural gas liquid production, respectively, as compared to the same period in the prior year.

In the quarter ended December 31, 2023, the Company amended certain of its Canadian purchase and sales contracts to change the sales price on 1,055 gross Mcf per day of the Canadian natural gas that it sells during the period from April 1, 2024 to October 31, 2024 to a fixed index price before differentials of $2.55 Canadian dollars per Mcf, with remaining volumes continuing to be sold at spot prices.

This per day volume of natural gas under fixed index price contract is equivalent to approximately 33% of Canadian natural gas gross production per day for the year ended September 30, 2024.

In July 2024, the Company amended the sales price on 1,055 gross Mcf per day of the Canadian natural gas it will sell during the period from November 1, 2024 to March 31, 2025 to a fixed index price before differentials of $2.64 Canadian dollars per Mcf, with remaining volumes continuing to be sold at spot prices.

This per day volume of natural gas under this fixed index price contract is equivalent to approximately 33% of Canadian natural gas gross production per day for the year ended September 30, 2024.

(2) The operating (loss) profit for the United States for the years ended September 30, 2025 and 2024 includes non-cash ceiling test impairments of $865,000 and $721,000, respectively.

Oil and natural gas revenues decreased $3,833,000 (22%) from $17,396,000 in fiscal 2024 to $13,563,000 in fiscal 2025, primarily due primarily due to decreases in natural gas, oil, and natural gas liquids production, which decreased 18%, 14%, and 13%, respectively, in the current year period as compared to the same period in the prior year.

The decrease in production was primarily the result of

natural declines in production from wells in the Company's Twining area as the wells age, and to a lesser extent due to properties sold in the prior year.

Revenues also decreased due to a decrease in oil prices which decreased 9% as compared to the same period in the prior year.

In February 2025, the Company amended certain of its Canadian purchase and sales contracts to change the sales price on 1,055 gross Mcf per day of the Canadian natural gas it will sell during the period from April 1, 2025 to October 31, 2025 to a fixed index price before differentials of $1.95 Canadian dollars per Mcf, with remaining volumes continuing to be sold at spot prices.

This per day volume of natural gas under this fixed index price contract was equivalent to approximately 38% of Canadian natural gas gross production per day for the year ended September 30, 2025.

Additionally, in September 2025, the Company amended the sales price on 1,583 gross Mcf per day of the Canadian natural gas it will sell during the period from November 1, 2025 to March 31, 2026 to a fixed index price before differentials of $3.03 Canadian dollars per Mcf, with remaining volumes continuing to be sold at spot prices.

This per day volume of natural gas under this fixed index price contract that will affect the period from November 1, 2025 to March 31, 2026, is equivalent to approximately 58% of Canadian natural gas gross production per day for the year ended September 30, 2025.

These natural gas contracts were eligible for and elected as normal purchase and normal sales exception contracts and were thus excluded from derivative accounting.

In the quarter ended December 31, 2023, the Company amended certain of its Canadian purchase and sales contracts to change the sales price on 225 gross barrels per day of the Canadian oil for sale for the period from January 1, 2024 to June 30, 2024 to a fixed index price before differentials of $69.46 per net barrel, with remaining volumes continuing to be sold at spot prices.

This per day volume of oil under this fixed index price contract was equivalent to approximately 35% of Canadian oil gross production per day for the year ended September 30, 2024.

In July 2024, the Company amended the sales price on 100 gross barrels per day of the Canadian oil that it sells during the period from August 1, 2024 to December 31, 2024 to a fixed index price before differentials of $79.00 per net barrel, with remaining volumes continuing to be sold at spot prices.

This per day volume of oil under this fixed index price contract is equivalent to approximately 16% of Canadian oil gross production per day for the year ended September 30, 2024.

In June 2025, the Company amended the sales price on 100 gross barrels per day of the Canadian oil that it will sell during the period from July 1, 2025 to December 31, 2025 to a fixed index price before differentials of $70.35 per net barrel, with remaining volumes continuing to be sold at spot prices.

This per day volume of oil under this fixed index price was equivalent to approximately 19% of Canadian oil gross production per day for the year ended September 30, 2025.

These oil contracts were eligible for and elected as normal purchase and normal sales exception contracts and were thus excluded from derivative accounting.

Oil and natural gas operating expenses decreased $585,000 (6%) from $10,434,000 in fiscal 2023 to $9,849,000 in fiscal 2024, primarily due to decreases in repairs, electricity and chemical costs in the current year period as compared to the same period in the prior year and due to optimization as a result of

certain capital expenditures made earlier in the current year.

The decrease in oil and natural gas operating expenses was partially offset by an increase in costs due to higher production and an increase in workovers and maintenance costs in the current year period as compared to the same period in the prior year.

