CAUTIONARY STATEMENT RELEVANT TO FORWARD-LOOKING INFORMATION
FOR THE PURPOSE OF “SAFE HARBOR” PROVISIONS OF THE
PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
This Form 10-K, and the documents incorporated herein by reference, contain “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995 ("PSLRA"). A forward-looking statement is one which is based on current expectations of future events or conditions and does not relate to historical or current facts. These statements include various estimates, forecasts, projections of Barnwell Industries, Inc.’s (referred to herein together with its majority-owned subsidiaries as “Barnwell,” “we,” “our,” “us” or the “Company”) future performance, statements of Barnwell’s plans and objectives and other similar statements. All such statements we make are forward-looking statements made under the safe harbor of the PSLRA, except to the extent such statements relate to the operations of a partnership or limited liability company. Forward-looking statements include phrases such as “expects,” “anticipates,” “intends,” “plans,” “believes,” “predicts,” “estimates,” “assumes,” “projects,” “may,” “will,” “will be,” “should,” or similar expressions. Although Barnwell believes that its current expectations are based on reasonable assumptions, it cannot assure that the expectations contained in such forward-looking statements will be achieved. Forward-looking statements involve risks, uncertainties and assumptions which could cause actual results to differ materially from those contained in such statements. Investors should not place undue reliance on these forward-looking statements, as they speak only as of the date of filing of this Form 10-K, and Barnwell expressly disclaims any obligation or undertaking to publicly release any updates or revisions to any forward-looking statements contained herein.
Among the important factors that could cause actual results to differ materially from those in the forward-looking statements are domestic and international general economic conditions, such as recessionary trends and inflation; domestic and international political, legislative, economic, regulatory and legal actions, including changes in the policies of the Organization of the Petroleum Exporting Countries or other developments involving or affecting oil and natural gas producing countries; military conflict, embargoes, internal instability or actions or reactions of the governments of the U.S. and/or Canada in anticipation of or in response to such developments; interest costs, restrictions on production, restrictions on imports and exports in both the U.S. and Canada, the maintenance of specified reserves, tax increases and retroactive tax claims, royalty increases, expropriation of property, cancellation of contract rights, environmental protection controls, environmental compliance requirements and laws pertaining to workers’ health and safety; the condition of Hawaii’s real estate market, including the level of real estate activity and prices, the demand for new housing and second homes on the island of Hawaii, the rate of increase in the cost of building materials and labor, the introduction of building code modifications, changes to zoning laws, the condition of Hawaii’s tourism industry and the level of confidence in Hawaii’s economy; levels of land development activity in Hawaii; levels of demand for water well drilling and pump installation in Hawaii; the potential liability resulting from pending or future litigation; the Company’s acquisition or disposition of assets; the effects of changed accounting rules under GAAP promulgated by rule-setting bodies; and the factors set forth under the heading “Risk Factors” in this Form 10-K, in other portions of this Form 10-K, in the Notes to Consolidated Financial Statements, and in other documents filed by Barnwell with the SEC. In addition, unpredictable or unknown factors not discussed in this report could also cause actual results to materially and adversely differ from those discussed in the forward-looking statements.
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PART I
ITEM 1.BUSINESS
Overview
Barnwell was incorporated in Delaware in 1956 and fiscal 2024 represented Barnwell’s 68th year of operations. 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 and in the U.S. states of Oklahoma and Texas.
•Land Investment Segment - Barnwell owns land interests in Hawaii.
•Contract Drilling Segment - Barnwell provides well drilling services and water pumping system installation and repairs in Hawaii.
Oil and Natural Gas Segment
Overview
Barnwell acquires and develops crude oil and natural gas assets in the province of Alberta, Canada via two corporate entities, Barnwell of Canada and Octavian Oil. Barnwell of Canada is a U.S. 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 and development of crude oil reserves. Additionally, through its wholly-owned subsidiaries BOK Drilling, LLC (“BOK”), established in February 2021, and Barnwell Texas, LLC (“Barnwell Texas”), established in November 2022, Barnwell is involved in oil and natural gas investments in Oklahoma and Texas, respectively.
Strategy
Twining represents 70% of Barnwell’s fiscal 2024 production (Boe) and consists of assets in the Twining field, in Alberta, Canada. These assets were purchased in August 2018 and were augmented with subsequent smaller acquisitions of partners. These assets are partially operated by the Company and partially operated by Pine Cliff Energy Ltd. The oil wells operated by the Company largely have less than 15% per year decline rates, and due to these lower decline rates, require less capital investment to replace decline. This lower capital requirement along with the fact that the land is largely held indefinitely, enables development drilling to be done when commodity prices support it. Since Barnwell’s entry into the Twining property, we have participated in drilling 12 gross horizontal development wells that were completed with multi-stage sand fracs, which have cumulatively been or are forecast to be profitable. Of these 12 wells, three are 100%-owned operated wells in locations selected by Barnwell and nine gross (2.6 net) are non-operated wells. Barnwell plans to continue to develop the pool with more horizontal wells if commodity prices continue to support their profitability.
Barnwell also has some minor legacy assets that represent 14% of Barnwell’s fiscal 2024 production (Boe) and consist of the largely non-operated oil and natural gas assets located throughout Alberta, Canada, and produce shallow gas or conventional oil from a variety of pools. These assets have been accumulated over decades of Barnwell activity. Barnwell has divested many of these properties in
5
fiscal 2024 in order to reduce risk and increase focus in the Twining area. Barnwell will continue to opportunistically divest our remaining legacy Canadian assets and minimal capital is expected to be invested in these properties. Barnwell is continually reviewing the market and evaluating opportunities to add to our production and development portfolio.
The Company has non-operated working interests in seven wells varying from 1.2% to 4.2% and a minor overriding royalty interest, 0.07%, in one well in Oklahoma. Our interests in Oklahoma produced 7% of Barnwell’s fiscal 2024 production (Boe).
The Company has a 15.4% non-operated working interest in two wells in the Permian Basin in Texas. Our interests in Texas produced 9% of Barnwell’s fiscal 2024 production (Boe).
Operations
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. 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 markets are volatile. We may seek to raise additional capital if such proceeds are considered attractive and would support potential growth.
Natural gas prices are typically higher in the winter than at other times due to increased heating demand. 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. Oil prices received in Canada are impacted by differentials in price to West Texas Intermediate (“WTI”). In recent history this meant that Barnwell at times received prices at a significant discount to WTI. In 2024, additional oil export pipeline capacity was made available in Canada which greatly reduced this differential. Gas prices received in Canada are based on published AECO hub prices and are also impacted by local market conditions that result in a discount to U.S. Henry Hub pricing. Oil prices received from the Texas and Oklahoma properties are generally in line with WTI pricing. Realized gas prices from our Texas natural gas sold at the Waha Hub are at a significant discount to Henry Hub due to limited gas egress from the Permian Basin and excess supply in the area.
Preparation of Reserve Estimates
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, which 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, which 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
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review controls, including an independent internal review of the final reserve report for completeness and accuracy.
Barnwell has a Reserves Committee consisting of two independent directors and Barnwell's Corporate Secretary. The Reserves Committee was established to ensure the independence of the Company’s petroleum reserve engineers. The Reserves Committee is responsible for reviewing the annual reserve evaluation reports prepared by the independent petroleum reserve engineering firms and ensuring that the reserves are reported fairly in a manner consistent with applicable standards. The Reserves Committee meets annually to discuss reserve issues and policies and to meet with Company personnel and the independent petroleum reserve engineers.
The President and Chief Operating Officer of Barnwell of Canada and Octavian Oil, who also serves as the President and Chief Executive Officer of Barnwell effective April 1, 2024, is a professional engineer with over 25 years of relevant experience in the oil and natural gas industry in Canada and is a member of the Association of Professional Engineers and Geoscientists of Alberta.
Reserves
At September 30, 2024, Barnwell’s reserves were approximately 52% operated and consisted of 41% conventional oil, 15% conventional natural gas liquids, and 44% natural gas. At September 30, 2023, Barnwell’s reserves were approximately 43% operated and consisted of 38% conventional oil, 14% conventional natural gas liquids, and 48% natural gas.
The amounts set forth in the following table, based on our independent reserve engineers’ evaluation of our reserves, summarize our estimated proved reserves of oil, natural gas liquids, and natural gas as of September 30, 2024 for all properties located in Canada and the U.S. in which Barnwell has an interest. All of our oil and natural gas reserves are based on constant dollar price and cost assumptions. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimates of established proved producing oil and natural gas properties. Accordingly, these estimates are expected to change as future information becomes available. Proved oil and natural gas reserves are the estimated quantities of oil and natural gas that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions (i.e., prices and costs) existing at the time the estimate is made. Proved developed oil and natural gas reserves are proved reserves that can be expected to be recovered through existing wells and equipment in place and under operating methods being utilized at the time the estimates were made. No estimates of total proved net oil or natural gas reserves have been filed with, or included in reports to, any federal authority or agency, other than the SEC, since October 1, 2023.
As of September 30, 2024
Estimated Net Proved Developed Reserves
Estimated Net Proved Undeveloped Reserves
Estimated Net Proved Reserves
Oil (Bbls)
873,000
109,000
982,000
Natural gas liquids (Bbls)
340,000
23,000
363,000
Natural gas (Mcf)
5,815,000
640,000
6,455,000
Total (Boe)
2,184,000
239,000
2,423,000
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During fiscal 2024, Barnwell’s total net proved reserves of oil and natural gas liquids increased by 83,000 Bbls (9%) and 36,000 Bbls (11%), respectively, and total net proved reserves of natural gas decreased by 246,000 Mcf (4%), for a combined increase of 80,000 Boe (3%). The increase in proved reserves for oil and natural gas liquids were primarily the result of revisions due to the improved production performance of many wells in Twining as a result of focused attention and investment in optimization. The Company has identified a number of additional optimization projects for fiscal 2025 that should further improve well performance and reduce operating costs. Projects are generally workovers, field automation, and facility debottlenecking. Barnwell has an ownership is all processing facilities that handle our net production volumes.
The following tables set forth Barnwell’s oil and natural gas net reserves at September 30, 2024, by location and property name, based on information prepared by our independent reserve engineers, as well as net production and net revenues by location and property name for the year ended September 30, 2024. The reserve data in these tables are based on constant dollars where reserve estimates are based on sales prices, costs and statutory tax rates using a historical average price of the first day pricing of the last 12-months ending with September 2024.
As of September 30, 2024
Net Proved Producing Reserves
Net Proved Reserves
Property Name
Oil (MBbls)
NGL (MBbls)
Gas (MMcf)
Oil (MBbls)
NGL (MBbls)
Gas (MMcf)
Canada:
Twining
710
126
3,637
867
156
4,549
Medicine River
23
43
366
23
43
366
Thornbury
—
—
2
—
—
26
Other properties
2
—
—
2
—
—
United States:
Oklahoma
33
86
699
33
86
699
Texas
57
78
815
57
78
815
Total
825
333
5,519
982
363
6,455
For the year ended September 30, 2024
Net Production
Net Revenues
Property Name
Oil (MBbls)
NGL (MBbls)
Gas (MMcf)
Oil
NGL
Gas
Canada:
Twining
160
23
944
$
11,241,000
$
1,190,000
$
1,619,000
Medicine River
2
4
18
171,000
107,000
26,000
Thornbury
—
—
52
—
—
39,000
Other properties
22
9
71
633,000
9,000
58,000
United States:
Oklahoma
5
12
99
406,000
252,000
190,000
Texas
14
16
160
1,058,000
322,000
75,000
Total
203
64
1,344
$
13,509,000
$
1,880,000
$
2,007,000
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Net proved reserves that are attributable to existing producing wells are primarily determined using decline curve analysis. Net proved reserves attributable to producing wells with limited production history and for undeveloped locations are estimated using performance from analogous wells in the surrounding area and geologic data to assess the reservoir continuity.
Standardized Measure of Discounted Future Net Cash Flows
The following table sets forth Barnwell’s “Estimated Future Net Revenues” from total proved oil, natural gas and natural gas liquids reserves located in Canada and the U.S. and the present value of Barnwell’s “Estimated Future Net Revenues” (discounted at 10%) as of September 30, 2024. Estimated future net revenues for total proved reserves are net of estimated future expenditures of developing and producing the proved reserves, and assume the continuation of existing economic conditions. Net revenues have been calculated using the average first-day-of-the-month price during the 12-month period ending as of the balance sheet date and current costs, after deducting all royalties, operating costs, future estimated capital expenditures (including abandonment costs), and income taxes. The amounts below include future cash flows from reserves that are currently proved undeveloped reserves and do not deduct general and administrative or interest expenses.
Year ending September 30,
2025
$
5,208,000
2026
4,802,000
2027
3,301,000
Thereafter
2,646,000
Undiscounted future net cash flows, after income taxes
$
15,957,000
Standardized measure of discounted future net cash flows
$
15,850,000
*
_______________________________________________
*This amount does not purport to represent, nor should it be interpreted as, the fair value of Barnwell’s oil and natural gas reserves. An estimate of fair value would also consider, among other items, the recovery of reserves not presently classified as proved, anticipated future changes in oil and natural gas prices (these amounts were based on a natural gas price of $1.16 per Mcf and an oil price of $70.78 per Bbl) and costs, and a discount factor more representative of the time value of money and the risks inherent in reserve estimates.
Barnwell has included all abandonment, decommissioning and reclamation costs and inactive well costs into the Company’s reserve reports in accordance with best practice recommendations.
Oil and Natural Gas Production
The following table summarizes (a) Barnwell’s net production for the last three fiscal years, based on sales of natural gas, oil and natural gas liquids, from all wells in which Barnwell has or had an interest, and (b) the average sales prices and average production costs for such production during the same periods. Production amounts reported are net of royalties. All of Barnwell’s net production in fiscal 2024 and 2023 was derived in Alberta, Canada and in the U.S. states of Oklahoma and Texas. Barnwell’s net production in fiscal 2022 was derived in Alberta, Canada and in Oklahoma. For a discussion regarding our total annual production volumes, average sales prices, and related production costs, see Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
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Year ended September 30,
2024
2023
2022
Annual net production:
Natural gas (Mcf)
1,344,000
1,263,000
964,000
Oil (Bbls)
203,000
204,000
182,000
Natural gas liquids (Bbls)
64,000
52,000
48,000
Total (Boe)
491,000
467,000
396,000
Total (Mcfe)
2,946,000
2,799,000
2,296,000
Annual average sales price per unit of production:
Mcf of natural gas*
$1.41
$2.64
$4.63
Bbl of oil**
$66.49
$69.77
$86.73
Bbl of natural gas liquids**
$29.38
$32.24
$48.06
Annual average production cost per Boe produced***
$19.82
$22.10
$23.66
Annual average production cost per Mcfe produced***
*Calculated on revenues net of pipeline charges before royalty expense divided by gross production.
**Calculated on revenues before royalty expense divided by gross production.
***Calculated on production costs, excluding natural gas pipeline charges, divided by the combined total production of natural gas liquids, oil and natural gas.
Capital Expenditures and Acquisitions
Barnwell invested $4,805,000 in oil and natural gas properties during fiscal 2024, including accrued capital expenditures and acquisitions of oil and natural gas properties and excluding additions and revisions to estimated asset retirement obligations. Barnwell’s capital expenditures were primarily for the drilling of a new well and for equipment and upgrades to facilities, all of which were in the Twining area.
Barnwell invested $10,729,000 in oil and natural gas properties during fiscal 2023, including accrued capital expenditures and acquisitions of oil and natural gas properties and excluding additions and revisions to estimated asset retirement obligations. Barnwell’s capital expenditures were primarily for the drilling of new wells in Texas and the Twining area.
Well Drilling Activities
During the year ended September 30, 2024, the Company drilled one gross (1.0 net) operated development oil well in the Twining area which started producing in mid-September 2024. The well has produced on average approximately 107 Boe per day in its first two months of production. Capital expenditures incurred by the Company for this well totaled approximately $3,183,000. The Company did not drill or participate in the drilling of wells in Texas or in Oklahoma during the year ended September 30, 2024.
In fiscal 2023, the Company participated in the drilling of three gross (0.9 net) non-operated development wells in the Twining area of Alberta, Canada. Total capital expenditures for the year ended September 30, 2023 totaled approximately $4,770,000 and included the drilling, completion and equipping of the three gross (0.9 net) wells along with various upgrades to the Twining facilities. Additionally, the Company participated in the drilling of two gross (0.3 net) non-operated development oil wells in Texas. Capital expenditures incurred for the drilling of these two wells totaled approximately
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$4,293,00 during the year ended September 30, 2023. The Company did not drill or participate in the drilling of wells in Oklahoma during the year ended September 30, 2023.
In fiscal 2022, the Company participated in the drilling of six gross (1.7 net) non-operated development wells in the Twining area. Capital expenditures incurred by the Company for these non-operated development wells totaled $4,366,000 for the year ended September 30, 2022. Five gross (1.4 net) wells were producing at September 30, 2022 and the remaining one gross (0.3 net) well was awaiting tie-in and started producing in fiscal 2023. 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.
Producing Wells
As of September 30, 2024, Barnwell has interests in 141 gross (69.3 net) producing wells in Alberta, Canada, of which 93 gross (63.3 net) were oil wells and 48 gross (6.0 net) were natural gas wells. Additionally, Barnwell has interests in seven gross (0.2 net) and two gross (0.3 net) producing oil wells in Oklahoma and Texas, respectively, as of September 30, 2024.
Developed Acreage and Undeveloped Acreage
The following table sets forth the gross and net acres of both developed and undeveloped oil and natural gas leases in the province of Alberta, Canada which Barnwell held as of September 30, 2024. 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
Location
Gross
Net
Gross
Net
Gross
Net
Alberta, Canada
131,590
30,730
26,210
7,410
157,800
38,140
_________________________________________________
*“Developed Acreage” includes the acres covered by leases upon which there are one or more producing wells. “Undeveloped Acreage” includes acres covered by leases upon which there are no producing wells and which are maintained by the payment of delay rentals or the commencement of drilling thereon.
Seventy-seven percent of Barnwell’s undeveloped acreage is not subject to expiration at September 30, 2024. Twenty-three percent of Barnwell’s leasehold interests in undeveloped acreage is subject to expiration and may expire over the next five fiscal years, if not developed, as follows: 4% expire during fiscal 2025; 9% expire during fiscal 2026; 6% expire during fiscal 2027; 4% expire during fiscal 2028; and no expirations during fiscal 2029. There can be no assurance that Barnwell will be successful in renewing its leasehold interests in the event of expiration.
Barnwell’s undeveloped acreage includes a significant concentration in the Twining area (2,810 net acres). The remaining undeveloped acreage is at non-operated properties over which we do not have control, and the value of such acreage is not estimated to be significant at current commodity prices.
Marketing of Oil and Natural Gas
Barnwell sells its Canadian oil, natural gas, and natural gas liquids production under short-term contracts between itself and two main oil purchasers, one natural gas purchaser, and one natural gas
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liquids purchaser. The prices received are freely negotiated between buyers and sellers and are determined from transparent posted prices adjusted for quality and transportation differentials.
In the quarter ended December 31, 2023, the Company amended certain of its Canadian purchase and sales contracts to change the sales price on 1,055 gross Mcf per day of the Canadian natural gas that it sells during the period from April 1, 2024 to October 31, 2024 to a fixed index price before differentials of $2.55 Canadian dollars per Mcf, with remaining volumes continuing to be sold at spot prices. This per day volume of natural gas under fixed index price contract is equivalent to approximately 33% of Canadian natural gas gross production per day for the year ended September 30, 2024. In July 2024, the Company amended the sales price on 1,055 gross Mcf per day of the Canadian natural gas it will sell during the period from November 1, 2024 to March 31, 2025 to a fixed index price before differentials of $2.64 Canadian dollars per Mcf, with remaining volumes continuing to be sold at spot prices. This per day volume of natural gas under this fixed index price contract is equivalent to approximately 33% of Canadian natural gas gross production per day for the year ended September 30, 2024. These natural gas contracts were eligible for and elected as normal purchase and normal sales exception contracts and were thus excluded from derivative accounting.
In the quarter ended December 31, 2023, the Company amended certain of its Canadian purchase and sales contracts to change the sales price on 225 gross barrels per day of the Canadian oil for sale for the period from January 1, 2024 to June 30, 2024 to a fixed index price before differentials of $69.46 per net barrel, with remaining volumes continuing to be sold at spot prices. This per day volume of oil under this fixed index price contract was equivalent to approximately 35% of Canadian oil gross production per day for the year ended September 30, 2024. In July 2024, the Company amended the sales price on 100 gross barrels per day of the Canadian oil that it sells during the period from August 1, 2024 to December 31, 2024 to a fixed index price before differentials of $79.00 per net barrel, with remaining volumes continuing to be sold at spot prices. This per day volume of oil under this fixed index price contract is equivalent to approximately 16% of Canadian oil gross production per day for the year ended September 30, 2024. These oil contracts were eligible for and elected as normal purchase and normal sales exception contracts and were thus excluded from derivative accounting.
In fiscal 2024 and 2023, Barnwell took most of its Canadian oil, natural gas liquids and natural gas “in kind” where Barnwell markets the products instead of having the operator of a producing property market the products on Barnwell’s behalf. We sell oil, natural gas and natural gas liquids to a variety of energy marketing companies. Because our products are commodities for which there are numerous marketers, we are not dependent upon one purchaser or a small group of purchasers. Accordingly, the loss of any single purchaser would not materially affect our revenues.
Governmental Regulation
The jurisdictions in which the oil and natural gas properties of Barnwell are located have regulatory provisions relating to permits for the drilling of wells, the spacing of wells, the prevention of oil and natural gas waste, allowable rates of production, environmental protection, and other matters. The amount of oil and natural gas produced is subject to control by regulatory agencies in each province. The province of Alberta and the Government of Canada also monitor the volume of natural gas that may be removed from the province and the conditions of removal; currently all our Canadian natural gas is sold within Alberta.
All of Barnwell’s Canadian gross revenues were derived from properties located within Alberta, which charges oil and natural gas producers a royalty for production within the province. Provincial
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royalties are calculated as a percentage of revenue and vary depending on production volumes, selling prices and the date of discovery. Barnwell also pays gross overriding royalties and leasehold royalties on a portion of its oil and natural gas sales to parties other than the province of Alberta.
Under the current royalty framework for newly drilled wells, the same royalty calculation applies to both oil and natural gas wells and royalties are determined on a revenue minus cost basis where producers pay a flat royalty rate of 5% of gross revenues until a well reaches payout after which an increased post-payout royalty applies. Post payout royalties vary with commodity prices and well production rates.
In fiscal 2024, 75% of Canadian royalties were related to Alberta government charges and 25% of royalties were related to freehold, overriding royalties and other charges.
In fiscal 2024, the weighted-average royalty rate paid on all of Barnwell’s Canadian natural gas was 6%, and the weighted-average royalty rate paid on oil was 21%. In fiscal 2024, the weighted-average royalty rate paid on all of Oklahoma’s and Texas’s production was 23% and 26%, respectively.
Under Canadian oil and gas law and regulations, in order for the Company to retain the right to acquire, transfer, or drill well licenses, Barnwell must maintain a favorable Licensee Capability Assessment (“LCA”) with the Alberta Energy Regulator’s (“AER”). The LCA is intended to be a comprehensive assessment of corporate health and considers a wide variety of factors and establishes guidelines for the industry with regards to the management of liabilities throughout the entire lifecycle of oil and gas projects. Factors considered by the AER are combined into six groups, these being current financial distress, liability magnitude, resources lifespan, operations compliance, closure efficiency, and administrative compliance. These factors are compared to peer operators and ranked into three “Tiers.” Barnwell’s assessment under the LCA Program is currently favorable with Tier 1 or Tier 2 overall rankings in the six factor groups. Barnwell believes it can continue to manage its operations to maintain a favorable ranking.
A program has also been implemented by the AER which requires mandatory annual minimum expenditures towards outstanding decommissioning and reclamation obligations in accordance with AER targets which are adjusted by the AER on an annual basis. The target for calendar 2025 is 6.2% of an individual company’s inactive liability. This amount for Barnwell is approximately $244,000. Barnwell believes the targets assessed by the AER are within estimated forecasts for Barnwell’s future ARO spending and therefore the Company expects to be in compliance with AER spending targets under their mandatory spend requirements.
In instances where Barnwell is a non-operating partner of a company which has become insolvent, Barnwell and any remaining partners are responsible for administering site closure. This is achieved in one of two ways. First, either Barnwell or the other partners proceed with closure, and then make a claim for the costs attributed to the insolvent entity from the Orphan Well Association (“OWA”) after the abandonment work has been certified complete by the AER. Alternatively, Barnwell may pay a deposit to the OWA for its net share of the estimated closure costs, plus contingency as determined by the OWA. This allows the OWA to proceed with closure work on behalf of all partners. As of September 2024, Barnwell had provided $923,000 in cash deposits to the OWA, and $353,000 of the deposit has been spent on closure activities as at September 30, 2024. If the amount of deposit proves larger than that required by the OWA to complete the estimated work, Barnwell will receive a refund on the excess after sites are certified by the AER. These deposits do not earn interest. Asset retirement obligations of Barnwell’s net
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share of sites operated by all partners are included in “Asset retirement obligation”, current and long-term, in the Consolidated Balance Sheets.
Over the past eight years, the Company has worked to reduce its abandonment and reclamation obligations associated with its oil and natural gas segment, both by divesting low-productivity assets and actively closing wells and sites. Twenty-four Barnwell-operated sites have been certified as fully reclaimed or exempt since 2016.
Competition
Barnwell competes in the sale of oil and natural gas on the basis of price and on the ability to deliver products. The oil and natural gas industry is intensely competitive in all phases, including the acquisition and development of new production and reserves and the acquisition of equipment and labor necessary to conduct drilling activities. The competition comes from numerous major oil companies as well as numerous other independent operators. There also is competition between the oil and natural gas industry and other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers. Barnwell is a minor participant in the industry and competes in its oil and natural gas activities with many other companies having far greater financial, technical and other resources.
Land Investment Segment
Overview
Barnwell owns a 77.6% interest in Kaupulehu Developments, a Hawaii general partnership (“Kaupulehu Developments”) that has the right to receive payments from KD I and KD II resulting from the sale of lots and/or residential units by KD I and KD II within the approximately 870 acres of the Kaupulehu Lot 4A area in two increments (“Increment I” and “Increment II”), located approximately six miles north of the Kona International Airport in the North Kona District of the island of Hawaii. Kaupulehu Developments also holds an interest in approximately 1,000 acres of vacant leasehold land zoned conservation located adjacent to Lot 4A under a lease that terminates in December 2025, which currently has no development potential without both a development agreement with the lessor and zoning reclassification.
Barnwell, through two limited liability limited partnerships, KD Kona and KKM Makai (“KKM”), holds a non-controlling ownership interest in the Kukio Resort Land Development Partnerships comprised of KD Kukio Resorts, KD Maniniowali, and KDK. The Kukio Resort Land Development Partnerships own certain real estate and development rights interests in the Kukio, Maniniowali and Kaupulehu portions of Kukio Resort, a private residential community on the Kona coast of the island of Hawaii, as well as Kukio Resort’s real estate sales office operations. KDK holds interests in KD I and KD II. KD I is the developer of Increment I, and KD II is the developer of Increment II. Barnwell's ownership interests in the Kukio Resort Land Development Partnerships are accounted for using the equity method of accounting.
Operations
Increment I is an area of 80 single-family lots, all of which were sold from 2006 to 2024, and a beach club on the portion of the property bordering the Pacific Ocean. Increment II is the remaining portion of the approximately 870-acre property and is zoned for single-family and multi-family residential units and a golf course and clubhouse. Two residential lots of approximately two to three acres in size
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fronting the ocean were developed within Increment II and sold by KD II, and the remaining acreage within Increment II is not yet under development. It is uncertain when or if KD II will develop the other areas of Increment II, and there is no assurance with regards to the amounts of future sales from Increment II. The remaining 420 developable acres at Increment II are entitled for up to 350 homesites. No definitive development plans have been made by KD II, the developer of Increment II, as of the date of this report.
Kaupulehu Developments was entitled to receive payments from KD I based on 10% of the gross receipts from KD I's sales of single-family residential lots in Increment I. In fiscal 2024, the last two remaining single-family lots of the 80 lots developed within Increment I were sold.
In March 2019, KD II admitted a new development partner, Replay Kaupulehu Development, LLC (“Replay”), a party unrelated to Barnwell, in an effort to move forward with development of the remainder of Increment II at Kaupulehu. KDK and Replay hold ownership interests of 55% and 45%, respectively, of KD II and Barnwell has a 10.8% indirect non-controlling ownership interest in KD II through KDK, which is accounted for using the equity method of accounting. Barnwell continues to have an indirect 19.6% non-controlling ownership interest in KD Kukio Resorts, KD Maniniowali, and KD I.
Under the terms of the Increment II agreement with KD II, Kaupulehu Developments is entitled to 15% of the distributions of KD II, the cost of which is to be solely borne by KDK out of its 55% ownership interest in KD II, plus a priority payout of 10% of KDK’s cumulative net profits derived from Increment II sales subsequent to Phase 2A, up to a maximum of $3,000,000 as to the priority payout. Such interests are limited to distributions or net profits interests and Barnwell does not have any partnership interests in KD II or KDK through its interest in Kaupulehu Developments. The arrangement also gives Barnwell rights to three single-family residential lots in Phase 2A of Increment II, and four single-family residential lots in phases subsequent to Phase 2A when such lots are developed by KD II, all at no cost to Barnwell. Barnwell is committed to commence construction of improvements within 90 days of the transfer of the four lots in the phases subsequent to Phase 2A as a condition of the transfer of such lots. Also, in addition to Barnwell’s existing obligations to pay professional fees to certain parties based on percentages of its gross receipts, Kaupulehu Developments 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, Replay, for Increment II. Such compensation will be reflected as the obligation becomes probable and the amount of the obligation can be reasonably estimated. As stated above, Increment II is not yet under development and it is uncertain when or if KD II will develop the other areas of Increment II, and there is no assurance with regards to the amounts of future sales from Increment II.
In fiscal 2024, the Kukio Resort Land Development Partnerships sold the last two remaining lots in Increment I and as a result of the lot sales, made cash distributions to its partners of which Barnwell received $1,071,000 resulting in a net amount of $953,000, after distributing $118,000 to non-controlling interests.
Competition
Barnwell’s land investment segment is subject to intense competition in all phases of its operations including the acquisition of new properties, the securing of approvals necessary for land rezoning, and the search for potential buyers of property interests presently owned. The competition comes from numerous independent land development companies and other industries involved in land investment activities. The principal factors affecting competition are the location of the project and pricing. Barnwell is a minor
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participant in the land development industry and competes in its land investment activities with many other entities having far greater financial and other resources.
