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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K 
(Mark One)
☒           ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended September 30, 2022
or
☐       TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission File Number 1-5103 
BARNWELL INDUSTRIES, INC.
(Exact name of registrant as specified in its charter)
Delaware   72-0496921
(State or other jurisdiction of incorporation or organization)   (I.R.S. Employer Identification No.)
1100 Alakea Street, Suite 500, Honolulu, Hawaii
 96813-2840
(Address of principal executive offices) (Zip code)
Registrant’s telephone number, including area code:  (808) 531-8400 
Securities registered pursuant to Section 12(b) of the Act:
Title of each class Trading Symbol(s) Name of each exchange on which registered
Common Stock, $0.50 par value BRN NYSE American
Common Stock Purchase Rights N/A NYSE American
Securities registered pursuant to Section 12(g) of the Act:  None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. o Yes     x No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. o Yes     x No
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.      x Yes     o No
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). x Yes     o No
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company.  See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and "emerging growth company" in Rule 12b-2 of the Exchange Act.
        Large accelerated filer ☐   Accelerated filer ☐
Non-accelerated filer   ☒ Smaller reporting company ☒
Emerging growth company ☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o
Indicate by check mark whether the Registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report.     ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).     ☐ Yes     x No
The aggregate market value of the voting common stock held by non-affiliates of the registrant, computed by reference to the closing price of a share of common stock on March 31, 2022 (the last business day of the registrant’s most recently completed second fiscal quarter) was $12,155,000.
As of December 9, 2022 there were 9,956,687 shares of common stock outstanding.
Documents Incorporated by Reference
1.            Proxy statement, to be forwarded to stockholders on or about January 13, 2023, is incorporated by reference in Part III hereof.


TABLE OF CONTENTS
 
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GLOSSARY OF TERMS

Unless otherwise indicated, all references to “dollars” in this Form 10-K are to U.S. dollars.
 
Defined below are certain terms used in this Form 10-K: 
Terms   Definitions
AER -
Alberta Energy Regulator
ARO -
Asset retirement obligation
ASC - Accounting Standards Codification
ASU - Accounting Standards Update
Barnwell of Canada - Barnwell of Canada, Limited
Bbl(s) - stock tank barrel(s) of oil equivalent to 42 U.S. gallons
Boe - barrel of oil equivalent at the rate of 5.8 Mcf per Bbl of oil or NGL
Consolidated Balance Sheets - The consolidated balance sheets of Barnwell Industries, Inc. and its subsidiaries.
FASB - Financial Accounting Standards Board
GAAP - U.S. generally accepted accounting principles
Gross - Total number of acres or wells in which Barnwell owns an interest; includes interests owned of record by Barnwell and, in addition, the portion(s) owned by others; for example, a 50% interest in a 320 acre lease represents 320 gross acres and a 50% interest in a well represents 1 gross well. In the context of production volumes, gross represents amounts before deduction of the royalty share due others.
InSite - InSite Petroleum Consultants Ltd.
KD I - KD Acquisition, LLLP, formerly known as WB KD Acquisition, LLC
KD II - KD Acquisition II, LP, formerly known as WB KD Acquisition, II, LLC
KD Development
KD Development, LLC
KD Kona - KD Kona 2013 LLLP
KKM Makai - KKM Makai, LLLP
Kukio Resort Land Development Partnerships - The following partnerships in which Barnwell owns non-controlling interest:
KD Kukio Resorts, LLLP (“KD Kukio Resorts”)
KD Maniniowali, LLLP (“KD Maniniowali”)
KD Kaupulehu, LLLP, which consists of KD I and KD II (“KDK”)
LCA -
Licensee Capability Assessment
LGX -
LGX Oil & Gas Ltd.
MBbls - thousands of barrels of oil
Mcf - one thousand cubic feet of natural gas at 14.65 pounds per square inch absolute and 60 degrees Fahrenheit
Mcfe - Mcf equivalent at the rate of 1 Bbl = 5.8 Mcf
MMcf - one million cubic feet of natural gas
Net - Barnwell’s aggregate interest in the total acres or wells; for example, a 50% interest in a 320 acre lease represents 160 net acres and a 50% interest in a well represents 0.5 net well. In the context of production volumes, net represents amounts after deduction of the royalty share due others.
NGL(s) - natural gas liquid(s)
Octavian Oil - Octavian Oil, Ltd.
OWA
Orphan Well Association
Ryder Scott - Ryder Scott Company, L.P.
SEC - United States Securities and Exchange Commission
U.S. - United States
VIE - Variable interest entity
Water Resources - Water Resources International, Inc.
WIP
Working Interest Partners
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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 2022 represented Barnwell’s 66th 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. state of Oklahoma.
 
•Land Investment Segment  -  Barnwell invests in 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 and development of those reserves. Additionally, through its wholly-owned subsidiary BOK Drilling, LLC (“BOK”), established in February 2021, Barnwell is indirectly involved in oil and natural gas investments in Oklahoma.

Strategy

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

Twining consists of assets in the Twining field, in Alberta, Canada, that were purchased in August 2018 and additions to the field subsequently. These assets are partially operated by the Company and partially operated by Pine Cliff Energy Ltd. The oil wells operated by the Company are largely low decline wells, less than 15% per year decline rates, and due to these lower decline rates, these Twining oil wells require a lower amount of capital investment than higher decline rate wells. This lower capital requirement along with the fact that the land is largely held indefinitely, enables development drilling to be done when commodity prices support it. Since Barnwell’s entry into the Twining property, we have participated in drilling eight gross horizontal development wells that were completed with multi-stage sand fracs, all of which have been or are forecast to be profitable. Of these eight wells, two are 100%-owned operated wells chosen by Barnwell and six gross (1.7 net) are non-operated wells. Barnwell plans to continue to develop the pool with more horizontal wells if commodity prices continue to support their profitability.

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The Legacy category consists of the Company's Canadian oil and natural gas assets not in the Twining area which are largely non-operated. The Canadian Legacy assets are located throughout Alberta, Canada, and produce shallow gas and conventional oil from a variety of pools. These assets have been accumulated over decades of Barnwell activity. Barnwell continues to evaluate opportunities to either divest the legacy Canadian assets or add to them through acquiring working interests depending on technical and economic evaluations.

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

At September 30, 2022, Barnwell’s reserves were approximately 54% operated and consisted of 56% conventional oil and natural gas liquids and 44% natural gas. At September 30, 2021, Barnwell’s reserves were approximately 64% operated and consisted of 56% conventional oil and natural gas liquids and 44% natural gas.

Operations

All acquisitions, operational and developmental activities in the Twining area are the responsibility of the President and Chief Operating Officer of Octavian Oil with approvals for major expenditures secured from Barnwell’s executive management and, when applicable, the Board of Directors.
 
Our oil and natural gas segment revenues, profitability, and future rate of growth are dependent upon oil and natural gas prices and 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 companies have been negatively affected as well, resulting in a decline in sources of financing as compared to previous years. Oil and natural gas prices have recovered significantly from the prior year which could improve sources of external finances.

Natural gas prices are typically higher in the winter than at other times due to increased heating demand. Oil prices also are subject to seasonal fluctuations, but to a lesser degree. Oil and natural gas unit sales are based on the quantity produced from the properties by the respective property operators. Prices received in Canada also have been negatively impacted by the lack of export pipeline capacity.

Preparation of Reserve Estimates

Barnwell’s reserves are estimated by our independent petroleum reserve engineers, InSite Petroleum Consultants Ltd. (“InSite”) in Canada and Ryder Scott Company, L.P. (“Ryder Scott”) in the U.S., in accordance with generally accepted petroleum engineering and evaluation principles and techniques and rules and regulations of the SEC. All information with respect to the Company’s Canadian reserves in this Form 10-K is derived from the report of InSite and a copy of the report issued by InSite is filed with this Form 10-K as Exhibit 99.1. All information with respect to the Company’s U.S. reserves in this Form 10-K is derived from the report of Ryder Scott and a copy of the report issued by Ryder Scott is filed with this Form 10-K as Exhibit 99.2.
 
The preparation of data used by the independent petroleum reserve engineers to compile our oil and natural gas reserve estimates was completed in accordance with various internal control procedures
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which include verification of data input into reserves evaluation software, reconciliations and reviews of data provided to the independent petroleum reserve engineers to ensure completeness, and management review controls, including an independent internal review of the final reserve report for completeness and accuracy.
 
Barnwell has a Reserves Committee consisting of two independent directors and Barnwell's CEO. The Reserves Committee was established to ensure the independence of the Company’s petroleum reserve engineers. The Reserves Committee is responsible for reviewing the annual reserve evaluation reports prepared by the independent petroleum reserve engineering firms and ensuring that the reserves are reported fairly in a manner consistent with applicable standards. The Reserves Committee meets annually to discuss reserve issues and policies and to meet with Company personnel and the independent petroleum reserve engineers.
 
Barnwell of Canada’s President and Chief Operating Officer is a professional engineer with over 25 years of relevant experience in the oil and natural gas industry in Canada and is a member of the Association of Professional Engineers and Geoscientists of Alberta.

Reserves

The amounts set forth in the following table, based on our independent reserve engineers’ evaluation of our reserves, summarize our estimated proved reserves of oil (including natural gas liquids) and natural gas as of September 30, 2022 for all properties located in Canada and the U.S. in which Barnwell has an interest. All of our oil and natural gas reserves are based on constant dollar price and cost assumptions. 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, 2021.
As of September 30, 2022
Estimated Net Proved Developed Reserves Estimated Net Proved Undeveloped Reserves Estimated Net Proved Reserves
Oil, including natural gas liquids (Bbls) 1,046,000  34,000  1,080,000 
Natural gas (Mcf) 4,857,000  128,000  4,985,000 
Total (Boe) 1,883,000  56,000  1,939,000 

During fiscal 2022, Barnwell’s total net proved developed reserves of oil and natural gas liquids increased by 410,000 Bbls (64%) and total net proved developed reserves of natural gas increased by 1,944,000 Mcf (67%), for a combined increase of 745,000 Boe (65%). The increase in natural gas reserves
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were primarily the result of higher oil and gas prices resulting in positive revisions in the current year period.

The following table sets forth Barnwell’s oil and natural gas net reserves at September 30, 2022, by location and property name, based on information prepared by our independent reserve engineers, as well as net production and net revenues by location and property name for the year ended September 30, 2022. The reserve data in this table is based on constant dollars where reserve estimates are based on sales prices, costs and statutory tax rates in existence at September 30, 2022, the date of the projection.

