NYSE: BRN

Strategy

The Twining field, in Alberta, Canada represents 86% of Barnwell’s fiscal 2025 production. These assets were acquired in August 2018 and subsequently expanded through smaller acquisitions of various partner interests. These assets are partially operated by the Company and partially operated by Pine Cliff Energy Ltd. The majority of Barnwell's operated oil wells have annual decline rates below 15%, which supports lower capital investment requirements to maintain production levels. This lower capital

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requirement to maintain production, in addition to the land being largely continued with no expiries, allows Barnwell to drill opportunistically when commodity prices are favorable.

Since entering the Twining area, Barnwell has participated in drilling 12 gross (5.6 net) horizontal development wells using multi-stage sand fracturing. Of these, 3 wells are 100%-owned and operated and 9 (2.6 net) are non-operated. These wells have all either been profitable or are forecasted to be profitable, and Barnwell intends to continue development of the pool with more horizontal wells as commodity prices permit.

Barnwell also holds minor legacy assets throughout Alberta, Canada representing 3% of Barnwell’s fiscal 2025 production. These non-operated oil and natural gas assets produce shallow gas or conventional oil from a varying interest in a variety of pools and have been accumulated over decades. In fiscal 2024 and 2025, Barnwell has divested many of these properties to reduce operational risk and increase strategic focus in the Twining area. Barnwell remains active in evaluating market opportunities to further divest remaining legacy assets along with acquisition opportunities to expand our production and development portfolio.

The Company had non-operated working interests in seven wells in Oklahoma ranging from 1.2% to 4.2%, along with a 0.07% overriding royalty interest in one well. Our interests in Oklahoma produced 4% of Barnwell’s fiscal 2025 production. Our interests in Oklahoma were sold on August 8, 2025.

The Company had a 15.4% non-operated working interest in two wells in the Permian Basin in Texas. Our interests in Texas produced 7% of Barnwell’s fiscal 2025 production. Our interests in Texas were sold on August 8, 2025.

Operations

Our oil and natural gas segment revenues, profitability, and future growth potential are closely tied to commodity prices and the Company’s ability to fund reserves development through cashflow or external financing. In recent years, the industry has experienced volatile oil and natural gas prices, and when these prices are in low cycle they negatively impact our operating results, cash flows and liquidity. Credit and capital markets for oil and natural gas investments have been tight recently, but as capital becomes more available we may seek to raise additional capital when market conditions are favorable and aligned with our growth strategy.

Barnwell's oil and natural gas unit sales are based on production from operated and non-operated properties. In Canada, oil prices received are influenced by differentials to West Texas Intermediate (“WTI”). Historically, these differentials resulted in significant discounts due to limited export capacity and transportation bottlenecks. In 2025, improved pipeline egress contributed to more favorable realized pricing for Barnwell's Canadian oil production. Oil prices received from our Texas and Oklahoma properties were generally in line with WTI pricing.

Natural gas prices continues to show seasonal strength during the winter months, driven by increased heating demand. In Canada, gas prices are based on AECO hub benchmark prices, which typically trade at a discount to U.S. Henry Hub pricing due to regional supply dynamics and infrastructure constraints.

While our Oklahoma and Texas interests were sold in the fourth quarter of 2025, in Oklahoma, the pricing of our natural gas reflected prices close to Henry Hub pricing. In Texas, our natural gas was sold at

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the Waha Hub, where prices were significantly discounted to Henry Hub pricing due to limited gas egress from the Permian Basin and excess supply in the area.

Preparation of Reserve Estimates

Barnwell’s reserves are estimated by our independent petroleum reserve engineers, InSite Petroleum Consultants Ltd. (“InSite”), in accordance with generally accepted petroleum engineering and evaluation principles and techniques and rules and regulations of the SEC. All information with respect to the Company’s reserves in this Form 10-K is derived from the report of InSite, which is filed with this Form 10-K as Exhibit 99.1.

The preparation of data used by the independent petroleum reserve engineers to compile our oil and natural gas reserve estimates was completed in accordance with various internal control procedures which include verification of data input into reserves evaluation software, reconciliations and reviews of data provided to the independent petroleum reserve engineers to ensure completeness, and management review controls, including an independent internal review of the final reserve report for completeness and accuracy.