Contract Drilling Segment
Overview
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.
Operations
Water Resources owns and operates three water well drilling rigs, two pump rigs and other ancillary drilling and pump equipment. Additionally, Water Resources leases short-term a storage facility in Waipahu, Hawaii, and a one-acre maintenance and storage facility with 2,800 square feet of interior space in Kawaihae, Hawaii. Water Resources also maintains an inventory of uninstalled materials for jobs in progress and an inventory of drilling materials and pump supplies.
Water Resources currently operates in Hawaii and is not subject to seasonal fluctuations. The demand for Water Resources’ services is primarily dependent upon land development activities in Hawaii. Water Resources markets its services to land developers and government agencies, and identifies potential contracts through public notices, and referrals. Contracts are usually fixed price per lineal foot drilled and are negotiated with private entities or obtained through competitive bidding with private entities or local, state and federal agencies. Contract revenues are not dependent upon the discovery of water or other similar targets, and contracts are not subject to renegotiation of profits or termination at the election of the governmental entities involved. Contracts provide for arbitration in the event of disputes.
In fiscal 2023, Water Resources sold a drilling rig to an independent third party for proceeds of $551,000, net of related costs, and recognized a $551,000 gain on the sale of the drilling rig during the year ended September 30, 2023, as the rig was fully depreciated.
In fiscal 2024, Water Resources started three pump installation and repair contracts and completed two well drilling and five pump installation and repair contracts. The two completed well drilling contracts were both started in fiscal 2023. Of the five completed pump installation and repair contracts, two were started in fiscal 2017, one was started in fiscal 2019, and two were started in the current year. Fifty-four percent of well drilling and pump installation and repair jobs, representing 18% of total contract drilling revenues in fiscal 2024, have been pursuant to government contracts.
At September 30, 2024, there was a backlog of one well drilling and two pump installation and repair contracts and all of the contracts were in progress as of September 30, 2024.
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The approximate dollar amount of Water Resources’ backlog of firm well drilling and pump installation and repair contracts at December 1, 2024 and 2023 was as follows:
December 1,
2024
2023
Well drilling
$
800,000
$
5,900,000
Pump installation and repair
300,000
900,000
$
1,100,000
$
6,800,000
All of the contract drilling revenues in backlog at December 1, 2024 is expected to be recognized in fiscal 2025.
Potential Sale or Wind Down of the Contract Drilling Segment
On December 13, 2023, the Company entered into a stock purchase agreement with a construction company for the sale of Water Resources. On December 27, 2023, the stock purchase agreement was terminated by the buyer prior to closing. The Company continues to investigate strategies regarding Water Resources' future including, but not limited to, other potential opportunities for a sale of its stock or assets. If no sale of its stock or assets along with contract backlog can be secured, Water Resources will likely be wound down after all contracts in backlog are completed and any remaining drilling rigs and equipment will be liquidated.
Competition
Water Resources competes with other drilling contractors in Hawaii, some of which use drill rigs similar to Water Resources’. 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 also is a significant factor.
Financial Information About Industry Segments and Geographic Areas
Note 12 in the “Notes to Consolidated Financial Statements” in Item 8 contains information on our segments and geographic areas.
Employees
At December 1, 2024, Barnwell employed 28 individuals; 27 on a full time basis and 1 on a part-time basis.
Environmental Costs
Barnwell is subject to extensive environmental laws and regulations. U.S. Federal and state and Canadian Federal and provincial governmental agencies issue rules and regulations and enforce laws to protect the environment which are often difficult and costly to comply with and which carry substantial penalties for failure to comply, particularly in regard to the discharge of materials into the environment. These laws, which are constantly changing, regulate the discharge of materials into the environment and maintenance of surface conditions and may require Barnwell to remove or mitigate the environmental
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effects of the disposal or release of petroleum or chemical substances at various sites where it has a working interest.
For further information on environmental remediation, see the Contingencies section included in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the notes to our consolidated financial statements included in Item 8, “Financial Statements and Supplementary Data.”
Available Information
We maintain a website at www.brninc.com. We make available on our website free of charge our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to those reports as soon as practicable after we electronically file such reports with, or furnish them to, the SEC. The contents of our website are not part of this Annual Report on Form 10-K and are not incorporated by reference into this document. Our filings with the SEC are available to the public through the SEC’s website at www.sec.gov. The Company’s references to URLs for these websites are intended to be textual references only.
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ITEM 1A.RISK FACTORS
The business of Barnwell and its subsidiaries face numerous risks, including those set forth below or those described elsewhere in this Form 10-K or in Barnwell’s other filings with the SEC. The risks described below are not the only risks that Barnwell faces. If any of the following risk factors should occur, our profitability, financial condition or liquidity could be materially negatively impacted.
Entity-Wide Risks
Stockholders may be diluted significantly through our efforts to obtain financing, satisfy obligations through the issuance of securities or use our stock as consideration in certain transactions.
Our Board of Directors has authority, without action or vote of the stockholders, subject to the requirements of the NYSE American and applicable law, to issue all shares of our common stock or warrants or other instruments to purchase such shares of our common stock. In addition, we may raise capital by selling shares of our common stock, possibly at a discount to market in the future. These actions would result in dilution of the ownership interests of existing stockholders and may further dilute common stock book value, and that dilution may be material. A related effect of such issuances may enhance existing large stockholders’ influence on the Company, including that of Alexander Kinzler, our General Counsel and Secretary.
A small number of stockholders, including our General Counsel and Secretary, own a significant amount of our common stock and may have influence over the Company.
As of September 30, 2024, our General Counsel and Secretary, who is the Executive Chairman of the Board of Directors, and two other stockholders hold approximately 48% of our outstanding common stock. The interests of one or more of these stockholders may not always coincide with the interests of other stockholders. These stockholders have significant influence over all matters submitted to our stockholders, including the election of our directors, and could accelerate, delay, deter or prevent a change of control of the Company.
Our operations are subject to currency rate fluctuations.
Our operations are subject to fluctuations in foreign currency exchange rates between the U.S. dollar and the Canadian dollar. Our financial statements, presented in U.S. dollars, may be affected by foreign currency fluctuations through both translation risk and transaction risk. Volatility in exchange rates may adversely affect our results of operations, particularly through the weakening of the U.S. dollar relative to the Canadian dollar which may affect the relative prices at which we sell our oil and natural gas and may affect the cost of certain items required in our operations. To date, we have not entered into foreign currency hedging transactions to control or minimize these risks.
Adverse changes in actuarial assumptions used to calculate retirement plan costs due to economic or other factors, or lower returns on plan assets could adversely affect Barnwell’s results and financial condition.
Retirement plan cash funding obligations and plan expenses and obligations are subject to a high degree of uncertainty and could increase in future years depending on numerous factors, including the performance of the financial markets, specifically the equity markets and levels of interest rates.
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Declines in the price of our common stock could adversely affect the value of an asset on our balance sheet and our stockholders’ equity.
Currently, Barnwell’s pension plan is overfunded, meaning that the current fair value of the assets held by the pension plan exceeds the estimated current accumulated benefit obligation of the pension plan. The overfunded amount is included on our balance sheet as an asset titled “Asset for retirement benefits.” As of September 30, 2024, the value of that asset was $4,899,000, which represented 16% of the Company’s total assets of $30,669,000 and 38% of our stockholders’ equity. A decline in the value of our pension plan’s investments overall, or of any one investment, could reduce the value of “Asset for retirement benefits.”
A portion of the pension plan’s investments is in publicly traded stocks, one of which is Barnwell’s common stock. As of September 30, 2024, the value of the Barnwell common stock held by the pension plan was $934,000, representing approximately 7% of the fair market value of the pension plan’s assets. A decline in the price of our common stock would also have the effect of reducing the value of our “Asset for retirement benefits,” total assets and our stockholders’ equity.
The price of our common stock has been volatile and could continue to fluctuate substantially.
The market price of our common stock has been volatile and could fluctuate based on a variety of factors, including:
•fluctuations in commodity prices;
•variations in results of operations;
•announcements by us and our competitors;
•legislative or regulatory changes;
•general trends in the industry;
•general market conditions;
•litigation; and
•other events applicable to our industries.
Failure to retain key personnel could hurt our operations.
We require highly skilled and experienced personnel to operate our business. In addition to competing in highly competitive industries, we compete in a highly competitive labor market. Our business could be adversely affected by an inability to retain personnel or upward pressure on wages as a result of the highly competitive labor market. Further, there are significant personal liability risks to Barnwell of Canada's individual officers and directors related to well clean-up costs that may affect our ability to attract or retain the necessary people.
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We are a smaller reporting company and benefit from certain reduced governance and disclosure requirements, including that our independent registered public accounting firm is not required to attest to the effectiveness of our internal control over financial reporting. We cannot be certain if the omission of reduced disclosure requirements applicable to smaller reporting companies will make our common stock less attractive to investors.
Currently, we are a “smaller reporting company,” meaning that our outstanding common stock held by nonaffiliates had a value of less than$250 million at the end of our most recently completed second fiscal quarter. As a smaller reporting company, we are not required to comply with the auditor attestation requirements of Section 404 of theSarbanes-Oxley Act, meaning our auditors are not required to attest to the effectiveness of the Company’s internal control over financial reporting. As aresult, investors and others may be less comfortable with the effectiveness of the Company’s internal controls and the risk that materialweaknesses or other deficiencies in internal controls go undetected may increase. In addition, as a smaller reporting company, we takeadvantage of our ability to provide certain other less comprehensive disclosures in our SEC filings, including, among other things, providing onlytwo years of audited financial statements in annual reports and simplified executive compensation disclosures. Consequently, it may be morechallenging for investors to analyze our results of operations and financial prospects, as the information we provide to stockholders may bedifferent from what one might receive from other public companies in which one hold shares. As a smaller reporting company, we are not required to provide this information.
Risks Related to Oil and Natural Gas Segment
Acquisitions or discoveries of additional reserves are needed to increase our oil and natural gas segment operating results and cash flow.
In August 2018, Barnwell made a significant reinvestment into its oil and natural gas segment with the acquisition of the Twining property in Alberta, Canada. The Company believes there are potential undeveloped reserves for which significant future capital expenditures will be needed to convert those potential undeveloped reserves into developed reserves. If future circumstances are such that we are not able to make the capital expenditures necessary to convert potential undeveloped reserves to developed reserves, we will not replace the amount of reserves produced and sold and our reserves and oil and natural gas segment operating results and cash flows will decline accordingly, and we may be forced to sell some of our oil and natural gas segment assets under untimely or unfavorable terms. Any such curtailment or sale could have a material adverse effect on our business, financial condition and results of operations.
Future oil and natural gas operating results and cash flow are highly dependent upon our level of success in acquiring or finding additional reserves on an economic basis. We cannot guarantee that we will be successful in developing or acquiring additional reserves and our current financial resources may be insufficient to make such investments. Furthermore, if oil or natural gas prices increase, our cost for additional reserves also could increase.
We may not realize an adequate return on oil and natural gas investments.
Drilling for oil and natural gas involves numerous risks, including the risk that we will not encounter commercially productive oil or natural gas reservoirs. The wells we drill or participate in may not be productive, and we may not recover all or any portion of our investment in those wells. If future oil
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and natural gas segment acquisition and development activities are not successful it could have an adverse effect on our future results of operations and financial condition.
Oil and natural gas prices are highly volatile and further declines, or extended low prices will significantly affect our financial condition and results of operations.
Much of our revenues and cash flow are greatly dependent upon prevailing prices for oil and natural gas. Lower oil and natural gas prices not only decrease our revenues on a per unit basis, but also reduce the amount of oil and natural gas we can produce economically, if any. Prices that do not produce sufficient operating margins will have a material adverse effect on our operations, financial condition, operating cash flows, borrowing ability, reserves, and the amount of capital that we are able to allocate for the acquisition and development of oil and natural gas reserves.
Various factors beyond our control affect prices of oil and natural gas including, but not limited to, changes in supply and demand, market uncertainty, weather, worldwide political instability, foreign supply of oil and natural gas, the level of consumer product demand, government regulations and taxes, the price and availability of alternative fuels and the overall economic environment. Energy prices also are subject to other political and regulatory actions outside our control, which may include changes in the policies of the Organization of the Petroleum Exporting Countries or other developments involving or affecting oil-producing countries, or actions or reactions of the government of the U.S. in anticipation of or in response to such developments.
The inability of one or more of our working interest partners to meet their obligations may adversely affect our financial results.
For our operated properties, we pay expenses and bill our non-operating partners for their respective shares of costs. Some of our non-operating partners may experience liquidity problems and may not be able to meet their financial obligations. Nonperformance by a non-operating partner could result in significant financial losses.
Liquidity problems encountered by our working interest partners or the third party operators of our non-operated properties also may result in significant financial losses as the other working interest partners or third party operators may be unwilling or unable to pay their share of the costs of projects as they become due. In the event a third party operator of a non-operated property becomes insolvent, it may result in increased operating expenses and cash required for abandonment liabilities if the Company is required to take over operatorship.
We may incur material costs to comply with or as a result of health, safety, and environmental laws and regulations.
The oil and natural gas industry is subject to extensive environmental regulation pursuant to local, provincial and federal legislation. A violation of that legislation may result in the imposition of fines or the issuance of “clean up” orders. Legislation regulating the oil and natural gas industry may be changed to impose higher standards and potentially more costly obligations. Although we have recorded a provision in our financial statements relating to our estimated future environmental and reclamation obligations that we believe is reasonable, we cannot guarantee that we will be able to satisfy our actual future environmental and reclamation obligations.
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Barnwell's oil and natural gas segment is subject to the provisions of the Alberta Energy Regulator’s (“AER”) Licensee Life-Cycle Management Program via a Licensee Capability Assessment (“LCA”). Under this program the AER assesses the corporate health of the Company and considers a wider variety of factors than those considered under the previous program. The LCA 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”. Under the LCA Program, an inventory reduction program has also been implemented which requires mandatory annual minimum expenditures towards outstanding decommissioning and reclamation obligations in accordance with AER targets which are adjusted by the AER on an annual basis. The target for 2025 is 6.2% of an individual company’s inactive liability. These targets became effective January 1, 2022.
The AER may require purchasers of AER licensed oil and natural gas assets to be within Tiers 1 or 2 overall rankings in the six factors group. This requirement for well transfers hinders our ability to generate capital by selling oil and natural gas assets as there are less qualified buyers.
The AER may require the Company to provide a security deposit if assessed at Tier 3. Diverting funds to the AER in the future would result in the diversion of cash on hand and operating cash flows that could otherwise be used to fund oil and natural gas reserve replacement efforts, which could in turn have a material adverse effect on our business, financial condition and results of operations. If Barnwell fails to comply with the requirements of the LCA program, Barnwell's oil and natural gas subsidiary would be subject to the AER's enforcement provisions which could include suspension of operations and non-compliance fees and could ultimately result in the AER serving the Company with a closure order to shut-in all operated wells. Additionally, if Barnwell is non-compliant, the Company would be prohibited from transferring well licenses which would prohibit us from selling any oil and natural gas assets until the required cash deposit is made with the AER.
We are not fully insured against certain environmental risks, either because such insurance is not available or because of high premium costs. In particular, insurance against risks from environmental pollution occurring over time, as opposed to sudden and catastrophic damages, is not available on economically reasonable terms. Accordingly, any site reclamation or abandonment costs actually incurred in the ordinary course of business in a specific period could negatively impact our cash flow. Should we be unable to fully fund the cost of remedying an environmental problem, we might be required to suspend operations or enter into interim compliance measures pending completion of the required remedy.
We may fail to fully identify potential problems related to acquired reserves or to properly estimate those reserves.
We periodically evaluate acquisitions of reserves, properties, prospects and leaseholds and other strategic transactions that appear to fit within our overall business strategy. Our evaluation includes an assessment of reserves, future oil and natural gas prices, operating costs, potential for future drilling and production, validity of the seller’s title to the properties and potential environmental issues, litigation and other liabilities.
In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess
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their deficiencies and potential recoverable reserves. Inspections may not always be performed on every well, and environmental problems are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller of the properties may be unwilling or unable to provide effective contractual protection against all or part of the problems. We often are not entitled to contractual indemnification for environmental liabilities or title defects in excess of the amounts claimed by us before closing and acquire properties on an “as is” basis.
There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves and future production rates and costs with respect to acquired properties, and actual results may vary substantially from those assumed in the estimates.
If oil and natural gas prices decline and remain low, we may be required to take write-downs of the carrying values of our oil and natural gas properties.
Oil and natural gas prices affect the value of our oil and natural gas properties as determined in our full cost ceiling calculation. Any future ceiling test write-downs will result in reductions of the carrying value of our oil and natural gas properties and an equivalent charge to earnings.
The oil and natural gas industry is highly competitive.
We compete for capital, acquisitions of reserves, undeveloped lands, skilled personnel, access to drilling rigs, service rigs and other equipment, access to processing facilities, pipeline capacity and in many other respects with a substantial number of other organizations, most of which have greater technical and financial resources than we do. Some of these organizations explore for, develop and produce oil and natural gas, carry on refining operations and market oil and other products on a worldwide basis. As a result of these complementary activities, some of our competitors may have competitive resources that are greater and more diverse than ours. Furthermore, many of our competitors may have a competitive advantage when responding to factors that affect demand for oil and natural gas production, such as changing prices and production levels, the cost and availability of alternative fuels and the application of government regulations. If our competitors are able to capitalize on these competitive resources, it could adversely affect our revenues and profitability.
An increase in operating costs greater than anticipated could have a material adverse effect on our results of operations and financial condition.
Higher operating costs for our properties will directly decrease the amount of cash flow received by us. Electricity, supplies, and labor costs are a few of the operating costs that are susceptible to material fluctuation. The need for significant repairs and maintenance of infrastructure may increase as our properties age. A significant increase in operating costs could negatively impact operating results and cash flow.
Our operating results are affected by our ability to market the oil and natural gas that we produce.
Our business depends in part upon the availability, proximity and capacity of oil and natural gas gathering systems, pipelines and processing facilities. Canadian federal and provincial, as well as U.S. federal and state, regulation of oil and natural gas production, processing and transportation, tax and energy policies, general economic conditions, and changes in supply and demand could adversely affect our ability to produce and market oil and natural gas. If market factors change and inhibit the marketing of our production, overall production or realized prices may decline.
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We are not the operator and have limited influence over the operations of certain of our oil and natural gas properties.
We hold minority interests in certain of our oil and natural gas properties. As a result, we cannot control the pace of exploration or development, major decisions affecting the drilling of wells, the plan for development and production at non-operated properties, or the timing and amount of costs related to abandonment and reclamation activities although contract provisions give Barnwell certain consent rights in some matters. The operator’s influence over these matters can affect the pace at which we incur capital expenditures. Additionally, as certain underlying joint venture data is not accessible to us, we depend on the operators at non-operated properties to provide us with reliable accounting information. We also depend on operators and joint operators to maintain the financial resources to fund their share of all abandonment and reclamation costs.
Actual reserves will vary from reserve estimates.
Estimating reserves is inherently uncertain and the reserves estimation process involves significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data. The reserve data and standardized measures set forth herein are only estimates. Ultimately, actual reserves attributable to our properties will vary from estimates, and those variations may be material. The estimation of reserves involves a number of factors and assumptions, including, among others:
•oil and natural gas prices as prescribed by SEC regulations;
•historical production from our wells compared with production rates from similar producing wells in the area;
•future commodity prices, production and development costs, royalties and capital expenditures;
•initial production rates;
•production decline rates;
•ultimate recovery of reserves;
•success of future development activities;
•marketability of production;
•effects of government regulation; and
•other government levies that may be imposed over the producing life of reserves.
If these factors, assumptions and prices prove to be inaccurate, actual results may vary materially from reserve estimates.
Part of our strategy involves using some of the latest available horizontal drilling and completion techniques. The results of our drilling are subject to drilling and completion technique risks, and results may not meet our expectations for reserves or production.
Many of our operations involve, and are planned to utilize, the latest drilling and completion techniques as developed by our service providers in order to maximize production and ultimate recoveries and therefore generate the highest possible returns. Risks we face while completing our wells include, but are not limited to, the inability to fracture the planned number of stages, the inability to run tools and other equipment the entire length of the well bore during completion operations, the inability to recover such tools and other equipment, and the inability to successfully clean out the well bore after completion of the final fracture stimulation. Ultimately, the success of these drilling and completion techniques can only be
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evaluated over time as more wells are drilled and production profiles are established over a sufficiently long time period. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, limited access to gathering systems and takeaway capacity, and/or prices for crude oil, natural gas, and natural gas liquids decline, then the return on our investment for a particular project may not be as attractive as we anticipated and we could incur material write-downs of oil and gas properties and the value of our undeveloped acreage could decline in the future.
Production and reserves, if any, attributable to the use of enhanced recovery methods are inherently difficult to predict. If our enhanced recovery methods do not allow for the extraction of crude oil, natural gas, and associated liquids in a manner or to the extent that we anticipate, we may not realize an acceptable return on our investments in such projects.
Delays in business operations could adversely affect the amount and timing of our cash inflows.
In addition to the usual delays in payment by purchasers of oil and natural gas to the operators of our properties, and the delays of those operators in remitting payment to us, payments between any of these parties may also be delayed by:
•restrictions imposed by lenders;
•accounting delays;
•delays in the sale or delivery of products;
•delays in the connection of wells to a gathering system;
•blowouts or other accidents;
•adjustments for prior periods;
•recovery by the operator of expenses incurred in the operation of the properties; and
•the establishment by the operator of reserves for these expenses.
Any of these delays could expose us to additional third party credit risks.
The oil and natural gas market in which we operate exposes us to potential liabilities that may not be covered by insurance.
Our operations are subject to all of the risks associated with the operation and development of oil and natural gas properties, including the drilling of oil and natural gas wells, and the production and transportation of oil and natural gas. These risks include encountering unexpected formations or pressures, premature declines of reservoirs, blow-outs, equipment failures and other accidents, cratering, sour gas releases, uncontrollable flows of oil, natural gas or well fluids, adverse weather conditions, pollution, other environmental risks, fires and spills. A number of these risks could result in personal injury, loss of life, or environmental and other damage to our property or the property of others.
While we carry various levels of insurance, we could be affected by civil, criminal, regulatory or administrative actions, claims or proceedings. We cannot fully protect against all of the risks listed above, nor are all of these risks insurable. There is no assurance that any applicable insurance or indemnification agreements will adequately protect us against liability for the risks listed above. We could face substantial losses if an event occurs for which we are not fully insured or are not indemnified against or a customer or insurer fails to meet its indemnification or insurance obligations. In addition, there can be no assurance that insurance will continue to be available to cover any or all of these risks, or, even if available, that
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insurance premiums or other costs will not rise significantly in the future, so as to make the cost of such insurance prohibitive.
Deficiencies in operating practices and record keeping, if any, may increase our risks and liabilities relating to incidents such as spills and releases and may increase the level of regulatory enforcement actions.
Our operations are subject to domestic and foreign government regulation and other risks, particularly in Canada and the U.S.
Barnwell’s oil and natural gas operations are affected by political developments and laws and regulations, particularly in Canada and the U.S., such as restrictions on production, restrictions on imports and exports, the maintenance of specified reserves, tax increases and retroactive tax claims, expropriation of property, cancellation of contract rights, environmental protection controls, environmental compliance requirements and laws pertaining to workers’ health and safety. Further, the right to explore for and develop oil and natural gas on lands in Alberta is controlled by the government of that province. Changes in royalties and other terms of provincial leases, permits and reservations may have a substantial effect on Barnwell’s operations. We derive a significant portion of our revenues from our operations in Canada; 70% in fiscal 2024.
Additionally, our ability to compete in the Canadian oil and natural gas industry may be adversely affected by governmental regulations or other policies that favor the awarding of contracts to contractors in which Canadian nationals have substantial ownership interests. Furthermore, we may face governmentally imposed restrictions or fees from time to time on the transfer of funds to the U.S.
Government regulations control and often limit access to potential markets and impose extensive requirements concerning employee safety, environmental protection, pollution control and remediation of environmental contamination. Environmental regulations, in particular, prohibit access to some markets and make others less economical, increase equipment and personnel costs and often impose liability without regard to negligence or fault. In addition, governmental regulations may discourage our customers’ activities, reducing demand for our products and services.
Changes in U.S. trade policy, including the imposition of tariffs and the resulting consequences, could adversely affect our business, prospects, financial condition, and operating results.
There is currently significant uncertainty about the future relationship between the United States and Canada, including potential changes with respect to trade policies, treaties, tariffs, taxes, and other limitations on cross-border operations. Because most of our oil and natural gas production is in Canada, changes in tariffs, trade barriers, and other regulatory requirements could have an adverse effect on our business, prospects, financial condition and operating results, the extent of which cannot be predicted with certainty at this time.
Legislation, regulation, and other government actions and shifting customer preferences and other private efforts related to greenhouse gas (“GHG”) emissions and climate change could increase our operational costs and reduce demand for our oil and natural gas, resulting in a material adverse effect on the Company’s results of operations and financial condition.
Barnwell may experience challenges from the impacts of international and domestic legislation, regulation, or other government actions relating to GHG emissions (e.g., carbon dioxide and methane) and
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climate change. International agreements and national, regional, and state legislation and regulatory measures that aim to directly or indirectly limit or reduce GHG emissions are in various stages of implementation. Many of these actions, as well as customers’ preferences and use of oil and natural gas or substitute products, are beyond the Company’s control. Similar to any significant changes in the regulatory environment, GHG emissions and climate change-related legislation, regulation, or other government actions may curtail profitability in the oil and gas sector, or render the extraction of the Company’s hydrocarbon resources economically infeasible. In particular, GHG emissions-related legislation, regulations, and other government actions and shifting consumer preferences and other private efforts aimed at reducing GHG emissions may result in increased and substantial capital, compliance, operating, and maintenance costs and could, among other things, reduce demand for the Company’s oil and natural gas; adversely affect the economic feasibility of the Company’s resources; impact or limit our business plans; and adversely affect the Company’s sales volumes, revenues, margins and reputation.
The ultimate impact of GHG emissions and climate change-related agreements, legislation, regulation, and government actions on the Company’s financial performance is highly uncertain because the Company is unable to predict with certainty, the outcome of political decision-making processes, including the actual laws and regulations enacted, the variables and tradeoffs that inevitably occur in connection with such processes, and market conditions.
Compliance with foreign tax and other laws may adversely affect our operations.
Tax and other laws and regulations are not always interpreted consistently among local, regional and national authorities. Income tax laws, other legislation or government incentive programs relating to the oil and natural gas industry may in the future be changed or interpreted in a manner that adversely affects us and our stockholders. It also is possible that in the future we will be subject to disputes concerning taxation and other matters in Canada, including the manner in which we calculate our income for tax purposes, and these disputes could have a material adverse effect on our financial performance.
Unforeseen title defects may result in a loss of entitlement to production and reserves.
Although we conduct title reviews in accordance with industry practice prior to any purchase of resource assets or property, such reviews do not guarantee that an unforeseen defect in the chain of title will not arise and defeat our title to the purchased assets. If such a defect were to occur, our entitlement to the production from such purchased assets could be jeopardized.
Risks Related to Land Investment Segment
Receipt of future payments from KD II and cash distributions from the Kukio Resort Land Development Partnerships is dependent upon the developer’s continued efforts and ability to develop the property.
We are entitled to receive future payments based on a percentage of the sales prices of residential lots sold within the Kaupulehu area by KD II as well as a percentage of future distributions KD II makes to its members. However, in order to collect such payments we are reliant upon the developer, KD II, in which we own a non-controlling ownership interest, to proceed with the development or sale of the remaining portion of Increment II. Additionally, future cash distributions from the Kukio Resort Land Development Partnerships, which includes KD II, are also dependent on the development or sale of Increment II by KD II. It is uncertain when or if KD II will develop or sell the remaining portion of Increment II, and there is no assurance with regards to the amounts of future sales from Increment II. We
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do not have a controlling interest in the partnerships, and therefore are dependent on the general partner for development decisions. The receipt of future payments and cash distributions could be jeopardized if the developer fails to proceed with development of the property.
We hold investment interests in unconsolidated land development partnerships, which are accounted for using the equity method of accounting, in which we do not have a controlling interest. These investments involve risks and are highly illiquid.
These investments involve risks which include:
•the lack of a controlling interest in these partnerships and, therefore, the inability to require that the entities sell assets, return invested capital or take any other action without obtaining the majority vote of partners;
•potential for future additional capital contributions to fund operations and development activities;
•the adverse impact on overall profitability if the entities do not achieve the financial results projected;
•the reallocation of amounts of capital from other operating initiatives and/or an increase in indebtedness to pay potential future additional capital contributions, which could in turn restrict our ability to access additional capital when needed or to pursue other important elements of our business strategy;
•undisclosed, contingent or other liabilities or problems, unanticipated costs, and an inability to recover or manage such liabilities and costs and which could delay or prevent development of the real estate held by the land development partnerships; and
•certain underlying partnership data is not accessible to us, therefore we depend on the general partner to provide us with reliable accounting information.
Our land investment business is concentrated in the state of Hawaii. As a result, our financial results are dependent on the economic growth and health of Hawaii, particularly the island of Hawaii.
Barnwell’s land investment segment is impacted by the condition of Hawaii’s real estate market, which is affected by Hawaii’s economy and Hawaii’s tourism industry, as well as the U.S. and world economies in general. Any future cash flows from Barnwell’s land development activities are subject to, among other factors, the level of real estate activity and prices, the demand for new housing and second homes on the island of Hawaii, the rate of increase in the cost of building materials and labor, the introduction of building code modifications, changes to zoning laws, and the level of confidence in Hawaii’s economy.
The occurrence of natural disasters in Hawaii could adversely affect our business.
The occurrence of a natural disaster in Hawaii such as, but not limited to, earthquakes, landslides, hurricanes, tornadoes, tsunamis, volcanic activity, droughts and floods, could have a material adverse effect on our land investments. The occurrence of a natural disaster could also cause property and flood insurance rates and deductibles to increase, which could reduce demand for real estate in Hawaii.
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Risks Related to Contract Drilling Segment
Demand for water well drilling and/or pump installation is volatile. A decrease in demand for our services could adversely affect our revenues and results of operations.
Demand for services is highly dependent upon land development activities in the state of Hawaii. The real estate development industry is cyclical in nature and is particularly vulnerable to shifts in local, regional, and national economic conditions outside of our control such as interest rates, housing demand, population growth, employment levels and job growth and property taxes. A decrease in water well drilling and/or pump installation contracts will result in decreased revenues and operating results.
If we are unable to accurately estimate the overall risks, requirements or costs when bidding on or negotiating a contract that is ultimately awarded, we may achieve a lower than anticipated profit or incur a loss on the contract.