As of September 30, 2022 For the year ended September 30, 2022
Net Proved Producing Reserves Net Proved Reserves Net Production Net Revenues
Property Name Oil & NGL (MBbls) Gas (MMcf) Oil & NGL (MBbls) Gas (MMcf) Oil & NGL (MBbls) Gas (MMcf) Oil & NGL Gas
Canada:
Twining 708  2,775  875  3,358  160  611  $ 13,537,000  $ 2,812,000 
Bonanza/Balsam 25  20  25  20  4  3  334,000  18,000 
Kaybob 30  117  30  117  3  17  257,000  73,000 
Medicine River 41  549  41  549  6  21  360,000  89,000 
Thornbury —  429  —  429  —  63  —  264,000 
Wood River 18  43  18  43  12  22  991,000  93,000 
Other properties —  3  1  3  3  35  113,000  144,000 
United States:
Oklahoma 90  466  90  466  42  192  2,462,000  1,034,000 
Total 912  4,402  1,080  4,985  230  964  $ 18,054,000  $ 4,527,000 

Net proved reserves that are attributable to existing producing wells are primarily determined using decline curve analysis and rate transient analysis, which incorporates the principles of hydrocarbon flow. Net proved reserves attributable to producing wells with limited production history and for undeveloped locations are estimated using performance from analogous wells in the surrounding area and geologic data to assess the reservoir continuity. Technologies relied on to establish reasonable certainty of economic producibility include electrical logs, radioactivity logs, core analyses, geologic maps and available production data, seismic data and well test data.

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Standardized Measure of Discounted Future Net Cash Flows

The following table sets forth Barnwell’s “Estimated Future Net Revenues” from total proved oil, natural gas and natural gas liquids reserves located in Canada and the U.S. and the present value of Barnwell’s “Estimated Future Net Revenues” (discounted at 10%) as of September 30, 2022. Estimated future net revenues for total proved reserves are net of estimated future expenditures of developing and producing the proved reserves, and assume the continuation of existing economic conditions. 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,
2023 $ 10,645,000 
2024 6,976,000 
2025 5,007,000 
Thereafter 8,206,000 
Undiscounted future net cash flows, after income taxes $ 30,834,000   
Standardized measure of discounted future net cash flows $ 27,878,000  *
_______________________________________________
*      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 value of Barnwell’s undeveloped land position, the recovery of reserves not presently classified as proved, anticipated future changes in oil and natural gas prices (these amounts were based on a natural gas price of $4.12 per Mcf and an oil price of $81.01 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 in accordance with best practice recommendations into the Company’s reserve reports.

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 2022 and 2021 was derived in Alberta, Canada and in Oklahoma. Barnwell's net production in fiscal 2020 was derived in Alberta, Canada. For a discussion regarding our total annual production volumes, average sales prices, and related production costs, see Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
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  Year ended September 30,
  2022 2021 2020
Annual net production:      
Natural gas (Mcf) 964,000  694,000  649,000 
Oil (Bbls) 182,000  147,000  153,000 
Natural gas liquids (Bbls) 48,000  24,000  21,000 
Total (Boe) 396,000  291,000  286,000 
Total (Mcfe) 2,296,000  1,685,000  1,658,000 
Annual average sales price per unit of production:
Mcf of natural gas* $4.63 $2.62 $1.64
Bbl of oil** $86.73 $51.74 $33.85
Bbl of natural gas liquids** $48.06 $31.92 $17.16
Annual average production cost per Boe produced*** $23.66 $22.40 $16.79
Annual average production cost per Mcfe produced*** $4.08 $3.86 $2.89
______________________________________________________
*           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 $11,052,000 in oil and natural gas properties during fiscal 2022, including accrued capital expenditures and acquisitions of oil and natural gas properties and excluding additions and revisions to estimated asset retirement obligations. Barnwell’s capital expenditures were mostly for the drilling of wells in the Twining area and also were for facilities expansion and upgrade costs in the Twining area and the acquisition of additional working interests in several wells in the Twining area.

Barnwell invested $2,217,000 in oil and natural gas properties during fiscal 2021, including accrued capital expenditures and acquisitions of oil and natural gas properties and excluding additions and revisions to estimated asset retirement obligations. Barnwell’s capital expenditures were mostly for the acquisition of additional working interests in several wells and equipment in the Twining area and the drilling of wells in Oklahoma that began in the third quarter of fiscal 2021.
 
Well Drilling Activities

The Company participated in the drilling of six gross (1.7 net) non-operated development wells in the Twining area during the year ended September 30, 2022. Capital expenditures incurred by the Company for these non-operated development wells totaled $4,366,000 for the year ended September 30, 2022. Five gross (1.4 net) wells were producing at September 30, 2022 and the remaining one gross (0.3 net) well is awaiting tie-in and is expected to produce in fiscal 2023. The Company drilled one gross (1.0 net) operated development well in the Twining area which was producing at September 30, 2022. Capital expenditures incurred by the Company for this operated well was $2,852,000. The Company did not drill or participate in the drilling of wells in Oklahoma during the year ended September 30, 2022.

In fiscal 2021, the Company participated in the drilling of seven gross (0.2 net) non-operated development wells in Oklahoma. Capital expenditures incurred by the Company for these Oklahoma wells totaled $1,178,000 for the year ended September 30, 2021. All wells were producing during the year
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ended September 30, 2022, producing 42,000 barrels of oil and natural gas liquids and 192,000 Mcf of natural gas. The Company did not drill or participate in the drilling of wells in Canada during the year ended September 30, 2021.

In fiscal 2020, the Company drilled one gross (1.0 net) horizontal development well in the Twining area. The Company did not drill or participate in the drilling of wells in Oklahoma during the year ended September 30, 2020.

Producing Wells

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

The following table sets forth the gross and net acres of both developed and undeveloped oil and natural gas leases in Canada which Barnwell held as of September 30, 2022. 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
Canada 136,220 32,890 28,400 8,210 164,620 41,100
_________________________________________________
*                  “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.
 
Eighty-six percent of Barnwell’s undeveloped acreage is not subject to expiration at September 30, 2022. Fourteen percent of Barnwell’s leasehold interests in undeveloped acreage is subject to expiration and expire over the next five fiscal years, if not developed, as follows: 12% expire during fiscal 2023; no expirations during fiscal 2024 and 2025; 2% expire during fiscal 2026; and no expirations during fiscal 2027. There can be no assurance that Barnwell will be successful in renewing its leasehold interests in the event of expiration.

Much of the undeveloped acreage is at non-operated properties over which we do not have control, and the value of such acreage is not estimated to be significant at current commodity prices. Barnwell’s undeveloped acreage includes a significant concentration in the Twining area (2,860 net acres).

Marketing of Oil and Natural Gas
 
Barnwell sells its Canadian oil, natural gas, and natural gas liquids production, including under short-term contracts between itself and two main oil marketers, one natural gas purchaser, and one natural gas liquids marketer. The prices received are freely negotiated between buyers and sellers and are determined from transparent posted prices adjusted for quality and transportation differentials. In fiscal 2022, over 80% of Barnwell’s Canadian oil and natural gas revenues were from products sold at spot prices. Barnwell does not use derivative instruments to manage price risk.

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In fiscal 2022 and 2021, Barnwell took most of its Canadian oil, natural gas liquids and natural gas “in kind” where Barnwell markets the products instead of having the operator of a producing property market the products on Barnwell’s behalf. We sell oil, natural gas and natural gas liquids to a variety of energy marketing companies. 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 natural gas is sold within Alberta.
 
All of Barnwell’s Canadian gross revenues were derived from properties located within Alberta, which charges oil and natural gas producers a royalty for production within the province. Provincial royalties are calculated as a percentage of revenue and vary depending on production volumes, selling prices and the date of discovery. 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.

In January 2016, the Alberta Royalty Panel recommended a new modernized Alberta royalty framework which applies to wells drilled on or after January 1, 2017. The previous royalty framework will continue to apply to wells drilled prior to January 1, 2017 for a period of ten years, after which they will fall under the current royalty framework. Under the current royalty framework the same royalty calculation applies to both oil and natural gas wells, whereas the previous royalty framework had different royalties applicable to each category, 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 are adjusted down for cost increases as wells age.

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

In fiscal 2022, the weighted-average royalty rate paid on all of Barnwell’s Canadian natural gas was 12%, and the weighted-average royalty rate paid on oil was 17%. In fiscal 2022, the weighted-average royalty rate paid on all of Oklahoma’s production was 23%.

In June 2021, the AER announced that the previous Licensee Liability Program (“LLP”) would be replaced by the Licensee Life-Cycle Management via a Licensee Capability Assessment (“LCA”). The LCA is intended to be a more comprehensive assessment of corporate health and considers a wider variety of factors than those considered under the LLP and establishes clear expectations for industry with regards to the management of liabilities throughout the entire lifecycle of oil and gas projects. Factors considered are grouped into six factor groups, these being current financial distress, liability magnitude, resources lifespan, operations compliance, closure efficiency, and administrative compliance. These factors are compared to peer operators and ranked into three “Tiers.” Barnwell’s assessment under the LCA Program
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is currently favorable with Tier 1 or 2 overall rankings in the six factor groups. Barnwell believes it can continue to manage its operations to maintain a favorable ranking. Importantly, an inventory reduction program also has been implemented which requires mandatory annual minimum expenditures towards outstanding decommissioning and reclamation obligations in accordance with five-year rolling spending targets. Currently, these targets are forecast by the AER to increase by 9% per year. These targets became effective January 1, 2022. Barnwell believes the targets assessed by the AER are within estimated forecasts for Barnwell’s future ARO spending and therefore the Company will be in compliance with spend targets under the Inventory Reduction Program.

In September 2019, the AER issued an abandonment/closure order for all wells and facilities in the Manyberries area which had been largely operated by LGX, an operating company that went into receivership in 2016. The estimated asset retirement obligation for the Company's interest in the wells and facilities in the Manyberries area is included in “Asset retirement obligation” in the Consolidated Balance Sheets.

Recently, the OWA created a WIP program for specific areas where there are a significant number of orphaned wells to abandon. The OWA has the ability and expertise to abandon wells using its internal resources and network of service providers resulting in efficiencies that companies such as Barnwell, would not be able to obtain on its own. Under the WIP program, the Company would be required to provide payment for only Barnwell’s working interest share, however, all WIP’s would have to participate in the program for the OWA to begin its work. In March 2021, the Company was notified by the OWA that Barnwell’s Manyberries wells were confirmed to be in the WIP program.

Under the new agreement with the OWA, the Company is required to pay the abandonment and reclamation costs in advance through a cash deposit. The total cash deposit amount was calculated to be approximately $1,525,000 and the Company paid $888,000 of the total deposit in July and August 2021 and will need to pay the remaining balance of $637,000 by August 2023. The Company revised its Manyberries ARO liability based on the OWA’s revised abandonment and reclamation estimates, which resulted in an increase of approximately $213,000 in the year ended September 30, 2021. The increase in the ARO liability was a result of higher reclamation and remediation costs than anticipated, partially offset by lower abandonment estimates. Based on a review of the details of the cash deposit calculation provided by the OWA, which includes amounts added for possible contingencies, the Company believes the required cash deposit amount by the OWA is higher than the actual costs of the asset retirement obligation for the Manyberries wells and that any excess of the deposit over actual asset retirement costs for the first phase of the work would be credited toward the second phase of the work. A remaining excess deposit, if any, would ultimately be refunded to the Company upon completion of all of the work. As at September 30, 2022, the Company recognized a cumulative reduction in the deposit balance of $113,000 for work performed under this program.

