What changed in this filing

/stocks — the workspaceLOADING

Item 1. Business

2024-12-17 compared with 2023-12-18 · 139 added, 126 removed, 196 unchanged (57% of the section changed)

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states of Oklahoma and Texas.

• Land Investment Segment - Barnwell invests in land interests in Hawaii.

• Land Investment Segment - Barnwell owns land interests in Hawaii.

• Contract Drilling Segment - Barnwell provides well drilling services and water pumping system installation and repairs in Hawaii.

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Additionally, through its wholly-owned subsidiaries BOK Drilling, LLC (“BOK”), established in February 2021, and Barnwell Texas, LLC (“Barnwell Texas”), established in November 2022, Barnwell is involved in oil and natural gas investments in Oklahoma and Texas, respectively.

Barnwell’s Canadian oil and natural gas assets are currently managed as two categories based on their differing attributes and strategies:

Twining and Legacy.

Twining represents 73% of Barnwell’s fiscal 2023 Boe production and consists of assets in the Twining field, in Alberta, Canada.

Twining represents 70% of Barnwell’s fiscal 2024 production (Boe) and consists of assets in the Twining field, in Alberta, Canada.

These assets were purchased in August 2018 and were augmented with subsequent smaller acquisitions of partners.

These assets are partially operated by the Company and partially operated by Pine Cliff Energy Ltd.

The oil wells operated by the Company have largely less than 15% per year decline rates, and due to these lower decline rates, require less capital investment to replace decline.

The oil wells operated by the Company largely have less than 15% per year decline rates, and due to these lower decline rates, require less capital investment to replace decline.

This lower capital requirement along with the fact that the land is largely held indefinitely, enables development drilling to be done when commodity prices support it.

Since Barnwell’s entry into the Twining property, we have participated in drilling 11 gross horizontal development wells that were completed with multi-stage sand fracs, all of which have been or are forecast to be profitable.

Of these 11 wells, two are 100%-owned operated wells in locations selected by Barnwell and nine gross (2.6 net) are non-operated wells.

Since Barnwell’s entry into the Twining property, we have participated in drilling 12 gross horizontal development wells that were completed with multi-stage sand fracs, which have cumulatively been or are forecast to be profitable.

Of these 12 wells, three are 100%-owned operated wells in locations selected by Barnwell and nine gross (2.6 net) are non-operated wells.

Barnwell plans to continue to develop the pool with more horizontal wells if commodity prices continue to support their profitability.

The Legacy assets represent 8% of Barnwell’s fiscal 2023 Boe production and consist of the largely non-operated Canadian oil and natural gas assets not in the Twining area.

The Legacy assets are located throughout Alberta, Canada, and produce shallow gas and conventional oil from a variety of pools.

Barnwell also has some minor legacy assets that represent 14% of Barnwell’s fiscal 2024 production (Boe) and consist of the largely non-operated oil and natural gas assets located throughout Alberta, Canada, and produce shallow gas or conventional oil from a variety of pools.

These assets have been accumulated over decades of Barnwell activity.

Barnwell continues to evaluate opportunities to either divest the legacy Canadian assets or add to them through acquiring working interests depending on technical and economic evaluations.

Minimal capital is expected to be invested in these properties.

In Oklahoma, which produced 9% of Barnwell’s fiscal 2023 Boe production, the Company has non-operated working interests in seven wells varying from 1.2% to 4.2% and a minor overriding royalty interest, 0.07%, in one well.

In December 2022, the Company entered into a purchase and sale agreement with an independent third party to acquire a 22.3% non-operated working interest in oil and natural gas leasehold acreage in the Permian Basin in Texas.

In connection with the purchase of such leasehold interests, Barnwell acquired a 15.4% non-operated working interest in two oil wells in the Wolfcamp Formation in Loving and Ward Counties, Texas.

Two gross (0.3 net) wells were drilled and began producing in late April 2023.

Additional drilling opportunities in the U.S.

are being investigated.

These wells produced 10% of Barnwell’s fiscal 2023 Boe production, but were only producing for five months.

All acquisitions, operational and developmental activities in the Twining area are the responsibility of the President and Chief Operating Officer of Barnwell of Canada and Octavian Oil with approvals for major expenditures secured from Barnwell’s executive management and, when applicable, the Board of Directors.