Oil and natural gas segment depletion increased $678,000 (16%) from $4,269,000 in fiscal 2023 to $4,947,000 in fiscal 2024, primarily due to an increase in the depletion rate for Canadian properties and also increased production from those properties, both of which were the result of the wells drilled in fiscal 2023 and late fiscal 2024, and facilities expansion and upgrade costs, all in the Twining area.

The increase in oil and natural gas segment depletion was also due to increased depletion from production in Texas, whereas there was only a minor amount of such depletion in the prior year period.

Subsequently, in October 2025, the Company amended the sales price on 1,055 gross Mcf per day of the Canadian natural gas it will sell during the period from April 1, 2026 to October 31, 2026 to a fixed index price before differentials of $2.94 Canadian dollars per Mcf, with remaining volumes continuing to be sold at spot prices.

This per day volume of natural gas under this fixed index price contract that will affect the period from April 1, 2026 to October 31, 2026, is equivalent to approximately 38% of Canadian natural gas gross production per day for the year ended September 30, 2025.

Oil and natural gas operating expenses decreased $883,000 (9%) from $9,849,000 in fiscal 2024 to $8,966,000 in fiscal 2025, primarily due to decreases in production in the current year, partially offset by an increase in workovers in the current year, as compared to the prior year.

Oil and natural gas segment depletion decreased $1,803,000 (36%) from $4,947,000 in fiscal 2024 to $3,144,000 in fiscal 2025, primarily due to decreases in the depletion rate and due to decreases in production in the current year as compared to the prior year.

The depletion rate decreased as a result of a decrease in the depletable base from significant ceiling test impairments between the prior year period and the current year period.

On August 8, 2025, Barnwell entered into an agreement with an independent third party to sell all of its working interests in its U.S.

oil and natural gas assets for a sales price of $2,300,000.

The sales price per the agreement was adjusted for customary purchase price adjustments to reflect the economic activity from the effective date of July 1, 2025 to the closing date August 8, 2025.

The Company recognized a loss on the sale of $636,000 before related income taxes in the year ended September 30, 2025.

oil and natural gas assets were located in the states of Texas and Oklahoma and were owned by wholly-

owned subsidiaries of Barnwell.

As a result of the sale, the Company no longer owns any oil and natural gas assets in the U.S., however, the Company will continue to explore for oil and natural gas opportunities in the U.S.

Sale of interest in leasehold land

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Sale of interest in leasehold land, net of fees paid $ — $ 439,000

No lots were sold during the year ended September 30, 2025.

During the year ended September 30, 2024, Barnwell received $500,000 in percentage of sales payments from KD I from the sale of the last two single-family lots within Increment I.

During the year ended September 30, 2023, Barnwell received $265,000 in percentage of sales payments from KD I from the sale of one single-family lot within Increment I.

There is an Increment II owned by KD II in which the Company has a 10.8% indirect non-controlling ownership interest.

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No definitive development plans have been made by KD II, the developer of Increment II, as of the date of this report.

Contract drilling

Contract drilling revenues and costs are associated with well drilling and water pump installation, replacement and repair in Hawaii.

Contract drilling revenues decreased $1,815,000 (33%) to $3,612,000 in fiscal 2024, as compared to $5,427,000 in fiscal 2023 and contract drilling costs decreased $1,186,000 (21%) to $4,483,000 in fiscal 2024, as compared to $5,669,000 in fiscal 2023.

The contract drilling segment generated a $1,027,000 operating loss before general and administrative expenses during fiscal 2024, a decrease in operating results of $599,000 as compared to an operating loss before general and administrative expenses of $428,000 in fiscal 2023.

The decreases in contract drilling revenues and contract drilling costs for the current year period as compared to the same period in the prior year were primarily due to decreased activity and a decrease in

revenues and costs recognized from materials deliveries and installations as compared to the same period in the prior year.

Also, during the current year period, unforeseen drilling difficulties were encountered on a job where costs were spent to retrieve a portion of the drill string that twisted off and slower drilling was required to ensure plumbness of the hole.

In addition, the Company commenced compensation adjustments for contract drilling segment personnel to decrease potential attrition of workers and enable the Company to complete its drilling obligations.

These factors resulted in contract drilling expenses decreasing less than the decrease in contract drilling revenues.

On December 13, 2023, the Company entered into a stock purchase agreement with a construction company for the sale of Water Resources.

On December 27, 2023, the stock purchase agreement was terminated by the buyer prior to closing.

In January 2024, a significant well drilling contract, which previously had an estimated contract drilling revenue backlog of $2,400,000 and which had not yet started, was cancelled by mutual agreement of Water Resources and the counterparty.

At September 30, 2024, there was a backlog of one well drilling and two pump installation and repair contracts and all of the contracts were in progress as of September 30, 2024.

The backlog of contract drilling revenues as of December 1, 2024 was approximately $1,100,000, all of which is expected to be realized in fiscal 2025.

Based on these contracts in backlog, contract drilling segment operating results for fiscal 2025 is estimated to be significantly less than fiscal 2024.