Over the past five years, the Company has worked to reduce its abandonment and reclamation obligations associated with its oil and natural gas segment, both by divesting low-productivity assets and actively closing wells and sites. Sixteen Barnwell operated sites have been certified as fully reclaimed or exempt since 2016. To aid in this regard, and as a stimulus response to the COVID-19 pandemic, the Canadian Federal Government created and funded the Alberta-administered Site Rehabilitation Program (“SRP”) in spring 2020. The SRP has been designed to reduce oil and gas industry liabilities by funding vendors who perform closure work. In partnership with its vendors, Barnwell-operated sites have received $388,000 in net funding to date, to be directed to ARO reduction activities. Barnwell has further benefited from grants allocated to its non-operated property partners amounting to $120,000.

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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

In the 1980s, Kaupulehu Developments obtained the state and county zoning changes necessary to permit development of the Four Seasons Resort Hualalai at Historic Ka`upulehu and Hualalai Golf Club, which opened in 1996, a second golf course, and single-family and multi-family residential units. These projects were developed by an unaffiliated entity on leasehold land acquired from Kaupulehu Developments.
 
In the 1990s and 2000s, Kaupulehu Developments obtained the state and county zoning changes necessary to permit development of single-family and multi-family residential units, a golf course and a limited commercial area on approximately 870 leasehold acres, known as Lot 4A, zoned for resort/residential development, located adjacent to and north of the Four Seasons Resort Hualalai at Historic Ka`upulehu. In 2004 and 2006, Kaupulehu Developments sold its leasehold interest in Kaupulehu Lot 4A to KD I's and KD II's predecessors in interest, which was prior to Barnwell’s affiliation with KD I and KD
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II which commenced on November 27, 2013, the acquisition date of our ownership interest in the Kukio Resort Land Development Partnerships.
 
Increment I is an area of 80 single-family lots, 78 of which were sold from 2006 to 2022, and a beach club on the portion of the property bordering the Pacific Ocean. The purchasers of the 80 single-family lots have the right to apply for membership in the Kuki`o Golf and Beach Club, which is located adjacent to and south of the Four Seasons Resort Hualalai at Historic Ka`upulehu. Increment II is the remaining portion of the approximately 870-acre property and is zoned for single-family and multi-family residential units and a golf course and clubhouse. Two residential lots of approximately two to three acres in size fronting the ocean were developed within Increment II and sold by KD II, and the remaining acreage within Increment II is not yet under development. It is uncertain when or if KD II will develop the other areas of Increment II, and there is no assurance with regards to the amounts of future sales from Increments I and II. The remaining 420 developable acres at Increment II are entitled for up to 350 homesites. No definitive development plans have been made by the developer of Increment II as of the date of this report.

Kaupulehu Developments is entitled to receive payments from KD I based on 10% of the gross receipts from KD I's sales of single-family residential lots in Increment I. In fiscal 2022, six single-family lots were sold and two single-family lots, of the 80 lots developed within Increment I, remained to be sold as of September 30, 2022.
 
In March 2019, KD II admitted a new development partner, Replay Kaupulehu Development, LLC (“Replay”), a party unrelated to Barnwell, in an effort to move forward with development of the remainder of Increment II at Kaupulehu. 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 for Increment II. Such compensation will be reflected as the obligation becomes probable and the amount of the obligation can be reasonably estimated.

In fiscal 2022, the Kukio Resort Land Development Partnerships sold six lots in Increment I and as a result of the lot sales, made cash distributions to its partners of which Barnwell received $3,400,000 resulting in a net amount of $3,028,000, after distributing $372,000 to non-controlling interests.
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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 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 month-to-month a storage facility in Honolulu, Hawaii, and leases a one-acre maintenance and storage facility with 2,800 square feet of interior space in Kawaihae, Hawaii, and a one-half acre equipment storage yard in Waimea, Hawaii. Water Resources also maintains an inventory of uninstalled materials for jobs in progress and an inventory of drilling materials and pump supplies.

Water Resources currently operates in Hawaii and is not subject to seasonal fluctuations. 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, its officers’ involvement in the community 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.

During the year ended September 30, 2022, Water Resources sold a drilling rig and related ancillary equipment to an independent third party for proceeds of $687,000, net of related costs, which was equivalent to its net carrying value. No drilling rigs were sold in fiscal 2021.

In October 2022, Water Resources sold an additional drilling rig to an independent third party for proceeds of $551,000, net of related costs and accordingly, the Company will recognize a $551,000 gain on the sale of the drilling rig in the first quarter of fiscal 2023 ending December 31, 2022 as the rig was fully depreciated.
 
In fiscal 2022, Water Resources started two well drilling and four pump installation and repair contracts and completed three well drilling and three pump installation and repair contracts. Of the three
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completed well drilling contracts, one was started in fiscal 2018 and two were started in fiscal 2019. Of the three completed pump installation and repair contracts, one was started in fiscal 2016, one was started in fiscal 2020 and one was started in the current year. Fifty-two percent of well drilling and pump installation and repair jobs, representing 59% of total contract drilling revenues in fiscal 2022, have been pursuant to government contracts.

At September 30, 2022, there was a backlog of seven well drilling and 14 pump installation and repair contracts, of which four well drilling and 10 pump installation and repair contracts were in progress as of September 30, 2022.
 
The approximate dollar amount of Water Resources’ backlog of firm well drilling and pump installation and repair contracts at December 1, 2022 and 2021 was as follows:
  December 1,
  2022 2021
Well drilling $ 10,000,000  $ 8,000,000 
Pump installation and repair 1,200,000  1,500,000 
  $ 11,200,000  $ 9,500,000 
 
Of the contracts in backlog at December 1, 2022, $8,600,000 is expected to be recognized in fiscal 2023 with the remainder to be recognized in the following fiscal year.

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.
 
Competitive pressures are expected to remain high, thus there is no assurance that the quantity or values of available or awarded jobs which occurred in fiscal 2022 will continue.
 
Financial Information About Industry Segments and Geographic Areas

Note 11 in the “Notes to Consolidated Financial Statements” in Item 8 contains information on our segments and geographic areas.
 
Employees

At December 1, 2022, Barnwell employed 35 individuals; 34 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.
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These laws, which are constantly changing, regulate the discharge of materials into the environment and maintenance of surface conditions and may require Barnwell to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites where it has a working interest.
 
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

Our business operations and financial condition have been and may continue to be materially and adversely affected by the outbreak of novel strains of coronavirus.

In March 2020, the World Health Organization declared the COVID-19 outbreak a global pandemic and the U.S. and Canadian governments declared the virus a national emergency shortly thereafter. The ongoing global health crisis (including resurgences) resulting from the pandemic have, and continue to, disrupt the normal operations of many businesses, including the temporary closure or scale-back of business operations and/or the imposition of either quarantine or remote work or meeting requirements for employees, either by government order or on a voluntary basis. While the outbreak recently appeared to be trending downward, particularly as vaccination rates increased, new variants of COVID-19 continue emerging, including the Omicron variants, spreading throughout the U.S. and globally and causing significant disruptions. The global economy, our markets and our business have been, and may continue to be, materially and adversely affected by COVID-19.

The COVID-19 outbreak materially and adversely affected our business operations and financial condition as a result of the deteriorating market outlook, the global economic recession and weakened liquidity. Although demand for oil and oil prices has increased significantly from the lows of March through May of 2020, uncertainty regarding future oil prices continues to exist. While the Company’s contract drilling segment remained operational throughout fiscal 2020 and 2021 and continues to work, the continuing potential impact of COVID-19 on the health of our contract drilling segment's crews is uncertain, and any work stoppage or discontinuation of contracts currently in backlog could result in a material adverse impact to the Company’s financial condition and outlook. Though availability of vaccines and reopening of state and local economies has improved the outlook for recovery from COVID-19's impacts, the impact of new, more contagious or lethal variants that may emerge, and the effectiveness of COVID-19 vaccines against variants and the related responses by governments, including reinstated government-imposed lockdowns or other measures, cannot be predicted at this time. Both the health and economic aspects of the COVID-19 pandemic remain highly fluid and the future course of each is uncertain. We cannot foresee whether the outbreak of COVID-19 will be effectively contained on a sustained basis, nor can we predict the severity and duration of its impact. If the impact of COVID-19 is not effectively and timely controlled on a sustained basis going forward, our business operations and financial condition may be materially and adversely affected by factors that we cannot foresee. Any of these factors and other factors beyond our control could have an adverse effect on the overall business environment, cause uncertainties in the regions where we conduct business, cause our business to suffer in ways that we cannot predict and materially and adversely impact our business, financial condition and results of operations.

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There may be adverse effects on the value of your investment from our use of our Tax Benefits Preservation Plan.

In October 2022, subsequent to the end of our 2022 fiscal year, our Board of Directors adopted a Tax Benefits Preservation Plan designed to protect the availability of the Company’s existing net operating loss carryforwards and certain other tax attributes by discouraging persons or groups of persons from acquiring ownership of our common stock in a manner that could trigger an “ownership change” for purposes of Sections 382 and 383 of the Internal Revenue Code (the “Code”).

The Tax Benefits Preservation Plan may have an “anti-takeover effect” because it may deter a person or group of persons from acquiring beneficial ownership of 4.95% or more of our outstanding common stock or, in the case of a person or group of persons that already own 4.95% or more of our outstanding common stock, from acquiring any additional common stock. The Tax Benefits Preservation Plan could discourage or prevent a merger, tender offer, proxy contest or accumulations of substantial blocks of shares of our common stock, and, notwithstanding its purpose, could adversely affect our stockholders’ ability to realize a premium over the then-prevailing market price for our common stock in connection with any such transactions or actions. In addition, because our Board of Directors may consent to certain transactions, the Tax Benefits Preservation Plan gives our Board of Directors significant discretion over whether a potential acquirer’s efforts to acquire a large interest in us will be successful.

Additionally, a stockholder’s ability to dispose of our common stock may be limited if the Tax Benefits Preservation Plan reduces the number of persons willing to acquire our common stock or the amount they are willing to acquire. Thus, the Tax Benefits Preservation Plan could severely reduce liquidity of our common stock, negatively impacting the value of your investment. A stockholder also may become a greater than 4.95% stockholder upon actions taken by persons related to, or affiliated with, that stockholder. Stockholders are advised to carefully monitor their ownership of our common stock and consult their own legal advisors and/or us to determine whether their ownership of common stock approaches the proscribed level.

There can be no assurance that the Tax Benefits Preservation Plan will prevent an “ownership change” within the meaning of Sections 382 and 383 of the Code, in which case we may lose all or most of the anticipated tax benefits associated with our prior losses.