Barnwell has a Reserves Committee consisting of three directors, two of which are independent directors and the third is Barnwell's Chief Executive Officer. The Reserves Committee was established to ensure the independence of the Company’s petroleum reserve engineers. The Reserves Committee is responsible for reviewing the annual reserve evaluation reports prepared by the independent petroleum reserve engineering firms and ensuring that the reserves are reported fairly in a manner consistent with applicable standards. The Reserves Committee meets annually to discuss reserve issues and policies and to meet with Company personnel and the independent petroleum reserve engineers.

The President and Chief Operating Officer of Barnwell of Canada and Octavian Oil, who also serves as the President and Chief Executive Officer of Barnwell effective April 1, 2024, is a professional engineer with over 25 years of relevant experience in the oil and natural gas industry in Canada and is a member of the Association of Professional Engineers and Geoscientists of Alberta.

Reserves

At September 30, 2025, Barnwell’s reserves were approximately 66% operated and consisted of 47% conventional oil, 12% conventional natural gas liquids, and 41% natural gas. At September 30, 2024, Barnwell’s reserves were approximately 52% operated and consisted of 41% conventional oil, 15% conventional natural gas liquids, and 44% natural gas.

The amounts set forth in the following table, based on our independent reserve engineers’ evaluation of our reserves, summarize our estimated proved reserves of oil, natural gas liquids, and natural gas as of September 30, 2025 for all properties located in Canada in which Barnwell has an interest. All of our oil and natural gas reserves are based on constant dollar price and cost assumptions. 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

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expected to be recovered through existing wells and equipment in place and under operating methods being utilized at the time the estimates were made. No estimates of total proved net oil or natural gas reserves have been filed with, or included in reports to, any federal authority or agency, other than the SEC, since October 1, 2024.

As of September 30, 2025

Estimated Net Proved Developed ReservesEstimated Net Proved Undeveloped ReservesEstimated Net Proved Reserves

Oil (Bbls)
643,000 — 643,000

Natural gas liquids (Bbls)
165,000 — 165,000

Natural gas (Mcf)3,429,000 — 3,429,000

Total (Boe)1,380,000 — 1,380,000

During fiscal 2025, Barnwell’s total net proved reserves of oil and natural gas liquids decreased by 339,000 Bbls (35%) and 198,000 Bbls (55%), respectively, and total net proved reserves of natural gas decreased by 3,026,000 Mcf (47%), for a combined decrease of 1,043,000 Boe (43%). The decrease in proved reserves were due to the sale of U.S. oil and natural gas interests which was completed on August 8, 2025 and amounted to 425,000 Boe. The remaining decrease in reserves were a result of production and the removal of a proved undeveloped well which was represented as 239,000 Boe in the prior year’s balance due to a significant portion of the Company's capital resources being devoted to a proxy contest and consent election.

The following tables set forth Barnwell’s oil and natural gas net reserves at September 30, 2025, by location and property name, based on information prepared by InSite, as well as net production and net revenues by location and property name for the year ended September 30, 2025. The reserve data in these tables are based on constant dollars where reserve estimates are based on sales prices, costs and statutory tax rates using a historical average price of the first day pricing of the last 12-months ending with September 2025.

As of September 30, 2025

Net Proved Producing ReservesNet Proved Reserves

Property NameOil

(MBbls)NGL (MBbls)Gas

(MMcf)Oil

(MBbls)NGL (MBbls)Gas

(MMcf)

Canada:

Twining631 163 3,326 641 165 3,376

Thornbury— — 23 — — 51

Other properties1 — 1 2 — 2

Total632 163 3,350 643 165 3,429

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For the year ended September 30, 2025

Net ProductionNet Revenues

Property NameOil

(MBbls)NGL (MBbls)Gas

(MMcf)OilNGLGas

Canada:

Twining159 40 911 $9,610,000 $1,216,000 $1,218,000

Medicine River3 3 9 194,000 74,000 16,000

Thornbury— — 35 — — 37,000

Other properties2 — 11 19,000 — 8,000

United States:

Oklahoma3 5 55 149,000 152,000 157,000

Texas7 8 84 504,000 146,000 63,000

Total174 56 1,105 $10,476,000 $1,588,000 $1,499,000

Net proved reserves that are attributable to existing producing wells are primarily determined using decline curve analysis. Net proved reserves attributable to producing wells with limited production history and for undeveloped locations are estimated using performance from analogous wells in the surrounding area and geologic data to assess the reservoir continuity.

