Barnwell Industries, Inc. (BRN, AMEX)
Industry: Energy / Oil & Gas E&P
Annual report, fiscal year 2022


# 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. □ Yes ☑ 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. □ Yes □ 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. ☒ Yes ☐ 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). ☒ Yes ☐ 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

8

Smaller reporting company

8

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. □

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 □ 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

Glossary of Terms
Discussion of Forward-Looking Statements
PART I
Item 1. Business
Item 1A. Risk Factors
Item 1B. Unresolved Staff Comments
Item 2. Properties
Item 3. Legal Proceedings
Item 4. Mine Safety Disclosures
PART II
Item 5. Market For Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Item 6. [Reserved]
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Item 8. Financial Statements and Supplementary Data
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Item 9A. Controls and Procedures
Item 9B. Other Information
Item 9C. Disclosure Regarding Foreign Jurisdictions That Prevent Inspections
PART III
Item 10. Directors, Executive Officers and Corporate Governance
Item 11. Executive Compensation
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Item 13. Certain Relationships and Related Transactions, and Director Independence
Item 14. Principal Accounting Fees and Services
PART IV
Item 15. Exhibits, Financial Statement Schedules
Signatures
Index to Exhibits



## 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:

<table><tr><td>Terms</td><td>Definitions</td></tr><tr><td>AER</td><td>- Alberta Energy Regulator</td></tr><tr><td>ARO</td><td>- Asset retirement obligation</td></tr><tr><td>ASC</td><td>- Accounting Standards Codification</td></tr><tr><td>ASU</td><td>- Accounting Standards Update</td></tr><tr><td>Barnwell of Canada</td><td>- Barnwell of Canada, Limited</td></tr><tr><td>Bbl(s)</td><td>- stock tank barrel(s) of oil equivalent to 42 U.S. gallons</td></tr><tr><td>Boe</td><td>- barrel of oil equivalent at the rate of 5.8 Mcf per Bbl of oil or NGL</td></tr><tr><td>Consolidated Balance Sheets</td><td>- The consolidated balance sheets of Barnwell Industries, Inc. and its subsidiaries.</td></tr><tr><td>FASB</td><td>- Financial Accounting Standards Board</td></tr><tr><td>GAAP</td><td>- U.S. generally accepted accounting principles</td></tr><tr><td>Gross</td><td>- 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.</td></tr><tr><td>InSite</td><td>- InSite Petroleum Consultants Ltd.</td></tr><tr><td>KD I</td><td>- KD Acquisition, LLLP, formerly known as WB KD Acquisition, LLC</td></tr><tr><td>KD II</td><td>- KD Acquisition II, LP, formerly known as WB KD Acquisition, II, LLC</td></tr><tr><td>KD Development</td><td>KD Development, LLC</td></tr><tr><td>KD Kona</td><td>- KD Kona 2013 LLLP</td></tr><tr><td>KKM Makai</td><td>- KKM Makai, LLLP</td></tr><tr><td>Kukio Resort Land</td><td>- The following partnerships in which Barnwell owns non-controlling interest:</td></tr><tr><td>Development Partnerships</td><td>KD Kukio Resorts, LLLP (“KD Kukio Resorts”)</td></tr><tr><td></td><td>KD Maniniowali, LLLP (“KD Maniniowali”)</td></tr><tr><td></td><td>KD Kaupulehu, LLLP, which consists of KD I and KD II (“KDK”)</td></tr><tr><td>LCA</td><td>- Licensee Capability Assessment</td></tr><tr><td>LGX</td><td>- LGX Oil &amp; Gas Ltd.</td></tr><tr><td>MBbls</td><td>- thousands of barrels of oil</td></tr><tr><td>Mcf</td><td>- one thousand cubic feet of natural gas at 14.65 pounds per square inch absolute and 60 degrees Fahrenheit</td></tr><tr><td>Mcfe</td><td>- Mcf equivalent at the rate of 1 Bbl = 5.8 Mcf</td></tr><tr><td>MMcf</td><td>- one million cubic feet of natural gas</td></tr><tr><td>Net</td><td>- 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.</td></tr><tr><td>NGL(s)</td><td>- natural gas liquid(s)</td></tr><tr><td>Octavian Oil</td><td>- Octavian Oil, Ltd.</td></tr><tr><td>OWA</td><td>- Orphan Well Association</td></tr><tr><td>Ryder Scott</td><td>- Ryder Scott Company, L.P.</td></tr><tr><td>SEC</td><td>- United States Securities and Exchange Commission</td></tr><tr><td>U.S.</td><td>- United States</td></tr><tr><td>VIE</td><td>- Variable interest entity</td></tr><tr><td>Water Resources</td><td>- Water Resources International, Inc.</td></tr><tr><td>WIP</td><td>Working Interest Partners</td></tr></table>



# 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.



## 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.



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



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.

<table><tr><td rowspan="2"></td><td colspan="3">As of September 30, 2022</td></tr><tr><td>Estimated Net Proved Developed Reserves</td><td>Estimated Net Proved Undeveloped Reserves</td><td>Estimated Net Proved Reserves</td></tr><tr><td>Oil, including natural gas liquids (Bbls)</td><td>1,046,000</td><td>34,000</td><td>1,080,000</td></tr><tr><td>Natural gas (Mcf)</td><td>4,857,000</td><td>128,000</td><td>4,985,000</td></tr><tr><td>Total (Boe)</td><td>1,883,000</td><td>56,000</td><td>1,939,000</td></tr></table>

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



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

The following table sets forth Barnwell’s 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.

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

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.



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.

<table><tr><td colspan="3">Year ending September 30,</td></tr><tr><td>2023</td><td>$ 10,645,000</td><td></td></tr><tr><td>2024</td><td>6,976,000</td><td></td></tr><tr><td>2025</td><td>5,007,000</td><td></td></tr><tr><td>Thereafter</td><td>8,206,000</td><td></td></tr><tr><td>Undiscounted future net cash flows, after income taxes</td><td>$ 30,834,000</td><td></td></tr><tr><td>Standardized measure of discounted future net cash flows</td><td>$ 27,878,000</td><td>*</td></tr></table>

* 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.”



<table><tr><td rowspan="2"></td><td colspan="3">Year ended September 30,</td></tr><tr><td>2022</td><td>2021</td><td>2020</td></tr><tr><td>Annual net production:</td><td></td><td></td><td></td></tr><tr><td>Natural gas (Mcf)</td><td>964,000</td><td>694,000</td><td>649,000</td></tr><tr><td>Oil (Bbls)</td><td>182,000</td><td>147,000</td><td>153,000</td></tr><tr><td>Natural gas liquids (Bbls)</td><td>48,000</td><td>24,000</td><td>21,000</td></tr><tr><td>Total (Boe)</td><td>396,000</td><td>291,000</td><td>286,000</td></tr><tr><td>Total (Mcfe)</td><td>2,296,000</td><td>1,685,000</td><td>1,658,000</td></tr><tr><td>Annual average sales price per unit of production:</td><td></td><td></td><td></td></tr><tr><td>Mcf of natural gas*</td><td>$4.63</td><td>$2.62</td><td>$1.64</td></tr><tr><td>Bbl of oil**</td><td>$86.73</td><td>$51.74</td><td>$33.85</td></tr><tr><td>Bbl of natural gas liquids**</td><td>$48.06</td><td>$31.92</td><td>$17.16</td></tr><tr><td>Annual average production cost per Boe produced***</td><td>$23.66</td><td>$22.40</td><td>$16.79</td></tr><tr><td>Annual average production cost per Mcfe produced***</td><td>$4.08</td><td>$3.86</td><td>$2.89</td></tr></table>

* 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



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.

<table><tr><td rowspan="2">Location</td><td colspan="2">Developed Acreage*</td><td colspan="2">Undeveloped Acreage*</td><td colspan="2">Total</td></tr><tr><td>Gross</td><td>Net</td><td>Gross</td><td>Net</td><td>Gross</td><td>Net</td></tr><tr><td>Canada</td><td>136,220</td><td>32,890</td><td>28,400</td><td>8,210</td><td>164,620</td><td>41,100</td></tr></table>

* “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.



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



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.



## 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



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.



## 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 Kawaīhae, 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



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:

<table><tr><td rowspan="2"></td><td colspan="2">December 1,</td></tr><tr><td>2022</td><td>2021</td></tr><tr><td>Well drilling</td><td>$ 10,000,000</td><td>$ 8,000,000</td></tr><tr><td>Pump installation and repair</td><td>1,200,000</td><td>1,500,000</td></tr><tr><td></td><td>$ 11,200,000</td><td>$ 9,500,000</td></tr></table>

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.



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.brminc.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.



## 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.



## 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.



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.



## 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



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.



## 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.



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



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.



## 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:



• 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.



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.



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.



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.



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.



## 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.



## 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:

<table><tr><td>Quarter Ended</td><td>High</td><td>Low</td><td>Quarter Ended</td><td>High</td><td>Low</td></tr><tr><td>December 31, 2020</td><td>$1.99</td><td>$0.76</td><td>December 31, 2021</td><td>$3.50</td><td>$2.30</td></tr><tr><td>March 31, 2021</td><td>$6.99</td><td>$1.25</td><td>March 31, 2022</td><td>$6.38</td><td>$2.38</td></tr><tr><td>June 30, 2021</td><td>$4.34</td><td>$2.02</td><td>June 30, 2022</td><td>$3.40</td><td>$2.29</td></tr><tr><td>September 30, 2021</td><td>$3.59</td><td>$2.00</td><td>September 30, 2022</td><td>$3.32</td><td>$2.12</td></tr></table>

## 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]



## 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.



## 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



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 consist of well casing or pumps, are excluded in the costs-to-costs calculation for the duration of the contract as including these costs would result in a distortion of progress towards satisfaction of the performance obligation due to the resulting cumulative catch-up in margin in a single period. An equal amount of cost and revenue is recorded when uninstalled materials are controlled by the customer, which is typically when Barnwell has the right to payment for the materials and when the materials are delivered to the customer's site or location and such



materials have been accepted by the customer. Uninstalled materials are held in inventory and included in “Other current assets” on the Company’s Consolidated Balance Sheets until control is transferred to the customer. When the estimate on a contract indicates a loss, Barnwell records the entire estimated loss in the period the loss becomes known.

Unexpected significant inefficiencies that were not considered a risk at the time of entering into the contract, such as design or construction execution errors that result in significant wasted resources, are excluded from the measure of progress toward completion and the costs are expensed as incurred.

To the extent a contract is deemed to have multiple performance obligations, the Company allocates the transaction price of the contract to each performance obligation using its best estimate of the standalone selling price of each distinct good or service in the contract. The contract price may include variable consideration, which includes such items as increases to the transaction price for unapproved change orders and claims for which price has not yet been agreed by the customer. The Company estimates variable consideration using either the most likely amount or expected value method, whichever is a more appropriate reflection of the amount to which it expects to be entitled based on the characteristics and circumstances of the contract. Variable consideration is included in the estimated transaction price to the extent it is probable that a significant reversal of cumulative recognized revenue will not occur.

Contracts are sometimes modified for a change in scope or other requirements. The Company considers contract modifications to exist when the modification either creates new or changes the existing enforceable rights and obligations. Most of the Company’s contract modifications are for goods and services that are not distinct from the existing performance obligations. The effect of a contract modification on the transaction price, and the measure of progress for the performance obligation to which it relates, is recognized as an adjustment to revenue (either as an increase or decrease) on a cumulative catchup basis.

## Judgments and Assumptions

Management evaluates the performance of contracts on an individual basis. In the ordinary course of business, but at least quarterly, we prepare updated estimates that may impact the cost and profit or loss for each contract based on actual results to date plus management’s best estimate of costs to be incurred to complete each performance obligation. Increases or decreases in the estimated costs to complete a performance obligation without a change to the contract price has the impact to decrease or increase, respectively, the contract completion percentage applied to the contract price to calculate the cumulative contract revenue to be recognized to date. Changes in the cost estimates can have a material impact on our contract revenue and are reflected in the results of operations when they become known. The nature of accounting for these contracts is such that refinements of the estimated costs to complete may occur and are characteristic of the estimation process due to changing conditions and new developments. Many factors and assumptions can and do change during a contract performance obligation period which can result in a change to contract profitability including unforeseen underground geological conditions (to the extent that contract remedies are unavailable), the availability and costs of skilled contract labor, the performance of major material suppliers, the performance of major subcontractors, unusual weather conditions and unexpected changes in material costs, changes in the scope and nature of work to be performed, and unexpected construction execution errors, among others. Any revisions to estimated costs to complete the performance obligation from period to period as a result of changes in these factors can materially affect revenue and operating results in the period such revisions are necessary. In addition, many contracts give the customer a unilateral right to cancel for convenience or other than for cause. In accordance with FASB ASC 606-10-32-4, our estimates are based on the assumption that the existing



contract will not be cancelled. Any unforeseen cancellation of a contract may result in a material revision to our estimates.

We have a long history of working with multiple types of projects and preparing cost estimates, and we rely on the expertise of key personnel to prepare what we believe are reasonable best estimates given available facts and circumstances. Due to the nature of the work involved, however, judgment is involved to estimate the costs to complete and the amounts estimated could have a material impact on the revenue we recognize in each accounting period. We can not estimate unforeseen events and circumstances which may result in actual results being materially different from previous estimates.

## Income Taxes

## Policy Description

Income taxes are determined using the asset and liability method. Deferred tax assets and liabilities are recognized for the estimated future tax impacts of differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the year in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.

Deferred income tax assets are routinely assessed for realizability. A valuation allowance is provided when it is more likely than not that some portion or all of the deferred tax asset will not be realized.

Barnwell recognizes the financial statement effects of tax positions when it is more likely than not that the position will be sustained by a taxing authority.

## Judgments and Assumptions

We make estimates and judgments in determining our income tax expense for each reporting period. Significant changes to these estimates could result in an increase or decrease in our tax provision in future periods. We are also required to make judgments about the recoverability of deferred tax assets and when it is more likely than not that all or a portion of deferred tax assets will not be realized, a valuation allowance is provided. We consider available positive and negative evidence and available tax planning strategies when assessing the realizability of deferred tax assets. Accordingly, changes in our business performance and unforeseen events could require a further increase in the valuation allowance or a reversal in the valuation allowance in future periods. This could result in a charge to, or an increase in, income in the period such determination is made, and the impact of these changes could be material.

In addition, Barnwell operates within the U.S. and Canada and is subject to audit by taxing authorities in these jurisdictions. Barnwell records accruals for the estimated outcomes of these audits, and the accruals may change in the future due to new developments in each matter. Tax benefits are recognized when we determine that it is more likely than not that such benefits will be realized. Management evaluates its potential exposures from tax positions taken that have or could be challenged by taxing authorities. These potential exposures result because taxing authorities may take positions that differ from those taken by management in the interpretation and application of statutes, regulations and rules. Management considers the possibility of alternative outcomes based upon past experience, previous actions by taxing authorities (e.g., actions taken in other jurisdictions) and advice from tax experts. Where



uncertainty exists due to the complexity of income tax statutes and where the potential tax amounts are significant, we generally seek independent tax opinions to support our positions. If our evaluation of the likelihood of the realization of benefits is inaccurate, we could incur additional income tax and interest expense that would adversely impact earnings, or we could receive tax benefits greater than anticipated which would positively impact earnings, either of which could be material.

## Overview

Barnwell is engaged in the following lines of business: 1) acquiring, developing, producing and selling oil and natural gas in Canada and 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



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.



## 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



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.



## 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.

<table><tr><td rowspan="3"></td><td colspan="5">Annual Average Price Per Unit</td></tr><tr><td rowspan="2">2022</td><td rowspan="2">2021</td><td colspan="3">Increase (Decrease)</td></tr><tr><td>$</td><td>%</td><td></td></tr><tr><td>Natural gas (Mcf)*</td><td>$</td><td>4.63</td><td>$</td><td>2.02</td><td>$</td></tr><tr><td>Oil (Bbls)</td><td>$</td><td>86.73</td><td>$</td><td>51.74</td><td>$</td></tr><tr><td>Natural gas liquids (Bbls)</td><td>$</td><td>48.06</td><td>$</td><td>31.92</td><td>$</td></tr></table>

<table><tr><td rowspan="3"></td><td colspan="4">Annual Net Production</td></tr><tr><td rowspan="2">2022</td><td rowspan="2">2021</td><td colspan="2">Increase (Decrease)</td></tr><tr><td>Units</td><td>%</td></tr><tr><td>Natural gas (Mcf)</td><td>964,000</td><td>694,000</td><td>270,000</td><td>39%</td></tr><tr><td>Oil (Bbls)</td><td>182,000</td><td>147,000</td><td>35,000</td><td>24%</td></tr><tr><td>Natural gas liquids (Bbls)</td><td>48,000</td><td>24,000</td><td>24,000</td><td>100%</td></tr></table>

* 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, 2011.

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.



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:

<table><tr><td rowspan="2"></td><td colspan="3">Year ended September 30,</td></tr><tr><td>2022</td><td>2021</td><td></td></tr><tr><td>Sale of interest in leasehold land:</td><td></td><td></td><td></td></tr><tr><td>Revenues - sale of interest in leasehold land</td><td>$ 1,295,000</td><td>$ 1,738,000</td><td></td></tr><tr><td>Fees - included in general and administrative expenses</td><td>(158,000)</td><td>(212,000)</td><td></td></tr><tr><td>Sale of interest in leasehold land, net of fees paid</td><td>$ 1,137,000</td><td>$ 1,526,000</td><td></td></tr></table>

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.



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



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



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 a 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.



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:

<table><tr><td rowspan="2"></td><td colspan="2">Year ended September 30,</td></tr><tr><td>2022</td><td>2021</td></tr><tr><td>United States</td><td>$ 739,000</td><td>$ 5,436,000</td></tr><tr><td>Canada</td><td>5,121,000</td><td>1,149,000</td></tr><tr><td></td><td>$ 5,860,000</td><td>$ 6,585,000</td></tr></table>

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.



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.



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.



## 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.



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



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



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.



# 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



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,



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



## BARWELL INDUSTRIES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS

<table><tr><td rowspan="2"></td><td colspan="2">September 30,</td></tr><tr><td>2022</td><td>2021</td></tr><tr><td>ASSETS</td><td></td><td></td></tr><tr><td>Current assets:</td><td></td><td></td></tr><tr><td>Cash and cash equivalents</td><td>$ 12,804,000</td><td>$ 11,279,000</td></tr><tr><td>Accounts and other receivables, net of allowance for doubtful accounts of: $231,000 at September 30, 2022; $391,000 at September 30, 2021</td><td>4,361,000</td><td>3,069,000</td></tr><tr><td>Income taxes receivable</td><td>—</td><td>530,000</td></tr><tr><td>Assets held for sale</td><td>—</td><td>687,000</td></tr><tr><td>Other current assets</td><td>2,932,000</td><td>2,470,000</td></tr><tr><td>Total current assets</td><td>20,097,000</td><td>18,035,000</td></tr><tr><td>Asset for retirement benefits</td><td>3,385,000</td><td>2,229,000</td></tr><tr><td>Operating lease right-of-use assets</td><td>132,000</td><td>296,000</td></tr><tr><td>Oil and natural gas properties, full cost method of accounting:</td><td></td><td></td></tr><tr><td>Proved properties, net</td><td>13,232,000</td><td>2,423,000</td></tr><tr><td>Unproved properties</td><td>—</td><td>962,000</td></tr><tr><td>Total oil and natural gas properties, net</td><td>13,232,000</td><td>3,385,000</td></tr><tr><td>Drilling rigs and other property and equipment, net</td><td>369,000</td><td>490,000</td></tr><tr><td>Total assets</td><td>$ 37,215,000</td><td>$ 24,435,000</td></tr><tr><td>LIABILITIES AND EQUITY</td><td></td><td></td></tr><tr><td>Current liabilities:</td><td></td><td></td></tr><tr><td>Accounts payable</td><td>$ 1,462,000</td><td>$ 1,416,000</td></tr><tr><td>Accrued capital expenditures</td><td>1,655,000</td><td>909,000</td></tr><tr><td>Accrued compensation</td><td>999,000</td><td>1,073,000</td></tr><tr><td>Accrued operating and other expenses</td><td>1,576,000</td><td>1,171,000</td></tr><tr><td>Current portion of asset retirement obligation</td><td>1,327,000</td><td>713,000</td></tr><tr><td>Other current liabilities</td><td>1,908,000</td><td>619,000</td></tr><tr><td>Total current liabilities</td><td>8,927,000</td><td>5,901,000</td></tr><tr><td>Long-term debt</td><td>44,000</td><td>47,000</td></tr><tr><td>Operating lease liabilities</td><td>117,000</td><td>180,000</td></tr><tr><td>Liability for retirement benefits</td><td>1,649,000</td><td>2,101,000</td></tr><tr><td>Asset retirement obligation</td><td>7,129,000</td><td>6,340,000</td></tr><tr><td>Deferred income tax liabilities</td><td>188,000</td><td>359,000</td></tr><tr><td>Total liabilities</td><td>18,054,000</td><td>14,928,000</td></tr><tr><td>Commitments and contingencies (Note 17)</td><td></td><td></td></tr><tr><td>Equity:</td><td></td><td></td></tr><tr><td>Common stock, par value $0.50 per share; authorized, 40,000,000 shares:</td><td></td><td></td></tr><tr><td>10,124,587 issued at September 30, 2022; 9,613,525 issued at September 30, 2021</td><td>5,062,000</td><td>4,807,000</td></tr><tr><td>Additional paid-in capital</td><td>7,351,000</td><td>4,590,000</td></tr><tr><td>Retained earnings</td><td>7,720,000</td><td>2,356,000</td></tr><tr><td>Accumulated other comprehensive income, net</td><td>1,294,000</td><td>32,000</td></tr><tr><td>Treasury stock, at cost:</td><td></td><td></td></tr><tr><td>167,900 shares at September 30, 2022 and 2021</td><td>(2,286,000)</td><td>(2,286,000)</td></tr><tr><td>Total stockholders&#x27; equity</td><td>19,141,000</td><td>9,499,000</td></tr><tr><td>Non-controlling interests</td><td>20,000</td><td>8,000</td></tr><tr><td>Total equity</td><td>19,161,000</td><td>9,507,000</td></tr><tr><td>Total liabilities and equity</td><td>$ 37,215,000</td><td>$ 24,435,000</td></tr></table>