Barnwell has divested many of these properties in

fiscal 2024 in order to reduce risk and increase focus in the Twining area.

Barnwell will continue to opportunistically divest our remaining legacy Canadian assets and minimal capital is expected to be invested in these properties.

Barnwell is continually reviewing the market and evaluating opportunities to add to our production and development portfolio.

The Company has non-operated working interests in seven wells varying from 1.2% to 4.2% and a minor overriding royalty interest, 0.07%, in one well in Oklahoma.

Our interests in Oklahoma produced 7% of Barnwell’s fiscal 2024 production (Boe).

The Company has a 15.4% non-operated working interest in two wells in the Permian Basin in Texas.

Our interests in Texas produced 9% of Barnwell’s fiscal 2024 production (Boe).

Our oil and natural gas segment revenues, profitability, and future rate of growth are dependent upon oil and natural gas prices and the Company’s ability to use its current cash, obtain external financing or generate sufficient cash flows to fund the development of our reserves.

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Oil and natural gas unit sales are based on the quantity produced from the properties by the respective property operators.

Prices received in Canada also have been negatively impacted by the lack of export pipeline capacity.

Oil prices received in Canada are impacted by differentials in price to West Texas Intermediate (“WTI”).

In recent history this meant that Barnwell at times received prices at a significant discount to WTI.

In 2024, additional oil export pipeline capacity was made available in Canada which greatly reduced this differential.

Gas prices received in Canada are based on published AECO hub prices and are also impacted by local market conditions that result in a discount to U.S.

Henry Hub pricing.

Oil prices received from the Texas and Oklahoma properties are generally in line with WTI pricing.

Realized gas prices from our Texas natural gas sold at the Waha Hub are at a significant discount to Henry Hub due to limited gas egress from the Permian Basin and excess supply in the area.

Preparation of Reserve Estimates

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All information with respect to the Company’s U.S.

reserves in this Form 10-K is derived from the reports of Ryder Scott, which are filed with this Form 10-K as Exhibits 99.2 and 99.3.

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 two independent directors and Barnwell's CEO.

reserves in this Form 10-K is derived from the report of Ryder Scott, which is filed with this Form 10-K as Exhibit 99.2.

review controls, including an independent internal review of the final reserve report for completeness and accuracy.

Barnwell has a Reserves Committee consisting of two independent directors and Barnwell's Corporate Secretary.

The Reserves Committee was established to ensure the independence of the Company’s petroleum reserve engineers.

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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 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.

At September 30, 2023, Barnwell’s reserves were approximately 43% operated and consisted of 52% conventional oil and natural gas liquids and 48% natural gas.

At September 30, 2022, Barnwell’s reserves were approximately 54% operated and consisted of 56% conventional oil and natural gas liquids and 44% natural gas.

This change in reserves was largely due to our Texas investment in two non-operated wells.

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 (including natural gas liquids) and natural gas as of September 30, 2023 for all properties located in Canada and the U.S.

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.

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.

At September 30, 2023, Barnwell’s reserves were approximately 43% operated and consisted of 38% conventional oil, 14% conventional natural gas liquids, and 48% 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, 2024 for all properties located in Canada and the U.S.

in which Barnwell has an interest.

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

Oil, including natural gas liquids (Bbls) 1,116,000 110,000 1,226,000

873,000 109,000 982,000

Natural gas liquids (Bbls)

340,000 23,000 363,000

Natural gas (Mcf) 5,815,000 640,000 6,455,000

Total (Boe) 2,184,000 239,000 2,423,000

During fiscal 2023, Barnwell’s total net proved developed reserves of oil and natural gas liquids increased by 70,000 Bbls (7%) and total net proved developed reserves of natural gas increased by 1,236,000 Mcf (25%), for a combined increase of 249,000 Boe (13%).

The increase in natural gas reserves were primarily the result of the wells drilled in Texas and Canada in the current year.

The following table sets forth Barnwell’s oil and natural gas net reserves at September 30, 2023, by location and property name, based on information prepared by our independent reserve engineers, as well as net production and net revenues by location and property name for the year ended September 30, 2023.

The reserve data in this table is 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 2023.

