BARNWELL INDUSTRIES INC - Annual Report: 2020 (Form 10-K)

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, 2020

☐ 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 2900, 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

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. o Yes x No

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. o Yes x No

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. x Yes o No

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). x Yes o No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and "emerging growth company" in Rule 12b-2 of the Exchange Act.

Large accelerated filer

☐

Accelerated filer

☐

Non-accelerated filer

☒

Smaller reporting company

☒

Emerging growth company

☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o

Indicate by check mark whether the Registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). ☐ Yes x No

The aggregate market value of the voting common stock held by non-affiliates of the registrant, computed by reference to the closing price of a share of common stock on March 31, 2020 (the last business day of the registrant’s most recently completed second fiscal quarter) was $1,990,000.

As of December 9, 2020 there were 8,277,160 shares of common stock outstanding.

Documents Incorporated by Reference

1. Proxy statement, to be forwarded to stockholders on or about January 15, 2021, is incorporated by reference in Part III hereof.

TABLE OF CONTENTS


			Page
		Glossary of Terms	3
PART I
		Discussion of Forward-Looking Statements	4
	Item 1.	Business	5
	Item 1A.	Risk Factors	20
	Item 1B.	Unresolved Staff Comments	34
	Item 2.	Properties	34
	Item 3.	Legal Proceedings	34
	Item 4.	Mine Safety Disclosures	35

PART II
	Item 5.	Market For Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	36
	Item 6.	Selected Financial Data	36
	Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	37
	Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	59
	Item 8.	Financial Statements and Supplementary Data	60
	Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	114
	Item 9A.	Controls and Procedures	114
	Item 9B.	Other Information	114

PART III
	Item 10.	Directors, Executive Officers and Corporate Governance	115
	Item 11.	Executive Compensation	115
	Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	115
	Item 13.	Certain Relationships and Related Transactions, and Director Independence	115
	Item 14.	Principal Accounting Fees and Services	115

PART IV
	Item 15.	Exhibits, Financial Statement Schedules	116
		Signatures	118
		Index to Exhibits	120

GLOSSARY OF TERMS

Defined below are certain terms used in this Form 10-K:


Terms		Definitions
ASC	-	Accounting Standards Codification
ASU	-	Accounting Standards Update
Barnwell of Canada	-	Barnwell of Canada, Limited
Bbl(s)	-	stock tank barrel(s) of oil equivalent to 42 U.S. gallons
Boe	-	barrel of oil equivalent at the rate of 5.8 Mcf per Bbl of oil or NGL
FASB	-	Financial Accounting Standards Board
GAAP	-	U.S. generally accepted accounting principles
Gross	-	Total number of acres or wells in which Barnwell owns an interest; includes interests owned of record by Barnwell and, in addition, the portion(s) owned by others; for example, a 50% interest in a 320 acre lease represents 320 gross acres and a 50% interest in a well represents 1 gross well. In the context of production volumes, gross represents amounts before deduction of the royalty share due others.
InSite	-	InSite Petroleum Consultants Ltd.
KD I	-	KD Acquisition, LLLP, formerly known as WB KD Acquisition, LLC
KD II	-	KD Acquisition II, LP, formerly known as WB KD Acquisition, II, LLC
KD Kona	-	KD Kona 2013 LLLP
KKM Makai	-	KKM Makai, LLLP
Kukio Resort Land Development Partnerships	-	The following partnerships in which Barnwell owns non-controlling interest: KD Kukio Resorts, LLLP (“KD Kukio Resorts”) KD Maniniowali, LLLP (“KD Maniniowali”) KD Kaupulehu, LLLP, which consists of KD I and KD II (“KDK”)
MBbls	-	thousands of barrels of oil
Mcf	-	one thousand cubic feet of natural gas at 14.65 pounds per square inch absolute and 60 degrees Fahrenheit
Mcfe	-	Mcf equivalent at the rate of 1 Bbl = 5.8 Mcf
MMcf	-	one million cubic feet of natural gas
Net	-	Barnwell’s aggregate interest in the total acres or wells; for example, a 50% interest in a 320 acre lease represents 160 net acres and a 50% interest in a well represents 0.5 net well. In the context of production volumes, net represents amounts after deduction of the royalty share due others.
NGL(s)	-	natural gas liquid(s)
Octavian Oil	-	Octavian Oil, Ltd.
OPEC	-	Organization of the Petroleum Exporting Countries
SEC	-	United States Securities and Exchange Commission
VIE	-	Variable interest entity
Water Resources	-	Water Resources International, Inc.

PART I

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 United States 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 United States 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.

Unless otherwise indicated, all references to “dollars” in this Form 10-K are to United States dollars.

ITEM 1. BUSINESS

Overview

Barnwell was incorporated in Delaware in 1956 and fiscal 2020 represented Barnwell’s 64th 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.

•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 of crude oil reserves and development of those reserves through horizontal well drilling and completion techniques.

Strategy

Barnwell’s oil and natural gas assets are currently managed as two categories, Twining and non-operated, based on their differing attributes and strategies.

Twining consists of the Company-owned assets in the Twining field that were purchased in 2018. These assets are characterized by being mostly low decline oil wells that the Company operates that we believe have development opportunities. Due to the lower decline rates in the field, Twining requires very little capital investment to maintain production levels. This lower capital requirement along with the fact that the land is largely held indefinitely, means development drilling can be done when higher commodity prices support it. With Barnwell’s entry into the Twining property in August 2018, the development methods in the area have evolved to include longer horizontal wells with multi-stage sand fracs. Barnwell invested approximately $2,400,000 and drilled its first well of this type in November 2019, and it is currently producing 103 Bbls of oil and 84 Boe of natural gas and NGL per day. Barnwell endeavors to improve the operational efficiency of the Twining property and, if possible, to expand our land position and level of influence in the Twining area.

The non-operated category consists of the Company assets not in the Twining area. These assets are diverse in location and attributes, being located throughout Alberta and producing shallow gas and conventional oil from a variety of pools. They are mostly non-operated and they have been accumulated

over decades of Barnwell activity in the basin. Barnwell is continually evaluating opportunities to either divest these assets, or add to them depending on technical and economic evaluations. The majority of these assets were put up for sale in January 2019, but COVID-19 and the resulting oil price collapse resulted in no reasonable offers being received.

Barnwell believes that market conditions are right to opportunistically pursue acquisitions as there are not many active buyers and plenty of motivated sellers of small to medium sized assets. We have hired agents and a consultant to pursue these opportunities. However, our ability to fund such investments is currently uncertain.

At September 30, 2020 Barnwell’s reserves were approximately 48% operated and 57% conventional oil and natural gas liquids. At September 30, 2019, Barnwell’s reserves were approximately 80% operated and 65% conventional oil and natural gas liquids.

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 the Board of Directors.

Our oil and natural gas segment revenues, profitability, and future rate of growth are dependent upon oil and natural gas prices and obtaining external financing or sufficient land investment cash flows to fund the development of our proved undeveloped reserves. The industry has experienced a prolonged period of low oil and natural gas prices that has negatively impacted our operating results, cash flows and liquidity. Credit and capital markets for oil and natural gas companies have been negatively affected as well, resulting in a decline in sources of financing as compared to previous years. By divesting significant oil and natural gas assets prior to the 2015 decline in commodity prices, Barnwell was able to repay all of its debt, use funds for general corporate purposes, and fund its acquisition investments.

Natural gas prices are typically higher in the winter than at other times due to increased heating demand. Oil prices are also 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 properties’ operator. Prices received in Canada have also been negatively impacted by the lack of export pipeline capacity.

On August 28, 2018, Barnwell completed the acquisition of interests in oil and natural gas properties located in the Twining area of Alberta, Canada, from an independent third party. The purchase price per the agreement was $10,362,000, which took into account estimated customary purchase price adjustments to reflect the economic activity from the effective date of July 1, 2018 to the closing date. The final determination of the customary adjustments to the purchase price resulted in a $172,000 reduction in the purchase price in the year ended September 30, 2019, bringing the final purchase price to $10,190,000. Barnwell also assumed $3,076,000 in asset retirement obligations associated with the Twining acquisition. This acquisition represented a significant step in Barnwell’s long-term strategy to transform its Canadian operations to having almost exclusively conventional light and medium oil assets. This was a strategic purchase by the Company of what is now its largest oil and natural gas property.

At September 30, 2019, proved undeveloped reserves were primarily attributable to Twining, and were estimated to be converted to proved developed reserves through future capital expenditures by Barnwell. This was for the development of 12 gross (8.82 net) wells over the next five years. However, at September 30, 2020, Barnwell had no proved undeveloped reserves related to Twining as oil prices fell

significantly this year making the drilling of proved undeveloped reserves uneconomic at current prices. As a result, the Company currently does not have a definitive plan to develop the reserves.

Preparation of Reserve Estimates

Barnwell’s reserves are estimated by our independent petroleum reserve engineers, InSite, in accordance with generally accepted petroleum engineering and evaluation principles and techniques and rules and regulations of the SEC. All information with respect to the Company’s reserves in this Form 10-K is derived from the report of InSite. A copy of the report issued by InSite is filed with this Form 10-K as Exhibit 99.1.

The preparation of data used by the independent petroleum reserve engineers to compile our oil and natural gas reserve estimates is completed in accordance with various internal control procedures which include verification of data input into reserves evaluation software, reconciliations and reviews of data provided to the independent petroleum reserve engineers to ensure completeness, and management review controls, including an independent internal review of the final reserve report for completeness and accuracy.

Barnwell has a Reserves Committee consisting of three of the six independent directors. The 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 report prepared by the independent petroleum reserve engineering firm 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 InSite’s evaluation of our reserves, summarize our estimated proved reserves of oil (including natural gas liquids) and natural gas as of September 30, 2020 on all properties in which Barnwell has an interest. All of our oil and natural gas reserves are located in Canada and are based on constant dollar price and cost assumptions. The 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, 2019.


	As of September 30, 2020
	Estimated Net Proved Developed Reserves	Estimated Net Proved Undeveloped Reserves	Estimated Net Proved Reserves
Oil, including natural gas liquids (Bbls)	530,000	5,000	535,000
Natural gas (Mcf)	2,310,000	—	2,310,000
Total (Boe)	928,000	5,000	933,000

During fiscal 2020, Barnwell’s total net proved developed reserves of oil and natural gas liquids increased by 1,000 Bbls (essentially unchanged) and total net proved developed reserves of natural gas increased by 410,000 Mcf (22%), for a combined increase of 72,000 Boe (8%). The increase in natural gas reserves were primarily the result of minor acquisitions and higher gas prices resulting in positive revisions in the current year period.

During fiscal 2020, total net proved undeveloped reserves of oil and natural gas liquids decreased by 885,000 Bbls (99%) and total net proved undeveloped reserves of gas decreased by 2,620,000 Mcf (100%). The ability of Barnwell to convert the undeveloped reserves to developed reserves is heavily influenced by the cash flows generated by the oil and natural gas segment, the results of such drilling, and the ability of the Company to raise sufficient funds. The low oil prices encountered during fiscal 2020 have rendered the proved undeveloped reserves uneconomic and management does not currently have a definitive plan to develop such reserves and therefore has excluded undeveloped reserves from this September 30, 2020 report. During fiscal 2020, Barnwell converted one gross (1.0 net) well from proved undeveloped to proved developed reserves in the Twining area and participated in conversion of one gross (0.3 net) well from proved undeveloped to proved developed reserves in the Spirit River area. These wells had total net proved reserves of 114,000 Boe and 94,000 Boe, respectively, at September 30, 2020.

The following table sets forth Barnwell’s oil and natural gas net reserves at September 30, 2020, by property name, based on information prepared by InSite, as well as net production and net revenues by property name for the year ended September 30, 2020. 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, 2020, the date of the projection.


	As of September 30, 2020				For the year ended September 30, 2020
	Net Proved Producing Reserves		Net Proved Reserves		Net Production		Net Revenues
Property Name	Oil & NGL (MBbls)	Gas (MMcf)	Oil & NGL (MBbls)	Gas (MMcf)	Oil & NGL (MBbls)	Gas (MMcf)	Oil & NGL		Gas
Bonanza/Balsam	28	13	33	13	5	5	$	176,000	$	9,000
Hillsdown	14	139	14	139	4	42	122,000		72,000
Kaybob	32	68	32	68	4	11	134,000		21,000
Medicine River	38	527	38	527	8	29	161,000		42,000
Spirit River	93	244	93	244	33	89	1,130,000		141,000
Thornbury	—	217	—	217	—	64	—		94,000
Twining	276	948	284	1,046	99	357	3,123,000		581,000
Wood River	41	56	41	56	19	13	657,000		24,000
Other properties	—	—	—	—	2	39	62,000		144,000
Total	522	2,212	535	2,310	174	649	$	5,565,000	$	1,128,000

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

Standardized Measure of Discounted Future Net Cash Flows

The following table sets forth Barnwell’s “Estimated Future Net Revenues” from total proved oil, natural gas and natural gas liquids reserves and the present value of Barnwell’s “Estimated Future Net Revenues” (discounted at 10%) as of September 30, 2020. Estimated future net revenues for total proved reserves are net of estimated future expenditures of developing and producing the proved reserves, and assume the continuation of existing economic conditions. Net revenues have been calculated using the average first-day-of-the-month price during the 12-month period ending as of the balance sheet date and current costs, after deducting all royalties, operating costs, future estimated capital expenditures (including abandonment costs), and income taxes. The amounts below include future cash flows from reserves that are currently proved undeveloped reserves and do not deduct general and administrative or interest expenses.