See Notes to Consolidated Financial Statements



## BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS

<table><tr><td rowspan="2"></td><td colspan="2">Year ended September 30,</td></tr><tr><td>2022</td><td>2021</td></tr><tr><td>Revenues:</td><td></td><td></td></tr><tr><td>Oil and natural gas</td><td>$ 22,581,000</td><td>$ 10,254,000</td></tr><tr><td>Contract drilling</td><td>4,540,000</td><td>5,809,000</td></tr><tr><td>Sale of interest in leasehold land</td><td>1,295,000</td><td>1,738,000</td></tr><tr><td>Gas processing and other</td><td>129,000</td><td>312,000</td></tr><tr><td></td><td>28,545,000</td><td>18,113,000</td></tr><tr><td>Costs and expenses:</td><td></td><td></td></tr><tr><td>Oil and natural gas operating</td><td>9,439,000</td><td>6,556,000</td></tr><tr><td>Contract drilling operating</td><td>4,591,000</td><td>5,555,000</td></tr><tr><td>General and administrative</td><td>8,044,000</td><td>7,088,000</td></tr><tr><td>Depletion, depreciation, and amortization</td><td>2,778,000</td><td>963,000</td></tr><tr><td>Impairment of assets</td><td>89,000</td><td>668,000</td></tr><tr><td>Foreign currency loss</td><td>484,000</td><td>—</td></tr><tr><td>Interest expense</td><td>1,000</td><td>13,000</td></tr><tr><td>Gain on debt extinguishment</td><td>—</td><td>(149,000)</td></tr><tr><td>Gain on termination of post-retirement medical plan</td><td>—</td><td>(2,341,000)</td></tr><tr><td>Gain on sale of assets</td><td>—</td><td>(1,982,000)</td></tr><tr><td></td><td>25,426,000</td><td>16,371,000</td></tr><tr><td>Earnings before equity in income of affiliates and income taxes</td><td>3,119,000</td><td>1,742,000</td></tr><tr><td>Equity in income of affiliates</td><td>3,400,000</td><td>5,793,000</td></tr><tr><td>Earnings before income taxes</td><td>6,519,000</td><td>7,535,000</td></tr><tr><td>Income tax provision</td><td>347,000</td><td>332,000</td></tr><tr><td>Net earnings</td><td>6,172,000</td><td>7,203,000</td></tr><tr><td>Less: Net earnings attributable to non-controlling interests</td><td>659,000</td><td>950,000</td></tr><tr><td>Net earnings attributable to Barnwell Industries, Inc. stockholders</td><td>$ 5,513,000</td><td>$ 6,253,000</td></tr><tr><td>Basic net earnings per common share</td><td></td><td></td></tr><tr><td>attributable to Barnwell Industries, Inc. stockholders</td><td>$ 0.57</td><td>$ 0.73</td></tr><tr><td>Diluted net earnings per common share</td><td></td><td></td></tr><tr><td>attributable to Barnwell Industries, Inc. stockholders</td><td>$ 0.57</td><td>$ 0.73</td></tr><tr><td>Weighted-average number of common shares outstanding:</td><td></td><td></td></tr><tr><td>Basic</td><td>9,732,936</td><td>8,592,154</td></tr><tr><td>Diluted</td><td>9,732,936</td><td>8,592,154</td></tr></table>

See Notes to Consolidated Financial Statements



## BARWELL INDUSTRIES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

<table><tr><td rowspan="3"></td><td colspan="3">Year ended September 30,</td></tr><tr><td>2022</td><td colspan="2">2021</td></tr><tr><td>$ 6,172,000</td><td>$ 7,203,000</td><td></td></tr><tr><td>Net earnings</td><td></td><td></td><td></td></tr><tr><td>Other comprehensive (loss) income:</td><td></td><td></td><td></td></tr><tr><td>Foreign currency translation adjustments, net of taxes of $0</td><td>(40,000)</td><td>(283,000)</td><td></td></tr><tr><td>Retirement plans:</td><td></td><td></td><td></td></tr><tr><td>Amortization of accumulated other comprehensive loss into net periodic benefit cost, net of taxes of $0</td><td>—</td><td>101,000</td><td></td></tr><tr><td>Net actuarial gain arising during the period, net of taxes of $0</td><td>1,302,000</td><td>1,108,000</td><td></td></tr><tr><td>Gain on termination of post-retirement medical plan, net of taxes of $0</td><td>—</td><td>541,000</td><td></td></tr><tr><td>Total other comprehensive income</td><td>1,262,000</td><td>1,467,000</td><td></td></tr><tr><td>Total comprehensive income</td><td>7,434,000</td><td>8,670,000</td><td></td></tr><tr><td>Less: Comprehensive income attributable to non-controlling interests</td><td>(659,000)</td><td>(950,000)</td><td></td></tr><tr><td>Comprehensive income attributable to Barnwell Industries, Inc.</td><td>$ 6,775,000</td><td>$ 7,720,000</td><td></td></tr></table>

See Notes to Consolidated Financial Statements



## BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF EQUITY
Years ended September 30, 2022 and 2021

<table><tr><td></td><td>Shares Outstanding</td><td>Common Stock</td><td>Additional Paid-In Capital</td><td>Retained Earnings (Accumulated Deficit)</td><td>Accumulated Other Comprehensive Income (Loss)</td><td>Treasury Stock</td><td>Non-controlling Interests</td><td>Total Equity (Deficit)</td></tr><tr><td>Balance at September 30, 2020</td><td>8,277,160</td><td>$4,223,000</td><td>$1,350,000</td><td>$ (3,897,000)</td><td>$ (1,435,000)</td><td>$ (2,286,000)</td><td>$ 92,000</td><td>$ (1,953,000)</td></tr><tr><td>Net earnings</td><td>—</td><td>—</td><td>—</td><td>6,253,000</td><td>—</td><td>—</td><td>950,000</td><td>7,203,000</td></tr><tr><td>Foreign currency translation adjustments, net of taxes of $0</td><td>—</td><td>—</td><td>—</td><td>—</td><td>(283,000)</td><td>—</td><td>—</td><td>(283,000)</td></tr><tr><td>Distributions to non-controlling interests</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>(1,034,000)</td><td>(1,034,000)</td></tr><tr><td>Share-based compensation</td><td>—</td><td>—</td><td>643,000</td><td>—</td><td>—</td><td>—</td><td>—</td><td>643,000</td></tr><tr><td>Issuance of common stock, net of costs</td><td>1,167,987</td><td>583,000</td><td>2,596,000</td><td>—</td><td>—</td><td>—</td><td>—</td><td>3,179,000</td></tr><tr><td>Issuance of common stock for services</td><td>478</td><td>1,000</td><td>1,000</td><td>—</td><td>—</td><td>—</td><td>—</td><td>2,000</td></tr><tr><td>Retirement plans:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Amortization of accumulated other comprehensive loss into net periodic benefit cost, net of taxes of $0</td><td>—</td><td>—</td><td>—</td><td>—</td><td>101,000</td><td>—</td><td>—</td><td>101,000</td></tr><tr><td>Net actuarial gain arising during the period, net of taxes of $0</td><td>—</td><td>—</td><td>—</td><td>—</td><td>1,108,000</td><td>—</td><td>—</td><td>1,108,000</td></tr><tr><td>Gain on termination of post-retirement medical plan, net of taxes of $0</td><td>—</td><td>—</td><td>—</td><td>—</td><td>541,000</td><td>—</td><td>—</td><td>541,000</td></tr><tr><td>Balance at September 30, 2021</td><td>9,445,625</td><td>4,807,000</td><td>4,590,000</td><td>2,356,000</td><td>32,000</td><td>(2,286,000)</td><td>8,000</td><td>9,507,000</td></tr><tr><td>Net earnings</td><td>—</td><td>—</td><td>—</td><td>5,513,000</td><td>—</td><td>—</td><td>659,000</td><td>6,172,000</td></tr><tr><td>Foreign currency translation adjustments, net of taxes of $0</td><td>—</td><td>—</td><td>—</td><td>—</td><td>(40,000)</td><td>—</td><td>—</td><td>(40,000)</td></tr><tr><td>Distributions to non-controlling interests</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>(647,000)</td><td>(647,000)</td></tr><tr><td>Share-based compensation</td><td>—</td><td>—</td><td>657,000</td><td>—</td><td>—</td><td>—</td><td>—</td><td>657,000</td></tr><tr><td>Issuance of common stock, net of costs</td><td>509,467</td><td>255,000</td><td>2,101,000</td><td>—</td><td>—</td><td>—</td><td>—</td><td>2,356,000</td></tr><tr><td>Issuance of common stock for services</td><td>1,595</td><td>—</td><td>3,000</td><td>—</td><td>—</td><td>—</td><td>—</td><td>3,000</td></tr><tr><td>Dividends declared, $0.015 per share</td><td>—</td><td>—</td><td>—</td><td>(149,000)</td><td>—</td><td>—</td><td>—</td><td>(149,000)</td></tr><tr><td>Retirement plans:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Net actuarial gain arising during the period, net of taxes of $0</td><td>—</td><td>—</td><td>—</td><td>—</td><td>1,302,000</td><td>—</td><td>—</td><td>1,302,000</td></tr><tr><td>Balance at September 30, 2022</td><td>9,956,687</td><td>$5,062,000</td><td>$7,351,000</td><td>$ 7,720,000</td><td>$ 1,294,000</td><td>$ (2,286,000)</td><td>$ 20,000</td><td>$19,161,000</td></tr></table>

See Notes to Consolidated Financial Statements



## BARWELL INDUSTRIES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS

<table><tr><td rowspan="2"></td><td colspan="2">Year ended September 30,</td></tr><tr><td>2022</td><td>2021</td></tr><tr><td>Cash flows from operating activities:</td><td></td><td></td></tr><tr><td>Net earnings</td><td>$ 6,172,000</td><td>$ 7,203,000</td></tr><tr><td>Adjustments to reconcile net earnings to net cash provided by operating activities:</td><td></td><td></td></tr><tr><td>Equity in income of affiliates</td><td>(3,400,000)</td><td>(5,793,000)</td></tr><tr><td>Depletion, depreciation, and amortization</td><td>2,778,000</td><td>963,000</td></tr><tr><td>Impairment of assets</td><td>89,000</td><td>668,000</td></tr><tr><td>Gain on sale of oil and natural gas properties</td><td>—</td><td>(818,000)</td></tr><tr><td>Gain on sale of other assets</td><td>—</td><td>(1,164,000)</td></tr><tr><td>Sale of interest in leasehold land, net of fees paid</td><td>(1,137,000)</td><td>(1,526,000)</td></tr><tr><td>Distributions of income from equity investees</td><td>3,170,000</td><td>5,045,000</td></tr><tr><td>Retirement benefits income</td><td>(272,000)</td><td>(88,000)</td></tr><tr><td>Accretion of asset retirement obligation</td><td>767,000</td><td>580,000</td></tr><tr><td>Deferred income tax (benefit) expense</td><td>(171,000)</td><td>165,000</td></tr><tr><td>Asset retirement obligation payments</td><td>(942,000)</td><td>(421,000)</td></tr><tr><td>Share-based compensation expense</td><td>657,000</td><td>643,000</td></tr><tr><td>Common stock issued for services</td><td>3,000</td><td>1,000</td></tr><tr><td>Non-cash rent income</td><td>(1,000)</td><td>(4,000)</td></tr><tr><td>Retirement plan contributions and payments</td><td>(3,000)</td><td>(14,000)</td></tr><tr><td>Bad debt expense</td><td>124,000</td><td>32,000</td></tr><tr><td>Foreign currency loss</td><td>484,000</td><td>—</td></tr><tr><td>Gain on debt extinguishment</td><td>—</td><td>(149,000)</td></tr><tr><td>Gain on termination of post-retirement medical plan</td><td>—</td><td>(2,341,000)</td></tr><tr><td>Decrease from changes in current assets and liabilities</td><td>(1,027,000)</td><td>(2,151,000)</td></tr><tr><td>Net cash provided by operating activities</td><td>7,291,000</td><td>831,000</td></tr><tr><td>Cash flows from investing activities:</td><td></td><td></td></tr><tr><td>Distributions from equity investees in excess of earnings</td><td>230,000</td><td>1,649,000</td></tr><tr><td>Proceeds from sale of interest in leasehold land, net of fees paid</td><td>1,137,000</td><td>1,526,000</td></tr><tr><td>Proceeds from sale of oil and natural gas assets</td><td>503,000</td><td>581,000</td></tr><tr><td>Proceeds from sale of contract drilling and other assets, net of closing costs</td><td>687,000</td><td>1,864,000</td></tr><tr><td>Deposit for sale of contract drilling asset</td><td>551,000</td><td>—</td></tr><tr><td>Payments to acquire oil and natural gas properties</td><td>(1,563,000)</td><td>(348,000)</td></tr><tr><td>Capital expenditures - oil and natural gas</td><td>(8,607,000)</td><td>(1,523,000)</td></tr><tr><td>Capital expenditures - all other</td><td>(50,000)</td><td>(63,000)</td></tr><tr><td>Net cash (used in) provided by investing activities</td><td>(7,112,000)</td><td>3,686,000</td></tr><tr><td>Cash flows from financing activities:</td><td></td><td></td></tr><tr><td>Borrowings on long-term debt</td><td>—</td><td>47,000</td></tr><tr><td>Distributions to non-controlling interests</td><td>(647,000)</td><td>(1,034,000)</td></tr><tr><td>Proceeds from issuance of stock, net of costs</td><td>2,356,000</td><td>3,179,000</td></tr><tr><td>Payment of dividends</td><td>(149,000)</td><td>—</td></tr><tr><td>Net cash provided by financing activities</td><td>1,560,000</td><td>2,192,000</td></tr><tr><td>Effect of exchange rate changes on cash and cash equivalents</td><td>(214,000)</td><td>(14,000)</td></tr><tr><td>Net increase in cash and cash equivalents</td><td>1,525,000</td><td>6,695,000</td></tr><tr><td>Cash and cash equivalents at beginning of year</td><td>11,279,000</td><td>4,584,000</td></tr><tr><td>Cash and cash equivalents at end of year</td><td>$ 12,804,000</td><td>$ 11,279,000</td></tr></table>

See Notes to Consolidated Financial Statements



# 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.



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 consist of well casing or pumps, are excluded in the costs-to-costs calculation for the duration of the contract as including these costs would result in a distortion of progress towards satisfaction of the performance obligation due to the resulting cumulative catch-up in margin in a single period. An equal amount of cost and revenue is recorded when uninstalled materials are controlled by the customer, which is typically when Barnwell has the right to payment for the materials and when the materials are delivered to the customer’s site or location and such materials have been accepted by the customer. Uninstalled materials are held in inventory and included in “Other current assets” on the Company’s Consolidated Balance Sheets until control is transferred to the customer. When the estimate on a contract indicates a loss, Barnwell records the entire estimated loss in the period the loss becomes known.

The contract price may include variable consideration, which includes such items as increases to the transaction price for unapproved change orders and claims for which price has not yet been agreed by the customer. The Company estimates variable consideration using either the most likely amount or expected value method, whichever is a more appropriate reflection of the amount to which it expects to be entitled based on the characteristics and circumstances of the contract. Variable consideration is included



in the estimated transaction price to the extent it is probable that a significant reversal of cumulative recognized revenue will not occur.

Contract price and cost estimates are reviewed periodically as work progresses and adjustments proportionate to the costs incurred to date to total estimated costs at completion are reflected in contract revenues in the reporting period when such estimates are revised. The nature of accounting for these contracts is such that refinements of the estimated costs to complete may occur and are characteristic of the estimation process due to changing conditions and new developments. Many factors and assumptions can and do change during a contract performance obligation period which can result in a change to contract profitability including unforeseen underground geological conditions (to the extent that contract remedies are unavailable), the availability and costs of skilled contract labor, the performance of major material suppliers, the performance of major subcontractors, unusual weather conditions and unexpected changes in material costs, changes in the scope and nature of the work to be performed, and unexpected construction execution errors, among others. These factors may result in revisions to costs and income and are recognized in the period in which the revisions become known. Revenue and profit in future periods of contract performance are recognized using the adjusted estimate.

Management evaluates the performance of contracts on an individual basis. In the ordinary course of business, but at least quarterly, we prepare updated estimates that may impact the cost and profit or loss for each contract based on actual results to date plus management's best estimate of costs to be incurred to complete each performance obligation. The cumulative effect of revisions in estimates of the total forecasted revenue and costs, including any unapproved change orders and claims, during the course of the contract is reflected in the accounting period in which the facts that caused the revision become known. Changes in the cost estimates can have a material impact on our consolidated financial statements and are reflected in the results of operations when they become known.

Unexpected significant inefficiencies that were not considered a risk at the time of entering into the contract, such as design or construction execution errors that result in significant wasted resources, are excluded from the measure of progress toward completion and the costs are expensed as incurred.

To the extent a contract is deemed to have multiple performance obligations, the Company allocates the transaction price of the contract to each performance obligation using its best estimate of the standalone selling price of each distinct good or service in the contract.

When the Company receives consideration, or such consideration is unconditionally due, from a customer prior to transferring goods or services to the customer under the terms of a sales contract, the Company records deferred revenue, which represents a contract liability. Such deferred revenue typically results from billings in excess of costs and estimated earnings on uncompleted contracts. Contract liabilities are included in “Other current liabilities” on the Company’s Consolidated Balance Sheets. Costs and estimated earnings in excess of billings represent certain amounts under customer contracts that were earned and billable, but yet not invoiced, and are included in contract assets and reported in “Other current assets” on the Company’s Consolidated Balance Sheets.

## Cash and Cash Equivalents

Cash and cash equivalents include cash on hand and short-term investments with original maturities of three months or less.



## Concentration of Credit Risk

Financial instruments that potentially subject the Company to concentrations of credit risk consist primarily of cash and cash equivalents. We maintain bank account balances with high quality financial institutions which often exceed insured limits. We have not experienced any losses with these accounts and believe that we are not exposed to any significant credit risk on cash.

## Accounts and Other Receivables

Accounts receivable are recorded at the invoiced amount and do not bear interest. The allowance for 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).



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.



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



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



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.



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.



## 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.



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:

<table><tr><td rowspan="2"></td><td colspan="4">Year ended September 30, 2022</td></tr><tr><td>Net Earnings (Numerator)</td><td>Shares (Denominator)</td><td>Per-Share Amount</td><td></td></tr><tr><td>Basic net earnings per share</td><td>$ 5,513,000</td><td>9,732,936</td><td>$ 0.57</td><td></td></tr><tr><td>Effect of dilutive securities - common stock options</td><td>—</td><td>—</td><td></td><td></td></tr><tr><td>Diluted net earnings per share</td><td>$ 5,513,000</td><td>9,732,936</td><td>$ 0.57</td><td></td></tr></table>

<table><tr><td rowspan="2"></td><td colspan="4">Year ended September 30, 2021</td></tr><tr><td>Net Earnings (Numerator)</td><td>Shares (Denominator)</td><td>Per-Share Amount</td><td></td></tr><tr><td>Basic net earnings per share</td><td>$ 6,253,000</td><td>8,592,154</td><td>$ 0.73</td><td></td></tr><tr><td>Effect of dilutive securities - common stock options</td><td>—</td><td>—</td><td></td><td></td></tr><tr><td>Diluted net earnings per share</td><td>$ 6,253,000</td><td>8,592,154</td><td>$ 0.73</td><td></td></tr></table>

## 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.



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:

<table><tr><td rowspan="2"></td><td colspan="3">Year ended September 30,</td></tr><tr><td>2022</td><td>2021</td><td></td></tr><tr><td>Revenue</td><td>$ 24,577,000</td><td>$ 43,013,000</td><td></td></tr><tr><td>Gross profit</td><td>$ 16,934,000</td><td>$ 24,759,000</td><td></td></tr><tr><td>Net earnings</td><td>$ 13,763,000</td><td>$ 20,612,000</td><td></td></tr></table>

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.

## Sale of Interest in Leasehold Land

Kaupulehu Developments has the right to receive payments from KD I and KD II resulting from the sale of lots and/or residential units within Increment I and Increment II by KD I and KD II (see Note 19).

With respect to Increment I, 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. Six single-family lots were sold during the year ended September 30, 2022 and two single-family lots, of the 80 lots developed within Increment I, remained to be sold as of September 30, 2022.

Under the terms of the Increment II agreement with KD II, Kaupulehu Developments is entitled to 15% of the distributions of KD II, the cost of which is to be solely borne by KDK out of its 55% ownership interest in KD II, plus a priority payout of 10% of KDK's cumulative net profits derived from Increment II sales subsequent to Phase 2A, up to a maximum of $3,000,000 as to the priority payout. Such interests are limited to distributions or net profits interests and Barnwell does not have any partnership interests in KD II or KDK through its interest in Kaupulehu Developments. The arrangement also gives Barnwell rights to three single-family residential lots in Phase 2A of Increment II, and four single-family residential lots in phases subsequent to Phase 2A when such lots are developed by KD II, all at no cost to Barnwell. Barnwell is committed to commence construction of improvements within 90 days of the transfer of the four lots in the phases subsequent to Phase 2A as a condition of the transfer of such lots. Also, in addition to Barnwell's existing obligations to pay professional fees to certain parties based on percentages of its gross receipts, Kaupulehu Developments is also obligated to pay an amount equal to 0.72% and 0.20% of the cumulative net profits of KD II to KD Development and a pool of various individuals, respectively, all of whom are partners of KKM and are unrelated to Barnwell, in compensation for the agreement of these parties to admit the new development partner for Increment II. Such compensation will be reflected as the obligation becomes probable and the amount of the obligation can be reasonably estimated.

The following table summarizes the Increment I revenues from KD I and the amount of fees directly related to such revenues (see Note 17 “Commitments and Contingencies - Other Matters”):

<table><tr><td rowspan="2"></td><td colspan="3">Year ended September 30,</td></tr><tr><td>2022</td><td>2021</td><td></td></tr><tr><td>Sale of interest in leasehold land:</td><td></td><td></td><td></td></tr><tr><td>Revenues - sale of interest in leasehold land</td><td>$ 1,295,000</td><td>$ 1,738,000</td><td></td></tr><tr><td>Fees - included in general and administrative expenses</td><td>(158,000)</td><td>(212,000)</td><td></td></tr><tr><td>Sale of interest in leasehold land, net of fees paid</td><td>$ 1,137,000</td><td>$ 1,526,000</td><td></td></tr></table>

In November 2022, one lot within Increment I was sold and Kaupulehu Developments received a percentage of sales payment of $265,000 from the sale, leaving one lot remaining to be sold in 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.



There is no assurance with regards to the amounts of future payments from Increment I or Increment II to be received, 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.

## Investment in Leasehold Land Interest – Lot 4C

Kaupulehu Developments holds an interest in an area of approximately 1,000 acres of vacant leasehold land zoned conservation located adjacent to Lot 4A, which currently has no development potential without both a development agreement with the lessor and zoning reclassification. The lease terminates in December 2025.

## 4. CONSOLIDATED VARIABLE INTEREST ENTITY

In February 2021, Barnwell Industries, Inc. established a new wholly-owned subsidiary named BOK Drilling, LLC (“BOK”) for the purpose of indirectly investing in oil and natural gas exploration and development in Oklahoma. BOK and Gros Ventre Partners, LLC (“Gros Ventre”), an entity previously affiliated with the Company (see Note 19 for additional details), entered into the Limited Liability Agreement (the “Teton Operating Agreement”) of Teton Barnwell Fund I, LLC (“Teton Barnwell”), an entity formed for the purpose of directly entering into such oil and natural gas investments. Under the terms of the Teton Operating Agreement, the profits of Teton Barnwell are split between BOK and Gros Ventre at 98% and 2%, respectively, and as the manager of Teton Barnwell, Gros Ventre is paid an annual asset management fee equal to 1% of the cumulative capital contributions made to Teton Barnwell as compensation for its management services. BOK is responsible for 100% of the capital contributions made to Teton Barnwell and as of September 30, 2022, the Company has made a total of $1,250,000 in cumulative capital contributions to Teton Barnwell to fund its initial oil and natural gas investment in Oklahoma and has received a total of $2,058,000 in distributions, net of non-controlling interests, from Teton Barnwell out of Teton Barnwell's operating cash flows. In October 2022, an additional $711,000 distribution, net of non-controlling interests, was received from Teton Barnwell. These contributions and distributions between Teton Barnwell and the Company do not affect our reported consolidated cash flows as Teton Barnwell is a consolidated entity, as discussed further below.