Contracts are usually fixed price per lineal foot drilled and require the provision of line-item materials at a fixed unit price based on approved quantities irrespective of actual per unit costs. Under such contracts, prices are established in part on cost and scheduling estimates, which are based on a number of assumptions, many of which are beyond our control. Expected profits on contracts are realized only if costs are accurately estimated and successfully controlled. We may not be able to obtain compensation for additional work performed or expenses incurred as a result of changes or inaccuracies in these estimates and underlying assumptions, such as unanticipated sub-surface site conditions, unanticipated technical problems, equipment failures, inefficiencies, cost of raw materials, schedule delays due to constraints on drilling hours, weather delays, or accidents. If cost estimates for a contract are inaccurate, or if the contract is not performed within cost estimates, then cost overruns may result in losses or cause the contract not to be as profitable as expected.
A significant portion of our contract drilling business is dependent on municipalities and a decline in municipal spending could adversely impact our business.
A significant portion of our contract drilling division revenues is derived from water and infrastructure contracts with governmental entities or agencies; 18% in fiscal 2024. Reduced tax revenues and governmental budgets may limit spending by local governments which in turn will affect the demand for our services. Material reductions in spending by a significant number of local governmental agencies could have a material adverse effect on our business, results of operations, liquidity and financial position.
Our contract drilling operations face significant competition.
We face competition for our services from a variety of competitors. Many of our competitors utilize drilling rigs that drill as quickly as our equipment but require less labor. Our strategy is to compete based on pricing and to a lesser degree, quality of service. If we are unable to compete effectively with our competitors, our financial results could be adversely affected.
Supply chain and manufacturing issues of well drilling and pump installation equipment could adversely affect our operating results.
We are dependent on various well drilling and pump installation equipment to conduct our contract drilling segment operations. The shortage of and/or delay in delivery of such equipment, such as pumps,
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interruptions in supply, and price increases of such equipment and materials due to supply chain issues and manufacturing disruptions could adversely impact our gross margin and results of operations.
Awarding of contracts is dependent upon our ability to obtain contract bid and performance bonds from insurers.
There can be no assurance that our ability to obtain such bonds will continue on the same basis as the past. Additionally, bonding insurance rates may increase and have an impact on our ability to win competitive bids, which could have a corresponding material impact on contract drilling operating results.
The contracts in our backlog are subject to change orders and cancellation.
Our backlog consists of the uncompleted portion of services to be performed under contracts that have been started and new contracts not yet started. Our contracts are subject to change orders and cancellations, and such changes could adversely affect our operations.
The occurrence of natural disasters in Hawaii could adversely affect our business.
The occurrence of a natural disaster in Hawaii such as, but not limited to, earthquakes, landslides, hurricanes, tornadoes, tsunamis, volcanic activity, droughts and floods, could have a material adverse effect on our ability to complete our contracts.
ITEM 1B.UNRESOLVED STAFF COMMENTS
None.
ITEM 1C.CYBERSECURITY
We recognize the importance of assessing, identifying, and managing material risks from cybersecurity threats. Our policies, standards, and procedures for assessing, identifying, and managing material risks from cybersecurity threats are integrated into our overall risk management system. In this regard, we use various tools and processes to help prevent, identify, and resolve any identified vulnerabilities and security incidents in a timely manner. These include, but are not limited to, internal reporting, periodic employee awareness updates, engaging experts and third-party monitoring and detection tools.
We employ third-party information technology (“IT”) consultants to manage our information technology environment and help manage and assess cybersecurity risks.
Our IT Steering Committee, comprised of our Chief Executive Officer, our Chief Financial Officer, our General Counsel, and an IT consultant, oversees efforts to prevent, detect, mitigate, and remediate cybersecurity risks and incidents through various means, which includes oversight over our third-party IT consultants, monitoring systems and employee engagement. Our senior management team is responsible for reporting any identified cybersecurity risks to the Audit Committee of our Board of Directors.
The Audit Committee of our Board of Directors meets periodically with management to review the Company’s overall policies with respect to risk assessment and risk management, including a review the systems and processes implemented by management to identify, assess, manage, and mitigate
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cybersecurity risks. Our senior management is responsible for the day-to-day supervision of the material risks we may face.
Our risks from cybersecurity threats have not affected or are reasonably not likely to materially affect our business strategy, results of operations, or financial condition.
ITEM 2.PROPERTIES
Oil and Natural Gas and Land Investment Properties
The location and character of Barnwell’s oil and natural gas properties and its land investment properties, are described above under Item 1, “Business.”
Corporate Offices
Barnwell's corporate headquarters is located in Honolulu, Hawaii, in a commercial office building under a lease that expires in February 2026.
ITEM 3.LEGAL PROCEEDINGS
Barnwell is routinely involved in disputes with third parties that occasionally require litigation. In addition, Barnwell is required to maintain compliance with all current governmental controls and regulations in the ordinary course of business. Barnwell’s management is not aware of any claims or litigation involving Barnwell that are likely to have a material adverse effect on its results of operations, financial position or liquidity.
ITEM 4.MINE SAFETY DISCLOSURES
Disclosure is not applicable to Barnwell.
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PART II
ITEM 5.MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Market Information
The principal market on which Barnwell’s common stock is being traded is the NYSE American under the ticker symbol “BRN.” The following tables present the quarterly high and low sales prices, on the NYSE American, for Barnwell’s common stock during the periods indicated:
Quarter Ended
High
Low
Quarter Ended
High
Low
December 31, 2022
$3.33
$2.70
December 31, 2023
$2.78
$2.06
March 31, 2023
$2.97
$1.89
March 31, 2024
$2.53
$2.15
June 30, 2023
$3.10
$2.47
June 30, 2024
$3.20
$2.30
September 30, 2023
$2.79
$2.18
September 30, 2024
$2.53
$2.12
Holders
As of December 13, 2024, there were 10,053,534 shares of common stock, par value $0.50, outstanding. As of December 13, 2024, there were approximately 80 shareholders of record and approximately 1,000 beneficial owners.
Dividends
No dividends were declared or paid during the year ended September 30, 2024. The following table sets forth the cash dividends paid per share of common stock during the year ended September 30, 2023.
Record Date
Date of Payment
Dividend Paid
August 24, 2023
September 11, 2023
$0.015
May 25, 2023
June 12, 2023
$0.015
February 23, 2023
March 13, 2023
$0.015
December 27, 2022
January 11, 2023
$0.015
The payment of future cash dividends will depend on, among other things, our financial condition, operating cash flows, and the level of our oil and natural gas capital expenditures and any other investments.
Securities Authorized for Issuance Under Equity Compensation Plans
See information included in Part III, Item 12, under the caption “Equity Compensation Plan Information.”
Stock Performance Graph and Cumulative Total Return
Disclosure is not required as Barnwell qualifies as a smaller reporting company.
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ITEM 6.[RESERVED]
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ITEM 7.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion is intended to assist in the understanding of the Consolidated Balance Sheets of Barnwell Industries, Inc. and subsidiaries (collectively referred to herein as “Barnwell,” “we,” “our,” “us” or the “Company”) as of September 30, 2024 and 2023, and the related Consolidated Statements of Operations, Comprehensive Loss, Equity, and Cash Flows for the years ended September 30, 2024 and 2023. This discussion should be read in conjunction with the consolidated financial statements and related Notes to Consolidated Financial Statements included in this report.
Critical Accounting Policies and Estimates
The Company considers an accounting estimate to be critical if the accounting estimate requires the Company to make assumptions that are difficult or subjective about matters that were highly uncertain at the time that the accounting estimate was made, and changes in the estimate that are reasonably likely to occur in periods subsequent to the period in which the estimate was made, or use of different estimates that the Company could have used in the current period, would have a material impact on the Company’s financial condition or results of operations. The most critical accounting policies inherent in the preparation of the Company’s consolidated financial statements are described below. We continue to monitor our accounting policies to ensure proper application of current rules and regulations.
Oil and Natural Gas Properties - full cost ceiling calculation and depletion
Policy Description
We use the full cost method of accounting for our oil and natural gas properties under which we are required to conduct quarterly calculations of a “ceiling,” or limitation, on the carrying value of oil and natural gas properties . The ceiling limitation is the sum of 1) the discounted present value (at 10%), using average first-day-of-the-month prices during the 12-month period ending as of the balance sheet date held constant over the life of the reserves (except where prices are defined by contractual arrangements), of Barnwell’s estimated future net cash flows from estimated production of proved oil and natural gas reserves, less estimated future expenditures to be incurred in developing and producing the proved reserves but excluding future cash outflows associated with settling asset retirement obligations with the exception of those associated with proved undeveloped reserves from wells that are to be drilled in the future; plus 2) the cost of major development projects and unproven properties not subject to depletion, if any; plus 3) the lower of cost or estimated fair value of unproven properties included in costs subject to depletion; less 4) related income tax effects. If net capitalized costs exceed this limit, the excess is expensed.
All items classified as unevaluated and unproved properties are assessed on a quarterly basis for possible impairment or reduction in value. Properties are assessed on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of various factors, including, but not limited to, the following: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; assignment of proved reserves; and economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and become subject to amortization.
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Judgments and Assumptions
The estimate of our oil and natural gas reserves is a major component of the ceiling calculation and represents the component that requires the most subjective judgments. Estimates of reserves are forecasts based on engineering data, historical data, projected future rates of production and the timing of future expenditures. The process of estimating oil and natural gas reserves requires substantial judgment, resulting in imprecise determinations, particularly for new discoveries. Our reserve estimates are prepared at least annually by independent petroleum reserve engineers. The passage of time provides more quantitative and qualitative information regarding estimates of reserves, and revisions are made to prior estimates to reflect updated information. A portion of the revisions are attributable to changes in the rolling 12-month average first-day-of-the-month prices, which impact the economics of producible reserves. In the last three fiscal years, annual revisions to our reserve volume estimates have averaged 18% of the previous year’s estimate, due in large part to the impacts of volatile oil and natural gas prices which change the economic viability of producing such reserves and changes in estimated proved undeveloped reserves which can fluctuate from year to year depending upon the Company's plans and ability to fund the capital expenditures necessary to develop such reserves. There can be no assurance that more significant revisions will not be necessary in the future. If future significant revisions are necessary that reduce previously estimated reserve quantities, such revisions could result in a write-down of oil and natural gas properties.
If reported reserve volumes were revised downward by 5% at the end of fiscal 2024, the ceiling limitation for Canada would have decreased approximately $906,000 which would not have resulted in a ceiling impairment before income taxes due to sufficient room between the ceiling and the carrying value of Canadian oil and natural gas properties at the end of fiscal 2024 of approximately $4,658,000. However, an additional $197,000 impairment would be recorded for U.S. oil and gas properties at the end of fiscal 2024 as there is no room between the ceiling and the carrying value of U.S. oil and natural gas properties at the end of fiscal 2024.
In addition to the impact of the estimates of proved reserves on the calculation of the ceiling, estimated proved reserves are also a significant component of the quarterly calculation of depletion expense. The lower the estimated reserves, the higher the depletion rate per unit of production. Conversely, the higher the estimated reserves, the lower the depletion rate per unit of production. If reported reserve volumes were revised downward by 5% as of the beginning of fiscal 2024, depletion for fiscal 2024 would have increased by approximately $222,000.
While the quantities of proved reserves require substantial judgment, the associated prices of oil, natural gas and natural gas liquids reserves are the average first-day-of-the-month prices during the 12-month period ending in the reporting period on a constant basis as prescribed by SEC regulations. Additionally, the applicable discount rate that is used to calculate the discounted present value of the reserves is mandated at 10%. Costs included in future net revenues are determined in a similar manner. As such, the future net revenues associated with the estimated proved reserves are not based on an assessment of future prices or costs.
Contract Drilling Revenues and Operating Expenses
Policy Description
Through contracts which are normally less than twelve months in duration, Barnwell drills water and water monitoring wells and installs and repairs water pumping systems in Hawaii. Barnwell
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recognizes revenue from well drilling or the installation of pumps over time based on total costs incurred on the projects relative to the total expected costs to satisfy the performance obligation as management believes this is an accurate representation of the percentage of completion as control is continuously transferred to the customer. Uninstalled materials, which typically consists of well casing or pumps, are excluded in the costs-to-costs calculation for the duration of the contract as including these costs would result in a distortion of progress towards satisfaction of the performance obligation due to the resulting cumulative catch-up in margin in a single period. An equal amount of cost and revenue is recorded when uninstalled materials are controlled by the customer, which is typically when Barnwell has the right to payment for the materials and when the materials are delivered to the customer’s site or location and such materials have been accepted by the customer. Uninstalled materials are held in inventory and included in “Other current assets” on the Company’s Consolidated Balance Sheets until control is transferred to the customer. When the estimate on a contract indicates a loss, Barnwell records the entire estimated loss in the period the loss becomes known.
Unexpected significant inefficiencies that were not considered a risk at the time of entering into the contract, such as design or construction execution errors that result in significant wasted resources, are excluded from the measure of progress toward completion and the costs are expensed as incurred.
To the extent a contract is deemed to have multiple performance obligations, the Company allocates the transaction price of the contract to each performance obligation using its best estimate of the standalone selling price of each distinct good or service in the contract. The contract price may include variable consideration, which includes such items as increases to the transaction price for unapproved change orders and claims for which price has not yet been agreed by the customer. The Company estimates variable consideration using either the most likely amount or expected value method, whichever is a more appropriate reflection of the amount to which it expects to be entitled based on the characteristics and circumstances of the contract. Variable consideration is included in the estimated transaction price to the extent it is probable that a significant reversal of cumulative recognized revenue will not occur.
Contracts are sometimes modified for a change in scope or other requirements. The Company considers contract modifications to exist when the modification either creates new or changes the existing enforceable rights and obligations. Most of the Company’s contract modifications are for goods and services that are not distinct from the existing performance obligations. The effect of a contract modification on the transaction price, and the measure of progress for the performance obligation to which it relates, is recognized as an adjustment to revenue (either as an increase or decrease) on a cumulative catchup basis.
Judgments and Assumptions
Management evaluates the performance of contracts on an individual basis. In the ordinary course of business, but at least quarterly, we prepare updated estimates that may impact the cost and profit or loss for each contract based on actual results to date plus management’s best estimate of costs to be incurred to complete each performance obligation. Increases or decreases in the estimated costs to complete a performance obligation without a change to the contract price has the impact to decrease or increase, respectively, the contract completion percentage applied to the contract price to calculate the cumulative contract revenue to be recognized to date. Changes in the cost estimates can have a material impact on our contract revenue and are reflected in the results of operations when they become known. The nature of accounting for these contracts is such that refinements of the estimated costs to complete may occur and are characteristic of the estimation process due to changing conditions and new developments. Many factors and assumptions can and do change during a contract performance obligation period which can
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result in a change to contract profitability including unforeseen underground geological conditions (to the extent that contract remedies are unavailable), the availability and costs of skilled contract labor, the performance of major material suppliers, the performance of major subcontractors, unusual weather conditions and unexpected changes in material costs, changes in the scope and nature of work to be performed, and unexpected construction execution errors, among others. Any revisions to estimated costs to complete the performance obligation from period to period as a result of changes in these factors can materially affect revenue and operating results in the period such revisions are necessary. In addition, many contracts give the customer a unilateral right to cancel for convenience or other than for cause. In accordance with FASB ASC 606-10-32-4, our estimates are based on the assumption that the existing contract will not be cancelled. Any unforeseen cancellation of a contract may result in a material revision to our estimates.
We have a long history of working with multiple types of projects and preparing cost estimates, and we rely on the expertise of key personnel to prepare what we believe are reasonable best estimates given available facts and circumstances. Due to the nature of the work involved, however, judgment is involved to estimate the costs to complete and the amounts estimated could have a material impact on the revenue we recognize in each accounting period. We can not estimate unforeseen events and circumstances which may result in actual results being materially different from previous estimates.
Income Taxes
Policy Description
Income taxes are determined using the asset and liability method. Deferred tax assets and liabilities are recognized for the estimated future tax impacts of differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the year in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.
Deferred income tax assets are routinely assessed for realizability. A valuation allowance is provided when it is more likely than not that some portion or all of the deferred tax asset will not be realized.
Barnwell recognizes the financial statement effects of tax positions when it is more likely than not that the position will be sustained by a taxing authority.
Judgments and Assumptions
We make estimates and judgments in determining our income tax expense for each reporting period. Significant changes to these estimates could result in an increase or decrease in our tax provision in future periods. We are also required to make judgments about the recoverability of deferred tax assets and when it is more likely than not that all or a portion of deferred tax assets will not be realized, a valuation allowance is provided. We consider available positive and negative evidence and available tax planning strategies when assessing the realizability of deferred tax assets. Accordingly, changes in our business performance and unforeseen events could require a further increase in the valuation allowance or a reversal in the valuation allowance in future periods. This could result in a charge to, or an increase in, income in the period such determination is made, and the impact of these changes could be material.
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In addition, Barnwell operates within the U.S. and Canada and is subject to audit by taxing authorities in these jurisdictions. Barnwell records accruals for the estimated outcomes of these audits, and the accruals may change in the future due to new developments in each matter. Tax benefits are recognized when we determine that it is more likely than not that such benefits will be realized. Management evaluates its potential exposures from tax positions taken that have or could be challenged by taxing authorities. These potential exposures result because taxing authorities may take positions that differ from those taken by management in the interpretation and application of statutes, regulations and rules. Management considers the possibility of alternative outcomes based upon past experience, previous actions by taxing authorities (e.g., actions taken in other jurisdictions) and advice from tax experts. Where uncertainty exists due to the complexity of income tax statutes and where the potential tax amounts are significant, we generally seek independent tax opinions to support our positions. If our evaluation of the likelihood of the realization of benefits is inaccurate, we could incur additional income tax and interest expense that would adversely impact earnings, or we could receive tax benefits greater than anticipated which would positively impact earnings, either of which could be material.
Overview
Barnwell is engaged in the following lines of business: 1) acquiring, developing, producing and selling oil and natural gas in Canada and the U.S. (oil and natural gas segment), 2) leasehold land interests in Hawaii (land investment segment), and 3) drilling wells and installing and repairing water pumping systems in Hawaii (contract drilling segment).
Oil and Natural Gas Segment
Barnwell is involved in the acquisition and development of oil and natural gas properties primarily in the Twining area of Alberta, Canada, where we initiate and participate in acquisition and developmental operations for oil and natural gas on properties in which we have an interest, and evaluate proposals by third parties with regard to participation in such exploratory and developmental operations elsewhere. Additionally, through its wholly-owned subsidiaries BOK and Barnwell Texas, Barnwell is involved in non-operated oil and natural gas investments in Oklahoma and Texas, respectively.
Barnwell sells all of its Canadian and U.S. oil and natural gas under short-term contracts with marketers based on prices indexed to market prices. The price of natural gas, oil and natural gas liquids is freely negotiated between the buyers and sellers. Oil and natural gas prices are determined by many factors that are outside of our control. Market prices for oil and natural gas products are dependent upon factors such as, but not limited to, changes in market supply and demand, which are impacted by overall economic activity, changes in weather, pipeline capacity constraints, inventory storage levels, and output. Oil and natural gas prices are very difficult to predict and fluctuate significantly. Natural gas prices tend to be higher in the winter than in the summer due to increased demand, although this trend has become less pronounced due to the increased use of natural gas to generate electricity for air conditioning in the summer and increased natural gas storage capacity in North America.
Oil and natural gas exploration, development and operating costs generally follow trends in product market prices, thus in times of higher product prices the cost of exploring, developing and operating the oil and natural gas properties will tend to escalate as well. Capital expenditures are required to fund the exploration, development, and production of oil and natural gas. Cash outlays for capital expenditures are largely discretionary, however, a minimum level of capital expenditures is required to replace depleting reserves. Due to the nature of oil and natural gas exploration and development, significant uncertainty exists as to the ultimate success of any drilling effort.
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Land Investment Segment
Through Barnwell’s 77.6% interest in Kaupulehu Developments, 75% interest in KD Kona, and 34.45% non-controlling interest in KKM Makai, the Company’s land investment interests include the following:
•The right to receive percentage of sales payments from KD I resulting from the sale of single-family residential lots by KD I, within Increment I of the Kaupulehu Lot 4A area located in the North Kona District of the island of Hawaii. However, in the quarter ended March 31, 2024, the last two remaining single-family lots in Increment I were sold and there are no more lots available for sale in Increment I. Kaupulehu Developments was entitled to receive payments from KD I based on 10% of the gross receipts from KD I’s sales at Increment I. Increment I is an area zoned for approximately 80 single-family lots.
•The right to receive 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. Such interests are limited to distributions or net profits interests and Barnwell does not have any partnership interest in KD II or KDK through its interest in Kaupulehu Developments. Barnwell also has 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 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. The remaining acreage within Increment II is not yet under development, and there is no assurance that development of such acreage will in fact occur. No definitive development plans have been made by KD II, the developer of Increment II, as of the date of this report.
•An indirect 19.6% non-controlling ownership interest in KD Kukio Resorts, LLLP, KD Maniniowali, LLLP and KD I and an indirect 10.8% non-controlling ownership interest in KD II through KDK. These entities own certain real estate and development rights interests in the Kukio, Maniniowali and Kaupulehu portions of Kukio Resort, a private residential community on the Kona coast of the island of Hawaii, as well as Kukio Resort’s real estate sales office operations. KDK was the developer of Kaupulehu Lot 4A Increments I and II. The partnerships derive income from the sale of residential parcels in Increment I, which is now completely sold, as well as from commissions on real estate resales by the real estate sales office and revenues resulting from the sale of private club memberships, a few of which remain available for sale.
The Kukio Resort Land Development Partnerships have remaining Increment I obligations to complete project amenities, infrastructure, beautification, and restoration of certain areas and therefore has yet to fully recognize its deferred profit on the Increment I project as a whole. The Increment I deferred profit at September 30, 2024 for the Kukio Resort Land
40
Development Partnerships as a whole was approximately $4,500,000; the recognition of which is dependent upon the completion of the Increment I obligations. The Kukio Resort Land Development Partnerships have accrued estimated costs of these obligations of approximately $3,000,000. The Kukio Resort Land Development Partnerships currently appears to have the ability to fund those obligations but there are no assurances that it can ultimately do so in the future if unforeseen events occur. The Kukio Resort Land Development Partnerships will recognize the Increment I deferred revenue and costs of sales on a percentage completion basis as the cash outlays to complete the remaining project obligations are made. The Kukio Resort Land Development Partnerships’ deferred profit and accrued costs to complete are not reflected in Barnwell’s Condensed Consolidated Balance Sheets as we account for our investment in the Kukio Resort Land Development Partnerships under the equity method of accounting. No percentage of sales payments will be earned by Barnwell on any future recognition of Increment I deferred profit as such payments were already fully earned and received based on cash received by the Kukio Resort Land Development Partnerships as the Increment I lots were sold.
•Approximately 1,000 acres of vacant leasehold land zoned conservation in the Kaupulehu Lot 4C area, which currently has no development potential without both a development agreement with the lessor and zoning reclassification. The lease terminates in December 2025.
Contract Drilling Segment
Barnwell drills water and water monitoring wells and installs and repairs water pumping systems in Hawaii. Contract drilling results are highly dependent upon the quantity, dollar value and timing of contracts awarded by governmental and private entities and can fluctuate significantly.
Business Environment
Our operations are located in Canada and in the states of Hawaii, Oklahoma, and Texas. Accordingly, our business performance is directly affected by macroeconomic conditions in those areas, as well as general economic conditions of the U.S. domestic and world economies.
Oil and Natural Gas Segment
Barnwell realized an average price for oil of $66.49 per barrel during the year ended September 30, 2024, a decrease of 5% from $69.77 per barrel realized during the prior year and realized an average price for natural gas of $1.41 per Mcf during the year ended September 30, 2024, a decrease of 47% from $2.64 per Mcf realized during the prior year. Oil and natural gas prices continue to be volatile over time and thus, the Company is unable to reasonably predict future prices and the impacts future prices will have on the Company.
Land Investment Segment
Future revenues from the sale of interest in leasehold land and any future cash distributions from our investment in the Kukio Resort Land Development Partnerships are dependent upon the potential future development or sale of the remaining portion of Increment II by KD II of Kaupulehu Lot 4A. The amount and timing of future land investment segment proceeds from percentage of sales payments and cash distributions from the Kukio Resort Land Development Partnerships are highly uncertain and out of
41
our control, and there is no assurance with regards to the amounts of future payments from Increment II to be received or that the remaining acreage within Increment II will be developed. No definitive development plans have been made by KD II, the developer of Increment II, as of the date of this report.
Contract Drilling Segment
Demand for water well drilling and/or pump installation and repair services is volatile and dependent upon land development activities within the state of Hawaii.
Results of Operations
Summary
Net loss attributable to Barnwell for fiscal 2024 totaled $5,565,000, a $4,604,000 increase in net loss from a net loss of $961,000 in fiscal 2023. The following factors affected the results of operations for the current fiscal year as compared to the prior fiscal year:
•A $4,958,000 decrease in oil and natural gas segment operating results, before income taxes, primarily attributable to a $2,885,000 non-cash ceiling test impairment in the current year and due to decreases in natural gas, oil, and natural gas prices in the current year period as compared to the same period in the prior year;
•A $599,000 decrease in contract drilling segment operating results, before income taxes, primarily resulting from decreased activity and an increase in drilling difficulties and labor costs as compared to the same period in the prior year;
•A $551,000 gain recognized in the prior year period from the sale of a contract drilling segment drilling rig, whereas there was no such gain in the current year period; and
•Results improved as general and administrative expenses decreased $1,358,000 primarily due to decreases in stockholder costs and professional fees in the current year period as compared to the same period in the prior year.
General
Barnwell conducts operations in the U.S. and Canada. Consequently, Barnwell is subject to foreign currency translation and transaction gains and losses due to fluctuations of the exchange rates between the Canadian dollar and the U.S. dollar. Barnwell cannot accurately predict future fluctuations of the exchange rates and the impact of such fluctuations may be material from period to period. To date, we have not entered into foreign currency hedging transactions. Foreign currency gains or losses on intercompany loans and advances that are not considered long-term investments in nature because management intends to settle these intercompany balances in the future are included in our statements of operations.
The average exchange rate of the Canadian dollar to the U.S. dollar decreased 1% in fiscal 2024, as compared to fiscal 2023 and the exchange rate of the Canadian dollar to the U.S. dollar remained unchanged at September 30, 2024, as compared to September 30, 2023. Accordingly, the assets, liabilities, stockholders’ equity and revenues and expenses of Barnwell’s subsidiaries operating in Canada have been
42
adjusted to reflect the change in the exchange rates. Other comprehensive income and losses are not included in net earnings and net loss.
Other comprehensive loss due to foreign currency translation adjustments, net of taxes, for fiscal 2024 was nil, a $2,000 change from other comprehensive loss due to foreign currency translation adjustments, net of taxes, of $2,000 in fiscal 2023. There were no taxes on other comprehensive loss due to foreign currency translation adjustments in fiscal 2024 and 2023 due to a full valuation allowance on the related deferred tax assets.
Oil and natural gas
Selected Operating Statistics
The following tables set forth Barnwell’s annual average prices per unit of production and annual net production volumes for fiscal 2024 as compared to fiscal 2023. Production amounts reported are net of royalties.
Annual Average Price Per Unit
Increase (Decrease)
2024
2023
$
%
Natural gas (Mcf)*
$
1.41
$
2.64
$
(1.23)
(47)%
Oil (Bbls)
$
66.49
$
69.77
$
(3.28)
(5)%
Natural gas liquids (Bbls)
$
29.38
$
32.24
$
(2.86)
(9)%
Annual Net Production
Increase (Decrease)
2024
2023
Units
%
Natural gas (Mcf)
1,344,000
1,263,000
81,000
6%
Oil (Bbls)
203,000
204,000
(1,000)
—%
Natural gas liquids (Bbls)
64,000
52,000
12,000
23%
_________________________________________________
*Natural gas price per unit is net of pipeline charges.
The oil and natural gas segment generated a $285,000 operating loss in fiscal 2024 before general and administrative expenses, a decrease in operating results of $4,958,000 as compared to $4,673,000 of operating profit in fiscal 2023.
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The following table sets forth Barnwell’s oil and natural gas segment operating (loss) profit before general and administrative expenses by geographic location:
Year ended September 30,
2024
2023
Operating (loss) profit (before general and administrative expenses)
Canada (1)
$
(440,000)
$
3,171,000
United States (2)
155,000
1,502,000
Total operating (loss) profit
$
(285,000)
$
4,673,000
________________________
(1) The operating loss for Canada for the year ended September 30, 2024 includes a non-cash ceiling test impairment of $2,164,000.
(2) The operating profit for the United States for year ended September 30, 2024 includes a non-cash ceiling test impairment of $721,000.
Oil and natural gas revenues decreased $1,980,000 (10%) from $19,376,000 in fiscal 2023 to $17,396,000 in fiscal 2024, primarily due to significant decreases in natural gas, oil, and natural gas liquid prices, which decreased 47%, 5%, and 9%, respectively, as compared to the same period in the prior year. The decrease was partially offset by 6% and 23% increases in natural gas and natural gas liquid production, respectively, as compared to the same period in the prior year.
In the quarter ended December 31, 2023, the Company amended certain of its Canadian purchase and sales contracts to change the sales price on 1,055 gross Mcf per day of the Canadian natural gas that it sells during the period from April 1, 2024 to October 31, 2024 to a fixed index price before differentials of $2.55 Canadian dollars per Mcf, with remaining volumes continuing to be sold at spot prices. This per day volume of natural gas under fixed index price contract is equivalent to approximately 33% of Canadian natural gas gross production per day for the year ended September 30, 2024. In July 2024, the Company amended the sales price on 1,055 gross Mcf per day of the Canadian natural gas it will sell during the period from November 1, 2024 to March 31, 2025 to a fixed index price before differentials of $2.64 Canadian dollars per Mcf, with remaining volumes continuing to be sold at spot prices. This per day volume of natural gas under this fixed index price contract is equivalent to approximately 33% of Canadian natural gas gross production per day for the year ended September 30, 2024. These natural gas contracts were eligible for and elected as normal purchase and normal sales exception contracts and were thus excluded from derivative accounting.