As of September 30, 2023 For the year ended September 30, 2023

Net Proved Producing Reserves Net Proved Reserves Net Production Net Revenues

Property Name Oil & NGL (MBbls) Gas (MMcf) Oil & NGL (MBbls) Gas (MMcf) Oil & NGL (MBbls) Gas (MMcf) Oil & NGL Gas

During fiscal 2024, Barnwell’s total net proved reserves of oil and natural gas liquids increased by 83,000 Bbls (9%) and 36,000 Bbls (11%), respectively, and total net proved reserves of natural gas decreased by 246,000 Mcf (4%), for a combined increase of 80,000 Boe (3%).

The increase in proved reserves for oil and natural gas liquids were primarily the result of revisions due to the improved production performance of many wells in Twining as a result of focused attention and investment in optimization.

The Company has identified a number of additional optimization projects for fiscal 2025 that should further improve well performance and reduce operating costs.

Projects are generally workovers, field automation, and facility debottlenecking.

Barnwell has an ownership is all processing facilities that handle our net production volumes.

The following tables set forth Barnwell’s oil and natural gas net reserves at September 30, 2024, by location and property name, based on information prepared by our independent reserve engineers, as well as net production and net revenues by location and property name for the year ended September 30, 2024.

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 2024.

As of September 30, 2024

Net Proved Producing Reserves Net Proved Reserves

Property Name Oil

(MBbls) NGL (MBbls) Gas

Twining 710 126 3,637 867 156 4,549

Bonanza/Balsam 27 24 27 24 4 15 265,000 30,000

Kaybob 22 101 22 101 3 14 211,000 42,000

Medicine River 23 43 366 23 43 366

Thornbury — — 2 — — 26

Wood River 17 33 17 33 6 9 436,000 32,000

Other properties 2 — — 2 — —

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Total 825 333 5,519 982 363 6,455

Net proved reserves that are attributable to existing producing wells are primarily determined using decline curve analysis and rate transient analysis, which incorporates the principles of hydrocarbon flow.

For the year ended September 30, 2024

Net Production Net Revenues

Property Name Oil

(MBbls) NGL (MBbls) Gas

(MMcf) Oil NGL Gas

Twining 160 23 944 $ 11,241,000 $ 1,190,000 $ 1,619,000

Medicine River 2 4 18 171,000 107,000 26,000

Thornbury — — 52 — — 39,000

Other properties 22 9 71 633,000 9,000 58,000

United States:

Oklahoma 5 12 99 406,000 252,000 190,000

Texas 14 16 160 1,058,000 322,000 75,000

Total 203 64 1,344 $ 13,509,000 $ 1,880,000 $ 2,007,000

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.

Technologies relied on to establish reasonable certainty of economic producibility include electrical logs, radioactivity logs, core analyses, geologic maps and available production data, seismic data and well test data.

Standardized Measure of Discounted Future Net Cash Flows

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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 value of Barnwell’s undeveloped land position, 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 $2.54 per Mcf and an oil price of $69.66 per Bbl) and costs, and a discount factor more representative of the time value of money and the risks inherent in reserve estimates.

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 $1.16 per Mcf and an oil price of $70.78 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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Production amounts reported are net of royalties.

All of Barnwell’s net production in fiscal 2023 was derived in Alberta, Canada and in the U.S.

All of Barnwell’s net production in fiscal 2024 and 2023 was derived in Alberta, Canada and in the U.S.

states of Oklahoma and Texas.

Barnwell’s net production in fiscal 2022 and 2021 was derived in Alberta, Canada and in Oklahoma.

Barnwell’s net production in fiscal 2022 was derived in Alberta, Canada and in Oklahoma.

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.”

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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 new wells in Texas and the Twining area.

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.

Barnwell invested $10,729,000 in oil and natural gas properties during fiscal 2023, 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 wells in the Twining area, for facilities expansion and upgrade costs in the Twining area and the acquisition of additional working interests in several wells in the Twining area.

Barnwell’s capital expenditures were primarily for the drilling of new wells in Texas and the Twining area.

Well Drilling Activities

The Company participated in the drilling of three gross (0.9 net) non-operated development wells in the Twining area of Alberta, Canada during the year ended September 30, 2023.

During the year ended September 30, 2024, the Company drilled one gross (1.0 net) operated development oil well in the Twining area which started producing in mid-September 2024.

The well has produced on average approximately 107 Boe per day in its first two months of production.

