What changed in this filing

/stocks — the workspaceLOADING

Item 1. Business

2022-12-29 compared with 2021-12-21 · 115 added, 141 removed, 192 unchanged (57% of the section changed)

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incorporated company that has been active in Canada for over 50 years, primarily as a non-operator participating in exploration projects operated by others.

Octavian Oil is a Canadian company incorporated in 2016 to achieve growth through the acquisition of crude oil reserves and development of those reserves.

Octavian Oil is a Canadian company incorporated in 2016 to achieve growth through the acquisition and development of crude oil reserves and development of those reserves.

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

Barnwell’s oil and natural gas assets are currently managed as two categories, Twining and non-operated, based on their differing attributes and strategies.

Twining consists of the Company-owned assets in the Twining field that were purchased in 2018.

These assets are characterized by being mostly low decline oil wells that the Company operates that we believe have development opportunities.

Due to the lower decline rates in the field, Twining requires a lower capital investment to maintain production levels.

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

Since Barnwell’s entry into the Twining property in August 2018, the development methods in the area have evolved to include longer horizontal wells with multi-stage sand fracs.

Barnwell invested approximately $2,400,000 and drilled its first well of this type in November 2019, and it is currently producing 90 Bbls of oil and 81 Boe of natural gas and NGL per day and has made cumulative production of 68,000 Boe since initial production.

Barnwell continues to work to improve the operational efficiency of the Twining property and, if possible, to expand our land position and level of influence in the Twining area.

The non-operated category consists of the Company's Canadian oil and natural gas assets not in the Twining area, as well as the new U.S.

wells in Oklahoma.

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

These non-operated Canadian 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 depending on technical and economic evaluations.

The majority of the Canadian assets have been up for sale on and off since January 2019, but COVID-19 and the resulting oil price collapse resulted in no reasonable offers being received.

However, in April 2021, the Company re-initiated marketing for the sale of these assets and sold some properties.

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 consists of assets in the Twining field, in Alberta, Canada, that were purchased in August 2018 and additions to the field subsequently.

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

The oil wells operated by the Company are largely low decline wells, less than 15% per year decline rates, and due to these lower decline rates, these Twining oil wells require a lower amount of capital investment than higher decline rate wells.

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 eight 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 eight wells, two are 100%-owned operated wells chosen by Barnwell and six gross (1.7 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 category consists of the Company's Canadian oil and natural gas assets not in the Twining area which are largely non-operated.

The Canadian Legacy assets are located throughout Alberta, Canada, and produce shallow gas and 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.

In Oklahoma, the Company commenced participation in an eight-well drilling program with non-operated working interests for seven wells varying from 1.2% to 4.2% and a minor overriding royalty interest, 0.07%, in one well.

Additional drilling opportunities in the U.S.

are being investigated, however no definitive plans have yet been developed.

At September 30, 2021, Barnwell’s Canadian reserves were approximately 64% operated and 56% conventional oil and natural gas liquids and 44% natural gas.

Proved oil and natural gas reserves located in the United States were not significant at September 30, 2021, as most of the wells drilled were still undergoing evaluation.

At September 30, 2020, Barnwell’s reserves were approximately 48% operated and 57% conventional oil and natural gas liquids and 43% natural gas.

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

are being investigated.

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.

At September 30, 2021, Barnwell’s reserves were approximately 64% operated and consisted of 56% conventional oil and natural gas liquids and 44% natural gas.

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.

The industry has experienced a period of low oil and natural gas prices that have negatively impacted our past operating results, cash flows and liquidity.

In the recent past, the industry experienced a period of low oil and natural gas prices that negatively impacted our past operating results, cash flows and liquidity.

Credit and capital markets for oil and natural gas companies have been negatively affected as well, resulting in a decline in sources of financing as compared to previous years.

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Natural gas prices are typically higher in the winter than at other times due to increased heating demand.

Oil prices are also subject to seasonal fluctuations, but to a lesser degree.

Oil and natural gas unit sales are based on the quantity produced from the properties by the properties’ operator.

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

In August 2018, Barnwell completed the acquisition of interests in oil and natural gas properties located in the Twining area of Alberta, Canada, from an independent third party.