Standardized Measure of Discounted Future Net Cash Flows

The following table sets forth Barnwell’s “Estimated Future Net Revenues” from total proved oil, natural gas and natural gas liquids reserves located in Canada and the present value of Barnwell’s “Estimated Future Net Revenues” (discounted at 10%) as of September 30, 2025. Estimated future net revenues for total proved reserves are net of estimated future expenditures of developing and producing the proved reserves, and assume the continuation of existing economic conditions. Net revenues have been calculated using the average first-day-of-the-month price during the 12-month period ending as of the balance sheet date and current costs, after deducting all royalties, operating costs, future estimated capital expenditures (including abandonment costs), and income taxes. The amounts below include future cash flows from reserves that are currently proved undeveloped reserves and do not deduct general and administrative or interest expenses.

Year ending September 30,

2026$4,457,000

20272,675,000

20281,739,000

Thereafter(10,243,000)

Undiscounted future net cash flows, after income taxes$(1,372,000)

Standardized measure of discounted future net cash flows$6,670,000 *

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* This amount does not purport to represent, nor should it be interpreted as, the fair value of Barnwell’s oil and natural gas reserves. An estimate of fair value would also consider, among other items, the recovery of reserves not presently classified as proved, anticipated future changes in oil and natural gas prices (these amounts were based on a natural gas price of $1.09 per Mcf and an oil price of $60.92 per Bbl) and costs, and a discount factor more representative of the time value of money and the risks inherent in reserve estimates.

Barnwell has included all abandonment, decommissioning and reclamation costs and inactive well costs into the Company’s reserve reports in accordance with best practice recommendations.

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Oil and Natural Gas Production

The following table summarizes (a) Barnwell’s net production for the last three fiscal years, based on sales of natural gas, oil and natural gas liquids, from all wells in which Barnwell has or had an interest, and (b) the average sales prices and average production costs for such production during the same periods. Production amounts reported are net of royalties. All of Barnwell’s net production in fiscal 2025, 2024 and 2023 was derived in Alberta, Canada and in the U.S. states of Oklahoma and Texas. For a discussion regarding our total annual production volumes, average sales prices, and related production costs, see Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Year ended September 30,

202520242023

Annual net production:

Natural gas (Mcf)1,105,000 1,344,000 1,263,000

Oil (Bbls)174,000 203,000 204,000

Natural gas liquids (Bbls)56,000 64,000 52,000

Total (Boe)414,000 491,000 467,000

Total (Mcfe)2,484,000 2,946,000 2,799,000

Annual average sales price per unit of production:

Mcf of natural gas*$1.27$1.41$2.64

Bbl of oil**$60.49$66.49$69.77

Bbl of natural gas liquids**$28.38$29.38$32.24

Annual average production cost per Boe produced***$21.45$19.82$22.10

Annual average production cost per Mcfe produced***$3.58$3.30$3.68

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* Calculated on revenues net of pipeline charges before royalty expense divided by gross production.

** Calculated on revenues before royalty expense divided by gross production.

*** Calculated on production costs, excluding natural gas pipeline charges, divided by the combined total production of natural gas liquids, oil and natural gas.

Capital Expenditures and Acquisitions

Barnwell invested $939,000 in oil and natural gas properties during fiscal 2025, including accrued capital expenditures and acquisitions of oil and natural gas properties and excluding additions and revisions to estimated asset retirement obligations. Barnwell's capital expenditures were primarily related to equipment, facility upgrades and well workovers.

