What changed in this filing

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Item 1. Business

2021-12-21 compared with 2020-12-16 · 123 added, 117 removed, 210 unchanged (53% of the section changed)

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Barnwell operates in the following three principal business segments:

• Oil and Natural Gas Segment - Barnwell engages in oil and natural gas development, production, acquisitions and sales in Canada.

• Oil and Natural Gas Segment - Barnwell engages in oil and natural gas development, production, acquisitions and sales in Canada and in the U.S.

state of Oklahoma.

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

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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 through horizontal well drilling and completion techniques.

Octavian Oil is a Canadian company incorporated in 2016 to achieve growth through the acquisition 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.

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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 very little capital investment to maintain production levels.

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.

With 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 103 Bbls of oil and 84 Boe of natural gas and NGL per day.

Barnwell endeavors 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 assets not in the Twining area.

These assets are diverse in location and attributes, being located throughout Alberta and producing shallow gas and conventional oil from a variety of pools.

They are mostly non-operated and they have been accumulated

over decades of Barnwell activity in the basin.

Barnwell is continually evaluating opportunities to either divest these assets, or add to them depending on technical and economic evaluations.

The majority of these assets were put up for sale in January 2019, but COVID-19 and the resulting oil price collapse resulted in no reasonable offers being received.

Barnwell believes that market conditions are right to opportunistically pursue acquisitions as there are not many active buyers and plenty of motivated sellers of small to medium sized assets.

We have hired agents and a consultant to pursue these opportunities.

However, our ability to fund such investments is currently uncertain.

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

At September 30, 2019, Barnwell’s reserves were approximately 80% operated and 65% conventional oil and natural gas liquids.

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.

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.

Our oil and natural gas segment revenues, profitability, and future rate of growth are dependent upon oil and natural gas prices and obtaining external financing or sufficient land investment cash flows to fund the development of our proved undeveloped reserves.

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

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.

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.

By divesting significant oil and natural gas assets prior to the 2015 decline in commodity prices, Barnwell was able to repay all of its debt, use funds for general corporate purposes, and fund its acquisition investments.

Oil and natural gas prices have recovered significantly from the prior year which could improve sources of external finances.

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

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

On August 28, 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.

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.

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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 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, 2019, proved undeveloped reserves were primarily attributable to Twining, and were estimated to be converted to proved developed reserves through future capital expenditures by Barnwell.

This was for the development of 12 gross (8.82 net) wells over the next five years.

However, at September 30, 2020, Barnwell had no proved undeveloped reserves related to Twining as oil prices fell

significantly this year making the drilling of proved undeveloped reserves uneconomic at current prices.

As a result, the Company currently does not have a definitive plan to develop the reserves.

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.

Preparation of Reserve Estimates

Barnwell’s 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 reserves in this Form 10-K is derived from the report of InSite.

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 is 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 of the six independent directors.

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.

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

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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, 2020 on all properties in which Barnwell has an interest.

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

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.

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

The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimates of established proved producing oil and natural gas properties.

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Total (Boe) 1,138,000 4,000 1,142,000

During fiscal 2020, Barnwell’s total net proved developed reserves of oil and natural gas liquids increased by 1,000 Bbls (essentially unchanged) and total net proved developed reserves of natural gas increased by 410,000 Mcf (22%), for a combined increase of 72,000 Boe (8%).

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

During fiscal 2020, total net proved undeveloped reserves of oil and natural gas liquids decreased by 885,000 Bbls (99%) and total net proved undeveloped reserves of gas decreased by 2,620,000 Mcf (100%).

The ability of Barnwell to convert the undeveloped reserves to developed reserves is heavily influenced by the cash flows generated by the oil and natural gas segment, the results of such drilling, and the ability of the Company to raise sufficient funds.

The low oil prices encountered during fiscal 2020 have rendered the proved undeveloped reserves uneconomic and management does not currently have a definitive plan to develop such reserves and therefore has excluded undeveloped reserves from this September 30, 2020 report.

During fiscal 2020, Barnwell converted one gross (1.0 net) well from proved undeveloped to proved developed reserves in the Twining area and participated in conversion of one gross (0.3 net) well from proved undeveloped to proved developed reserves in the Spirit River area.