The purchase price per the agreement was $10,362,000, which took into account estimated customary purchase price adjustments to reflect the economic activity from the effective date of July 1, 2018 to the closing date.

The final determination of the customary adjustments to the purchase price resulted in a $172,000 reduction in the purchase price in the year ended September 30, 2019, bringing the final purchase price to $10,190,000.

Barnwell also assumed $3,076,000 in asset retirement obligations associated with the Twining acquisition.

This acquisition represented a significant step in Barnwell’s long-term strategy to transform its Canadian

operations to having almost exclusively conventional light and medium oil assets.

This was a strategic purchase by the Company of what is now its largest oil and natural gas property.

At September 30, 2020, Barnwell reported no proved undeveloped reserves related to Twining as oil prices fell significantly in the second quarter of fiscal 2020 making the drilling of proved undeveloped reserves uneconomic and as a result, the Company suspended its development of proved undeveloped reserves in the Twining area.

The Company currently is planning to drill a new 100% working interest, operated horizontal well in the Twining area in the first half of fiscal 2022.

Additionally, the Company is participating in the drilling of 2.0 gross (0.6 net) non-operated horizontal wells in the area over the same period.

The results of these wells will help determine the quality and pace of future development.

As stated above, the Company commenced participation in an eight-well drilling program in Oklahoma with 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.

One well began production in late May 2021 and the Company’s share of net production, after royalties, from this well was 1,000 barrels of oil, 4,000 MCF of natural gas and 1,000 barrels of natural gas liquids through September 30, 2021.

The remaining wells started production in September 2021.

Oil prices also are subject to seasonal fluctuations, but to a lesser degree.

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.

Preparation of Reserve Estimates

Barnwell’s Canadian reserves are estimated by our independent petroleum reserve engineers, 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 Canadian reserves in this Form 10-K is derived from the report of InSite.

A copy of the report issued by InSite 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 independent directors.

Barnwell’s reserves are estimated by our independent petroleum reserve engineers, InSite Petroleum Consultants Ltd.

(“InSite”) in Canada and Ryder Scott Company, L.P.

(“Ryder Scott”) in the U.S., 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 Canadian reserves in this Form 10-K is derived from the report of InSite and a copy of the report issued by InSite is filed with this Form 10-K as Exhibit 99.1.

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

reserves in this Form 10-K is derived from the report of Ryder Scott and a copy of the report issued by Ryder Scott is filed with this Form 10-K as Exhibit 99.2.

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.

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 report prepared by the independent petroleum reserve engineering firm and ensuring that the reserves are reported fairly in a manner consistent with applicable standards.

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.

Barnwell of Canada’s President and Chief Operating Officer 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.

The amounts set forth in the following table, based on InSite’s evaluation of our reserves, summarize our estimated proved reserves of oil (including natural gas liquids) and natural gas as of September 30, 2021, for all properties located in Canada in which Barnwell has an interest.

Proved oil and natural gas reserves located in the United States are not yet significant and are therefore not included in the table below.

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, 2022 for all properties located in Canada and the U.S.

in which Barnwell has an interest.

All of our oil and natural gas reserves are based on constant dollar price and cost assumptions.

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During fiscal 2022, Barnwell’s total net proved developed reserves of oil and natural gas liquids increased by 410,000 Bbls (64%) and total net proved developed reserves of natural gas increased by 1,944,000 Mcf (67%), for a combined increase of 745,000 Boe (65%).

The increase in natural gas reserves were primarily the result of higher oil and gas prices resulting in positive revisions in the current year period.

The following table sets forth Barnwell’s Canadian oil and natural gas net reserves at September 30, 2021, by property name, based on information prepared by InSite, as well as net production and net revenues by property name for the year ended September 30, 2021.

The increase in natural gas reserves

were primarily the result of higher oil and gas prices resulting in positive revisions in the current year period.

The following table sets forth Barnwell’s oil and natural gas net reserves at September 30, 2022, 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, 2022.

The reserve data in this table is based on constant dollars where reserve estimates are based on sales prices, costs and statutory tax rates in existence at September 30, 2022, the date of the projection.