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 which began producing in late April 2023.

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

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.

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Capital expenditures incurred by the Company for these non-operated development wells totaled $4,366,000 for the year ended September 30, 2022.

Five gross (1.4

net) wells were producing at September 30, 2022 and the remaining one gross (0.3 net) well was awaiting tie-in and started producing in fiscal 2023.

Five gross (1.4 net) wells were producing at September 30, 2022 and the remaining one gross (0.3 net) well was awaiting tie-in and started producing in fiscal 2023.

The Company drilled one gross (1.0 net) operated development well in the Twining area which was producing at September 30, 2022.

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The Company did not drill or participate in the drilling of wells in Oklahoma during the year ended September 30, 2022.

In fiscal 2021, the Company participated in the drilling of seven gross (0.2 net) non-operated development wells in Oklahoma.

Capital expenditures incurred by the Company for these Oklahoma wells totaled $1,178,000 for the year ended September 30, 2021.

The Company did not drill or participate in the drilling of wells in Canada during the year ended September 30, 2021.

Producing Wells

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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 Canada which Barnwell held as of September 30, 2023.

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, 2024.

The acreage of developed and undeveloped oil and natural gas leases in the U.S.

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Location Gross Net Gross Net Gross Net

Canada 136,220 33,980 27,110 8,710 163,330 42,690

Alberta, Canada 131,590 30,730 26,210 7,410 157,800 38,140

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“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-three percent of Barnwell’s undeveloped acreage is not subject to expiration at September 30, 2023.

Seventeen 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:

Seventy-seven percent of Barnwell’s undeveloped acreage is not subject to expiration at September 30, 2024.

Twenty-three 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:

4% expire during fiscal 2025;

no expirations during fiscal 2025;

9% expire during fiscal 2026;

6% expire during fiscal 2027;

and 4% expire during fiscal 2028.

4% expire during fiscal 2028;

and no expirations during fiscal 2029.

There can be no assurance that Barnwell will be successful in renewing its leasehold interests in the event of expiration.

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Marketing of Oil and Natural Gas

Barnwell sells its Canadian oil, natural gas, and natural gas liquids production, including 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.

In fiscal 2023, 95% of Barnwell’s Canadian oil and natural gas revenues were from products sold at spot prices.

In November 2023, to provide partial protection against the risk of declining natural gas prices during the second half of our fiscal 2024, the Company amended certain of its Canadian purchase and sales contracts to change the sales price on a portion of the natural gas it sells to a fixed price during the period from April 1, 2024 to October 31, 2024.

With these changes, the Company anticipates that during that period approximately 25% of its Canadian natural gas production will be sold at fixed prices while the remaining 75% of such production will continue to be sold at spot prices.

Additionally, in December 2023, the Company amended certain of its Canadian purchase and sales contract to change the sales price on a portion of the oil it sells to a fixed price during the period from January 1, 2024 to June 30, 2024.

With these changes, the Company anticipates that during that period approximately 40% of its Canadian oil production will be sold at fixed prices while the remaining 60% of such production will continue to be sold at spot prices.

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.

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

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

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

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

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

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

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

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

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

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

In fiscal 2024 and 2023, 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.

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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 prices and the date of discovery.

royalties are calculated as a percentage of revenue and vary depending on production volumes, selling 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.

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In fiscal 2024, the weighted-average royalty rate paid on all of Oklahoma’s and Texas’s production was 23% and 26%, respectively.

In June 2021, the AER announced that the previous Licensee Liability Program (“LLP”) would be replaced by a Licensee Life-Cycle Management Program via a Licensee Capability Assessment (“LCA”).

The LCA is intended to be a more comprehensive assessment of corporate health and considers a wider variety of factors than those considered under the LLP and establishes clear expectations for industry with regards to the management of liabilities throughout the entire lifecycle of oil and gas projects.

Factors considered are grouped into six factor 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 2 overall rankings in the six factor groups.

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’s (“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.

Importantly, an inventory reduction program also has been implemented 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 2024 is 6.6% of an individual company’s inactive liability.

These targets became effective January 1, 2022.

Barnwell believes the targets assessed by the AER are within estimated forecasts for Barnwell’s future ARO spending and therefore the Company will be in compliance with spend targets under the Inventory Reduction Program.