Year ending September 30,
2021	$	1,285,000
2022	571,000
2023	(34,000)
Thereafter	(12,476,000)
Undiscounted future net cash flows, after income taxes	$	(10,654,000)

Standardized measure of discounted future net cash flows	$	(1,685,000)	*

_______________________________________________

* This amount does not purport to represent, nor should it be interpreted as, the fair value of Barnwell’s oil and natural gas reserves. An estimate of fair value would also consider, among other items, the value of Barnwell’s undeveloped land position, the recovery of reserves not presently classified as proved, anticipated future changes in oil and natural gas prices (these amounts were based on a natural gas price of $1.49 per Mcf and an oil price of $33.26 per Bbl) and costs, and a discount factor more representative of the time value of money and the risks inherent in reserve estimates.

In December 2018, the Society of Petroleum Evaluation Engineers and associated industry professionals updated the Canadian Oil and Gas Evaluation (“COGE”) Handbook. The updates clarify and streamline existing guidelines and offer additional guidance regarding Canadian reserves evaluations. Barnwell has included all abandonment, decommissioning and reclamation costs and inactive well costs in accordance with best practice recommendations into the Company’s September 30, 2020 and September 30, 2019 year-end reserve reports.

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 2020, 2019 and 2018 was derived in Alberta, Canada. For a discussion regarding our total annual production volumes, average sales prices, and related production costs, see Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” The 2018 volumes reflect volumes from the Twining acquisition only from the closing date of August 28, 2018.


	Year ended September 30,
	2020	2019	2018
Annual net production:
Natural gas (Mcf)	649,000	628,000	328,000
Oil (Bbls)	153,000	123,000	62,000
Natural gas liquids (Bbls)	21,000	18,000	5,000
Total (Boe)	286,000	250,000	123,000
Total (Mcfe)	1,658,000	1,446,000	717,000
Annual average sales price per unit of production:
Mcf of natural gas*	$1.64	$1.15	$1.12
Bbl of oil**	$33.85	$41.84	$51.53
Bbl of natural gas liquids**	$17.16	$25.84	$43.02
Annual average production cost per Boe produced***	$16.79	$20.64	$21.08
Annual average production cost per Mcfe produced***	$2.89	$3.56	$3.63

______________________________________________________

* 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 $3,151,000 in oil and natural gas properties during fiscal 2020, including accrued capital expenditures and acquisitions of oil and natural gas properties and excluding additions and revisions to estimated asset retirement obligations. Barnwell’s capital expenditures were mostly due to the Twining horizontal development well drilled in the first quarter of fiscal 2020 which amounted to approximately $2,400,000 and the participation in one gross (0.3 net) development well in the Spirit River area that was drilled in fiscal 2019 and completed in fiscal 2020 where approximately $670,000 in capital expenditures was incurred in fiscal 2020.

There were no significant amounts paid for oil and natural gas property acquisitions during fiscal 2020.

Well Drilling Activities

In fiscal 2020, Barnwell drilled one gross (1.0 net) horizontal development well in the Twining area. This well was successful and started producing in January 2020. This well contributed approximately 15,900 barrels of net oil production from January through September 2020, representing 10% total net oil production for fiscal 2020. The well was temporarily shut-in from mid-April 2020 to mid-May 2020 due to decreased oil prices. Recent net oil production from this well was approximately 103 barrels per day.

One gross (0.3 net) horizontal development well was drilled in the Spirit River area in fiscal 2019 and then completed in fiscal 2020. The well commenced production on November 17, 2019 and produced approximately 26,000 net barrels of oil during the fiscal year ended September 30, 2020 which represented 17% of the year's net oil production. The Company's share of net oil production from this well averaged over 200 barrels per day during the first month of production but has since declined to approximately 40 barrels per day due to natural declines.

Producing Wells

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

Developed Acreage and Undeveloped Acreage

The following table sets forth the gross and net acres of both developed and undeveloped oil and natural gas leases which Barnwell held as of September 30, 2020.

Developed Acreage*

Undeveloped Acreage*

Total

Location

Gross

Net

Gross

Net

Gross

Net

Canada

180,030

36,710

74,177

12,600

254,207

49,310

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* “Developed Acreage” includes the acres covered by leases upon which there are one or more producing wells. “Undeveloped Acreage” includes acres covered by leases upon which there are no producing wells and which are maintained by the payment of delay rentals or the commencement of drilling thereon.

Eighty-nine percent of Barnwell’s undeveloped acreage is not subject to expiration at September 30, 2020. Eleven percent of Barnwell’s leasehold interests in undeveloped acreage is subject to expiration and expire over the next five fiscal years, if not developed, as follows: 3% expire during fiscal 2021; 3% expire during fiscal 2022; 5% expire during fiscal 2023; no expirations during fiscal 2024 and fiscal 2025. There can be no assurance that Barnwell will be successful in renewing its leasehold interests in the event of expiration.

Much of the undeveloped acreage is at non-operated properties over which we do not have control, and the value of such acreage is not estimated to be significant at current commodity prices. Barnwell’s undeveloped acreage includes a significant concentration in the Thornbury (5,279 net acres) and Twining (1,472 net acres) areas of Alberta, Canada.

Marketing of Oil and Natural Gas

Barnwell sells its 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 2020, over 80% of Barnwell’s oil and natural gas revenues were from products sold at spot prices. Barnwell does not use derivative instruments to manage price risk.

In fiscal 2020 and 2019, Barnwell took most of its 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 that periodically assign allowable rates of production. The province of Alberta and Government of Canada also monitor and regulate the volume of natural gas that may be removed from the province and the conditions of removal.

There is no current government regulation of the price that may be charged on the sale of Canadian oil or natural gas production. Canadian natural gas production destined for export is priced by market forces subject to export contracts meeting certain criteria prescribed by Canada’s National Energy Board and the Government of Canada.

All of Barnwell’s gross revenues were derived from properties located within Alberta, which charges oil and natural gas producers a royalty for production within the province. 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 2020 and 2019, 44% and 47%, respectively, of royalties related to Alberta government charges, and 56% and 53%, respectively, of royalties related to freehold, override and other charges which are not directly affected by the Alberta royalty framework.

In fiscal 2020, the weighted-average royalty rate paid on all of Barnwell’s natural gas was 7%, and the weighted-average royalty rate paid on oil was 11%.

Barnwell's oil and natural gas segment is currently subject to the provisions of the Alberta Energy Regulator's (“AER”) Licensee Liability Rating (“LLR”) program. Under the LLR program the AER calculates a Liability Management Ratio (“LMR”) for a company based on the ratio of the company’s deemed assets over its deemed liabilities relating to wells and facilities for which the company is the licensed operator. The LMR assessment is designed to assess a company’s ability to address its suspension, abandonment, remediation, and reclamation liabilities. The value of the deemed assets is based on each well's most recent twelve months of production and a rolling three-year average industry netback as determined by the AER annually. The AER has not recalculated the three-year average industry netback since March 2015 making the current value a premium to what most producers have been realizing. A recalculation of the value using current industry netback values would likely have a negative impact on our LMR. Companies with an LMR less than 1.0 are required to deposit funds with the AER to

cover future deemed liabilities. At September 30, 2020, the Company had sufficient deemed asset value that no security deposit was due. The current liability framework is under revision by the AER. A percentage-based retirement framework is expected to be introduced, but further details are unknown at this time.

The AER reviews and approves the transfers of all well, facility and pipeline license from one operator to another, and requires purchasers of AER licensed oil and natural gas assets to have an LMR of 2.0 or higher immediately following the transfer of a license. This review process typically takes 30 to 60 days from the date of application. Application was made on August 28, 2018 for Barnwell of Canada to accept the transfer of the various licenses relating to the Twining acquisition. On October 2, 2018, the AER approved the transfer of all of the related licenses.

In September 2019, the AER issued an abandonment/closure order for all wells and facilities in the Manyberries area which had been largely operated by LGX Oil & Gas Ltd. (“LGX”), an operating company that went into receivership in 2016. The estimated asset retirement obligation for the Company's wells and facilities in the Manyberries area is included in “Asset retirement obligation” in the Consolidated Balance Sheets. Many 100% LGX owned wells are to be reclaimed by the Orphan Well Association (“OWA”). However, as next largest interest holder in 78 of the wells and 6 facilities formerly operated by LGX, averaging 11%, the Company is required to take care and custody of those properties and to coordinate their closure.

On November 5, 2019, in response to the AER order, the Company submitted its proposed plan to abandon the Manyberries wells and facilities in an orderly fashion over a ten-year period. This area has unique access issues as a result of an Emergency Protection Order to protect the Sage Grouse under the Canadian Government’s Species at Risk Act. Access is limited to a window of mid-September to the end of November each year.

The plan that the Company has submitted began in October 2019 with field inspections, securing wells, and equipment inventory, for which minor expenses were expended. The plan includes further field activity beginning in the fall of 2020, our fiscal 2021 first quarter, which has been initiated and initially involves removal and salvage of the surface equipment; these costs are estimated to be minimal due in part to the salvage value of the equipment. Beyond fiscal 2021, the Company proposes to perform seven to ten well abandonments per year over an estimated ten-year period as well as abandon the facilities in that time period. Annual gross costs estimated to be incurred currently are approximately $500,000, approximately $55,000 net to the Company, however, the Company expects it will have to pay the gross costs and then recover from the other working interest owners and the OWA their costs, such that there will be a period between Barnwell having to pay the gross costs and getting reimbursed for the other parties’ portions.

As an alternative to the above plan, the Company is in discussions to allow the OWA to perform well abandonments and reclamations on the Company’s behalf. This would eliminate the need for Barnwell to carry LGX’s average 85% portion of Barnwell interest in wells in Manyberries. Barnwell would also benefit from the OWA’s extensive experience and scale of operations in this area. This could allow Barnwell to accelerate closure of the Manyberries area to a 4-year period (fiscal 2022-2025) from the above ten-year plan, and it is estimated that this plan would increase Barnwell’s net expenditures to approximately $150,000 annually, with some minor costs likely extending into fiscal 2026.

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

reclaimed or exempt since 2016. 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 $200,000 in net funding to date, to be directed to ARO reduction activities. Barnwell has further benefited from grants allocated to its non-operated property partners, with a further $75,000 in activities approved to date.

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 is also 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, 63 of which were sold from 2006 to 2020 and of which 17 lots remain to be sold, and a beach club on the portion of the property bordering the Pacific Ocean. The purchasers of the 80 single-family lots will have the right to apply for membership in the Kuki`o Golf and Beach Club, which is located adjacent to and south of the Four Seasons Resort Hualalai at Historic Ka`upulehu. 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.

Kaupulehu Developments is entitled to receive payments from KD I based on the following percentages of the gross receipts from KD I’s sales of single-family residential lots in Increment I: 10% of such aggregate gross proceeds greater than $100,000,000 up to $300,000,000; and 14% of such aggregate gross proceeds in excess of $300,000,000. In fiscal 2020, two single-family lots in Increment I were sold bringing the total amount of gross proceeds from single-family lot sales through September 30, 2020 to $219,700,000.

Prior to March 7, 2019, Kaupulehu Developments was entitled to receive payments from KD II based on a percentage of the gross receipts from KD II’s sales of residential lots or units in Increment II ranging from 8% to 10% of the price of improved or unimproved lots or 2.60% to 3.25% of the price of units constructed on a lot, to be determined in the future depending upon a number of variables, including whether the lots are sold prior to improvement. Kaupulehu Developments was also entitled to receive 50% of distributions otherwise payable from KD II to its members up to $8,000,000, of which $3,500,000 had been received, after the members of KD II received distributions equal to the original basis of capital invested in the project.

In March 2019, KD II admitted a new development partner, Replay Kaupulehu Development, LLC (“Replay”), a party unrelated to Barnwell, in an effort to move forward with development of the remainder of Increment II at Kaupulehu. Effective March 7, 2019, KDK and Replay hold ownership interests of 55% and 45%, respectively, of KD II. Accordingly, Barnwell has a 10.8% indirect non-controlling ownership interest in KD II through KDK as of that date that will continue to be accounted for using the equity method of accounting. Barnwell continues to have an indirect 19.6% non-controlling ownership interest in KD Kukio Resorts, KD Maniniowali, and KD I.

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

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

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

In fiscal 2020, the Kukio Resort Land Development Partnerships sold two lots in Increment I and as a result of the lot sales, made cash distributions to its partners of which Barnwell received $360,000, after distributing $20,000 to minority interests. Of the $360,000 cash distribution received from the Kukio Resort Land Development Partnerships, $197,000 represented a partial payment of the preferred return from KKM and was recorded as an additional equity pickup in the “Equity in income (loss) of affiliates” line item on the accompanying Consolidated Statement of Operations during the year ended September 30, 2020. See Note 6 for further discussion on the preferred return from KKM.

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 Floway pumps and equipment in the state of Hawaii.

Operations

Water Resources owns and operates five water well drilling rigs, two pump rigs and other ancillary drilling and pump equipment. Additionally, Water Resources temporarily rents a storage facility in Honolulu, Hawaii, and leases a one acre maintenance and storage facility with 2,800 square feet of interior space in Kawaihae, Hawaii, and a one-half acre equipment storage yard in Waimea, Hawaii. Water Resources also maintains an inventory of uninstalled materials for jobs in progress and an inventory of drilling materials and pump supplies.