The Company has determined that Teton Barnwell is a VIE as the entity is structured with non-substantive voting rights and that the Company is the primary beneficiary. This is due to the fact that even though Teton Barnwell has a unanimous consent voting structure, BOK is responsible for 100% of the capital contributions required to fund Teton Barnwell's future oil exploration and development investments pursuant to the Teton Operating Agreement and thus, BOK has the power to steer the decisions that most significantly impact Teton Barnwell's economic performance and has the obligation to absorb any potential losses that could be significant to Teton Barnwell. As BOK is the primary beneficiary of the VIE, Teton Barnwell's operating results, assets and liabilities are consolidated by the Company.



The following table summarizes the carrying value of the assets and liabilities of Teton Barnwell that are consolidated by the Company. Intercompany balances are eliminated in consolidation and thus, are not reflected in the table below.

<table><tr><td></td><td>September 30, 2022</td><td>September 30, 2021</td></tr><tr><td>ASSETS</td><td></td><td></td></tr><tr><td>Cash and cash equivalents</td><td>$ 623,000</td><td>$ 136,000</td></tr><tr><td>Accounts and other receivables</td><td>606,000</td><td>118,000</td></tr><tr><td>Oil and natural gas properties, full cost method of accounting:</td><td></td><td></td></tr><tr><td>Proved properties, net</td><td>655,000</td><td>203,000</td></tr><tr><td>Unproved properties</td><td>—</td><td>962,000</td></tr><tr><td>Total assets</td><td>$ 1,884,000</td><td>$ 1,419,000</td></tr><tr><td>LIABILITIES</td><td></td><td></td></tr><tr><td>Accounts payable</td><td>$ 15,000</td><td>$ 3,000</td></tr><tr><td>Accrued capital expenditures</td><td>—</td><td>581,000</td></tr><tr><td>Accrued operating and other expenses</td><td>26,000</td><td>20,000</td></tr><tr><td>Total liabilities</td><td>$ 41,000</td><td>$ 604,000</td></tr></table>

## 5. ASSET HELD FOR SALE

## Contract Segment Drilling Rigs and Equipment

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 fair value of these assets in the aggregate amount of $687,000 was recorded as “Assets held for sale” on the Company's Consolidated Balance Sheet at September 30, 2021. In October 2021, the Company sold the drilling rig and related ancillary equipment for proceeds of $687,000, net of related costs, which was equivalent to its net carrying value.

In September 2022, the Company entered into a purchase and sale agreement with an independent third party for the sale of a contract drilling segment drilling rig and received a payment of $551,000, net of related costs. At September 30, 2022, the legal title for the drilling rig had not yet transferred to the buyer and therefore, the Company did not record a sale during the year ended September 30, 2022. The proceeds received from the buyer was recognized as a deposit and recorded in “Other Current Liabilities” on the Company's Consolidated Balance Sheet at September 30, 2022. No amount was recorded as assets held for sale at September 30, 2022 as the drilling rig was fully depreciated and therefore had a net book value of zero. In October 2022, the legal title for the drilling rig was transferred to the buyer and as a result, 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.



## 6. OIL AND NATURAL GAS PROPERTIES

## 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 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.

## Impairment of Oil and Natural Gas Properties

Under the full cost method of accounting, the Company performs quarterly oil and natural gas ceiling test calculations. 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.



## 7. PROPERTY AND EQUIPMENT AND ASSET RETIREMENT OBLIGATION

Barnwell’s property and equipment is detailed as follows:

<table><tr><td></td><td>Estimated Useful Lives</td><td>Gross Property and Equipment</td><td>Accumulated Depletion, Depreciation, Amortization, and Impairment</td><td>Net Property and Equipment</td></tr><tr><td>At September 30, 2022:</td><td></td><td></td><td></td><td></td></tr><tr><td>Oil and natural gas properties: (full cost accounting)</td><td></td><td></td><td></td><td></td></tr><tr><td>Proved properties</td><td>$     67,883,000</td><td>$    (54,651,000)</td><td>$   13,232,000</td><td></td></tr><tr><td>Unproved properties</td><td>—</td><td>—</td><td>—</td><td></td></tr><tr><td>Total oil and natural gas properties</td><td>67,883,000</td><td>(54,651,000)</td><td>13,232,000</td><td></td></tr><tr><td>Drilling rigs and equipment</td><td>3 - 10 years</td><td>6,304,000</td><td>(5,943,000)</td><td>361,000</td></tr><tr><td>Other property and equipment</td><td>3 - 10 years</td><td>619,000</td><td>(611,000)</td><td>8,000</td></tr><tr><td>Total</td><td>$   74,806,000</td><td>$    (61,205,000)</td><td>$   13,601,000</td><td></td></tr></table>

<table><tr><td></td><td>Estimated Useful Lives</td><td>Gross Property and Equipment</td><td>Accumulated Depletion, Depreciation, Amortization, and Impairment</td><td>Net Property and Equipment</td></tr><tr><td>At September 30, 2021:</td><td></td><td></td><td></td><td></td></tr><tr><td>Oil and natural gas properties: (full cost accounting)</td><td></td><td></td><td></td><td></td></tr><tr><td>Proved properties</td><td>$     58,490,000</td><td>$    (56,067,000)</td><td>$   2,423,000</td><td></td></tr><tr><td>Unproved properties</td><td>962,000</td><td>—</td><td>962,000</td><td></td></tr><tr><td>Total oil and natural gas properties</td><td>59,452,000</td><td>(56,067,000)</td><td>3,385,000</td><td></td></tr><tr><td>Drilling rigs and equipment</td><td>3 - 10 years</td><td>7,273,000</td><td>(6,789,000)</td><td>484,000</td></tr><tr><td>Other property and equipment</td><td>3 - 10 years</td><td>687,000</td><td>(681,000)</td><td>6,000</td></tr><tr><td>Total</td><td>$   67,412,000</td><td>$    (63,537,000)</td><td>$   3,875,000</td><td></td></tr></table>

See Note 6 for discussion of acquisitions and divestitures of oil and natural gas properties in fiscal 2022 and 2021.

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.



Barnwell recognizes the fair value of a liability for an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made. The following is a reconciliation of the asset retirement obligation:

<table><tr><td rowspan="2"></td><td colspan="2">Year ended September 30,</td></tr><tr><td>2022</td><td>2021</td></tr><tr><td>Asset retirement obligation as of beginning of year</td><td>$ 7,053,000</td><td>$ 6,194,000</td></tr><tr><td>Obligations incurred on new wells drilled or acquired</td><td>1,682,000</td><td>532,000</td></tr><tr><td>Liabilities associated with properties sold</td><td>(483,000)</td><td>(375,000)</td></tr><tr><td>Revision of estimated obligation</td><td>1,021,000</td><td>279,000</td></tr><tr><td>Accretion expense</td><td>767,000</td><td>580,000</td></tr><tr><td>Payments</td><td>(942,000)</td><td>(421,000)</td></tr><tr><td>Foreign currency translation adjustment</td><td>(642,000)</td><td>264,000</td></tr><tr><td>Asset retirement obligation as of end of year</td><td>8,456,000</td><td>7,053,000</td></tr><tr><td>Less current portion</td><td>(1,327,000)</td><td>(713,000)</td></tr><tr><td>Asset retirement obligation, long-term</td><td>$ 7,129,000</td><td>$ 6,340,000</td></tr></table>

Asset retirement obligations were reduced by $483,000 and $375,000, in fiscal 2022 and 2021, respectively, for those obligations that were assumed by purchasers of Barnwell's oil and natural gas properties. Asset retirement obligations increased by $1,021,000 and $279,000 in fiscal 2022 and 2021, respectively, primarily due to upward revisions from acceleration in the estimated timing of future abandonments as a result of changes in the estimated economic life of certain wells and changes in management's discretionary timing of abandonment projects due to an increase in estimated funds available as well as changes to the estimated cost of abandonments at the Manyberries area, as further discussed below. Asset retirement obligations also increased by $1,682,000 and $532,000 in fiscal 2022 and 2021, respectively, due primarily to our acquisitions (see Note 6 for additional details). The asset retirement obligation reflects the estimated present value of the amount of dismantlement, removal, site reclamation, and similar activities associated with Barnwell's oil and natural gas properties. Barnwell estimates the ultimate productive life of the properties, a credit-adjusted risk-free rate, and an inflation factor in order to determine the current present value of this obligation. The credit-adjusted risk-free rate for the entire asset retirement obligation is a blended rate which ranges from 6% to 13.5%.

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

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 of September 30, 2022, the Company recognized a cumulative reduction in the deposit balance of $113,000 for work performed under this program.

## 8. RETIREMENT PLANS

Barnwell sponsors a noncontributory defined benefit pension plan (“Pension Plan”) covering substantially all of its U.S. employees, with benefits based on years of service and the employee’s highest consecutive 5 years average earnings. Barnwell’s funding policy is intended to provide for both benefits attributed to service to date and for those expected to be earned in the future. In addition, Barnwell sponsors a Supplemental Executive Retirement Plan (“SERP”), a noncontributory supplemental retirement benefit plan which covers certain current and former employees of Barnwell for amounts exceeding the limits allowed under the Pension Plan, and previously sponsored a post-retirement medical insurance benefits plan (“Post-retirement Medical”) covering officers of Barnwell Industries, Inc., the parent company, who have attained at least 20 years of service of which at least 10 years were at the position of Vice President or higher, their spouses and qualifying dependents.

In June 2021, the Company terminated its Post-retirement Medical plan effective June 4, 2021. Pursuant to the Post-retirement Medical plan document, the Company, as the sponsor of the Post-retirement Medical plan, had the right to terminate the plan by the resolution of the Board of the Directors of the Company and sixty days' notice to each participant in the plan. Further, under the terms of the plan document, the participants in the Post-retirement Medical plan were not entitled to any unpaid vested benefits thereunder upon termination of the plan. The Post-retirement Medical plan was an unfunded plan and the Company funded benefits when payments were made. As a result of the plan termination, the Company recognized a non-cash gain of $2,341,000 during the year ended September 30, 2021.



The following tables detail the changes in benefit obligations, fair values of plan assets and reconciliations of the funded status of the retirement plans:

<table><tr><td rowspan="3"></td><td colspan="3">Pension</td><td colspan="3">SERP</td><td colspan="2">Post-retirement Medical</td></tr><tr><td colspan="8">September 30,</td></tr><tr><td>2022</td><td>2021</td><td>2022</td><td>2021</td><td>2022</td><td>2021</td><td></td><td></td></tr><tr><td>Change in Projected Benefit Obligation:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Benefit obligation at beginning of year</td><td>$ 10,365,000</td><td>$ 10,280,000</td><td>$ 2,136,000</td><td>$ 2,031,000</td><td>$</td><td>—</td><td>$ 2,839,000</td><td></td></tr><tr><td>Interest cost</td><td>290,000</td><td>258,000</td><td>60,000</td><td>51,000</td><td></td><td>—</td><td>48,000</td><td></td></tr><tr><td>Actuarial (gain) loss</td><td>(2,418,000)</td><td>(15,000)</td><td>(478,000)</td><td>63,000</td><td></td><td>—</td><td>—</td><td></td></tr><tr><td>Benefits paid</td><td>(306,000)</td><td>(158,000)</td><td>(3,000)</td><td>(9,000)</td><td></td><td>—</td><td>(5,000)</td><td></td></tr><tr><td>Termination of post-retirement medical plan</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td><td>—</td><td>(2,882,000)</td><td></td></tr><tr><td>Benefit obligation at end of year</td><td>7,931,000</td><td>10,365,000</td><td>1,715,000</td><td>2,136,000</td><td></td><td>—</td><td>—</td><td></td></tr><tr><td>Change in Plan Assets:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Fair value of plan assets at beginning of year</td><td>12,594,000</td><td>11,051,000</td><td>—</td><td>—</td><td></td><td>—</td><td>—</td><td></td></tr><tr><td>Actual return on plan assets</td><td>(972,000)</td><td>1,701,000</td><td>—</td><td>—</td><td></td><td>—</td><td>—</td><td></td></tr><tr><td>Employer contributions</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td><td>—</td><td>5,000</td><td></td></tr><tr><td>Benefits paid</td><td>(306,000)</td><td>(158,000)</td><td>—</td><td>—</td><td></td><td>—</td><td>(5,000)</td><td></td></tr><tr><td>Fair value of plan assets at end of year</td><td>11,316,000</td><td>12,594,000</td><td>—</td><td>—</td><td></td><td>—</td><td>—</td><td></td></tr><tr><td>Funded status</td><td>$ 3,385,000</td><td>$ 2,229,000</td><td>$ (1,715,000)</td><td>$ (2,136,000)</td><td>$</td><td>—</td><td>$</td><td>—</td></tr></table>

<table><tr><td rowspan="3"></td><td colspan="3">Pension</td><td colspan="3">SERP</td><td colspan="2">Post-retirement Medical</td></tr><tr><td colspan="8">September 30,</td></tr><tr><td>2022</td><td>2021</td><td>2022</td><td>2021</td><td>2022</td><td>2021</td><td></td><td></td></tr><tr><td>Amounts recognized in the Consolidated Balance Sheets:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Noncurrent assets</td><td>$ 3,385,000</td><td>$ 2,229,000</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td></td></tr><tr><td>Current liabilities</td><td>—</td><td>—</td><td>(66,000)</td><td>(35,000)</td><td>—</td><td>—</td><td>—</td><td></td></tr><tr><td>Noncurrent liabilities</td><td>—</td><td>—</td><td>(1,649,000)</td><td>(2,101,000)</td><td>—</td><td>—</td><td>—</td><td></td></tr><tr><td>Net amount</td><td>$ 3,385,000</td><td>$ 2,229,000</td><td>$ (1,715,000)</td><td>$ (2,136,000)</td><td>$ —</td><td>$ —</td><td>$ —</td><td></td></tr><tr><td>Amounts recognized in accumulated other comprehensive income before income taxes:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Net actuarial (gain) loss</td><td>$ (353,000)</td><td>$ 471,000</td><td>$ (343,000)</td><td>$ 135,000</td><td>$ —</td><td>$ —</td><td>$ —</td><td></td></tr><tr><td>Accumulated other comprehensive (income) loss</td><td>$ (353,000)</td><td>$ 471,000</td><td>$ (343,000)</td><td>$ 135,000</td><td>$ —</td><td>$ —</td><td>$ —</td><td></td></tr></table>

The accumulated benefit obligation for the Pension Plan was $7,931,000 and $10,365,000 at September 30, 2022 and 2021, respectively. The accumulated benefit obligation for the SERP was $1,715,000 and $2,136,000 at September 30, 2022 and 2021, respectively. The accumulated benefit obligations are the same as the projected benefit obligations due to the Pension Plan and SERP being frozen as of December 31, 2019.

Currently, no contributions will be made to the Pension Plan during fiscal 2023. The SERP plan is unfunded and Barnwell funds benefits when payments are made. Expected payments under the SERP for fiscal 2023 is not material. Fluctuations in actual market returns as well as changes in general interest rates



will result in changes in the market value of plan assets and may result in increased or decreased retirement benefits costs and contributions in future periods.

The Pension Plan actuarial gains in fiscal 2022 were primarily due to an increase in the discount rate, partially offset by an actuarial loss resulting from actual investment returns that were less than the assumed rate of return. The SERP actuarial gains in fiscal 2022 were primarily due to an increase in the discount rate.

The Pension Plan actuarial gains in fiscal 2021 were primarily due to an increase in the discount rate and actual investment returns that were greater than the assumed rate of return. The SERP actuarial losses in fiscal 2021 were primarily due to an updated mortality projection scale and adjustments due to experience, partially offset by an increase in the discount rate.

The following table presents the weighted-average assumptions used to determine benefit obligations and net benefit (income) costs:

<table><tr><td rowspan="3"></td><td colspan="2">Pension</td><td colspan="2">SERP</td><td colspan="2">Post-retirement Medical</td></tr><tr><td colspan="6">Year ended September 30,</td></tr><tr><td>2022</td><td>2021</td><td>2022</td><td>2021</td><td>2022</td><td>2021</td></tr><tr><td colspan="7">Assumptions used to determine fiscal year-end benefit obligations:</td></tr><tr><td>Discount rate</td><td>5.25%</td><td>2.84%</td><td>5.25%</td><td>2.84%</td><td>N/A</td><td>N/A</td></tr><tr><td>Rate of compensation increase</td><td>N/A</td><td>N/A</td><td>N/A</td><td>N/A</td><td>N/A</td><td>N/ A</td></tr><tr><td colspan="7">Assumptions used to determine net benefit costs (years ended):</td></tr><tr><td>Discount rate</td><td>2.84%</td><td>2.54%</td><td>2.84%</td><td>2.54%</td><td>N/A</td><td>2.54% / 3.00% \( ^{(1)} \)</td></tr><tr><td>Expected return on plan assets</td><td>5.00%</td><td>5.00%</td><td>N/A</td><td>N/A</td><td>N/A</td><td>N/A</td></tr><tr><td>Rate of compensation increase</td><td>N/A</td><td>N/A</td><td>N/A</td><td>N/A</td><td>N/A</td><td>N/ A</td></tr></table>

(1) 2.54% as of September 30, 2020 and 3.00% as of May 31, 2021 termination.

We select a discount rate by reference to yields available on the ICE Bank of America Merrill Lynch AA-AAA 15+ Index at our consolidated balance sheet date. The expected return on plan assets is based on an actuarial model which takes into consideration our investment mix and market conditions.

The components of net periodic benefit (income) cost are as follows:

<table><tr><td rowspan="3"></td><td colspan="2">Pension</td><td colspan="2">SERP</td><td colspan="2">Post-retirement Medical</td></tr><tr><td colspan="6">Year ended September 30,</td></tr><tr><td>2022</td><td>2021</td><td>2022</td><td>2021</td><td>2022</td><td>2021</td></tr><tr><td>Net periodic benefit (income) cost for the year:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Interest cost</td><td>$ 290,000</td><td>$ 258,000</td><td>$ 60,000</td><td>$ 51,000</td><td>$ —</td><td>$ 48,000</td></tr><tr><td>Expected return on plan assets</td><td>(622,000)</td><td>(546,000)</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Amortization of net actuarial loss</td><td>—</td><td>39,000</td><td>—</td><td>—</td><td>—</td><td>62,000</td></tr><tr><td>Net periodic benefit (income) cost</td><td>$ (332,000)</td><td>$ (249,000)</td><td>$ 60,000</td><td>$ 51,000</td><td>$ —</td><td>$ 110,000</td></tr></table>



The benefits expected to be paid under the retirement plans as of September 30, 2022 are as follows:

<table><tr><td></td><td colspan="2">Pension</td><td>SERP</td></tr><tr><td>Expected Benefit Payments:</td><td></td><td></td><td></td></tr><tr><td>Fiscal year ending September 30, 2023</td><td>$     412,000</td><td>$     66,000</td><td></td></tr><tr><td>Fiscal year ending September 30, 2024</td><td>$     552,000</td><td>$     130,000</td><td></td></tr><tr><td>Fiscal year ending September 30, 2025</td><td>$     545,000</td><td>$     129,000</td><td></td></tr><tr><td>Fiscal year ending September 30, 2026</td><td>$     537,000</td><td>$     128,000</td><td></td></tr><tr><td>Fiscal year ending September 30, 2027</td><td>$     529,000</td><td>$     127,000</td><td></td></tr><tr><td>Fiscal years ending September 30, 2028 through 2032</td><td>$     2,969,000</td><td>$     667,000</td><td></td></tr></table>

## Plan Assets

Management communicates periodically with its professional investment advisors to establish investment policies, direct investments and select investment options. The overall investment objective of the Pension Plan is to attain a diversified combination of investments that provides long-term growth in the assets of the plan to fund future benefit obligations while managing risk in order to meet current benefit obligations. Generally, interest and dividends received provide cash flows to fund current benefit obligations. Longer-term obligations are generally estimated to be provided for by growth in equity securities. The Company’s investment policy permits investments in a diversified mix of U.S. and international equities, fixed income securities and cash equivalents.

Barnwell’s investments in fixed income securities include corporate bonds, U.S. treasury and government securities, preferred securities, and fixed income exchange-traded funds. The Company’s investments in equity securities primarily include domestic and international large-cap companies, as well as, domestic and international equity securities exchange-traded funds.

The Company’s year-end target allocation, by asset category, and the actual asset allocations were as follows:

<table><tr><td></td><td rowspan="2">Target Allocation</td><td colspan="2">September 30,</td></tr><tr><td>Asset Category</td><td>2022</td><td>2021</td></tr><tr><td>Cash and other</td><td>0% - 25%</td><td>14%</td><td>—%</td></tr><tr><td>Fixed income securities</td><td>15% - 40%</td><td>34%</td><td>31%</td></tr><tr><td>Equity securities</td><td>45% - 75%</td><td>52%</td><td>69%</td></tr></table>

Actual investment allocations may vary from our target allocations from time to time due to prevailing market conditions. We periodically review our actual investment allocations and rebalance our investments to our target allocations as dictated by current and anticipated market conditions and required cash flows.

We categorize plan assets into three levels based upon the assumptions used to price the assets. Level 1 provides the most reliable measure of fair value, whereas Level 3 requires significant management judgment in determining the fair value. Equity securities and exchange-traded funds are valued by obtaining quoted prices on recognized and highly liquid exchanges. Fixed income securities are valued based upon the closing price reported in the active market in which the security is traded. All of our plan



assets are categorized as Level 1 assets, and as such, the actual market value is used to determine the fair value of assets.