These wells had total net proved reserves of 114,000 Boe and 94,000 Boe, respectively, at September 30, 2020.

The following table sets forth Barnwell’s oil and natural gas net reserves at September 30, 2020, 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, 2020.

During fiscal 2021, Barnwell’s total net proved developed reserves of oil and natural gas liquids increased by 106,000 Bbls (20%) and total net proved developed reserves of natural gas increased by 603,000 Mcf (26%), for a combined increase of 210,000 Boe (23%).

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 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, 2021, the date of the projection.

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Other properties — 2 — 3 1 37 64,000 86,000

Total 522 2,212 535 2,310 174 649 $ 5,565,000 $ 1,128,000

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

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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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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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 $2.23 per Mcf and an oil price of $49.73 per Bbl) and costs, and a discount factor more representative of the time value of money and the risks inherent in reserve estimates.

In December 2018, the Society of Petroleum Evaluation Engineers and associated industry professionals updated the Canadian Oil and Gas Evaluation (“COGE”) Handbook.

The updates clarify and streamline existing guidelines and offer additional guidance regarding Canadian reserves evaluations.

Barnwell has included all abandonment, decommissioning and reclamation costs and inactive well costs in accordance with best practice recommendations into the Company’s September 30, 2020 and September 30, 2019 year-end reserve reports.

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

Oil and Natural Gas Production

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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.

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.” The 2018 volumes reflect volumes from the Twining acquisition only from the closing date of August 28, 2018.

Year ended September 30,

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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 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 invested $3,151,000 in oil and natural gas properties during fiscal 2020, 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.

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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.

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.

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.

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.

The well was temporarily shut-in from mid-April 2020 to mid-May 2020 due to decreased oil prices.

Recent net oil production from this well was approximately 103 barrels per day.

One gross (0.3 net) horizontal development well was drilled in the Spirit River area in fiscal 2019 and then completed in fiscal 2020.

The well commenced production on November 17, 2019 and produced approximately 26,000 net barrels of oil during the fiscal year ended September 30, 2020 which represented 17% of the year's net oil production.

The Company's share of net oil production from this well averaged over 200 barrels per day during the first month of production but has since declined to approximately 40 barrels per day due to natural declines.

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

Producing Wells

As of September 30, 2020, Barnwell had interests in 134 gross (50.4 net) producing wells, of which 69 gross (42.2 net) were oil wells and 65 gross (8.2 net) were natural gas wells.

All wells were in Alberta, Canada.

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.

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 which Barnwell held as of September 30, 2020.

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, 2021.

Proved oil and natural gas reserves located in the United States 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-nine percent of Barnwell’s undeveloped acreage is not subject to expiration at September 30, 2020.

Eleven 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:

3% expire during fiscal 2021;

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:

6% expire during fiscal 2022;

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no expirations during fiscal 2024 and fiscal 2025;

and 2% expire during fiscal 2026.

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

Much of the undeveloped acreage is at non-operated properties over which we do not have control, and the value of such acreage is not estimated to be significant at current commodity prices.

Barnwell’s undeveloped acreage includes a significant concentration in the Thornbury (5,279 net acres) and Twining (1,472 net acres) areas of Alberta, Canada.

Barnwell’s undeveloped acreage includes a significant concentration in the Twining area (2,164 net acres).

Marketing of Oil and Natural Gas

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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 2020, over 80% of Barnwell’s oil and natural gas revenues were from products sold at spot prices.

In fiscal 2021, over 80% of

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

Barnwell does not use derivative instruments to manage price risk.

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The jurisdictions in which the oil and natural gas properties of Barnwell are located have regulatory provisions relating to permits for the drilling of wells, the spacing of wells, the prevention of oil and natural gas waste, allowable rates of production, environmental protection, and other matters.

The amount of oil and natural gas produced is subject to control by regulatory agencies in each province that periodically assign allowable rates of production.

The province of Alberta and Government of Canada also monitor and regulate the volume of natural gas that may be removed from the province and the conditions of removal.