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

Twining 708 2,775 875 3,358 160 611 $ 13,537,000 $ 2,812,000

Bonanza/Balsam 25 20 25 20 4 3 334,000 18,000

Hillsdown — — — — 2 18 76,000 44,000

Kaybob 30 117 30 117 3 17 257,000 73,000

Medicine River 41 549 41 549 6 21 360,000 89,000

Spirit River — — — — 8 44 345,000 107,000

Thornbury — 429 — 429 — 63 — 264,000

Twining 408 1,516 461 1,719 118 456 5,931,000 1,289,000

Wood River 18 43 18 43 12 22 991,000 93,000

Other properties — 3 1 3 3 35 113,000 144,000

Canada Total 579 2,693 640 2,913 169 690 $ 8,277,000 $ 1,859,000

United States:

Oklahoma 90 466 90 466 42 192 2,462,000 1,034,000

Total 912 4,402 1,080 4,985 230 964 $ 18,054,000 $ 4,527,000

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.

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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 and the present value of Barnwell’s “Estimated Future Net Revenues” (discounted at 10%) as of September 30, 2021.

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 U.S.

and the present value of Barnwell’s “Estimated Future Net Revenues” (discounted at 10%) as of September 30, 2022.

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.

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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.

Proved oil, natural gas and natural gas liquids reserves located in the United States are not significant and are therefore not included in the table below.

Year ending September 30,

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2024 6,976,000

2025 5,007,000

Thereafter 8,206,000

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Production amounts reported are net of royalties.

Barnwell’s net production in fiscal 2021 was derived primarily in Alberta, Canada and to a lesser extent in Oklahoma.

All of Barnwell's net production in fiscal 2020 and 2019 was derived in Alberta, Canada.

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

Barnwell's net production in fiscal 2020 was derived in Alberta, Canada.

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 $11,052,000 in oil and natural gas properties during fiscal 2022, 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 mostly for the acquisition of additional working interests in several wells and equipment in the Twining area and the drilling of wells in Oklahoma that began in the third quarter of fiscal 2021.

Barnwell’s capital expenditures were mostly for the drilling of wells in the Twining area and also were 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 invested $2,217,000 in oil and natural gas properties during fiscal 2021, 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 mostly due to the Twining horizontal development well drilled in the first quarter of fiscal 2020 which amounted to approximately $2,400,000 and the participation in one gross (0.3 net) development well in the Spirit River area that was drilled in fiscal 2019 and completed in fiscal 2020 where approximately $670,000 in capital expenditures was incurred in fiscal 2020.

There were no significant amounts paid for oil and natural gas property acquisitions during fiscal 2020.

Well Drilling Activities

The Company participated in the drilling of seven gross (0.20 net) non-operated wells in Oklahoma during the year ended September 30, 2021.

The Company participated in the drilling of six gross (1.7 net) non-operated development wells in the Twining area during the year ended September 30, 2022.

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 is awaiting tie-in and is expected to produce 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.

Capital expenditures incurred by the Company for this operated well was $2,852,000.

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.

One gross (0.04 net) well was completed, the well began flowback production in late May 2021 and the Company’s share of net production, after royalties, from this well was 1,000 barrels of oil, 4,000 MCF of natural gas and 1,000 barrels of natural gas liquids through September 30, 2021.

The remaining six gross (0.16 net) wells were all producing in October 2021.

All wells were producing during the year

ended September 30, 2022, producing 42,000 barrels of oil and natural gas liquids and 192,000 Mcf of natural gas.

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

Drilling opportunities in the Company's core Twining area are being investigated for potential investment in the forthcoming months.

In fiscal 2020, Barnwell drilled one gross (1.0 net) horizontal development well in the Twining area.

This well was successful and started producing in January 2020 and was temporarily shut-in from mid-April 2020 to mid-May 2020 due to decreased oil prices.

This well contributed approximately 15,900 barrels of net oil production from January through September 2020, representing 10% total net oil production for fiscal 2020.

In fiscal 2021, this well contributed approximately 34,200 barrels of net oil production, representing 23% total net oil production.

In fiscal 2020, the Company drilled one gross (1.0 net) horizontal development well in the Twining area.

The Company did not drill or participate in the drilling of wells in Oklahoma during the year ended September 30, 2020.