The following tables set forth by level, within the fair value hierarchy, pension plan assets at their fair value:

<table><tr><td rowspan="2"></td><td colspan="5">Fair Value Measurements Using:</td></tr><tr><td>Carrying Amount as of September 30, 2022</td><td>Quoted Prices in Active Markets (Level 1)</td><td>Significant Other Observable Inputs (Level 2)</td><td>Significant Unobservable Inputs (Level 3)</td><td></td></tr><tr><td>Financial Assets:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Cash</td><td>$ 1,539,000</td><td>$ 1,539,000</td><td>$ —</td><td>$ —</td><td></td></tr><tr><td>Corporate bonds</td><td>1,000</td><td>1,000</td><td>—</td><td>—</td><td></td></tr><tr><td>U.S. treasury and government securities</td><td>561,000</td><td>561,000</td><td>—</td><td>—</td><td></td></tr><tr><td>Fixed income exchange-traded funds</td><td>3,223,000</td><td>3,223,000</td><td>—</td><td>—</td><td></td></tr><tr><td>Preferred securities</td><td>67,000</td><td>67,000</td><td>—</td><td>—</td><td></td></tr><tr><td>Equity securities exchange-traded funds</td><td>408,000</td><td>408,000</td><td>—</td><td>—</td><td></td></tr><tr><td>Equities</td><td>5,517,000</td><td>5,517,000</td><td>—</td><td>—</td><td></td></tr><tr><td>Total</td><td>$ 11,316,000</td><td>$ 11,316,000</td><td>$ —</td><td>$ —</td><td></td></tr></table>

<table><tr><td rowspan="2"></td><td>Carrying Amount as of September 30, 2021</td><td>Quoted Prices in Active Markets (Level 1)</td><td>Significant Other Observable Inputs (Level 2)</td><td>Significant Unobservable Inputs (Level 3)</td></tr><tr><td>Financial Assets:</td><td></td><td></td><td></td></tr><tr><td>Cash</td><td>$ 25,000</td><td>$ 25,000</td><td>$ —</td><td>$ —</td></tr><tr><td>Corporate bonds</td><td>1,000</td><td>1,000</td><td>—</td><td>—</td></tr><tr><td>Fixed income exchange-traded funds</td><td>3,809,000</td><td>3,809,000</td><td>—</td><td>—</td></tr><tr><td>Preferred securities</td><td>48,000</td><td>48,000</td><td>—</td><td>—</td></tr><tr><td>Equity securities exchange-traded funds</td><td>459,000</td><td>459,000</td><td>—</td><td>—</td></tr><tr><td>Equities</td><td>8,252,000</td><td>8,252,000</td><td>—</td><td>—</td></tr><tr><td>Total</td><td>$ 12,594,000</td><td>$ 12,594,000</td><td>$ —</td><td>$ —</td></tr></table>



## 9. INCOME TAXES

The components of earnings before income taxes, after adjusting the earnings for non-controlling interests, are as follows:

<table><tr><td rowspan="2"></td><td colspan="2">Year ended September 30,</td></tr><tr><td>2022</td><td>2021</td></tr><tr><td>United States</td><td>$ 739,000</td><td>$ 5,436,000</td></tr><tr><td>Canada</td><td>5,121,000</td><td>1,149,000</td></tr><tr><td></td><td>$ 5,860,000</td><td>$ 6,585,000</td></tr></table>

The components of the income tax provision related to the above earnings are as follows:

<table><tr><td rowspan="2"></td><td colspan="2">Year ended September 30,</td></tr><tr><td>2022</td><td>2021</td></tr><tr><td>Current provision:</td><td></td><td></td></tr><tr><td>United States - Federal</td><td></td><td></td></tr><tr><td>Before operating loss carryforwards</td><td>$ 727,000</td><td>$ 60,000</td></tr><tr><td>Benefit of operating loss carryforwards</td><td>(665,000)</td><td>(60,000)</td></tr><tr><td>After operating loss carryforwards</td><td>62,000</td><td>—</td></tr><tr><td>United States - State</td><td></td><td></td></tr><tr><td>Before operating loss carryforwards</td><td>518,000</td><td>174,000</td></tr><tr><td>Benefit of operating loss carryforwards</td><td>(62,000)</td><td>(7,000)</td></tr><tr><td>After operating loss carryforwards</td><td>456,000</td><td>167,000</td></tr><tr><td>Canadian</td><td></td><td></td></tr><tr><td>Before operating loss carryforwards</td><td>510,000</td><td>—</td></tr><tr><td>Benefit of operating loss carryforwards</td><td>(510,000)</td><td>—</td></tr><tr><td>After operating loss carryforwards</td><td>—</td><td>—</td></tr><tr><td>Total current</td><td>518,000</td><td>167,000</td></tr><tr><td>Deferred (benefit) provision:</td><td></td><td></td></tr><tr><td>United States - State</td><td>(171,000)</td><td>165,000</td></tr><tr><td>Canadian</td><td>—</td><td>—</td></tr><tr><td>Total deferred</td><td>(171,000)</td><td>165,000</td></tr><tr><td></td><td>$ 347,000</td><td>$ 332,000</td></tr></table>

Consolidated taxes do not bear a customary relationship to pretax results due primarily to the fact that the Company is taxed separately in Canada based on Canadian source operations and in the U.S. based on consolidated operations, and essentially all deferred tax assets, net of relevant offsetting deferred tax liabilities, are not estimated to have a future benefit as tax credits or deductions. 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 December 27, 2020, the President signed into law the Consolidated Appropriations Act (the “Act”), an omnibus spending bill to fund the federal government that also includes an array of COVID-related tax relief for individuals and businesses. The tax-related measures contained in the Act revise and expand provisions enacted earlier in the year by the Families First Coronavirus Response Act and the Coronavirus Aid, Relief, and Economic Security Act. The Act also extends a number of expiring tax provisions. Additionally, the Act provides for a 100% deduction for certain business meals incurred in calendar years 2021 and 2022. The Company determined that income tax effects related to the passage of the Consolidated Appropriations Act were not material to the financial statements for the years ended September 30, 2021 and 2022.

A reconciliation between the reported income tax expense and the amount computed by multiplying the earnings attributable to Barnwell before income taxes by the U.S. federal tax rate of 21% is as follows:

<table><tr><td rowspan="2"></td><td colspan="2">Year ended September 30,</td></tr><tr><td>2022</td><td>2021</td></tr><tr><td>Tax provision computed by applying statutory rate</td><td>$ 1,231,000</td><td>$ 1,383,000</td></tr><tr><td>Decrease in the valuation allowance</td><td>(1,450,000)</td><td>(1,427,000)</td></tr><tr><td>Additional effect of the foreign tax provision on the total tax provision</td><td>130,000</td><td>31,000</td></tr><tr><td>Uncertain tax positions</td><td>62,000</td><td>—</td></tr><tr><td>U.S. state tax provision, net of federal benefit</td><td>285,000</td><td>332,000</td></tr><tr><td>Other</td><td>89,000</td><td>13,000</td></tr><tr><td></td><td>$ 347,000</td><td>$ 332,000</td></tr></table>

The changes in the valuation allowance shown in the table above exclude the impact of changes in state taxes and foreign tax credit expiries, the valuation allowance impacts of which are incorporated within the respective reconciliation line items elsewhere in the table.



The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities are as follows:

<table><tr><td rowspan="2"></td><td colspan="2">September 30,</td></tr><tr><td>2022</td><td>2021</td></tr><tr><td>Deferred income tax assets:</td><td></td><td></td></tr><tr><td>Foreign tax credit carryover under U.S. tax law</td><td>$ 953,000</td><td>$ 1,197,000</td></tr><tr><td>U.S. federal net operating loss carryover</td><td>8,258,000</td><td>8,846,000</td></tr><tr><td>U.S. state unitary net operating loss carryovers</td><td>1,117,000</td><td>939,000</td></tr><tr><td>Canadian net operating loss carryovers</td><td>877,000</td><td>1,411,000</td></tr><tr><td>Tax basis of investment in land in excess of book basis under U.S. tax law</td><td>26,000</td><td>305,000</td></tr><tr><td>Property and equipment accumulated book depreciation and depletion in excess of tax under Canadian tax law</td><td>—</td><td>1,091,000</td></tr><tr><td>Property and equipment accumulated book depreciation and depletion in excess of tax under U.S. tax law</td><td>568,000</td><td>699,000</td></tr><tr><td>Liabilities accrued for books but not for tax under U.S. tax law</td><td>882,000</td><td>1,225,000</td></tr><tr><td>Liabilities accrued for books but not for tax under Canadian tax law</td><td>2,120,000</td><td>1,813,000</td></tr><tr><td>Foreign currency loss under U.S. tax law</td><td>102,000</td><td>—</td></tr><tr><td>Foreign currency loss under Canadian tax law</td><td>124,000</td><td>—</td></tr><tr><td>Other</td><td>278,000</td><td>442,000</td></tr><tr><td>Total gross deferred income tax assets</td><td>15,305,000</td><td>17,968,000</td></tr><tr><td>Less valuation allowance</td><td>(12,608,000)</td><td>(14,616,000)</td></tr><tr><td>Net deferred income tax assets</td><td>2,697,000</td><td>3,352,000</td></tr><tr><td>Deferred income tax liabilities:</td><td></td><td></td></tr><tr><td>Property and equipment accumulated tax depreciation and depletion in excess of book under Canadian tax law</td><td>(280,000)</td><td>—</td></tr><tr><td>Book basis of investment in land development partnerships in excess of tax basis under U.S. tax law</td><td>(545,000)</td><td>(1,156,000)</td></tr><tr><td>Book basis of investment in land development partnerships in excess of tax basis under U.S. state non-unitary tax law</td><td>(166,000)</td><td>(352,000)</td></tr><tr><td>U.S. oil and gas property and equipment accumulated tax depreciation and depletion in excess of book under U.S. tax law</td><td>(121,000)</td><td>(142,000)</td></tr><tr><td>U.S. oil and gas property and equipment accumulated tax depreciation and depletion in excess of book under U.S. state tax law</td><td>(23,000)</td><td>(7,000)</td></tr><tr><td>U.S. tax law impact of foreign branch deferred tax asset under Canadian tax law</td><td>(1,465,000)</td><td>(1,782,000)</td></tr><tr><td>Other</td><td>(285,000)</td><td>(272,000)</td></tr><tr><td>Total deferred income tax liabilities</td><td>(2,885,000)</td><td>(3,711,000)</td></tr><tr><td>Net deferred income tax liability</td><td>$ (188,000)</td><td>$ (359,000)</td></tr><tr><td>Reported as:</td><td></td><td></td></tr><tr><td>Deferred income tax assets</td><td>—</td><td>—</td></tr><tr><td>Deferred income tax liabilities</td><td>(188,000)</td><td>(359,000)</td></tr><tr><td>Net deferred income tax liability</td><td>$ (188,000)</td><td>$ (359,000)</td></tr></table>

The total valuation allowance decreased $2,008,000 for the year ended September 30, 2022. The decrease was due to current fiscal year operational activity that resulted in changes in deferred tax asset



and liability balances, and there were no changes in judgment about the realizability of related deferred tax assets in future years. Of the total net decrease in the valuation allowance for fiscal 2022, $1,614,000 was recognized as an income tax benefit and $394,000 was credited to accumulated other comprehensive loss.

Net deferred tax assets at September 30, 2022 of $2,697,000 consists of the portion of U.S. federal consolidated deferred tax assets that are estimated to be partially realized through corresponding reversals of U.S. federal consolidated deferred tax liabilities related to the Kukio Resort Land Development Partnerships' excess of book income over taxable income, the book basis of property and equipment in excess of tax basis under U.S. federal and Canadian tax law, foreign branch deferred taxes and certain other minor deferred tax liabilities.

At September 30, 2022, Barnwell had U.S. federal foreign tax credit carryovers, U.S. federal net operating loss carryovers, U.S. state net operating loss carryovers and Canadian net operating loss carryovers totaling $953,000, $39,327,000, $17,452,000 and $3,411,000, respectively. All four items were fully offset by valuation allowances at September 30, 2022, except for a portion of Hawaii NOLs which is expected to shelter a portion of the reversal of the Company’s Hawaii non-unitary taxable temporary difference related to its investment in Hawaii land development partnerships. The U.S. federal net operating loss carryovers generated through September 30, 2018 expire in fiscal years 2032-2038, the U.S. state unitary net operating loss carryovers generated through September 30, 2017 expire in fiscal years 2033-2037, the Canadian net operating loss carryovers expire in fiscal years 2037-2042, and the foreign tax credit carryovers expire in fiscal years 2023-2025. The U.S. federal net operating loss carryovers generated in fiscal years 2019-2021 and the U.S. state net operating loss carryovers generated in fiscal years 2018-2022 have no expiry, however utilization of the U.S. state and U.S. federal net operating loss carryovers generated in these and future years are limited to 80% of taxable income.

FASB ASC Topic 740, Income Taxes, prescribes a threshold for recognizing the financial statement effects of a tax position when it is more likely than not, based on the technical merits, that the position will be sustained upon examination by a taxing authority.

Barnwell files U.S. federal income tax returns, income tax returns in various U.S. states, and Canadian federal and provincial tax returns. A number of years may elapse before an uncertain tax position, for which we have unrecognized tax benefits, is audited and finally resolved. We believe that our unrecognized tax benefits are reflected on a more likely than not basis. We evaluate uncertain tax positions based on ongoing facts and circumstances. Any change in judgment related to the expected resolution of uncertain tax positions is recognized in earnings in the period in which such change occurs. Interest and penalties, if any, related to unrecognized tax benefits are recorded as a component of income tax expense. Settlement of any particular position could require the use of cash. Favorable resolution for an amount less than the amount estimated by Barnwell would be recognized as a decrease in the effective income tax rate in the period of resolution, and unfavorable resolution in excess of the amount estimated by Barnwell would be recognized as an increase in the effective income tax rate in the period of resolution.

Below are the changes in unrecognized tax benefits.

<table><tr><td rowspan="2"></td><td colspan="2">Year ended September 30,</td></tr><tr><td>2022</td><td>2021</td></tr><tr><td>Balance at beginning of year</td><td>$ —</td><td>$ —</td></tr><tr><td>Effect of tax positions taken in prior years</td><td>60,000</td><td>—</td></tr><tr><td>Accrued interest related to tax positions taken</td><td>2,000</td><td>—</td></tr><tr><td>Balance at end of year</td><td>$ 62,000</td><td>$ —</td></tr></table>



Uncertain tax positions at September 30, 2022 are related to the potential assessment of penalties and interest for the failure to file certain foreign information forms with 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 missing forms and plans to request abatement of the potential penalties and interest.

Included below is a summary of the tax years, by jurisdiction, that remain subject to examination by taxing authorities at September 30, 2022:

<table><tr><td>Jurisdiction</td><td>Fiscal Years Open</td></tr><tr><td>U.S. federal</td><td>2019 - 2021</td></tr><tr><td>Various U.S. states</td><td>2019 - 2021</td></tr><tr><td>Canada federal</td><td>2015 - 2021</td></tr><tr><td>Various Canadian provinces</td><td>2015 - 2021</td></tr></table>



## 10. REVENUE FROM CONTRACTS WITH CUSTOMERS

## Disaggregation of Revenue

The following tables provide information about disaggregated revenue by revenue streams, reportable segments, geographical region, and timing of revenue recognition for the years ended September 30, 2022 and 2021.

Year ended September 30, 2022

<table><tr><td></td><td>Oil and natural gas</td><td>Contract drilling</td><td>Land investment</td><td>Other</td><td>Total</td></tr><tr><td>Revenue streams:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Oil</td><td>$ 15,747,000</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ 15,747,000</td></tr><tr><td>Natural gas</td><td>4,527,000</td><td>—</td><td>—</td><td>—</td><td>4,527,000</td></tr><tr><td>Natural gas liquids</td><td>2,307,000</td><td>—</td><td>—</td><td>—</td><td>2,307,000</td></tr><tr><td>Drilling and pump</td><td>—</td><td>4,540,000</td><td>—</td><td>—</td><td>4,540,000</td></tr><tr><td>Contingent residual payments</td><td>—</td><td>—</td><td>1,295,000</td><td>—</td><td>1,295,000</td></tr><tr><td>Other</td><td>—</td><td>—</td><td>—</td><td>111,000</td><td>111,000</td></tr><tr><td>Total revenues before interest income</td><td>$ 22,581,000</td><td>$ 4,540,000</td><td>$ 1,295,000</td><td>$ 111,000</td><td>$ 28,527,000</td></tr><tr><td>Geographical regions:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>United States</td><td>$ 3,496,000</td><td>$ 4,540,000</td><td>$ 1,295,000</td><td>$ 9,000</td><td>$ 9,340,000</td></tr><tr><td>Canada</td><td>19,085,000</td><td>—</td><td>—</td><td>102,000</td><td>19,187,000</td></tr><tr><td>Total revenues before interest income</td><td>$ 22,581,000</td><td>$ 4,540,000</td><td>$ 1,295,000</td><td>$ 111,000</td><td>$ 28,527,000</td></tr><tr><td>Timing of revenue recognition:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Goods transferred at a point in time</td><td>$ 22,581,000</td><td>$ —</td><td>$ 1,295,000</td><td>$ 111,000</td><td>$ 23,987,000</td></tr><tr><td>Services transferred over time</td><td>—</td><td>4,540,000</td><td>—</td><td>—</td><td>4,540,000</td></tr><tr><td>Total revenues before interest income</td><td>$ 22,581,000</td><td>$ 4,540,000</td><td>$ 1,295,000</td><td>$ 111,000</td><td>$ 28,527,000</td></tr></table>

Year ended September 30, 2021

<table><tr><td></td><td>Oil and natural gas</td><td>Contract drilling</td><td>Land investment</td><td>Other</td><td>Total</td></tr><tr><td>Revenue streams:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Oil</td><td>$ 7,617,000</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ 7,617,000</td></tr><tr><td>Natural gas</td><td>1,871,000</td><td>—</td><td>—</td><td>—</td><td>1,871,000</td></tr><tr><td>Natural gas liquids</td><td>766,000</td><td>—</td><td>—</td><td>—</td><td>766,000</td></tr><tr><td>Drilling and pump</td><td>—</td><td>5,809,000</td><td>—</td><td>—</td><td>5,809,000</td></tr><tr><td>Contingent residual payments</td><td>—</td><td>—</td><td>1,738,000</td><td>—</td><td>1,738,000</td></tr><tr><td>Other</td><td>—</td><td>—</td><td>—</td><td>304,000</td><td>304,000</td></tr><tr><td>Total revenues before interest income</td><td>$ 10,254,000</td><td>$ 5,809,000</td><td>$ 1,738,000</td><td>$ 304,000</td><td>$ 18,105,000</td></tr><tr><td>Geographical regions:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>United States</td><td>$ 118,000</td><td>$ 5,809,000</td><td>$ 1,738,000</td><td>$ 35,000</td><td>$ 7,700,000</td></tr><tr><td>Canada</td><td>10,136,000</td><td>—</td><td>—</td><td>269,000</td><td>10,405,000</td></tr><tr><td>Total revenues before interest income</td><td>$ 10,254,000</td><td>$ 5,809,000</td><td>$ 1,738,000</td><td>$ 304,000</td><td>$ 18,105,000</td></tr><tr><td>Timing of revenue recognition:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Goods transferred at a point in time</td><td>$ 10,254,000</td><td>$ —</td><td>$ 1,738,000</td><td>$ 304,000</td><td>$ 12,296,000</td></tr><tr><td>Services transferred over time</td><td>—</td><td>5,809,000</td><td>—</td><td>—</td><td>5,809,000</td></tr><tr><td>Total revenues before interest income</td><td>$ 10,254,000</td><td>$ 5,809,000</td><td>$ 1,738,000</td><td>$ 304,000</td><td>$ 18,105,000</td></tr></table>



## Contract Balances

The following table provides information about accounts receivables, contract assets and contract liabilities from contracts with customers:

<table><tr><td rowspan="2"></td><td colspan="3">September 30,</td></tr><tr><td>2022</td><td colspan="2">2021</td></tr><tr><td>Accounts receivables from contracts with customers</td><td>$ 4,038,000</td><td>$ 2,797,000</td><td></td></tr><tr><td>Contract assets</td><td>580,000</td><td>581,000</td><td></td></tr><tr><td>Contract liabilities</td><td>1,087,000</td><td>455,000</td><td></td></tr></table>

Accounts receivables from contracts with customers are included in “Accounts and other receivables, net of allowance for doubtful accounts,” and contract assets, which includes costs and estimated earnings in excess of billings and retainage, are included in “Other current assets.” Contract liabilities, which includes billings in excess of costs and estimated earnings are included in “Other current liabilities” in the accompanying Consolidated Balance Sheets.

Retainage, included in contract assets, represents amounts due from customers, but where payments are withheld contractually until certain construction milestones are met. Amounts retained typically range from 5% to 10% of the total invoice, up to contractually-specified maximums. The Company classifies as a current asset those retainages that are expected to be collected in the next twelve months.

Contract assets represent the Company’s rights to consideration in exchange for services transferred to a customer that have not been billed as of the reporting date. The Company’s rights are generally unconditional at the time its performance obligations are satisfied.

When the Company receives consideration, or such consideration is unconditionally due, from a customer prior to transferring goods or services to the customer under the terms of a sales contract, the Company records deferred revenue, which represents a contract liability. Such deferred revenue typically results from billings in excess of costs and estimated earnings on uncompleted contracts. As of September 30, 2022 and 2021, the Company had $1,087,000 and $455,000, respectively, included in “Other current liabilities” on the Consolidated Balance Sheets for those performance obligations expected to be completed in the next twelve months.

During the years ended September 30, 2022 and 2021, the amount of revenue recognized that was previously included in contract liabilities as of the beginning of the respective period was $394,000 and $1,013,000, respectively.

Contracts are sometimes modified for a change in scope or other requirements. The Company considers contract modifications to exist when the modification either creates new or changes the existing enforceable rights and obligations. Most of the Company’s contract modifications are for goods and services that are not distinct from the existing performance obligations. The effect of a contract modification on the transaction price, and the measure of progress for the performance obligation to which it relates, is recognized as an adjustment to revenue (either as an increase or decrease) on a cumulative catchup basis.



## Performance Obligations

The Company’s remaining performance obligations for drilling and pump installation contracts (hereafter referred to as “backlog”) represent the unrecognized revenue value of the Company’s contract commitments. The Company’s backlog may vary significantly each reporting period based on the timing of major new contract commitments. In addition, our customers have the right, under some infrequent circumstances, to terminate contracts or defer the timing of the Company’s services and their payments to us. Nearly all of the Company’s contract drilling segment contracts have original expected durations of one year or less. At September 30, 2022, the Company had five contract drilling jobs with original expected durations of greater than one year. For these contracts, approximately 71% of the remaining performance obligation of $4,890,000 is expected to be recognized in the next twelve months and the remaining, thereafter.

## Contract Fulfillment Costs

Preconstruction costs, which include costs such as set-up and mobilization, are capitalized and allocated across all performance obligations and deferred and amortized over the contract term on a progress towards completion basis. As of September 30, 2022 and 2021, the Company had $689,000 and $326,000, respectively, in unamortized preconstruction costs related to contracts that were not completed. During the years ended September 30, 2022 and 2021, the amortization of preconstruction costs related to contracts was $296,000 and $224,000, respectively. These amounts have been included in “Contract drilling operating” costs and expenses in the accompanying Consolidated Statements of Operations. Additionally, no impairment charges in connection with the Company’s preconstruction costs were recorded during the years ended September 30, 2022 and 2021.

## Uninstalled Materials

Uninstalled materials, which typically consists of well casing or pumps, are excluded in the costs-to-costs calculation for the duration of the contract as including these costs would result in a distortion of progress towards satisfaction of the performance obligation due to the resulting cumulative catch-up in margin in a single period. An equal amount of cost and revenue is recorded when uninstalled materials are controlled by the customer, which is typically when Barnwell has the right to payment for the materials and when the materials are delivered to the customer's site or location and such materials have been accepted by the customer. Uninstalled materials are held in inventory and included in “Other current assets” on the Company’s Consolidated Balance Sheets.