In September 2019, the AER issued an abandonment/closure order for all wells and facilities in the Manyberries area which had been largely operated by LGX, an operating company that went into receivership in 2016.

The estimated asset retirement obligation for the Company's interest in the wells and facilities in the Manyberries area is included in “Asset retirement obligation” in the Consolidated Balance Sheets.

After the abandonment/closure order was issued for Manyberries, the OWA created a Working Interest Partners (“WIP”) program for specific areas where there are a significant number of orphaned wells to abandon.

The OWA has the ability and expertise to abandon wells using its internal resources and network of service providers resulting in efficiencies that companies such as Barnwell would not be able to obtain on its own.

Under the WIP program, the Company would be required to provide payment for only Barnwell’s working interest share, however, all WIP’s would have to participate in the program for the OWA to begin its work.

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

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

The total cash deposit amount was calculated to be approximately $1,525,000 and the Company paid $888,000 of the total deposit in July and August 2021 and may need to pay the remaining balance of $637,000 by August 2024.

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

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

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

As at September 30, 2023, the Company recognized a cumulative reduction in the deposit balance of $300,000 for work performed under this program.

Over the past seven 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-three Barnwell-operated sites have been certified as fully reclaimed or exempt since 2016.

To aid in this regard, and as a stimulus response to the COVID-19 pandemic, the Canadian Federal Government created and funded the Alberta-administered Site Rehabilitation Program (“SRP”) in spring 2020.

The SRP has been designed to reduce oil and gas industry liabilities by funding vendors who perform closure work.

In partnership with its vendors, Barnwell-operated sites have received $388,000 in net funding to date, to be directed to ARO reduction activities.

Barnwell has further benefited from grants allocated to its non-operated property partners amounting to $120,000.

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 2025 is 6.2% of an individual company’s inactive liability.

This amount for Barnwell is approximately $244,000.

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 2024, Barnwell had provided $923,000 in cash deposits to the OWA, and $353,000 of the deposit has been spent on closure activities as at September 30, 2024.

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.

Over the past eight 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-four Barnwell-operated sites have been certified as fully reclaimed or exempt since 2016.

Barnwell competes in the sale of oil and natural gas on the basis of price and on the ability to deliver products.

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Barnwell's ownership interests in the Kukio Resort Land Development Partnerships are accounted for using the equity method of accounting.

In the 1980s, Kaupulehu Developments obtained the state and county zoning changes necessary to permit development of the Four Seasons Resort Hualalai at Historic Ka`upulehu and Hualalai Golf Club, which opened in 1996, a second golf course, and single-family and multi-family residential units.

These projects were developed by an unaffiliated entity on leasehold land acquired from Kaupulehu Developments.

In the 1990s and 2000s, Kaupulehu Developments obtained the state and county zoning changes necessary to permit development of single-family and multi-family residential units, a golf course and a limited commercial area on approximately 870 leasehold acres, known as Lot 4A, zoned for resort/residential development, located adjacent to and north of the Four Seasons Resort Hualalai at Historic Ka`upulehu.

In 2004 and 2006, Kaupulehu Developments sold its leasehold interest in Kaupulehu Lot 4A to KD I's and KD II's predecessors in interest, which was prior to Barnwell’s affiliation with KD I and KD II which commenced on November 27, 2013, the acquisition date of our ownership interest in the Kukio Resort Land Development Partnerships.

Increment I is an area of 80 single-family lots, 78 of which were sold from 2006 to 2023, and a beach club on the portion of the property bordering the Pacific Ocean.

The purchasers of the 80 single-family lots also have the right to apply for membership in the Kuki`o Golf and Beach Club, which is located adjacent to and south of the Four Seasons Resort Hualalai at Historic Ka`upulehu.

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 Increments I and II.

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 KDII, the developer of Increment II, as of the date of this report.

Kaupulehu Developments is entitled to receive payments from KD I based on 10% of the gross receipts from KD I's sales of single-family residential lots in Increment I.

In fiscal 2023, one single-family lot was sold and two single-family lots, of the 80 lots developed within Increment I, remained to be sold as of September 30, 2023.

The developer had consolidated these two remaining lots into one large lot but has since split them back into the original two lots.

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.

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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.

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.

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Such compensation will be reflected as the obligation becomes probable and the amount of the obligation can be reasonably estimated.