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.

In fiscal 2020, Water Resources started one well drilling and three pump installation and repair contracts and completed three well drilling contracts. No pump installation and repair contracts were completed in fiscal 2020. All of the three completed well drilling contracts were started in fiscal 2019. Sixty-five percent of well drilling and pump installation and repair jobs, representing 9% of total contract drilling revenues in fiscal 2020, have been pursuant to government contracts.

The approximate dollar amount of Water Resources’ backlog of firm well drilling and pump installation and repair contracts at December 1, 2020 and 2019 was as follows:


	December 1,
	2020		2019
Well drilling	$	4,700,000	$	8,800,000
Pump installation and repair	2,500,000		1,200,000
	$	7,200,000	$	10,000,000

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

Competition

Water Resources competes with other drilling contractors in Hawaii, some of which use drill rigs similar to Water Resources’. These competitors are also 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 is also 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 2020 will continue. Management currently estimates that well drilling activity for fiscal 2021 will be significantly lower than fiscal 2020 based upon the number and value of contracts in backlog.

Financial Information About Industry Segments and Geographic Areas

Note 12 in the “Notes to Consolidated Financial Statements” in Item 8 contains information on our segments and geographic areas.

Employees

At December 1, 2020, Barnwell employed 43 individuals; 42 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 are required to file annual, quarterly and current reports and other information with the SEC. These filings are not deemed to be incorporated by reference in this report. You may read and copy any document filed by us at the Public Reference Room of the SEC, 100 F Street, N.E., Washington, D.C. 20549, on official business days during the hours of 10 a.m. to 3 p.m. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Our filings with the SEC are also available to the public through the SEC’s website at www.sec.gov. Furthermore, we maintain an internet site at www.brninc.com. We make available on our internet 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 these websites are not incorporated into this filing. Furthermore, 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

The Company faces issues that could impair our ability to continue as a going concern in the future.

Our ability to sustain our business in the future will depend on sufficient oil and natural gas operating cash flows, which are highly sensitive to volatile oil and natural gas prices, sufficient contract drilling operating cash flows, which are subject to potentially large changes in demand, and sufficient future land investment segment proceeds and distributions from the Kukio Resort Land Development Partnerships, the timing of which are both highly uncertain and not within Barnwell’s control. A sufficient level of such cash inflows are necessary to fund discretionary oil and natural gas capital expenditures, which must be economically successful to provide sufficient returns, as well as fund our non-discretionary outflows such as oil and natural gas asset retirement obligations and ongoing operating and general and administrative expenses.

We have experienced a trend of losses and negative operating cash flows in three of the last four years. Due to the additional impacts of the COVID-19 pandemic, we now face a greater uncertainty about our cash inflows as described above, which in turn leads to substantial doubt regarding our ability to make the required discretionary cash outflows for the capital expenditures necessary to convert our proved undeveloped reserves to proved developed reserves. Furthermore, because of the greater uncertainty about our cash inflows described above, there is substantial doubt about our ability to fund our non-discretionary cash outflows and thus substantial doubt about our ability to continue as a going concern for one year from the date of the filing of this report.

Prior to and during fiscal 2020 and subsequently, the Company investigated potential sources of funding, including non-core oil and natural gas property sales, however, no probable sources of such funding have yet been secured. Additionally, the Company has listed its corporate office on the 29th floor of a commercial office building in downtown Honolulu, Hawaii, for sale to generate liquidity in order to help mitigate the substantial doubt about our ability to continue as a going concern. However, the Company’s ability to sell its corporate office at an appropriate time or for a sufficient price is outside of the Company’s control and is therefore not probable. Because of this uncertainty as well as uncertainties regarding the potential duration and depth of the impacts of the COVID-19 pandemic on our business as described above, substantial doubt about our ability to continue as a going concern for one year from the date of the filing of this report exists.

Our business operations and financial condition have been and may continue to be materially and adversely affected by the outbreak of a novel strain of coronavirus, which resulted in the global health pandemic referred to as COVID-19.

An outbreak of a novel strain of coronavirus, which causes the disease referred to as COVID-19, emerged in Wuhan, China in late 2019. The novel coronavirus is considered highly contagious and has spread to most countries around the world and throughout the United States, creating a serious impact on customers, workforces and suppliers, disrupting economies and financial markets and leading to a world-

wide economic downturn. On March 11, 2020, the World Health Organization declared the COVID-19 outbreak a global pandemic and the United States and Canadian governments declared the virus a national emergency shortly thereafter. As a result, the normal operations of many businesses have been disrupted, 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. The Company is currently following the recommendations of local and federal health authorities to minimize exposure risk for its various stakeholders, including employees.

The global economy, our markets and our business have been materially and adversely affected by COVID-19. In the first calendar quarter of 2020, the COVID-19 outbreak caused significant reductions in demand for oil and oil prices, which made the Company's development of its proven undeveloped reserves uneconomical and negatively impacted the Company’s financial condition and outlook. As the COVID-19 pandemic continued throughout fiscal 2020 and is continuing, oil prices have continued to make the development of proven undeveloped reserves uneconomical and have severely reduced if not eliminated the Company's ability to finance such development, therefore, the Company has suspended such development. While the Company’s contract drilling segment remained operational throughout fiscal 2020 and continues to work, the continuing impact of COVID-19 on the ability or desire for customers to continue such work is uncertain, and any discontinuation of contracts currently in backlog would result in a material adverse impact to the Company’s financial condition and outlook. 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 outbreak of COVID-19 is not effectively and timely controlled, our business operations and financial condition may continue to be materially and adversely affected as a result of the deteriorating market outlook, the global economic recession, weakened liquidity or 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.

We are subject to the Continued Listing Criteria of the NYSE American and our failure to maintain continued compliance with the listing requirements of the NYSE American exchange could result in the delisting of our common stock.

Our common stock is listed on the NYSE American. The rules of NYSE American provide that, among other things, the Company must meet certain continued listing standards relating to stockholders’ equity as set forth in Part 10, Section 1003(a) of the NYSE American Company Guide (the “Guide”) and that shares be delisted from trading, if, among other things, the Company has failed to comply with such listing agreements. For example, the NYSE American may consider suspending trading in, or removing the listing of, securities of an issuer that is not in compliance with: (i) Section 1003(a)(i) of the Guide, which requires an issuer to have stockholders’ equity of $6.0 million or more if such issuer reported losses from continuing operations and/or net losses in its five most recent fiscal years, (ii) Section 1003(a)(ii) of the Guide, which requires an issuer to have stockholders’ equity of $4.0 million or more if such issuer reported losses from continuing operations and/or net losses in three of its four most recent fiscal years, and (iii) Section 1003(a)(iii) of the Guide, which requires an issuer to have stockholders’ equity of $2.0 million or more if such issuer reported losses from continuing operations and/or net losses in two of its three most recent fiscal years. Even if an issuer fails to meet the foregoing stockholders’ equity requirements, the NYSE American will not normally consider delisting securities of such issuer if the issuer has (1) average global market capitalization of at least $50,000,000; or total assets and revenue of $50,000,000 in its last fiscal year, or in two of its last three fiscal years; and (2) the issuer has at least

1,100,000 shares publicly held, a market value of publicly held shares of at least $15,000,000 and 400 round lot shareholders. With respect to an issuer that is not in compliance with the foregoing requirements, upon notifying the issuer of such deficiency, the NYSE American generally provides an 18-month “cure period” for the issuer to regain the minimum stockholders’ equity requirement, however if the issuer is unable to do so, the NYSE American may delist its stock.

As of September 30, 2019, the Company had stockholders’ equity of approximately $1.2 million, as set forth in the Company’s annual report on Form 10-K for the fiscal year ended September 30, 2019, which was filed with the SEC on December 20, 2019, and the Company’s total value of market capitalization was approximately $4,304,000. On January 13, 2020, the Company received a letter from the NYSE American staff (the “Exchange Staff”) indicating that the Company was not in compliance with Part 10, Sections 1003(a)(i) and (a)(ii) of the Guide since it reported stockholders’ equity of $1.2 million and net losses in fiscal years ended September 30, 2019, September 30, 2018 and September 30, 2016. The Company’s failure to meet the NYSE American’s stockholders’ equity requirements and the exceptions resulted in a risk that our common stock may be delisted.

In accordance with the NYSE American’s policies and procedures, the Company submitted a plan (the “Plan”) addressing how the Company intended to regain compliance with Part 10, Section 1003 of the Guide. On April 2, 2020, the NYSE American notified the Company that it accepted the Company’s Plan and granted the Company an extension for its continued listing until July 13, 2021 (the “Plan Period”). The Company has been and will continue to be subject to periodic review by Exchange Staff during the Plan Period. The Plan was submitted to the NYSE American before the start of the COVID-19 pandemic-related low commodity price environment, the oil price war between Saudi Arabia and Russia and other macroeconomic pressures that have impacted our businesses and the U.S. economy in general. The magnitude and duration of these factors have and will adversely affect the Company’s ability to achieve the Plan’s goals and to return to compliance with the NYSE American’s listing standards. If the Company does not regain compliance by the end of the Plan Period, or if the Company does not make ongoing progress consistent with its Plan, the NYSE American may initiate delisting procedures as appropriate.

The Company’s reported stockholders’ equity fell from $2,049,000 at March 31, 2020 to a stockholders’ deficit of $1,512,000 at June 30, 2020, and then to a stockholders’ deficit of $2,045,000 at September 30, 2020, as disclosed in the accompanying consolidated financial statements of this report. Thus, the Company may fail to be in compliance with the NYSE American continued listing standards relating to stockholders’ equity to which the Plan relates; specifically Section 1003(a)(i) and Section 1003(a)(ii). The Company submitted updates to the Plan, as required or requested by the NYSE American, in July 2020, August 2020 and September 2020. The September 2020 Plan updates presented initiatives which, if all of them are achieved, could result in the amount of stockholders’ equity required by the NYSE American at the end of the Plan Period and accordingly result in the Company regaining compliance with the NYSE American’s continued listing standards. There is no assurance that the presented initiatives will in fact be achieved. The Company has not yet received any correspondence from the NYSE American regarding the September 2020 Plan updates. If the NYSE American delists our common stock, investors may face material adverse consequences, including, but not limited to, a lack of a trading market for our common stock, reduced liquidity, and an inability for us to obtain financing to fund our operations.

Stockholders may be diluted significantly through our efforts to obtain financing and satisfy obligations through the issuance of securities.

Our Board of Directors has authority, without action or vote of the stockholders, subject to the

requirements of the NYSE American (which generally require stockholder approval for any transactions which would result in the issuance of more than 20% of our then outstanding shares of common stock or voting rights representing over 20% of our then outstanding shares of stock, subject to certain exceptions, including sales in public offerings and/or sales which are undertaken at or above the greater of the book value and/or market value of the issuer’s common stock on the date the transaction is agreed to be completed), to issue all or part of the authorized but unissued shares of common stock, preferred stock or warrants to purchase such shares of common stock. In addition, we may attempt to 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 have influence over our business regardless of the opposition of other stockholders.

As of September 30, 2020, the CEO, who is a member of the Board of Directors, and two others hold approximately 36% 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. The significant stockholders who are also members of the Board of Directors could significantly affect our business, policies and affairs.

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. However, the ability to develop reserves will be heavily influenced by available financial resources. The Company has been unable to raise sufficient funds and does not currently have a definitive plan to develop such reserves and therefore has excluded

undeveloped reserves from this Annual Report on Form 10-K. 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 could also 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 are also 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 United States 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 may also 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. Barnwell holds an 11% working interest, the largest working interest other than that held by the operator, in a property with approximately 78 wells and 6 facilities where the operator is in receivership.

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 LLR program. Under the LLR program the AER calculates a LMR for a company based on the ratio of the company’s deemed assets over its deemed liabilities relating to wells and facilities for which the company is the licensed operator and imposes a security deposit on operators whose estimated liabilities exceed their deemed asset value. At September 30, 2020, the Company had sufficient deemed asset value that no security deposit was due. However, decreases in prices and production and related netbacks from relevant properties could result in a decline in the Company's deemed asset value to a point where a deposit could be due in the future. The current liability framework is under revision by the AER. A percentage-based retirement framework is expected to be introduced, but further details are unknown at this time.

The AER requires purchasers of AER licensed oil and natural gas assets to have an LMR of 2.0 or higher immediately following the transfer of a license. This LMR requirement for well transfers hinders our ability to generate capital by selling oil and natural gas assets as there are less qualified buyers.

A requirement to provide security deposit 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 LLR 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 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 United States 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.

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 additional PUDs as we pursue our drilling program. Moreover, we may be required to write down our PUDs if we do not drill or plan on delaying those wells within the required five-year timeframe.

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 stimulate 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 United States.

Barnwell’s oil and natural gas operations are affected by political developments and laws and regulations, particularly in Canada and the United States, 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, Saskatchewan and British Columbia is controlled by the governments of each of those provinces. 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; 38% in fiscal 2020.

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.

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 is also 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

•certain underlying partnership data is not accessible to us, therefore we depend on the general partner to provide us with reliable accounting information.

We may be required to write-down the carrying value of our investment in the Kukio Resort Land Development Partnerships if our assumptions about future lot sales and profitability prove incorrect. Any write-down would negatively impact our results of operations.