Barnwell invested $4,805,000 in oil and natural gas properties during fiscal 2024, including accrued capital expenditures and acquisitions of oil and natural gas properties and excluding additions and revisions to estimated asset retirement obligations. Barnwell’s capital expenditures were primarily for the drilling of a new well and for equipment and upgrades to facilities, all of which were in the Twining area.

Well Drilling Activities

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

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In fiscal 2024, the Company drilled one gross (1.0 net) operated development oil well in the Twining area which started producing in mid-September 2024. Capital expenditures incurred by the Company for this well totaled approximately $3,183,000. The Company did not drill or participate in the drilling of wells in Texas or in Oklahoma during the year ended September 30, 2024.

In fiscal 2023, the Company participated in the drilling of three gross (0.9 net) non-operated development wells in the Twining area of Alberta, Canada. Total capital expenditures for the year ended September 30, 2023 totaled approximately $4,770,000 and included the drilling, completion and equipping of the three gross (0.9 net) wells along with various upgrades to the Twining facilities. 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. The Company did not drill or participate in the drilling of wells in Oklahoma during the year ended September 30, 2023.

Producing Wells

As of September 30, 2025, Barnwell has interests in 109 gross (62.9 net) producing wells in Alberta, Canada, of which 76 gross (58.2 net) were oil wells and 33 gross (4.7 net) were natural gas wells.

Developed Acreage and Undeveloped Acreage

The following table sets forth the gross and net acres of both developed and undeveloped oil and natural gas leases in the province of Alberta, Canada which Barnwell held as of September 30, 2025.

Developed Acreage*Undeveloped Acreage*Total

LocationGrossNetGrossNetGrossNet

Alberta, Canada117,24429,14922,5067,741139,75036,890

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* “Developed Acreage” includes the acres covered by leases upon which there are one or more producing wells. “Undeveloped Acreage” includes acres covered by leases upon which there are no producing wells and which are maintained by the payment of delay rentals or the commencement of drilling thereon.

Eighty-one percent of Barnwell’s undeveloped acreage is not subject to expiration at September 30, 2025. Nineteen percent of Barnwell’s leasehold interests in undeveloped acreage is subject to expiration and may expire over the next five fiscal years, if not developed, as follows: 9% expire during fiscal 2026; 6% expire during fiscal 2027; 4% expire during fiscal 2028; and no expirations during fiscal 2029 and fiscal 2030. There can be no assurance that Barnwell will be successful in renewing its leasehold interests in the event of expiration.

Barnwell’s undeveloped acreage includes a significant concentration in the Twining area (3,707 net acres). The remaining undeveloped acreage is at non-operated properties over which we do not have control, and the value of such acreage is not estimated to be significant at current commodity prices.

Marketing of Oil and Natural Gas

Barnwell sells its Canadian oil, natural gas, and natural gas liquids production under short-term contracts between itself and two main oil purchasers, one natural gas purchaser, and one natural gas liquids purchaser. The prices received are freely negotiated between buyers and sellers and are determined from transparent posted prices adjusted for quality and transportation differentials.

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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 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.

Subsequent to fiscal 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.

In fiscal 2025 and 2024, Barnwell took most of its Canadian oil, natural gas liquids and natural gas “in kind” where Barnwell markets the products instead of having the operator of a producing property market the products on Barnwell’s behalf. We sell oil, natural gas and natural gas liquids to a variety of energy marketing companies. Because our products are commodities for which there are numerous marketers, we are not dependent upon one purchaser or a small group of purchasers.

Governmental Regulation

The jurisdictions in which the oil and natural gas properties of Barnwell are located have regulatory provisions relating to permits for the drilling of wells, the spacing of wells, the prevention of oil and natural gas waste, allowable rates of production, environmental protection, and other matters. The amount of oil and natural gas produced is subject to control by regulatory agencies in each province. The province of Alberta and the Government of Canada also monitor the volume of natural gas that may be removed from the province and the conditions of removal; currently all our Canadian natural gas is sold within Alberta.

All of Barnwell’s Canadian gross revenues were derived from properties located within Alberta, which charges oil and natural gas producers a royalty for production within the province. Provincial royalties are calculated as a percentage of revenue and vary depending on production volumes, selling

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prices and the date of discovery. Barnwell also pays gross overriding royalties and leasehold royalties on a portion of its oil and natural gas sales to parties other than the province of Alberta.