The Company continues to investigate strategies regarding Water Resources' future including, but not limited to, other potential opportunities for a sale of its stock or assets.

If no sale of its stock or assets along with contract backlog can be secured, Water Resources will likely be wound down after all contracts in backlog are completed and any remaining drilling rigs and equipment will be liquidated.

Management estimates that its three remaining contracts in backlog at September 30, 2024 will be completed in March 2025 or soon thereafter, however it is uncertain as to when the contingent liability related to the required drilling of a monitoring well in satisfaction of a regulatory assessment will be settled (see Note 17 in the “Notes to Consolidated Financial Statements” in Item 8 of this report).

In November 2025, Kaupulehu Developments entered into an agreement with Mr.

David Johnston, the son of Mr.

Terry Johnston, a partner in Kaupulehu Developments, to surrender any and all remaining rights for Increment II for $2,000,000 of which $70,000 was.

The closing of this transaction is entirely dependent on the purchaser and therefore may not happen.

Subsequent to fiscal 2025, pursuant to a unit purchase agreement KDK, of which Barnwell holds a 19.6% interest, agreed to sell KDK’s interests in Increment II to Mr.

David Johnston for $2,109,000.

The unit purchase agreement is subject to due diligence, and there is no certainty that the transaction will close.

Furthermore, there is also no assurance on the timing or amounts that the general partner of KDK would distribute upon a closing.

General and administrative expenses

General and administrative expenses decreased $1,358,000 (20%) to $5,598,000 in fiscal 2024, as compared to $6,956,000 in fiscal 2023.

The decrease was primarily due to decreases of $962,000 in professional fees primarily related to legal and consulting services and $533,000 in stockholders costs primarily attributed to the cooperation and support agreement and associated fees to certain directors in the prior year period as compared to the same period in the current year.

General and administrative expenses increased $1,807,000 (35%) to $6,937,000 in fiscal 2025, as compared to $5,130,000 in fiscal 2024.

The increase was primarily due to $1,958,000 in new fees and costs incurred, net of $348,000 of estimated accrued insurance recoveries receivable, for legal services, proxy solicitation, proxy advisory, and public relations costs related to a shareholder consent solicitation,

various legal actions between the Sherwood Group and the Company and certain of its directors, and a proxy contest in the current year period as compared to the same period in the prior year.

The amount of estimated accrued insurance recoveries receivable aforementioned above is management's best estimate of the probable recoverable amount under the insurance policies.

While the insurer has confirmed that certain costs incurred by the Company are eligible for claim under the Company's insurance policies, the amount ultimately recoverable through insurance is dependent upon the insurer's completion of their review of eligible legal costs incurred and the recoverable amount may differ from management's estimate.

Depletion, depreciation, and amortization

Depletion, depreciation, and amortization increased $649,000 (15%) from $4,457,000 in fiscal 2023 to $5,106,000 in fiscal 2024, primarily due to increases in the depletion rate for Canadian properties and also new production from those properties and due to depletion attributable to production in Texas as discussed in the “Oil and natural gas” section above.

Depletion, depreciation, and amortization decreased $1,804,000 (36%) from $4,950,000 in fiscal 2024 to $3,146,000 in fiscal 2025, primarily due to decreases in the depletion rate and decreases in production, as discussed in the “Oil and natural gas” section above.

Impairment of assets

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Changes in the 12-month rolling average first-day-of-the-month prices for oil, natural gas and natural gas liquids prices (except where prices are defined by contractual arrangements), the value of reserve additions as compared to the amount of capital expenditures to obtain them, and changes in production rates and estimated levels of reserves, future development costs and the market value of unproved properties, impact the determination of the maximum carrying value of oil and natural gas properties.

During the year ended September 30, 2025, the Company incurred a non-cash ceiling test impairment for our U.S.

oil and natural gas properties of $865,000.

During the year ended September 30, 2024, the Company incurred a non-cash ceiling test impairment of $2,885,000, which included impairments for our U.S.

and Canadian oil and natural gas properties of $721,000 and $2,164,000, respectively.

The impairments to our U.S.

and Canadian oil and natural gas properties were primarily due to a decline in the historical 12-month rolling average first-day-of-the-month prices.

There was no ceiling test impairment during the year ended September 30, 2023.

As discussed above, the ceiling test uses a 12-month historical rolling average first-day-of-the-month prices.

As such, declines in the 12-month historical rolling average first-day-of-the-month prices used in our ceiling test calculation in future periods could result in impairment write-downs in future periods in the absence of any offsetting factors that are not currently known or projected.

Based on the oil and gas prices for October 1, November 1 and December 1 of 2024, the oil prices and natural gas prices used in the 12-month historical rolling first-day-of-the-month average oil price for the ceiling test at December 31, 2024 will be lower than at September 30, 2024.