In analyzing the value of our investment in the Kukio Resort Land Development Partnerships, we have made assumptions about the level of future lot sales, operating and development costs, cash generation and market conditions. These assumptions are based on management’s and the general partner’s best estimates and if the actual results differ significantly from these assumptions, we may not be able to realize the value of the assets recorded, which could lead to an impairment of certain of these assets in the future. Such a write-down would have a negative impact on our results of operations.

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 United States 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. As also noted above, 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; 9% in fiscal 2020. 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.

The loss of or damage to key vendor, customer or sub-contractor relationships would adversely affect our operations.

Our contract drilling business is dependent on our relationships with key vendors, customers and subcontractors. The loss of or damage to any of our key relationships could negatively affect our business.

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.

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, through a wholly-owned subsidiary, owns the 29th floor of a commercial office building in downtown Honolulu that it uses as its corporate office and is currently available for sale.

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:


Quarter Ended	High	Low	Quarter Ended	High	Low
December 31, 2018	$1.86	$1.22	December 31, 2019	$1.11	$0.30
March 31, 2019	$1.64	$1.27	March 31, 2020	$2.68	$0.30
June 30, 2019	$1.49	$1.03	June 30, 2020	$2.10	$0.44
September 30, 2019	$1.12	$0.46	September 30, 2020	$1.64	$0.66

Holders

As of December 3, 2020, there were 8,277,160 shares of common stock, par value $0.50, outstanding. As of December 3, 2020, there were approximately 80 shareholders of record and approximately 1,000 beneficial owners.

Dividends

No dividends were declared or paid during fiscal years 2020 or 2019. 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.

Securities Authorized for Issuance Under Equity Compensation Plans

None.

Stock Performance Graph and Cumulative Total Return

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

ITEM 6. SELECTED FINANCIAL DATA

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

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, 2020 and 2019, and the related Consolidated Statements of Operations, Comprehensive Loss, Equity (Deficit), and Cash Flows for the years ended September 30, 2020 and 2019. 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

On March 11, 2020, the World Health Organization declared the COVID-19 outbreak a global pandemic and the United States and Canadian governments declared the virus a national emergency shortly thereafter. As a result, the normal operations of many businesses have been disrupted, 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. The global economy, our markets and our business have been materially and adversely affected by COVID-19.

The COVID-19 outbreak has caused and continues to cause significant reductions in demand for oil and oil prices, which has caused the Company to suspend the development of proved undeveloped reserves and has impacted and continues to impact the Company’s financial condition and outlook. While the Company’s contract drilling segment remained operational throughout fiscal 2020 and continues to work, the continuing impact of COVID-19 on the ability or desire for customers to continue such work is uncertain, and any discontinuation of contracts currently in backlog would result in a material adverse impact to the Company’s financial condition and outlook. 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 outbreak of COVID-19 is not effectively and timely controlled, our business operations and financial condition may continue to be materially and adversely affected as a result of the deteriorating market outlook, the global economic recession, weakened liquidity or 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.

Going Concern

outflows such as oil and natural gas asset retirement obligations and ongoing operating and general and administrative expenses.

Prior to and during fiscal 2020 and subsequently, the Company investigated potential sources of funding, including non-core oil and natural gas property sales, however, no probable sources of such funding have yet been secured. Additionally, the Company has listed its corporate office on the 29th floor of a commercial office building in downtown Honolulu, Hawaii, for sale to generate liquidity in order to help mitigate the substantial doubt about our ability to continue as a going concern. However, the Company’s ability to sell its corporate office at an appropriate time or for a sufficient price is outside of the Company's control and is therefore not probable. Because of this uncertainty as well as uncertainties regarding the potential duration and depth of the impacts of the COVID-19 pandemic on our business as described above, substantial doubt about our ability to continue as a going concern for one year from the date of the filing of this report exists.

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.

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 27% 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 2020, the ceiling limitation would have decreased approximately $141,000 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 2020 of approximately $500,000.

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 2020, depletion for fiscal 2020 would have increased by approximately $82,000.

While the quantities of proved reserves require substantial judgment, the associated prices of oil, natural gas and natural gas liquids reserves are the average first-day-of-the-month prices during the 12-month period ending in the reporting period on a constant basis as prescribed by SEC regulations. Additionally, the applicable discount rate that is used to calculate the discounted present value of the reserves is mandated at 10%. Costs included in future net revenues are determined in a similar manner. As such, the future net revenues associated with the estimated proved reserves are not based on an assessment of future prices or costs.

Contract Drilling Revenues and Operating Expenses

Policy Description

Through contracts which are normally less than twelve months in duration, Barnwell drills water and water monitoring wells and installs and repairs water pumping systems in Hawaii. Barnwell recognizes revenue from well drilling or the installation of pumps over time based on total costs incurred on the projects relative to the total expected costs to satisfy the performance obligation as management believes this is an accurate representation of the percentage of completion as control is continuously transferred to the customer. Uninstalled materials, which typically consists of well casing or pumps, are excluded in the costs-to-costs calculation for the duration of the contract as including these costs would result in a distortion of progress towards satisfaction of the performance obligation due to the resulting cumulative catch-up in margin in a single period. An equal amount of cost and revenue is recorded when uninstalled materials are controlled by the customer, which is typically when Barnwell has the right to payment for the materials and when the materials are delivered to the customer’s site or location and such 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

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 (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 in 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 exploratory and developmental operations elsewhere.

Barnwell sells all of its 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 approximately 870 acres 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 the following percentages of the gross receipts from KD I’s sales at Increment I: 10% of such aggregate gross proceeds greater than $100,000,000 up to $300,000,000; and 14% of such aggregate gross proceeds in excess of $300,000,000. Increment I is an area zoned for approximately 80 single-family lots, of which 17 remained to be sold at September 30, 2020, and a beach club on the portion of the property bordering the Pacific Ocean.

•Prior to March 7, 2019, the right to receive percentage of sales payments from KD II resulting from the sale of lots and/or residential units by KD II, within Increment II of Kaupulehu Lot 4A. 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. Kaupulehu Developments was entitled to receive payments from KD II based on a percentage of the gross receipts from KD II’s sales ranging from 8% to 10% of the price of improved or unimproved lots or 2.60% to 3.25% of the price of units constructed on a lot, to be determined in the future depending upon a number of variables, including whether the lots are sold prior to improvement. Kaupulehu Developments was also entitled to receive 50% of any future distributions otherwise payable from KD II to it members up to $8,000,000, of which $3,500,000 had been received. Two ocean front parcels approximately two to three acres in size fronting the ocean were developed and sold within Increment II by KD II, and Kaupulehu Developments received percentage of sales payments from those sales. The remaining acreage within Increment II is not yet developed. In February 2019, KD II was granted a 20-year time extension of the allowed zoning for the project that would have otherwise expired in April 2019.

As of March 7, 2019, with the admission of Replay as a new development partner of Increment II, the ownership interests in KD II of KDK and Replay were changed to 55% and 45%, respectively. Additionally, Kaupulehu Developments has 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 now also obligated to pay an amount equal to 0.72% and 0.20% of the cumulative net profits of KD II to KD Development, LLC and a pool of various individuals, respectively, all of whom are partners of KKM and are unrelated to Barnwell, in compensation for the agreement of these parties to admit the new development partner for Increment II.

•Prior to March 7, 2019, we had an indirect 19.6% non-controlling ownership interest in KD Kukio Resorts, KD Maniniowali, and KDK. As of March 7, 2019, with the admission of Replay as a new development partner of Increment II, we now have an indirect 10.8% non-controlling ownership interest in KD II through KDK. Our indirect interest in the other entities remains unchanged. 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 Increments I and II. The partnerships derive income from the sale of residential parcels as well as from commission on real estate sales by the real estate sales office. KD I has engaged Replay as a consultant to assist with the sales and marketing strategy of Increment I. Replay does not have an ownership interest in KD I.

•Approximately 1,000 acres of vacant leasehold land zoned conservation in the Kaupulehu Lot 4C area located adjacent to the 870-acre Lot 4A described above, 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 state of Hawaii. 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 $33.85 per barrel during the year ended September 30, 2020, a decrease of 19% from $41.84 per barrel realized during the prior year. The decrease in the average price for oil over the past year is primarily due to the contraction of global oil demand resulting from the COVID-19 pandemic and the impact of the price war between Saudi Arabia and Russia. Accordingly, oil price declines began in March 2020, with oil futures prices temporarily declining to unprecedented levels below zero. While oil prices have recovered somewhat from those record lows, 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 $1.64 per Mcf during the year ended September 30, 2020, an increase of 43% from $1.15 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 17 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.

Barnwell estimates that it will be heavily reliant upon land investment segment proceeds in order to provide sufficient liquidity to fund our operations in 2021 and beyond. However, there can be no assurance that the amount of future land investment segment proceeds will provide the liquidity required.

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 2021 will be significantly lower than fiscal 2020 based upon the number and value of contracts in backlog.

Results of Operations

Summary

Net loss attributable to Barnwell for fiscal 2020 totaled $4,756,000, a $7,658,000 increase in operating results from a net loss of $12,414,000 in fiscal 2019. The following factors affected the results of operations for the current fiscal year as compared to the prior fiscal year:

•A $3,036,000 increase in contract drilling segment operating results, before income taxes, primarily resulting from significantly increased activity attributable to a significant well drilling contract;

•A $1,336,000 gain recognized in the current year period from the sale of the Company's leasehold interest in a three-quarter of an acre contract drilling segment maintenance and storage yard in Honolulu, Hawaii;

•A $2,967,000 decrease in oil and natural gas segment operating losses, before income taxes, due primarily to a $1,384,000 decrease in the ceiling test impairment which was $5,710,000 in the prior year period, compared to $4,326,000 in the current year period, and $287,000 higher revenues and $363,000 lower operating expenses and a $933,000 decrease in the oil and natural gas depletion in the current year period as compared to the same period in prior year; and

•A $628,000 increase in equity in income from affiliates as a result of increased operating results of the Kukio Resort Land Development Partnerships.

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.

The average exchange rate of the Canadian dollar to the U.S. dollar decreased 1% in fiscal 2020, as compared to fiscal 2019, and the exchange rate of the Canadian dollar to the U.S. dollar remained relatively the same rate at September 30, 2020, as compared to September 30, 2019. 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. Barnwell’s Canadian dollar assets are greater than its Canadian dollar liabilities; therefore, increases or decreases in the value of the Canadian dollar to the U.S. dollar generate other comprehensive income or loss, respectively. Other comprehensive income and losses are not included in net loss. Other comprehensive loss due to foreign currency translation adjustments, net of taxes, for fiscal 2020 was $146,000, an $88,000 decrease from other comprehensive loss due to foreign currency translation adjustments, net of taxes, of $234,000 in fiscal 2019. There were no taxes on other comprehensive loss due to foreign currency translation adjustments in fiscal 2020 and 2019 due to a full valuation allowance on the related deferred tax assets.

Oil and natural gas

Selected Operating Statistics

The following tables set forth Barnwell’s annual average prices per unit of production and annual net production volumes for fiscal 2020 as compared to fiscal 2019. Production amounts reported are net of royalties.


	Annual Average Price Per Unit
					Increase (Decrease)
	2020		2019		$		%
Natural gas (Mcf)*	$	1.64	$	1.15	$	0.49	43%
Oil (Bbls)	$	33.85	$	41.84	$	(7.99)	(19)%
Liquids (Bbls)	$	17.16	$	25.84	$	(8.68)	(34)%


	Annual Net Production
			Increase (Decrease)
	2020	2019	Units	%
Natural gas (Mcf)	649,000	628,000	21,000	3%
Oil (Bbls)	153,000	123,000	30,000	24%
Liquids (Bbls)	21,000	18,000	3,000	17%

_________________________________________________

* Natural gas price per unit is net of pipeline charges.

The oil and natural gas segment generated a $4,230,000 operating loss in fiscal 2020 before general and administrative expenses, an increase in operating results of $2,967,000 as compared to

$7,197,000 of operating loss in fiscal 2019. There was a $4,326,000 ceiling test impairment included in the operating loss in the current year as compared to a $5,710,000 ceiling test impairment in the prior year.

Oil and natural gas revenues increased $287,000 (4%) from $6,406,000 in fiscal 2019 to $6,693,000 in fiscal 2020, primarily due to an increase in oil production from new wells drilled in fiscal 2020 in the Spirit River and Twining areas, and an increase in natural gas prices in the current year period as compared to the prior year period. The increase in oil production from the two new wells in the Spirit River and Twining areas and oil production from minor acquisitions in the current year period was partially offset by natural declines in oil production due to aging of wells and the sale of interests in the Progress area in October 2019, as well as temporary shut-ins in certain areas due to workovers, unfavorable weather conditions, and low oil prices. The increase was largely offset by a 19% decrease in oil prices in the current year period as compared to the prior year period.

Oil and natural gas operating expenses decreased $363,000 (7%) from $5,213,000 in fiscal 2019 to $4,850,000 in fiscal 2020, primarily due to significant repair and maintenance costs at the Twining property included in the prior year period, whereas there were no such costs in the current year period. The decrease was also due to shut-in of wells with relatively high operating costs and reductions in operator time and discounted costs obtained from vendors that were negotiated in light of the extremely low oil prices.