In the quarter ended December 31, 2023, the Company amended certain of its Canadian purchase and sales contracts to change the sales price on 225 gross barrels per day of the Canadian oil for sale for the period from January 1, 2024 to June 30, 2024 to a fixed index price before differentials of $69.46 per net barrel, with remaining volumes continuing to be sold at spot prices. This per day volume of oil under this fixed index price contract was equivalent to approximately 35% of Canadian oil gross production per day for the year ended September 30, 2024. In July 2024, the Company amended the sales price on 100 gross barrels per day of the Canadian oil that it sells during the period from August 1, 2024 to December 31, 2024 to a fixed index price before differentials of $79.00 per net barrel, with remaining volumes continuing to be sold at spot prices. This per day volume of oil under this fixed index price contract is equivalent to approximately 16% of Canadian oil gross production per day for the year ended September 30, 2024. These oil contracts were eligible for and elected as normal purchase and normal sales exception contracts and were thus excluded from derivative accounting.
Oil and natural gas operating expenses decreased $585,000 (6%) from $10,434,000 in fiscal 2023 to $9,849,000 in fiscal 2024, primarily due to decreases in repairs, electricity and chemical costs in the current year period as compared to the same period in the prior year and due to optimization as a result of
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certain capital expenditures made earlier in the current year. The decrease in oil and natural gas operating expenses was partially offset by an increase in costs due to higher production and an increase in workovers and maintenance costs in the current year period as compared to the same period in the prior year.
Oil and natural gas segment depletion increased $678,000 (16%) from $4,269,000 in fiscal 2023 to $4,947,000 in fiscal 2024, primarily due to an increase in the depletion rate for Canadian properties and also increased production from those properties, both of which were the result of the wells drilled in fiscal 2023 and late fiscal 2024, and facilities expansion and upgrade costs, all in the Twining area. The increase in oil and natural gas segment depletion was also due to increased depletion from production in Texas, whereas there was only a minor amount of such depletion in the prior year period.
Sale of interest in leasehold land
Kaupulehu Developments was entitled to receive a percentage of the gross receipts from the sales of lots and/or residential units in Increment I by KD I.
The following table summarizes the revenues received from KD I and the amount of fees directly related to such revenues:
Year ended September 30,
2024
2023
Sale of interest in leasehold land:
Revenues - sale of interest in leasehold land
$
500,000
$
265,000
Fees - included in general and administrative expenses
(61,000)
(32,000)
Sale of interest in leasehold land, net of fees paid
$
439,000
$
233,000
During the year ended September 30, 2024, Barnwell received $500,000 in percentage of sales payments from KD I from the sale of the last two single-family lots within Increment I. During the year ended September 30, 2023, Barnwell received $265,000 in percentage of sales payments from KD I from the sale of one single-family lot within Increment I.
There is an Increment II owned by KD II in which the Company has a 10.8% indirect non-controlling ownership interest. There is no assurance with regards to the amounts of future sales from Increment II or that the remaining acreage within Increment II will be developed. No definitive development plans have been made by KD II, the developer of Increment II, as of the date of this report.
Contract drilling
Contract drilling revenues and costs are associated with well drilling and water pump installation, replacement and repair in Hawaii. Contract drilling revenues decreased $1,815,000 (33%) to $3,612,000 in fiscal 2024, as compared to $5,427,000 in fiscal 2023 and contract drilling costs decreased $1,186,000 (21%) to $4,483,000 in fiscal 2024, as compared to $5,669,000 in fiscal 2023. The contract drilling segment generated a $1,027,000 operating loss before general and administrative expenses during fiscal 2024, a decrease in operating results of $599,000 as compared to an operating loss before general and administrative expenses of $428,000 in fiscal 2023.
The decreases in contract drilling revenues and contract drilling costs for the current year period as compared to the same period in the prior year were primarily due to decreased activity and a decrease in
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revenues and costs recognized from materials deliveries and installations as compared to the same period in the prior year. Also, during the current year period, unforeseen drilling difficulties were encountered on a job where costs were spent to retrieve a portion of the drill string that twisted off and slower drilling was required to ensure plumbness of the hole. In addition, the Company commenced compensation adjustments for contract drilling segment personnel to decrease potential attrition of workers and enable the Company to complete its drilling obligations. These factors resulted in contract drilling expenses decreasing less than the decrease in contract drilling revenues.
On December 13, 2023, the Company entered into a stock purchase agreement with a construction company for the sale of Water Resources. On December 27, 2023, the stock purchase agreement was terminated by the buyer prior to closing.
In January 2024, a significant well drilling contract, which previously had an estimated contract drilling revenue backlog of $2,400,000 and which had not yet started, was cancelled by mutual agreement of Water Resources and the counterparty.
At September 30, 2024, there was a backlog of one well drilling and two pump installation and repair contracts and all of the contracts were in progress as of September 30, 2024. The backlog of contract drilling revenues as of December 1, 2024 was approximately $1,100,000, all of which is expected to be realized in fiscal 2025. Based on these contracts in backlog, contract drilling segment operating results for fiscal 2025 is estimated to be significantly less than fiscal 2024.
The Company continues to investigate strategies regarding Water Resources' future including, but not limited to, other potential opportunities for a sale of its stock or assets. If no sale of its stock or assets along with contract backlog can be secured, Water Resources will likely be wound down after all contracts in backlog are completed and any remaining drilling rigs and equipment will be liquidated. Management estimates that its three remaining contracts in backlog at September 30, 2024 will be completed in March 2025 or soon thereafter, however it is uncertain as to when the contingent liability related to the required drilling of a monitoring well in satisfaction of a regulatory assessment will be settled (see Note 17 in the “Notes to Consolidated Financial Statements” in Item 8 of this report).
General and administrative expenses
General and administrative expenses decreased $1,358,000 (20%) to $5,598,000 in fiscal 2024, as compared to $6,956,000 in fiscal 2023. The decrease was primarily due to decreases of $962,000 in professional fees primarily related to legal and consulting services and $533,000 in stockholders costs primarily attributed to the cooperation and support agreement and associated fees to certain directors in the prior year period as compared to the same period in the current year.
Depletion, depreciation, and amortization
Depletion, depreciation, and amortization increased $649,000 (15%) from $4,457,000 in fiscal 2023 to $5,106,000 in fiscal 2024, primarily due to increases in the depletion rate for Canadian properties and also new production from those properties and due to depletion attributable to production in Texas as discussed in the “Oil and natural gas” section above.
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Impairment of assets
Under the full cost method of accounting, the Company performs quarterly oil and natural gas ceiling test calculations. Changes in the 12-month rolling average first-day-of-the-month prices for oil, natural gas and natural gas liquids prices (except where prices are defined by contractual arrangements), the value of reserve additions as compared to the amount of capital expenditures to obtain them, and changes in production rates and estimated levels of reserves, future development costs and the market value of unproved properties, impact the determination of the maximum carrying value of oil and natural gas properties.
During the year ended September 30, 2024, the Company incurred a non-cash ceiling test impairment of $2,885,000, which included impairments for our U.S. and Canadian oil and natural gas properties of $721,000 and $2,164,000, respectively. The impairments to our U.S. and Canadian oil and natural gas properties were primarily due to a decline in the historical 12-month rolling average first-day-of-the-month prices. There was no ceiling test impairment during the year ended September 30, 2023.
As discussed above, the ceiling test uses a 12-month historical rolling average first-day-of-the-month prices. As such, declines in the 12-month historical rolling average first-day-of-the-month prices used in our ceiling test calculation in future periods could result in impairment write-downs in future periods in the absence of any offsetting factors that are not currently known or projected. Based on the oil and gas prices for October 1, November 1 and December 1 of 2024, the oil prices and natural gas prices used in the 12-month historical rolling first-day-of-the-month average oil price for the ceiling test at December 31, 2024 will be lower than at September 30, 2024. Whereas we believe our Canadian full cost pool is sufficiently below the ceiling limit, our U.S. full cost pool had no ceiling excess at September 30, 2024, and thus a further impairment charge is more likely than not for our U.S full cost pool for the first quarter of fiscal 2025 ending December 31, 2024. The Company is currently unable to estimate a range of the amount of any potential future impairment write-downs as variables that impact the ceiling limitation are dependent upon actual results of activity through the end of December 2024.
Foreign currency gain
Foreign currency gain was $10,000 and $76,000 during the years ended September 30, 2024 and 2023, respectively, due to the effects of foreign exchange rate changes on intercompany loans and advances as a result of changes in the U.S. dollar against the Canadian dollar. The foreign currency gains from intercompany balances are included in our consolidated statement of operations as the intercompany balances were not considered long-term in nature because management estimates that these intercompany balances will be settled in the future.
Gain on sale of assets
In October 2022, the Company completed the sale of a contract drilling segment drilling rig to an independent third party for proceeds of $551,000, net of related costs. The drilling rig was fully depreciated and had a net book value of zero and as a result of the sale, the Company recognized a $551,000 gain during the year ended September 30, 2023.
Equity in income of affiliates
Barnwell’s investment in the Kukio Resort Land Development Partnerships is accounted for using the equity method of accounting. Barnwell recognized equity in income of affiliates of $1,071,000 for the
47
year ended September 30, 2024, as compared to equity in income of affiliates of $758,000 for the year ended September 30, 2023. The increase in partnership income is primarily due to the Kukio Resort Land Development Partnerships' sale of the last two lots in Increment I during the current year period, as compared to one lot sale in the prior year period.
During the year ended September 30, 2024, Barnwell received cash distributions of $1,071,000 from the Kukio Resort Land Development Partnerships resulting in a net amount of $953,000, after distributing $118,000 to non-controlling interests. During the year ended September 30, 2023, Barnwell received cash distributions of $758,000 from the Kukio Resort Land Development Partnerships resulting in a net amount of $674,000, after distributing $84,000 to non-controlling interests.
In the quarter ended June 30, 2021, the Company received cumulative distributions from the Kukio Resort Land Development Partnerships in excess of our investment balance and in accordance with applicable accounting guidance, the Company suspended its equity method earnings recognition and the Kukio Resort Land Development Partnerships’ investment balance was reduced to zero with the distributions received in excess of our investment balance recorded as equity in income of affiliates because the distributions are not refundable by agreement or by law and the Company is not liable for the obligations of or otherwise committed to provide financial support to the Kukio Resort Land Development Partnerships. The Company will record future equity method earnings only after our share of the Kukio Resort Land Development Partnerships’ cumulative earnings in excess of distributions during the suspended period exceeds our share of the Kukio Resort Land Development Partnerships’ income recognized for the excess distributions, and during this suspended period any distributions received will be recorded as equity in income of affiliates. Accordingly, the amount of equity in income of affiliates recognized in the year ended September 30, 2024 was equivalent to the $1,071,000 of distributions received in that period.
Cumulative distributions received from the Kukio Resort Land Development Partnerships in excess of our investment balance was $373,000 at September 30, 2024 and $708,000 at September 30, 2023.
Income taxes
The components of loss before income taxes, after adjusting the loss for non-controlling interests, are as follows:
Year ended September 30,
2024
2023
United States
$
(2,820,000)
$
(2,414,000)
Canada
(2,532,000)
1,400,000
$
(5,352,000)
$
(1,014,000)
Barnwell’s effective consolidated income tax rate for fiscal 2024, after adjusting loss before income taxes for non-controlling interests, was (4)%, as compared to an effective consolidated income tax benefit rate of 5% for fiscal 2023.
Consolidated taxes do not bear a customary relationship to pretax results due primarily to the fact that the Company is taxed separately in Canada based on Canadian source operations and in the U.S. based on consolidated operations, and essentially all deferred tax assets, net of relevant offsetting deferred tax liabilities, are not estimated to have a future benefit as tax credits or deductions. The Company
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operates two subsidiaries in Canada, one of which is a U.S. corporation operating as a branch in Canada that is treated as a non-resident for Canadian tax purposes and thus has operating results that cannot be offset against or combined with the other Canadian subsidiary that files as a resident for Canadian tax purposes. Income from our non-controlling interest in the Kukio Resort Land Development Partnerships is treated as non-unitary for state of Hawaii unitary filing purposes, thus unitary Hawaii losses provide limited sheltering of such non-unitary income. Income from our investment in the Oklahoma oil venture is 100% allocable to Oklahoma. As such, Barnwell receives no benefit from consolidated or unitary losses and, therefore, is subject to Oklahoma state taxes. Consolidated taxes also include the impacts of favorable state jurisdiction provision to tax return true-ups. Our operations in Texas are subject to a franchise tax assessed by the state of Texas, however no significant amounts have been incurred to date.
Net earnings attributable to non-controlling interests
Earnings and losses attributable to non-controlling interests represent the non-controlling interests’ share of revenues and expenses related to the various partnerships and joint ventures in which Barnwell has controlling interests and consolidates.
Net earnings attributable to non-controlling interests totaled $234,000 in fiscal 2024, as compared to net earnings attributable to non-controlling interests of $150,000 in fiscal 2023. The $84,000 (56%) increase is primarily due to increases in the amount of equity in income of affiliates and percentage of sales revenue received in the current year period as compared to the same period in the prior year.
Inflation
The effect of inflation on Barnwell has generally been to increase its cost of operations, general and administrative costs and direct costs associated with oil and natural gas production and contract drilling operations. Oil and natural gas prices realized by Barnwell are essentially determined by world prices for oil and western Canadian/Midwestern U.S. prices for natural gas.
Impact of Recently Issued Accounting Standards on Future Filings
In November 2023, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2023-07 “Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures”, which expands reportable segment disclosure requirements on an annual and interim basis, primarily through enhanced disclosures about significant segment expenses. This ASU is effective for annual reporting periods beginning after December 15, 2023 and interim periods within fiscal years beginning after December 15, 2024, with early adoption permitted.The Company is currently evaluating the impact of this standard on Barnwell’s consolidated financial statements but does not expect that the adoption of this update will have a material impact on Barnwell's consolidated financial statements.
In December 2023, the FASB issued ASU No. 2023-09 “Income Taxes (Topic 740): Improvements to Income Tax Disclosures”, which requires disclosure of incremental income tax information within the tax rate reconciliation and expanded disclosures of income taxes paid both in the U.S. and foreign jurisdiction, among other disclosure requirements. This ASU is effective for annual reporting periods beginning after December 15, 2024, with early adoption permitted.The Company is currently evaluating the impact of this standard on Barnwell’s consolidated financial statements.
In November 2024, the FASB issued ASU No. 2024-03 “Income Statement - Reporting Comprehensive Income - Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of
49
Income Statement Expenses”, which requires public companies to disclose specified information about certain costs and expenses in the notes to the financial statements at interim and annual reporting periods. This ASU is effective for annual reporting periods beginning after December 15, 2026 and interim reporting periods beginning after December 15, 2027, with early adoption permitted. The Company is currently evaluating the impact of this standard on Barnwell’s consolidated financial statements.
Liquidity and Capital Resources
At September 30, 2024, Barnwell had $1,071,000 in working capital. Barnwell’s primary sources of liquidity are cash on hand and cash flow generated by our oil and natural gas operations, as cash flow from our land investment segment, if any, is expected to be minimal.
In recent years, the Company generated a significant amount of cash inflows from its land investment segment, however, the last lots at Increment I were sold in the quarter ended March 31, 2024 and there are no more lots available for sale in Increment I. In addition, no definitive development plans have been made by the developer of Increment II as of the date of this report and thus future cash inflows from the land investment segment are uncertain. Management estimates that cash flows from the sale of the contract drilling segment business or its operating assets may also provide some level of liquidity in the near-term. The Company will primarily be reliant upon sufficient operating cash inflows from its oil and natural gas segment, which in turn will be largely determined by prices and production levels. A certain level of oil and natural gas capital expenditures will be necessary to grow reserves and production or at a minimum replace declining production from aging wells. Such a level of oil and natural gas capital expenditures may require funding from external debt or equity sources that are not currently in place. Management estimates that, barring any significant unforeseen events, it is more likely than not that there is sufficient cash on hand, cash flows from contract drilling segment asset sales and cash flows from oil and natural gas segment operations to continue as a going concern for the twelve months from the filing of this report. However, the aforementioned factors will influence the Company’s liquidity beyond that twelve month period.
Cash Flows
Cash flows provided by operating activities totaled $4,710,000 for fiscal 2024, as compared to cash flows provided by operating activities of $1,943,000 for fiscal 2023. This $2,767,000 change in operating cash flows was due to fluctuations in working capital in the current year period as compared to the prior year period. The adjustment in operating cash flows due to the effect of changes in current assets and liabilities was an increase of $2,780,000 in the current year period as compared to a decrease of $393,000 in the prior year period. The change was also due to an increase in distributions of income from the Kukio Resort Land Development Partnerships and a decrease in general and administrative costs in the current year period as compared to the prior year period, partially offset by lower operating results for the oil and natural gas and contract drilling segments in the current year period as compared to the same period in the prior year.
Cash flows used in investing activities totaled $2,832,000 for fiscal 2024, as compared to cash flows used in investing activities of $11,180,000 for fiscal 2023. This $8,348,000 change in investing cash flows was primarily due to a decrease of $7,790,000 in cash paid for investments in oil and natural gas properties in the current year period as compared to the same period in the prior year and a $441,000 increase in proceeds from the sale of oil and natural gas properties in the current year period as compared to the prior year period.
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Cash flows used in financing activities totaled $226,000 for fiscal 2024, as compared to cash flows used in financing activities of $786,000 for fiscal 2023. The $560,000 change in financing cash flows was due to a decrease of $599,000 in payment of dividends, partially offset by an increase of $69,000 in distributions to non-controlling interests in the current year period as compared to the same period in the prior year.
Cash Dividends
No dividends were declared or paid during the year ended September 30, 2024. The following table sets forth the cash dividends paid per share of common stock during the year ended September 30, 2023.
Record Date
Date of Payment
Dividend Paid
August 24, 2023
September 11, 2023
$0.015
May 25, 2023
June 12, 2023
$0.015
February 23, 2023
March 13, 2023
$0.015
December 27, 2022
January 11, 2023
$0.015
Oil and Natural Gas Capital Expenditures
Barnwell’s oil and natural gas capital expenditures, including accrued capital expenditures and acquisitions of oil and natural gas properties and excluding additions and revisions to estimated asset retirement obligations, decreased $5,924,000 from $10,729,000 in fiscal 2023 to $4,805,000 in fiscal 2024.
During the year ended September 30, 2024, the Company participated in the drilling of one gross (1.0 net) operated development oil well in the Twining area. Capital expenditures incurred for the drilling of this well during the year ended September 30, 2024 totaled approximately $3,183,000.
In fiscal 2023, the Company participated in the drilling of three gross (0.9 net) non-operated wells in the Twining area of Alberta, Canada. Capital expenditures incurred for the drilling of these wells and Twining facilities during the year ended September 30, 2023 totaled approximately $4,770,000. Additionally, the Company participated in the drilling of two gross (0.3 net) non-operated development oil wells in Texas. Capital expenditures incurred for the drilling of these two wells totaled approximately $4,293,00 during the year ended September 30, 2023.
Oil and Natural Gas Property Dispositions
In the quarter ended June 30, 2024, Barnwell entered into and completed a purchase and sale agreement with an independent third party and sold its interests in certain natural gas and oil properties located in the Kaybob area of Alberta, Canada. The sales price per the agreement was adjusted for customary purchase price adjustments to $441,000 in order to, among other things, reflect an economic effective date of May 1, 2024. The final determination of the customary adjustments to the purchase price has not yet been made, however, it is not expected to result in a material adjustment.
In July 2024, Barnwell entered into and completed an agreement with an independent third party to convey interests in certain natural gas and oil properties located in the Bonanza and Balsam areas of Alberta, Canada. In consideration for the sale of the working interests in these properties, Barnwell retained a 4% overriding royalty on these properties and the buyer assumed the asset retirement
51
obligations associated with these properties. There were no cash proceeds from the sale and no gain or loss was recognized on this conveyance as this did not result in a significant alteration of the relationship between capitalized costs and proved reserves. With the disposition of the working interest, Barnwell reduced the full cost pool and abandonment liabilities associated with the working interests conveyed by approximately $153,000.
In September 2024, Barnwell entered into and completed a purchase and sale agreement with an independent third party and sold its interests in certain natural gas and oil properties located in the Wood River area of Alberta, Canada. The sales price per the agreement was adjusted for customary purchase price adjustments to $292,000 in order to, among other things, reflect an economic effective closing date of September 30, 2024. The final determination of the customary adjustments to the purchase price has not yet been made, however, it is not expected to result in a material adjustment. From the sales proceeds, $38,000 was remitted directly to the Canada Revenue Agency by the buyers for potential amounts due for Barnwell’s Canadian income taxes related to the sale. The proceeds from the sale was credited to our cash in October 2024 and will be reflected in the Statement of Cash Flows for the first quarter of fiscal 2025 ending December 31, 2024. No gain or loss was recognized on this disposition as the sale proceeds were credited to the full cost pool and did not result in a significant alteration of the relationship between capitalized costs and proved reserves.
Asset Retirement Obligation
In September 2019, the AER issued an abandonment/closure order for all wells and facilities in the Manyberries area which had been largely operated by LGX, an operating company that went into receivership in 2016. The estimated asset retirement obligation for the Company's interest in the wells and facilities in the Manyberries area is included in “Asset retirement obligation” in the Consolidated Balance Sheets.
After the abandonment/closure order was issued for Manyberries, the OWA created a WIP program for specific areas where there are a significant number of orphaned wells to abandon. The OWA has the ability and expertise to abandon wells using its internal resources and network of service providers resulting in efficiencies that companies such as Barnwell would not be able to obtain on its own. Under the WIP program, the Company would be required to provide payment for only Barnwell’s working interest share, however, all WIP’s would have to participate in the program for the OWA to begin its work. In March 2021, the Company was notified by the OWA that Barnwell’s Manyberries wells were confirmed to be in the WIP program.
Under the agreement with the OWA, the Company is required to pay the abandonment and reclamation costs in advance through a cash deposit. The total cash deposit amount was calculated to be approximately $1,525,000 and the Company paid $888,000 of the total deposit in July and August 2021 and may need to pay the remaining balance of $637,000 by August 2025. The Company revised its Manyberries ARO liability based on the OWA’s revised abandonment and reclamation estimates. Based on a review of the details of the cash deposit calculation provided by the OWA, which includes amounts added for possible contingencies, the Company believes the required cash deposit amount by the OWA is higher than the actual costs of the asset retirement obligation for the Manyberries wells and that any excess of the deposit over actual asset retirement costs for the first phase of the work would be credited toward the second phase of the work. A remaining excess deposit, if any, would ultimately be refunded to the Company upon completion of all of the work. As of September 30, 2024, the Company recognized a cumulative reduction in the deposit balance of $353,000 for work performed under this program.
52
Contractual Obligations
Disclosure is not required as Barnwell qualifies as a smaller reporting company.
Contingencies
For a detailed discussion of contingencies, see Note 17 in the “Notes to Consolidated Financial Statements” in Item 8 of this report.
ITEM 7A.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Disclosure is not required as Barnwell qualifies as a smaller reporting company.
53
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Report of Independent Registered Public Accounting Firm
To the Board of Stockholders and Board of Directors of
Barnwell Industries, Inc.
Opinion on the Consolidated Financial Statements
We have audited the accompanying consolidated balance sheets of Barnwell Industries, Inc. and subsidiaries (the Company) as of September 30, 2024 and 2023, and the related consolidated statements of operations, comprehensive loss, equity, and cash flows for each of the two years in the period ended September 30, 2024, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of September 30, 2024 and 2023, and the results of its operations and its cash flows for each of the two years in the period ended September 30, 2024, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the entity’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) ("PCAOB") and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters
54
does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
Estimation of proved reserves impacting the recognition and valuation of depletion expense and
impairment of oil and gas properties
Critical Accounting Matter Description
As described in Note 1 to the financial statements, the Company accounts for its oil and gas propertiesusing the full cost method of accounting which requires management to make estimates of provedreserve volumes and future revenues and expenses to calculate depletion expense and measure its oiland gas properties for potential impairment. To estimate the volume of proved reserves and futurerevenues, management makes significant estimates and assumptions, including forecasting theproduction decline rate of producing properties and forecasting the timing and volume of productionassociated with the Company’s development plan for proved undeveloped properties. In addition, theestimation of proved reserves is also impacted by management’s judgments and estimates regardingthe financial performance of wells associated with proved reserves to determine if wells are expected,with reasonable certainty, to be economical under the appropriate pricing assumptions required in theestimation of depletion expense and potential impairment measurements. We identified the estimationof proved reserves of oil and gas properties, due to its impact on depletion expense and impairmentevaluation, as a critical audit matter.
The principal consideration for our determination that the estimation of proved reserves is a critical audit matter is that changes in certain inputs and assumptions, which require a high degree of subjectivity necessary to estimate the volume and future revenues of the Company’s proved reserves could have a significant impact on the measurement of depletion expense or the impairment assessment. In turn, auditing those inputs and assumptions required subjective and complex auditor judgement.
How the Critical Audit Matter was Addressed in the Audit
We obtained an understanding of the design and implementation of management’s controls and our audit procedures related to the estimation of proved reserves included the following, among others.
•We evaluated the level of knowledge, skill, and ability of the Company’s reservoir engineering specialists and their relationship to the Company, made inquiries of those reservoir engineers regarding the process followed and judgments made to estimate the Company’s proved reserve volumes, and read the reserve report prepared by the Company’s specialists.
•To the extent key, sensitive inputs and assumptions used to determine proved reserve volumes and other cash flow inputs and assumptions are derived from Company’s accounting records, such as commodity pricing, historical pricing differentials, operating costs, and working and net revenue interests, we tested management’s process for determining the assumptions, including examining the underlying support, on a sample basis. Specifically, our audit procedures involved testing management’s assumptions, to the extent key, as follows:
◦Compared the estimated pricing differentials used in the reserve report to realized prices related to revenue transactions recorded in the current year and examined contractual support for the pricing differentials;
◦Evaluated the forecasted operating costs at year-end compared to historical operating costs;
◦Evaluated the working and net revenue interests used in the reserve report by inspecting a sample of ownership interests;
◦Evaluated the Company’s evidence supporting the amount of proved undeveloped properties reflected in the reserve report by examining support for the Company’s or the operator’s ability and intent to develop the proved undeveloped properties;
55
◦Applied analytical procedures to the reserve report by comparing to historical actual results and to the prior year reserve report.
Revenue recognition based on the percentage of completion method
Critical Accounting Matter Description
As described further in Note 1 to the financial statements, revenues derived from contract drilling contracts are recognized over time, as performance obligations are satisfied, due to the continuous transfer of control to the customer, using the percentage-of-completion method of accounting, based primarily on contract cost incurred to date compared to total estimated contract cost. Revenue recognition under this method is judgmental, particularly on lump-sum contracts, as it requires the Company to prepare estimates of total contract revenue and total contract costs, including costs to complete in-process contracts.
Auditing the Company’s estimates or total contract revenue and costs used to recognize revenue on contract drilling contracts involved significant auditor judgment, as it required the evaluation of subjective factors such as assumptions related to project schedule and completion, forecasted labor, and material and subcontract costs. These assumptions involved significant management judgment, which affects the measurement of revenue recognized by the Company.
How the Critical Audit Matter was Addressed in the Audit
We obtained an understanding of the design and implementation of management’s controls and our audit procedures related to the estimation of proved reserves included the following, among others.
•We obtained an understanding of the Company’s estimation process that affected revenue recognized on engineering and construction contracts. This included controls over management’s monitoring and review of project costs, including the Company’s procedures to validate the completeness and accuracy of data used to determine the estimates;
•We selected a sample of projects and, among other procedures, obtained and inspected the contract agreements, amendments and change orders to test the existence of customer arrangements and understand the scope of pricing of the related contracts;
•Evaluated the Company’s estimated revenue and costs to complete by obtaining and analyzing supporting documentation of management’s estimates of variable consideration and contract costs;
•Compared contract profitability estimates in the current year to historical estimates and actual performance.
/s/ WEAVER AND TIDWELL, L.L.P.
We have served as the Company’s auditor since 2020.
Little Falls, New Jersey
December 16, 2024
56
BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
September 30,
2024
2023
ASSETS
Current assets:
Cash and cash equivalents
$
4,505,000
$
2,830,000
Accounts and other receivables, net of allowance for credit losses of: $375,000 at September 30, 2024; $284,000 at September 30, 2023
2,770,000
3,246,000
Assets held for sale
69,000
—
Other current assets
1,539,000
3,009,000
Total current assets
8,883,000
9,085,000
Asset for retirement benefits
4,899,000
4,471,000
Operating lease right-of-use assets
39,000
54,000
Property and equipment:
Proved oil and natural gas properties, net (full cost method)
16,554,000
21,302,000
Drilling rigs and other property and equipment, net
294,000
509,000
Total property and equipment, net
16,848,000
21,811,000
Total assets
$
30,669,000
$
35,421,000
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable
$
1,822,000
$
881,000
Accrued capital expenditures
2,407,000
1,099,000
Accrued compensation
650,000
726,000
Accrued operating and other expenses
1,834,000
1,747,000
Current portion of asset retirement obligation
798,000
1,536,000
Other current liabilities
301,000
609,000
Total current liabilities
7,812,000
6,598,000
Operating lease liabilities
7,000
47,000
Liability for retirement benefits
1,898,000
1,664,000
Asset retirement obligation
7,790,000
8,297,000
Deferred income tax liabilities
100,000
58,000
Total liabilities
17,607,000
16,664,000
Commitments and contingencies (Note 17)
Equity:
Common stock, par value $0.50 per share; authorized, 40,000,000 shares:
10,195,990 issued at September 30, 2024; 10,158,678 issued at September 30, 2023
5,098,000
5,079,000
Additional paid-in capital
7,690,000
7,687,000
Retained earnings
595,000
6,160,000
Accumulated other comprehensive income, net
1,943,000
2,104,000
Treasury stock, at cost:
167,900 shares at September 30, 2024 and 2023
(2,286,000)
(2,286,000)
Total stockholders’ equity
13,040,000
18,744,000
Non-controlling interests
22,000
13,000
Total equity
13,062,000
18,757,000
Total liabilities and equity
$
30,669,000
$
35,421,000
See Notes to Consolidated Financial Statements
57
BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
Year ended September 30,
2024
2023
Revenues:
Oil and natural gas
$
17,396,000
$
19,376,000
Contract drilling
3,612,000
5,427,000
Sale of interest in leasehold land
500,000
265,000
Gas processing and other
216,000
201,000
21,724,000
25,269,000
Costs and expenses:
Oil and natural gas operating
9,849,000
10,434,000
Contract drilling operating
4,483,000
5,669,000
General and administrative
5,598,000
6,956,000
Depletion, depreciation, and amortization
5,106,000
4,457,000
Impairment of assets
2,885,000
—
Foreign currency gain
(10,000)
(76,000)
Interest expense
2,000
2,000
Gain on sale of assets
—
(551,000)
27,913,000
26,891,000
Loss before equity in income of affiliates and income taxes
(6,189,000)
(1,622,000)
Equity in income of affiliates
1,071,000
758,000
Loss before income taxes
(5,118,000)
(864,000)
Income tax provision (benefit)
213,000
(53,000)
Net loss
(5,331,000)
(811,000)
Less: Net earnings attributable to non-controlling interests
234,000
150,000
Net loss attributable to Barnwell Industries, Inc. stockholders
$
(5,565,000)
$
(961,000)
Basic net loss per common share
attributable to Barnwell Industries, Inc. stockholders
$
(0.56)
$
(0.10)
Diluted net loss per common share
attributable to Barnwell Industries, Inc. stockholders
$
(0.56)
$
(0.10)
Weighted-average number of common shares outstanding:
Basic
10,017,997
9,969,856
Diluted
10,017,997
9,969,856
See Notes to Consolidated Financial Statements
58
BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS
Year ended September 30,
2024
2023
Net loss
$
(5,331,000)
$
(811,000)
Other comprehensive (loss) income:
Foreign currency translation adjustments, net of taxes of $0
—
(2,000)
Retirement plans:
Amortization of accumulated other comprehensive gain into net periodic benefit cost, net of taxes of $0
(85,000)
(79,000)
Net actuarial (loss) gain arising during the period, net of taxes of $0
(76,000)
891,000
Total other comprehensive (loss) income
(161,000)
810,000
Total comprehensive loss
(5,492,000)
(1,000)
Less: Comprehensive income attributable to non-controlling interests
(234,000)
(150,000)
Comprehensive loss attributable to Barnwell Industries, Inc.