A summary of Barnwell's uninstalled materials is as follows:

<table><tr><td rowspan="2">Uninstalled materials</td><td colspan="2">September 30, 2022</td><td colspan="2">September 30, 2021</td></tr><tr><td>$</td><td>351,000</td><td>$</td><td>226,000</td></tr></table>

## 11. SEGMENT AND GEOGRAPHIC INFORMATION

Barnwell operates the following segments: 1) acquiring, developing, producing and selling oil and natural gas in Canada and Oklahoma (oil and natural gas); 2) investing in land interests in Hawaii (land investment); and 3) drilling wells and installing and repairing water pumping systems in Hawaii (contract drilling).



The following table presents certain financial information related to Barnwell’s reporting segments. All revenues reported are from external customers with no intersegment sales or transfers.

<table><tr><td rowspan="2"></td><td colspan="2">Year ended September 30,</td></tr><tr><td>2022</td><td>2021</td></tr><tr><td>Revenues:</td><td></td><td></td></tr><tr><td>Oil and natural gas</td><td>$ 22,581,000</td><td>$ 10,254,000</td></tr><tr><td>Contract drilling</td><td>4,540,000</td><td>5,809,000</td></tr><tr><td>Land investment</td><td>1,295,000</td><td>1,738,000</td></tr><tr><td>Other</td><td>111,000</td><td>304,000</td></tr><tr><td>Total before interest income</td><td>28,527,000</td><td>18,105,000</td></tr><tr><td>Interest income</td><td>18,000</td><td>8,000</td></tr><tr><td>Total revenues</td><td>$ 28,545,000</td><td>$ 18,113,000</td></tr><tr><td>Depletion, depreciation, and amortization:</td><td></td><td></td></tr><tr><td>Oil and natural gas</td><td>$ 2,606,000</td><td>$ 645,000</td></tr><tr><td>Contract drilling</td><td>171,000</td><td>305,000</td></tr><tr><td>Other</td><td>1,000</td><td>13,000</td></tr><tr><td>Total depletion, depreciation, and amortization</td><td>$ 2,778,000</td><td>$ 963,000</td></tr><tr><td>Impairment:</td><td></td><td></td></tr><tr><td>Oil and natural gas</td><td>$ —</td><td>$ 630,000</td></tr><tr><td>Contract drilling</td><td>—</td><td>38,000</td></tr><tr><td>Land investment</td><td>89,000</td><td>—</td></tr><tr><td>Total impairment</td><td>$ 89,000</td><td>$ 668,000</td></tr><tr><td>Operating profit (loss) (before general and administrative expenses):</td><td></td><td></td></tr><tr><td>Oil and natural gas</td><td>$ 10,536,000</td><td>$ 2,423,000</td></tr><tr><td>Contract drilling</td><td>(222,000)</td><td>(89,000)</td></tr><tr><td>Land investment</td><td>1,206,000</td><td>1,738,000</td></tr><tr><td>Other</td><td>110,000</td><td>291,000</td></tr><tr><td>Gain on sale of assets</td><td>—</td><td>1,982,000</td></tr><tr><td>Total operating profit</td><td>11,630,000</td><td>6,345,000</td></tr><tr><td>Equity in income of affiliates:</td><td></td><td></td></tr><tr><td>Land investment</td><td>3,400,000</td><td>5,793,000</td></tr><tr><td>General and administrative expenses</td><td>(8,044,000)</td><td>(7,088,000)</td></tr><tr><td>Foreign currency loss</td><td>(484,000)</td><td>—</td></tr><tr><td>Interest expense</td><td>(1,000)</td><td>(13,000)</td></tr><tr><td>Interest income</td><td>18,000</td><td>8,000</td></tr><tr><td>Gain on debt extinguishment</td><td>—</td><td>149,000</td></tr><tr><td>Gain on termination of post-retirement medical plan</td><td>—</td><td>2,341,000</td></tr><tr><td>Earnings before income taxes</td><td>$ 6,519,000</td><td>$ 7,535,000</td></tr></table>



## Capital Expenditures:

<table><tr><td rowspan="2"></td><td colspan="2">Year ended September 30,</td></tr><tr><td>2022</td><td>2021</td></tr><tr><td>Oil and natural gas</td><td>$ 13,755,000</td><td>$ 3,028,000</td></tr><tr><td>Contract drilling</td><td>45,000</td><td>62,000</td></tr><tr><td>Other</td><td>5,000</td><td>1,000</td></tr><tr><td>Total</td><td>$ 13,805,000</td><td>$ 3,091,000</td></tr></table>

Oil and natural gas capital expenditures include acquisitions as well as changes to capitalized asset retirement obligations, including revisions of asset retirement obligations (see Note 7 for additional details).

Assets By Segment:

<table><tr><td rowspan="2"></td><td colspan="2">September 30,</td></tr><tr><td>2022</td><td>2021</td></tr><tr><td>Oil and natural gas (1)</td><td>$ 17,477,000</td><td>$ 6,401,000</td></tr><tr><td>Contract drilling (2)</td><td>3,260,000</td><td>4,071,000</td></tr><tr><td>Other:</td><td></td><td></td></tr><tr><td>Cash and cash equivalents</td><td>12,804,000</td><td>11,279,000</td></tr><tr><td>Corporate and other</td><td>3,674,000</td><td>2,684,000</td></tr><tr><td>Total</td><td>$ 37,215,000</td><td>$ 24,435,000</td></tr></table>

(1) Located primarily in the province of Alberta, Canada with a minor portion in Oklahoma.

(2) Located in Hawaii.

Long-Lived Assets By Geographic Area:

<table><tr><td rowspan="2"></td><td colspan="2">September 30,</td></tr><tr><td>2022</td><td>2021</td></tr><tr><td>United States</td><td>$ 4,540,000</td><td>$ 4,180,000</td></tr><tr><td>Canada</td><td>12,578,000</td><td>2,220,000</td></tr><tr><td>Total</td><td>$ 17,118,000</td><td>$ 6,400,000</td></tr></table>

Revenue By Geographic Area:

<table><tr><td rowspan="2"></td><td colspan="2">Year ended September 30,</td></tr><tr><td>2022</td><td>2021</td></tr><tr><td>United States</td><td>$ 9,340,000</td><td>$ 7,700,000</td></tr><tr><td>Canada</td><td>19,187,000</td><td>10,405,000</td></tr><tr><td>Total (excluding interest income)</td><td>$ 28,527,000</td><td>$ 18,105,000</td></tr></table>



## 12. ACCUMULATED OTHER COMPREHENSIVE INCOME

Components of accumulated other comprehensive income, net of taxes, are as follows:

<table><tr><td rowspan="2"></td><td colspan="3">Year ended September 30,</td></tr><tr><td>2022</td><td>2021</td><td></td></tr><tr><td>Foreign currency translation:</td><td></td><td></td><td></td></tr><tr><td>Beginning accumulated foreign currency translation</td><td>$ 262,000</td><td>$ 545,000</td><td></td></tr><tr><td>Change in cumulative translation adjustment before reclassifications</td><td>(40,000)</td><td>(283,000)</td><td></td></tr><tr><td>Income taxes</td><td>—</td><td>—</td><td></td></tr><tr><td>Net current period other comprehensive loss</td><td>(40,000)</td><td>(283,000)</td><td></td></tr><tr><td>Ending accumulated foreign currency translation</td><td>222,000</td><td>262,000</td><td></td></tr><tr><td>Retirement plans:</td><td></td><td></td><td></td></tr><tr><td>Beginning accumulated retirement plans benefit cost</td><td>(230,000)</td><td>(1,980,000)</td><td></td></tr><tr><td>Amortization of net actuarial loss</td><td>—</td><td>101,000</td><td></td></tr><tr><td>Net actuarial gain arising during the period</td><td>1,302,000</td><td>1,108,000</td><td></td></tr><tr><td>Gain on termination of post-retirement medical plan</td><td>—</td><td>541,000</td><td></td></tr><tr><td>Income taxes</td><td>—</td><td>—</td><td></td></tr><tr><td>Net current period other comprehensive income</td><td>1,302,000</td><td>1,750,000</td><td></td></tr><tr><td>Ending accumulated retirement plans benefit income (cost)</td><td>1,072,000</td><td>(230,000)</td><td></td></tr><tr><td>Accumulated other comprehensive income, net of taxes</td><td>$ 1,294,000</td><td>$ 32,000</td><td></td></tr></table>

The amortization of net actuarial loss for the retirement plans are included in the computation of net periodic benefit (income) cost which is a component of “General and administrative” expenses on the accompanying Consolidated Statements of Operations (see Note 8 for additional details).

## 13. FAIR VALUE MEASUREMENTS

## Fair Value of Financial Instruments

The carrying values of cash and cash equivalents, accounts and other receivables, accounts payable and accrued current liabilities approximate their fair values due to the short-term nature of the instruments.

## Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

The estimated fair values of oil and natural gas properties and the asset retirement obligation incurred in the drilling of oil and natural gas wells or assumed in the acquisitions of additional oil and natural gas working interests are based on an estimated discounted cash flow model and market assumptions. The significant Level 3 assumptions used in the calculation of estimated discounted cash flows included future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development, operating and asset retirement costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates. See Note 6 for additional information regarding oil and natural gas property acquisitions.

Barnwell estimates the fair value of asset retirement obligations based on the projected discounted future cash outflows required to settle abandonment and restoration liabilities. Such an estimate requires assumptions and judgments regarding the existence of liabilities, the amount and timing of cash outflows



required to settle the liability, what constitutes adequate restoration, inflation factors, credit adjusted discount rates, and consideration of changes in legal, regulatory, environmental and political environments. Abandonment and restoration cost estimates are determined in conjunction with Barnwell's reserve engineers based on historical information regarding costs incurred to abandon and restore similar well sites, information regarding current market conditions and costs, and knowledge of subject well sites and properties. Asset retirement obligation fair value measurements in the current period were Level 3 fair value measurements. As further described in Note 7, the Company recognizes the fair value of a liability for an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made. Asset retirement obligations are not measured at fair value subsequent to initial recognition.

## 14. DEBT

## 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 PPP pursuant to the CARES Act that was signed into law in March 2020. 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.

## 15. LEASES

The Company’s right-of-use (“ROU”) assets and lease liabilities at September 30, 2022, primarily relate to non-cancelable operating leases for our Hawaii corporate and Canadian office spaces and our leasehold land interest for Lot 4C held by Kaupulehu Developments. Management determines if a contract is or contains a lease at inception of the contract or modification of the contract. A contract is or contains a lease if the contract conveys the right to control the use of the asset for a period in exchange for consideration.

Operating lease ROU assets and liabilities are recognized based on the present value of future minimum lease payments over the expected lease term at commencement date. The Company’s leases do not provide a readily determinable implicit rate; therefore, management uses the Company’s incremental borrowing rate to discount lease payments based on information available at lease commencement. Our



lease terms may include options to extend or terminate the lease when it is reasonably certain we will exercise that option. Lease expense for minimum lease payments is recognized on a straight-line basis over the expected lease terms. The Company has lease agreements with lease and non-lease components and the non-lease components are excluded in the calculation of the ROU asset and lease liability and expensed as incurred. None of the Company’s lease agreements contain material residual value guarantees or material restrictions or covenants.

A ROU asset and corresponding lease liability is not recorded for leases with an initial term of 12 months or less (short-term leases) as the Company recognizes lease expense for these leases as incurred over the lease term.

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.

Leases recorded on the balance sheet consist of the following:

<table><tr><td rowspan="2"></td><td colspan="3">September 30,</td></tr><tr><td>2022</td><td>2021</td><td></td></tr><tr><td>Assets:</td><td></td><td></td><td></td></tr><tr><td>Operating lease right-of-use assets</td><td>$ 132,000</td><td>$ 296,000</td><td></td></tr><tr><td>Total right-of-use assets</td><td>$ 132,000</td><td>$ 296,000</td><td></td><td></td></tr><tr><td>Liabilities:</td><td></td><td></td><td></td></tr><tr><td>Current portion of operating lease liabilities (1)</td><td>$ 105,000</td><td>$ 117,000</td><td></td></tr><tr><td>Operating lease liabilities</td><td>117,000</td><td>180,000</td><td></td></tr><tr><td>Total lease liabilities</td><td>$ 222,000</td><td>$ 297,000</td><td></td></tr></table>

(1) Amount included in “Other Current Liabilities” in the Consolidated Balance Sheets.

The components of lease expense are as follows:

<table><tr><td rowspan="2"></td><td colspan="2">Year ended September 30,</td></tr><tr><td>2022</td><td>2021</td></tr><tr><td>Operating lease cost</td><td>$ 108,000</td><td>$ 130,000</td></tr><tr><td>Short-term lease cost</td><td>327,000</td><td>254,000</td></tr><tr><td>Variable lease cost</td><td>154,000</td><td>103,000</td></tr><tr><td>Total lease cost</td><td>$ 589,000</td><td>$ 487,000</td></tr></table>

Supplemental information related to leases is as follows:

<table><tr><td rowspan="2"></td><td colspan="2">September 30,</td></tr><tr><td>2022</td><td>2021</td></tr><tr><td>Cash paid related to operating lease liabilities</td><td>$ 108,000</td><td>$ 133,000</td></tr><tr><td>Operating leases:</td><td></td><td></td></tr><tr><td>Weighted-average remaining lease term (in years)</td><td>2.4</td><td>2.9</td></tr><tr><td>Weighted-average discount rate</td><td>5.30%</td><td>5.19%</td></tr></table>



The remaining lease payments for our operating leases as of September 30, 2022, are as follows:

<table><tr><td colspan="3">Fiscal year ending:</td></tr><tr><td>2023</td><td>$ 113,000</td><td></td></tr><tr><td>2024</td><td>75,000</td><td></td></tr><tr><td>2025</td><td>41,000</td><td></td></tr><tr><td>2026</td><td>8,000</td><td></td></tr><tr><td>2027</td><td>—</td><td></td></tr><tr><td>Thereafter through 2028</td><td>—</td><td></td></tr><tr><td>Total lease payments</td><td>237,000</td><td></td></tr><tr><td>Less: amounts representing interest</td><td>(15,000)</td><td></td></tr><tr><td>Present value of lease liabilities</td><td>$ 222,000</td><td></td></tr></table>

The lease payments for the Lot 4C leasehold land zoned conservation were subject to renegotiation as of January 1, 2006. Per the lease agreement, the lease payments will remain unchanged pending an appraisal, whereupon the lease rent could be adjusted to fair market value. Barnwell does not know the amount of the new lease payments which could be effective upon performance of the appraisal; they may remain unchanged or increase, and Barnwell currently expects the adjustment, if any, to not be material. The future lease payment disclosures above assume the minimum lease payments for leasehold land in effect at December 31, 2005 remain unchanged through December 2025, the end of the lease term.

## 16. STOCKHOLDERS' EQUITY

In May 2022, Barnwell’s stockholders approved the amendment to increase the Company’s number of authorized shares of common stock from 20,000,000 to 40,000,000 shares and approved amendments to the Company’s 2018 Equity Incentive Plan which included the amendment to increase the total number of shares of stock authorized for awards from 800,000 to 1,600,000 shares among other amendments.

## Share-based Compensation

## 2018 Equity Incentive Plan

The Company’s stock option plans are administered by the Compensation Committee of the Board of Directors. The stockholder-approved 2018 Equity Incentive Plan provides for the issuance of incentive stock options, nonstatutory stock options, stock options with stock appreciation rights, restricted stock, restricted stock units and performance units, qualified performance-based awards, and stock grants to employees, consultants and non-employee members of the Board of Directors. 1,600,000 shares of Barnwell common stock have been reserved for issuance and as of September 30, 2022, a total of 935,000 share options remain available for grant.

Barnwell currently has a policy of issuing new shares to satisfy share option exercises when the optionee requests shares.

## Equity-classified Awards

In February 2021, the Board of Directors of the Company granted options to purchase 665,000 shares of common stock, 310,000 shares to independent directors and 355,000 shares to employees. 605,000 shares of the stock options granted have an exercise price equal to the closing market price of



Barnwell’s stock on the date of grant of $3.33, vest annually over three years, and expire in ten years from the date of grant. 60,000 shares of the stock options granted have an exercise price of $3.66 (110% of the closing market price on the date of grant for options granted to affiliates), vest annually over three years, and expire in five years from the date of grant.

The following assumptions were used in estimating the fair value for equity-classified share options granted in the year ended September 30, 2021:

<table><tr><td></td><td>&gt; 10% Owner-Employee</td><td>Others</td></tr><tr><td>Number of shares</td><td>60,000</td><td>605,000</td></tr><tr><td>Expected volatility</td><td>127.4%</td><td>105.8%</td></tr><tr><td>Expected dividends</td><td>None</td><td>None</td></tr><tr><td>Expected term (in years)</td><td>3.5</td><td>6.0</td></tr><tr><td>Risk-free interest rate</td><td>0.19%</td><td>0.82%</td></tr><tr><td>Expected forfeitures</td><td>None</td><td>None</td></tr><tr><td>Fair value per share</td><td>$2.51</td><td>$2.70</td></tr></table>

The application of alternative assumptions could produce significantly different estimates of the fair value of share-based compensation, and consequently, the related costs reported in the “General and administrative” expenses in the Consolidated Statements of Operations.

A summary of the activity in Barnwell’s equity-classified share options from October 1, 2021 through September 30, 2022 is presented below:

<table><tr><td>Options</td><td>Shares</td><td>Weighted-Average Exercise Price</td><td>Weighted-Average Remaining Contractual Term</td><td>Aggregate Intrinsic Value</td></tr><tr><td>Outstanding at October 1, 2021</td><td>615,000</td><td>$ 3.36</td><td></td><td></td></tr><tr><td>Granted</td><td>—</td><td>—</td><td></td><td></td></tr><tr><td>Exercised</td><td>—</td><td>—</td><td></td><td></td></tr><tr><td>Expired/Forfeited</td><td>—</td><td>—</td><td></td><td></td></tr><tr><td>Outstanding at September 30, 2022</td><td>615,000</td><td>$ 3.36</td><td>7.9</td><td>$ —</td></tr><tr><td>Exercisable at September 30, 2022</td><td>205,000</td><td>$ 3.36</td><td>7.9</td><td>$ —</td></tr></table>

Compensation cost for equity-classified awards is measured at the grant date based on the fair value of the award and is recognized as an expense over the requisite service period. During the years ended September 30, 2022 and 2021, the Company recognized share-based compensation expense of $657,000 and $643,000, respectively. There was no impact on income taxes for the years ended September 30, 2022 and 2021 due to a full valuation allowance on the related deferred tax asset. As of September 30, 2022, the total remaining unrecognized compensation cost related to nonvested share options was $348,000, which is expected to be recognized over the weighted-average remaining requisite service period of 1.4 years.



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.

## 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 an at-the-market offering program ("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.

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.

## 17. COMMITMENTS AND CONTINGENCIES

## Incentive compensation plan

Barnwell established an incentive compensation plan to compensate all Canadian oil and natural gas segment personnel and an incentive compensation plan to compensate Canadian executive officers. The value of the plans are directly related to our oil and natural gas segment's free cash flows from Canadian properties and the divestiture of Canadian oil and natural gas assets. As of September 30, 2022, Barnwell has accrued approximately $381,000 in bonus compensation under these plans and the amount is reported in “Accrued compensation” on the Consolidated Balance Sheet at September 30, 2022.

## Subscription Receipts Agreement

In May 2022, Barnwell Investments LLC, a new wholly-owned subsidiary of Barnwell Industries Inc., entered into an agreement to participate in a private placement offering (the "Offering") of subscriptions receipts (the "Subscription Agreement") with 1287398 B.C. Ltd. (the "Issuer") and agreed to purchase 1,724,138 subscription receipts at a price of $1.16 per subscription receipt for a total of



$2,000,000 from the Issuer. 1287398 B.C. Ltd. is a Canadian reporting issuer. The Offering is subject to regulatory approvals, including the conditional listing approval by the TSX Venture Exchange.

The Subscription Agreement was held in escrow by the Issuer until certain escrow release conditions were met which included the Issuer raising an additional $3,000,000 in gross proceeds from other parties under the private placement offering for total minimum gross proceeds of $5,000,000. As of September 30, 2022, the escrow release condition had not been satisfied and no cash was paid by the Company to the Issuer. In November 2022, the Subscription Agreement was terminated by the Company and therefore the Company no longer has a commitment with the Issuer.

## Environmental Matters

Because of the inherent uncertainties associated with environmental assessment and remediation activities, future expenses to remediate sites identified in the future, if any, could be incurred. Barnwell's management is not currently aware of any significant environmental contingent liabilities requiring disclosure or accrual.

## Legal and Regulatory Matters

Barnwell is routinely involved in disputes with third parties that occasionally require litigation. In addition, Barnwell is required to maintain compliance with all current governmental controls and regulations in the ordinary course of business. Barnwell’s management is not aware of any claims or litigation involving Barnwell that are likely to have a material adverse effect on its results of operations, financial position or liquidity.

In 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.

## Other Matters

Barnwell is obligated to pay Nearco Enterprises Ltd. 10.4%, net of non-controlling interests' share, of Kaupulehu Developments' gross receipts from real estate transactions. The fees represent compensation for promotion and marketing of Kaupulehu Developments' property and were determined based on the estimated fair value of such services. These fees are included in general and administrative expenses.

Barnwell is obligated to pay its external real estate legal counsel 1.2%, net of non-controlling interests' share, of all Increment II payments received by Kaupulehu Developments for services provided



by its external real estate legal counsel in the negotiation and closing of the Increment II transaction. These fees are included in general and administrative expenses.

Kaupulehu Developments is also obligated to pay an amount equal to 0.72% and 0.20% of the cumulative net profits of KD II to KD Development and a pool of various individuals, respectively, all of whom are partners of KKM and are unrelated to Barnwell, in compensation for the agreement of these parties to admit the new development partner for Increment II. Such compensation will be reflected as the obligation becomes probable and the amount of the obligation can be reasonably estimated.

## 18. INFORMATION RELATING TO THE CONSOLIDATED STATEMENTS OF CASH FLOWS

The following table details the effect of changes in current assets and liabilities on the Consolidated Statements of Cash Flows, and presents supplemental cash flow information:

<table><tr><td rowspan="2"></td><td colspan="2">Year ended September 30,</td></tr><tr><td>2022</td><td>2021</td></tr><tr><td>Increase (decrease) from changes in:</td><td></td><td></td></tr><tr><td>Receivables</td><td>$ (1,763,000)</td><td>$ (814,000)</td></tr><tr><td>Income tax receivable</td><td>15,000</td><td>457,000</td></tr><tr><td>Other current assets</td><td>(531,000)</td><td>(920,000)</td></tr><tr><td>Accounts payable</td><td>110,000</td><td>(746,000)</td></tr><tr><td>Accrued compensation</td><td>(48,000)</td><td>668,000</td></tr><tr><td>Other current liabilities</td><td>1,190,000</td><td>(796,000)</td></tr><tr><td>Decrease from changes in current assets and liabilities</td><td>$ (1,027,000)</td><td>$ (2,151,000)</td></tr><tr><td>Supplemental disclosure of cash flow information:</td><td></td><td></td></tr><tr><td>Cash paid (received) during the year for:</td><td></td><td></td></tr><tr><td>Income taxes refunded, net</td><td>$ (98,000)</td><td>$ (303,000)</td></tr><tr><td>Supplemental disclosure of non-cash investing activities:</td><td></td><td></td></tr><tr><td>Canadian income tax withheld on proceeds from the sale of oil and natural gas properties</td><td>$ —</td><td>$ 598,000</td></tr></table>

Capital expenditure accruals related to oil and natural gas acquisition and development increased $882,000 and $346,000 during the years ended September 30, 2022 and 2021, respectively. Additionally, capital expenditure accruals related to oil and natural gas asset retirement obligations increased $2,703,000 and $811,000 during the years ended September 30, 2022 and 2021, respectively.