Whereas we believe our Canadian full cost pool is sufficiently below the ceiling limit, our U.S.

full cost pool had no ceiling excess at September 30, 2024, and thus a further impairment charge is more likely than not for our U.S full cost pool for the first quarter of fiscal 2025 ending December 31, 2024.

Based on the oil and gas prices for October 1, November 1 and December 1 of 2025, the oil prices used in the 12-month historical rolling first-day-of-the-month average for the ceiling test at December 31, 2025 are likely to be lower than at September 30, 2025.

As such, we may incur a further impairment charge in the first quarter of fiscal 2026 ending December 31, 2025.

The Company is currently unable to estimate a range of the amount of any potential future impairment write-downs as variables that impact the ceiling limitation are dependent upon actual results of activity through the end of December 2025.

Foreign currency gain

Foreign currency gain was $10,000 and $76,000 during the years ended September 30, 2024 and 2023, respectively, due to the effects of foreign exchange rate changes on intercompany loans and advances as a result of changes in the U.S.

Foreign currency loss (gain)

Foreign currency loss was $192,000 during the year ended September 30, 2025, as compared to a foreign currency gain of $10,000 during the year ended September 30, 2024, due to the effects of foreign exchange rate changes on intercompany loans and advances as a result of changes in the exchange rate between the U.S.

dollar against the Canadian dollar.

The foreign currency gains from intercompany balances are included in our consolidated statement of operations as the intercompany balances were not considered long-term in nature because management estimates that these intercompany balances will be settled in the future.

Gain on sale of assets

In October 2022, the Company completed the sale of a contract drilling segment drilling rig to an independent third party for proceeds of $551,000, net of related costs.

The drilling rig was fully depreciated and had a net book value of zero and as a result of the sale, the Company recognized a $551,000 gain during the year ended September 30, 2023.

The foreign currency losses or gains from

intercompany balances are included in our Consolidated Statements of Operations as the intercompany balances were not considered long-term in nature because management estimates that these intercompany balances will be settled in the future.

Loss on sale of assets

On August 8, 2025, Barnwell entered into an agreement with an independent third party to sell all of its working interests in its U.S.

oil and natural gas assets for a sales price of $2,300,000.

The sales price per the agreement was adjusted for customary purchase price adjustments to reflect the economic activity from the effective date of July 1, 2025 to the closing date August 8, 2025.

The Company recognized a loss on the sale of $636,000 before related income taxes in the year ended September 30, 2025.

Equity in income of affiliates

Barnwell’s investment in the Kukio Resort Land Development Partnerships is accounted for using the equity method of accounting.

Barnwell recognized equity in income of affiliates of $1,071,000 for the

year ended September 30, 2024, as compared to equity in income of affiliates of $758,000 for the year ended September 30, 2023.

The increase in partnership income is primarily due to the Kukio Resort Land Development Partnerships' sale of the last two lots in Increment I during the current year period, as compared to one lot sale in the prior year period.

During the year ended September 30, 2024, Barnwell received cash distributions of $1,071,000 from the Kukio Resort Land Development Partnerships resulting in a net amount of $953,000, after distributing $118,000 to non-controlling interests.

During the year ended September 30, 2023, Barnwell received cash distributions of $758,000 from the Kukio Resort Land Development Partnerships resulting in a net amount of $674,000, after distributing $84,000 to non-controlling interests.

Equity in income of affiliates was nil for the year ended September 30, 2025, as compared to equity in income of affiliates of $1,071,000 for the year ended September 30, 2024.

The decrease in partnership income is primarily due to the Kukio Resort Land Development Partnerships' sale of the last two lots in Increment I in the prior year period, whereas there were no lots sold in the current year period.

No cash distributions were received during the year ended September 30, 2025.

During the year ended September 30, 2024, Barnwell received cash distributions of $1,071,000 (resulting in a net amount of $953,000, after distributing $118,000 to non-controlling interests) from the Kukio Resort Land Development Partnerships.

In the quarter ended June 30, 2021, the Company received cumulative distributions from the Kukio Resort Land Development Partnerships in excess of our investment balance and in accordance with applicable accounting guidance, the Company suspended its equity method earnings recognition and the Kukio Resort Land Development Partnerships’ investment balance was reduced to zero with the distributions received in excess of our investment balance recorded as equity in income of affiliates because the distributions are not refundable by agreement or by law and the Company is not liable for the obligations of or otherwise committed to provide financial support to the Kukio Resort Land Development Partnerships.

The Company will record future equity method earnings only after our share of the Kukio Resort Land Development Partnerships’ cumulative earnings in excess of distributions during the suspended period exceeds our share of the Kukio Resort Land Development Partnerships’ income recognized for the excess distributions, and during this suspended period any distributions received will be recorded as equity in income of affiliates.

Accordingly, the amount of equity in income of affiliates recognized in the year ended September 30, 2024 was equivalent to the $1,071,000 of distributions received in that period.

Accordingly, no equity in income of affiliates was recognized in the year ended September 30, 2025.