There is no current government regulation of the price that may be charged on the sale of Canadian oil or natural gas production.

Canadian natural gas production destined for export is priced by market forces subject to export contracts meeting certain criteria prescribed by Canada’s National Energy Board and the Government of Canada.

All of Barnwell’s gross revenues were derived from properties located within Alberta, which charges oil and natural gas producers a royalty for production within the province.

The amount of oil and natural gas produced is subject to control by regulatory agencies in each province.

The province of Alberta and the Government of Canada also monitor the volume of natural gas that may be removed from the province and the conditions of removal;

currently all our natural gas is sold within Alberta.

All of Barnwell’s Canadian gross revenues were derived from properties located within Alberta, which charges oil and natural gas producers a royalty for production within the province.

Provincial royalties are calculated as a percentage of revenue and vary depending on production volumes, selling prices and the date of discovery.

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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 Alberta Energy Regulator's (“AER”) Licensee Liability Rating (“LLR”) program.

Under the LLR program the AER calculates a Liability Management Ratio (“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.

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 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.

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.

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

The AER reviews and approves the transfers of all well, facility and pipeline license from one operator to another, and requires purchasers of AER licensed oil and natural gas assets to have an LMR of 2.0 or higher immediately following the transfer of a license.

This review process typically takes 30 to 60 days from the date of application.

Application was made on August 28, 2018 for Barnwell of Canada to accept the transfer of the various licenses relating to the Twining acquisition.

On October 2, 2018, the AER approved the transfer of all of the related licenses.

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 Oil & Gas Ltd.

(“LGX”), an operating company that went into receivership in 2016.

The estimated asset retirement obligation for the Company's 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 Orphan Well Association (“OWA”).

However, as next largest interest holder in 78 of the wells and 6 facilities formerly operated by LGX, averaging 11%, the Company is required to take care and custody of those properties and to coordinate their closure.

On November 5, 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.

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 has submitted began in October 2019 with field inspections, securing wells, and equipment inventory, for which minor expenses were expended.

The plan includes 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;

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 proposes 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.

Annual gross costs estimated to be incurred currently are approximately $500,000, approximately $55,000 net to the Company, however, the Company expects it will have to pay the gross costs and then recover from the other working interest owners and the OWA their costs, such that there will be a period between Barnwell having to pay the gross costs and getting reimbursed for the other parties’ portions.

As an alternative to the above plan, the Company is in discussions to allow the OWA to perform well abandonments and reclamations on the Company’s behalf.

This would eliminate the need for Barnwell to carry LGX’s average 85% portion of Barnwell interest in wells in Manyberries.

Barnwell would also benefit from the OWA’s extensive experience and scale of operations in this area.

This could allow Barnwell to accelerate closure of the Manyberries area to a 4-year period (fiscal 2022-2025) from the above ten-year plan, and it is estimated that this plan would increase Barnwell’s net expenditures to approximately $150,000 annually, with some minor costs likely extending into fiscal 2026.

Over the past five years, the Company has worked to reduce its abandonment and reclamation obligations (“ARO”) associated with its oil and natural gas segment, both by divesting low-productivity assets and actively closing wells and sites.

Fifteen Barnwell operated sites have been certified as fully

reclaimed or exempt since 2016.

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.

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 new 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 will need to pay the remaining balance of $637,000 by August 2022.

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 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.

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.

Sixteen 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.

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In partnership with its vendors, Barnwell-operated sites have received $303,000 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, with a further $75,000 in activities approved to date.

Barnwell has further benefited from grants allocated to its non-operated property partners amounting to $114,000.

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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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.

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

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, 63 of which were sold from 2006 to 2020 and of which 17 lots remain to be sold, and a beach club on the portion of the property bordering the Pacific Ocean.

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.

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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.

The remaining 420 developable acres at Increment II are entitled for up to 350 homesites.

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:

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

In fiscal 2020, two single-family lots in Increment I were sold bringing the total amount of gross proceeds from single-family lot sales through September 30, 2020 to $219,700,000.