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 Chief Executive Officer.

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A small number of stockholders, including our CEO, own a significant amount of our common stock and may have influence over the Company.
 
As of September 30, 2022, the CEO, who is a member of the Board of Directors, and two other stockholders hold approximately 39% 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, levels of interest rates, and the cost of health care insurance premiums.

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.
  
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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.

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 the Sarbanes-Oxley Act, meaning our auditors are not required to attest to the effectiveness of the Company’s internal control over financial reporting. As a result, investors and others may be less comfortable with the effectiveness of the Company’s internal controls and the risk that material weaknesses or other deficiencies in internal controls go undetected may increase. In addition, as a smaller reporting company, we take advantage of our ability to provide certain other less comprehensive disclosures in our SEC filings, including, among other things, providing only two years of audited financial statements in annual reports and simplified executive compensation disclosures. Consequently, it may be more challenging for investors to analyze our results of operations and financial prospects, as the information we provide to stockholders may be different 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
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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 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.
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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.
 
Barnwell's oil and natural gas segment is subject to the provisions of the AER’s 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 five-year rolling spending targets which are currently forecasted by the AER to increase by approximately 9% per year. 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.
 
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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 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, 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
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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.
 
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.
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Actual revenues and operating expenses for our Oklahoma properties may differ from our estimates.

    As revenue and operating expense information from our royalty and non-operated working interest properties in Oklahoma are generally received several months after the production month, the Company accrues for revenue and operating expenses by estimating our share of production volumes and costs based on data provided by the operator of the properties and product spot prices, and are subsequently adjusted to actual amounts in the period of receipt of actual data. Any identified differences between estimated revenue and operating cost estimates and actual data historically have not been significant, however at this time there is limited history to date and thus there is no assurance that actual information will not vary significantly from our estimates.

SEC rules could limit our ability to book additional proved undeveloped reserves (“PUDs”) in the future.
 
    SEC rules require that, subject to limited exceptions, PUDs may only be booked if they relate to wells scheduled to be drilled within five years after the date of booking. This requirement may limit our ability to book PUDs as we pursue our drilling program.

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 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:
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•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 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; 67% in fiscal 2022.
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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.
 
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 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.

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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 I and KD II and cash distributions from the Kukio Resort Land Development Partnerships is dependent upon the developer’s continued efforts and ability to develop and market 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 I and 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 I and KD II, in which we own a non-controlling ownership interest, to continue to market the remaining lots within Increment I and 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 I and KD II, are also dependent on future lot sales in Increment I by KD I and 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 Increments I and II. We 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 and marketing 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.
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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.
 
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.

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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; 59% in fiscal 2022. 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, 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.
 
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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 2024.
 
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, 2020 $1.99 $0.76 December 31, 2021 $3.50 $2.30
March 31, 2021 $6.99 $1.25 March 31, 2022 $6.38 $2.38
June 30, 2021 $4.34 $2.02 June 30, 2022 $3.40 $2.29
September 30, 2021 $3.59 $2.00 September 30, 2022 $3.32 $2.12
 
Holders
 
As of December 9, 2022, there were 9,956,687 shares of common stock, par value $0.50, outstanding. As of December 9, 2022, there were approximately 80 shareholders of record and approximately 1,000 beneficial owners.
 
Dividends
 
In August 2022, the Company's Board of Directors declared a cash dividend of $0.015 per share that was paid on September 6, 2022 to stockholders of record on August 23, 2022. No dividends were declared or paid during fiscal 2021. The payment of future cash dividends will depend on, among other things, our financial condition, operating cash flows, the amount of cash inflows from land investment activities, 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.
 
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, 2022 and 2021, and the related Consolidated Statements of Operations, Comprehensive Income, Equity, and Cash Flows for the years ended September 30, 2022 and 2021. This discussion should be read in conjunction with the consolidated financial statements and related Notes to Consolidated Financial Statements included in this report.
 
Current Outlook
 
Impact of COVID-19

In March 2020, the World Health Organization declared the COVID-19 outbreak a global pandemic and the U.S. and Canadian governments declared the virus a national emergency shortly thereafter. The ongoing global health crisis (including resurgences) resulting from the pandemic have, and continue to, disrupt the normal operations of many businesses, including the temporary closure or scale-back of business operations and/or the imposition of either quarantine or remote work or meeting requirements for employees, either by government order or on a voluntary basis. While the outbreak recently appeared to be trending downward, particularly as vaccination rates increased, new variants of COVID-19 continue emerging, including the Omicron variants, spreading throughout the U.S. and globally and causing significant disruptions. The global economy, our markets and our business have been, and may continue to be, materially and adversely affected by COVID-19.
The COVID-19 outbreak materially and adversely affected our business operations and financial condition as a result of the deteriorating market outlook, the global economic recession and weakened liquidity. Although demand for oil and oil prices has increased significantly from the lows of March through May of 2020, uncertainty regarding future oil prices continues to exist. While the Company’s contract drilling segment remained operational throughout fiscal 2020 and 2021 and continues to work, the continuing potential impact of COVID-19 on the health of our contract drilling segment's crews is uncertain, and any work stoppage or discontinuation of contracts currently in backlog could result in a material adverse impact to the Company’s financial condition and outlook. Though availability of vaccines and reopening of state and local economies has improved the outlook for recovery from COVID-19's impacts, the impact of new, more contagious or lethal variants that may emerge, and the effectiveness of COVID-19 vaccines against variants and the related responses by governments, including reinstated government-imposed lockdowns or other measures, cannot be predicted at this time. Both the health and economic aspects of the COVID-19 pandemic remain highly fluid and the future course of each is uncertain. We cannot foresee whether the outbreak of COVID-19 will be effectively contained on a sustained basis, nor can we predict the severity and duration of its impact. If the impact of COVID-19 is not effectively and timely controlled on a sustained basis going forward, our business operations and financial condition may be materially and adversely affected by factors that we cannot foresee. Any of these factors and other factors beyond our control could have an adverse effect on the overall business environment, cause uncertainties in the regions where we conduct business, cause our business to suffer in ways that we cannot predict and materially and adversely impact our business, financial condition and results of operations.

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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, 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.
 
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
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44% 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 2022, the ceiling limitation would have decreased approximately $1,664,000 before income taxes, which would not have resulted in an increase in the ceiling impairment before income taxes due to sufficient room between the ceiling and the carrying value of oil and natural gas properties at the end of fiscal 2022 of approximately $20,064,000. The significant amount of room between the ceiling and the carrying value of oil and natural gas properties at the end of fiscal 2022 was due primarily to the fact that the carrying value was significantly reduced in prior years by impairment write-downs due to the extremely low average historical prices that were used in the ceiling test for those prior periods, whereas the prices used in the ceiling test at the end of fiscal 2022 reflects the significantly higher average historical prices used in that ceiling test.

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 2022, depletion for fiscal 2022 would have increased by approximately $129,000.

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 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
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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 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
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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.
 
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
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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 Oklahoma (oil and natural gas segment), 2) investing in 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 subsidiary BOK, Barnwell is indirectly involved in non-operated oil and natural gas investments in Oklahoma.
 
Barnwell sells all of its Canadian 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.
 
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
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located in the North Kona District of the island of Hawaii. Kaupulehu Developments is 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, of which two remained to be sold at September 30, 2022.

•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 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, of which two remained to be sold at September 30, 2022, as well as from commissions on real estate sales by the real estate sales office and revenues resulting from the sale of private club memberships.

•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.

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.

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Business Environment
 
Our operations are located in Canada and in the states of Hawaii and Oklahoma. 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 $86.73 per barrel during the year ended September 30, 2022, an increase of 68% from $51.74 per barrel realized during the prior year. Oil prices continue to be volatile over time and thus, the Company is unable to reasonably predict future oil prices and the impacts future oil prices will have on the Company.

Barnwell realized an average price for natural gas of $4.63 per Mcf during the year ended September 30, 2022, an increase of 77% from $2.62 per Mcf realized during the prior year.

Land Investment Segment

Future land investment payments and any future cash distributions from our investment in the Kukio Resort Land Development Partnerships are dependent upon the sale of the remaining two residential lots within Increment I by KD I and 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 our control, and there is no assurance with regards to the amounts of future sales of residential lots within Increments I and II. No definitive development plans have been made by 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. Management currently estimates that well drilling activity for fiscal 2023 is expected to be higher than fiscal 2022 based upon the number and value of contracts in backlog and anticipated job starts and durations.
 
Results of Operations
 
Summary
 
Net earnings attributable to Barnwell for fiscal 2022 totaled $5,513,000, a $740,000 decrease in operating results from net earnings of $6,253,000 in fiscal 2021. The following factors affected the results of operations for the current fiscal year as compared to the prior fiscal year:

•In the prior year period, the Company recognized $4,472,000 in gains that did not occur in fiscal 2022, which included a $2,341,000 gain from the termination of the Company's Post-retirement Medical plan, $1,982,000 in gains from the sales of assets, and a $149,000 gain on debt extinguishment;

•An $8,113,000 improvement in oil and natural gas segment operating results, before income taxes, due primarily to a significant increase in oil and natural gas prices in the current period
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as compared to the same period in the prior year and new production from wells drilled in Oklahoma. Also contributing to the increase was a ceiling test impairment of $630,000 in the prior year period, whereas there was no such ceiling test impairment in the current year period;

•Equity in income from affiliates decreased $2,393,000 and land investment segment operating results, before non-controlling interests’ share of such profits, decreased $532,000 due to the Kukio Resort Development Partnerships' sale of six lots in the current year period, whereas there were eight lot sales in the prior year period;

•General and administrative expenses increased $956,000 primarily due to increases in professional fees in the current year period as compared to the same period in the prior year, partially offset by a decrease in stockholder costs in the prior year period as compared to the current year period; and

•A $484,000 foreign currency loss recorded in the current year period due to the effects of foreign exchange rate changes on intercompany loans and advances as a result of the strengthening of the U.S. dollar against the Canadian dollar.

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 2022, as compared to fiscal 2021, and the exchange rate of the Canadian dollar to the U.S. dollar decreased 7% at September 30, 2022, as compared to September 30, 2021. Accordingly, the assets, liabilities, stockholders’ equity and revenues and expenses of Barnwell’s subsidiaries operating in Canada have been 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 2022 was $40,000, a $243,000 change from other comprehensive loss due to foreign currency translation adjustments, net of taxes, of $283,000 in fiscal 2021. There were no taxes on other comprehensive loss due to foreign currency translation adjustments in fiscal 2022 and 2021 due to a full valuation allowance on the related deferred tax assets.
 
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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 2022 as compared to fiscal 2021. Production amounts reported are net of royalties.
 