Cumulative distributions received from the Kukio Resort Land Development Partnerships in excess of our investment balance was $106,000 at September 30, 2025 and $373,000 at September 30, 2024.

The components of loss before income taxes, after adjusting the loss for non-controlling interests, are as follows:

The components of loss from continuing operations before income taxes, after adjusting the loss for non-controlling interests, are as follows:

Year ended September 30,

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$ (7,044,000) $ (3,892,000)

Barnwell’s effective consolidated income tax rate for fiscal 2024, after adjusting loss before income taxes for non-controlling interests, was (4)%, as compared to an effective consolidated income tax benefit rate of 5% for fiscal 2023.

Barnwell’s effective consolidated income tax rate from continuing operations for fiscal 2025, after adjusting loss from continuing operations before income taxes for non-controlling interests, was (1)%, as compared to an effective consolidated income tax rate of (5)% for fiscal 2024.

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.

operates two subsidiaries in Canada, one of which is a U.S.

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.

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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.

On July 4, 2025, the President of the United States signed into law the One Big Beautiful Bill Act ("OBBBA").

The legislation, among other things, makes permanent, extends or modifies certain provisions under the 2017 Tax Cuts and Jobs Act, including a permanent extension of 100% bonus depreciation for certain capital expenditures.

The Company has determined that there are no tax law changes in the OBBBA that significantly impact the Company’s current and deferred income taxes.

Net earnings attributable to non-controlling interests

Earnings and losses attributable to non-controlling interests represent the non-controlling interests’ share of revenues and expenses related to the various partnerships and joint ventures in which Barnwell has controlling interests and consolidates.

Net earnings attributable to non-controlling interests totaled $234,000 in fiscal 2024, as compared to net earnings attributable to non-controlling interests of $150,000 in fiscal 2023.

The $84,000 (56%) increase is primarily due to increases in the amount of equity in income of affiliates and percentage of sales revenue received in the current year period as compared to the same period in the prior year.

Net loss attributable to non-controlling interests totaled $8,000 in fiscal 2025, as compared to net earnings attributable to non-controlling interests of $234,000 in fiscal 2024.

The $242,000 (103%) decrease is primarily due to decreases in the amount of equity in income of affiliates and percentage of sales revenue received in the current year period as compared to the same period in the prior year.

Net earnings (loss) from discontinued operations

Net earnings from discontinued operations was $12,000 during the year ended September 30, 2025, as compared to net loss from discontinued operation of $1,460,000 during the year ended September 30, 2024.

On March 14, 2025, the Company completed the sale of Water Resources, which represented the Company’s contract drilling segment.

The financial results of the Company’s contract drilling business has been presented as discontinued operations in the consolidated financial statements for all periods presented.

See Note 3 “Discontinued Operations” in the Notes to Consolidated Financial Statements in Item 8 of this report for further discussion and additional disclosures related to discontinued operations.

The effect of inflation on Barnwell has generally been to increase its cost of operations, general and administrative costs and direct costs associated with oil and natural gas production and contract drilling operations.

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Impact of Recently Issued Accounting Standards on Future Filings

In November 2023, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No.

2023-07 “Segment Reporting (Topic 280):

Improvements to Reportable Segment Disclosures”, which expands reportable segment disclosure requirements on an annual and interim basis, primarily through enhanced disclosures about significant segment expenses.

This ASU is effective for annual reporting periods beginning after December 15, 2023 and interim periods within fiscal years beginning after December 15, 2024, with early adoption permitted.

The Company is currently evaluating the impact of this standard on Barnwell’s consolidated financial statements but does not expect that the adoption of this update will have a material impact on Barnwell's consolidated financial statements.

In December 2023, the FASB issued ASU No.

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2024-03 “Income Statement - Reporting Comprehensive Income - Expense Disaggregation Disclosures (Subtopic 220-40):

Disaggregation of

Income Statement Expenses”, which requires public companies to disclose specified information about certain costs and expenses in the notes to the financial statements at interim and annual reporting periods.

Disaggregation of Income Statement Expenses”, which requires public companies to disclose specified information about certain costs and expenses in the notes to the financial statements at interim and annual reporting periods.

This ASU is effective for annual reporting periods beginning after December 15, 2026 and interim reporting periods beginning after December 15, 2027, with early adoption permitted.

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Liquidity and Capital Resources

The Company has presented cash flows from discontinued operations in the accompanying Consolidated Statements of Cash Flows separately after the presentation of cash flows from operating, investing, and financing activities of continuing operations.

The focus of this section, “Liquidity and Capital Resources,” is on the cash flows from continuing operations, which affects future liquidity and capital resources as the Company no longer has any significant continuing involvement with the discontinued operations after the sale.

At September 30, 2025, Barnwell had $504,000 in working capital.

Barnwell’s primary sources of liquidity are cash on hand and cash flow generated by our oil and natural gas operations, as cash flow from our land investment segment, if any, is expected to be minimal.