## 19. RELATED PARTY TRANSACTIONS

Kaupulehu Developments is entitled to receive payments from the sales of lots and/or residential units by KD I and KD II. KD I and KD II are part of the Kukio Resort Land Development Partnerships in which Barnwell holds indirect 19.6% and 10.8% non-controlling ownership interests, respectively, accounted for under the equity method of investment. The percentage of sales payments are part of transactions which took place in 2004 and 2006 where Kaupulehu Developments sold its leasehold interests in Increment I and Increment II to KD I's and KD II's predecessors in interest, respectively, which was prior to Barnwell's affiliation with KD I and KD II which commenced on November 27, 2013, the acquisition date of our ownership interest in the Kukio Resort Land Development Partnerships. Changes



to the arrangement above, effective March 7, 2019, are discussed in Note 3.

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 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 lots within Increment I.

Mr. Colin R. O'Farrell, formerly a member of the Board of Directors of the Company through March 7, 2022, is the sole member of Four Pines Operating LLC which owns a 25% interest in Gros Ventre. In February 2021, Gros Ventre and BOK, a wholly-owned subsidiary of Barnwell, entered into the Teton Operating Agreement of Teton Barnwell, an entity formed for the purpose of directly investing in oil and natural gas exploration and development in Oklahoma. Under the terms of the Teton Operating Agreement, Gros Ventre makes no capital contributions and receives 2% of the profits of Teton Barnwell. Additionally, as the manager of Teton Barnwell, Gros Ventre is paid an annual asset management fee equal to 1% of the cumulative capital contributions made to Teton Barnwell as compensation for its management services.

## 20. SUBSEQUENT EVENTS

## Gain on Sale of Drilling Rig

In September 2022, the Company entered into a purchase and sale agreement with an independent third party for the sale of a contract drilling segment drilling rig and received a payment of $551,000, net of related costs. At September 30, 2022, the legal title for the drilling rig had not yet transferred to the buyer and therefore, the Company did not record a sale during the year ended September 30, 2022. The proceeds received from the buyer was recognized as a deposit and recorded in “Other Current Liabilities” on the Company's Consolidated Balance Sheet at September 30, 2022. No amount was recorded as assets held for sale at September 30, 2022 as the drilling rig was fully depreciated and therefore had a net book value of zero. In October 2022, the legal title for the drilling rig was transferred to the buyer and as a result, 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.

## The Tax Benefits Preservation Plan

On October 17, 2022, the Board of Directors of the Company adopted a Tax Benefits Preservation Plan (the “Tax Plan”) designed to protect the availability of the Company’s existing net operating loss carryforwards and certain other tax attributes (collectively, the “Tax Benefits”).

The Company has generated substantial Tax Benefits, which could potentially be used in certain circumstances to reduce its future income tax obligations. Utilization of these NOLs and other Tax Benefits depends on many factors, including the Company’s future taxable income. Additionally, the Company’s ability to use its Tax Benefits would be substantially limited if it were to experience an “ownership change,” as defined under Section 382 of the Internal Revenue Code of 1986, as amended (“Section 382”). In general, a corporation would experience an ownership change if the percentage of the corporation’s stock owned by one or more “5% stockholders,” as defined under Section 382, were to increase by more than 50 percentage points over their lowest ownership percentage within a rolling three-year period (or, if a shorter period, since the Company’s last ownership change). The purpose of the Tax Plan is to reduce the likelihood that the Company will experience an ownership change under Section 382, which would limit the Company’s future use of its Tax Benefits and, in turn, significantly impair the value of such Tax Benefits.



Absent the adoption of the Tax Plan, the Company would be at a greater risk of experiencing an ownership change under Section 382 in the future as a result of certain changes in its investor base and subsequent shifts in its stock ownership that cannot be predicted or controlled. If the Company were to undergo an ownership change, limitations would be placed on the Company’s ability to utilize the Tax Benefits in future years in which it has taxable income, and the Company would pay more taxes than if it were able to utilize the Tax Benefits fully. This could result in a negative impact on the Company’s financial position, results of operations, and cash flows. The Tax Plan is designed to preserve the Tax Benefits by reducing the risk of an ownership change under Section 382.

The Tax Plan adopted by the Board of Directors is similar to plans adopted by other publicly held companies with substantial Tax Benefits and has a limited duration of three years. The Tax Plan is not designed to prevent any action that the Board of Directors determines to be in the best interest of the Company and its stockholders.

To implement the Tax Plan, the Board of Directors declared a dividend of one right (a “Right”) for each outstanding share of the Company’s common stock. The Rights will be issued to stockholders of record at the close of business on October 27, 2022 pursuant to the Tax Plan. The Rights will be exercisable if a person or group of persons acquires 4.95% or more of the Company’s common stock. The Rights will also be exercisable if a person or group of persons that already owns 4.95% or more of the Company’s common stock acquires an additional share other than as a result of a dividend or a stock split. Existing stockholders that beneficially own in excess of 4.95% of the Company’s common stock will be “grandfathered in” at their current ownership level. If the Rights become exercisable, all holders of Rights, other than the person or group of persons triggering the Rights, will be entitled to purchase shares of the Company’s common stock at a 50% discount. Rights held by the person or group of persons triggering the Rights will become void and will not be exercisable.

The Tax Plan also includes an exchange option. At any time after any person or group of persons acquires 4.95% or more of the Company’s common stock, but less than 50% or more of the outstanding shares of the Company’s common stock, the Board of Directors, at its option, may exchange the Rights (other than Rights owned by such person or group of persons which will have become void), in whole or in part, at an exchange ratio of three shares of the Company’s common stock per outstanding Right (subject to adjustment).

The Rights will trade with the Company’s common stock and will expire at the close of business on October 17, 2025. The Rights will expire under other circumstances as described in the Tax Plan, including on the date set by the Board of Directors following a determination that the Tax Plan is no longer necessary or desirable for the preservation of the Tax Benefits or no significant Tax Benefits are available to be carried forward or are otherwise available. The Board of Directors may terminate the Tax Plan prior to the time the Rights are triggered or may redeem the Rights prior to the Distribution Date, as defined in the Tax Plan.

## Kukio Resort Land Development Partnerships and Sale of Interest in Leasehold Land

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.

Additionally, 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.



In December 2022, the Company, through a new wholly-owned subsidiary named Barnwell Texas, LLC, entered into agreements with an independent third party whereby the Company will now own a 22.3% non-operated working interest in oil and natural gas leasehold acreage and a 15.4% non-operated working interest in the planned drilling of two oil wells in the Permian Basin in Texas. The Company paid $5,099,000 to the independent third party under these agreements. In addition, the Company is obligated to pay a broker’s fee of 5% of the capital invested under this arrangement to Four Pines Exploration LLC - Exploration - Series 1 (“Four Pines”). Four Pines is controlled by Mr. Colin O’Farrell who is an affiliate of Teton Barnwell (see Note 19 for additional details). This transaction will be reflected in Barnwell's first quarter of fiscal 2023 ending December 31, 2022.

## Cash Dividend

In December 2022, the Company's Board of Directors declared a cash dividend of $0.015 per share payable on January 11, 2023 to stockholders of record on December 27, 2022.

## 21. SUMMARY OF SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)

Disclosure is not required as Barnwell qualifies as a smaller reporting company.

## 22. SUPPLEMENTARY OIL AND NATURAL GAS INFORMATION (UNAUDITED)

The following tables summarize information relative to Barnwell’s oil and natural gas operations, which are conducted in Canada and in the U.S. state of Oklahoma. Proved reserves are the estimated quantities of oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved producing oil and natural gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. The estimated net interests in total proved and proved producing reserves are based upon subjective engineering judgments and may be affected by the limitations inherent in such estimations. The process of estimating reserves is subject to continual revision as additional information becomes available as a result of drilling, testing, reservoir studies and production history. There can be no assurance that such estimates will not be materially revised in subsequent periods.

## (A) Oil and Natural Gas Reserves

The following tables summarizes changes in the estimates of Barnwell’s net interests in total proved reserves of oil and natural gas liquids and natural gas, which are located in Canada and the U.S. state of Oklahoma. Proved oil, natural gas liquids and natural gas reserves located in the U.S state of Oklahoma were not significant in fiscal 2021 and was therefore not included in the tables below. All of the information regarding Canadian reserves in this Form 10-K is derived from the report of our independent petroleum reserve engineers, InSite, and is included as an Exhibit to this Form 10-K. All of the information regarding U.S. reserves in this Form 10-K is derived from the report of our independent petroleum reserve engineers, Ryder Scott, and is included as an Exhibit to this Form 10-K. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimates of established proved producing oil and natural gas properties. Accordingly, these estimates are expected to change as future information becomes available.



Proved oil and natural gas reserves are the estimated quantities of oil and natural gas that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions (i.e., prices and costs) existing at the time the estimate is made. 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.

<table><tr><td rowspan="2"></td><td colspan="3">Oil &amp; NGL (Bbls)</td></tr><tr><td>Canada</td><td>United States</td><td>Total</td></tr><tr><td>Proved reserves:</td><td></td><td></td><td></td></tr><tr><td>Balance at September 30, 2020</td><td>535,000</td><td>—</td><td>535,000</td></tr><tr><td>Revisions of previous estimates</td><td>291,000</td><td>—</td><td>291,000</td></tr><tr><td>Acquisitions of reserves</td><td>80,000</td><td>—</td><td>80,000</td></tr><tr><td>Less sales of reserves</td><td>(97,000)</td><td>—</td><td>(97,000)</td></tr><tr><td>Less production</td><td>(169,000)</td><td>—</td><td>(169,000)</td></tr><tr><td>Balance at September 30, 2021</td><td>640,000</td><td>—</td><td>640,000</td></tr><tr><td>Revisions of previous estimates</td><td>154,000</td><td>—</td><td>154,000</td></tr><tr><td>Extensions, discoveries and other additions</td><td>285,000</td><td>132,000</td><td>417,000</td></tr><tr><td>Acquisitions of reserves</td><td>99,000</td><td>—</td><td>99,000</td></tr><tr><td>Less production</td><td>(188,000)</td><td>(42,000)</td><td>(230,000)</td></tr><tr><td>Proved Reserves, September 30, 2022</td><td>990,000</td><td>90,000</td><td>1,080,000</td></tr><tr><td>Proved Developed Reserves, September 30, 2022</td><td>956,000</td><td>90,000</td><td>1,046,000</td></tr><tr><td>Proved Undeveloped Reserves, September 30, 2022</td><td>34,000</td><td>—</td><td>34,000</td></tr></table>

<table><tr><td rowspan="2"></td><td colspan="3">Natural Gas (Mcf)</td></tr><tr><td>Canada</td><td>United States</td><td>Total</td></tr><tr><td>Proved reserves:</td><td></td><td></td><td></td></tr><tr><td>Balance at September 30, 2020</td><td>2,310,000</td><td>—</td><td>2,310,000</td></tr><tr><td>Revisions of previous estimates</td><td>1,345,000</td><td>—</td><td>1,345,000</td></tr><tr><td>Acquisitions of reserves</td><td>289,000</td><td>—</td><td>289,000</td></tr><tr><td>Less sales of reserves</td><td>(341,000)</td><td>—</td><td>(341,000)</td></tr><tr><td>Less production</td><td>(690,000)</td><td>—</td><td>(690,000)</td></tr><tr><td>Balance at September 30, 2021</td><td>2,913,000</td><td>—</td><td>2,913,000</td></tr><tr><td>Revisions of previous estimates</td><td>968,000</td><td>—</td><td>968,000</td></tr><tr><td>Extensions, discoveries and other additions</td><td>1,200,000</td><td>658,000</td><td>1,858,000</td></tr><tr><td>Acquisitions of reserves</td><td>223,000</td><td>—</td><td>223,000</td></tr><tr><td>Less sales of reserves</td><td>(13,000)</td><td>—</td><td>(13,000)</td></tr><tr><td>Less production</td><td>(772,000)</td><td>(192,000)</td><td>(964,000)</td></tr><tr><td>Proved Reserves, September 30, 2022</td><td>4,519,000</td><td>466,000</td><td>4,985,000</td></tr><tr><td>Proved Developed Reserves, September 30, 2022</td><td>4,391,000</td><td>466,000</td><td>4,857,000</td></tr><tr><td>Proved Undeveloped Reserves, September 30, 2022</td><td>128,000</td><td>—</td><td>128,000</td></tr></table>



<table><tr><td rowspan="2"></td><td colspan="3">Total Equivalent Reserves (Boe)</td></tr><tr><td>Canada</td><td>United States</td><td>Total</td></tr><tr><td>Proved reserves:</td><td></td><td></td><td></td></tr><tr><td>Balance at September 30, 2020</td><td>933,000</td><td>—</td><td>933,000</td></tr><tr><td>Revisions of previous estimates</td><td>523,000</td><td>—</td><td>523,000</td></tr><tr><td>Acquisitions of reserves</td><td>130,000</td><td>—</td><td>130,000</td></tr><tr><td>Less sales of reserves</td><td>(156,000)</td><td>—</td><td>(156,000)</td></tr><tr><td>Less production</td><td>(288,000)</td><td>—</td><td>(288,000)</td></tr><tr><td>Balance at September 30, 2021</td><td>1,142,000</td><td>—</td><td>1,142,000</td></tr><tr><td>Revisions of previous estimates</td><td>321,000</td><td>—</td><td>321,000</td></tr><tr><td>Extensions, discoveries and other additions</td><td>492,000</td><td>245,000</td><td>737,000</td></tr><tr><td>Acquisitions of reserves</td><td>137,000</td><td>—</td><td>137,000</td></tr><tr><td>Less sales of reserves</td><td>(2,000)</td><td>—</td><td>(2,000)</td></tr><tr><td>Less production</td><td>(321,000)</td><td>(75,000)</td><td>(396,000)</td></tr><tr><td>Proved Reserves, September 30, 2022</td><td>1,769,000</td><td>170,000</td><td>1,939,000</td></tr><tr><td>Proved Developed Reserves, September 30, 2022</td><td>1,713,000</td><td>170,000</td><td>1,883,000</td></tr><tr><td>Proved Undeveloped Reserves, September 30, 2022</td><td>56,000</td><td>—</td><td>56,000</td></tr></table>

## (B) Capitalized Costs Relating to Oil and Natural Gas Producing Activities

All capitalized costs relating to oil and natural gas producing activities in Canada and the U.S. are summarized as follows:

<table><tr><td rowspan="2"></td><td colspan="4">September 30, 2022</td></tr><tr><td>Canada</td><td colspan="2">United States</td><td>Total</td></tr><tr><td>Proved properties</td><td>$ 66,825,000</td><td>$ 1,058,000</td><td>$ 67,883,000</td><td></td></tr><tr><td>Unproved properties</td><td>—</td><td>—</td><td>—</td><td></td></tr><tr><td>Total capitalized costs</td><td>66,825,000</td><td>1,058,000</td><td>67,883,000</td><td></td></tr><tr><td>Accumulated depletion, depreciation, and impairment</td><td>54,248,000</td><td>403,000</td><td>54,651,000</td><td></td></tr><tr><td>Net capitalized costs</td><td>$ 12,577,000</td><td>$ 655,000</td><td>$ 13,232,000</td><td></td></tr></table>

<table><tr><td rowspan="2"></td><td colspan="4">September 30, 2021</td></tr><tr><td>Canada</td><td>United States</td><td>Total</td><td></td></tr><tr><td>Proved properties</td><td>$ 58,273,000</td><td>$ 217,000</td><td>$ 58,490,000</td><td></td></tr><tr><td>Unproved properties</td><td>—</td><td>962,000</td><td>962,000</td><td></td></tr><tr><td>Total capitalized costs</td><td>58,273,000</td><td>1,179,000</td><td>59,452,000</td><td></td></tr><tr><td>Accumulated depletion, depreciation, and impairment</td><td>56,053,000</td><td>14,000</td><td>56,067,000</td><td></td></tr><tr><td>Net capitalized costs</td><td>$ 2,220,000</td><td>$ 1,165,000</td><td>$ 3,385,000</td><td></td></tr></table>



(C) Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development

<table><tr><td rowspan="2"></td><td colspan="4">Year ended September 30, 2022</td></tr><tr><td>Canada</td><td>United States</td><td>Total</td><td></td></tr><tr><td>Acquisition of properties:</td><td></td><td></td><td></td><td></td></tr><tr><td>Proved</td><td>$ 3,247,000</td><td>$ —</td><td>$ 3,247,000</td><td></td></tr><tr><td>Unproved</td><td>—</td><td>—</td><td>—</td><td></td></tr><tr><td>Exploration costs</td><td>55,000</td><td>—</td><td>55,000</td><td></td></tr><tr><td>Development costs</td><td>10,574,000</td><td>(121,000)</td><td>10,453,000</td><td></td></tr><tr><td>Total</td><td>$ 13,876,000</td><td>$ (121,000)</td><td>$ 13,755,000</td><td></td></tr></table>

<table><tr><td rowspan="2"></td><td colspan="4">September 30, 2021</td></tr><tr><td>Canada</td><td>United States</td><td>Total</td><td></td></tr><tr><td>Acquisition of properties:</td><td></td><td></td><td></td><td></td></tr><tr><td>Proved</td><td>$ 1,032,000</td><td>$ 70,000</td><td>$ 1,102,000</td><td></td></tr><tr><td>Unproved</td><td>—</td><td>—</td><td>—</td><td></td></tr><tr><td>Exploration costs</td><td>255,000</td><td>—</td><td>255,000</td><td></td></tr><tr><td>Development costs</td><td>563,000</td><td>1,108,000</td><td>1,671,000</td><td></td></tr><tr><td>Total</td><td>$ 1,850,000</td><td>$ 1,178,000</td><td>$ 3,028,000</td><td></td></tr></table>

Costs incurred in the tables above include additions and revisions to Barnwell’s asset retirement obligation of $2,703,000 and $811,000 for the years ended September 30, 2022 and 2021, respectively.

(D) Results of Operations for Oil and Natural Gas Producing Activities

<table><tr><td rowspan="2"></td><td colspan="4">Year ended September 30, 2022</td></tr><tr><td>Canada</td><td>United States</td><td>Total</td><td></td></tr><tr><td>Net revenues</td><td>$ 19,085,000</td><td>$ 3,496,000</td><td>$ 22,581,000</td><td></td></tr><tr><td>Production costs</td><td>(8,999,000)</td><td>(440,000)</td><td>(9,439,000)</td><td></td></tr><tr><td>Depletion</td><td>(2,217,000)</td><td>(389,000)</td><td>(2,606,000)</td><td></td></tr><tr><td>Pre-tax results of operations (1)</td><td>7,869,000</td><td>2,667,000</td><td>10,536,000</td><td></td></tr><tr><td>Estimated income tax expense (2)</td><td>—</td><td>107,000</td><td>107,000</td><td></td></tr><tr><td>Results of operations (1)</td><td>$ 7,869,000</td><td>$ 2,560,000</td><td>$ 10,429,000</td><td></td></tr></table>



<table><tr><td rowspan="2"></td><td colspan="4">Year ended September 30, 2021</td></tr><tr><td>Canada</td><td colspan="2">United States</td><td>Total</td></tr><tr><td>Net revenues</td><td>$ 10,136,000</td><td>$ 118,000</td><td>$ 10,254,000</td><td></td></tr><tr><td>Production costs</td><td>(6,532,000)</td><td>(24,000)</td><td>(6,556,000)</td><td></td></tr><tr><td>Depletion</td><td>(631,000)</td><td>(14,000)</td><td>(645,000)</td><td></td></tr><tr><td>Reduction of carrying value of oil and natural gas properties</td><td>(630,000)</td><td>—</td><td>(630,000)</td><td></td></tr><tr><td>Pre-tax results of operations (1)</td><td>2,343,000</td><td>80,000</td><td>2,423,000</td><td></td></tr><tr><td>Estimated income tax expense (2)</td><td>—</td><td>—</td><td>—</td><td></td></tr><tr><td>Results of operations (1)</td><td>$ 2,343,000</td><td>$ 80,000</td><td>$ 2,423,000</td><td></td></tr></table>

(1) Before gain on sale of oil and natural gas properties, general and administrative expenses, interest expense, and foreign exchange gains and losses.
(2) Estimated income tax expense includes changes to the deferred income tax valuation allowance necessary for the portion of Canadian and U.S. federal tax law deferred tax assets that may not be realizable.

## (E) Standardized Measure, Including Year-to-Year Changes Therein, of Estimated Discounted Future Net Cash Flows

The following tables utilize reserve and production data estimated by independent petroleum reserve engineers. The information may be useful for certain comparison purposes but should not be solely relied upon in evaluating Barnwell or its performance. Moreover, the projections should not be construed as realistic estimates of future cash flows, nor should the standardized measure be viewed as representing current value. Additionally, proved oil, natural gas liquids and natural gas reserves located in the U.S. were not significant in fiscal 2021 and was therefore not included in the tables below.

The estimated future cash flows at September 30, 2022 and 2021 were based on average sales prices in effect on the first day of the month for the preceding twelve month period in accordance with SEC Release No. 33-8995. The future production and development costs represent the estimated future expenditures that we will incur to develop and produce the proved reserves, assuming continuation of existing economic conditions. The future income tax expenses were computed by applying statutory income tax rates in existence at September 30, 2022 and 2021 to the future pre-tax net cash flows relating to proved reserves, net of the tax basis of the properties involved.

Material revisions to reserve estimates may occur in the future, development and production of the oil and natural gas reserves may not occur in the periods assumed and actual prices realized and actual costs incurred are expected to vary significantly from those used. Management does not rely upon this information in making investment and operating decisions; rather, those decisions are based upon a wide range of factors, including estimates of probable reserves as well as proved reserves and price and cost assumptions different than those reflected herein.