$
(5,726,000)
$
(151,000)
See Notes to Consolidated Financial Statements
59
BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF EQUITY
Years ended September 30, 2024 and 2023
Shares Outstanding
Common Stock
Additional Paid-In Capital
Retained Earnings
Accumulated Other Comprehensive Income
Treasury Stock
Non-controlling Interests
Total Equity
Balance at September 30, 2022
9,956,687
$
5,062,000
$
7,351,000
$
7,720,000
$
1,294,000
$
(2,286,000)
$
20,000
$
19,161,000
Net (loss) earnings
—
—
—
(961,000)
—
—
150,000
(811,000)
Foreign currency translation adjustments, net of taxes of $0
—
—
—
—
(2,000)
—
—
(2,000)
Distributions to non-controlling interests
—
—
—
—
—
—
(157,000)
(157,000)
Share-based compensation
—
—
263,000
—
—
—
—
263,000
Issuance of common stock for services
34,091
17,000
73,000
—
—
—
—
90,000
Dividends declared, $0.060 per share
—
—
—
(599,000)
—
—
—
(599,000)
Retirement plans:
Amortization of accumulated other comprehensive gain into net periodic benefit cost, net of taxes of $0
—
—
—
—
(79,000)
—
—
(79,000)
Net actuarial gain arising during the period, net of taxes of $0
—
—
—
—
891,000
—
—
891,000
Balance at September 30, 2023
9,990,778
5,079,000
7,687,000
6,160,000
2,104,000
(2,286,000)
13,000
18,757,000
Net (loss) earnings
—
—
—
(5,565,000)
—
—
234,000
(5,331,000)
Distributions to non-controlling interests
—
—
—
—
—
—
(226,000)
(226,000)
Acquisition of non-controlling interest
(186,000)
1,000
(185,000)
Share-based compensation
—
—
208,000
—
—
—
—
208,000
Issuance of common stock for restricted stock units vested
37,312
19,000
(19,000)
—
—
—
—
—
Retirement plans:
Amortization of accumulated other comprehensive gain into net periodic benefit cost, net of taxes of $0
—
—
—
—
(85,000)
—
—
(85,000)
Net actuarial loss arising during the period, net of taxes of $0
—
—
—
—
(76,000)
—
—
(76,000)
Balance at September 30, 2024
10,028,090
$
5,098,000
$
7,690,000
$
595,000
$
1,943,000
$
(2,286,000)
$
22,000
$
13,062,000
See Notes to Consolidated Financial Statements
60
BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year ended September 30,
2024
2023
Cash flows from operating activities:
Net loss
$
(5,331,000)
$
(811,000)
Adjustments to reconcile net loss to net cash provided by operating activities:
Equity in income of affiliates
(1,071,000)
(758,000)
Depletion, depreciation, and amortization
5,106,000
4,457,000
Impairment of assets
2,885,000
—
Gain on sale of assets
—
(551,000)
Sale of interest in leasehold land, net of fees paid
(439,000)
(233,000)
Distributions of income from equity investees
1,071,000
539,000
Retirement benefits income
(345,000)
(252,000)
Accretion of asset retirement obligation
900,000
808,000
Deferred income tax expense (benefit)
42,000
(130,000)
Asset retirement obligation payments
(1,139,000)
(1,005,000)
Share-based compensation expense
208,000
263,000
Common stock issued for services
—
90,000
Non-cash rent income
(28,000)
(25,000)
Retirement plan contributions and payments
(4,000)
(3,000)
Credit loss expense
85,000
38,000
Foreign currency gain
(10,000)
(76,000)
Gain on debt extinguishment
—
(15,000)
Increase (decrease) from changes in current assets and liabilities
2,780,000
(393,000)
Net cash provided by operating activities
4,710,000
1,943,000
Cash flows from investing activities:
Acquisition of non-controlling interest
(185,000)
—
Distributions from equity investees in excess of earnings
—
219,000
Proceeds from sale of interest in leasehold land, net of fees paid
439,000
233,000
Proceeds from the sale of oil and natural gas assets
441,000
—
Capital expenditures - oil and natural gas
(3,514,000)
(11,304,000)
Capital expenditures - all other
(13,000)
(328,000)
Net cash used in investing activities
(2,832,000)
(11,180,000)
Cash flows from financing activities:
Repayment of long-term debt
—
(30,000)
Distributions to non-controlling interests
(226,000)
(157,000)
Payment of dividends
—
(599,000)
Net cash used in financing activities
(226,000)
(786,000)
Effect of exchange rate changes on cash and cash equivalents
23,000
49,000
Net increase (decrease) in cash and cash equivalents
1,675,000
(9,974,000)
Cash and cash equivalents at beginning of year
2,830,000
12,804,000
Cash and cash equivalents at end of year
$
4,505,000
$
2,830,000
See Notes to Consolidated Financial Statements
61
BARNWELL INDUSTRIES, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED SEPTEMBER 30, 2024 AND 2023
1.SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Description of Business
Barnwell is engaged in the following lines of business: 1) acquiring, developing, producing and selling oil and natural gas in Canada and the U.S., 2) leasehold land interests in Hawaii, and 3) drilling wells and installing and repairing water pumping systems in Hawaii.
Principles of Consolidation
The consolidated financial statements include the accounts of Barnwell Industries, Inc. and all majority-owned subsidiaries (collectively referred to herein as “Barnwell,” “we,” “our,” “us,” or the “Company”), including a 77.6%-owned land investment general partnership (Kaupulehu Developments) and a 75%-owned land investment partnership (KD Kona). All significant intercompany accounts and transactions have been eliminated.
Undivided interests in oil and natural gas exploration and production joint ventures are consolidated on a proportionate basis. Barnwell’s investments in both unconsolidated entities in which a significant, but less than controlling, interest is held and in VIEs in which the Company is not deemed to be the primary beneficiary are accounted for by the equity method.
Use of Estimates in the Preparation of Consolidated Financial Statements
The preparation of the consolidated financial statements in conformity with U.S. GAAP requires management of Barnwell to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Actual results could differ significantly from those estimates. Significant assumptions are required in the valuation of deferred tax assets, asset retirement obligations, contract drilling estimated costs to complete, and proved oil and natural gas reserves, and such assumptions may impact the amount at which such items are recorded.
Revenue Recognition
Barnwell operates in and derives revenue from 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 and the U.S.
•Land Investment Segment - Barnwell owns land interests in Hawaii.
•Contract Drilling Segment - Barnwell provides well drilling services and water pumping system installation and repairs in Hawaii.
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Oil and Natural Gas - Barnwell’s investments in oil and natural gas properties are located in Alberta, Canada, Oklahoma, and Texas. These property interests are principally held under governmental leases or licenses. Barnwell sells the large majority of its oil, natural gas and natural gas liquids production under short-term contracts between itself and marketers based on prices indexed to market prices and recognizes revenue at a point in time when the oil, natural gas and natural gas liquids are delivered, as this is where Barnwell’s performance obligation is satisfied and title has passed to the customer.
Land Investment - Barnwell is entitled to receive contingent residual payments from the entities that previously purchased Barnwell’s land investment interests under contracts entered into in prior years. The residual payments under those contracts become due when the entities sell lots and/or residential units in the areas that were previously sold under the aforementioned contracts or when a preferred payment threshold is achieved. The residual payments received by Barnwell are recognized as revenue when it is probable that a significant reversal in the amount of cumulative revenue recognized will not occur.
Contract Drilling - Through contracts which are normally less than twelve months in duration, Barnwell drills water and water monitoring wells and installs and repairs water pumping systems in Hawaii. Barnwell recognizes revenue from well drilling or the installation of pumps over time based on total costs incurred on the projects relative to the total expected costs to satisfy the performance obligation as management believes this is an accurate representation of the percentage of completion as control is continuously transferred to the customer. Uninstalled materials, which typically consists of well casing or pumps, are excluded in the costs-to-costs calculation for the duration of the contract as including these costs would result in a distortion of progress towards satisfaction of the performance obligation due to the resulting cumulative catch-up in margin in a single period. An equal amount of cost and revenue is recorded when uninstalled materials are controlled by the customer, which is typically when Barnwell has the right to payment for the materials and when the materials are delivered to the customer’s site or location and such materials have been accepted by the customer. Uninstalled materials are held in inventory and included in “Other current assets” on the Company’s Consolidated Balance Sheets until control is transferred to the customer. When the estimate on a contract indicates a loss, Barnwell records the entire estimated loss in the period the loss becomes known.
The contract price may include variable consideration, which includes such items as increases to the transaction price for unapproved change orders and claims for which price has not yet been agreed by the customer. The Company estimates variable consideration using either the most likely amount or expected value method, whichever is a more appropriate reflection of the amount to which it expects to be entitled based on the characteristics and circumstances of the contract. Variable consideration is included in the estimated transaction price to the extent it is probable that a significant reversal of cumulative recognized revenue will not occur.
Contract price and cost estimates are reviewed periodically as work progresses and adjustments proportionate to the costs incurred to date to total estimated costs at completion are reflected in contract revenues in the reporting period when such estimates are revised. The nature of accounting for these contracts is such that refinements of the estimated costs to complete may occur and are characteristic of the estimation process due to changing conditions and new developments. Many factors and assumptions can and do change during a contract performance obligation period which can result in a change to contract profitability including unforeseen underground geological conditions (to the extent that contract remedies are unavailable), the availability and costs of skilled contract labor, the performance of major material suppliers, the performance of major subcontractors, unusual weather conditions and unexpected changes in material costs, changes in the scope and nature of the work to be performed, and unexpected construction execution errors, among others. These factors may result in revisions to costs and income and
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are recognized in the period in which the revisions become known. Revenue and profit in future periods of contract performance are recognized using the adjusted estimate.
Management evaluates the performance of contracts on an individual basis. In the ordinary course of business, but at least quarterly, we prepare updated estimates that may impact the cost and profit or loss for each contract based on actual results to date plus management's best estimate of costs to be incurred to complete each performance obligation. The cumulative effect of revisions in estimates of the total forecasted revenue and costs, including any unapproved change orders and claims, during the course of the contract is reflected in the accounting period in which the facts that caused the revision become known. Changes in the cost estimates can have a material impact on our consolidated financial statements and are reflected in the results of operations when they become known.
Unexpected significant inefficiencies that were not considered a risk at the time of entering into the contract, such as design or construction execution errors that result in significant wasted resources, are excluded from the measure of progress toward completion and the costs are expensed as incurred.
To the extent a contract is deemed to have multiple performance obligations, the Company allocates the transaction price of the contract to each performance obligation using its best estimate of the standalone selling price of each distinct good or service in the contract.
When the Company receives consideration, or such consideration is unconditionally due, from a customer prior to transferring goods or services to the customer under the terms of a sales contract, the Company records deferred revenue, which represents a contract liability. Such deferred revenue typically results from billings in excess of costs and estimated earnings on uncompleted contracts. Contract liabilities are included in “Other current liabilities” on the Company’s Consolidated Balance Sheets. Costs and estimated earnings in excess of billings represent certain amounts under customer contracts that were earned and billable, but yet not invoiced, and are included in contract assets and reported in “Other current assets” on the Company’s Consolidated Balance Sheets.
Cash and Cash Equivalents
Cash and cash equivalents include cash on hand and short-term investments with original maturities of three months or less.
Concentration of Credit Risk
Financial instruments that potentially subject the Company to concentrations of credit risk consist primarily of cash and cash equivalents. We maintain bank account balances with high quality financial institutions which often exceed insured limits. We have not experienced any losses with these accounts and believe that we are not exposed to any significant credit risk on cash.
Accounts and Other Receivables
Accounts receivable are recorded at the invoiced amount and do not bear interest. The allowance for credit losses is Barnwell’s best estimate of the amount of current expected credit losses in Barnwell’s existing accounts receivable and is based on the aging of the receivable balances, analysis of historical credit loss rates, and current and future economic conditions affecting collectability. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote. Barnwell does not have any off-balance sheet credit exposure related to its customers.
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Investments in Real Estate
Barnwell accounts for sales of Increment I and Increment II leasehold land interests under the full accrual method. Gains from such sales were recognized when the buyer’s investments were adequate to demonstrate a commitment to pay for the property, risks and rewards of ownership transferred to the buyer, and Barnwell did not have a substantial continuing involvement with the property sold. With regard to payments Kaupulehu Developments is entitled to receive from KD I and KD II, the percentage of sales payments from KD I and KD II and percentage of distributions from KD II are contingent future profits which will be recognized when they are realized. All costs of the sales of Increment I and Increment II leasehold land interests were recognized at the time of sale and were not deferred to future periods when any contingent profits will be recognized.
Variable Interest Entities
The consolidation of VIEs is required when an enterprise has a controlling financial interest and is therefore the VIE’s primary beneficiary. A controlling financial interest will have both of the following characteristics: (a) the power to direct the activities of a VIE that most significantly impact the VIE’s economic performance and (b) the obligation to absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE. The determination of whether an entity is a VIE and, if so, whether the Company is the primary beneficiary, may require significant judgment.
Barnwell analyzes its entities in which it has a variable interest to determine whether the entities are VIEs and, if so, whether the Company is the primary beneficiary. This analysis includes a qualitative review based on an evaluation of the design of the entity, its organizational structure, including decision making ability and financial agreements, as well as a quantitative review. Our unconsolidated affiliates that have been determined to be VIEs are accounted under the equity method because we do not have a controlling financial interest and are therefore not the VIE’s primary beneficiary (see Note 4).
Equity Method Investments
Affiliated companies, which are limited partnerships or similar entities, in which Barnwell holds more than a 3% to 5% ownership interest and does not control, are accounted for as equity method investments. Equity method investment adjustments include Barnwell’s proportionate share of investee income or loss, adjustments to recognize certain differences between Barnwell’s carrying value and Barnwell’s equity in net assets of the investee at the date of investment, impairments and other adjustments required by the equity method. Gains or losses are realized when such investments are sold. Barnwell classifies distributions received from equity method investments using the cumulative earnings approach in the Consolidated Statements of Cash Flows. Under the cumulative earnings approach, distributions received up to the amount of cumulative equity in earnings recognized are treated as returns on investment and are classified within operating cash flows and those in excess of that amount are treated as returns of investment and are classified within investing cash flows.
Investments in equity method investees are evaluated for impairment as events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If the carrying amounts of the assets exceed their respective fair values, additional impairment tests are performed to measure the amounts of the impairment losses, if any. When an impairment test demonstrates that the fair value of an investment is less than its carrying value, management will determine whether the impairment
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is either temporary or other-than-temporary. Examples of factors which may be indicative of an other-than-temporary impairment include (a) the length of time and extent to which fair value has been less than carrying value, (b) the financial condition and near-term prospects of the investee, and (c) the intent and ability to retain the investment in the investee for a period of time sufficient to allow for any anticipated recovery in fair value. If the decline in fair value is determined by management to be other-than-temporary, the carrying value of the investment is written down to its estimated fair value as of the balance sheet date of the reporting period in which the assessment is made.
Oil and Natural Gas Properties
Barnwell uses the full cost method of accounting under which all costs incurred in the acquisition, exploration and development of oil and natural gas reserves, including costs related to unsuccessful wells and estimated future site restoration and abandonment, are capitalized. We capitalize internal costs that can be directly identified with our acquisition, exploration and development activities and do not include any costs related to production, general corporate overhead or similar activities.
The capitalized costs of oil and gas properties, excluding unevaluated and unproved properties, are amortized as depreciation, depletion and amortization expense using the units-of-production method based on estimated proved recoverable oil and gas reserves.
Costs associated with unevaluated and unproved properties, initially excluded from the amortization base, relate to unproved leasehold acreage, wells and production facilities in progress and wells pending determination of the existence of proved reserves. Unproved leasehold costs are transferred to the amortization base with the costs of drilling the related well once a determination of the existence of proved reserves has been made or upon impairment of a lease. Costs associated with wells in progress and completed wells that have yet to be evaluated are transferred to the amortization base once a determination is made whether or not proved reserves can be assigned to the property. Costs of dry wells are transferred to the amortization base immediately upon determination that the well is unsuccessful.
All items classified as unevaluated and unproved properties are assessed on a quarterly basis for possible impairment or reduction in value. Properties are assessed on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of various factors, including, but not limited to, the following: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; assignment of proved reserves; and economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and become subject to amortization.
Under the full cost method of accounting, we review the carrying value of our oil and natural gas properties, on a country-by-country basis, each quarter in what is commonly referred to as the ceiling test. Under the ceiling test, capitalized costs, net of accumulated depletion and oil and natural gas related deferred income taxes, may not exceed an amount equal to the sum of 1) the discounted present value (at 10%), using average first-day-of-the-month prices during the 12-month period ending as of the balance sheet date held constant over the life of the reserves (except where prices are defined by contractual arrangements), of Barnwell’s estimated future net cash flows from estimated production of proved oil and natural gas reserves as determined by independent petroleum reserve engineers, less estimated future expenditures to be incurred in developing and producing the proved reserves but excluding future cash outflows associated with settling asset retirement obligations with the exception of those associated with proved undeveloped reserves from wells that are to be drilled in the future; plus 2) the cost of major
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development projects and unproven properties not subject to depletion, if any; plus 3) the lower of cost or estimated fair value of unproven properties included in costs subject to depletion; less 4) related income tax effects. If net capitalized costs exceed this limit, the excess is expensed. Depletion is computed using the units-of-production method whereby capitalized costs, net of estimated salvage values, plus estimated future costs to develop proved reserves and satisfy asset retirement obligations, are amortized over the total estimated proved reserves on a country-by-country basis. Investments in major development projects are not depleted until either proved reserves are associated with the projects or impairment has been determined. Proceeds from the disposition of oil and natural gas properties are credited to the full cost pool, with no gain or loss recognized, unless such a sale would significantly alter the relationship between capitalized costs and the proved reserves in a particular country.
Given the volatility of oil and gas prices, it is reasonably possible that the estimate of discounted future net cash flows from proved oil and gas reserves could change in the near term. If oil and gas prices decline in the future, even if only for a short period of time, it is possible that impairments of oil and gas properties could occur. In addition, it is reasonably possible that impairments could occur if costs are incurred in excess of any increases in the present value of future net cash flows from proved oil and gas reserves, or if properties are sold for proceeds less than the discounted present value of the related proved oil and gas reserves.
Barnwell’s sales reflect its working interest share after royalties. Barnwell’s production is generally delivered and sold at the plant gate. Barnwell does not have transportation volume commitments with pipelines and does not have natural gas imbalances related to natural gas balancing arrangements with its partners.
Acquisitions
In accordance with the guidance for business combinations, Barnwell determines whether an acquisition is a business combination, which requires that the assets acquired and liabilities assumed constitute a business. Each business combination is then accounted for by applying the acquisition method of accounting. If the assets acquired are not a business, the Company accounts for the transaction as an asset acquisition. Under both methods purchase prices are allocated to acquired assets and assumed liabilities based on their estimated fair value at the time of the acquisition. For transactions that are business combinations, the Company evaluates the existence of goodwill or a gain from a bargain purchase. The Company capitalizes acquisition-related costs and fees associated with asset acquisitions and immediately expenses acquisition-related costs and fees associated with business combinations.
Long-lived Assets
Long-lived assets to be held and used, other than oil and natural gas properties, are evaluated for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be fully recoverable. Recoverability is measured by comparing the carrying amount of the asset to the future net cash flows expected to result from use of the asset (undiscounted and without interest charges). If it is determined that the asset may not be recoverable, impairment loss is measured as the amount by which the carrying amount of the asset exceeds the fair value of the asset. Long-lived assets to be disposed of by sale are classified as held for sale and are reported at the lower of the asset carrying value or fair value, less cost to sell.
Water well drilling rigs, office and other property and equipment are depreciated using the straight-line method based on estimated useful lives.
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Share-based Compensation
Share-based compensation cost for Barnwell’s equity-classified stock options, restricted stock units, and common stock issued for services is measured at fair value and is recognized as an expense over the requisite service period. For stock options, Barnwell utilizes a closed-form valuation model to determine the fair value of each option award. Expected volatilities are based on the historical volatility of Barnwell’s stock over a period consistent with that of the expected terms of the options. The expected terms of the options represent expectations of future employee exercise and are estimated based on factors such as vesting periods, contractual expiration dates, historical trends in Barnwell’s stock price, and historical exercise behavior. If the Company does not have sufficient historical data regarding employee exercise behavior, the “simplified method” as permitted by the SEC’s Staff Accounting Bulletin No. 110, Share-Based Payment is utilized to estimate the expected terms of the options. The risk-free rates for periods within the contractual life of the options are based on the yields of U.S. Treasury instruments with terms comparable to the estimated option terms. Expected dividends are based on historical dividend payments. For restricted stock units, Barnwell utilizes the closing market price of the Company’s common stock on the grant date reduced by the present value of the dividends expected to be paid on the underlying shares of common stock during the requisite service period (as these awards are not entitled to receive dividends until vested) to determine the fair value of each restricted stock unit award. For common stock issued for services, Barnwell utilizes the closing market price of the Company’s common stock on the grant date to determine the fair value of the common stock issued for services. The Company's policy is to recognize forfeitures as they occur.
Retirement Plans
Barnwell accounts for its defined benefit pension plan and Supplemental Executive Retirement Plan by recognizing the over-funded or under-funded status as an asset or liability in its Consolidated Balance Sheets and recognizes changes in that funded status in the year in which the changes occur through comprehensive income. See further discussion at Note 9.
The estimation of Barnwell’s retirement plan obligations, costs and liabilities requires management to estimate the amount and timing of cash outflows for projected future payments and cash inflows for maturities and expected returns on plan assets. These assumptions may have an effect on the amount and timing of future contributions.
At the end of each year, Barnwell determines the discount rate to be used to calculate the present value of plan liabilities and the net periodic benefit cost. The discount rate is an estimate of the current interest rate at which the retirement plan liabilities could be effectively settled at the end of the year. In estimating this rate, Barnwell performs a cash-flow matching discount rate analysis developed using high-quality corporate bonds yield. The discount rate used to value the future benefit obligation as of each year-end is the rate used to determine the periodic benefit cost in the following year.
The expected long-term return on assets assumption for the pension plans represents the average rate of return to be earned on plan assets over the period the benefits included in the benefit obligation are to be paid. The actual fair value of plan assets and estimated rate of return is used to determine the expected investment return during the year. The estimated rate of return on plan assets is based on an estimate of future experience for plan asset returns, the mix of plan assets, current market conditions, and expectations for future market conditions. A decrease (increase) of 50 basis points in the expected return
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on assets assumption would increase (decrease) pension expense by approximately $64,000 based on the assets of the plan at September 30, 2024.
The effects of changing assumptions are included in unamortized net gains and losses, which directly affect accumulated other comprehensive income. These unamortized gains and losses in excess of certain thresholds are amortized and reclassified to (loss) income over the average remaining service life of active employees.
Asset Retirement Obligation
Barnwell accounts for asset retirement obligations by recognizing the fair value of a liability for an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made. Barnwell estimates the fair value of asset retirement obligations based on the projected discounted future cash outflows required to settle abandonment and restoration liabilities. Such an estimate requires assumptions and judgments regarding the existence of liabilities, the amount and timing of cash outflows required to settle the liability, what constitutes adequate restoration, inflation factors, credit adjusted discount rates, and consideration of changes in legal, regulatory, environmental and political environments. Abandonment and restoration cost estimates are determined in conjunction with Barnwell’s reserve engineers based on historical information regarding costs incurred to abandon and restore similar well sites, information regarding current market conditions and costs, and knowledge of subject well sites and properties. These assumptions represent Level 3 inputs.
Barnwell’s estimated site restoration and abandonment costs of its oil and natural gas properties are capitalized as part of the carrying amount of oil and natural gas properties and depleted over the life of the related reserves. When the assumptions used to estimate a recorded asset retirement obligation change, a revision is recorded to both the asset retirement obligation and the capitalized cost of asset retirements. The liability is accreted at the end of each period through charges to oil and natural gas operating expense.
Income Taxes
Income taxes are determined using the asset and liability method. Deferred tax assets and liabilities are recognized for the estimated future tax impacts of differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the year in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. A valuation allowance is provided when it is more likely than not that some portion or all of the deferred tax asset will not be realized.
Management evaluates its potential exposures from tax positions taken that have been or could be challenged by taxing authorities. These potential exposures result because taxing authorities may take positions that differ from those taken by management in the interpretation and application of statutes, regulations and rules. Management considers the possibility of alternative outcomes based upon past experience, previous actions by taxing authorities (e.g., actions taken in other jurisdictions) and advice from tax experts. Recognized tax positions are initially and subsequently measured as the largest amount of tax benefit that is more likely than not of being realized upon ultimate settlement with a taxing authority on a jurisdiction-by-jurisdiction basis. Liabilities for unrecognized tax benefits related to such tax positions are included in long-term liabilities unless the tax position is expected to be settled within the upcoming year, in which case the liabilities are included in current liabilities. Interest and penalties related to uncertain tax positions are included in income tax expense.
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Our operations in Texas are subject to a franchise tax assessed by the state of Texas which is presented as income tax expense.
Environmental
Barnwell is subject to extensive environmental laws and regulations. These laws, which are constantly changing, regulate the discharge of materials into the environment and maintenance of surface conditions and may require Barnwell to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefit are expensed. Liabilities for expenditures of a noncapital nature are recorded when environmental assessment and/or remediation is probable, and the costs can be reasonably estimated.
Barnwell recognizes an insurance receivable related to environmental expenditures when collection of the receivable is deemed probable. Any recognition of an insurance receivable is recorded by crediting and offsetting the original charge. Any differential arising between insurance recoveries and insurance receivables is expensed or capitalized, consistent with the original treatment.
Derivative Instruments
Barnwell may utilize physical forward commodity contracts to mitigate market price risk on its oil and natural gas output when deemed appropriate. Purchase and sale contracts with a fixed price determined at inception are recorded on the Consolidated Balance Sheets as derivative financial instruments if such contracts are readily convertible to cash - unless the contracts are eligible for and elected as the normal purchases and normal sales exception (“NPNS”); in which case, the contracts are recorded on an accrual basis and the Company recognizes the amounts relating to such transactions during the period when the commodities are physically delivered. The Company generally applies the NPNS exception to eligible oil and natural gas contracts to purchase or sell quantities it expects to use or sell in the normal course of business. The Company has not traded in any derivative contracts other than where the NPNS exception is applied, and it does not apply hedge accounting.
Foreign Currency Translations and Transactions
Assets and liabilities of foreign subsidiaries are translated at the year-end exchange rate. Operating results of foreign subsidiaries are translated at average exchange rates during the period. Translation adjustments have no effect on net income and are included in “Accumulated other comprehensive income, net” in the accompanying Consolidated Balance Sheets.
Foreign currency gains or losses on intercompany loans and advances that are not considered long-term investments in nature because management intends to settle these intercompany balances in the future are included in our statements of operations.
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Fair Value Measurements
Fair value is defined as the amount that would be received from the sale of an asset or paid for the transfer of a liability in an orderly transaction between market participants at the measurement date. Fair value measurements are classified and disclosed in one of the following categories:
•Level 1: Unadjusted quoted prices in active markets for identical assets and liabilities in active markets and have the highest priority.
•Level 2: Inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly.
•Level 3: Unobservable inputs for the financial asset or liability and have the lowest priority.
Recently Adopted Accounting Pronouncements
In June 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2016-13, “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments,” which replaces the incurred loss model with an expected loss model referred to as the current expected credit loss (“CECL”) model. The CECL model is applicable to the measurement of credit losses on financial assets measured at amortized cost, including but not limited to trade receivables. The FASB has subsequently issued other related ASUs which amend ASU 2016-13 to provide clarification and additional guidance. The Company adopted the provisions of this ASU effective October 1, 2023. The adoption of this update did not have an impact on Barnwell’s consolidated financial statements.
2.LOSS PER COMMON SHARE
Basic loss per share is computed using the weighted-average number of common shares outstanding for the period. Diluted loss per share is calculated using the treasury stock method to reflect the assumed issuance of common shares for all potentially dilutive securities, which consist of outstanding stock options and nonvested restricted stock units. Potentially dilutive shares are excluded from the computation of diluted loss per share if their effect is anti-dilutive.
Options to purchase 465,000 shares of common stock and 98,795 restricted stock units were excluded from the computation of diluted shares for the year ended September 30, 2024, as their inclusion would have been anti-dilutive. Options to purchase 546,781 shares of common stock and 18,605 restricted stock units were excluded from the computation of diluted shares for the year ended September 30, 2023, as their inclusion would have been anti-dilutive.