Oil and natural gas segment depletion decreased $933,000 from $2,680,000 in fiscal 2019 to $1,747,000 in fiscal 2020, primarily due to a decrease in the depletion rate for the current year period, as compared to the same period in prior year, due primarily to impairment write-downs in the prior and current years.

The well drilled in the Spirit River area commenced production on November 17, 2019 and produced approximately 26,000 net barrels of oil during the fiscal year ended September 30, 2020 which represented 17% of the year's net oil production. The Company's share of recent net oil production from this well averaged over 200 barrels per day during the first month of production but has since declined to approximately 40 barrels per day due to natural declines.

The new well that was drilled and completed in December 2019 at the Twining area began producing oil and natural gas in January 2020. This well contributed approximately 15,900 barrels of net oil production from January through September 2020, representing 10% total net oil production for the year ended September 30, 2020. The well was temporarily shut-in from mid-April 2020 to mid-May 2020 due to decreased oil prices. Recent net oil production from this well was approximately 103 barrels per day.

As a result of the unprecedented contraction of global oil demand resulting from the COVID-19 pandemic combined with the price war between Saudi Arabia and Russia, oil price declines began in March 2020, with oil futures prices temporarily declining to unprecedented levels below zero. While oil prices have recovered somewhat from those record lows, the Company is unable to reasonably predict future oil prices and the impacts future oil 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. Prior to March 7, 2019, Kaupulehu Developments was also entitled to receive percentage of sales payments from the sales of lots and/or residential units in

Increment II by KD II and entitled to receive 50% of any future distributions otherwise payable from KD II to its members up to $8,000,000, of which $3,500,000 was received. Effective March 7, 2019 Kaupulehu Developments' arrangements with regard to payments from the sales of lots and/or residential units in Increment II were changed, as detailed in the Overview section above.

The following table summarizes the revenues received from KD I and KD II and the amount of fees directly related to such revenues:


	Year ended September 30,
	2020		2019
Sale of interest in leasehold land:
Revenues - sale of interest in leasehold land	$	325,000	$	165,000
Fees - included in general and administrative expenses	(40,000)		(20,000)
Sale of interest in leasehold land, net of fees paid	$	285,000	$	145,000

During the year ended September 30, 2020, Barnwell received $325,000 in percentage of sales payments from KD I from the sale of two single-family lots within Phase II of Increment I. During the year ended September 30, 2019, Barnwell received $165,000 in percentage of sales payments from KD I from the sale of one single-family lot within Phase II of Increment I.

In November 2020, subsequent to the close of the year ended September 30, 2020, Kaupulehu Developments received a percentage of sales payment of $170,000 from the sale of one lot within Phase II of Increment I. Financial results from the receipt of this payment will be reflected in Barnwell's quarter ending December 31, 2020. Accordingly, with the inclusion of the lot sale in November 2020, 16 single-family lots of the 80 lots developed within Increment I remained to be sold as of the date of this report. As discussed in the Overview section above, Replay was admitted as a new development partner of Increment II on March 7, 2019. 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.

Contract drilling

Contract drilling revenues and costs are associated with well drilling and water pump installation, replacement and repair in Hawaii.

Contract drilling revenues increased $5,645,000 (106%) to $10,994,000 in fiscal 2020, as compared to $5,349,000 in fiscal 2019, and contract drilling costs increased $2,540,000 (51%) to $7,513,000 in fiscal 2020, as compared to $4,973,000 in fiscal 2019. The contract drilling segment generated a $3,125,000 operating profit before general and administrative expenses during fiscal 2020, an increase in operating results of $3,036,000 as compared to an operating profit before general and administrative expenses of $89,000 in fiscal 2019. The increase in operating results was primarily due to a significant well drilling contract for multiple wells that is based on a fixed rate per day or fixed rate per hour, depending upon the activity, as opposed to the Company's typical contracts that are based on a fixed price per lineal foot drilled. Up to three drilling rigs were being used at this job during the current year period with crews working extended hours. The current period increase in operating results was partially offset by a decrease in operating results due to the unfavorable impact of the unsuccessful removal of a hole opener at the bottom of a water well as discussed below.

The significantly increased operational activity that has led to the increased contract drilling segment operating results for the year ended September 30, 2020, has declined since September 30, 2020,

as the aforementioned significant well drilling contract is nearing completion, such that contract drilling revenues are anticipated to decline in fiscal 2021 as compared to fiscal 2020 based on the number and value of contracts in backlog.

At September 30, 2020, there was a backlog of four well drilling and thirteen pump installation and repair contracts, of which all four well drilling and ten pump installation and repair contracts were in progress as of September 30, 2020. The backlog of contract drilling revenues as of December 1, 2020 was approximately $7,200,000, of which $4,400,000 is expected to be realized in fiscal 2021 with the remainder to be recognized in the following fiscal year. Based on these contracts in backlog, contract drilling segment operating profit is estimated to be significantly lower in fiscal 2021 as compared to fiscal 2020.

In the quarter ended December 31, 2019, the Company experienced the failure of a hole opener which broke apart leaving pieces in the bottom of a water well being drilled in Hawaii. Efforts to remove the items from the well were unsuccessful through the quarter ended March 31, 2020 and subsequently the Company determined that the well should be abandoned and a new well drilled at no incremental cost to the customer as per the terms of the contract. Accordingly, all the costs to drill and abandon the first well, which are all wasted costs, were excluded from the measurement of progress toward contract completion and all such costs were fully accrued in the quarter ended March 31, 2020, as this contract was determined to be a loss job. In September 2020, while making progress towards the drilling of a replacement well in different location, the drill string twisted off and became lodged in the well borehole, which required a stoppage of drilling and the need to dislodge and retrieve the broken drill string. Accordingly, estimated total rework costs to remediate the situation have been accrued at September 30, 2020. As a result of all of the above, $390,000 of revenue previously recognized was reversed in the year ended September 30, 2020 and the Company recognized a decrease of approximately $1,440,000 in the margin of this contract in the year ended September 30, 2020.

In the year ended September 30, 2019, two of the water wells drilled by the contract drilling segment for one customer were determined to not meet the contract specifications for plumbness. Subsequently, in the quarter ended March 31, 2020, the Company executed a separate five-year warranty agreement with the customer for one of the wells that did not meet plumbness. Under the terms of the agreement, if the lack of plumbness is determined to be the cause of a pump failure within the warranty period, the Company would be obligated to replace the pump at no cost to the customer. If the Company is unable to replace the pump using industry-standard methods, or if there are two or more pump failures attributable to lack of plumbness within the five-year warranty period, the Company would be obligated to drill a new well at no cost to the customer. Negotiations with the customer are currently ongoing for the other well that the customer claims did not meet plumbness despite the fact that the independent consulting engineer for the job concluded that the most recent plumbness test, completed after the well was cased with casing cemented into place as per the contract, showed that the well meets the plumbness specifications of the contract. Management believes the degrees of deviation for both wells are not impactful to the performance of the submersible pumps that will be installed in those wells. Accordingly, no accruals have been recorded as of September 30, 2020 as there is no probable or estimable contingent liability.

On July 28, 2020, the Staff of the State of Hawaii’s Commission on Water Resource Management (“Commission”) circulated a draft of a proposed recommendation to the Commission under which the Company, the water utility, the water utility's independent hydrologist firm and the owner of the land on which the two aforementioned water wells were drilled would be assessed penalty fines because each of the wells were calculated to have been drilled beyond the depth permitted by the permit. The wells were

drilled to a depth to penetrate certain layers of impermeable rock necessary to access the aquifer at the instructions and on the advice of the hydrologist hired by the owner of the well. The Company’s share of the proposed penalties and fines were originally calculated to approximately $1,200,000. Subsequently, the Staff of the Commission acknowledged that one well had not been drilled to a depth beyond its permitted depth and the fines on that well were eliminated. Additionally, the fines applicable to the depth of the second well were recalculated and reduced to approximately $300,000 as to the Company. The Commission and the aforementioned four parties fined have worked on a possible proposed alternative settlement in lieu of the penalties and fines whereby the named parties would be responsible for providing the Commission with assistance to monitor the aquifer, at no cost to the Commission, to aid in the Commission’s efforts to monitor water quality in the subject area. The Company and the other three parties are currently evaluating proposals that it believes would likely satisfy the Commission's request under the proposed alternative settlement but it is currently uncertain as to whether or not they will be acceptable to the Commission. Additionally, it is uncertain as to how the cost of the alternative settlement would be allocated to the named parties of the subject violations. Accordingly, the Company recorded a contingent liability of approximately $300,000 at September 30, 2020.

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. While the Company’s contract drilling segment continues to work, the impact of COVID-19 on the ability or desire for customers to continue such work is uncertain, and any discontinuation of contracts currently in backlog for any reason would result in a material adverse impact to the Company’s financial condition and outlook.

General and administrative expenses

General and administrative expenses increased $296,000 (5%) to $5,820,000 in fiscal 2020, as compared to $5,524,000 in fiscal 2019. The increase was due to increased proxy legal costs, proxy solicitation, proxy advisory, public relations costs and bad debt expense in the current year period, as compared to the same period in the prior year. The increase was partially offset by lower compensation costs in the current year period, as compared to the same period in the prior year.

Depletion, depreciation, and amortization

Depletion, depreciation, and amortization decreased $875,000 (29%) in fiscal 2020 as compared to fiscal 2019 primarily due to the decrease in oil and natural gas depletion as discussed in the “Oil and natural gas” section above.

Impairment of assets

Under the full cost method of accounting, the Company performs quarterly oil and natural gas ceiling test calculations. There was a ceiling test impairment of $4,326,000 during the year ended September 30, 2020. There was a $5,710,000 ceiling test impairment during the year ended September 30, 2019.

of the maximum carrying value of oil and natural gas properties. Prior to the quarter ended March 31, 2020, the ceiling test calculation included management’s estimation that the Company had the ability to fund all of the future capital expenditures necessary over the next five years to develop proved undeveloped reserves in the Twining area of Alberta, Canada. However, due to the impact on oil prices and the extreme uncertainties created by the COVID-19 pandemic on the Company's financial outlook, management is no longer reasonably certain that the Company will have the financial resources necessary to make any of the capital expenditures necessary to develop the proved undeveloped reserves. Therefore, the proved undeveloped reserves were excluded from the quarterly ceiling test calculations subsequent to December 31, 2019.

As discussed above, the ceiling test mandates the use of the 12-month historical rolling average first-day-of-the-month prices. If oil prices remain at current levels or decline further, it is more likely than not that the Company will incur further impairment write-downs in future periods in the absence of any offsetting factors that are not currently known or projected.

During the year ended September 30, 2020, the Company recorded a $50,000 impairment in the carrying value of its investment in leasehold land interest in Lot 4C as a result of recent uncertainty regarding the timing of future development and potential use of water rights within Lot 4C prior to the expiration of the lease term. The lease terminates in December 2025.

Gain on sale of asset

In March 2020, the Company sold its leasehold interest in a three-quarter of an acre contract drilling segment maintenance and storage yard in Honolulu, Hawaii to an unrelated third party for a $1,100,000 cash payment. As a result of the sale transaction, the Company recognized a gain of $1,336,000, inclusive of a $236,000 gain from the reversal of the storage yard's lease liability in excess of the right-of-use asset, in the year ended September 30, 2020.

Equity in income (loss) of affiliates

Barnwell’s investment in the Kukio Resort Land Development Partnerships is accounted for using the equity method of accounting. Barnwell was allocated partnership income of $352,000 in fiscal 2020, as compared to allocated losses of $276,000 in fiscal 2019. The increase in the allocated partnership income is primarily due to the Kukio Resort Land Development Partnerships' sale of two lots during the current year, whereas there was one lot sale in the prior year, and an increase in real estate resale activity in the current year as compared to the prior year period. Additionally, the increase is also attributed to a $197,000 partial payment of the preferred return from KKM, as discussed below.

Additionally, subsequent to September 30, 2020, the Kukio Resort Land Development Partnerships sold one lot in Increment I and made additional net cash distributions of $1,034,000 to the Company. Accordingly, Barnwell received additional preferred return payments of $459,000, which will be reflected in Barnwell's financial results for the quarter ending December 31, 2020. The preferred return payments received after September 30, 2020 brought the cumulative preferred return to $656,000, which is the total amount Barnwell was entitled to, and thus there is no more preferred return outstanding as of the date of this report.

During the year ended September 30, 2020, Barnwell received net cash distributions in the amount of $360,000 from the Kukio Resort Land Development Partnerships after distributing $20,000 to non-controlling interests. Of the $360,000 net cash distribution received from the Kukio Resort Land Development Partnerships, $197,000 represented a partial payment of the preferred return from KKM, as discussed above.

During the year ended September 30, 2019, Barnwell received net cash distributions in the amount of $314,000 from the Kukio Resort Land Development Partnerships after distributing $38,000 to non-controlling interest

Income taxes

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


	Year ended September 30,
	2020		2019
United States	$	1,518,000	$	(3,039,000)
Canada	(6,271,000)		(9,606,000)
	$	(4,753,000)	$	(12,645,000)

Barnwell’s effective consolidated income tax benefit rate for fiscal 2020, after adjusting loss before income taxes for non-controlling interests, was nil as compared to 2% for fiscal 2019.

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.

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, however, had not been enacted as of September 30, 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 have no significant

impact to earnings/loss as a result of a full valuation allowance being applied to Canadian deferred tax assets.