In recent years, the Company generated a significant amount of cash inflows from its land investment segment, however, the last lots at Increment I were sold in the quarter ended March 31, 2024 and there are no more lots available for sale in Increment I.

In addition, no definitive development plans have been made by the developer of Increment II as of the date of this report and thus future cash inflows from the land investment segment are uncertain.

Management estimates that cash flows from the sale of the contract drilling segment business or its operating assets may also provide some level of liquidity in the near-term.

The Company will primarily be reliant upon sufficient operating cash inflows from its oil and natural gas segment, which in turn will be largely determined by prices and production levels.

A certain level of oil and natural gas capital expenditures will be necessary to grow reserves and production or at a minimum replace declining production from aging wells.

Such a level of oil and natural gas capital expenditures may require funding from external debt or equity sources that are not currently in place.

Management estimates that, barring any significant unforeseen events, it is more likely than not that there is sufficient cash on hand, cash flows from contract drilling segment asset sales and cash flows from oil and natural gas segment operations to continue as a going concern for the twelve months from the filing of this report.

However, the aforementioned factors will influence the Company’s liquidity beyond that twelve month period.

Cash flows provided by operating activities totaled $4,710,000 for fiscal 2024, as compared to cash flows provided by operating activities of $1,943,000 for fiscal 2023.

This $2,767,000 change in operating cash flows was due to fluctuations in working capital in the current year period as compared to the prior year period.

The adjustment in operating cash flows due to the effect of changes in current assets and liabilities was an increase of $2,780,000 in the current year period as compared to a decrease of $393,000 in the prior year period.

The change was also due to an increase in distributions of income from the Kukio Resort Land Development Partnerships and a decrease in general and administrative costs in the current year period as compared to the prior year period, partially offset by lower operating results for the oil and natural gas and contract drilling segments in the current year period as compared to the same period in the prior year.

Barnwell’s primary sources of liquidity are cash on hand and cash flow generated by our oil and natural gas operations, as cash flow from our land investment segment, if any, are expected to be intermittent and not significant to our liquidity.

Cash Flows From Continuing Operations

Cash flows used in operating activities totaled $1,773,000 for fiscal 2025, as compared to cash flows provided by operating activities of $5,334,000 for fiscal 2024.

This $7,107,000 decrease in operating cash flows was primarily due to lower operating results for the oil and natural gas segment in the current year period as compared to the same period in the prior year, higher general and administrative expenses in the current year period due to the shareholder contests, and a distribution of income from the Kukio Resort Land Development Partnerships in the prior year period as compared to none in the current year period.

The change was also due to the effect of changes in current assets and liabilities which was an increase of $2,100,000 in the prior year period as compared to $224,000 in the current year period.

Cash flows used in investing activities totaled $352,000 for fiscal 2025, as compared to cash flows used in investing activities of $2,819,000 for fiscal 2024.

This $8,348,000 change in investing cash flows was primarily due to a decrease of $7,790,000 in cash paid for investments in oil and natural gas properties in the current year period as compared to the same period in the prior year and a $441,000 increase in proceeds from the sale of oil and natural gas properties in the current year period as compared to the prior year period.

This $2,467,000 change in investing cash flows was due to an increase of $2,281,000 in proceeds from the sale of oil and natural gas assets and a decrease of $440,000 in cash paid for oil and natural gas capital expenditures in the current year period as compared to the same period in the prior year, partially offset by $439,000 of proceeds received by the land investment segment in the prior year period, as compared to none in the current year period.

Cash flows used in financing activities totaled $168,000 for fiscal 2025, as compared to cash flows used in financing activities of $226,000 for fiscal 2024.

The $560,000 change in financing cash flows was due to a decrease of $599,000 in payment of dividends, partially offset by an increase of $69,000 in distributions to non-controlling interests in the current year period as compared to the same period in the prior year.

Cash Dividends

No dividends were declared or paid during the year ended September 30, 2024.

The following table sets forth the cash dividends paid per share of common stock during the year ended September 30, 2023.

Record Date Date of Payment Dividend Paid

August 24, 2023 September 11, 2023 $0.015

May 25, 2023 June 12, 2023 $0.015

February 23, 2023 March 13, 2023 $0.015

December 27, 2022 January 11, 2023 $0.015

The $58,000 change in financing cash flows was due to a decrease of $226,000 in distributions to non-controlling interests, partially offset by $168,000 in repayments for insurance premium financing in the current year period as compared to none the same period in the prior year.

Going Concern

Our ability to sustain our business in the future will depend on sufficient oil and natural gas operating cash flows which are dependent on oil and natural gas prices, which can and in the past have fluctuated significantly, and on oil and natural gas operating expenses which are both variable and fixed.

A sufficient level of oil and natural gas operating cash flows are necessary to fund discretionary oil and natural gas capital expenditures which must be economically successful to provide sufficient returns to grow reserves and production or at a minimum replace declining production from aging wells.