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Reconciliations between net loss attributable to Barnwell stockholders and common shares outstanding of the basic and diluted net loss per share computations are detailed in the following tables:
Year ended September 30, 2024
Net Loss
Shares
Per-Share
(Numerator)
(Denominator)
Amount
Basic
$
(5,565,000)
10,017,997
$
(0.56)
Effect of dilutive securities - common stock options and restricted stock units
—
—
Diluted
$
(5,565,000)
10,017,997
$
(0.56)
Year ended September 30, 2023
Net Loss
Shares
Per-Share
(Numerator)
(Denominator)
Amount
Basic
$
(961,000)
9,969,856
$
(0.10)
Effect of dilutive securities - common stock options and restricted stock units
—
—
Diluted
$
(961,000)
9,969,856
$
(0.10)
3.ALLOWANCE FOR CREDIT LOSSES
The following table summarizes the activity in the balance of allowance for credit losses related to accounts and other receivables:
Year ended September 30,
2024
2023
Allowance for credit losses as of beginning of year
$
284,000
$
231,000
Provision for expected losses
85,000
38,000
Write-offs charged against the allowance
(10,000)
(20,000)
Recoveries of amounts previously written off
16,000
34,000
Foreign currency translation adjustment
—
1,000
Allowance for credit losses as of end of year
$
375,000
$
284,000
4.INVESTMENTS
Investment in Kukio Resort Land Development Partnerships
On November 27, 2013, Barnwell, through a wholly-owned subsidiary, entered into two limited liability limited partnerships, KD Kona and KKM, and indirectly acquired a 19.6% non-controlling ownership interest in each of KD Kukio Resorts, KD Maniniowali, and KDK for $5,140,000. The Kukio Resort Land Development Partnerships own certain real estate and development rights interests in the Kukio, Maniniowali and Kaupulehu portions of Kukio Resort, a private residential community on the Kona coast of the island of Hawaii, as well as Kukio Resort’s real estate sales office operations. KDK holds interests in KD I and KD II. KD I is the developer of Increment I and KD II is the developer of Increment II. Barnwell's ownership interests in the Kukio Resort Land Development Partnerships is accounted for using the equity method of accounting.
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In March 2019, KD II admitted a new development partner, Replay, a party unrelated to Barnwell, in an effort to move forward with development of the remainder of Increment II at Kaupulehu. KDK and Replay hold ownership interests of 55% and 45%, respectively, of KD II and Barnwell has a 10.8% indirect non-controlling ownership interest in KD II through KDK, which is accounted for using the equity method of accounting. Barnwell continues to have an indirect 19.6% non-controlling ownership interest in KD Kukio Resorts, KD Maniniowali, and KD I.
The partnerships derive income from the sale of residential parcels in Increment I, which is now completely sold, as well as from commissions on real estate resales by the real estate sales office and revenues resulting from the sale of a few remaining private club memberships. In the quarter ended March 31, 2024, the last two remaining single-family lots of the 80 lots developed within Increment I were sold.
Increment II is not yet under development, and there is no assurance that development of such acreage will in fact occur. No definitive development plans have been made by KD II, the developer of Increment II, as of the date of this report.
Barnwell has the right to receive distributions from the Kukio Resort Land Development Partnerships via its non-controlling interests in KD Kona and KKM, based on its respective partnership sharing ratios of 75% and 34.45%, respectively. During the year ended September 30, 2024, Barnwell received cash distributions of $1,071,000 (resulting in a net amount of $953,000, after distributing $118,000 to non-controlling interests) from the Kukio Resort Land Development Partnerships. During the year ended September 30, 2023, Barnwell received cash distributions of $758,000 from the Kukio Resort Land Development Partnerships resulting in a net amount of $674,000, after distributing $84,000 to non-controlling interests.
Equity in income of affiliates was $1,071,000 for the year ended September 30, 2024, as compared to equity in income of affiliates of $758,000 for the year ended September 30, 2023.
Summarized financial information for the Kukio Resort Land Development Partnerships is as follows:
Year ended September 30,
2024
2023
Revenue
$
13,555,000
$
13,055,000
Gross profit
$
8,651,000
$
7,733,000
Net earnings
$
6,437,000
$
4,436,000
In the quarter ended June 30, 2021, the Company received cumulative distributions from the Kukio Resort Land Development Partnerships in excess of our investment balance and in accordance with applicable accounting guidance, the Company suspended its equity method earnings recognition and the Kukio Resort Land Development Partnerships’ investment balance was reduced to zero with the distributions received in excess of our investment balance recorded as equity in income of affiliates because the distributions are not refundable by agreement or by law and the Company is not liable for the obligations of or otherwise committed to provide financial support to the Kukio Resort Land Development Partnerships. The Company will record future equity method earnings only after our share of the Kukio Resort Land Development Partnerships’ cumulative earnings in excess of distributions during the suspended period exceeds our share of the Kukio Resort Land Development Partnerships’ income recognized for the excess distributions, and during this suspended period any distributions received will be recorded as equity in income of affiliates. Accordingly, the amount of equity in income of affiliates
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recognized in the year ended September 30, 2024 was equivalent to the $1,071,000 of distributions received in that period.
Cumulative distributions received from the Kukio Resort Land Development Partnerships in excess of our investment balance was $373,000 at September 30, 2024 and $708,000 at September 30, 2023.
Sale of Interest in Leasehold Land
Kaupulehu Developments holds rights to receive payments from KD I and KD II resulting from the sale of lots and/or residential units within Increment I, which is now fully sold, and within Increment II, which is not yet developed (see Note 19).
With respect to Increment I, Kaupulehu Developments was entitled to receive payments from KD I based on 10% of the gross receipts from KD I’s sales of single-family residential lots in Increment I. In the quarter ended March 31, 2024, the last two single-family lots of the 80 lots developed within Increment I were sold.
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 also obligated to pay an amount equal to 0.72% and 0.20% 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 following table summarizes the Increment I revenues from KD I and the amount of fees directly related to such revenues (see Note 17 “Commitments and Contingencies - Other Matters”):
Year ended September 30,
2024
2023
Sale of interest in leasehold land:
Revenues - sale of interest in leasehold land
$
500,000
$
265,000
Fees - included in general and administrative expenses
(61,000)
(32,000)
Sale of interest in leasehold land, net of fees paid
$
439,000
$
233,000
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There is no assurance with regards to the amounts of future payments from Increment II to be received or that the remaining acreage within Increment II will be developed. No definitive development plans have been made by KD II, the developer of Increment II, as of the date of this report.
Investment in Leasehold Land Interest – Lot 4C
Kaupulehu Developments holds an interest in an area of approximately 1,000 acres of vacant leasehold land zoned conservation located adjacent to Lot 4A, which currently has no development potential without both a development agreement with the lessor and zoning reclassification. The lease terminates in December 2025.
5. CONSOLIDATED VARIABLE INTEREST ENTITY
In February 2021, Barnwell Industries, Inc. established a wholly-owned subsidiary named BOK Drilling, LLC (“BOK”) for the purpose of indirectly investing in oil and natural gas exploration and development in Oklahoma. BOK and Gros Ventre Partners, LLC (“Gros Ventre”) entered into the Limited Liability Agreement (the “Teton Operating Agreement”) of Teton Barnwell Fund I, LLC (“Teton Barnwell”), an entity formed for the purpose of directly entering into such oil and natural gas investments. Under the terms of the Teton Operating Agreement, the profits of Teton Barnwell were split between BOK and Gros Ventre at 98% and 2%, respectively, and as the manager of Teton Barnwell, Gros Ventre was paid an annual asset management fee equal to 1% of the cumulative capital contributions made to Teton Barnwell as compensation for its management services. BOK was responsible for 100% of the capital contributions made to Teton Barnwell. Teton Barnwell was a variable interest entity for which the Company was deemed the primary beneficiary and thus, was consolidated by the Company.
In the quarter ended June 30, 2024, BOK acquired Gros Ventre’s 2% non-controlling interest in Teton Barnwell for $185,000 and following the acquisition, BOK now owns 100% interest in Teton Barnwell. As such, although Teton Barnwell is no longer a variable interest entity as of the acquisition date, it will continue to be consolidated by the Company. This transaction was accounted for as an equity transaction with no gain or loss recognized and the difference between the carrying amount of Gros Ventre’s non-controlling interest and the consideration given for the acquisition of the additional equity interest was recorded as a reduction in additional paid-in capital in the accompanying Consolidated Balance Sheets and Consolidated Statements of Equity.
6. ASSETS HELD FOR SALE
Contract Drilling Segment Property and Equipment
In the quarter ended March 31, 2024, the Company commenced the marketing of a portion of the contract drilling segment's property and equipment, the majority of which was already fully depreciated. There was no impairment related to the classification change from held and used to held for sale as the fair value, less estimated selling costs, of the disposal group exceeded its carrying value. The property and equipment deemed necessary to complete the contract drilling segment's contracts in backlog continue to be classified as held and used as of September 30, 2024. At September 30, 2024, a sale of the remainder of the contract drilling segment's property and equipment or the contract drilling segment as a whole was not estimated to be probable due to the lack of any definitive sale opportunities at that date.
75
7.OIL AND NATURAL GAS PROPERTIES
Oil and Natural Gas Property Dispositions
In the quarter ended June 30, 2024, Barnwell entered into and completed a purchase and sale agreement with an independent third party and sold its interests in certain oil and natural gas properties located in the Kaybob area of Alberta, Canada. The sales price per the agreement was adjusted for customary purchase price adjustments to $441,000 in order to, among other things, reflect an economic effective date of May 1, 2024. The final determination of the customary adjustments to the purchase price has not yet been made; however, it is not expected to result in a material adjustment. The proceeds were credited to the full cost pool, with no gain or loss recognized, as the sale did not result in a significant alteration of the relationship between capitalized costs and proved reserves.
In July 2024, Barnwell entered into and completed an agreement with an independent third party to convey interests in certain oil and natural gas properties located in the Bonanza and Balsam areas of Alberta, Canada. In consideration for the sale of the working interests in these properties, Barnwell retained a 4% overriding royalty on these properties and the buyer assumed the asset retirement obligations associated with these properties. There were no cash proceeds from the sale and no gain or loss was recognized on this conveyance as this did not result in a significant alteration of the relationship between capitalized costs and proved reserves. With the disposition of the working interest, Barnwell reduced the full cost pool and abandonment liabilities associated with the working interests conveyed by approximately $153,000.
In September 2024, Barnwell entered into and completed a purchase and sale agreement with an independent third party and sold its interests in certain oil and natural gas properties located in the Wood River area of Alberta, Canada. The sales price per the agreement was adjusted for customary purchase price adjustments to $292,000 in order to, among other things, reflect an economic effective closing date of September 30, 2024. The final determination of the customary adjustments to the purchase price has not yet been made, however, it is not expected to result in a material adjustment. From the sales proceeds, $38,000 was remitted directly to the Canada Revenue Agency by the buyers for potential amounts due for Barnwell’s Canadian income taxes related to the sale. The proceeds from the sale was credited to our cash in October 2024 and will be reflected in the Statement of Cash Flows for the first quarter of fiscal 2025 ending December 31, 2024. No gain or loss was recognized on this disposition as the sale proceeds were credited to the full cost pool and did not result in a significant alteration of the relationship between capitalized costs and proved reserves.
Investments and Acquisitions
In December 2022, Barnwell Texas, LLC (“Barnwell Texas”), a wholly-owned subsidiary of the Company, entered into a purchase and sale agreement with an independent third party whereby Barnwell Texas acquired a 22.3% non-operated working interest in oil and natural gas leasehold acreage in the Permian Basin in Texas for cash consideration of $806,000. Additionally, in connection with the purchase of such leasehold interests, Barnwell Texas acquired a 15.4% non-operated working interest in two oil wells in the Wolfcamp Formation in Loving and Ward Counties, Texas and paid $4,293,000 for its share of the costs to drill, complete and equip the wells during the year ended September 30, 2023.
76
Impairment of Oil and Natural Gas Properties
Under the full cost method of accounting, the Company performs quarterly oil and natural gas ceiling test calculations. Changes in the 12-month rolling average first-day-of-the-month prices for oil, natural gas and natural gas liquids prices (except where prices are defined by contractual arrangements), the value of reserve additions as compared to the amount of capital expenditures to obtain them, and changes in production rates and estimated levels of reserves, future development costs and the market value of unproved properties, impact the determination of the maximum carrying value of oil and natural gas properties.
During the year ended September 30, 2024, the Company incurred a non-cash ceiling test impairment of $2,885,000, which included impairments for our U.S. and Canadian oil and natural gas properties of $721,000 and $2,164,000, respectively. The impairment to our U.S. and Canadian oil and natural gas properties were primarily due to a decline in the historical 12-month rolling average first-day-of-the-month prices. There was no ceiling test impairment during the year ended September 30, 2023.
As discussed above, the ceiling test uses a 12-month historical rolling average first-day-of-the-month prices. As such, declines in the 12-month historical rolling average first-day-of-the-month prices used in our ceiling test calculation in future periods could result in impairment write-downs in future periods in the absence of any offsetting factors that are not currently known or projected. Based on the oil and gas prices for October 1, November 1 and December 1 of 2024, the oil prices and natural gas prices used in the 12-month historical rolling first-day-of-the-month average oil price for the ceiling test at December 31, 2024 will be lower than at September 30, 2024. Whereas we believe our Canadian full cost pool is sufficiently below the ceiling limit, our U.S. full cost pool had no ceiling excess at September 30, 2024, and thus a further impairment charge is more likely than not for our U.S full cost pool for the first quarter of fiscal 2025 ending December 31, 2024. The Company is currently unable to estimate a range of the amount of any potential future impairment write-downs as variables that impact the ceiling limitation are dependent upon actual results of activity through the end of December 2024.
77
8.PROPERTY AND EQUIPMENT AND ASSET RETIREMENT OBLIGATION
Barnwell’s property and equipment is detailed as follows:
Estimated Useful Lives
Gross Property and Equipment
Accumulated Depletion, Depreciation, Amortization, and Impairment
Net Property and Equipment
At September 30, 2024:
Proved oil and natural gas properties (full cost method)
$
83,557,000
$
(67,003,000)
$
16,554,000
Drilling rigs and equipment
3 – 10 years
3,103,000
(2,823,000)
280,000
Other property and equipment
3 – 10 years
576,000
(562,000)
14,000
Total
$
87,236,000
$
(70,388,000)
$
16,848,000
Estimated Useful Lives
Gross Property and Equipment
Accumulated Depletion, Depreciation, Amortization, and Impairment
Net Property and Equipment
At September 30, 2023:
Proved oil and natural gas properties (full cost method)
$
80,851,000
$
(59,549,000)
$
21,302,000
Drilling rigs and equipment
3 – 10 years
6,618,000
(6,127,000)
491,000
Other property and equipment
3 – 10 years
605,000
(587,000)
18,000
Total
$
88,074,000
$
(66,263,000)
$
21,811,000
See Note 7 for discussion of acquisitions and divestitures of oil and natural gas properties in fiscal 2024 and 2023.
78
Asset Retirement Obligation
Barnwell recognizes the fair value of a liability for an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made. The following is a reconciliation of the asset retirement obligation:
Year ended September 30,
2024
2023
Asset retirement obligation as of beginning of year
$
9,833,000
$
8,456,000
Obligations incurred on new wells drilled or acquired
37,000
21,000
Liabilities associated with properties sold
(442,000)
—
Revision of estimated obligation
(614,000)
1,462,000
Accretion expense
900,000
808,000
Payments
(1,139,000)
(1,005,000)
Foreign currency translation adjustment
13,000
91,000
Asset retirement obligation as of end of year
8,588,000
9,833,000
Less current portion
(798,000)
(1,536,000)
Asset retirement obligation, long-term
$
7,790,000
$
8,297,000
Asset retirement obligations were reduced by $442,000 and nil in fiscal 2024 and 2023, respectively, for those obligations that were assumed by purchasers of Barnwell's oil and natural gas properties (see Note 7 for additional details on dispositions). Asset retirement obligations were also reduced by $614,000 in fiscal 2024 as compared to an increase of $1,462,000 in fiscal 2023 primarily due to downward revisions related to deferrals in the estimated timing of future abandonments as a result of changes in the estimated economic lives of certain wells due to improved production performance of many wells in the Twining area as a result of focused attention and investment in optimization to improve well performance and reduce operating costs. Asset retirement obligations also increased by $37,000 and $21,000 in fiscal 2024 and 2023, respectively, due primarily to our wells drilled and acquisitions. The asset retirement obligation reflects the estimated present value of the amount of dismantlement, removal, site reclamation, and similar activities associated with Barnwell's oil and natural gas properties. Barnwell estimates the ultimate productive life of the properties, a credit-adjusted risk-free rate, and an inflation factor in order to determine the current present value of this obligation. The credit-adjusted risk-free rate for the entire asset retirement obligation is a blended rate which ranges from 6% to 13.5%.
In September 2019, the AER issued an abandonment/closure order for all wells and facilities in the Manyberries area which had been largely operated by LGX, an operating company that went into receivership in 2016. The estimated asset retirement obligation for the Company's interest in the wells and facilities in the Manyberries area is included in “Asset retirement obligation” in the Consolidated Balance Sheets.
After the abandonment/closure order was issued for Manyberries, the OWA created a 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.
79
Under the agreement with the OWA, the Company is required to pay the abandonment and reclamation costs in advance through a cash deposit. The total cash deposit amount was calculated to be approximately $1,525,000 and the Company paid $888,000 of the total deposit in July and August 2021 and may need to pay the remaining balance of $637,000 by August 2025. The Company revised its Manyberries ARO liability based on the OWA’s revised abandonment and reclamation estimates. Based on a review of the details of the cash deposit calculation provided by the OWA, which includes amounts added for possible contingencies, the Company believes the required cash deposit amount by the OWA is higher than the actual costs of the asset retirement obligation for the Manyberries wells and that any excess of the deposit over actual asset retirement costs for the first phase of the work would be credited toward the second phase of the work. A remaining excess deposit, if any, would ultimately be refunded to the Company upon completion of all of the work. As of September 30, 2024, the Company recognized a cumulative reduction in the deposit balance of $353,000 for work performed under this program.
9.RETIREMENT PLANS
Barnwell sponsors a noncontributory defined benefit pension plan (“Pension Plan”) covering substantially all of its U.S. employees, with benefits based on years of service and the employee’s highest consecutive 5 years average earnings. Barnwell’s funding policy is intended to provide for both benefits attributed to service to date and for those expected to be earned in the future. In addition, Barnwell sponsors a Supplemental Executive Retirement Plan (“SERP”), a noncontributory supplemental retirement benefit plan which covers certain current and former employees of Barnwell for amounts exceeding the limits allowed under the Pension Plan. Effective December 31, 2019, the accrual of benefits for all participants in the Pension Plan and SERP was frozen and the plans were closed to new participants from that point forward.
The following tables detail the changes in benefit obligations, fair values of plan assets and reconciliations of the funded status of the retirement plans:
Pension Plan
SERP
September 30,
2024
2023
2024
2023
Change in Projected Benefit Obligation:
Benefit obligation at beginning of year
$
7,511,000
$
7,931,000
$
1,734,000
$
1,715,000
Interest cost
411,000
406,000
95,000
88,000
Actuarial loss (gain)
520,000
(394,000)
149,000
(66,000)
Benefits paid
(247,000)
(432,000)
(4,000)
(3,000)
Benefit obligation at end of year
8,195,000
7,511,000
1,974,000
1,734,000
Change in Plan Assets:
Fair value of plan assets at beginning of year
11,982,000
11,316,000
—
—
Actual return on plan assets
1,359,000
1,098,000
—
—
Benefits paid
(247,000)
(432,000)
—
—
Fair value of plan assets at end of year
13,094,000
11,982,000
—
—
Funded status
$
4,899,000
$
4,471,000
$
(1,974,000)
$
(1,734,000)
80
Pension Plan
SERP
September 30,
2024
2023
2024
2023
Amounts recognized in the Consolidated Balance Sheets:
Noncurrent assets
$
4,899,000
$
4,471,000
$
—
$
—
Current liabilities
—
—
(76,000)
(70,000)
Noncurrent liabilities
—
—
(1,898,000)
(1,664,000)
Net amount
$
4,899,000
$
4,471,000
$
(1,974,000)
$
(1,734,000)
Amounts recognized in accumulated other comprehensive income before income taxes:
Net actuarial gain
$
(1,251,000)
$
(1,178,000)
$
(96,000)
$
(330,000)
Accumulated other comprehensive income
$
(1,251,000)
$
(1,178,000)
$
(96,000)
$
(330,000)
The accumulated benefit obligation for the Pension Plan was $8,195,000 and $7,511,000 at September 30, 2024 and 2023, respectively. The accumulated benefit obligation for the SERP was $1,974,000 and $1,734,000 at September 30, 2024 and 2023, respectively. The accumulated benefit obligations are the same as the projected benefit obligations due to the Pension Plan and SERP being frozen as of December 31, 2019.
Currently, no contributions are planned to be made to the Pension Plan during fiscal 2025. The SERP plan is unfunded and Barnwell funds benefits when payments are made. Expected payments under the SERP for fiscal 2025 are expected to be $76,000. Fluctuations in actual market returns as well as changes in general interest rates will result in changes in the market value of plan assets and may result in increased or decreased retirement benefits costs and contributions in future periods.
The Pension Plan actuarial losses in fiscal 2024 were primarily due to a decrease in the discount rate, partially offset by an actuarial gain resulting from actual investment returns that were greater than the assumed rate of return. The SERP actuarial losses in fiscal 2024 were primarily due to a decrease in the discount rate.
The Pension Plan actuarial gains in fiscal 2023 were primarily due to an increase in the discount rate and actual investment returns that were greater than the assumed rate of return. The SERP actuarial gains in fiscal 2023 were primarily due to an increase in the discount rate.
81
The following table presents the weighted-average assumptions used to determine benefit obligations and net benefit (income) costs:
Pension Plan
SERP
Year ended September 30,
2024
2023
2024
2023
Assumptions used to determine fiscal year-end benefit obligations:
Discount rate
4.88%
5.62%
4.88%
5.62%
Rate of compensation increase
N/A
N/A
N/A
N/A
Assumptions used to determine net benefit costs (years ended):
Discount rate
5.62%
5.25%
5.62%
5.25%
Expected return on plan assets
6.50%
6.00%
N/A
N/A
Rate of compensation increase
N/A
N/A
N/A
N/A
We select a discount rate by reference to yields from the Willis Towers Watson RATE:Link 10-90 yield curve at our consolidated balance sheet date. The expected return on plan assets is based on an actuarial model which takes into consideration our investment mix and market conditions.
The components of net periodic benefit (income) cost are as follows:
Pension Plan
SERP
Year ended September 30,
2024
2023
2024
2023
Net periodic benefit (income) cost for the year:
Interest cost
$
411,000
$
406,000
$
95,000
$
88,000
Expected return on plan assets
(766,000)
(667,000)
—
—
Amortization of net actuarial gain
—
—
(85,000)
(79,000)
Net periodic benefit (income) cost
$
(355,000)
$
(261,000)
$
10,000
$
9,000
The benefits expected to be paid under the retirement plans as of September 30, 2024 are as follows:
Pension Plan
SERP
Expected Benefit Payments:
Fiscal year ending September 30, 2025
$
396,000
$
76,000
Fiscal year ending September 30, 2026
$
562,000
$
152,000
Fiscal year ending September 30, 2027
$
555,000
$
150,000
Fiscal year ending September 30, 2028
$
593,000
$
155,000
Fiscal year ending September 30, 2029
$
630,000
$
160,000
Fiscal years ending September 30, 2030 through 2034
$
3,075,000
$
764,000
Plan Assets
The trustees of the Pension Plan communicate periodically with the Pension Plan’s professional investment advisors to establish investment policies, direct investments and select investment options. The overall investment objective of the Pension Plan is to attain a diversified combination of investments that provides long-term growth in the assets of the plan to fund future benefit obligations while managing risk
82
in order to meet current benefit obligations. Generally, interest and dividends received provide cash flows to fund current benefit obligations. Longer-term obligations are generally estimated to be provided for by growth in equity securities. The Pension Plan’s investment policy permits investments in a diversified mix of U.S. and international equities, fixed income securities, other investments, and cash equivalents.
The Pension Plan’s investments in fixed income securities include corporate bonds, U.S. treasury and government securities, preferred securities, and fixed income exchange-traded funds. The Pension Plan’s investments in equity securities primarily include domestic companies and is comprised of companies with market capitalization categorized as follows: 47% micro-cap; 20% small-cap; 15% mid-cap; and 18% large-cap. The Pension Plan’s other investment is a short-term note receivable from an unrelated private company.
The Company’s year-end target allocation, by asset category, and the actual asset allocations were as follows:
Target
September 30,
Asset Category
Allocation
2024
2023
Cash and cash equivalents
0% - 25%
4%
2%
Fixed income securities
15% - 40%
19%
32%
Equity securities
45% - 75%
73%
66%
Other investment
0% - 10%
4%
—%
Actual investment allocations may vary from our target allocations from time to time due to prevailing market conditions. We periodically review our actual investment allocations and rebalance our investments to our target allocations as dictated by current and anticipated market conditions and required cash flows.
We categorize plan assets into three levels based upon the assumptions used to price the assets. Level 1 provides the most reliable measure of fair value, whereas Level 3 requires significant management judgment in determining the fair value. Equity securities and exchange-traded funds are valued by obtaining quoted prices on recognized and highly liquid exchanges. Fixed income securities are valued based upon the closing price reported in the active market in which the security is traded. All of our plan assets, except for the note receivable from a private company, are categorized as Level 1 assets, and as such, the actual market value is used to determine the fair value of assets. The fair value of the note receivable from an unrelated private company is valued based upon the terms of the note receivable’s agreement and unobservable inputs such as management’s consideration of the counterparty’s credit risk and as such, is categorized as a Level 3 asset.
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The following tables set forth by level, within the fair value hierarchy, pension plan assets at their fair value:
Fair Value Measurements Using:
September 30, 2024
Carrying Amount
Quoted Prices in Active Markets (Level 1)
Significant Other Observable Inputs (Level 2)
Significant Unobservable Inputs (Level 3)
Financial Assets:
Cash
$
531,000
$
531,000
$
—
$
—
U.S. treasury and government securities
516,000
516,000
—
—
Fixed income exchange-traded funds
1,872,000
1,872,000
—
—
Preferred securities
88,000
88,000
—
—
Equities
9,516,000
9,516,000
—
—
Note receivable from an unrelated private company
571,000
—
—
571,000
Total
$
13,094,000
$
12,523,000
$
—
$
571,000
Fair Value Measurements Using:
September 30, 2023
Carrying Amount
Quoted Prices in Active Markets (Level 1)
Significant Other Observable Inputs (Level 2)
Significant Unobservable Inputs (Level 3)
Financial Assets:
Cash
$
263,000
$
263,000
$
—
$
—
U.S. treasury and government securities
709,000
709,000
—
—
Fixed income exchange-traded funds
3,102,000
3,102,000
—
—
Preferred securities
47,000
47,000
—
—
Equities
7,861,000
7,861,000
—
—
Total
$
11,982,000
$
11,982,000
$
—
$
—
The following sets forth a summary of changes in the fair value of the pension plan Level 3 asset:
Year ended September 30,
2024
2023
Balance at beginning of year
$
—
$
—
Issuance of note receivable from an unrelated private company
571,000
—
Balance at end of year
$
571,000
$
—
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10.INCOME TAXES
The components of loss before income taxes, after adjusting the loss for non-controlling interests, are as follows:
Year ended September 30,
2024
2023
United States
$
(2,820,000)
$
(2,414,000)
Canada
(2,532,000)
1,400,000
$
(5,352,000)
$
(1,014,000)
The components of the income tax provision (benefit) related to the above losses are as follows:
Year ended September 30,
2024
2023
Current provision:
United States – State
Before operating loss carryforwards
$
23,000
$
47,000
Benefit of operating loss carryforwards
—
—
After operating loss carryforwards
23,000
47,000
Canadian
Before operating loss carryforwards
148,000
274,000
Benefit of operating loss carryforwards
—
(244,000)
After operating loss carryforwards
148,000
30,000
Total current
171,000
77,000
Deferred provision (benefit):
United States – State
42,000
(130,000)
Total deferred
42,000
(130,000)
$
213,000
$
(53,000)
Consolidated taxes do not bear a customary relationship to pretax results due primarily to the fact that the Company is taxed separately in Canada based on Canadian source operations and in the U.S. based on consolidated operations, and essentially all deferred tax assets, net of relevant offsetting deferred tax liabilities, are not estimated to have a future benefit as tax credits or deductions. The Company operates two subsidiaries in Canada, one of which is a U.S. corporation operating as a branch in Canada that is treated as a non-resident for Canadian tax purposes and thus has operating results that cannot be offset against or combined with the other Canadian subsidiary that files as a resident for Canadian tax purposes. Income from our non-controlling interest in the Kukio Resort Land Development Partnerships is treated as non-unitary for state of Hawaii unitary filing purposes, thus unitary Hawaii losses provide limited sheltering of such non-unitary income. Income from our investment in the Oklahoma oil venture is 100% allocable to Oklahoma. As such, Barnwell receives no benefit from consolidated or unitary losses and, therefore, is subject to Oklahoma state taxes. Consolidated taxes also include the impacts of favorable state jurisdiction provision to tax return true-ups. Our operations in Texas are subject to a franchise tax assessed by the state of Texas, however no significant amounts have been incurred to date.
85
A reconciliation between the reported income tax expense (benefit) and the amount computed by multiplying the loss attributable to Barnwell before income taxes by the U.S. federal tax rate of 21% is as follows:
Year ended September 30,
2024
2023
Tax benefit computed by applying statutory rate
$
(1,124,000)
$
(213,000)
Increase in the valuation allowance
1,383,000
182,000
Additional effect of the foreign tax provision on the total tax provision
(129,000)
(4,000)
U.S. state income tax provision (benefit), net of federal effect
70,000
(9,000)
U.S. state provision to tax return adjustments
(12,000)
(106,000)
Other
25,000
97,000
$
213,000
$
(53,000)
The change in the valuation allowance shown in the table above excludes the impact of changes in the valuation allowance of items that are incorporated within the respective reconciliation line items elsewhere in the table.