  Annual Average Price Per Unit
      Increase (Decrease)
  2022 2021 $ %
Natural gas (Mcf)* $ 4.63  $ 2.62  $ 2.01  77%
Oil (Bbls) $ 86.73  $ 51.74  $ 34.99  68%
Natural gas liquids (Bbls) $ 48.06  $ 31.92  $ 16.14  51%
 
  Annual Net Production
      Increase (Decrease)
  2022 2021 Units %
Natural gas (Mcf) 964,000  694,000  270,000  39%
Oil (Bbls) 182,000  147,000  35,000  24%
Natural gas liquids (Bbls) 48,000  24,000  24,000  100%
_________________________________________________
*      Natural gas price per unit is net of pipeline charges.
 
The oil and natural gas segment generated a $10,536,000 operating profit in fiscal 2022 before general and administrative expenses, an increase in operating results of $8,113,000 as compared to $2,423,000 of operating profit in fiscal 2021. There was no ceiling test impairment during the year ended September 30, 2022 and a $630,000 ceiling test impairment during the year ended September 30, 2021.

Our Oklahoma operations generated $2,667,000 (25%) of our oil and natural gas segment operating profits for the year ended September 30, 2022 as compared to $80,000 (3%) of our oil and natural gas segment operating profits for the year ended September 30, 2021.

Oil and natural gas revenues increased $12,327,000 (120%) from $10,254,000 in fiscal 2021 to $22,581,000 in fiscal 2022, primarily due to significant increases in oil, natural gas and natural gas liquids prices as compared to the same period in the prior year. Additionally, production increased due to new wells drilled in the Twining area and Oklahoma, as well as due to additional working interests acquired in the Twining area. The increase in net production from Canadian areas was partially offset by an increase in royalty rates attributed to the increase in commodity prices.
 
Oil and natural gas operating expenses increased $2,883,000 (44%) from $6,556,000 in fiscal 2021 to $9,439,000 in fiscal 2022, primarily due to production from the new wells drilled in the Twining area and Oklahoma, as well as due to additional working interests acquired in the Twining area. The increase was also partially attributable to workovers, repairs, higher utilities and hauling costs, and restart costs for certain acquired wells, as well as to the remediation of a minor pipeline leak.
 
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    Oil and natural gas segment depletion increased $1,961,000 (304%) from $645,000 in fiscal 2021 to $2,606,000 in fiscal 2022, primarily due to increases in the depletion rate for Canadian properties and also new production from those properties, both of which were the result of the drilling of new wells, acquisition of additional working interests, and facilities expansion and upgrade costs, all in the Twining area. The increase also was due to increased depletion from production in Oklahoma, whereas there was only a minor amount of such depletion in the prior year period.

All seven non-operated wells in Oklahoma were producing during the year ended September 30, 2022. The Company’s share of net production from these wells plus another well with a minor overriding royalty interest totaled 42,000 barrels of oil and natural gas liquids and 192,000 Mcf of natural gas for total revenues of $3,496,000 during the year ended September 30, 2022. Our Oklahoma production is from shale oil wells that typically have steep production declines and accordingly, we estimate that their production will continue to decline significantly.

Oil prices continue to be volatile over time and thus, the Company is unable to reasonably predict future oil, natural gas and natural gas liquids prices and the impacts future prices will have on the Company.

Sale of interest in leasehold land
 
Kaupulehu Developments is 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,
  2022 2021
Sale of interest in leasehold land:    
Revenues - sale of interest in leasehold land $ 1,295,000  $ 1,738,000 
Fees - included in general and administrative expenses (158,000) (212,000)
Sale of interest in leasehold land, net of fees paid $ 1,137,000  $ 1,526,000 
 
During the year ended September 30, 2022, Barnwell received $1,295,000 in percentage of sales payments from KD I from the sale of six single-family lots within Increment I. During the year ended September 30, 2021, Barnwell received $1,738,000 in percentage of sales payments from KD I from the sale of eight single-family lots within Increment I.

In November 2022, Kaupulehu Developments received a percentage of sales payment of $265,000 from the sale of one lot within Increment I. Financial results from the receipt of this payment will be reflected in Barnwell's first quarter of fiscal 2023 ending December 31, 2022. Accordingly, with the inclusion of the lot sale subsequent to September 30, 2022, one single-family lot of the 80 lots developed within Increment I remained to be sold as of the date of this report. The Company does not have a controlling interest in Increments I and II, and there is no assurance with regards to the amounts of future sales from Increments I and II, or that the remaining acreage within Increment II will be developed. No definitive development plans have been made by the developer of Increment II as of the date of this report.
  
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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 $1,269,000 (22%) to $4,540,000 in fiscal 2022, as compared to $5,809,000 in fiscal 2021, and contract drilling costs decreased $964,000 (17%) to $4,591,000 in fiscal 2022, as compared to $5,555,000 in fiscal 2021. The contract drilling segment generated a $222,000 operating loss before general and administrative expenses during fiscal 2022, a decrease in operating results of $133,000 as compared to an operating loss before general and administrative expenses of $89,000 in fiscal 2021. The decrease in contract drilling revenues, costs, and operating results for the year ended September 30, 2022 is due to decreased water well drilling activity in the current year period as compared to the same period in the prior year, primarily due to a significant well drilling contract in a portion of the prior year period, which was essentially completed as of December 31, 2020 and thus, did not contribute to operating results from that point forward.

At September 30, 2022, there was a backlog of seven well drilling and 14 pump installation and repair contracts, of which four well drilling and 10 pump installation and repair contracts were in progress as of September 30, 2022. The backlog of contract drilling revenues as of December 1, 2022 was approximately $11,200,000, of which $8,600,000 is expected to be realized in fiscal 2023 with the remainder to be recognized in the following fiscal year. Based on these contracts in backlog, contract drilling segment operating results are estimated to be higher in fiscal 2023 as compared to fiscal 2022.

In the quarter ended December 31, 2021, it was determined that a contract drilling segment well completed in the period did not meet the contract specifications for plumbness under a gyroscopic plumbness test which the contract required. While the well did pass the cage plumbness test, the contract uses the gyroscopic test as the measure of plumbness. Barnwell and the customer currently have an arrangement where Barnwell will provide for centralizers, armored cabling and a pump installation and removal test to confirm that plumbness is satisfactory. Barnwell’s management believes the plumbness deviation is not impactful to the performance of the submersible pumps that will be installed in the well. Accordingly, while costs for the centralizers, armored cabling and the pump installation and removal test have been accrued, no accrual has been recorded as of September 30, 2022 for any further costs related to this contract as there is no related probable or estimable contingent liability.

There has been a significant decrease in demand for water well drilling contracts in recent years that has generally led to increased competition for available contracts and lower margins on awarded contracts. The Company is unable to predict the near-term and long-term availability of water well drilling and pump installation and repair contracts as a result of this volatility in demand. The continuing potential impact of COVID-19 on the health of our contract drilling segment's crew is uncertain, and any work stoppage or discontinuation of contracts currently in backlog due to COVID-19 impacts could result in a material adverse impact to the Company’s financial condition and outlook.

General and administrative expenses
 
General and administrative expenses increased $956,000 (13%) to $8,044,000 in fiscal 2022, as compared to $7,088,000 in fiscal 2021. The increase was primarily due to increases of $1,245,000 in professional fees primarily related to legal and consulting services and $65,000 in director fees in the current year period as compared to the same period in the prior year, partially offset by a reduction of $191,000 in pension and post-retirement medical plan costs and $296,000 in stockholder costs related to
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the cooperation and support agreement executed with the MRMP Stockholders in the prior year period as compared to the current year period.
 
Depletion, depreciation, and amortization
 
Depletion, depreciation, and amortization increased $1,815,000 (188%) from $963,000 in fiscal 2021 to $2,778,000 in fiscal 2022, primarily due to increases in the depletion rate for Canadian properties and also new production from those properties, both of which were the result of the drilling of new wells, acquisition of additional working interests, and facilities expansion and upgrade costs, all in the Twining area. The increase was also due to increased depletion from production in Oklahoma, whereas there was only a minor amount of such depletion in the prior year period.

Impairment of assets

Under the full cost method of accounting, the Company performs quarterly oil and natural gas ceiling test calculations. There was no ceiling test impairment during the year ended September 30, 2022 and a $630,000 ceiling test impairment during the year ended September 30, 2021.
    
Changes in the mandated 12-month historical rolling average first-day-of-the-month prices for oil, natural gas and natural gas liquids prices, 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 estimated market value of unproved properties, impact the determination of the maximum carrying value of oil and natural gas properties.

In September 2022, the Company determined that the right-of-use asset related to the operating lease for the Lot 4C leasehold land zoned conservation held by Kaupulehu Developments was fully impaired as of September 30, 2022. As a result, the Company recognized an $89,000 right-of-use asset impairment expense during the year ended September 30, 2022. The operating lease terminates in December 2025.

In September 2021, the Company designated a contract drilling segment drilling rig and related ancillary equipment, with an aggregate net carrying value of $725,000, as assets held for sale and recorded an impairment of $38,000 to reduce the value of these assets to its fair value, less estimated selling costs. The impairment expense was included in the “Impairment of assets” line item in the accompanying Consolidated Statements of Operations for the year ended September 30, 2021.

Foreign currency loss

Foreign currency loss was $484,000 during the year ended September 30, 2022, as compared to none during the year ended September 30, 2021 due to the effects of foreign exchange rate changes on intercompany loans and advances as a result of the strengthening of the U.S. dollar against the Canadian dollar. The foreign currency loss from intercompany balances was included in our consolidated net earnings 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 termination of Post-Retirement Medical plan

    In June 2021, the Company terminated its Post-retirement Medical plan, which covered officers of the Company who had attained at least 20 years of service of which at least 10 years were at the position
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of Vice President or higher, their spouses and qualifying dependents, effective June 4, 2021. The Post-retirement Medical plan was an unfunded plan and the Company funded benefits when payments were made. As result of the plan termination, the Company recognized a non-cash gain of $2,341,000 during the year ended September 30, 2021.

Gain on sale of assets

In July 2021, Barnwell 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 Spirit River area of Alberta, Canada. The sales price per the agreement was adjusted for customary purchase price adjustments to $1,047,000 in order to, among other things, reflect an economic effective closing date of sale of July 8, 2021. Income taxes were withheld by the buyers from Barnwell's net proceeds for potential amounts due to the Canada Revenue Agency related to the sale, and the amount was subsequently refunded to Barnwell in fiscal 2022.

The difference in the relationship between capitalized costs and proved reserves of the Spirit River properties sold, as compared to the properties retained by Barnwell, was significant as there was a 93% difference in capitalized costs divided by proved reserves if the gain was recorded versus the gain being credited against the full-cost pool. Accordingly, Barnwell recorded a gain on the sale of Spirit River of $818,000 in the year ended September 30, 2021 in accordance with the guidance in Rule 4-10(c)(6)(i) of Regulation S-X of the rules and regulations of the SEC, which requires an allocation of capitalized costs to the reserves sold and reserves retained on the basis of the relative fair values of the properties as there was a substantial economic difference between the properties sold and those retained. Also included in the gain calculation were asset retirement obligations of $77,000 assumed by the purchaser.