On March 27, 2020, the Coronavirus Aid, Relief, and Economic Security (“CARES”) Act was signed into law to provide economic relief to businesses that were negatively impacted by the COVID-19 pandemic. Key tax provisions of the CARES Act impacting the Company include the modification of rules related to corporate alternative minimum tax (“AMT”) credits and net operating losses (“NOLs”), as discussed further below.

The repeal of the corporate AMT by the Tax Cuts and Jobs Act of 2017 (“TCJA”) provided a mechanism for the refund over time of any unused AMT credit carryovers. Under the TCJA, 50% of the Company's total credit ($230,000 = $460,000 x 50%) was refundable effective for tax years beginning after December 31, 2017 (i.e., our fiscal 2019) and was reclassified to current taxes receivable as of September 30, 2019. The CARES Act subsequently provided for an election to take the entire refundable credit in the Company’s 2018 tax year (fiscal year 2019 return). As such, the Company reclassified the remaining 50% from non-current to current taxes receivable as of March 31, 2020 as a result of the CARES Act legislation.

The TCJA imposed an 80% limitation on the utilization of U.S. federal NOLs generated in tax years beginning after December 31, 2017, which is the Company’s fiscal 2019, however the CARES Act suspended this limitation through the 2020 tax year (the Company’s fiscal 2021). This limitation will be reinstated effective for tax years beginning on or after January 1, 2021.

Net earnings (loss) 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 $79,000 in fiscal 2020, as compared to net loss attributable to non-controlling interests of $3,000 in fiscal 2019. The $82,000 (2,733%) increase is primarily due to an increase in the amount of Kaupulehu Developments' and Kukio Resort Land Development Partnerships’ income in the current year period as compared to the same period in the prior year.

Retirement plans curtailment

In December 2019, the Company’s Board of Directors approved a resolution to freeze all future benefit accruals for all participants under the Company’s defined benefit pension plan (“Pension Plan”) and Supplemental Executive Retirement Plan (“SERP”) effective December 31, 2019. Consequently, current participants in the Pension Plan and SERP no longer accrue new benefits under the plans and new employees of the Company are no longer eligible to enter the Pension Plan and SERP as participants after December 31, 2019. The freezing of the Pension Plan and SERP triggered a curtailment which required a remeasurement of the projected benefit obligations of the Pension Plan and SERP and resulted in a $1,726,000 reduction in unrecognized pension benefit costs that were previously included in accumulated other comprehensive loss, with a corresponding curtailment gain in other comprehensive income which was recorded during the year ended September 30, 2020.

Inflation

The effect of inflation on Barnwell has generally been to increase its cost of operations, general and administrative costs and direct costs associated with oil and natural gas production and contract drilling operations. Oil and natural gas prices realized by Barnwell are essentially determined by world prices for oil and western Canadian/Midwestern U.S. prices for natural gas.

Impact of Recently Issued Accounting Standards on Future Filings

In June 2016, the 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.

In August 2018, the FASB issued ASU No. 2018-13, “Fair Value Measurement: Disclosure Framework-Changes to the Disclosure Requirements for Fair Value Measurement,” which provides changes to certain fair value disclosure requirements. This ASU is effective for annual reporting periods beginning after December 15, 2019 and interim periods within those annual periods, with early adoption permitted. The adoption of this update is not expected to have a material impact on Barnwell's consolidated financial statements.

In August 2018, the FASB issued ASU No. 2018-14, “Compensation - Retirement Benefits-Defined Benefit Plans - General: Disclosure Framework-Changes to the Disclosure Requirements for Defined Benefit Plans,” which provides changes to certain pension and postretirement plan disclosures. This ASU is effective for annual reporting periods ending after December 15, 2020, with early adoption permitted. The adoption of this update is not expected to have a material impact on Barnwell's consolidated financial statements.

In October 2018, the FASB issued ASU No. 2018-17, “Consolidation: Targeted Improvements to Related Party Guidance for Variable Interest Entities,” which modifies the guidance related to indirect interests held through related parties under common control for determining whether fees paid to decision makers and service providers are variable interest. This ASU is effective for annual reporting periods beginning after December 15, 2019 and interim periods within those annual periods, with early adoption permitted. The adoption of this update is not expected to have a material impact on Barnwell's consolidated financial statements.

In December 2019, the FASB issued 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. This ASU is effective for annual reporting periods beginning after December 15, 2020 and interim periods within those annual periods, with early adoption permitted. The adoption of this update is not expected to have a material impact on Barnwell's consolidated financial statements.

Liquidity and Capital Resources

Barnwell’s primary sources of liquidity are cash on hand, cash flow generated by operations, and land investment segment proceeds. At September 30, 2020, Barnwell had $3,123,000 in working capital.

Cash Flows

Cash flows provided by operating activities totaled $750,000 for fiscal 2020, as compared to cash flows used by operating activities of $2,133,000 for the same period in fiscal 2019. This $2,883,000 change in operating cash flows was primarily due to significantly higher operating results for the contract drilling segment as compared to the prior year period and changes in working capital, primarily attributed to fluctuations in contract liabilities in the current period as compared to the prior year period.

Net cash used in investing activities totaled $833,000 for fiscal 2020, as compared to net cash provided by investing activities of $905,000 for fiscal 2019. The $1,738,000 decrease in investing cash flows was primarily due to $741,000 in maturities of certificates of deposit in the prior fiscal year period as compared to none in the current year period, a $911,000 decrease in proceeds from the sale of oil and natural gas properties in the current period as compared to the prior year period, and an increase of $2,331,000 in cash used for oil and natural gas capital expenditures, mainly attributed to two new wells drilled in the Twining and Spirit River areas in the current period, as compared to the prior year period. These items were partially offset by an increase of $1,100,000 in proceeds in the current year period attributed to the sale of the Company's leasehold interest in a three-quarter of an acre contract drilling segment maintenance and storage yard in Honolulu, Hawaii, and a decrease of $848,000 in other capital expenditures in the current year period, primarily due to the purchase of a water well drilling rig and other ancillary equipment in the prior year period.

Cash flows provided by financing activities totaled $60,000 for fiscal 2020, as compared to cash used in financing activities of $110,000 for fiscal 2019. The $170,000 change in financing cash flows was primarily attributed to an increase of $147,000 in long-term debt borrowings attributed to the PPP loan received during the current year period. This change was partially offset by $87,000 in distributions to non-controlling interests in the current year period, whereas there was $110,000 in distributions to non-controlling interests in the prior year period.

Paycheck Protection Program Loan

On April 28, 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 CARES Act that was signed into law in March 2020. The note matures two years after the date of the loan disbursement and bears interest at a fixed annual rate of 1.00%, with the first six months of principal and interest deferred. Under the terms of the CARES Act, as amended by the Paycheck Protection Program Flexibility Act of 2020 (“Flexibility Act”), and the PPP, the Company can apply for and be granted forgiveness for all or a portion of the loan issued under the PPP and the loan is expected to be forgiven to the extent the proceeds are used in accordance with the PPP to cover payroll, mortgage interest, rent, and utility costs incurred by the Company over the 24-week period following the loan disbursement date.

principal and interest payments from six months to ten months after the last day of the covered period and if the Company does not apply for forgiveness of the loan within ten months after the last day of the covered period. As of the date of this filing, the Company is in the process of applying for forgiveness and believes that its use of the loan proceeds will meet the conditions for forgiveness under the PPP and expects the loan to be recorded as income when legal forgiveness is obtained.

Canada Emergency Wage Subsidy

During the year ended September 30, 2020, the Company’s two subsidiaries with Canadian operations, Barnwell of Canada and Octavian Oil qualified for the Canada Emergency Wage Subsidy (“CEWS”). Initially, the CEWS program provided a subsidy of 75% of eligible employee wages up to a maximum of approximately $600 per week for each employee calculated based on specified decreases in revenues. Subsequent to July 5, 2020, the CEWS program was adjusted and the subsidy amounts were reduced according to the government's revised eligibility requirements. As of the date of this report, the Company received a total of approximately $82,000 in CEWS subsidies. The CEWS is currently scheduled to run through December 19, 2020 with a commitment by the Canadian government to extend the program into 2021.

Going Concern

Prior to and during fiscal 2020 and subsequently, the Company investigated potential sources of funding, including non-core oil and natural gas property sales, however, no probable sources of such funding have yet been secured. Additionally, the Company has listed its corporate office on the 29th floor of a commercial office building in downtown Honolulu, Hawaii, for sale to generate liquidity without impacting operations significantly, in order to mitigate the substantial doubt about our ability to continue as a going concern. However, the Company’s ability to sell its corporate office at an appropriate time or for a sufficient price is outside of the Company's control and is therefore not probable. Because of this uncertainty as well as uncertainties regarding the potential duration and depth of the impacts of the COVID-19 pandemic on our business as described above, substantial doubt about our ability to continue as a going concern for one year from the date of the filing of this report exists.

NYSE American Continued Listing Standard

On January 13, 2020, the Company received a letter from the Exchange Staff indicating that the Company was not in compliance with Part 10, Sections 1003(a)(i) and (a)(ii) of the Guide since it reported stockholders’ equity of $1.2 million and net losses in fiscal years ended September 30, 2019, September 30, 2018 and September 30, 2016. The Company’s failure to meet the NYSE American’s stockholders’ equity requirements and the exceptions resulted in a risk that our common stock may be delisted.

In accordance with the NYSE American’s policies and procedures, the Company submitted its Plan addressing how the Company intended to regain compliance with Part 10, Section 1003 of the Guide. On April 2, 2020, the NYSE American notified the Company that it accepted the Company’s Plan and granted the Company an extension for its continued listing during the Plan Period. The Company has been and will continue to be subject to periodic review by Exchange Staff during the Plan Period. The Plan was submitted to the NYSE American before the start of the COVID-19 pandemic-related low commodity price environment, the oil price war between Saudi Arabia and Russia and other macroeconomic pressures that have impacted our businesses and the U.S. economy in general. The magnitude and duration of these factors have and will adversely affect the Company’s ability to achieve the Plan’s goals and to return to compliance with the NYSE American’s listing standards. If the Company does not regain compliance by the end of the Plan Period, or if the Company does not make ongoing progress consistent with its Plan, the NYSE American may initiate delisting procedures as appropriate.

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 $2,522,000 from $629,000 in fiscal 2019 to $3,151,000 in fiscal 2020.

Due to the uncertainties created by the COVID-19 pandemic, investments in oil and natural gas properties have been suspended pending suitable market opportunities and sufficient sources of funding.

Oil and Natural Gas Property Acquisitions and Dispositions

Dispositions

In October 2019, Barnwell entered into a purchase and sale agreement with an independent third party and sold its interests in properties located in the Progress area of Alberta, Canada. The sales price per the agreement was adjusted for customary purchase price adjustments to $594,000 in order to, among other things, reflect an economic effective date of October 1, 2019. 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.

There were no oil and natural gas property dispositions during the year ended September 30, 2019. The $1,519,000 of proceeds from sale of oil and natural gas properties included in the Consolidated Statement of Cash Flows for the year ended September 30, 2019 primarily represents the refund of income taxes previously withheld from what otherwise would have been proceeds on prior years' oil and natural gas property sales.

Acquisitions

There were no significant amounts paid for oil and natural gas property acquisitions during the year ended September 30, 2020.

In the quarter ended December 31, 2018, Barnwell acquired additional working interests in oil and natural gas properties located in the Wood River and Twining areas of Alberta, Canada for cash consideration of $355,000. The purchase prices per the agreements were adjusted for customary purchase price adjustments to reflect the economic activity from the effective date to the closing date. The customary adjustments to the purchase prices were finalized in the quarter ended June 30, 2019 and resulted in an immaterial adjustment. There were no other oil and natural gas working interest acquisitions during the year ended September 30, 2019.

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. The estimated asset retirement obligation for the Company's wells and facilities in the Manyberries area is included in “Asset retirement obligation” in the Consolidated Balance Sheets. Many 100% LGX owned wells are to be reclaimed by the OWA. However, as next largest interest holder in 78 of the wells and 6 facilities formerly operated by LGX, averaging 11%, the Company is required to take care and custody of those properties and to coordinate their closure.

On November 5, 2019, in response to the AER order, the Company submitted its proposed plan to abandon the Manyberries wells and facilities in an orderly fashion over a ten-year period. This area has unique access issues as a result of an Emergency Protection Order, under the Canadian Government’s Species at Risk Act, to protect the Sage Grouse. Access is limited to a window of mid-September to the end of November each year.

involves removal and salvage of the surface equipment; these costs are estimated to be minimal due in part to the salvage value of the equipment. Beyond fiscal 2021, the Company proposes to perform seven to ten well abandonments per year over an estimated ten-year period as well as abandon the facilities in that time period. Annual gross costs estimated to be incurred currently are approximately $500,000, approximately $55,000 net to the Company, however, the Company expects it will have to pay the gross costs and then recover from the other working interest owners and the OWA their costs, such that there will be a period between Barnwell having to pay the gross costs and getting reimbursed for the other parties’ portions.

As an alternative to the above plan, the Company is in discussions to allow the OWA to perform well abandonments and reclamations on the company’s behalf. This would eliminate the need for Barnwell to carry LGX’s average 85% portion of Barnwell interest in wells in Manyberries. Barnwell would also benefit from the OWA’s extensive experience and scale of operations in this area. This could allow Barnwell to accelerate closure of the Manyberries area to a 4-year period (fiscal 2022-2025) from the above ten-year plan, and it is estimated that this plan would increase Barnwell’s net expenditures to approximately $150,000 annually, with some minor costs likely extending into fiscal 2026.