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



Standardized Measure of Discounted Future Net Cash Flows

<table><tr><td rowspan="2"></td><td colspan="3">Year ended September 30, 2022</td></tr><tr><td>Canada</td><td>United States</td><td>Total</td></tr><tr><td>Future cash inflows</td><td>$ 93,658,000</td><td>$ 6,676,000</td><td>$ 100,334,000</td></tr><tr><td>Future production costs</td><td>(44,523,000)</td><td>(832,000)</td><td>(45,355,000)</td></tr><tr><td>Future development costs</td><td>(274,000)</td><td>—</td><td>(274,000)</td></tr><tr><td>Future income tax expenses</td><td>(6,908,000)</td><td>(233,000)</td><td>(7,141,000)</td></tr><tr><td>Future net cash flows excluding abandonment, decommissioning and reclamation</td><td>41,953,000</td><td>5,611,000</td><td>47,564,000</td></tr><tr><td>Future abandonment, decommissioning and reclamation</td><td>(16,719,000)</td><td>(11,000)</td><td>(16,730,000)</td></tr><tr><td>Future net cash flows</td><td>25,234,000</td><td>5,600,000</td><td>30,834,000</td></tr><tr><td>10% annual discount for timing of cash flows</td><td>(1,144,000)</td><td>(1,812,000)</td><td>(2,956,000)</td></tr><tr><td>Standardized measure of discounted future net cash flows</td><td>$ 24,090,000</td><td>$ 3,788,000</td><td>$ 27,878,000</td></tr></table>

<table><tr><td rowspan="2"></td><td colspan="3">Year ended September 30, 2021</td></tr><tr><td>Canada</td><td>United States</td><td>Total</td></tr><tr><td>Future cash inflows</td><td>$ 36,130,000</td><td>$ —</td><td>$ 36,130,000</td></tr><tr><td>Future production costs</td><td>(25,323,000)</td><td>—</td><td>(25,323,000)</td></tr><tr><td>Future development costs</td><td>(240,000)</td><td>—</td><td>(240,000)</td></tr><tr><td>Future income tax expenses</td><td>(995,000)</td><td>—</td><td>(995,000)</td></tr><tr><td>Future net cash flows excluding abandonment, decommissioning and reclamation</td><td>9,572,000</td><td>—</td><td>9,572,000</td></tr><tr><td>Future abandonment, decommissioning and reclamation</td><td>(14,525,000)</td><td>—</td><td>(14,525,000)</td></tr><tr><td>Future net cash flows</td><td>(4,953,000)</td><td>—</td><td>(4,953,000)</td></tr><tr><td>10% annual discount for timing of cash flows</td><td>7,598,000</td><td>—</td><td>7,598,000</td></tr><tr><td>Standardized measure of discounted future net cash flows</td><td>$ 2,645,000</td><td>$ —</td><td>$ 2,645,000</td></tr></table>

Changes in the Standardized Measure of Discounted Future Net Cash Flows

<table><tr><td rowspan="2"></td><td colspan="2">Year ended September 30,</td></tr><tr><td>2022</td><td>2021</td></tr><tr><td>Beginning of year</td><td>$ 2,645,000</td><td>$ (1,685,000)</td></tr><tr><td>Sales of oil and natural gas produced, net of production costs</td><td>(13,142,000)</td><td>(3,604,000)</td></tr><tr><td>Net changes in prices and production costs, net of royalties and wellhead taxes</td><td>27,828,000</td><td>5,702,000</td></tr><tr><td>Extensions and discoveries</td><td>8,889,000</td><td>—</td></tr><tr><td>Net change due to purchases and sales of minerals in place</td><td>2,451,000</td><td>(882,000)</td></tr><tr><td>Revisions of previous quantity estimates</td><td>4,270,000</td><td>4,217,000</td></tr><tr><td>Net change in income taxes</td><td>(4,774,000)</td><td>(845,000)</td></tr><tr><td>Accretion of discount</td><td>(1,566,000)</td><td>(176,000)</td></tr><tr><td>Other - changes in the timing of future production and other</td><td>801,000</td><td>(55,000)</td></tr><tr><td>Other - net change in Canadian dollar translation rate</td><td>476,000</td><td>(27,000)</td></tr><tr><td>Net change</td><td>25,233,000</td><td>4,330,000</td></tr><tr><td>End of year</td><td>$ 27,878,000</td><td>$ 2,645,000</td></tr></table>



# ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

## ITEM 9A. CONTROLS AND PROCEDURES

## Disclosure Controls and Procedures

We have established disclosure controls and procedures to ensure that material information relating to Barnwell, including its consolidated subsidiaries, is made known to the officers who certify Barnwell’s financial reports and to other members of executive management and the Board of Directors.

As of September 30, 2022, an evaluation was carried out by Barnwell’s Chief Executive Officer and Chief Financial Officer of the effectiveness of Barnwell’s disclosure controls and procedures. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that Barnwell’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934 (the “Exchange Act”)) were effective as of September 30, 2022 to ensure that information required to be disclosed by Barnwell in reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Exchange Act and the rules thereunder.

## Management’s Annual Report on Internal Control Over Financial Reporting

Barnwell’s management is responsible for establishing and maintaining adequate internal control over financial reporting for Barnwell, as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act. Under the supervision and with the participation of Barnwell’s management, including our Chief Executive Officer and Chief Financial Officer, Barnwell conducted an evaluation of the effectiveness of its internal control over financial reporting using criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in the report entitled Internal Control — Integrated Framework (2013) (the “COSO Framework”). Based on this evaluation under the COSO Framework, management concluded that its internal control over financial reporting was effective as of September 30, 2022.

This Annual Report on Form 10-K does not include an attestation report of our independent registered public accounting firm regarding internal control over financial reporting. Pursuant to Item 308(b) of Regulation S-K, management’s report is not subject to attestation by our independent registered public accounting firm because the Company is neither an “accelerated filer” nor a “large accelerated filer” as those terms are defined by the SEC.

## Changes in Internal Control Over Financial Reporting

There was no change in Barnwell’s internal control over financial reporting during the quarter ended September 30, 2022 that materially affected, or is reasonably likely to materially affect, Barnwell’s internal control over financial reporting.

## ITEM 9B. OTHER INFORMATION

None.



Not applicable.



## PART III

## ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

The information required is omitted pursuant to General Instruction G(3) of Form 10-K, since the Registrant will file its definitive proxy statement for the Annual Meeting of Stockholders no later than 120 days after the close of its fiscal year ended September 30, 2022, which proxy statement is incorporated herein by reference.

Barnwell adopted a Code of Ethics that applies to its Chief Executive Officer and the Chief Financial Officer. This Code of Ethics has been posted on Barnwell’s website at www.brninc.com.

## ITEM 11. EXECUTIVE COMPENSATION

The information required is omitted pursuant to General Instruction G(3) of Form 10-K, since the Registrant will file its definitive proxy statement for the Annual Meeting of Stockholders no later than 120 days after the close of its fiscal year ended September 30, 2022, which proxy statement is incorporated herein by reference.

## ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The information required is omitted pursuant to General Instruction G(3) of Form 10-K, since the Registrant will file its definitive proxy statement for the Annual Meeting of Stockholders no later than 120 days after the close of its fiscal year ended September 30, 2022, which proxy statement is incorporated herein by reference.

## Equity Compensation Plan Information

The following table provides information about Barnwell's common stock that may be issued upon exercise of options and rights under Barnwell's existing equity compensation plan as of September 30, 2022:

<table><tr><td>Plan Category</td><td>(a) Number of securities to be issued upon exercise of outstanding options, warrants and rights</td><td>(b) Weighted-average price of outstanding options, warrants and rights</td><td>(c) Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))</td></tr><tr><td>Equity compensation plans approved by security holders</td><td>615,000</td><td>$3.36</td><td>935,000</td></tr><tr><td>Equity compensation plans not approved by security holders</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Total</td><td>615,000</td><td>$3.36</td><td>935,000</td></tr></table>



## ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

The information required is omitted pursuant to General Instruction G(3) of Form 10-K, since the Registrant will file its definitive proxy statement for the Annual Meeting of Stockholders no later than 120 days after the close of its fiscal year ended September 30, 2022, which proxy statement is incorporated herein by reference.

## ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

The information required is omitted pursuant to General Instruction G(3) of Form 10-K, since the Registrant will file its definitive proxy statement for the Annual Meeting of Stockholders no later than 120 days after the close of its fiscal year ended September 30, 2022, which proxy statement is incorporated herein by reference.



## PART IV

## ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

## (a) Financial Statements

The following consolidated financial statements of Barnwell Industries, Inc. and its subsidiaries are included in Part II, Item 8:

Report of Independent Registered Public Accounting Firm - WEAVER AND TIDWELL, L.L.P. (PCAOB ID: 410)

Consolidated Balance Sheets – September 30, 2022 and 2021

Consolidated Statements of Operations – for the years ended September 30, 2022 and 2021

Consolidated Statements of Comprehensive Income – for the years ended September 30, 2022 and 2021

Consolidated Statements of Equity – for the years ended September 30, 2022 and 2021

Consolidated Statements of Cash Flows – for the years ended September 30, 2022 and 2021

Notes to Consolidated Financial Statements

Schedules have been omitted because they were not applicable, not required, or the information is included in the consolidated financial statements or notes thereto.

## (b) Exhibits

<table><tr><td>Exhibit Number</td><td>Description</td></tr><tr><td>3.1</td><td>Certificate of Incorporation, as amended (1)</td></tr><tr><td>3.2</td><td>Amended and Restated By-Laws (2)</td></tr><tr><td>4.1</td><td>Form of the Registrant&#x27;s certificate of common stock, par value $.50 per share (3)</td></tr><tr><td>4.2</td><td>Tax Benefits Preservation Plan, dated as of October 17, 2022, by and between Barnwell Industries, Inc. and Broadridge Corporate Issuer Solutions, Inc., as Rights Agent (13)</td></tr><tr><td>10.1</td><td>The Barnwell Industries, Inc. Employees&#x27; Pension Plan (restated as of October 1, 1989) (4)</td></tr><tr><td>10.2</td><td>Form of Purchase and Sale Agreement dated February 13, 2004 by and between Kaupulehu Developments and WB KD Acquisition, LLC (5)</td></tr><tr><td>10.3</td><td>Agreement dated May 27, 2009 which became effective June 23, 2009 by and between Kaupulehu Developments and WB KD Acquisition, LLC and WB KD Acquisition II, LLC (6)</td></tr><tr><td>10.4</td><td>Limited Liability Limited Partnership Agreement of KD Kona 2013 LLLP dated November 27, 2013 (7)</td></tr><tr><td>10.5</td><td>Limited Liability Limited Partnership Agreement of KKM Makai, LLLP dated November 27, 2013 (8)</td></tr><tr><td>10.6</td><td>Agreement with KD Kaupulehu, LLLP to Release Retained Rights, dated as of March 7, 2019, between Kaupulehu Developments and KD Kaupulehu, LLLP (9)</td></tr></table>



10.7 Agreement with Respect to Retained Rights, dated as of March 7, 2019 between Kaupulehu Developments and KD Acquisition II, LP (10)

10.8 Form of Option Agreement (11)

10.9 Asset Purchase and Sale Agreement, dated July 8, 2021, between Barnwell of Canada, Limited and Tourmaline Oil Corp. (12)

10.10 Cooperation and Support Agreement, dated January 27, 2021 (14)

10.11 Amended and Restated 2018 Equity Incentive Plan (15)

10.12 Sales Agent Agreement, dated March 16, 2021 (16)

21 List of Subsidiaries

23.1 Consent of InSite Petroleum Consultants Ltd.

23.2 Consent of Ryder Scott Company, L.P.

23.3 Consent of Weaver and Tidwell, L.L.P.

31.1 Certification of Chief Executive Officer Pursuant To Section 302 of the Sarbanes-Oxley Act of 2002

31.2 Certification of Chief Financial Officer Pursuant To Section 302 of the Sarbanes-Oxley Act of 2002

32 Certification Pursuant To Section 906 of the Sarbanes-Oxley Act of 2002

99.1 Reserve Report Summary prepared by InSite Petroleum Consultants Ltd.

99.2 Reserve Report Summary prepared by Ryder Scott Company, L.P.

101.INS XBRL Instance Document

101.SCH XBRL Taxonomy Extension Schema Document

101.CAL XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF XBRL Taxonomy Extension Definition Linkbase Document

101.LAB XBRL Taxonomy Extension Label Linkbase Document

101.PRE XBRL Taxonomy Extension Presentation Linkbase Document

104 Cover Page Interactive Data File (embedded within the Inline XBRL document)

(1) Incorporated by reference to Exhibit 3.1 to Registrant's Form 10-Q for the quarterly period ended June 30, 2022.

(2) Incorporated by reference to Exhibit 3.1 to Registrant's Form 8-K filed on January 14, 2020.

(3) Incorporated by reference to the registration statement on Form S-1 originally filed by the Registrant January 29, 1957 and as amended February 15, 1957 and February 19, 1957.

(4) Incorporated by reference to Registrant's Form 10-K for the year ended September 30, 1989.

(5) Incorporated by reference to Exhibit 2.1 to Registrant's Form 8-K filed on February 13, 2004.

(6) Incorporated by reference to Exhibit 10.1 to Registrant's Form 10-Q for the quarterly period ended June 30, 2009.

(7) Incorporated by reference to Exhibit 10.7 to Registrant's Form 10-Q for the quarterly period ended December 31, 2013.

(8) Incorporated by reference to Exhibit 10.8 to Registrant's Form 10-Q for the quarterly period ended December 31, 2013

(9) Incorporated by reference to Exhibit 10.1 to Registrant's Form 10-Q for the quarterly period ended March 31, 2019.

(10) Incorporated by reference to Exhibit 10.2 to Registrant's Form 10-Q for the quarterly period ended March 31, 2019. Certain confidential information has been omitted from a portion of this exhibit.

(11) Incorporated by reference to Exhibit 10.1 to Registrant's Form 10-Q for the quarterly period ended March 31, 2021.

(12) Incorporated by reference to Exhibit 10.9 to Registrant's Form 10-K for the year ended September 30, 2021.

(13) Incorporated by reference to Exhibit 4.1 to Registrant's Form 8-K filed on October 17, 2022.

(14) Incorporated by reference to Exhibit 10.1 to Registrant's Form 8-K filed on February 1, 2021.

(15) Incorporated by reference from Definitive Proxy 2022 Appendix A filed by the Registrant on March 24, 2022.

(16) Incorporated by reference to Exhibit 1.1 to Registrant's Form 8-K filed on March 16, 2021.



## SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

BARNWELL INDUSTRIES, INC.

(Registrant)

/s/ Russell M. Gifford

By: Russell M. Gifford

Executive Vice President,
Chief Financial Officer,
Treasurer and Secretary

Date: December 29, 2022



Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

/s/ Alexander C. Kinzler

Alexander C. Kinzler
President, Chief Executive Officer,
Chief Operating Officer,
General Counsel and Director
Date: December 29, 2022

/s/ Peter J. O'Malley

Peter J. O'Malley, Chairman of the Board
Date: December 29, 2022

Kenneth S. Grossman, Director

/s/ Philip J. McPherson

Philip J. McPherson, Director
Date: December 29, 2022

Doug N. Woodrum, Director

/s/ Russell M. Gifford

Russell M. Gifford
Executive Vice President,
Chief Financial Officer,
Treasurer and Secretary
Date: December 29, 2022

/s/ Francis J. Kelly

Francis J. Kelly, Director
Date: December 29, 2022

Bradley M. Tirpak, Director



## INDEX TO EXHIBITS

Exhibit Number | Description
3.1 | Certificate of Incorporation, as amended (1)
3.2 | Amended and Restated By-Laws (2)
4.1 | Form of the Registrant's certificate of common stock, par value $.50 per share (3)
4.2 | Tax Benefits Preservation Plan, dated as of October 17, 2022, by and between Barnwell Industries, Inc. and Broadridge Corporate Issuer Solutions, Inc., as Rights Agent (13)
10.1 | The Barnwell Industries, Inc. Employees' Pension Plan (restated as of October 1, 1989) (4)
10.2 | Form of Purchase and Sale Agreement dated February 13, 2004 by and between Kaupulehu Developments and WB KD Acquisition, LLC (5)
10.3 | Agreement dated May 27, 2009 which became effective June 23, 2009 by and between Kaupulehu Developments and WB KD Acquisition, LLC and WB KD Acquisition II, LLC (6)
10.4 | Limited Liability Limited Partnership Agreement of KD Kona 2013 LLLP dated November 27, 2013 (7)
10.5 | Limited Liability Limited Partnership Agreement of KKM Makai, LLLP dated November 27, 2013 (8)
10.6 | Agreement with KD Kaupulehu, LLLP to Release Retained Rights, dated as of March 7, 2019, between Kaupulehu Developments and KD Kaupulehu, LLLP (9)
10.7 | Agreement with Respect to Retained Rights, dated as of March 7, 2019 between Kaupulehu Developments and KD Acquisition II, LP (10)
10.8 | Form of Option Agreement (11)
10.9 | Asset Purchase and Sale Agreement, dated July 8, 2021, between Barnwell of Canada, Limited and Tourmaline Oil Corp. (12)
10.10 | Cooperation and Support Agreement, dated January 27, 2021 (14)
10.11 | Amended and Restated 2018 Equity Incentive Plan (15)
10.12 | Sales Agent Agreement, dated March 16, 2021 (16)
21 | List of Subsidiaries
23.1 | Consent of InSite Petroleum Consultants Ltd.
23.2 | Consent of Ryder Scott Company, L.P.
23.3 | Consent of Weaver and Tidwell, L.L.P.
31.1 | Certification of Chief Executive Officer Pursuant To Section 302 of the Sarbanes-Oxley Act of 2002
31.2 | Certification of Chief Financial Officer Pursuant To Section 302 of the Sarbanes-Oxley Act of 2003
32 | Certification Pursuant To Section 906 of the Sarbanes-Oxley Act of 2002
99.1 | Reserve Report Summary prepared by InSite Petroleum Consultants Ltd.
99.2 | Reserve Report Summary prepared by Ryder Scott Company, L.P.
101.INS | XBRL Instance Document



101.SCH XBRL Taxonomy Extension Schema Document

101.CAL XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF XBRL Taxonomy Extension Definition Linkbase Document

101.LAB XBRL Taxonomy Extension Label Linkbase Document

101.PRE XBRL Taxonomy Extension Presentation Linkbase Document

104 Cover Page Interactive Data File (embedded within the Inline XBRL document)

(1) Incorporated by reference to Exhibit 3.1 to Registrant’s Form 10-Q for quarterly period ended June 30, 2022.

(2) Incorporated by reference to Exhibit 3.1 to Registrant’s Form 8-K filed on January 14, 2020.

(3) Incorporated by reference to the registration statement on Form S-1 originally filed by the Registrant January 29, 1957 and as amended February 15, 1957 and February 19, 1957.

(4) Incorporated by reference to Registrant’s Form 10-K for the year ended September 30, 1989.

(5) Incorporated by reference to Exhibit 2.1 to Registrant’s Form 8-K filed on February 13, 2004.

(6) Incorporated by reference to Exhibit 10.1 to Registrant’s Form 10-Q for the quarterly period ended June 30, 2009.

(7) Incorporated by reference to Exhibit 10.7 to Registrant’s Form 10-Q for the quarterly period ended December 31, 2013.

(8) Incorporated by reference to Exhibit 10.8 to Registrant’s Form 10-Q for the quarterly period ended December 31, 2013

(9) Incorporated by reference to Exhibit 10.1 to Registrant’s Form 10-Q for the quarterly period ended March 31, 2019.

(10) Incorporated by reference to Exhibit 10.2 to Registrant’s Form 10-Q for the quarterly period ended March 31, 2019. Certain confidential information has been omitted from a portion of this exhibit.

(11) Incorporated by reference to Exhibit 10.1 to Registrant’s Form 10-Q for the quarterly period ended March 31, 2021.

(12) Incorporated by reference to Exhibit 10.9 to Registrant’s Form 10-K for the year ended September 30, 2021.

(13) Incorporated by reference to Exhibit 4.1 to Registrant’s Form 8-K filed on October 17, 2022.

(14) Incorporated by reference to Exhibit 10.1 to Registrant’s Form 8-K filed on February 1, 2021.

(15) Incorporated by reference from Definitive Proxy 2022 Appendix A filed by the Registrant on March 24, 2022.

(16) Incorporated by reference to Exhibit 1.1 to Registrant’s Form 8-K filed on March 16, 2021.



## List of Subsidiaries

The subsidiaries of Barnwell Industries, Inc., at September 30, 2022 were:

<table><tr><td>Name of Subsidiary</td><td>Jurisdiction of Incorporation or Organization</td></tr><tr><td>Barnwell of Canada, Limited</td><td>Delaware</td></tr><tr><td>Water Resources International, Inc.</td><td>Delaware</td></tr><tr><td>Barnwell Hawaiian Properties, Inc.</td><td>Delaware</td></tr><tr><td>Barnwell Investments LLC</td><td>Delaware</td></tr><tr><td>Barnwell Kona Corporation</td><td>Hawaii</td></tr><tr><td>Kaupulehu Developments</td><td>Hawaii</td></tr><tr><td>KD Kona 2013 LLLP</td><td>Hawaii</td></tr><tr><td>BOK Drilling, LLC</td><td>Hawaii</td></tr><tr><td>Bill Robbins Drilling, Ltd.</td><td>Alberta, Canada</td></tr><tr><td>Gypsy Petroleum Ltd.</td><td>Alberta, Canada</td></tr><tr><td>Dartmouth Petroleum, Ltd.</td><td>Alberta, Canada</td></tr><tr><td>J.H. Wilson Associates, Ltd.</td><td>Alberta, Canada</td></tr><tr><td>Octavian Oil, Ltd.</td><td>Alberta, Canada</td></tr></table>



## Consent of InSite Petroleum Consultants Ltd.

We hereby consent to the use of our name in the Annual Report on Form 10-K of Barnwell Industries, Inc. and to all references to us, our report concerning reserves and the data in that report appearing in the 10-K.

Date: December 29, 2022

InSite Petroleum Consultants Ltd.

By: /s/ Peter Hadala

Peter Hadala, P. Eng.

President and Managing Director



Exhibit No. 23.2

# Consent of Ryder Scott Company, L.P.

We hereby consent to the use of our name in the Annual Report on Form 10-K of Barnwell Industries, Inc. and to all references to us, our report concerning reserves, and the data in that report appearing in the 10-K.

/s/ Ryder Scott Company, L.P.

RYDER SCOTT COMPANY, L.P.

TBPELS Firm Registration No. F-1580

Denver, CO

December 29, 2022



# Consent of Independent Registered Public Accounting Firm

To The Board of Directors

Barnwell Industries, Inc.

We hereby consent to the incorporation by reference in the following Registration Statements and prospectus:

1. Form S-3 No. 333-254365 pertaining to the at-the-market offering program pursuant to which the Company may offer and sell, from time to time, shares of its common stock under price and volume guidelines set by the Company's Board of Directors and the terms and conditions described in the Registration Statement, and

2. Form S-8 No. 333-251471 pertaining to the 2018 Employee Incentive Plan of Barnwell Industries, Inc.

our report dated December 29, 2022, with respect to the consolidated balance sheets as of September 30, 2022 and 2021 of Barnwell Industries, Inc. and subsidiaries and related consolidated statements of operations, comprehensive income (loss), equity (deficit) and cash flows for the years then ended, and related notes, which report appears in the September 30, 2022 Annual Report on Form 10-K of Barnwell Industries, Inc. We also consent to the reference to us under the heading “Experts” in such Registration Statements and prospectus.

/s/ WEAVER AND TIDWELL, L.L.P.