In September 2021, the Company’s Honolulu corporate office was sold for approximately $1,864,000, net of related costs, resulting in a gain of $1,164,000, which was recognized in the year ended September 30, 2021.  

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 $3,400,000 for the year ended September 30, 2022, as compared to equity in income of affiliates of $5,793,000 for the year ended September 30, 2021. The decrease in partnership income is primarily due to the Kukio Resort Land Development Partnerships' sale of eight lots during the prior year period, as compared to six lot sales in the current year period, and $459,000 in preferred return payments received from KKM in the prior year period as compared to none in the current year period.

During the year ended September 30, 2022, Barnwell received cash distributions of $3,400,000 from the Kukio Resort Land Development Partnership resulting in a net amount of $3,028,000, after distributing $372,000 to non-controlling interests. During the year ended September 30, 2021, Barnwell received net cash distributions in the amount of $6,011,000 from the Kukio Resort Land Development Partnerships after distributing $683,000 to non-controlling interests. Of the $6,011,000 net cash distribution received from the Kukio Resort Land Development Partnerships, $459,000 represented a payment of the preferred return from KKM, as discussed in Note 3 of the Notes to Consolidated Financial Statements.

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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 Partnership 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 Partnership’s cumulative earnings in excess of distributions during the suspended period exceeds our share of the Kukio Resort Land Development Partnership’s 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, 2022 was equivalent to the $3,400,000 of distributions received in that period.

Cumulative distributions received from the Kukio Resort Land Development Partnerships in excess of our investment balance was $958,000 at September 30, 2022 and $654,000 at September 30, 2021.

In November 2022, Barnwell received a net cash distribution in the amount of $478,000 from the Kukio Resort Land Development Partnerships. Financial results from this distribution will be reflected in Barnwell's first quarter of fiscal 2023 ending December 31, 2022.

Additionally, in November 2022, Kaupulehu Developments received a percentage of sales payment of $265,000 from the sale of one lot within Increment I. Financial results from the receipt of this payment will be reflected in Barnwell's first quarter of fiscal 2023 ending December 31, 2022. Accordingly, with the inclusion of the lot sale subsequent to September 30, 2022, one single-family lot of the 80 lots developed within Increment I remained to be sold as of the date of this report. The Company does not have a controlling interest in Increments I and II, and there is no assurance with regards to the amounts of future sales from Increments I and II, or that the remaining acreage within Increment II will be developed. No definitive development plans have been made by the developer of Increment II as of the date of this report.

Income taxes
 
The components of earnings before income taxes, after adjusting the earnings for non-controlling interests, are as follows:
  Year ended September 30,
  2022 2021
United States $ 739,000  $ 5,436,000 
Canada 5,121,000  1,149,000 
  $ 5,860,000  $ 6,585,000 
 
Barnwell’s effective consolidated income tax rate for fiscal 2022, after adjusting earnings before income taxes for non-controlling interests, was 6% as compared to 5% for fiscal 2021.
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.
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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. 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, and therefore, receives no benefit from consolidated or unitary losses and, therefore, is subject to Oklahoma state taxes.
In addition, net operating loss carryforwards, all of which had a full valuation allowance at the end of the previous fiscal year, are being partially utilized in the current year to offset taxable income in the U.S. federal and Canadian jurisdictions. The net operating loss carryforwards beyond the current year’s utilization continue to have a full valuation allowance as realization of their benefit is not more likely than not.
Included in the current income tax provision for the year ended September 30, 2022 is a $62,000 expense for income tax penalties and interest thereon for the non-filing of IRS Form 8858 in each of our U.S. federal income tax returns for fiscal years 2019, 2020 and 2021. The Company is in the process of amending its U.S. federal tax returns to include Form 8858 and plans to request abatement of the potential penalties and interest. There was no such expense included in the current income tax provision for the year ended September 30, 2021.
On June 28, 2019, the Government of Alberta reduced its corporate income tax rate from 12% to 11%, effective July 1, 2019, with further reductions in the rate by 1% on January 1 of every year until it reaches 8% on January 1, 2022. On June 29, 2020, the Government of Alberta introduced Alberta’s Recovery Plan which will, among other things, reduce Alberta’s general corporate income tax rate to 8% (from 10%) effective July 1, 2020. This reduction was enacted in the quarter ended December 31, 2020. Canadian deferred tax assets and liabilities have been measured using the enacted tax rates in effect for the year in which the differences are expected to reverse. Alberta rate changes had no significant impact to earnings/loss as a result of a full valuation allowance being applied to Canadian deferred tax assets.
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 $659,000 in fiscal 2022, as compared to net earnings attributable to non-controlling interests of $950,000 in fiscal 2021. The $291,000 (31%) decrease is primarily due to decreases 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.

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Impact of Recently Issued Accounting Standards on Future Filings
  
In June 2016, the Financial Accounting Standards Board (“FASB”) issued 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. This ASU is effective for annual reporting periods beginning after December 15, 2022, and interim periods within those annual periods. The FASB has subsequently issued other related ASUs which amend ASU 2016-13 to provide clarification and additional guidance. The Company is currently evaluating the impact of these standards.

Liquidity and Capital Resources
 
Barnwell’s primary sources of liquidity are cash on hand, cash flow generated by operations, and land investment segment proceeds. Prior to the suspension of the at-the-market offering program (“ATM”) in August 2022, the Company received $2,356,000 in net proceeds from the shares of common stock sold under the ATM in fiscal 2022. At September 30, 2022, Barnwell had $11,170,000 in working capital.
 
Cash Flows
 
Cash flows provided by operating activities totaled $7,291,000 for fiscal 2022, as compared to cash flows provided by operating activities of $831,000 for the same period in fiscal 2021. This $6,460,000 change in operating cash flows was primarily due to significantly higher operating results for the oil and natural gas segment, which was partially offset by lower operating results for the contract drilling segment and a decrease in distributions from the Kukio Resort Land Development Partnerships in the current year period as compared to the prior year period. The change was also due to fluctuations in working capital.

Cash flows used in investing activities totaled $7,112,000 for fiscal 2022, as compared to cash flows provided by investing activities of $3,686,000 for fiscal 2021. This $10,798,000 change in investing cash flows was primarily due to an increase of $1,215,000 in payments to acquire oil and natural gas properties, an increase of $7,084,000 in cash paid for oil and natural gas capital expenditures, a decrease of $1,419,000 received in distributions from equity investees in excess of earnings, and a net decrease of $1,177,000 in proceeds from the sale of assets in the current year period as compared to same period in the prior year.

Cash flows provided by financing activities totaled $1,560,000 for fiscal 2022, as compared to cash flows provided by financing activities of $2,192,000 for fiscal 2021. The $632,000 change in financing cash flows was primarily attributed to a decrease of $823,000 in proceeds from issuance of stock, net of costs, related to the Company's ATM offering, a $149,000 increase in dividend payments, and a decrease of $387,000 in distributions to non-controlling interests in the current year period as compared to the same period in the prior year.

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Cash Dividend

In August 2022, the Company's Board of Directors declared a cash dividend of $0.015 per share that was paid on September 6, 2022 to stockholders of record on August 23, 2022.

Canada Emergency Business Account Loan

In the quarter ended December 31, 2020, the Company’s Canadian subsidiary, Barnwell of Canada, received a loan of CAD$40,000 (in Canadian dollars) under the Canada Emergency Business Account (“CEBA”) loan program for small businesses. In the quarter ended March 31, 2021, the Company applied for an increase to our CEBA loan and received an additional CAD$20,000 for a total loan amount received of CAD$60,000 ($44,000) under the program. In January 2022, the Canadian government announced the extension of the CEBA loan repayment deadline and interest-free period from December 31, 2022 to December 31, 2023. Accordingly, the CEBA loan is interest-free with no principal payments required until December 31, 2023, after which the remaining loan balance is converted to a two year term loan at 5% annual interest paid monthly. If the Company repays 66.7% of the principal amount prior to December 31, 2023, there will be loan forgiveness of 33.3% up to a maximum of CAD$20,000.

Paycheck Protection Program Loan

In April 2020, the Company, as obligor, entered into a promissory note evidencing an unsecured loan in the approximate amount of $147,000 under the Paycheck Protection Program (“PPP”) pursuant to the Coronavirus Aid, Relief, and Economic Security Act. The note was to mature two years after the date of the loan disbursement with interest at a fixed annual rate of 1.00% and with the principal and interest payments deferred until ten months after the last day of the covered period. In April 2021, the Company was notified by the lender of our PPP loan that the entire PPP loan amount and related accrued interest was forgiven by the Small Business Administration. As a result of the loan forgiveness, the Company recognized a gain on debt extinguishment of $149,000 during the year ended September 30, 2021.

At The Market Offering

On March 16, 2021, the Company entered into a Sales Agreement (the “Sales Agreement”) with A.G.P./Alliance Global Partners (“A.G.P,”), with respect to the ATM pursuant to which the Company may offer and sell, from time to time, shares of its common stock, par value $0.50 per share, having an aggregate sales price of up to $25 million (subject to certain limitations set forth in the Sales Agreement and applicable securities laws, rules and regulations), through or to A.G.P as the Company’s sales agent or as principal. Sales of our common stock under the ATM, if any, will be made by any methods deemed to be “at the market offerings” as defined in Rule 415(a)(4) under the Securities Act, including sales made directly on the NYSE American, on any other existing trading market for our Common Stock, or to or through a market maker. Shares of common stock sold under the ATM are offered pursuant to the Company’s Registration Statement on Form S-3 (File No. 333-254365), filed with the Securities and Exchange Commission on March 16, 2021, and declared effective on March 26, 2021 (the "Registration Statement”), and the prospectus dated March 26, 2021, included in the Registration Statement.

During the year ended September 30, 2022, the Company sold 509,467 shares of common stock resulting in net proceeds of $2,356,000 after commissions and fees of $75,000 and ATM-related professional services of $22,000. During the year ended September 30, 2021, the Company sold 1,167,987 shares of common stock resulting in net proceeds of $3,179,000 after commissions and fees of $123,000 and ATM-related professional services of $605,000.
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As of September 30, 2022, the Company has received $5,535,000 in cumulative net proceeds from the shares sold under the ATM program. In August 2022, the Company’s Board of Directors suspended the sales of our common stock under the ATM until further notice.

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, increased $8,835,000 from $2,217,000 in fiscal 2021 to $11,052,000 in fiscal 2022.
 
The Company participated in the drilling of six gross (1.7 net) non-operated wells in the Twining area during the year ended September 30, 2022. Capital expenditures incurred by the Company for these non-operated wells totaled $4,366,000 for the year ended September 30, 2022. Five gross (1.4 net) wells were producing at September 30, 2022 and the remaining one gross (0.3 net) well is awaiting tie in and is expected to produce in fiscal 2023. The Company drilled one gross (1.0 net) operated 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 Canada during the year ended September 30, 2021.