Producing Wells

As of September 30, 2021, Barnwell had interests in 139 gross (49.7 net) producing wells in Alberta, Canada, of which 82 gross (42.0 net) were oil wells and 57 gross (7.7 net) were natural gas wells.

As of September 30, 2021, Barnwell had interests in seven gross (0.20 net) producing oil wells in Oklahoma.

As of September 30, 2022, Barnwell had interests in 148 gross (62.4 net) producing wells in Alberta, Canada, of which 93 gross (55.2 net) were oil wells and 55 gross (7.2 net) were natural gas wells and had interests in seven gross (0.2 net) producing oil wells in Oklahoma.

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, 2022.

Proved oil and natural gas reserves located in the United States are not significant and are therefore not included in the table below.

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

are not significant and are therefore not included in the table below.

Developed Acreage* Undeveloped Acreage* Total

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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-five percent of Barnwell’s undeveloped acreage is not subject to expiration at September 30, 2021.

Fifteen percent of Barnwell’s leasehold interests in undeveloped acreage is subject to expiration and expire over the next five fiscal years, if not developed, as follows:

Eighty-six percent of Barnwell’s undeveloped acreage is not subject to expiration at September 30, 2022.

Fourteen percent of Barnwell’s leasehold interests in undeveloped acreage is subject to expiration and expire over the next five fiscal years, if not developed, as follows:

12% expire during fiscal 2023;

no expirations during fiscal 2024 and 2025;

2% expire during fiscal 2026;

no expirations during fiscal 2024 and fiscal 2025;

and 2% expire during fiscal 2026.

and no expirations during fiscal 2027.

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 oil, natural gas, and natural gas liquids production, including under short-term contracts between itself and two main oil marketers, one natural gas purchaser, and one natural gas liquids marketer.

Barnwell sells its Canadian oil, natural gas, and natural gas liquids production, including under short-term contracts between itself and two main oil marketers, one natural gas purchaser, and one natural gas liquids marketer.

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 2021, over 80% of

Barnwell’s oil and natural gas revenues were from products sold at spot prices.

In fiscal 2022, over 80% of Barnwell’s Canadian oil and natural gas revenues were from products sold at spot prices.

Barnwell does not use derivative instruments to manage price risk.

In fiscal 2021 and 2020, Barnwell took most of its 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.

In fiscal 2022 and 2021, 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.

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Post payout royalties vary with commodity prices and are adjusted down for cost increases as wells age.

In fiscal 2021 and 2020, 45% and 44%, respectively, of royalties related to Alberta government charges, and 55% and 56%, respectively, of royalties related to freehold, override and other charges which are not directly affected by the Alberta royalty framework.

In fiscal 2021, the weighted-average royalty rate paid on all of Barnwell’s natural gas was 8%, and the weighted-average royalty rate paid on oil was 12%.

Barnwell's oil and natural gas segment is currently subject to the provisions of the AER’s LLR program.

Under the LLR program the AER calculates a LMR for a company based on the ratio of the company’s deemed assets over its deemed liabilities relating to wells and facilities for which the company is the licensed operator.

The LMR assessment is designed to assess a company’s ability to address its suspension, abandonment, remediation, and reclamation liabilities.

The value of the deemed assets is based on each well's most recent twelve months of production and a rolling three-year average industry

netback as determined by the AER annually.

The AER has not recalculated the three-year average industry netback since March 2015 making the current value a premium to what most producers have been realizing.

A recalculation of the value using current industry netback values would likely have a negative impact on our LMR.

Companies with an LMR less than 1.0 are required to deposit funds with the AER to cover future deemed liabilities.

At September 30, 2021, the Company had sufficient deemed asset value that no security deposit was due.

The current liability framework is under revision by the AER.

A percentage-based retirement framework is expected to be introduced, but further details are unknown at this time.

In fiscal 2022 and 2021, 67% and 45%, respectively, of Canadian royalties related to Alberta government charges, and 33% and 55%, respectively, of royalties related to freehold, override and other charges which are not directly affected by the Alberta royalty framework.

In fiscal 2022, the weighted-average royalty rate paid on all of Barnwell’s Canadian natural gas was 12%, and the weighted-average royalty rate paid on oil was 17%.