Under the current royalty framework for newly drilled wells, the same royalty calculation applies to both oil and natural gas wells and royalties are determined on a revenue minus cost basis where producers pay a flat royalty rate of 5% of gross revenues until a well reaches payout after which an increased post-payout royalty applies. Post payout royalties vary with commodity prices and well production rates.

In fiscal 2025, 72% of total Canadian royalties were related to Alberta government charges and 28% of royalties were related to freehold, overriding royalties and other charges.

In fiscal 2025, the weighted-average royalty rate paid on all of Barnwell’s Canadian natural gas was 4%, and the weighted-average royalty rate paid on oil was 16%.

Under Canadian oil and gas law and regulations, in order for the Company to retain the right to acquire, transfer, or drill well licenses, Barnwell must maintain a favorable Licensee Capability Assessment (“LCA”) with the Alberta Energy Regulator (“AER”). The LCA is intended to be a comprehensive assessment of corporate health and considers a wide variety of factors and establishes guidelines for the industry with regards to the management of liabilities throughout the entire lifecycle of oil and gas projects. Factors considered by the AER are combined into six groups, these being current financial distress, liability magnitude, resources lifespan, operations compliance, closure efficiency, and administrative compliance. These factors are compared to peer operators and ranked into three “Tiers.” Barnwell’s assessment under the LCA Program is currently favorable with Tier 1 or Tier 2 overall rankings in the six factor groups. Barnwell believes it can continue to manage its operations to maintain a favorable ranking.

A program has also been implemented by the AER which requires mandatory annual minimum expenditures towards outstanding decommissioning and reclamation obligations in accordance with AER targets which are adjusted by the AER on an annual basis. The target for calendar 2026 is 6.5% of an individual company’s inactive liability. This amount for Barnwell is approximately $237,000. Barnwell believes the targets assessed by the AER are within estimated forecasts for Barnwell’s future ARO spending and therefore the Company expects to be in compliance with AER spending targets under their mandatory spend requirements.

In instances where Barnwell is a non-operating partner of a company which has become insolvent, Barnwell and any remaining partners are responsible for administering site closure. This is achieved in one of two ways. First, either Barnwell or the other partners proceed with closure, and then make a claim for the costs attributed to the insolvent entity from the Orphan Well Association (“OWA”) after the abandonment work has been certified complete by the AER. Alternatively, Barnwell may pay a deposit to the OWA for its net share of the estimated closure costs, plus contingency as determined by the OWA. This allows the OWA to proceed with closure work on behalf of all partners. As of September 2025, Barnwell had provided $975,000 in cash deposits to the OWA, and $462,000 of the deposit has been spent on closure activities as at September 30, 2025. If the amount of deposit proves larger than that required by the OWA to complete the estimated work, Barnwell will receive a refund on the excess after sites are certified by the AER. These deposits do not earn interest. Asset retirement obligations of Barnwell’s net share of sites operated by all partners are included in “Asset retirement obligation”, current and long-term, in the Consolidated Balance Sheets.

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Over the past nine years, the Company has worked to reduce its abandonment and reclamation obligations associated with its oil and natural gas segment, both by divesting low-productivity assets and actively closing wells and sites. Twenty-five Barnwell-operated sites have been certified as fully reclaimed or exempt since 2016.

Competition

Barnwell competes in the sale of oil and natural gas mainly on the ability to deliver products. The oil and natural gas industry is intensely competitive in all phases, including the acquisition and development of new production and reserves and the acquisition of equipment and labor necessary to conduct drilling activities. The competition comes from numerous major oil companies as well as numerous other independent operators. There also is competition between the oil and natural gas industry and other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers. Barnwell is a minor participant in the industry and competes in its oil and natural gas activities with many other companies having far greater financial, technical and other resources.