Such a level of oil and natural gas capital expenditures will require funding from external debt and/or equity sources that are not currently in place, but those sources may not be feasible or sufficient.

In addition, we will need sufficient cash flows to fund our non-discretionary outflows such as oil and natural gas asset retirement obligations, ongoing oil and natural gas operating expenses and general and administrative expenses, both those related to our oil and natural gas operations and those related to our being a public company.

In the quarters ended March 31, 2025 and June 30, 2025, continuing uncertainties regarding the sufficiency of our cash balances and future cash inflows due largely to a reduction in oil and natural gas prices and recent shareholder consent solicitation and proxy contest costs incurred, raised substantial doubt about our ability to meet our estimated cash outflows or continue as a going concern.

However, due to the gross proceeds of $2,443,000 raised in the private placement offering in November 2025, management has determined that there is no longer substantial doubt regarding the Company's ability to continue as a going concern for one year from the filing of this Annual Report on Form 10-K.

Oil and Natural Gas Capital Expenditures

Barnwell’s oil and natural gas capital expenditures, including accrued capital expenditures and acquisitions of oil and natural gas properties and excluding additions and revisions to estimated asset retirement obligations, decreased $3,866,000 from $4,805,000 in fiscal 2024 to $939,000 in fiscal 2025.

During the year ended September 30, 2024, the Company participated in the drilling of one gross (1.0 net) operated development oil well in the Twining area.

The Company did not drill or participate in the drilling of wells during the year ended September 30, 2025.

In fiscal 2024, the Company participated in the drilling of one gross (1.0 net) operated development oil well in the Twining area.

Capital expenditures incurred for the drilling of this well during the year ended September 30, 2024 totaled approximately $3,183,000.

In fiscal 2023, the Company participated in the drilling of three gross (0.9 net) non-operated wells in the Twining area of Alberta, Canada.

Capital expenditures incurred for the drilling of these wells and Twining facilities during the year ended September 30, 2023 totaled approximately $4,770,000.

Additionally, the Company participated in the drilling of two gross (0.3 net) non-operated development oil wells in Texas.

Capital expenditures incurred for the drilling of these two wells totaled approximately $4,293,00 during the year ended September 30, 2023.

Oil and Natural Gas Property Dispositions

In the quarter ended June 30, 2024, Barnwell entered into and completed a purchase and sale agreement with an independent third party and sold its interests in certain natural gas and oil properties located in the Kaybob area of Alberta, Canada.

On August 8, 2025, Barnwell entered into an agreement with an independent third party to sell all of its working interests in its U.S.

oil and natural gas assets for a sales price of $2,300,000.

The sales price per the agreement was adjusted for customary purchase price adjustments to reflect the economic activity from the effective date of July 1, 2025 to the closing date August 8, 2025.

The Company recognized a loss on the sale of $636,000 before related income taxes in the year ended September 30, 2025.

oil and natural gas assets were located in the states of Texas and Oklahoma and were owned by wholly-owned subsidiaries of Barnwell.

As a result of the sale, the Company no longer owns any oil and natural gas assets in the U.S., however, the Company will continue to explore for oil and natural gas opportunities in the U.S.

On August 28, 2025, Barnwell entered into and completed a purchase and sale agreement with an independent third party and sold its interests in certain oil and natural gas properties located in the Medicine River area of Alberta, Canada.

The sales price per the agreement was adjusted for customary purchase price adjustments to $288,000 in order to, among other things, reflect an economic closing date of September 30, 2025.

The final determination of the customary adjustments to the purchase price has not yet been made;

however, it is not expected to result in a material adjustment.

The proceeds were credited to the full cost pool, with no gain or loss recognized, as the sale did not result in a significant alteration of the relationship between capitalized costs and proved reserves.

In April 2024, Barnwell entered into and completed a purchase and sale agreement with an independent third party and sold its interests in certain oil and natural gas properties located in the Kaybob area of Alberta, Canada.

The sales price per the agreement was adjusted for customary purchase price adjustments to $441,000 in order to, among other things, reflect an economic effective date of May 1, 2024.

The final determination of the customary adjustments to the purchase price has not yet been made, however, it is not expected to result in a material adjustment.

In July 2024, Barnwell entered into and completed an agreement with an independent third party to convey interests in certain natural gas and oil properties located in the Bonanza and Balsam areas of Alberta, Canada.

In consideration for the sale of the working interests in these properties, Barnwell retained a 4% overriding royalty on these properties and the buyer assumed the asset retirement

obligations associated with these properties.

There were no cash proceeds from the sale and no gain or loss was recognized on this conveyance as this did not result in a significant alteration of the relationship between capitalized costs and proved reserves.

In July 2024, Barnwell entered into and completed an agreement with an independent third party to convey interests in certain oil and natural gas properties located in the Bonanza and Balsam areas of Alberta, Canada.