In fiscal 2022, the weighted-average royalty rate paid on all of Oklahoma’s production was 23%.

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

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 five-year rolling spending targets.

Currently, these targets are forecast by the AER to increase by 9% per year.

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.

Many 100% LGX-owned wells are to be reclaimed by the OWA.

However, as next largest interest holder in 82 wells and 7 facilities formerly operated by LGX, averaging 11%, the Company is required to take care and custody of those properties and to coordinate their closure.

In November 2019, in response to the AER order, the Company submitted its proposed plan to abandon the Manyberries wells and facilities in an orderly fashion over a ten-year period.

This area has unique access issues as a result of an Emergency Protection Order to protect the Sage Grouse under the Canadian Government’s Species at Risk Act.

Access is limited to a window of mid-September to the end of November each year.

The plan that the Company submitted began in October 2019 with field inspections, securing wells, and equipment inventory and the plan included further field activity beginning in the fall of 2020, our fiscal 2021 first quarter, which has been initiated and initially involves removal and salvage of the surface equipment;

these costs are estimated to be minimal due in part to the salvage value of the equipment.

Beyond fiscal 2021, the Company proposed and intends to perform seven to ten well abandonments per year over an estimated ten-year period as well as abandon the facilities in that time period.

Recently, the OWA created a WIP program for specific areas where there are a significant number of orphaned wells to abandon.

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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 will need to pay the remaining balance of $637,000 by August 2023.

The Company revised its Manyberries ARO liability based on the OWA’s revised abandonment and reclamation estimates, which resulted in an increase of approximately $213,000 in the current year.

The Company revised its Manyberries ARO liability based on the OWA’s revised abandonment and reclamation estimates, which resulted in an increase of approximately $213,000 in the year ended September 30, 2021.

The increase in the ARO liability was a result of higher reclamation and remediation costs than anticipated, partially offset by lower abandonment 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, 2022, the Company recognized a cumulative reduction in the deposit balance of $113,000 for work performed under this program.

Over the past five 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.

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

The Company began participating in non-operated oil and natural gas investments in Oklahoma in fiscal 2021, however such operations were not significant as they were only in the initial stages of development and production.

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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The competition comes from numerous major oil companies as well as numerous other independent operators.

There is also competition between the oil and natural gas industry and other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers.

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.

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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.

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.

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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, 71 of which were sold from 2006 to 2021 and of which nine lots remain to be sold, and a beach club on the portion of the property bordering the Pacific Ocean.

The purchasers of the 80 single-family lots will 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.

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 2022, and a beach club on the portion of the property bordering the Pacific Ocean.

The purchasers of the 80 single-family lots 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 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.

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

Kaupulehu Developments is entitled to receive payments from KD I based on the following percentages of the gross receipts from KD I’s sales of single-family residential lots in Increment I:

10% of such aggregate gross proceeds greater than $100,000,000 up to $300,000,000;

and 14% of such aggregate gross proceeds in excess of $300,000,000.

In fiscal 2021, eight single-family lots in Increment I were sold bringing the total amount of gross proceeds from single-family lot sales through September 30, 2021 to $237,038,000.

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 2022, six single-family lots were sold and two single-family lots, of the 80 lots developed within Increment I, remained to be sold as of September 30, 2022.

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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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.

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.

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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 0.2% 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 for Increment II.

Also, in addition to Barnwell’s existing obligations to pay professional fees to certain parties based on percentages of its gross receipts, Kaupulehu Developments also 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 for Increment II.

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

In fiscal 2021, the Kukio Resort Land Development Partnerships sold eight lots in Increment I and as a result of the lot sales, made cash distributions to its partners of which Barnwell received $6,011,000, after distributing $683,000 to minority interests.

Of the $6,011,000 net cash distribution received from the Kukio Resort Land Development Partnerships, $459,000 represented a payment of the preferred return from KKM and was recorded as an additional equity pickup in the “Equity in income of affiliates” line item on the accompanying Consolidated Statement of Operations during the year ended September 30, 2021.

See Note 4 for further discussion on the preferred return from KKM.

