Item 1. Business
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
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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 *
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* This amount does not purport to represent, nor should it be interpreted as, the fair value of Barnwell’s oil and natural gas reserves. An estimate of fair value would also consider, among other items, the recovery of reserves not presently classified as proved, anticipated future changes in oil and natural gas prices (these amounts were based on a natural gas price of $1.16 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*** $3.30 $3.68 $4.08
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* Calculated on revenues net of pipeline charges before royalty expense divided by gross production.
** Calculated on revenues before royalty expense divided by gross production.
*** Calculated on production costs, excluding natural gas pipeline charges, divided by the combined total production of natural gas liquids, oil and natural gas.
Capital Expenditures and Acquisitions
Barnwell invested $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
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* “Developed Acreage” includes the acres covered by leases upon which there are one or more producing wells. “Undeveloped Acreage” includes acres covered by leases upon which there are no producing wells and which are maintained by the payment of delay rentals or the commencement of drilling thereon.
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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