86
The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities are as follows:
September 30,
2024
2023
Deferred income tax assets:
Foreign tax credit carryover under U.S. tax law
$
916,000
$
928,000
U.S. federal net operating loss carryover
10,382,000
9,406,000
U.S. state unitary net operating loss carryovers
1,334,000
1,177,000
Canadian net operating loss carryovers
1,331,000
1,025,000
Tax basis of investment in land in excess of book basis under U.S. tax law
11,000
25,000
Property and equipment accumulated book depreciation and depletion in excess of tax under U.S. tax law
548,000
275,000
Asset retirement obligation accrued for books but not for tax under U.S. tax law
907,000
1,084,000
Asset retirement obligation accrued for books but not for tax under Canadian tax law
2,141,000
2,461,000
Other liabilities accrued for books but not for tax under U.S. tax law
669,000
612,000
Foreign currency loss under U.S. tax law
68,000
68,000
Foreign currency loss under Canadian tax law
79,000
81,000
Other
168,000
116,000
Total gross deferred income tax assets
18,554,000
17,258,000
Less valuation allowance
(13,896,000)
(12,439,000)
Net deferred income tax assets
4,658,000
4,819,000
Deferred income tax liabilities:
Property and equipment accumulated tax depreciation and depletion in excess of book under Canadian tax law
(117,000)
(926,000)
Book basis of investment in land development partnerships in excess of tax basis under U.S. tax law
(282,000)
(133,000)
Book basis of investment in land development partnerships in excess of tax basis under U.S. state non-unitary tax law
(86,000)
(40,000)
U.S. oil and gas property and equipment accumulated tax depreciation and depletion in excess of book under U.S. tax law
(698,000)
(906,000)
U.S. oil and gas property and equipment accumulated tax depreciation and depletion in excess of book under U.S. state tax law
(16,000)
(19,000)
U.S. tax law impact of foreign branch deferred tax asset under Canadian tax law
(2,215,000)
(1,655,000)
Asset for retirement benefits
(1,029,000)
(939,000)
Other
(315,000)
(259,000)
Total deferred income tax liabilities
(4,758,000)
(4,877,000)
Net deferred income tax liability
$
(100,000)
$
(58,000)
Reported as:
Deferred income tax assets
$
—
$
—
Deferred income tax liabilities
(100,000)
(58,000)
Net deferred income tax liability
$
(100,000)
$
(58,000)
87
The total valuation allowance increased $1,457,000 for the year ended September 30, 2024. The increase was due to current fiscal year operational activity that resulted in changes in deferred tax asset and liability balances, and there were no changes in judgment about the realizability of related deferred tax assets in future years. Of the total net increase in the valuation allowance for fiscal 2024, $1,392,000 was recognized as an income tax expense and $65,000 was charged to accumulated other comprehensive income.
Net deferred tax assets at September 30, 2024 of $4,658,000 consists of the portion of deferred tax assets that are estimated to be partially realized through corresponding concurrent reversals of deferred tax liabilities related to the Kukio Resort Land Development Partnerships' excess of book income over taxable income, the book basis of property and equipment in excess of tax basis, foreign branch deferred taxes, asset for retirement benefits accrued for books but not for tax under U.S. tax law, and certain other minor deferred tax liabilities.
At September 30, 2024, Barnwell had U.S. federal foreign tax credit carryovers, U.S. federal net operating loss carryovers, U.S. state net operating loss carryovers and Canadian net operating loss carryovers totaling $916,000, $49,439,000, $20,848,000 and $4,958,000, respectively. The U.S. federal net operating loss carryovers generated through September 30, 2018 expire in fiscal years 2032-2038, the U.S. state unitary net operating loss carryovers generated through September 30, 2017 expire in fiscal years 2033-2037, the Canadian net operating loss carryovers expire in fiscal years 2039-2044, and the foreign tax credit carryover expires in fiscal year 2025. The U.S. federal net operating loss carryovers generated in fiscal years 2019-2024 and the U.S. state net operating loss carryovers generated in fiscal years 2018-2024 have no expiry, however utilization of the U.S. state and U.S. federal net operating loss carryovers generated in these and future years are limited to 80% of taxable income.
FASB ASC Topic 740, Income Taxes, prescribes a threshold for recognizing the financial statement effects of a tax position when it is more likely than not, based on the technical merits, that the position will be sustained upon examination by a taxing authority.
Barnwell files U.S. federal income tax returns, income tax returns in various U.S. states, and Canadian federal and provincial tax returns. A number of years may elapse before an uncertain tax position, for which we have unrecognized tax benefits, is audited and finally resolved. We believe that our unrecognized tax benefits are reflected on a more likely than not basis. We evaluate uncertain tax positions based on ongoing facts and circumstances. Any change in judgment related to the expected resolution of uncertain tax positions is recognized in earnings in the period in which such change occurs. Interest and penalties, if any, related to unrecognized tax benefits are recorded as a component of income tax expense. Settlement of any particular position could require the use of cash. Favorable or unfavorable resolution for an amount less than or greater than the amount estimated by Barnwell will result in a decrease or increase to income tax expense in the period of resolution.
88
There were no changes in unrecognized tax benefits during the years ended September 30, 2024 or 2023.
Year ended September 30,
2024
2023
Balance at beginning of year
$
62,000
$
62,000
Effect of tax positions taken in prior years
—
—
Accrued interest related to tax positions taken
—
—
Balance at end of year
$
62,000
$
62,000
Uncertain tax positions at September 30, 2024 are related to the potential assessment of penalties and interest for the failure to file a certain foreign information form with each of our U.S. federal income tax returns for fiscal years 2019, 2020 and 2021. The Company filed amended U.S. federal income tax returns which included the missing form and statement of reasonable cause for these years in September and October 2023 and requested abatement of any potential penalties and interest which could subsequently be assessed. The Company is awaiting a response from the IRS and the probability of success of the abatement request remains uncertain.
Included below is a summary of the tax years, by jurisdiction, that remain subject to examination by taxing authorities at September 30, 2024:
Jurisdiction
Fiscal Years Open
U.S. federal
2019 – 2023
Various U.S. states
2021 – 2023
Canada federal
2017 – 2023
Various Canadian provinces
2017 – 2023
89
11. REVENUE FROM CONTRACTS WITH CUSTOMERS
Disaggregation of Revenue
The following tables provide information about disaggregated revenue by revenue streams, reportable segments, geographical region, and timing of revenue recognition for the years ended September 30, 2024 and 2023.
Year ended September 30, 2024
Oil and natural gas
Contract drilling
Land investment
Other
Total
Revenue streams:
Oil
$
13,509,000
$
—
$
—
$
—
$
13,509,000
Natural gas
2,007,000
—
—
—
2,007,000
Natural gas liquids
1,880,000
—
—
—
1,880,000
Drilling and pump
—
3,612,000
—
—
3,612,000
Contingent residual payments
—
—
500,000
—
500,000
Other
—
—
—
128,000
128,000
Total revenues before interest income
$
17,396,000
$
3,612,000
$
500,000
$
128,000
$
21,636,000
Geographical regions:
United States
$
2,303,000
$
3,612,000
$
500,000
$
37,000
$
6,452,000
Canada
15,093,000
—
—
91,000
15,184,000
Total revenues before interest income
$
17,396,000
$
3,612,000
$
500,000
$
128,000
$
21,636,000
Timing of revenue recognition:
Goods transferred at a point in time
$
17,396,000
$
—
$
500,000
$
128,000
$
18,024,000
Services transferred over time
—
3,612,000
—
—
3,612,000
Total revenues before interest income
$
17,396,000
$
3,612,000
$
500,000
$
128,000
$
21,636,000
Year ended September 30, 2023
Oil and natural gas
Contract drilling
Land investment
Other
Total
Revenue streams:
Oil
$
14,259,000
$
—
$
—
$
—
$
14,259,000
Natural gas
3,441,000
—
—
—
3,441,000
Natural gas liquids
1,676,000
—
—
—
1,676,000
Drilling and pump
—
5,427,000
—
—
5,427,000
Contingent residual payments
—
—
265,000
—
265,000
Other
—
—
—
114,000
114,000
Total revenues before interest income
$
19,376,000
$
5,427,000
$
265,000
$
114,000
$
25,182,000
Geographical regions:
United States
$
2,746,000
$
5,427,000
$
265,000
$
10,000
$
8,448,000
Canada
16,630,000
—
—
104,000
16,734,000
Total revenues before interest income
$
19,376,000
$
5,427,000
$
265,000
$
114,000
$
25,182,000
Timing of revenue recognition:
Goods transferred at a point in time
$
19,376,000
$
—
$
265,000
$
114,000
$
19,755,000
Services transferred over time
—
5,427,000
—
—
5,427,000
Total revenues before interest income
$
19,376,000
$
5,427,000
$
265,000
$
114,000
$
25,182,000
90
Contract Balances
The following table provides information about accounts receivables, contract assets and contract liabilities from contracts with customers:
September 30,
2024
2023
2022
Accounts receivables from contracts with customers
$
2,031,000
$
2,931,000
$
4,038,000
Contract assets
267,000
958,000
580,000
Contract liabilities
—
377,000
1,087,000
Accounts receivables from contracts with customers are included in “Accounts and other receivables, net of allowance for credit losses,” in the accompanying Consolidated Balance Sheets and contract assets, which includes costs and estimated earnings in excess of billings and retainage, are included in “Other current assets” in the accompanying Consolidated Balance Sheets. Contract liabilities, which includes billings in excess of costs and estimated earnings are included in “Other current liabilities” in the accompanying Consolidated Balance Sheets.
Retainage, included in contract assets, represents amounts due from customers, but where payments are withheld contractually until certain construction milestones are met. Amounts retained typically range from 5% to 10% of the total invoice, up to contractually-specified maximums. The Company classifies as a current asset those retainages that are expected to be collected in the next twelve months.
Contract assets represent the Company’s rights to consideration in exchange for services transferred to a customer that have not been billed as of the reporting date. The Company’s rights are generally unconditional at the time its performance obligations are satisfied.
When the Company receives consideration, or such consideration is unconditionally due, from a customer prior to transferring goods or services to the customer under the terms of a sales contract, the Company records deferred revenue, which represents a contract liability. Such deferred revenue typically results from billings in excess of costs and estimated earnings on uncompleted contracts. As of September 30, 2024 and 2023, the Company had nil and $377,000, respectively, included in “Other current liabilities” on the Consolidated Balance Sheets for those performance obligations expected to be completed in the next twelve months.
During the years ended September 30, 2024 and 2023, the amount of revenue recognized that was previously included in contract liabilities as of the beginning of the respective period was $377,000 and $1,015,000, respectively.
Contracts are sometimes modified for a change in scope or other requirements. The Company considers contract modifications to exist when the modification either creates new or changes the existing enforceable rights and obligations. Most of the Company’s contract modifications are for goods and services that are not distinct from the existing performance obligations. The effect of a contract modification on the transaction price, and the measure of progress for the performance obligation to which it relates, is recognized as an adjustment to revenue (either as an increase or decrease) on a cumulative catchup basis.
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Performance Obligations
The Company’s remaining performance obligations for drilling and pump installation contracts (hereafter referred to as “backlog”) represent the unrecognized revenue value of the Company’s contract commitments. The Company’s backlog may vary significantly each reporting period based on the timing of major new contract commitments. In addition, our customers have the right, under some infrequent circumstances, to terminate contracts or defer the timing of the Company’s services and their payments to us. Nearly all of the Company's contract drilling segment contracts have original expected durations of one year or less. At September 30, 2024, the remaining performance obligation for contract drilling jobs with original expected durations greater than one year was not material.
Contract Fulfillment Costs
Preconstruction costs, which include costs such as set-up and mobilization, are capitalized and allocated across all performance obligations and deferred and amortized over the contract term on a progress towards completion basis. As of September 30, 2024 and 2023, the Company had $173,000 and $504,000, respectively, in unamortized preconstruction costs related to contracts that were not completed. During the years ended September 30, 2024 and 2023, the amortization of preconstruction costs related to contracts was $306,000 and $326,000, respectively. These amounts have been included in “Contract drilling operating” costs and expenses in the accompanying Consolidated Statements of Operations. Additionally, no impairment charges in connection with the Company’s preconstruction costs were recorded during the years ended September 30, 2024 and 2023.
Uninstalled Materials
Uninstalled materials, which typically consists of well casing or pumps, are excluded in the costs-to-costs calculation for the duration of the contract as including these costs would result in a distortion of progress towards satisfaction of the performance obligation due to the resulting cumulative catch-up in margin in a single period. An equal amount of cost and revenue is recorded when uninstalled materials are controlled by the customer, which is typically when Barnwell has the right to payment for the materials and when the materials are delivered to the customer’s site or location and such materials have been accepted by the customer. As of of September 30, 2024 and 2023, uninstalled materials was $65,000 and $348,000, respectively. Uninstalled materials are held in inventory and included in “Other current assets” on the Company’s Consolidated Balance Sheets.
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12.SEGMENT AND GEOGRAPHIC INFORMATION
Barnwell operates the following segments: 1) acquiring, developing, producing and selling oil and natural gas in Canada and the U.S. (oil and natural gas); 2) leasehold land interests in Hawaii (land investment); and 3) drilling wells and installing and repairing water pumping systems in Hawaii (contract drilling).
The following table presents certain financial information related to Barnwell’s reporting segments. All revenues reported are from external customers with no intersegment sales or transfers.
Year ended September 30,
2024
2023
Revenues:
Oil and natural gas
$
17,396,000
$
19,376,000
Contract drilling
3,612,000
5,427,000
Land investment
500,000
265,000
Other
128,000
114,000
Total before interest income
21,636,000
25,182,000
Interest income
88,000
87,000
Total revenues
$
21,724,000
$
25,269,000
Depletion, depreciation, and amortization:
Oil and natural gas
$
4,947,000
$
4,269,000
Contract drilling
156,000
186,000
Other
3,000
2,000
Total depletion, depreciation, and amortization
$
5,106,000
$
4,457,000
Impairment:
Oil and natural gas
$
2,885,000
$
—
Total impairment
$
2,885,000
$
—
Operating (loss) profit (before general and administrative expenses):
Oil and natural gas
$
(285,000)
$
4,673,000
Contract drilling
(1,027,000)
(428,000)
Land investment
500,000
265,000
Other
125,000
112,000
Gain on sale of assets
—
551,000
Total operating (loss) profit
(687,000)
5,173,000
Equity in income of affiliates:
Land investment
1,071,000
758,000
General and administrative expenses
(5,598,000)
(6,956,000)
Foreign currency gain
10,000
76,000
Interest expense
(2,000)
(2,000)
Interest income
88,000
87,000
Loss before income taxes
$
(5,118,000)
$
(864,000)
93
Capital Expenditures:
Year ended September 30,
2024
2023
Oil and natural gas
$
4,228,000
$
12,212,000
Contract drilling
12,000
314,000
Other
1,000
14,000
Total
$
4,241,000
$
12,540,000
Oil and natural gas capital expenditures include acquisitions as well as changes to capitalized asset retirement obligations, including revisions of asset retirement obligations (see Note 8 for additional details).
Assets By Segment:
September 30,
2024
2023
Oil and natural gas:
Canada
$
15,218,000
$
18,855,000
United States
4,190,000
5,917,000
Contract drilling (1)
1,597,000
3,100,000
Other:
Cash and cash equivalents
4,505,000
2,830,000
Asset for retirement benefits
4,899,000
4,471,000
Corporate and other
260,000
248,000
Total
$
30,669,000
$
35,421,000
______________
(1) Located in Hawaii.
Long-Lived Assets By Geographic Area:
September 30,
2024
2023
United States
$
9,214,000
$
10,373,000
Canada
12,572,000
15,963,000
Total
$
21,786,000
$
26,336,000
Revenue By Geographic Area:
Year ended September 30,
2024
2023
United States
$
6,452,000
$
8,448,000
Canada
15,184,000
16,734,000
Total (before interest income)
$
21,636,000
$
25,182,000
94
13.ACCUMULATED OTHER COMPREHENSIVE INCOME
Components of accumulated other comprehensive income, net of taxes, are as follows:
Change in cumulative translation adjustment before reclassifications
—
(2,000)
Income taxes
—
—
Net current period other comprehensive loss
—
(2,000)
Ending accumulated foreign currency translation
220,000
220,000
Retirement plans:
Beginning accumulated retirement plans benefit income
1,884,000
1,072,000
Amortization of net actuarial gain
(85,000)
(79,000)
Net actuarial (loss) gain arising during the period
(76,000)
891,000
Income taxes
—
—
Net current period other comprehensive (loss) income
(161,000)
812,000
Ending accumulated retirement plans benefit income
1,723,000
1,884,000
Accumulated other comprehensive income, net of taxes
$
1,943,000
$
2,104,000
The amortization of net actuarial gain for the retirement plans are included in the computation of net periodic benefit (income) cost which is a component of “General and administrative” expenses on the accompanying Consolidated Statements of Operations (see Note 9 for additional details).
14.FAIR VALUE MEASUREMENTS
Fair Value of Financial Instruments
The carrying values of cash and cash equivalents, accounts and other receivables, accounts payable and accrued current liabilities approximate their fair values due to the short-term nature of the instruments.
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
The estimated fair values of oil and natural gas properties and the asset retirement obligation incurred in the drilling of oil and natural gas wells or assumed in the acquisitions of additional oil and natural gas working interests are based on an estimated discounted cash flow model and market assumptions. The assumptions used in the calculation of estimated discounted cash flows were primarily Level 3 assumptions; assumptions included future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development, operating and asset retirement costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates. See Note 7 for additional information regarding oil and natural gas property acquisitions.
Barnwell estimates the fair value of asset retirement obligations based on the projected discounted future cash outflows required to settle abandonment and restoration liabilities. Such an estimate requires assumptions and judgments regarding the existence of liabilities, the amount and timing of cash outflows required to settle the liability, what constitutes adequate restoration, inflation factors, credit adjusted discount rates, and consideration of changes in legal, regulatory, environmental and political
95
environments. Abandonment and restoration cost estimates are determined in conjunction with Barnwell’s reserve engineers based on historical information regarding costs incurred to abandon and restore similar well sites, information regarding current market conditions and costs, and knowledge of subject well sites and properties. Asset retirement obligation fair value measurements in the current period were Level 3 fair value measurements. As further described in Note 8, the Company recognizes the fair value of a liability for an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made. Asset retirement obligations are not measured at fair value subsequent to initial recognition.
15. LEASES
The Company’s right-of-use (“ROU”) assets and lease liabilities at September 30, 2024, primarily relate to non-cancelable operating leases for our Hawaii corporate and Canadian office spaces and our leasehold land interest for Lot 4C held by Kaupulehu Developments. Management determines if a contract is or contains a lease at inception of the contract or modification of the contract. A contract is or contains a lease if the contract conveys the right to control the use of the asset for a period in exchange for consideration.
Operating lease ROU assets and liabilities are recognized based on the present value of future minimum lease payments over the expected lease term at commencement date. The Company’s leases do not provide a readily determinable implicit rate; therefore, management uses the Company’s incremental borrowing rate to discount lease payments based on information available at lease commencement. Our lease terms may include options to extend or terminate the lease when it is reasonably certain we will exercise that option. Lease expense for minimum lease payments is recognized on a straight-line basis over the expected lease terms. The Company has lease agreements with lease and non-lease components and the non-lease components are excluded in the calculation of the ROU asset and lease liability and expensed as incurred. None of the Company’s lease agreements contain material residual value guarantees or material restrictions or covenants.
A ROU asset and corresponding lease liability is not recorded for leases with an initial term of 12 months or less (short-term leases) as the Company recognizes lease expense for these leases as incurred over the lease term.
Leases recorded on the balance sheet consist of the following:
September 30,
2024
2023
Assets:
Operating lease right-of-use assets
$
39,000
$
54,000
Total right-of-use assets
$
39,000
$
54,000
Liabilities:
Current portion of operating lease liabilities (1)
$
68,000
$
71,000
Operating lease liabilities
7,000
47,000
Total lease liabilities
$
75,000
$
118,000
______________
(1) Amount included in “Other Current Liabilities” in the Consolidated Balance Sheets.
96
The components of lease expense are as follows:
Year ended September 30,
2024
2023
Operating lease cost
$
87,000
$
88,000
Short-term lease cost
358,000
347,000
Variable lease cost
142,000
136,000
Total lease cost
$
587,000
$
571,000
Supplemental information related to leases is as follows:
September 30,
2024
2023
Cash paid related to operating lease liabilities
$
114,000
$
114,000
Operating leases:
Weighted-average remaining lease term (in years)
0.9
1.7
Weighted-average discount rate
6.99%
5.53%
The remaining lease payments for our operating leases as of September 30, 2024, are as follows:
Fiscal year ending:
2025
$
70,000
2026
7,000
2027
—
2028
—
2029
—
Thereafter
—
Total lease payments
77,000
Less: amounts representing interest
(2,000)
Present value of lease liabilities
$
75,000
The lease payments for the Lot 4C leasehold land zoned conservation were subject to renegotiation as of January 1, 2006. Per the lease agreement, the lease payments will remain unchanged pending an appraisal, whereupon the lease rent could be adjusted to fair market value. Barnwell does not know the amount of the new lease payments which could be effective upon performance of the appraisal; they may remain unchanged or increase, and Barnwell currently expects the adjustment, if any, to not be material. The future lease payment disclosures above assume the minimum lease payments for leasehold land in effect at December 31, 2005 remain unchanged through December 2025, the end of the lease term.
16.STOCKHOLDERS' EQUITY
Share-based Payment Arrangements
2018 Equity Incentive Plan
The stockholder-approved 2018 Equity Incentive Plan is administered by the Compensation Committee of the Board of Directors and provides for the issuance of incentive stock options, nonstatutory stock options, stock options with stock appreciation rights, restricted stock, restricted stock units and performance units, qualified performance-based awards, and stock grants to employees, consultants and
97
non-employee members of the Board of Directors. 1,600,000 shares of Barnwell common stock have been reserved for issuance and as of September 30, 2024, a total of 925,188 share options remain available for grant.
Barnwell currently has a policy of issuing new shares to satisfy share option exercises when the optionee requests shares.
Stock Options
In February 2021, the Board of Directors of the Company granted options to purchase 665,000 shares of common stock, 310,000 shares to independent directors and 355,000 shares to employees. 605,000 shares of the stock options granted have an exercise price equal to the closing market price of Barnwell’s stock on the date of grant of $3.33, vest annually over three years, and expire in ten years from the date of grant. 60,000 shares of the stock options granted have an exercise price of $3.66 (110% of the closing market price on the date of grant for options granted to affiliates), vest annually over three years, and expire in five years from the date of grant. Of the 665,000 shares of common stock granted, 100,000 vested stock options expired and 100,000 shares were forfeited, both of which were as a result of director departures since the date of grant.
The following assumptions were used in estimating the fair value for equity-classified stock options granted in the year ended September 30, 2021:
> 10% Owner-Employee
Others
Number of shares
60,000
605,000
Expected volatility
127.4%
105.8%
Expected dividends
None
None
Expected term (in years)
3.5
6.0
Risk-free interest rate
0.19%
0.82%
Expected forfeitures
None
None
Fair value per share
$2.51
$2.70
The application of alternative assumptions could produce significantly different estimates of the fair value of share-based compensation, and consequently, the related costs reported in the “General and administrative” expenses in the Consolidated Statements of Operations.
98
The following table summarizes Barnwell’s equity-classified stock options activity from October 1, 2023 through September 30, 2024:
Options
Shares
Weighted- Average Exercise Price
Weighted- Average Remaining Contractual Term
Aggregate Intrinsic Value
Outstanding at October 1, 2023
465,000
$
3.37
Granted
—
—
Exercised
—
—
Expired/Forfeited
—
—
Outstanding at September 30, 2024
465,000
$
3.37
5.7
$
—
Exercisable at September 30, 2024
465,000
$
3.37
5.7
$
—
Compensation cost for stock option awards is measured at the grant date based on the fair value of the award and is recognized as an expense over the requisite service period. During the years ended September 30, 2024 and 2023, the Company recognized share-based compensation expense related to stock options of $50,000 and $164,000, respectively. There was no impact on income taxes for the years ended September 30, 2024 and 2023 due to a full valuation allowance on the related deferred tax asset. There is no remaining unrecognized compensation cost related to stock options as of September 30, 2024.
Restricted Stock Units
On November 2, 2023, the Board of Directors of the Company granted a total of 76,336 restricted stock units to the independent directors of the Board as partial payment of director fees for their service as members of the Board. The restricted stock units vest ratably over a three-year period, subject to the director’s continued service through the applicable vesting dates; provided that, any unvested restricted stock would vest upon a director’s death, disability, a change in control of the Company resulting in the director not continuing as a director or the director not being renominated for election even though he was willing to stand for re-election.
On May 16, 2024, the Board of Directors of the Company granted 60,000 restricted stock units to the Company’s President and Chief Executive Officer. The restricted stock units vest ratably over a three-year period, subject to the employee’s continued service through the applicable vesting dates.
99
The following table summarizes Barnwell’s restricted stock units activity from October 1, 2023 through September 30, 2024:
Restricted Stock Units
Shares
Weighted-Average Grant Date Fair Value
Nonvested at October 1, 2023
—
$
—
Granted
136,336
2.62
Vested (1)
(25,444)
2.62
Forfeited
—
—
Nonvested at September 30, 2024
110,892
$
2.63
______________
(1) The underlying common stock for these vested restricted stock units were not yet issued as of September 30, 2024; in October 2024, the Company issued 25,444 shares of common stock for these vested restricted stock units.
Compensation cost for restricted stock unit awards is measured at fair value and is recognized as an expense over the requisite service period. During the years ended September 30, 2024 and 2023, the Company recognized share-based compensation expense related to vested restricted stock units of $158,000 and $99,000, respectively. There was no impact on income taxes for the years ended September 30, 2024 and 2023 due to a net operating loss and net operating loss carryforwards with a full valuation allowance in the relevant taxing jurisdiction. As of September 30, 2024, the total remaining unrecognized compensation cost related to nonvested restricted stock units was $200,000, which is expected to be recognized over the weighted-average remaining requisite service period of 1.7 years.
Common Stock Issued for Services
In May 2023, the Company issued a total of 34,091 shares of Barnwell common stock to certain independent directors for their services on behalf of the Company and the Board of Directors pertaining to the negotiations of the Cooperation Agreement and the settlement of the potential proxy contest (see Note 19 for additional details). The total value of the shares issued was $90,000 which was valued using the closing price of Barnwell's common stock on May 11, 2023, the date of grant. There was no impact on income taxes for the year ended September 30, 2023 related to the common stock issued for services due to a net operating loss and net operating loss carryforwards with a full valuation allowance in the relevant taxing jurisdiction.
Cash Dividends
Nodividends were declared or paid during the year ended September 30, 2024. The following table sets forth the cash dividends paid per share of common stock during the year ended September 30, 2023.
Record Date
Date of Payment
Dividend Paid
August 24, 2023
September 11, 2023
$0.015
May 25, 2023
June 12, 2023
$0.015
February 23, 2023
March 13, 2023
$0.015
December 27, 2022
January 11, 2023
$0.015
100
17.COMMITMENTS AND CONTINGENCIES
Incentive compensation plan
Barnwell established incentive compensation plans to compensate the four oil and natural gas segment Canadian executive officers. The value of the plans are directly related to our oil and natural gas segment's free cash flows from Canadian properties and the divestiture of Canadian oil and natural gas assets. As of September 30, 2024, Barnwell has accrued approximately $286,000 in bonus compensation under these plans and the amount is reported in “Accrued compensation” on the Consolidated Balance Sheet at September 30, 2024.
Environmental Matters
Because of the inherent uncertainties associated with environmental assessment and remediation activities, future expenses to remediate sites identified in the future, if any, could be incurred. Barnwell's management is not currently aware of any significant environmental contingent liabilities requiring disclosure or accrual.
Legal and Regulatory Matters
Barnwell is routinely involved in disputes with third parties that occasionally require litigation. In addition, Barnwell is required to maintain compliance with all current governmental controls and regulations in the ordinary course of business. Barnwell’s management is not aware of any claims or litigation involving Barnwell that are likely to have a material adverse effect on its results of operations, financial position or liquidity.
In fiscal 2020, the Staff of the State of Hawaii’s Commission on Water Resource Management (“Commission”) circulated a draft of a proposed recommendation to the Commission under which the Company, the water utility, the water utility's independent hydrologist firm and the owner of the land on which two water wells were drilled would be assessed penalty fines because each of the wells were calculated to have been drilled beyond the depth permitted by the permit. The wells were drilled to a depth to penetrate certain layers of impermeable rock necessary to access the aquifer at the instructions and on the advice of the hydrologist hired by the owner of the well. Subsequently, the Staff of the Commission acknowledged that one well had not been drilled to a depth beyond its permitted depth and the fines on that well were eliminated. Additionally, the fines applicable to the depth of the second well were dropped in lieu of the parties entering into an agreement to perform a water quality study and repurpose a current well into a monitoring well. Accordingly, the Company recorded a liability of $300,000 to accrue for the costs to drill the monitoring well in the year ended September 30, 2020. During the year ended September 30, 2024, the liability was reduced to $200,000 due to a decrease in the estimated cost of the monitoring well due to reductions in the scope of work from what had been previously estimated.
Other Matters
During the year ended September 30, 2024, one of our water well drilling jobs encountered numerous unforeseen difficulties causing an increase in costs which led to the water well drilling contract becoming a loss job for which the Company had a $141,000 remaining loss accrual liability as of September 30, 2024.
101
Barnwell is obligated to pay Nearco Enterprises Ltd. 10.4%, net of non-controlling interests' share, of Kaupulehu Developments’ gross receipts from real estate transactions. This fee represents compensation for promotion and marketing of Kaupulehu Developments’ property and were determined based on the estimated fair value of such services. These fees are included in general and administrative expenses.
Barnwell is obligated to pay its external real estate legal counsel’s estate 1.2%, net of non-controlling interests' share, of all Increment II payments received by Kaupulehu Developments for services provided by its external real estate legal counsel in the negotiation and closing of the Increment II transaction. These fees are included in general and administrative expenses.
Kaupulehu Developments is also obligated to pay an amount equal to 0.72% and 0.20% of the cumulative net profits of KD II to KD Development 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.
18.INFORMATION RELATING TO THE CONSOLIDATED STATEMENTS OF CASH FLOWS
The following table details the effect of changes in current assets and liabilities on the Consolidated Statements of Cash Flows, and presents supplemental cash flow information:
Year ended September 30,
2024
2023
Increase (decrease) from changes in:
Receivables
$
650,000
$
1,103,000
Income tax receivable
(3,000)
(16,000)
Other current assets
1,475,000
(51,000)
Accounts payable
928,000
(595,000)
Accrued compensation
(79,000)
(278,000)
Other current liabilities
(191,000)
(556,000)
Increase (decrease) from changes in current assets and liabilities
$
2,780,000
$
(393,000)
Supplemental disclosure of cash flow information:
Cash paid during the year for:
Income taxes paid
$
71,000
$
100,000
Capital expenditure accruals related to oil and natural gas acquisition and development increased $1,291,000 during the year ended September 30, 2024 and decreased $575,000 during the year ended September 30, 2023. Additionally, capital expenditure accruals related to oil and natural gas asset retirement obligations decreased $577,000 during the year ended September 30, 2024 and increased $1,483,000 during the year ended September 30, 2023.
102
19.RELATED PARTY TRANSACTIONS
Kaupulehu Developments is entitled to receive payments from the sales of lots and/or residential units by KD I and KD II. KD I and KD II are part of the Kukio Resort Land Development Partnerships in which Barnwell holds indirect 19.6% and 10.8% non-controlling ownership interests, respectively, accounted for under the equity method of investment. The percentage of sales payments are part of transactions which took place in 2004 and 2006 where Kaupulehu Developments sold its leasehold interests in Increment I and Increment II to KD I's and KD II's predecessors in interest, respectively, 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. Changes to the arrangement above, effective March 7, 2019, are discussed in Note 4.