Over the past five years, the Company has diligently worked to reduce its ARO associated with its oil and natural gas segment, both by divesting low-productivity assets and actively closing wells and sites. Fifteen Barnwell operated sites have been certified as fully reclaimed or exempt since 2016. To aid in this regard, and as a stimulus response to the COVID-19 pandemic, the Canadian Federal Government has funded the 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 $200,000 in net funding to date, to be directed to ARO reduction activities. Barnwell has further benefited from grants allocated to its non-operated property partners, with a further $75,000 in activities approved to date.

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.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Report of Independent Registered Public Accounting Firm

To the Stockholders and Board of Directors

Barnwell Industries, Inc.

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheet of Barnwell Industries, Inc. and subsidiaries (the Company) as of September 30, 2020, and the related consolidated statement of operations, comprehensive loss, equity, and cash flows for the year then ended, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of September 30, 2020, and the results of its operations and its cash flows for the year then ended, in conformity with accounting principles generally accepted in the United States of America.

Going Concern

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 2 to the consolidated financial statements, the Company has suffered recurring losses from operations and has a net capital deficiency. These conditions raise substantial doubt about its ability to continue as a going concern. Management’s plans in regard to these matters are also described in Note 2. The consolidated financial statements do not include any adjustments that might results from the outcome of this uncertainty.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audit. 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 consolidated 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 audit 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 Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audit included performing procedures to assess the risks of material misstatement of the consolidated 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 consolidated financial statements. Our audit also included evaluating the accounting principles used

and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audit provides a reasonable basis for our opinion.

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

We have served as the Company's auditor since 2020.

Dallas, Texas

December 16, 2020

Report of Independent Registered Public Accounting Firm

To the Stockholders and Board of Directors

Barnwell Industries, Inc.:

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheet of Barnwell Industries, Inc. and subsidiaries (the Company) as of September 30, 2019, the related consolidated statements of operations, comprehensive loss, equity, and cash flows for the year ended September 30, 2019 and the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of September 30, 2019, and the results of its operations and its cash flows for the year ended September 30, 2019, in conformity with U.S. generally accepted accounting principles.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audit. 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 audit 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 consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audit included performing procedures to assess the risks of material misstatement of the consolidated 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 consolidated financial statements. Our audit also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audit provides a reasonable basis for our opinion.

/s/ KPMG LLP

We served as the Company’s auditor from 1990 to 2020.

Honolulu, Hawaii

December 20, 2019

BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS


	September 30,
	2020		2019
ASSETS
Current assets:
Cash and cash equivalents	$	4,584,000	$	4,613,000


Accounts and other receivables, net of allowance for doubtful accounts of: $341,000 at September 30, 2020; $44,000 at September 30, 2019	2,176,000		1,884,000
Income taxes receivable	472,000		386,000
Asset held for sale	699,000		—

Other current assets	1,556,000		1,821,000
Total current assets	9,487,000		8,704,000
Income taxes receivable, net of current portion	—		230,000

Asset for retirement benefits	771,000		—
Investments	901,000		980,000
Operating lease right-of-use assets	249,000		—
Property and equipment, net	3,774,000		8,388,000
Total assets	$	15,182,000	$	18,302,000
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	2,104,000	$	1,223,000
Accrued capital expenditures	542,000		287,000
Accrued compensation	408,000		205,000
Accrued operating and other expenses	1,325,000		1,079,000
Current portion of operating lease liabilities	111,000		—
Current portion of asset retirement obligation	647,000		330,000
Other current liabilities	1,227,000		1,644,000
Total current liabilities	6,364,000		4,768,000
Deferred rent	—		193,000
Long-term debt	58,000		—
Operating lease liabilities	143,000		—
Liability for retirement benefits	4,829,000		5,785,000
Asset retirement obligation	5,547,000		6,059,000
Deferred income tax liabilities	194,000		168,000
Total liabilities	17,135,000		16,973,000
Commitments and contingencies (Note 17)
Equity:
Common stock, par value $0.50 per share; authorized, 20,000,000 shares:
8,445,060 issued at September 30, 2020 and 2019	4,223,000		4,223,000
Additional paid-in capital	1,350,000		1,350,000
(Accumulated deficit) retained earnings	(3,897,000)		859,000
Accumulated other comprehensive loss, net	(1,435,000)		(2,917,000)
Treasury stock, at cost:
167,900 shares at September 30, 2020 and 2019	(2,286,000)		(2,286,000)
Total stockholders’ (deficit) equity	(2,045,000)		1,229,000
Non-controlling interests	92,000		100,000
Total (deficit) equity	(1,953,000)		1,329,000
Total liabilities and equity	$	15,182,000	$	18,302,000

See Notes to Consolidated Financial Statements

BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS


	Year ended September 30,
	2020		2019
Revenues:
Oil and natural gas	$	6,693,000	$	6,406,000
Contract drilling	10,994,000		5,349,000
Sale of interest in leasehold land	325,000		165,000

Gas processing and other	335,000		155,000
	18,347,000		12,075,000
Costs and expenses:
Oil and natural gas operating	4,850,000		5,213,000
Contract drilling operating	7,513,000		4,973,000

General and administrative	5,820,000		5,524,000
Depletion, depreciation, and amortization	2,147,000		3,022,000
Impairment of assets	4,376,000		5,710,000
Interest expense	3,000		5,000
Gain on sale of asset	(1,336,000)		—
	23,373,000		24,447,000
Loss before equity in income (loss) of affiliates and income taxes	(5,026,000)		(12,372,000)

Equity in income (loss) of affiliates	352,000		(276,000)
Loss before income taxes	(4,674,000)		(12,648,000)
Income tax provision (benefit)	3,000		(231,000)
Net loss	(4,677,000)		(12,417,000)
Less: Net earnings (loss) attributable to non-controlling interests	79,000		(3,000)
Net loss attributable to Barnwell Industries, Inc. stockholders	$	(4,756,000)	$	(12,414,000)
Basic net loss per common share
attributable to Barnwell Industries, Inc. stockholders	$	(0.57)	$	(1.50)
Diluted net loss per common share
attributable to Barnwell Industries, Inc. stockholders	$	(0.57)	$	(1.50)
Weighted-average number of common shares outstanding:
Basic	8,277,160		8,277,160
Diluted	8,277,160		8,277,160

See Notes to Consolidated Financial Statements

BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS


	Year ended September 30,
	2020		2019
Net loss	$	(4,677,000)	$	(12,417,000)
Other comprehensive income (loss):
Foreign currency translation adjustments, net of taxes of $0	(146,000)		(234,000)
Retirement plans:
Amortization of accumulated other comprehensive loss into net periodic benefit cost, net of taxes of $0	120,000		55,000
Net actuarial loss arising during the period, net of taxes of $0	(218,000)		(2,224,000)
Curtailment gain, net of taxes of $0	1,726,000		—
Total other comprehensive income (loss)	1,482,000		(2,403,000)
Total comprehensive loss	(3,195,000)		(14,820,000)
Less: Comprehensive income (loss) attributable to non-controlling interests	79,000		(3,000)
Comprehensive loss attributable to Barnwell Industries, Inc.	$	(3,274,000)	$	(14,817,000)

See Notes to Consolidated Financial Statements

BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF EQUITY (DEFICIT)

Years ended September 30, 2020 and 2019


	Shares Outstanding	Common Stock		Additional Paid-In Capital		Retained Earnings (Accumulated Deficit)		Accumulated Other Comprehensive Loss		Treasury Stock		Non-controlling Interests		Total Equity (Deficit)
Balance at September 30, 2018	8,277,160	$	4,223,000	$	1,350,000	$	13,253,000	$	(514,000)	$	(2,286,000)	$	213,000	$	16,239,000

Cumulative impact from the adoption of ASU No. 2014-09	—	—		—		20,000		—		—		—		20,000
Distributions to non-controlling interests	—	—		—		—		—		—		(110,000)		(110,000)
Net loss	—	—		—		(12,414,000)		—		—		(3,000)		(12,417,000)

Foreign currency translation adjustments, net of taxes of $0	—	—		—		—		(234,000)		—		—		(234,000)
Retirement plans:
Amortization of accumulated other comprehensive loss into net periodic benefit cost, net of taxes of $0	—	—		—		—		55,000		—		—		55,000
Net actuarial loss arising during the period, net of taxes of $0	—	—		—		—		(2,224,000)		—		—		(2,224,000)
Balance at September 30, 2019	8,277,160	4,223,000		1,350,000		859,000		(2,917,000)		(2,286,000)		100,000		1,329,000


Distributions to non-controlling interests	—	—		—		—		—		—		(87,000)		(87,000)
Net (loss) earnings	—	—		—		(4,756,000)		—		—		79,000		(4,677,000)

Foreign currency translation adjustments, net of taxes of $0	—	—		—		—		(146,000)		—		—		(146,000)
Retirement plans:
Amortization of accumulated other comprehensive loss into net periodic benefit cost, net of taxes of $0	—	—		—		—		120,000		—		—		120,000
Net actuarial loss arising during the period, net of taxes of $0	—	—		—		—		(218,000)		—		—		(218,000)
Curtailment gain, net of taxes of $0	—	—		—		—		1,726,000		—		—		1,726,000
Balance at September 30, 2020	8,277,160	$	4,223,000	$	1,350,000	$	(3,897,000)	$	(1,435,000)	$	(2,286,000)	$	92,000	$	(1,953,000)

See Notes to Consolidated Financial Statements

BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS


	Year ended September 30,
	2020		2019
Cash flows from operating activities:
Net loss	$	(4,677,000)	$	(12,417,000)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Equity in (income) loss of affiliates	(352,000)		276,000
Depletion, depreciation, and amortization	2,147,000		3,022,000
Impairment of assets	4,376,000		5,710,000

Gain on sale of asset	(1,336,000)		—
Sale of interest in leasehold land, net of fees paid	(285,000)		(124,000)
Distributions of income from equity investees	75,000		—
Retirement benefits (income) expense	(60,000)		177,000
Income tax receivable, noncurrent	—		(31,000)
Accretion of asset retirement obligation	561,000		608,000
Deferred income tax expense (benefit)	26,000		(144,000)
Asset retirement obligation payments	(498,000)		(372,000)
Share-based compensation benefit	—		(42,000)
Non-cash rent expense	48,000		86,000
Retirement plan contributions and payments	(8,000)		(124,000)

Bad debt expense	285,000		—
Increase from changes in current assets and liabilities	448,000		1,242,000
Net cash provided by (used in) operating activities	750,000		(2,133,000)
Cash flows from investing activities:

Proceeds from the maturity of certificates of deposit	—		741,000

Distributions from equity investees in excess of earnings	305,000		352,000
Proceeds from sale of interest in leasehold land, net of fees paid	285,000		124,000
Proceeds from sale of oil and natural gas assets	608,000		1,519,000
Proceeds from final acquisition purchase price adjustments	—		172,000

Proceeds from the sale of asset	1,100,000		—
Payments to acquire oil and natural gas properties	—		(355,000)
Capital expenditures - oil and natural gas	(2,716,000)		(385,000)
Capital expenditures - all other	(415,000)		(1,263,000)
Issuance of note receivable	—		(300,000)
Proceeds from repayment of note receivable	—		300,000
Net cash (used in) provided by investing activities	(833,000)		905,000
Cash flows from financing activities:



Borrowings on long-term debt	147,000		—
Distributions to non-controlling interests	(87,000)		(110,000)
Net cash provided by (used in) financing activities	60,000		(110,000)
Effect of exchange rate changes on cash and cash equivalents	(6,000)		(14,000)
Net decrease in cash and cash equivalents	(29,000)		(1,352,000)
Cash and cash equivalents at beginning of year	4,613,000		5,965,000
Cash and cash equivalents at end of year	$	4,584,000	$	4,613,000

See Notes to Consolidated Financial Statements

BARNWELL INDUSTRIES, INC.

AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED SEPTEMBER 30, 2020 AND 2019

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, 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) and a 75%-owned land investment partnership (KD Kona). All significant intercompany accounts and transactions have been eliminated.

Undivided interests in oil and natural gas exploration and production joint ventures are consolidated on a proportionate basis. Barnwell’s investments in both unconsolidated entities in which a significant, but less than controlling, interest is held and in VIEs in which the Company is not deemed to be the primary beneficiary are accounted for by the equity method.

Use of Estimates in the Preparation of Consolidated Financial Statements

The preparation of the consolidated financial statements in conformity with U.S. GAAP requires management of Barnwell to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Actual results could differ significantly from those estimates. Significant assumptions are required in the valuation of deferred tax assets, asset retirement obligations, 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.

Revenue Recognition

Barnwell operates in and derives revenue from the following three principal business segments:

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

•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. These property interests are principally held under governmental leases or licenses. Barnwell sells the large majority of its oil, natural gas and natural gas liquids production under short-term contracts between itself and marketers based on prices indexed to market prices and recognizes revenue at a point in time when the oil, natural gas and natural gas liquids are delivered, as this is where Barnwell’s performance obligation is satisfied and title has passed to the customer.

Land Investment - Barnwell is entitled to receive contingent residual payments from the entities that previously purchased Barnwell’s land investment interests under contracts entered into in prior years. The residual payments under those contracts become due when the entities sell lots and/or residential units in the areas that were previously sold under the aforementioned contracts or when a preferred payment threshold is achieved. The residual payments received by Barnwell are recognized as revenue when it is probable that a significant reversal in the amount of cumulative revenue recognized will not occur.