In consideration for the sale of the working interests in these properties, Barnwell retained a 4% overriding royalty on these properties and the buyer assumed the asset retirement obligations associated with these properties.

There were no cash proceeds from the sale and no gain or loss was recognized on this conveyance as this did not result in a significant alteration of the relationship

between capitalized costs and proved reserves.

With the disposition of the working interest, Barnwell reduced the full cost pool and abandonment liabilities associated with the working interests conveyed by approximately $153,000.

In September 2024, Barnwell entered into and completed a purchase and sale agreement with an independent third party and sold its interests in certain natural gas and oil properties located in the Wood River area of Alberta, Canada.

In September 2024, Barnwell entered into and completed a purchase and sale agreement with an independent third party and sold its interests in certain oil and natural gas properties located in the Wood River area of Alberta, Canada.

The sales price per the agreement was adjusted for customary purchase price adjustments to $292,000 in order to, among other things, reflect an economic effective closing date of September 30, 2024.

The final determination of the customary adjustments to the purchase price has not yet been made, however, it is not expected to result in a material adjustment.

From the sales proceeds, $38,000 was remitted directly to the Canada Revenue Agency by the buyers for potential amounts due for Barnwell’s Canadian income taxes related to the sale.

The proceeds from the sale was credited to our cash in October 2024 and will be reflected in the Statement of Cash Flows for the first quarter of fiscal 2025 ending December 31, 2024.

The proceeds from the sale was credited to our cash in October 2024 and is reflected in the Statement of Cash Flows for the year ended September 30, 2025.

No gain or loss was recognized on this disposition as the sale proceeds were credited to the full cost pool and did not result in a significant alteration of the relationship between capitalized costs and proved reserves.

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In March 2021, the Company was notified by the OWA that Barnwell’s Manyberries wells were confirmed to be in the WIP program.

Under the agreement with the OWA, the Company is required to pay the abandonment and reclamation costs in advance through a cash deposit.

The total cash deposit amount was calculated to be approximately $1,525,000 and the Company paid $888,000 of the total deposit in July and August 2021 and may need to pay the remaining balance of $637,000 by August 2025.

The Company revised its Manyberries ARO liability based on the OWA’s revised abandonment and reclamation estimates.

Based on a review of the details of the cash deposit calculation provided by the OWA, which includes amounts added for possible contingencies, the Company believes the required cash deposit amount by the OWA is higher than the actual costs of the asset retirement obligation for the Manyberries wells and that any excess of the deposit over actual asset retirement costs for the first phase of the work would be credited toward the second phase of the work.

A remaining excess deposit, if any, would ultimately be refunded to the Company upon completion of all of the work.

As of September 30, 2024, the Company recognized a cumulative reduction in the deposit balance of $353,000 for work performed under this program.

Under the agreement with the OWA, the Company was required to pay the abandonment and reclamation costs in advance through a cash deposit.

Barnwell has provided $975,000 in cumulative cash deposits to the OWA since the program began in the fall of 2021, and any amount remaining after completion of the abandonments was to be refunded to the Company, and then upon commencement of the reclamation program a new deposit was to be made for those estimated costs.

To date, the excess deposits that relate to abandonment work have not yet been refunded but have been used to fund the reclamation part of the program and the Company now estimates that a portion of the unused deposit will instead be applied to future reclamation work over the next several years.

The estimated current portion of the unused deposit was $173,000 and $527,000 as of September 30, 2025 and 2024, respectively, and is included in “Other current assets” on the Company’s Consolidated Balance Sheets.

The non-current portion of the unused deposit of $222,000 along with $61,000 of non-current receivables at September 30, 2025, is included in “Other non-current assets” on the Company’s Consolidated Balance Sheet at September 30, 2025.

Private Placement Offering

On November 24, 2025, the Company entered into a securities purchase agreement (the “Purchase Agreement”) with certain investors (the “Purchasers”), including certain directors of the board of directors of the Company pursuant to which the Company agreed to issue and sell an aggregate of:

(i) 2,221,141 shares of its common stock, par value $0.50 per share (the “Common Stock”), and (ii) warrants (the “Common Warrants”) to purchase up to 1,029,104 shares of Common Stock (the “Warrant Shares”) in a private placement offering of the Company’s securities (the “Offering”).

The directors of the Company participating as Purchasers in the Offering and certain other Purchasers did not receive any Common Warrants.

The price of the shares of Common Stock sold in the private placement was $1.10 per share of Common Stock.

The Common Warrants have an exercise price of $1.65 per share.

The Offering closed on November 28, 2025 and the gross proceeds received from the Offering was approximately $2,443,000.

The proceeds will be used for general corporate purposes.

See Note 21 in the Notes to Consolidated Financial Statements in Item 8 of this report for additional disclosures related to the private placement offering.

Contractual Obligations

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What changed 10-K

Item 7. Management’s Discussion and Analysis