In fiscal 2023, the Kukio Resort Land Development Partnerships sold one lot in Increment I and as a result of the lot sale, made cash distributions to its partners of which Barnwell received $758,000 resulting in a net amount of $674,000, after distributing $84,000 to non-controlling interests.

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.

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.

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.

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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.

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.

Contract Drilling Segment

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Water Resources owns and operates three water well drilling rigs, two pump rigs and other ancillary drilling and pump equipment.

Additionally, Water Resources leases month-to-month a storage facility in Honolulu, Hawaii, and a one-acre maintenance and storage facility with 2,800 square feet of interior space in Kawaihae, Hawaii.

Additionally, Water Resources leases short-term a storage facility in Waipahu, Hawaii, and a one-acre maintenance and storage facility with 2,800 square feet of interior space in Kawaihae, Hawaii.

Water Resources also maintains an inventory of uninstalled materials for jobs in progress and an inventory of drilling materials and pump supplies.

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Contracts are usually fixed price per lineal foot drilled and are negotiated with private entities or obtained through competitive bidding with private entities or local, state and federal agencies.

Contract revenues are not dependent upon the discovery of water or other

similar targets, and contracts are not subject to renegotiation of profits or termination at the election of the governmental entities involved.

Contract revenues are not dependent upon the discovery of water or other similar targets, and contracts are not subject to renegotiation of profits or termination at the election of the governmental entities involved.

Contracts provide for arbitration in the event of disputes.

In fiscal 2023, Water Resources sold a drilling rig to an independent third party for proceeds of $551,000, net of related costs, and recognized a $551,000 gain on the sale of the drilling rig during the year ended September 30, 2023, as the rig was fully depreciated.

In fiscal 2022, Water Resources sold a drilling rig and related ancillary equipment to an independent third party for proceeds of $687,000, net of related costs, which was equivalent to its net carrying value.

In fiscal 2023, Water Resources started two well drilling and three pump installation and repair contracts and completed three well drilling and nine pump installation and repair contracts.

Of the three completed well drilling contracts, two were started in fiscal 2021 and one was started in fiscal 2022.

Of the nine completed pump installation and repair contracts, one was started in fiscal 2015, one was started in fiscal 2017, two were started in fiscal 2021, two were started in fiscal 2022, and three were started in the current year.

Fifty-two percent of well drilling and pump installation and repair jobs, representing 8% of total contract drilling revenues in fiscal 2023, have been pursuant to government contracts.

At September 30, 2023, there was a backlog of four well drilling and seven pump installation and repair contracts, of which three well drilling and four pump installation and repair contracts were in progress as of September 30, 2023.

In fiscal 2024, Water Resources started three pump installation and repair contracts and completed two well drilling and five pump installation and repair contracts.

The two completed well drilling contracts were both started in fiscal 2023.

Of the five completed pump installation and repair contracts, two were started in fiscal 2017, one was started in fiscal 2019, and two were started in the current year.

Fifty-four percent of well drilling and pump installation and repair jobs, representing 18% of total contract drilling revenues in fiscal 2024, have been pursuant to government contracts.

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 approximate dollar amount of Water Resources’ backlog of firm well drilling and pump installation and repair contracts at December 1, 2024 and 2023 was as follows:

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$ 1,100,000 $ 6,800,000

Of the contracts in backlog at December 1, 2023, $6,300,000 is expected to be recognized in fiscal 2024 with the remainder to be recognized in the following fiscal year.

Sale of Water Resources

In December 2023, the Company entered into an agreement with a construction company for the sale of Water Resources for gross proceeds of $2,000,000, subject to customary post-closing price adjustments and the purchaser’s completion of due diligence.

The sale is expected to close in the first half of our fiscal 2024.

All of the contract drilling revenues in backlog at December 1, 2024 is expected to be recognized in fiscal 2025.

Potential Sale or Wind Down of the Contract Drilling Segment

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.

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.

Water Resources competes with other drilling contractors in Hawaii, some of which use drill rigs similar to Water Resources’.

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reliability of service also is a significant factor.

Competitive pressures are expected to remain high, thus there is no assurance that the quantity or values of available or awarded jobs which occurred in fiscal 2023 will continue.

Financial Information About Industry Segments and Geographic Areas

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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.

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.”

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Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 1. Business