Land Investment Segment

Overview

Barnwell owns a 77.6% interest in Kaupulehu Developments, a Hawaii general partnership (“Kaupulehu Developments”) that has the right to receive payments from KD I and KD II resulting from the sale of lots and/or residential units by KD I and KD II within the approximately 870 acres of the Kaupulehu Lot 4A area in two increments (“Increment I” and “Increment II”), located approximately six miles north of the Kona International Airport in the North Kona District of the island of Hawaii. Kaupulehu Developments also holds an interest in approximately 1,000 acres of vacant leasehold land zoned conservation located adjacent to Lot 4A under a lease that terminates in December 2025, which currently has no development potential without both a development agreement with the lessor and zoning reclassification.

Barnwell, through two limited liability limited partnerships, KD Kona and KKM Makai (“KKM”), holds a non-controlling ownership interest in the Kukio Resort Land Development Partnerships comprised of KD Kukio Resorts, KD Maniniowali, and KDK. 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 are accounted for using the equity method of accounting.

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.

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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.

Operations

Increment I is an area of 80 single-family lots, all of which were sold from 2006 to 2024, and a beach club on the portion of the property bordering the Pacific Ocean. Increment II is the remaining portion of the approximately 870-acre property and is zoned for single-family and multi-family residential units and a golf course and clubhouse. Two residential lots of approximately two to three acres in size fronting the ocean were developed within Increment II and sold by KD II, and the remaining acreage within Increment II is not yet under development. It is uncertain when or if KD II will develop the other areas of Increment II, and there is no assurance with regards to the amounts of future sales from Increment II. The remaining 420 developable acres at Increment II are entitled for up to 350 homesites. No definitive development plans have been made by KD II, the developer of Increment II, as of the date of this report.

Kaupulehu Developments was entitled to receive payments from KD I based on 10% of the gross receipts from KD I's sales of single-family residential lots in Increment I. In fiscal 2024, the last two remaining single-family lots of the 80 lots developed within Increment I were sold.

In March 2019, KD II admitted a new development partner, Replay Kaupulehu Development, LLC (“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.

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 obligated to pay an amount equal to 0.72% and 0.2% 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, Replay, for Increment II. Such compensation will be reflected as the obligation becomes probable and the amount of the obligation can be reasonably estimated. As stated above, Increment II is not yet under development and it is uncertain when or if KD II will develop the other areas of Increment II, and there is no assurance with regards to the amounts of future sales from Increment II.

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In fiscal 2024, the Kukio Resort Land Development Partnerships sold the last two remaining lots in Increment I and as a result of the lot sales, made cash distributions to its partners of which Barnwell received $1,071,000 resulting in a net amount of $953,000, after distributing $118,000 to non-controlling interests.

Competition

Barnwell’s land investment segment is subject to intense competition in all phases of its operations including the acquisition of new properties, the securing of approvals necessary for land rezoning, and the search for potential buyers of property interests presently owned. The competition comes from numerous independent land development companies and other industries involved in land investment activities. The principal factors affecting competition are the location of the project and pricing. Barnwell is a minor participant in the land development industry and competes in its land investment activities with many other entities having far greater financial and other resources.

Financial Information About Industry Segments and Geographic Areas

Note 11 in the “Notes to Consolidated Financial Statements” in Item 8 contains information on our segments and geographic areas.

Employees

At December 1, 2025, Barnwell employed 18 individuals; 16 on a full time basis and 2 on a part-time basis.

Environmental Costs

Barnwell is subject to extensive environmental laws and regulations. U.S. Federal and state and Canadian Federal and provincial governmental agencies issue rules and regulations and enforce laws to protect the environment which are often difficult and costly to comply with and which carry substantial penalties for failure to comply, particularly in regard to the discharge of materials into the environment. 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 where it has a working interest.

For further information on environmental remediation, see the Contingencies section included in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the notes to our consolidated financial statements included in Item 8, “Financial Statements and Supplementary Data.”

Available Information

We maintain a website at www.brninc.com. We make available on our website free of charge our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to those reports as soon as practicable after we electronically file such reports with, or furnish them to, the SEC. The contents of our website are not part of this Annual Report on Form 10-K and are not incorporated by reference into this document. Our filings with the SEC are available to the public

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through the SEC’s website at www.sec.gov. The Company’s references to URLs for these websites are intended to be textual references only.

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