In fiscal 2022, the Kukio Resort Land Development Partnerships sold six lots in Increment I and as a result of the lot sales, made cash distributions to its partners of which Barnwell received $3,400,000 resulting in a net amount of $3,028,000, after distributing $372,000 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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Barnwell’s wholly-owned subsidiary, Water Resources, drills water and water monitoring wells of varying depths in Hawaii, installs and repairs water pumping systems, and is the distributor for Trillium Flow Technologies, previously known as Floway, pumps and equipment in the state of Hawaii.

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

Additionally, Water Resources temporarily rents a storage facility in Honolulu, Hawaii, and leases a one acre maintenance and storage facility with 2,800 square feet of interior space in Kawaihae, Hawaii, and a one-half acre equipment storage yard in Waimea, Hawaii.

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

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 leases a one-acre maintenance and storage facility with 2,800 square feet of interior space in Kawaihae, Hawaii, and a one-half acre equipment storage yard in Waimea, Hawaii.

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

Water Resources currently operates in Hawaii and is not subject to seasonal fluctuations.

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Contracts provide for arbitration in the event of disputes.

In fiscal 2021, Water Resources started one well drilling and five pump installation and repair contracts and completed six pump and repair contracts.

No well drilling contracts were completed in fiscal 2021.

Of the six completed pump and repair contracts, one was started in fiscal 2019, two were started in fiscal 2020 and three were started in the current year.

Fifty-six percent of well drilling and pump installation and repair jobs, representing 48% of total contract drilling revenues in fiscal 2021, have been pursuant to government contracts.

At September 30, 2021, there was a backlog of six well drilling and ten pump installation and repair contracts, of which five well drilling and nine pump installation and repair contracts were in progress as of September 30, 2021.

During the year ended September 30, 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.

No drilling rigs were sold in fiscal 2021.

In October 2022, Water Resources sold an additional drilling rig to an independent third party for proceeds of $551,000, net of related costs and accordingly, the Company will recognize a $551,000 gain on the sale of the drilling rig in the first quarter of fiscal 2023 ending December 31, 2022 as the rig was fully depreciated.

In fiscal 2022, Water Resources started two well drilling and four pump installation and repair contracts and completed three well drilling and three pump installation and repair contracts.

completed well drilling contracts, one was started in fiscal 2018 and two were started in fiscal 2019.

Of the three completed pump installation and repair contracts, one was started in fiscal 2016, one was started in fiscal 2020 and one was started in the current year.

Fifty-two percent of well drilling and pump installation and repair jobs, representing 59% of total contract drilling revenues in fiscal 2022, have been pursuant to government contracts.

At September 30, 2022, there was a backlog of seven well drilling and 14 pump installation and repair contracts, of which four well drilling and 10 pump installation and repair contracts were in progress as of September 30, 2022.

The approximate dollar amount of Water Resources’ backlog of firm well drilling and pump installation and repair contracts at December 1, 2022 and 2021 was as follows:

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$ 11,200,000 $ 9,500,000

Of the contracts in backlog at December 1, 2021, $5,900,000 is expected to be recognized in fiscal 2022, $2,436,000 pertains to a government contract that expires in 2022 and may not be extended, with the remainder to be recognized in the following fiscal year.

Of the contracts in backlog at December 1, 2022, $8,600,000 is expected to be recognized in fiscal 2023 with the remainder to be recognized in the following fiscal year.

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

These competitors are also capable of installing and repairing vertical turbine and submersible water pumping systems in Hawaii.

These competitors also are capable of installing and repairing vertical turbine and submersible water pumping systems in Hawaii.

These contractors compete actively with Water Resources for government and private contracts.

Pricing is Water Resources’ major method of competition;

reliability of service is also a significant factor.

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 2022 will continue.

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Available Information

We are required to file annual, quarterly and current reports and other information with the SEC.

These filings are not deemed to be incorporated by reference in this report.

You may read and copy any document filed by us at the Public Reference Room of the SEC, 100 F Street, N.E., Washington, D.C.

20549, on official business days during the hours of 10 a.m.

You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330.

Our filings with the SEC are also available to the public through the SEC’s website at www.sec.gov.

Furthermore, we maintain an internet site at www.brninc.com.

We make available on our internet 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 these websites are not incorporated into this filing.

Furthermore, the Company’s references to URLs for these websites are intended to be textual references only.

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 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.

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