The Company did not drill or participate in the drilling of wells in Oklahoma during the year ended September 30, 2022. In fiscal 2021, the Company participated in the drilling of seven gross (0.2 net) non-operated wells in Oklahoma. Capital expenditures incurred by the Company for these Oklahoma wells totaled $1,178,000 for the year ended September 30, 2021.

Oil and Natural Gas Property Acquisitions and Dispositions 

Acquisitions

    In the quarter ended December 31, 2021, Barnwell acquired working interests in oil and natural gas properties located in the Twining area of Alberta, Canada, for cash consideration of $317,000.

In January 2022, Barnwell acquired additional working interests in oil and natural gas properties located in the Twining area of Alberta, Canada for consideration of $1,246,000. The purchase price per the agreement was adjusted for customary purchase price adjustments to reflect the economic activity from the effective date to the closing date. 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. Barnwell also assumed $1,500,000 in asset retirement obligations associated with the acquisition.

In April 2021, Barnwell acquired additional working interests in oil and natural gas properties located in the Twining area of Alberta, Canada for cash consideration of $348,000. The purchase price per the agreement was adjusted for customary purchase price adjustments to reflect the economic activity from the effective date to the closing date.

Dispositions

There were no significant oil and natural gas property dispositions during the year ended September 30, 2022. The $503,000 of proceeds from sale of oil and natural gas properties included in the Consolidated Statement of Cash Flows for the year ended September 30, 2022 primarily represents the
53


refund of income taxes previously withheld from what otherwise would have been proceeds on prior year's oil and natural gas property sales.

In April 2021, Barnwell entered into a purchase and sale agreement with an independent third party and sold its interests in properties located in the Hillsdown area of Alberta, Canada. The sales price per the agreement was adjusted for customary purchase price adjustments to $132,000 in order to, among other things, reflect an economic effective date of October 1, 2020. $72,000 of the sales proceeds was withheld by the buyers for potential amounts due for Barnwell’s Canadian income taxes related to the sale. 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 2021, Barnwell 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 Spirit River area of Alberta, Canada. The sales price per the agreement was adjusted for customary purchase price adjustments to $1,047,000 in order to, among other things, reflect an economic effective closing date of sale of July 8, 2021. Income taxes were withheld by the buyers from Barnwell's net proceeds for potential amounts due to the Canada Revenue Agency related to the sale, and the amount was subsequently refunded to Barnwell in fiscal 2022.

The difference in the relationship between capitalized costs and proved reserves of the Spirit River properties sold, as compared to the properties retained by Barnwell, was significant as there was a 93% difference in capitalized costs divided by proved reserves if the gain was recorded versus the gain being credited against the full-cost pool. Accordingly, Barnwell recorded a gain on the sale of Spirit River of $818,000 in the year ended September 30, 2021 in accordance with the guidance in Rule 4-10(c)(6)(i) of Regulation S-X of the rules and regulations of the SEC, which requires an allocation of capitalized costs to the reserves sold and reserves retained on the basis of the relative fair values of the properties as there was a substantial economic difference between the properties sold and those retained. Also included in the gain calculation were asset retirement obligations of $77,000 assumed by the purchaser.

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.

Recently, the OWA created a WIP program for specific areas where there are a significant number of orphaned wells to abandon. The OWA has the ability and expertise to abandon wells using its internal resources and network of service providers resulting in efficiencies that companies such as Barnwell, would not be able to obtain on its own. Under the WIP program, the Company would be required to provide payment for only Barnwell’s working interest share, however, all WIP’s would have to participate in the program for the OWA to begin its work. In March 2021, the Company was notified by the OWA that Barnwell’s Manyberries wells were confirmed to be in the WIP program.

Under the new agreement with the OWA, the Company is required to pay the abandonment and reclamation costs in advance through a cash deposit. The total cash deposit amount was calculated to be approximately $1,525,000 and the Company paid $888,000 of the total deposit in July and August 2021 and will need to pay the remaining balance of $637,000 by August 2023. The Company revised its
54


Manyberries ARO liability based on the OWA’s revised abandonment and reclamation estimates, which resulted in an increase of approximately $213,000 in the year ended September 30, 2021. The increase in the ARO liability was a result of higher reclamation and remediation costs than anticipated, partially offset by lower abandonment estimates. Based on a review of the details of the cash deposit calculation provided by the OWA, which includes amounts added for possible contingencies, the Company believes the required cash deposit amount by the OWA is higher than the actual costs of the asset retirement obligation for the Manyberries wells and that any excess of the deposit over actual asset retirement costs for the first phase of the work would be credited toward the second phase of the work. A remaining excess deposit, if any, would ultimately be refunded to the Company upon completion of all of the work. As of September 30, 2022, the Company recognized a cumulative reduction in the deposit balance of $113,000 for work performed under this program.
 
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.
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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, 2022 and 2021, and the related consolidated statements of operations, comprehensive income (loss), equity (deficit), and cash flows for the years then ended, 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, 2022 and 2021, and the results of its operations and its cash flows for the years then ended, 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 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
56


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 properties using the full cost method of accounting which requires management to make estimates of proved reserve volumes and future revenues and expenses to calculate depletion expense and measure its oil and gas properties for potential impairment. To estimate the volume of proved reserves and future revenues, management makes significant estimates and assumptions, including forecasting the production decline rate of producing properties and forecasting the timing and volume of production associated with the Company’s development plan for proved undeveloped properties. In addition, the estimation of proved reserves is also impacted by management’s judgments and estimates regarding the 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 the estimation of depletion expense and potential impairment measurements. We identified the estimation of proved reserves of oil and gas properties, due to its impact on depletion expense and impairment evaluation, 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,
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◦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;
◦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.

Dallas, Texas
December 29, 2022



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BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
  September 30,
  2022 2021
ASSETS    
Current assets:    
Cash and cash equivalents $ 12,804,000  $ 11,279,000 
Accounts and other receivables, net of allowance for doubtful accounts of: $231,000 at September 30, 2022; $391,000 at September 30, 2021
 4,361,000  3,069,000 
Income taxes receivable —  530,000 
Assets held for sale —  687,000 
Other current assets 2,932,000  2,470,000 
Total current assets 20,097,000  18,035,000 
Asset for retirement benefits 3,385,000  2,229,000 
Operating lease right-of-use assets 132,000  296,000 
Oil and natural gas properties, full cost method of accounting:
Proved properties, net 13,232,000  2,423,000 
Unproved properties —  962,000 
Total oil and natural gas properties, net 13,232,000  3,385,000 
Drilling rigs and other property and equipment, net 369,000  490,000 
Total assets $ 37,215,000  $ 24,435,000 
LIABILITIES AND EQUITY    
Current liabilities:    
Accounts payable $ 1,462,000  $ 1,416,000 
Accrued capital expenditures 1,655,000  909,000 
Accrued compensation 999,000  1,073,000 
Accrued operating and other expenses 1,576,000  1,171,000 
Current portion of asset retirement obligation 1,327,000  713,000 
Other current liabilities 1,908,000  619,000 
Total current liabilities 8,927,000  5,901,000 
Long-term debt 44,000  47,000 
Operating lease liabilities 117,000  180,000 
Liability for retirement benefits 1,649,000  2,101,000 
Asset retirement obligation 7,129,000  6,340,000 
Deferred income tax liabilities 188,000  359,000 
Total liabilities 18,054,000  14,928,000 
Commitments and contingencies (Note 17)
Equity:    
Common stock, par value $0.50 per share; authorized, 40,000,000 shares:
    
10,124,587 issued at September 30, 2022; 9,613,525 issued at September 30, 2021
 5,062,000  4,807,000 
Additional paid-in capital 7,351,000  4,590,000 
Retained earnings 7,720,000  2,356,000 
Accumulated other comprehensive income, net 1,294,000  32,000 
Treasury stock, at cost:    
167,900 shares at September 30, 2022 and 2021
 (2,286,000) (2,286,000)
Total stockholders’ equity 19,141,000  9,499,000 
Non-controlling interests 20,000  8,000 
Total equity 19,161,000  9,507,000 
Total liabilities and equity $ 37,215,000  $ 24,435,000 
See Notes to Consolidated Financial Statements 
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BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
 
  Year ended September 30,
  2022 2021
Revenues:    
Oil and natural gas $ 22,581,000  $ 10,254,000 
Contract drilling 4,540,000  5,809,000 
Sale of interest in leasehold land 1,295,000  1,738,000 
Gas processing and other 129,000  312,000 
  28,545,000  18,113,000 
Costs and expenses:    
Oil and natural gas operating 9,439,000  6,556,000 
Contract drilling operating 4,591,000  5,555,000 
General and administrative 8,044,000  7,088,000 
Depletion, depreciation, and amortization 2,778,000  963,000 
Impairment of assets 89,000  668,000 
Foreign currency loss 484,000  — 
Interest expense 1,000  13,000 
Gain on debt extinguishment —  (149,000)
Gain on termination of post-retirement medical plan —  (2,341,000)
Gain on sale of assets —  (1,982,000)
  25,426,000  16,371,000 
Earnings before equity in income of affiliates and income taxes 3,119,000  1,742,000 
Equity in income of affiliates 3,400,000  5,793,000 
Earnings before income taxes 6,519,000  7,535,000 
Income tax provision 347,000  332,000 
Net earnings 6,172,000  7,203,000 
Less: Net earnings attributable to non-controlling interests 659,000  950,000 
Net earnings attributable to Barnwell Industries, Inc. stockholders $ 5,513,000  $ 6,253,000 
Basic net earnings per common share    
attributable to Barnwell Industries, Inc. stockholders $ 0.57  $ 0.73 
Diluted net earnings per common share    
attributable to Barnwell Industries, Inc. stockholders $ 0.57  $ 0.73 
Weighted-average number of common shares outstanding:    
Basic 9,732,936  8,592,154 
Diluted 9,732,936  8,592,154 

See Notes to Consolidated Financial Statements

 
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BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
 
  Year ended September 30,
  2022 2021
Net earnings $ 6,172,000  $ 7,203,000 
Other comprehensive (loss) income:    
Foreign currency translation adjustments, net of taxes of $0
 (40,000) (283,000)
Retirement plans:    
Amortization of accumulated other comprehensive loss into net periodic benefit cost, net of taxes of $0
 —  101,000 
Net actuarial gain arising during the period, net of taxes of $0
 1,302,000  1,108,000 
Gain on termination of post-retirement medical plan, net of taxes of $0
 —  541,000 
Total other comprehensive income 1,262,000  1,467,000 
Total comprehensive income 7,434,000  8,670,000 
Less: Comprehensive income attributable to non-controlling interests (659,000) (950,000)
Comprehensive income attributable to Barnwell Industries, Inc. $ 6,775,000  $ 7,720,000 