Dallas, Texas

December 29, 2022



## Certifications

I, Alexander C. Kinzler, certify that:

1. I have reviewed this annual report on Form 10-K of Barnwell Industries, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: December 29, 2022

/s/ Alexander C. Kinzler

Alexander C. Kinzler

President, Chief Executive Officer, Chief Operating Officer, General Counsel



## Certifications

I, Russell M. Gifford, certify that:

1. I have reviewed this annual report on Form 10-K of Barnwell Industries, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: December 29, 2022

/s/ Russell M. Gifford

Russell M. Gifford

Executive Vice President, Chief Financial Officer



# Barnwell Industries, Inc.

# Certification Pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002

Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code) each of the undersigned officers of Barnwell Industries, Inc. (the "Company"), does hereby certify, to such officer's knowledge that:

The Annual Report on Form 10-K for the year ended September 30, 2022 of the Company fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934 and the information contained in the Form 10-K fairly presents, in all material respects, the consolidated financial condition as of September 30, 2022 and consolidated results of operations for the year ended September 30, 2022 of the Company and its subsidiaries.

Dated: December 29, 2022

/s/ Alexander C. Kinzler

Name: Alexander C. Kinzler

Title: President, Chief Executive Officer, Chief Operating Officer, General Counsel

Dated: December 29, 2022

/s/ Russell M. Gifford

Name: Russell M. Gifford

Title: Executive Vice President, Chief Financial Officer

The foregoing certification is being furnished solely pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code) and is not being filed as part of the Form 10-K or as a separate disclosure document.

A signed original of the written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.



Barnwell of Canada, Limited
Suite 2410, 500 – 4th Avenue SW
Calgary, Alberta
T2P 2V6

Re: Evaluation of the Oil and Gas Properties of Barnwell of Canada, Limited and Octavian Oil Ltd.

## Dear Sirs:

As requested, an evaluation has been made of all of the crude oil and natural gas assets of Barnwell of Canada, Limited and Octavian Oil Ltd., hereinafter referred to as the "Company." The properties evaluated are located in the Canadian provinces of Alberta and British Columbia. The effective date of the reserve estimates presented in this report is September 30, 2022. The purpose of this evaluation and report is to fulfill Securities and Exchange Commission (SEC) reporting requirements.

All Company assets were evaluated in full detail. Individual property evaluations were prepared in the context of belonging to a larger portfolio of properties. Due to the principal of aggregation of reserves, the total portfolio reserves estimate carries a higher degree of confidence than the estimates for the individual properties.

This evaluation is based in part on prices, currency exchange rates and estimates which, in future, may differ materially from the forecasts utilized herein. In addition, changes in government policy and regulation may result in higher (or lower) royalties and taxes and the change may be material; therefore, the present values of revenues documented in this report do not necessarily represent the fair market value of the reserves evaluated. The reserve estimates presented in this report are considered reasonable as of the effective date of the report given the quality and quantity of data available; however, they should be accepted with the understanding that reservoir performance subsequent to the date of these estimates may necessitate revision, which may be material.



## Barnwell of Canada, Limited plus Octavian Oil Ltd.
Summary of Net Reserves – Constant Prices and Costs

Net Remaining Reserves

<table><tr><td></td><td>Crude Oil (Stb)</td><td>NGL + Cond. (Stb)</td><td>Market Gas (Mcf)</td></tr><tr><td>Proved Producing</td><td>697,600</td><td>124,700</td><td>3,935,800</td></tr><tr><td>Proved Non-Producing</td><td>120,400</td><td>13,800</td><td>454,900</td></tr><tr><td>Proved Undeveloped</td><td>28,700</td><td>4,600</td><td>128,400</td></tr><tr><td>Total Proved</td><td>846,700</td><td>143,100</td><td>4,519,100</td></tr></table>

Constant prices were prepared based on posted prices of crude oil and natural gas, and natural gas liquids using a 12 month unweighted arithmetic average closing price of each commodity on the 1 \( ^{st} \)  day of each month from October 1, 2021 through September 1, 2022 during the fiscal year. This report has been prepared using constant prices and costs and conforms to our understanding of the SEC’s guidelines and applicable financial accounting rules.

All prices used in the evaluation have been adjusted from posted prices for applicable quality, heating value and transportation considerations. The weighted average prices, after applicable adjustments, over the life of the properties used in the evaluation were US$ 80.78 barrel of oil, US$ 4.07 per Mcf of gas, US$ 50.78 per barrel of condensate and natural gas liquids.

During the course of the evaluation, the Company provided InSite Petroleum Consultants Ltd. ("InSite") personnel with basic information including land data, well information, geological information, reservoir studies, estimates of on-stream dates, contract details, operating cost data, capital budget forecasts, operating statements and other financial data and future operating plans. Additional engineering, geological or economic data used in the preparation of this report were obtained from public records, other operators and from InSite non-confidential files. InSite encountered no indications that the data was incomplete or inaccurate. Should evidence become available in the future suggesting that the data was incomplete or inaccurate, InSite reserves the right to revise the estimates based on new data. Similarly, the performance of the producing entities subsequent to the effective date of this report may necessitate upward or downward revisions to the reserve and production estimates.

In conducting our reserve analysis, proved reserve volumes were determined by volumetric, material balance, and production decline curve methods. The volumetric reserves were determined by reviewing all well logs, core, and geological data. Recovery factors were assigned after analyzing the performance of similar wells in the area. Historical well production was reviewed to determine reserves calculated by production decline curve analysis where sufficient historical data was available. The order of preference in choosing the methodology to be used was firstly production decline curve analysis or material balance where sufficient data was available for such analysis with volumetric calculations used where there was a lack of historical data.

The production and revenue forecasts for each property and the corporate cash flow summaries have not been adjusted for risk. Well abandonment, decommissioning and site reclamation costs (ADR) were included in the economic runs for all wells with reserves assigned, as wells as the ADR costs for producing wells with no reserves assigned, suspended wells and existing facilities. The ADR costs and timing were adopted from the Company's internal Asset Retirement Obligation (ARO) estimates.

The oil and gas reserves calculations and income projections upon which this report is based, were determined in accordance with generally accepted evaluation practices. InSite used all assumptions, data, methods and procedures it considered appropriate, under the circumstances, to prepare this report.

The extent and character of ownership and all factual data supplied by the Company were accepted as presented. A field inspection was not considered necessary by InSite.



In this report, gross (or Company share) reserves are defined as the total remaining recoverable reserves owned by the Company before deduction of any royalties. Net reserves are defined as those accruing to the Company after all interests owned by others including Crown and Freehold royalties have been deducted. The reserve category definitions utilized in this report are in accordance with SEC standards and Regulation S-X.

Yours very truly,

InSite Petroleum Consultants Ltd.

Original signed by Peter Hadala, P. Eng.

(2022-12-06)
Peter Hadala, P. Eng.

President and Managing Director

Original signed by Radu Afilipoaei, P. Eng.

(2022-12-06)
Radu Afilipoaei, P. Eng.

Managing Director

Original signed by J. Ed Hasiuk, P. Geol.

(2022-12-06)
J. Ed Hasiuk, P. Geol.

Senior Geologist



# TETON BARNWELL FUND I, LLC

Estimated

Future Reserves and Income

Attributable to Certain

Leasehold and Royalty Interests

SEC Parameters

As of

September 30, 2022

/s/ Stephen E. Gardner

Stephen E. Gardner, P.E.

Colorado License No. 44720

Managing Senior Vice President

[SEAL]

RYDER SCOTT COMPANY, L.P.
TBPELS Firm Registration No. F-1580

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS



December 7, 2022

Mark A. Roche,
Partner
Gros Ventre Partners, LLC
145 E. Snow King Ave.
Jackson, WY 83001

Dear Mr. Roche:

At your request, Ryder Scott Company, L.P. (Ryder Scott) has prepared an estimate of the proved reserves, future production, and income attributable to certain leasehold and royalty interests of Teton Barnwell Fund I, LLC (TBF1), a fund managed by Gros Ventre Partners, LLC (Gros Ventre), as of September 30, 2022. TBF1 is an entity formed by Gros Ventre and BOK Drilling, LLC, a wholly owned subsidiary of Barnwell Industries, Inc. (Barnwell), for the purpose of investing in oil and natural gas exploration and development in Oklahoma. Accordingly, the subject properties in this report are located in the state of Oklahoma. The reserves and income data were estimated based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). Our third party study, completed on September 28, 2022 and presented herein, was prepared for public disclosure by Barnwell in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations.

The properties evaluated by Ryder Scott account for a portion of Barnwell’s total net proved liquid hydrocarbon and gas reserves as of September 30, 2022. Based on information provided by Barnwell, the third party estimate conducted by Ryder Scott addresses approximately 8.8 percent of the total proved net reserves of Barnwell on a barrel of oil equivalent, BOE, basis as of September 30, 2022.

The estimated reserves and future net income amounts presented in this report, as of September 30, 2022 are related to hydrocarbon prices. The hydrocarbon prices used in the preparation of this report are based on the average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, as required by the SEC regulations. Actual future prices may vary considerably from the prices required by SEC regulations. The reserves volumes and the income attributable thereto have a direct relationship to the hydrocarbon prices actually received; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The results of this study are summarized as follows.



SEC PARAMETERS
Estimated Net Reserves and Income Data
Certain Leasehold and Royalty Interests of
Teton Barnwell Fund I, LLC

<table><tr><td colspan="2">As of September 30, 2022</td></tr><tr><td></td><td>Total Proved Developed Producing</td></tr><tr><td>Net Reserves</td><td></td></tr><tr><td>Oil/Condensate - Mbbl</td><td>29</td></tr><tr><td>Plant Products - Mbbl</td><td>61</td></tr><tr><td>Gas - MMcf</td><td>466</td></tr><tr><td>Income Data ($M)</td><td></td></tr><tr><td>Future Gross Revenue</td><td>$6,254</td></tr><tr><td>Deductions</td><td>421</td></tr><tr><td>Future Net Income (FNI)</td><td>$5,833</td></tr><tr><td>Discounted FNI @ 10%</td><td>$3,946</td></tr></table>

Liquid hydrocarbons are expressed in standard 42 U.S. gallon barrels and shown herein as thousands of barrels (Mbbl). All gas volumes are reported on an “as sold basis” expressed in millions of cubic feet (MMcf) at the official temperature and pressure bases of the areas in which the gas reserves are located. In this report, the revenues, deductions, and income data are expressed as thousands of U.S. dollars ($M).

The estimates of the reserves, future production, and income attributable to properties in this report were prepared using the economic software package ARIES \( ^{™} \)  Petroleum Economics and Reserves Software, a copyrighted program of Halliburton. The program was used at the request of TBF1. Ryder Scott has found this program to be generally acceptable, but notes that certain summaries and calculations may vary due to rounding and may not exactly match the sum of the properties being summarized. Furthermore, one line economic summaries may vary slightly from the more detailed cash flow projections of the same properties, also due to rounding. The rounding differences are not material.

The future gross revenue is after the deduction of production taxes. The deductions incorporate the normal direct costs of operating the wells and certain abandonment costs net of salvage. The future net income is before the deduction of state and federal income taxes and general administrative overhead, and has not been adjusted for outstanding loans that may exist nor does it include any adjustment for cash on hand or undistributed income.

Liquid hydrocarbon reserves account for approximately 67 percent and gas reserves account for the remaining 33 percent of total future gross revenue from proved reserves.

The discounted future net income shown above was calculated using a discount rate of 10 percent per annum compounded monthly. Future net income was discounted at four other discount rates which were also compounded monthly. These results are shown in summary form as follows.



<table><tr><td rowspan="2">Discount Rate Percent</td><td colspan="2">Discounted Future Net Income ($M) As of September 30, 2022</td></tr><tr><td>Total</td><td></td></tr><tr><td></td><td>Proved</td><td></td></tr><tr><td>8</td><td>$4,181</td><td></td></tr><tr><td>9</td><td>$4,059</td><td></td></tr><tr><td>12</td><td>$3,747</td><td></td></tr><tr><td>15</td><td>$3,498</td><td></td></tr></table>

The results shown above are presented for your information and should not be construed as our estimate of fair market value.

## Reserves Included in This Report

The proved reserves included herein conform to the definition as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “PETROLEUM RESERVES DEFINITIONS” is included as an attachment to this report.

The various reserves status categories are defined in the attachment entitled “PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES” in this report.

No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. The proved gas volumes presented herein do not include volumes of gas consumed in operations as reserves.

Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.” All reserves estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends primarily on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal categories, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-categorized as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At TBF1’s request, this report addresses only the proved reserves attributable to the properties evaluated herein.

Proved oil and gas reserves are “those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward.” The proved reserves included herein were estimated using deterministic methods. The SEC has defined reasonable certainty for proved reserves, when based on deterministic methods, as a “high degree of confidence that the quantities will be recovered.”

Proved reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.” Moreover, estimates of proved reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved reserves included in this report are estimates only and should not be construed as being exact quantities, and if



recovered, the revenues therefrom, and the actual costs related thereto, could be more or less than the estimated amounts.

TBF1's operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the estimated quantities.

The estimates of proved reserves presented herein were based upon a detailed study of the properties in which TBF1 owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included for potential liabilities to restore and clean up damages, if any, caused by past operating practices.

## Estimates of Reserves

The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission's Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods, (2) volumetric-based methods and (3) analogy. These methods may be used individually or in combination by the reserves evaluator in the process of estimating the quantities of reserves. Reserves evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated, and the stage of development or producing maturity of the property.

In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserves quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserves category assigned by the evaluator. Therefore, it is the categorization of reserves quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the "quantities actually recovered are much more likely to be achieved than not." The SEC states that "probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered." The SEC states that "possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves." All quantities of reserves within the same reserves category must meet the SEC definitions as noted above.

Estimates of reserves quantities and their associated reserves categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserves categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.

The proved reserves for the properties included herein were estimated by a combination of performance and analogy methods. Decline curve analysis, a performance method which utilized extrapolations of historical production and pressure data available through August 2022, was performed



on each well. However, due to the early-life circumstances of these wells, decline trends and total recoverable volumes were guided by analogy to older, more established wells within the analogy area. The data utilized in this analysis were furnished to Ryder Scott by TBF1 or obtained from public data sources and were considered sufficient for the purpose thereof.

To estimate economically producible proved oil and gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

TBF1 has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In preparing our forecast of future proved production and income, we have relied upon data furnished by TBF1 with respect to property interests owned, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, production taxes, abandonment costs after salvage, product prices based on the SEC regulations, adjustments or differentials to product prices, and pressure measurements. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by TBF1. We consider the factual data used in this report appropriate and sufficient for the purpose of preparing the estimates of reserves and future net revenues herein.

In summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate to prepare the estimates of reserves herein. The proved reserves included herein were determined in conformance with the United States Securities and Exchange Commission (SEC) Modernization of Oil and Gas Reporting; Final Rule, including all references to Regulation S-X and Regulation S-K, referred to herein collectively as the "SEC Regulations." In our opinion, the proved reserves presented in this report comply with the definitions, guidelines and disclosure requirements as required by the SEC regulations.

## Future Production Rates

Our forecasts of future production rates and decline trends are based on a combination of their individual historical production data and the performance trends of analogous wells. These future production rates may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.

## Hydrocarbon Prices

The hydrocarbon prices used herein are based on SEC price parameters using the average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period.

We furnished TBF1 with the above mentioned average benchmark prices in effect on September 30, 2022. These initial SEC hydrocarbon prices were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials as



described herein. The table below summarizes the “benchmark prices” and “price reference” used for the geographic area included in the report.

The product prices that were actually used to determine the future gross revenue for each property reflect adjustments to the benchmark prices for gravity, quality, local conditions, gathering and transportation fees and/or distance from market, referred to herein as “differentials.” The differentials used in the preparation of this report were furnished to us by TBF1. The differentials furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by TBF1 to determine these differentials.

In addition, the table below summarizes the net volume weighted benchmark prices adjusted for differentials and referred to herein as the “average realized prices.” The average realized prices shown in the table below were determined from the total future gross revenue before production taxes and the total net reserves for the geographic area and presented in accordance with SEC disclosure requirements for the geographic area included in the report.

<table><tr><td>Geographic Area</td><td>Product</td><td>Price Reference</td><td>Average Benchmark Prices</td><td>Average Realized Prices</td></tr><tr><td>North America</td><td></td><td></td><td></td><td></td></tr><tr><td rowspan="3">United States</td><td>Oil/Condensate</td><td>WTI Cushing</td><td>$91.71/bbl</td><td>$89.51/bbl</td></tr><tr><td>NGLs</td><td>WTI Cushing</td><td>$91.71/bbl</td><td>$31.51/bbl</td></tr><tr><td>Gas</td><td>Henry Hub</td><td>$6.127/MMBTU</td><td>$4.67/Mcf</td></tr></table>

The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in our individual property evaluations.

## Costs

Operating costs for the leases and wells in this report were furnished by TBF1. The operating costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the operating cost data used by TBF1. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells.

The estimated net cost of abandonment after salvage was included for properties where abandonment costs net of salvage were material. The estimates of the net abandonment costs furnished by TBF1 were accepted without independent verification.

Current costs used by TBF1 were held constant throughout the life of the properties.

## Standards of Independence and Professional Qualification

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1937. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have approximately eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any privately-owned or publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services.



Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.

Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists receive professional accreditation in the form of a registered or certified professional engineer's license or a registered or certified professional geoscientist's license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization. Regulating agencies require that, in order to maintain active status, a certain amount of continuing education hours be completed annually, including an hour of ethics training. Ryder Scott fully supports this technical and ethics training with our internal requirement mentioned above.

We are independent petroleum engineers with respect to Gros Ventre, TBF1, Barnwell, and their collective affiliates. Neither we nor any of our employees have any financial interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

The results of this study, presented herein, are based on technical analyses conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical person primarily responsible for overseeing the evaluation of the reserves information discussed in this report, are included as an attachment to this letter.



## Terms of Usage

The results of our third party study, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by Barnwell.

Barnwell makes periodic filings on Form 10-K with the SEC under the 1934 Exchange Act. Furthermore, Barnwell has certain registration statements filed with the SEC under the 1933 Securities Act into which any subsequently filed Form 10-K is incorporated by reference. We have consented to the incorporation by reference in the registration statements on Form S-3 (No. 333-254365) and Form S-8 (No. 333-251471) of Barnwell, of the references to our name, as well as to the references to our third party report for TBF1, which appears in the September 30, 2022 annual report on Form 10-K of Barnwell. Our written consent for such use is included as a separate exhibit to the filings made with the SEC by Barnwell.

We have provided TBF1 with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filings made by TBF1, or their partners, and the original signed report letter, the original signed report letter shall control and supersede the digital version.

The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

Very truly yours,

RYDER SCOTT COMPANY, L.P.
TBPELS Firm Registration No. F-1580

/s/ Stephen E. Gardner
Stephen E. Gardner, P.E.
Colorado License No. 44720

Managing Senior Vice President

SEG (LPC)/pl



## Professional Qualifications of Primary Technical Person

The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Mr. Stephen E. Gardner is the primary technical person responsible for the estimate of the reserves, future production and income.

Mr. Gardner, an employee of Ryder Scott Company, L.P. (Ryder Scott) since 2006, is a Managing Senior Vice President responsible for ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Gardner served in a number of engineering positions with Exxon Mobil Corporation. For more information regarding Mr. Gardner's geographic and job specific experience, please refer to the Ryder Scott Company website at https://ryderscott.com/employees/denver-employees.

Mr. Gardner earned a Bachelor of Science degree in Mechanical Engineering from Brigham Young University in 2001 (summa cum laude). He is a licensed Professional Engineer in the States of Colorado and Texas. Mr. Gardner is a member of the Society of Petroleum Engineers and a former chairperson of the Society of Petroleum Evaluation Engineers for the Denver Chapter. He also currently serves on the latter organization's board of directors at the international level.

In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of 15 hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Gardner fulfills. As part of his 2021 continuing education hours, Mr. Gardner attended the annual Ryder Scott Reserves Conference, which covered a variety of reserves topics including analysis techniques for unconventional reservoirs, ESG issues, reserves definitions and guidelines, SEC comment letter trends, and others. In addition, Mr. Gardner participated in various SPE and SPEE technical seminars, and other internal company training courses throughout the year covering topics such as reserves evaluation methods and evaluation software, ethics, regulatory issues, greenhouse gas management, and more.

Based on his educational background, professional training and more than 16 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Gardner has attained the professional qualifications as a Reserves Estimator set forth in Article III of the "Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information" promulgated by the Society of Petroleum Engineers as of June 2019.



# PETROLEUM RESERVES DEFINITIONS

# As Adapted From:
RULE 4-10(a) of REGULATION S-X PART 210
UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

## PREAMBLE

On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oil and Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA). The “Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K. The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to Regulation S-X and Regulation S-K, shall be referred to herein collectively as the “SEC regulations”. The SEC regulations take effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010. Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) for the complete definitions (direct passages excerpted in part or wholly from the aforementioned SEC document are denoted in italics herein).

Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. Under the SEC regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the SEC. The SEC regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the SEC unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202.

Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change.

Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleum technology continues to evolve.

Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum accumulations are considered as either conventional or unconventional based on the nature of their in-place characteristics, extraction method applied, or degree of processing prior to sale. Examples of unconventional petroleum accumulations include coalbed or coal seam methane (CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale.



Reserves do not include quantities of petroleum being held in inventory.

Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from different reserves categories.

## RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows:

Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

## PROVED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows:

Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and

(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

## PROVED RESERVES (SEC DEFINITIONS) CONTINUED

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.



(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and
(B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.



# PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

# As Adapted From:
RULE 4-10(a) of REGULATION S-X PART 210
UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

and

# 2018 PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)
Sponsored and Approved by:
SOCIETY OF PETROLEUM ENGINEERS (SPE)
WORLD PETROLEUM COUNCIL (WPC)
AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)
SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)
SOCIETY OF EXPLORATION GEOPHYSICISTS (SEG)
SOCIETY OF PETROPHYSICISTS AND WELL LOG ANALYSTS (SPWLA)
EUROPEAN ASSOCIATION OF GEOSCIENTISTS & ENGINEERS (EAGE)

Reserves status categories define the development and producing status of wells and reservoirs. Reference should be made to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) and the SPE-PRMS as the following reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the aforementioned SEC and SPE-PRMS documents are denoted in italics herein).

## DEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows:

Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

## Developed Producing (SPE-PRMS Definitions)

While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing.

## Developed Producing Reserves

Developed Producing Reserves are expected quantities to be recovered from completion intervals that are open and producing at the effective date of the estimate.
Improved recovery reserves are considered producing only after the improved recovery project is in operation.



## Developed Non-Producing

Developed Non-Producing Reserves include shut-in and behind-pipe Reserves.

## Shut-In

Shut-in Reserves are expected to be recovered from:

(1) completion intervals that are open at the time of the estimate but which have not yet started producing;
(2) wells which were shut-in for market conditions or pipeline connections; or
(3) wells not capable of production for mechanical reasons.

## Behind-Pipe

Behind-pipe Reserves are expected to be recovered from zones in existing wells that will require additional completion work or future re-completion before start of production with minor cost to access these reserves.
In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

## UNDEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves as follows:

Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(1) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.