During the year ended September 30, 2024, Barnwell received $500,000 in percentage of sales payments from KD I from the sale of the last two single-family lots within Increment I. During the year ended September 30, 2023, Barnwell received $265,000 in percentage of sales payments from KD I from the sale of one single-family lot within Increment I.
In May 2023, the Company’s Board of Directors approved and ratified the payment of one-time special director fees to directors Kenneth Grossman and Doug Woodrum for their services on behalf of the Company and the Board of Directors pertaining to the negotiations of the cooperation and support agreement and the settlement of the potential proxy contest at the 2023 annual meeting of stockholders. Mr. Grossman received a one-time special director fee of $100,000, which was paid in $40,000 cash and a stock grant of 22,728 shares of Barnwell common stock (valued at $60,000 using the closing price of Barnwell's common stock on May 11, 2023, the date of grant). Mr. Woodrum received a one-time special director fee of $50,000, which was paid in $20,000 cash and a stock grant of 11,363 shares of Barnwell common stock (valued at $30,000 using the closing price of Barnwell's common stock on May 11, 2023, the date of grant).
20.SUBSEQUENT EVENTS
Restricted Stock Units
In October 2024, the Board of Directors of the Company granted a total of 105,820 restricted stock units to the independent directors of the Board as partial payment of director fees for their service as members of the Board. The restricted stock units vest ratably over a three-year period, subject to the director’s continued service through the applicable vesting date.
Contract Drilling Segment Drilling Rig
In December 2024, the Company entered into a purchase agreement with an independent third party for the sale of a contract drilling segment drilling rig and related ancillary equipment. The sale of these assets will close upon the buyer’s acceptance of the drilling rig and transfer of the legal title at delivery which is expected to occur in our second quarter of fiscal 2025.
21.SUMMARY OF SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)
Disclosure is not required as Barnwell qualifies as a smaller reporting company.
103
22.SUPPLEMENTARY OIL AND NATURAL GAS INFORMATION (UNAUDITED)
The following tables summarize information relative to Barnwell’s oil and natural gas operations, which are conducted in Canada and in the U.S. states of Oklahoma and Texas. Proved reserves are the estimated quantities of oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved producing oil and natural gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. The estimated net interests in total proved and proved producing reserves are based upon subjective engineering judgments and may be affected by the limitations inherent in such estimations. The process of estimating reserves is subject to continual revision as additional information becomes available as a result of drilling, testing, reservoir studies and production history. There can be no assurance that such estimates will not be materially revised in subsequent periods.
(A)Oil and Natural Gas Reserves
The following tables summarizes changes in the estimates of Barnwell’s net interests in total proved reserves of oil and natural gas liquids and natural gas, which are located in Canada and the U.S. states of Oklahoma and Texas. All of the information regarding Canadian reserves in this Form 10-K is derived from the report of our independent petroleum reserve engineers, InSite, and is included as an Exhibit to this Form 10-K.All of the information regarding U.S. reserves in this Form 10-K is derived from the report of our independent petroleum reserve engineers, Ryder Scott, and is included as an Exhibit to this Form 10-K. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimates of established proved producing oil and natural gas properties. Accordingly, these estimates are expected to change as future information becomes available.
Proved oil and natural gas reserves are the estimated quantities of oil and natural gas that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions (i.e., prices and costs) existing at the time the estimate is made.
Oil (Bbls)
Canada
United States
Total
Proved reserves:
Balance at September 30, 2022
846,000
29,000
875,000
Revisions of previous estimates
(43,000)
19,000
(24,000)
Extensions, discoveries and other additions
167,000
85,000
252,000
Less production
(183,000)
(21,000)
(204,000)
Balance at September 30, 2023
787,000
112,000
899,000
Revisions of previous estimates
222,000
(3,000)
219,000
Extensions, discoveries and other additions
117,000
—
117,000
Acquisitions of reserves
4,000
—
4,000
Less sales of reserves
(54,000)
—
(54,000)
Less production
(184,000)
(19,000)
(203,000)
Proved Reserves, September 30, 2024
892,000
90,000
982,000
104
NGL (Bbls)
Canada
United States
Total
Proved reserves:
Balance at September 30, 2022
144,000
61,000
205,000
Revisions of previous estimates
1,000
29,000
30,000
Extensions, discoveries and other additions
32,000
112,000
144,000
Less production
(27,000)
(25,000)
(52,000)
Balance at September 30, 2023
150,000
177,000
327,000
Revisions of previous estimates
70,000
15,000
85,000
Extensions, discoveries and other additions
15,000
—
15,000
Acquisitions of reserves
2,000
—
2,000
Less sales of reserves
(2,000)
—
(2,000)
Less production
(36,000)
(28,000)
(64,000)
Proved Reserves, September 30, 2024
199,000
164,000
363,000
Natural Gas (Mcf)
Canada
United States
Total
Proved reserves:
Balance at September 30, 2022
4,519,000
466,000
4,985,000
Revisions of previous estimates
435,000
387,000
822,000
Extensions, discoveries and other additions
1,079,000
1,078,000
2,157,000
Less production
(1,023,000)
(240,000)
(1,263,000)
Balance at September 30, 2023
5,010,000
1,691,000
6,701,000
Revisions of previous estimates
826,000
82,000
908,000
Extensions, discoveries and other additions
313,000
—
313,000
Acquisitions of reserves
16,000
—
16,000
Less sales of reserves
(139,000)
—
(139,000)
Less production
(1,085,000)
(259,000)
(1,344,000)
Proved Reserves, September 30, 2024
4,941,000
1,514,000
6,455,000
105
Total Equivalent Reserves (Boe)
Canada
United States
Total
Proved reserves:
Balance at September 30, 2022
1,769,000
170,000
1,939,000
Revisions of previous estimates
5,000
110,000
115,000
Extensions, discoveries and other additions
379,000
377,000
756,000
Less production
(381,000)
(86,000)
(467,000)
Balance at September 30, 2023
1,772,000
571,000
2,343,000
Revisions of previous estimates
430,000
27,000
457,000
Extensions, discoveries and other additions
184,000
—
184,000
Acquisitions of reserves
9,000
—
9,000
Less sales of reserves
(79,000)
—
(79,000)
Less production
(401,000)
(90,000)
(491,000)
Proved Reserves, September 30, 2024
1,915,000
508,000
2,423,000
The following tables summarize changes in the estimates of Barnwell’s net interests in total proved undeveloped reserves and presents the balances of total proved developed reserves of oil and natural gas liquids and natural gas, which are located in Canada and the U.S. states of Oklahoma and Texas. Proved developed oil and natural gas reserves are proved reserves that can be expected to be recovered through existing wells and equipment in place and under operating methods being utilized at the time the estimates were made.
Oil (Bbls)
Canada
United States
Total
Proved undeveloped reserves:
Balance at September 30, 2023
92,000
—
92,000
Conversion to proved developed reserves
(98,000)
—
(98,000)
Revisions of previous estimates
6,000
—
6,000
Additions due to a new well
109,000
—
109,000
Proved Undeveloped Reserves, September 30, 2024
109,000
—
109,000
Proved Developed Reserves, September 30, 2023
695,000
112,000
807,000
Proved Developed Reserves, September 30, 2024
783,000
90,000
873,000
106
NGL (Bbls)
Canada
United States
Total
Proved undeveloped reserves:
Balance at September 30, 2023
18,000
—
18,000
Conversion to proved developed reserves
(10,000)
—
(10,000)
Revisions of previous estimates
(8,000)
—
(8,000)
Additions due to a new well
23,000
—
23,000
Proved Undeveloped Reserves, September 30, 2024
23,000
—
23,000
Proved Developed Reserves, September 30, 2023
132,000
177,000
309,000
Proved Developed Reserves, September 30, 2024
176,000
164,000
340,000
Natural Gas (Mcf)
Canada
United States
Total
Proved undeveloped reserves:
Balance at September 30, 2023
608,000
—
608,000
Conversion to proved developed reserves
(279,000)
—
(279,000)
Revisions of previous estimates
(330,000)
—
(330,000)
Additions due to a new well
641,000
—
641,000
Proved Undeveloped Reserves, September 30, 2024
640,000
—
640,000
Proved Developed Reserves, September 30, 2023
4,402,000
1,691,000
6,093,000
Proved Developed Reserves, September 30, 2024
4,301,000
1,514,000
5,815,000
Total Equivalent Reserves (Boe)
Canada
United States
Total
Proved undeveloped reserves:
Balance at September 30, 2023
211,000
—
211,000
Conversion to proved developed reserves
(155,000)
—
(155,000)
Revisions of previous estimates
(56,000)
—
(56,000)
Additions due to a new well
239,000
—
239,000
Proved Undeveloped Reserves, September 30, 2024
239,000
—
239,000
Proved Developed Reserves, September 30, 2023
1,561,000
571,000
2,132,000
Proved Developed Reserves, September 30, 2024
1,676,000
508,000
2,184,000
107
(B)Capitalized Costs Relating to Oil and Natural Gas Producing Activities
All capitalized costs relating to oil and natural gas producing activities in Canada and the U.S. are summarized as follows:
September 30, 2024
Canada
United States
Total
Proved properties
$
76,963,000
$
6,594,000
$
83,557,000
Unproved properties
—
—
—
Total capitalized costs
76,963,000
6,594,000
83,557,000
Accumulated depletion, depreciation, and impairment
64,402,000
2,601,000
67,003,000
Net capitalized costs
$
12,561,000
$
3,993,000
$
16,554,000
September 30, 2023
Canada
United States
Total
Proved properties
$
74,440,000
$
6,411,000
$
80,851,000
Unproved properties
—
—
—
Total capitalized costs
74,440,000
6,411,000
80,851,000
Accumulated depletion, depreciation, and impairment
58,477,000
1,072,000
59,549,000
Net capitalized costs
$
15,963,000
$
5,339,000
$
21,302,000
(C)Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development
Year ended September 30, 2024
Canada
United States
Total
Acquisition of properties:
Proved
$
146,000
$
—
$
146,000
Unproved
—
—
—
Exploration costs
34,000
—
34,000
Development costs
3,865,000
183,000
4,048,000
Total
$
4,045,000
$
183,000
$
4,228,000
Year ended September 30, 2023
Canada
United States
Total
Acquisition of properties:
Proved
$
66,000
$
—
$
66,000
Unproved
—
—
—
Exploration costs
461,000
255,000
716,000
Development costs
6,331,000
5,099,000
11,430,000
Total
$
6,858,000
$
5,354,000
$
12,212,000
108
(D)Results of Operations for Oil and Natural Gas Producing Activities
Year ended September 30, 2024
Canada
United States
Total
Net revenues
$
15,093,000
$
2,303,000
$
17,396,000
Production costs
(9,230,000)
(619,000)
(9,849,000)
Depletion
(4,139,000)
(808,000)
(4,947,000)
Impairment of assets
(2,164,000)
(721,000)
(2,885,000)
Pre-tax results of operations (1)
(440,000)
155,000
(285,000)
Estimated income tax expense (2)
320,000
20,000
340,000
Results of operations (1)
$
(760,000)
$
135,000
$
(625,000)
Year ended September 30, 2023
Canada
United States
Total
Net revenues
$
16,630,000
$
2,746,000
$
19,376,000
Production costs
(9,859,000)
(575,000)
(10,434,000)
Depletion
(3,600,000)
(669,000)
(4,269,000)
Pre-tax results of operations (1)
3,171,000
1,502,000
4,673,000
Estimated income tax expense (2)
107,000
44,000
151,000
Results of operations (1)
$
3,064,000
$
1,458,000
$
4,522,000
_________________
(1) Before general and administrative expenses, interest expense, and foreign exchange gains and losses.
(2) Estimated income tax expense includes changes to the deferred income tax valuation allowance necessary for the portion of Canadian and U.S. federal tax law deferred tax assets that may not be realizable.
(E)Standardized Measure, Including Year-to-Year Changes Therein, of Estimated Discounted Future Net Cash Flows
The following tables utilize reserve and production data estimated by independent petroleum reserve engineers. The information may be useful for certain comparison purposes but should not be solely relied upon in evaluating Barnwell or its performance. Moreover, the projections should not be construed as realistic estimates of future cash flows, nor should the standardized measure be viewed as representing current value.
The estimated future cash flows at September 30, 2024 and 2023 were based on average sales prices in effect on the first day of the month for the preceding twelve month period in accordance with SEC Release No. 33-8995. The future production and development costs represent the estimated future expenditures that we will incur to develop and produce the proved reserves, assuming continuation of existing economic conditions. The future income tax expenses were computed by applying statutory income tax rates in existence at September 30, 2024 and 2023 to the future pre-tax net cash flows relating to proved reserves, net of the tax basis of the properties involved.
Material revisions to reserve estimates may occur in the future, development and production of the oil and natural gas reserves may not occur in the periods assumed and actual prices realized and actual costs incurred are expected to vary significantly from those used. Management does not rely upon this information in making investment and operating decisions; rather, those decisions are based upon a wide range of factors, including estimates of probable reserves as well as proved reserves and price and cost assumptions different than those reflected herein.
109
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.
Standardized Measure of Discounted Future Net Cash Flows
Year ended September 30, 2024
Canada
United States
Total
Future cash inflows
$
75,293,000
$
12,043,000
$
87,336,000
Future production costs
(42,601,000)
(5,080,000)
(47,681,000)
Future development costs
(2,795,000)
—
(2,795,000)
Future income tax expenses
(2,666,000)
(161,000)
(2,827,000)
Future net cash flows excluding abandonment, decommissioning and reclamation
27,231,000
6,802,000
34,033,000
Future abandonment, decommissioning and reclamation
(18,026,000)
(50,000)
(18,076,000)
Future net cash flows
9,205,000
6,752,000
15,957,000
10% annual discount for timing of cash flows
2,697,000
(2,804,000)
(107,000)
Standardized measure of discounted future net cash flows
$
11,902,000
$
3,948,000
$
15,850,000
Year ended September 30, 2023
Canada
United States
Total
Future cash inflows
$
73,429,000
$
15,995,000
$
89,424,000
Future production costs
(41,935,000)
(4,168,000)
(46,103,000)
Future development costs
(2,958,000)
—
(2,958,000)
Future income tax expenses
(1,512,000)
(264,000)
(1,776,000)
Future net cash flows excluding abandonment, decommissioning and reclamation
27,024,000
11,563,000
38,587,000
Future abandonment, decommissioning and reclamation
(18,585,000)
(42,000)
(18,627,000)
Future net cash flows
8,439,000
11,521,000
19,960,000
10% annual discount for timing of cash flows
4,790,000
(4,837,000)
(47,000)
Standardized measure of discounted future net cash flows
$
13,229,000
$
6,684,000
$
19,913,000
110
Changes in the Standardized Measure of Discounted Future Net Cash Flows
Year ended September 30,
2024
2023
Beginning of year
$
19,913,000
$
27,878,000
Sales of oil and natural gas produced, net of production costs
(7,547,000)
(8,942,000)
Net changes in prices and production costs, net of royalties and wellhead taxes
(12,201,000)
(11,913,000)
Extensions and discoveries
1,725,000
10,767,000
Net change due to purchases and sales of minerals in place
(895,000)
—
Changes in future development costs
170,000
(2,959,000)
Revisions of previous quantity estimates
9,478,000
2,227,000
Net change in income taxes
1,786,000
2,868,000
Accretion of discount
3,359,000
905,000
Other - changes in the timing of future production and other
76,000
(1,202,000)
Other - net change in Canadian dollar translation rate
(14,000)
284,000
Net change
(4,063,000)
(7,965,000)
End of year
$
15,850,000
$
19,913,000
111
ITEM 9.CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A.CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
We have established disclosure controls and procedures to ensure that material information relating to Barnwell, including its consolidated subsidiaries, is made known to the officers who certify Barnwell’s financial reports and to other members of executive management and the Board of Directors.
As of September 30, 2024, an evaluation was carried out by Barnwell’s Chief Executive Officer and Chief Financial Officer of the effectiveness of Barnwell’s disclosure controls and procedures. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that Barnwell’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934 (the “Exchange Act”)) were effective as of September 30, 2024 to ensure that information required to be disclosed by Barnwell in reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Exchange Act and the rules thereunder.
Management’s Annual Report on Internal Control Over Financial Reporting
Barnwell’s management is responsible for establishing and maintaining adequate internal control over financial reporting for Barnwell, as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act. Under the supervision and with the participation of Barnwell’s management, including our Chief Executive Officer and Chief Financial Officer, Barnwell conducted an evaluation of the effectiveness of its internal control over financial reporting using criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in the report entitled Internal Control — Integrated Framework (2013) (the “COSO Framework”). Based on this evaluation under the COSO Framework, management concluded that its internal control over financial reporting was effective as of September 30, 2024.
This Annual Report on Form 10-K does not include an attestation report of our independent registered public accounting firm regarding internal control over financial reporting. Pursuant to Item 308(b) of Regulation S-K, management’s report is not subject to attestation by our independent registered public accounting firm because the Company is neither an “accelerated filer” nor a “large accelerated filer” as those terms are defined by the SEC.
Changes in Internal Control Over Financial Reporting
There was no change in Barnwell’s internal control over financial reporting during the quarter ended September 30, 2024 that materially affected, or is reasonably likely to materially affect, Barnwell’s internal control over financial reporting.
112
ITEM 9B.OTHER INFORMATION
During the three months ended September 30, 2024, no director or officer of the Company adopted or terminated a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement,” as each term is defined in Item 408 of Regulation S-K.
ITEM 9C.DISCLOSURES REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS
Not applicable.
113
PART III
ITEM 10.DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
The information required is omitted pursuant to General Instruction G(3) of Form 10-K, since the Registrant will file its definitive proxy statement for the Annual Meeting of Stockholders no later than 120 days after the close of its fiscal year ended September 30, 2024, which proxy statement is incorporated herein by reference.
Barnwell adopted a Code of Ethics that applies to its Chief Executive Officer and the Chief Financial Officer. This Code of Ethics has been posted on Barnwell’s website at www.brninc.com.
ITEM 11.EXECUTIVE COMPENSATION
The information required is omitted pursuant to General Instruction G(3) of Form 10-K, since the Registrant will file its definitive proxy statement for the Annual Meeting of Stockholders no later than 120 days after the close of its fiscal year ended September 30, 2024, which proxy statement is incorporated herein by reference.
ITEM 12.SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
The information required is omitted pursuant to General Instruction G(3) of Form 10-K, since the Registrant will file its definitive proxy statement for the Annual Meeting of Stockholders no later than 120 days after the close of its fiscal year ended September 30, 2024, which proxy statement is incorporated herein by reference.
Equity Compensation Plan Information
The following table provides information about Barnwell's common stock that may be issued upon exercise of options and rights under Barnwell's existing equity compensation plan as of September 30, 2024:
(a)
(b)
(c)
Plan Category
Number of
securities
to be issued
upon exercise
of outstanding options, warrants
and rights (1)
Weighted- average price of outstanding options, warrants and rights
Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
Equity compensation plans approved by security holders
575,892
$3.37
925,188
Equity compensation plans not approved by security holders
—
—
—
Total
575,892
$3.37
925,188
________________
(1) In addition to shares issuable upon exercise of stock options, includes 110,892 restricted stock units, issuable under the 2018 Equity Incentive Plan at a rate of one share for each restricted stock unit. The restricted stock units do not have an exercise price. Therefore, these awards are not included in the calculation of weighted average exercise price in column (b).
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ITEM 13.CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
The information required is omitted pursuant to General Instruction G(3) of Form 10-K, since the Registrant will file its definitive proxy statement for the Annual Meeting of Stockholders no later than 120 days after the close of its fiscal year ended September 30, 2024, which proxy statement is incorporated herein by reference.
ITEM 14.PRINCIPAL ACCOUNTING FEES AND SERVICES
The information required is omitted pursuant to General Instruction G(3) of Form 10-K, since the Registrant will file its definitive proxy statement for the Annual Meeting of Stockholders no later than 120 days after the close of its fiscal year ended September 30, 2024, which proxy statement is incorporated herein by reference.
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PART IV
ITEM 15.EXHIBITS, FINANCIAL STATEMENT SCHEDULES
(a) Financial Statements
The following consolidated financial statements of Barnwell Industries, Inc. and its subsidiaries are included in Part II, Item 8:
Report of Independent Registered Public Accounting Firm - WEAVER AND TIDWELL, L.L.P. (PCAOB ID: 410)
Consolidated Balance Sheets – September 30, 2024 and 2023
Consolidated Statements of Operations – for the years ended September 30, 2024 and 2023
Consolidated Statements of Comprehensive Loss – for the years ended September 30, 2024 and 2023
Consolidated Statements of Equity – for the years ended September 30, 2024 and 2023
Consolidated Statements of Cash Flows – for the years ended September 30, 2024 and 2023
Notes to Consolidated Financial Statements
Schedules have been omitted because they were not applicable, not required, or the information is included in the consolidated financial statements or notes thereto.
(b) Exhibits
Exhibit Number
Description
3.1
Certificate of Incorporation, as amended (1)
3.2
Amended and Restated By-Laws (2)
4.1
Form of the Registrant’s certificate of common stock, par value $.50 per share (3)
4.2
Description of Securities Registered Pursuant to Section 12 of The Securities Exchange Act of 1934 (20)
10.1
The Barnwell Industries, Inc. Employees’ Pension Plan (restated as of October 1, 1989) (4)
10.2
Form of Purchase and Sale Agreement dated February 13, 2004 by and between Kaupulehu Developments and WB KD Acquisition, LLC (5)
10.3
Agreement dated May 27, 2009 which became effective June 23, 2009 by and between Kaupulehu Developments and WB KD Acquisition, LLC and WB KD Acquisition II, LLC (6)
10.4
Limited Liability Limited Partnership Agreement of KD Kona 2013 LLLP dated November 27, 2013 (7)
10.5
Limited Liability Limited Partnership Agreement of KKM Makai, LLLP dated November 27, 2013 (8)
10.6
Agreement with KD Kaupulehu, LLLP to Release Retained Rights, dated as of March 7, 2019, between Kaupulehu Developments and KD Kaupulehu, LLLP (9)
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10.7
Agreement with Respect to Retained Rights, dated as of March 7, 2019 between Kaupulehu Developments and KD Acquisition II, LP (10)
10.8#
Form of Option Agreement under Barnwell Industries, Inc. 2018 Equity Incentive Plan, as amended (11)
10.9
Asset Purchase and Sale Agreement, dated July 8, 2021, between Barnwell of Canada, Limited and Tourmaline Oil Corp. (12)
10.10
Cooperation and Support Agreement, dated January 27, 2021 (14)
10.11#
Amended and Restated 2018 Equity Incentive Plan (15)
10.12
Sales Agent Agreement, dated March 16, 2021 (16)
10.13
Purchase and Sale Agreement, dated as of December 12, 2022, between Barnwell Texas, LLC and Alchemist Energy LeaseCo, LP (17)
10.14#
Form of Stock Grant Award Agreement under Barnwell Industries, Inc. 2018 Equity Incentive Plan, as amended (18)
10.15#
Form of Director Restricted Stock Unit Award under Barnwell Industries, Inc. 2018 Equity Incentive Plan, as amended (19)
10.16#
Form of Employee Restricted Stock Unit Award under Barnwell Industries, Inc. 2018 Equity Incentive Plan, as amended (13)
19.1*
Statement of Company Policy on Insider Trading
21*
List of Subsidiaries
23.1*
Consent of InSite Petroleum Consultants Ltd.
23.2*
Consent of Ryder Scott Company, L.P.
23.3*
Consent of Weaver and Tidwell, L.L.P.
24.1*
Power of Attorney (included on signature page of this Annual Report on Form 10-K)
31.1*
Certification of Chief Executive Officer Pursuant To Section 302 of the Sarbanes-Oxley Act of 2002
31.2*
Certification of Chief Financial Officer Pursuant To Section 302 of the Sarbanes-Oxley Act of 2002
32**
Certification Pursuant To Section 906 of the Sarbanes-Oxley Act of 2002
97
Barnwell Industries, Inc. Clawback Policy (21)
99.1*
Reserve Report Summary prepared by InSite Petroleum Consultants Ltd.
99.2*
Reserve Report Summary prepared by Ryder Scott Company, L.P.
# Management contract or compensatory plan or arrangement.
(1) Incorporated by reference to Exhibit 3.1 to Registrant’s Form 10-Q for the quarterly period ended June 30, 2022.
(2) Incorporated by reference to Exhibit 3.2 to Registrant’s Form 8-K filed on February 23, 2024.
(3) Incorporated by reference to the registration statement on Form S-1 originally filed by the Registrant January 29, 1957 and as amended February 15, 1957 and February 19, 1957.
(4) Incorporated by reference to Registrant’s Form 10-K for the year ended September 30, 1989.
(5) Incorporated by reference to Exhibit 2.1 to Registrant’s Form 8-K filed on February 13, 2004.
(6)Incorporated by reference to Exhibit 10.1 to Registrant’s Form 10-Q for the quarterly period ended June 30, 2009.
(7)Incorporated by reference to Exhibit 10.7 to Registrant’s Form 10-Q for the quarterly period ended December 31, 2013.
(8)Incorporated by reference to Exhibit 10.8 to Registrant’s Form 10-Q for the quarterly period ended December 31, 2013
(9)Incorporated by reference to Exhibit 10.1 to Registrant’s Form 10-Q for the quarterly period ended March 31, 2019.
(10)Incorporated by reference to Exhibit 10.2 to Registrant’s Form 10-Q for the quarterly period ended March 31, 2019. Certain confidential information has been omitted from a portion of this exhibit.
(11)Incorporated by reference to Exhibit 10.1 to Registrant’s Form 10-Q for the quarterly period ended March 31, 2021.
(12)Incorporated by reference to Exhibit 10.9 to Registrant’s Form 10-K for the year ended September 30, 2021.
(13)Incorporated by reference to Exhibit 10.1 to Registrant’s Form 8-K filed on May 22, 2024.
(14)Incorporated by reference to Exhibit 10.1 to Registrant’s Form 8-K filed on February 1, 2021.
(15)Incorporated by reference from Definitive Proxy 2022 Appendix A filed by the Registrant on March 24, 2022.
(16)Incorporated by reference to Exhibit 1.1 to Registrant’s Form 8-K filed on March 16, 2021.
(17)Incorporated by reference to Exhibit 10.1 to Registrant’s Form 10-Q filed on February 13, 2023.
(18)Incorporated by reference to Exhibit 10.1 to Registrant’s Form 10-Q filed on May 15, 2023.
(19)Incorporated by reference to Exhibit 10.1 to Registrant’s Form 8-K filed on June 15, 2023.
(20)Incorporated by reference to Exhibit 4.3 to Registrant’s Form 10-K for the year ended September 30, 2023.
(21)Incorporated by reference to Exhibit 97 to Registrant’s Form 10-K for the year ended September 30, 2023.
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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
BARNWELL INDUSTRIES, INC.
(Registrant)
/s/ Russell M. Gifford
By:
Russell M. Gifford
Executive Vice President,
Chief Financial Officer,
and Treasurer
Date:
December 16, 2024
119
POWER OF ATTORNEY
KNOW ALL PERSONS BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints Russell M. Gifford and Alexander C. Kinzler, jointly and severally, his or her attorneys-in-fact, each with the power of substitution, for him or her in any and all capacities, to sign any amendments to this Annual Report on Form 10-K, and to file the same, with exhibits thereto and other documents in connection therewith, with the Securities and Exchange Commission, hereby ratifying and confirming all that each of said attorneys-in-fact, or his substitute or substitutes, may do or cause to be done by virtue hereof.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
/s/ Craig D. Hopkins
/s/ Russell M. Gifford
Craig D. Hopkins
President and Chief Executive Officer
Date: December 16, 2024
Russell M. Gifford
Executive Vice President, Chief Financial Officer and Treasurer
Date: December 16, 2024
/s/ Alexander C. Kinzler
/s/ Kenneth S. Grossman
Alexander C. Kinzler, General Counsel, Secretary and Executive Chairman of the Board
Cover Page Interactive Data File (embedded within the Inline XBRL document)
_________________________________________________
* Filed herewith.
** Furnished herewith.
# Management contract or compensatory plan or arrangement.
(1) Incorporated by reference to Exhibit 3.1 to Registrant’s Form 10-Q for quarterly period ended June 30, 2022.
(2) Incorporated by reference to Exhibit 3.2 to Registrant’s Form 8-K filed on February 23, 2024.
(3) Incorporated by reference to the registration statement on Form S-1 originally filed by the Registrant January 29, 1957 and as amended February 15, 1957 and February 19, 1957.
(4) Incorporated by reference to Registrant’s Form 10-K for the year ended September 30, 1989.
(5) Incorporated by reference to Exhibit 2.1 to Registrant’s Form 8-K filed on February 13, 2004.
(6)Incorporated by reference to Exhibit 10.1 to Registrant’s Form 10-Q for the quarterly period ended June 30, 2009.
(7)Incorporated by reference to Exhibit 10.7 to Registrant’s Form 10-Q for the quarterly period ended December 31, 2013.
(8)Incorporated by reference to Exhibit 10.8 to Registrant’s Form 10-Q for the quarterly period ended December 31, 2013
(9)Incorporated by reference to Exhibit 10.1 to Registrant’s Form 10-Q for the quarterly period ended March 31, 2019.
(10)Incorporated by reference to Exhibit 10.2 to Registrant’s Form 10-Q for the quarterly period ended March 31, 2019. Certain confidential information has been omitted from a portion of this exhibit.
(11)Incorporated by reference to Exhibit 10.1 to Registrant’s Form 10-Q for the quarterly period ended March 31, 2021.
(12)Incorporated by reference to Exhibit 10.9 to Registrant’s Form 10-K for the year ended September 30, 2021.
(13)Incorporated by reference to Exhibit 10.1 to Registrant’s Form 8-K filed on May 22, 2024.
(14)Incorporated by reference to Exhibit 10.1 to Registrant’s Form 8-K filed on February 1, 2021.
(15)Incorporated by reference from Definitive Proxy 2022 Appendix A filed by the Registrant on March 24, 2022.
(16)Incorporated by reference to Exhibit 1.1 to Registrant’s Form 8-K filed on March 16, 2021.
(17)Incorporated by reference to Exhibit 10.1 to Registrant’s Form 10-Q filed on February 13, 2023.
(18)Incorporated by reference to Exhibit 10.1 to Registrant’s Form 10-Q filed on May 15, 2023.
(19)Incorporated by reference to Exhibit 10.1 to Registrant’s Form 8-K filed on June 15, 2023.
(20)Incorporated by reference to Exhibit 4.3 to Registrant’s Form 10-K for the year ended September 30, 2023.
(21)Incorporated by reference to Exhibit 97 to Registrant’s Form 10-K for the year ended September 30, 2023.