See Notes to Consolidated Financial Statements
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BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF EQUITY
Years ended September 30, 2022 and 2021 
Shares
Outstanding		 Common
Stock		 Additional
Paid-In
Capital		 Retained
Earnings (Accumulated Deficit)		 Accumulated
Other
Comprehensive Income (Loss)		 Treasury
Stock		 Non-controlling
Interests		 Total
Equity
(Deficit)
Balance at September 30, 2020 8,277,160  $ 4,223,000  $ 1,350,000  $ (3,897,000) $ (1,435,000) $ (2,286,000) $ 92,000  $ (1,953,000)
Net earnings —  —  —  6,253,000  —  —  950,000  7,203,000 
Foreign currency translation adjustments, net of taxes of $0
 —  —  —  —  (283,000) —  —  (283,000)
Distributions to non-controlling interests —  —  —  —  —  —  (1,034,000) (1,034,000)
Share-based compensation —  —  643,000  —  —  —  —  643,000 
Issuance of common stock, net of costs 1,167,987  583,000  2,596,000  —  —  —  —  3,179,000 
Issuance of common stock for services 478  1,000  1,000  —  —  —  —  2,000 
Retirement plans:    
Amortization of accumulated other comprehensive loss into net periodic benefit cost, net of taxes of $0
 —  —  —  —  101,000  —  —  101,000 
Net actuarial gain arising during the period, net of taxes of $0
 —  —  —  —  1,108,000  —  —  1,108,000 
Gain on termination of post-retirement medical plan, net of taxes of $0
 —  —  —  —  541,000  —  —  541,000 
Balance at September 30, 2021 9,445,625  4,807,000  4,590,000  2,356,000  32,000  (2,286,000) 8,000  9,507,000 
Net earnings —  —  —  5,513,000  —  —  659,000  6,172,000 
Foreign currency translation adjustments, net of taxes of $0
 —  —  —  —  (40,000) —  —  (40,000)
Distributions to non-controlling interests —  —  —  —  —  —  (647,000) (647,000)
Share-based compensation —  —  657,000  —  —  —  —  657,000 
Issuance of common stock, net of costs 509,467  255,000  2,101,000  —  —  —  —  2,356,000 
Issuance of common stock for services 1,595  —  3,000  —  —  —  —  3,000 
Dividends declared, $0.015 per share
 —  —  —  (149,000) —  —  —  (149,000)
Retirement plans:                
Net actuarial gain arising during the period, net of taxes of $0
 —  —  —  —  1,302,000  —  —  1,302,000 
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 
 See Notes to Consolidated Financial Statements
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BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
  Year ended September 30,
  2022 2021
Cash flows from operating activities:    
Net earnings $ 6,172,000  $ 7,203,000 
Adjustments to reconcile net earnings to net cash provided by operating activities:    
Equity in income of affiliates (3,400,000) (5,793,000)
Depletion, depreciation, and amortization 2,778,000  963,000 
Impairment of assets 89,000  668,000 
Gain on sale of oil and natural gas properties —  (818,000)
Gain on sale of other assets —  (1,164,000)
Sale of interest in leasehold land, net of fees paid (1,137,000) (1,526,000)
Distributions of income from equity investees 3,170,000  5,045,000 
Retirement benefits income (272,000) (88,000)
Accretion of asset retirement obligation 767,000  580,000 
Deferred income tax (benefit) expense (171,000) 165,000 
Asset retirement obligation payments (942,000) (421,000)
Share-based compensation expense 657,000  643,000 
Common stock issued for services 3,000  1,000 
Non-cash rent income (1,000) (4,000)
Retirement plan contributions and payments (3,000) (14,000)
Bad debt expense 124,000  32,000 
Foreign currency loss 484,000  — 
Gain on debt extinguishment —  (149,000)
Gain on termination of post-retirement medical plan —  (2,341,000)
Decrease from changes in current assets and liabilities (1,027,000) (2,151,000)
Net cash provided by operating activities 7,291,000  831,000 
Cash flows from investing activities:    
Distributions from equity investees in excess of earnings 230,000  1,649,000 
Proceeds from sale of interest in leasehold land, net of fees paid 1,137,000  1,526,000 
Proceeds from sale of oil and natural gas assets 503,000  581,000 
Proceeds from sale of contract drilling and other assets, net of closing costs 687,000  1,864,000 
Deposit for sale of contract drilling asset 551,000  — 
Payments to acquire oil and natural gas properties (1,563,000) (348,000)
Capital expenditures - oil and natural gas (8,607,000) (1,523,000)
Capital expenditures - all other (50,000) (63,000)
Net cash (used in) provided by investing activities (7,112,000) 3,686,000 
Cash flows from financing activities:    
Borrowings on long-term debt —  47,000 
Distributions to non-controlling interests (647,000) (1,034,000)
Proceeds from issuance of stock, net of costs 2,356,000  3,179,000 
Payment of dividends (149,000) — 
Net cash provided by financing activities 1,560,000  2,192,000 
Effect of exchange rate changes on cash and cash equivalents (214,000) (14,000)
Net increase in cash and cash equivalents 1,525,000  6,695,000 
Cash and cash equivalents at beginning of year 11,279,000  4,584,000 
Cash and cash equivalents at end of year $ 12,804,000  $ 11,279,000 
See Notes to Consolidated Financial Statements
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BARNWELL INDUSTRIES, INC.
 
AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 
YEARS ENDED SEPTEMBER 30, 2022 AND 2021
 
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 Oklahoma, 2) investing in 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), a 75%-owned land investment partnership (KD Kona), and a variable interest entity (Teton Barnwell Fund I, LLC) for which the Company is deemed to be the primary beneficiary. 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, share-based payment arrangements, obligations for retirement plans, contract drilling estimated costs to complete, proved oil and natural gas reserves, and the carrying value of other assets, and such assumptions may impact the amount at which such items are recorded.

Reclassifications

Certain reclassifications of prior period amounts have been made in the Notes to Consolidated Financial Statements to conform to the current period presentations.
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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 Oklahoma.

•Land Investment Segment - Barnwell invests in 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 - Barnwell’s investments in oil and natural gas properties are located in Alberta, Canada and Oklahoma. 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
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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 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.
 
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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 doubtful accounts is Barnwell’s best estimate of the amount of probable credit losses in Barnwell’s existing accounts receivable and is based on historical write-off experience and the application of the specific identification method. 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.
 
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. Entities that have been determined to be VIEs and for which we have a controlling financial interest and are therefore the VIE’s primary beneficiary are consolidated (see Note 4). Entities that have been determined to be VIEs and for which we do not have a controlling financial interest and are therefore not the VIE’s primary beneficiary are not consolidated. These unconsolidated entities are accounted for under the equity method (see Note 3).

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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 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.

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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, 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 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
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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 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.
 
Share-based Compensation
 
Share-based compensation cost is measured at fair value. 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. The Company's policy is to recognize forfeitures as they occur.

Retirement Plans

Barnwell accounts for its defined benefit pension plan, Supplemental Executive Retirement Plan, and post-retirement medical insurance benefits plan, which was terminated in June 2021, 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 8.
 
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
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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 on assets assumption would increase (decrease) pension expense by approximately $56,000 based on the assets of the plan at September 30, 2022.
 
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.
 
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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.

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.
 
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 stockholders’ equity.

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 December 2019, the Financial Accounting Standards Board issued Accounting Standards Update (“ASU”) No. 2019-12, “Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes,” which enhances and simplifies various aspects of the income tax accounting guidance in ASC 740. The Company adopted the provisions of this ASU effective October 1, 2021. The adoption of this update did not have an impact on Barnwell's consolidated financial statements.

2.                                   EARNINGS PER COMMON SHARE
 
Basic earnings per share is computed using the weighted-average number of common shares outstanding for the period. Diluted earnings 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. Potentially dilutive shares are excluded from the computation of diluted earnings per share if their effect is anti-dilutive.
 
Options to purchase 615,000 shares were excluded from the computation of diluted shares for the years ended September 30, 2022 and 2021, as their inclusion would have been anti-dilutive.

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Reconciliations between net earnings attributable to Barnwell stockholders and common shares outstanding of the basic and diluted net earnings per share computations are detailed in the following tables:
  Year ended September 30, 2022
  Net Earnings Shares Per-Share
  (Numerator) (Denominator) Amount
Basic net earnings per share $ 5,513,000  9,732,936  $ 0.57 
Effect of dilutive securities - common stock options —  —   
Diluted net earnings per share $ 5,513,000  9,732,936  $ 0.57 
  Year ended September 30, 2021
  Net Earnings Shares Per-Share
  (Numerator) (Denominator) Amount
Basic net earnings per share $ 6,253,000  8,592,154  $ 0.73 
Effect of dilutive securities - common stock options —  —   
Diluted net earnings per share $ 6,253,000  8,592,154  $ 0.73 
 
3.                                 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.

The partnerships derive income from the sale of residential parcels, of which two lots, one being a large lot that is now a consolidation of two previous separate lots and one being an original size lot, remain to be sold at Increment I as of September 30, 2022, as well as from commissions on real estate sales by the real estate sales office and revenues resulting from the sale of private club memberships. Two ocean front parcels approximately two to three acres in size fronting the ocean were developed within Increment II by KD II, of which one was sold in fiscal 2017 and one was sold in fiscal 2016. 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 the developer of Increment II as of the date of this report.

 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.
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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. Additionally, Barnwell was entitled to a preferred return from KKM on any allocated equity in income of the Kukio Resort Land Development Partnerships in excess of its partnership sharing ratio for cumulative distributions to all of its partners in excess of $45,000,000 from those partnerships. Cumulative distributions from the Kukio Resort Land Development Partnerships reached the $45,000,000 threshold, and accordingly, Barnwell received a total of $459,000 in preferred return payments in the year ended September 30, 2021. The payments were reflected as an additional equity pickup in the "Equity in income of affiliates" line item on the accompanying Consolidated Statement of Operations for the year ended September 30, 2021. Those preferred return payments brought the cumulative preferred return total to $656,000, which was the total amount to which Barnwell was entitled.

During the year ended September 30, 2022, Barnwell received cash distributions of $3,400,000 from the Kukio Resort Land Development Partnership resulting in a net amount of $3,028,000, after distributing $372,000 to non-controlling interests. During the year ended September 30, 2021, Barnwell received net cash distributions in the amount of $6,011,000 from the Kukio Resort Land Development Partnerships after distributing $683,000 to non-controlling interests. Of the $6,011,000 net cash distribution received from the Kukio Resort Land Development Partnerships, $459,000 represented a payment of the preferred return from KKM, as discussed above.

 Equity in income of affiliates was $3,400,000 for the year ended September 30, 2022, as compared to equity in income of affiliates of $5,793,000 for the year ended September 30, 2021, which includes the $459,000 payment of the preferred return from KKM discussed above. 

Summarized financial information for the Kukio Resort Land Development Partnerships is as follows: 
  Year ended September 30,
  2022 2021
Revenue $ 24,577,000  $ 43,013,000 
Gross profit $ 16,934,000  $ 24,759,000