Prior to March 7, 2019, Kaupulehu Developments was entitled to receive payments from KD II based on a percentage of the gross receipts from KD II’s sales of residential lots or units in Increment II ranging from 8% to 10% of the price of improved or unimproved lots or 2.60% to 3.25% of the price of units constructed on a lot, to be determined in the future depending upon a number of variables, including whether the lots are sold prior to improvement.

Kaupulehu Developments was also entitled to receive 50% of distributions otherwise payable from KD II to its members up to $8,000,000, of which $3,500,000 had been received, after the members of KD II received distributions equal to the original basis of capital invested in the project.

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.

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.

Effective March 7, 2019, KDK and Replay hold ownership interests of 55% and 45%, respectively, of KD II.

Accordingly, Barnwell has a 10.8% indirect non-controlling ownership interest in KD II through KDK as of that date that will continue to be accounted for using the equity method of accounting.

KDK and Replay hold ownership interests of 55% and 45%, respectively, of KD II and Barnwell has a 10.8% indirect non-controlling ownership interest in KD II through KDK, which is accounted for using the equity method of accounting.

Barnwell continues to have an indirect 19.6% non-controlling ownership interest in KD Kukio Resorts, KD Maniniowali, and KD I.

Concurrent with the transaction whereby KD II admitted Replay as a new development partner, Kaupulehu Developments entered into new agreements with KD II whereby the aforementioned terms of

the former Increment II arrangement were eliminated and Kaupulehu Developments will instead be entitled to 15% of the cumulative net profits 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 will not have any partnership interests in KD II or KDK through its interest in Kaupulehu Developments.

The new 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.

Under the terms of the Increment II agreement with KD II, Kaupulehu Developments is entitled to 15% of the distributions of KD II, the cost of which is to be solely borne by KDK out of its 55%

ownership interest in KD II, plus a priority payout of 10% of KDK’s cumulative net profits derived from Increment II sales subsequent to Phase 2A, up to a maximum of $3,000,000 as to the priority payout.

Such interests are limited to distributions or net profits interests and Barnwell does not have any partnership interests in KD II or KDK through its interest in Kaupulehu Developments.

The arrangement also gives Barnwell rights to three single-family residential lots in Phase 2A of Increment II, and four single-family residential lots in phases subsequent to Phase 2A when such lots are developed by KD II, all at no cost to Barnwell.

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

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

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

The Increment I percentage of sales arrangement between Barnwell and KD I remains unchanged.

In fiscal 2020, the Kukio Resort Land Development Partnerships sold two lots in Increment I and as a result of the lot sales, made cash distributions to its partners of which Barnwell received $360,000, after distributing $20,000 to minority interests.

Of the $360,000 cash distribution received from the Kukio Resort Land Development Partnerships, $197,000 represented a partial payment of the preferred return from KKM and was recorded as an additional equity pickup in the “Equity in income (loss) of affiliates” line item on the accompanying Consolidated Statement of Operations during the year ended September 30, 2020.

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.

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Contract Drilling Segment

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 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.

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

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 2020, Water Resources started one well drilling and three pump installation and repair contracts and completed three well drilling contracts.

No pump installation and repair contracts were completed in fiscal 2020.

All of the three completed well drilling contracts were started in fiscal 2019.

Sixty-five percent of well drilling and pump installation and repair jobs, representing 9% of total contract drilling revenues in fiscal 2020, have been pursuant to government contracts.

At September 30, 2020, there was a backlog of four well drilling and thirteen pump installation and repair contracts, of which all four well drilling and ten pump installation and repair contracts were in progress as of September 30, 2020.

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.

The approximate dollar amount of Water Resources’ backlog of firm well drilling and pump installation and repair contracts at December 1, 2021 and 2020 was as follows:

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$ 9,500,000 $ 7,200,000

Of the contracts in backlog at December 1, 2020, $4,400,000 is expected to be recognized in fiscal 2021 with the remainder to be recognized in the following fiscal year.

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.

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

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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 2021 will continue.

Management currently estimates that well drilling activity for fiscal 2021 will be significantly lower than fiscal 2020 based upon the number and value of contracts in backlog.

Financial Information About Industry Segments and Geographic Areas

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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