Contract Drilling - Through contracts which are normally less than twelve months in duration, Barnwell drills water and water monitoring wells and installs and repairs water pumping systems in Hawaii. Barnwell recognizes revenue from well drilling or the installation of pumps over time based on total costs incurred on the projects relative to the total expected costs to satisfy the performance obligation as management believes this is an accurate representation of the percentage of completion as control is continuously transferred to the customer. Uninstalled materials, which typically consists of well casing or pumps, are excluded in the costs-to-costs calculation for the duration of the contract as including these costs would result in a distortion of progress towards satisfaction of the performance obligation due to the resulting cumulative catch-up in margin in a single period. An equal amount of cost and revenue is recorded when uninstalled materials are controlled by the customer, which is typically when Barnwell has the right to payment for the materials and when the materials are delivered to the customer’s site or location and such materials have been accepted by the customer. Uninstalled materials are held in inventory and included in “Other current assets” on the Company’s Consolidated Balance Sheets until control is transferred to the customer. When the estimate on a contract indicates a loss, Barnwell records the entire estimated loss in the period the loss becomes known.

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

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

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.

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.

Equity Method Investments

Affiliated companies, which are limited partnerships or similar entities, in which Barnwell holds more than a 3% to 5% ownership interest and does not control, are accounted for as equity method investments. Equity method investment adjustments include Barnwell’s proportionate share of investee income or loss, adjustments to recognize certain differences between Barnwell’s carrying value and Barnwell’s equity in net assets of the investee at the date of investment, impairments and other adjustments required by the equity method. Gains or losses are realized when such investments are sold.

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.

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 primary beneficiary, may require significant judgment.

Barnwell analyzes its unconsolidated affiliates in which it has an investment to determine whether the unconsolidated entities are VIEs and, if so, whether the Company is the primary beneficiary. This analysis includes a qualitative review based on an evaluation of the design of the entity, its organizational structure, including decision making ability and financial agreements, as well as a quantitative review. Our unconsolidated affiliates that have been determined to be VIEs are accounted under the equity method

because we do not have a controlling financial interest and are therefore not the VIE’s primary beneficiary (see Note 6).

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.

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.

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. 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 current and 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 postretirement medical insurance benefits plan by recognizing the over-funded or under-funded status as an asset or liability in its Consolidated Balance Sheets and recognizes changes in that funded status in the year in which the changes occur through comprehensive income. See further discussion at Note 9.

The estimation of Barnwell’s retirement plan obligations, costs and liabilities requires management to estimate the amount and timing of cash outflows for projected future payments and cash inflows for maturities and expected returns on plan assets. These assumptions may have an effect on the amount and timing of future contributions.

At the end of each year, Barnwell determines the discount rate to be used to calculate the present value of plan liabilities and the net periodic benefit cost. The discount rate is an estimate of the current interest rate at which the retirement plan liabilities could be effectively settled at the end of the year. In estimating this rate, Barnwell performs a cash-flow matching discount rate analysis developed using high-quality corporate bonds yield. The discount rate used to value the future benefit obligation as of each year-end is the rate used to determine the periodic benefit cost in the following year.

The expected long-term return on assets assumption for the pension plans represents the average rate of return to be earned on plan assets over the period the benefits included in the benefit obligation are to be paid. The actual fair value of plan assets and estimated rate of return is used to determine the expected investment return during the year. The estimated rate of return on plan assets is based on an

estimate of future experience for plan asset returns, the mix of plan assets, current market conditions, and expectations for future market conditions. A decrease (increase) of 50 basis points in the expected return on assets assumption would increase (decrease) pension expense by approximately $55,000 based on the assets of the plan at September 30, 2020.

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

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 Translation

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 loss, net” in stockholders’ equity.

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 February 2016, the FASB issued ASU No. 2016-02, “Leases (Topic 842),” which requires an entity to recognize a right-of-use asset and a lease liability on the balance sheet for all leases with terms greater than 12 months at the lease commencement date. The Company adopted the provisions of this ASU effective October 1, 2019. See Note 16 “Leases and Gain on Sale of Asset.”

In February 2018, the FASB issued ASU No. 2018-02, “Reclassification of Certain Tax Effects From Accumulated Other Comprehensive Income,” which allows a reclassification from accumulated

other comprehensive income to retained earnings for stranded tax effects resulting from the Tax Cuts and Jobs Act of 2017. The Company adopted the provisions of this ASU effective October 1, 2019. The adoption of this update did not have an impact on Barnwell's consolidated financial statements.

In July 2018, the FASB issued ASU No. 2018-09, “Codification Improvements,” which provides further clarification to the codification literature. The Company adopted the provisions of this ASU effective October 1, 2019. The adoption of this update did not have an impact on Barnwell's consolidated financial statements.

Impact of COVID-19

2. GOING CONCERN

The accompanying consolidated financial statements have been prepared on a going concern basis, which contemplates the realization of assets and satisfaction of liabilities in the normal course of business for the twelve-month period following the date of issuance of these consolidated financial statements.

outflows such as oil and natural gas asset retirement obligations and ongoing operating and general and administrative expenses.

Prior to and during fiscal 2020 and subsequently, the Company investigated potential sources of funding, including non-core oil and natural gas property sales, however, no probable sources of such funding have yet been secured. Additionally, the Company has listed its corporate office on the 29th floor of a commercial office building in downtown Honolulu, Hawaii, for sale to generate liquidity in order to help mitigate the substantial doubt about our ability to continue as a going concern. However, the Company’s ability to sell its corporate office at an appropriate time or for a sufficient price is outside of the Company's control and is therefore not probable. Because of this uncertainty as well as uncertainties regarding the potential duration and depth of the impacts of the COVID-19 pandemic on our business as described above, substantial doubt about our ability to continue as a going concern for one year from the date of the filing of this report exists. These financial statements do not include any adjustments that might result from the outcome of these uncertainties.

3. LOSS PER COMMON SHARE

Basic loss per share is computed using the weighted-average number of common shares outstanding for the period. Diluted loss per share is calculated using the treasury stock method to reflect the assumed issuance of common shares for all potentially dilutive securities, which consist of outstanding stock options. Potentially dilutive shares are excluded from the computation of diluted loss per share if their effect is anti-dilutive.

There were no options outstanding at September 30, 2020. Options to purchase 318,750 shares of common stock was excluded from the computation of diluted shares for the year ended September 30, 2019, as their inclusion would have been antidilutive.

Reconciliations between net loss attributable to Barnwell stockholders and common shares outstanding of the basic and diluted net loss per share computations are detailed in the following tables:


	Year ended September 30, 2020
	Net Loss		Shares	Per-Share
	(Numerator)		(Denominator)	Amount
Basic net loss per share	$	(4,756,000)	8,277,160	$	(0.57)
Effect of dilutive securities - common stock options	—		—
Diluted net loss per share	$	(4,756,000)	8,277,160	$	(0.57)

	Year ended September 30, 2019
	Net Loss		Shares	Per-Share
	(Numerator)		(Denominator)	Amount
Basic net loss per share	$	(12,414,000)	8,277,160	$	(1.50)
Effect of dilutive securities - common stock options	—		—
Diluted net loss per share	$	(12,414,000)	8,277,160	$	(1.50)

4. SHARE-BASED PAYMENTS

The Company’s share-based compensation benefit and related income tax effects are as follows:


	Year ended September 30,
	2020		2019
Share-based benefit	$	—	$	(42,000)
Income tax effect	$	—	$	—

There was no share-based compensation expense or benefit recognized for the year ended September 30, 2020. The share-based compensation benefit recognized for the year ended September 30, 2019 is reflected in “General and administrative” expenses in the Consolidated Statements of Operations. There was no impact on income taxes for the years ended September 30, 2020 and 2019 due to a full valuation allowance on the related deferred tax asset. As of September 30, 2020, there was no unrecognized compensation cost related to non-vested share options.

Description of Share-Based Payment Arrangements

The Company’s stock option plans are administered by the Compensation Committee of the Board of Directors.

2008 Equity Incentive Plan: Under the stockholder-approved 2008 Stock Option Plan (the "2008 Plan"), Barnwell was authorized to grant up to 800,000 shares of common stock to employees. A total of 737,500 share options were granted under this plan; as the 2008 Plan previously reached its tenth anniversary, option shares are no longer available for grant. Stock options grants included nonqualified stock options that had exercise prices equal to Barnwell’s stock price on the date of grant, vested annually over a service period of four years commencing one year from the date of grant and expired ten years from the date of grant. Certain options had stock appreciation rights that permitted the holder to receive stock, cash or a combination thereof equal to the amount by which the fair market value, at the time of exercise of the option, exceeded the option price. All of the outstanding share options under the plan expired

unexercised during the year ended September 30, 2020.

2018 Equity Incentive Plan: 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. 800,000 shares of Barnwell common stock have been reserved for issuance and as of September 30, 2020, a total of 800,000 share options remain available for grant as no options have yet been issued under this plan.

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

Equity-classified Awards

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.

A summary of the activity in Barnwell’s equity-classified share options from October 1, 2019 through September 30, 2020 is presented below:


Options	Shares	Weighted- Average Exercise Price		Weighted- Average Remaining Contractual Term	Aggregate Intrinsic Value
Outstanding at October 1, 2019	30,000	$	3.01
Granted	—	—
Exercised	—	—
Expired/Forfeited	(30,000)	3.01
Outstanding at September 30, 2020	—	$	—	—	$	—
Exercisable at September 30, 2020	—	$	—	—	$	—

There was no shared-based compensation expense for equity-classified awards vested in the years ended September 30, 2020 and 2019.

Liability-classified Awards

Compensation cost for liability-classified awards is remeasured to current fair value using a closed-form valuation model based on current values at each period end with the change in fair value recognized as an expense or benefit until the award is settled.

The following assumptions were used in estimating fair value for all liability-classified share options outstanding:


	Year ended September 30,
	2020	2019
Expected volatility range	—	87.8% to 91.1%
Weighted-average volatility	—	90.8%
Expected dividends	—	None
Expected term (in years)	—	0.2 to 0.5
Risk-free interest rate	—	1.8% to 1.9%
Expected forfeitures	—	None

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 Consolidated Statements of Operations.

A summary of the activity in Barnwell’s liability-classified share options from October 1, 2019 through September 30, 2020 is presented below:


Options	Shares	Weighted- Average Exercise Price		Weighted- Average Remaining Contractual Term	Aggregate Intrinsic Value
Outstanding at October 1, 2019	288,750	$	4.18
Granted	—	—
Exercised	—	—
Expired/Forfeited	(288,750)	4.18
Outstanding at September 30, 2020	—	$	—	—	$	—
Exercisable at September 30, 2020	—	$	—	—	$	—

The following table summarizes the components of the total share-based compensation for liability-classified awards:


	Year ended September 30,
	2020		2019
Due to vesting	$	—	$	—
Due to remeasurement	—		(42,000)
Total share-based compensation benefit for liability-based awards	$	—	$	(42,000)

5. ASSET HELD FOR SALE

In August 2020, the Company listed its Honolulu corporate office for sale. Accordingly, the Company has designated this property as an asset held for sale and recorded the carrying value of this property in the aggregate amount of $699,000 as “Asset held for sale” on the Company's Consolidated Balance Sheet at September 30, 2020.

6. INVESTMENTS

A summary of Barnwell’s non-current investments is as follows:


	September 30,
	2020		2019
Investment in Kukio Resort Land Development Partnerships	$	901,000	$	930,000
Investment in leasehold land interest – Lot 4C	—		50,000
Total non-current investments	$	901,000	$	980,000

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 are accounted for using the equity method of accounting. The partnerships derive income from the sale of residential parcels as well as from commissions on real estate sales by the real estate sales office.

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. Effective March 7, 2019, KDK and Replay hold ownership interests of 55% and 45%, respectively, of KD II. Accordingly, Barnwell has a 10.8% indirect non-controlling ownership interest in KD II through KDK as of that date that will continue to be accounted for using the equity method of accounting. 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. Additionally, Barnwell is 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 have reached the $45,000,000 threshold and in August 2020, the Kukio Resort Land Development Partnerships made distributions in excess of the threshold out of the proceeds from the sale of two lots in Increment I in that month. Accordingly, Barnwell received a $197,000 partial payment of the preferred return in August 2020, which is reflected as an additional equity pickup in the "Equity in income (loss) of affiliates" line item on the accompanying Consolidated Statement of Operations for the year ended September 30, 2020. Additionally, subsequent to September 30, 2020, the Kukio Resort Land Development Partnerships sold one lot in Increment I and made additional net cash distributions of $1,034,000 to the Company. Accordingly, Barnwell received additional preferred return payments of $459,000, which will be reflected in Barnwell's financial results for the quarter ending December 31, 2020. The preferred return payments received after September 30, 2020 brought the cumulative preferred return total to $656,000, which is the total amount Barnwell was entitled to, and thus there is no more preferred return outstanding as of the date of this report.

Barnwell's share of the operating results of its equity affiliates was income of $352,000 for the year ended September 30, 2020, which includes the $197,000 partial payment of the preferred return from KKM discussed above, as compared to a loss of $276,000 for the year ended September 30, 2019. The equity in the underlying net assets of the Kukio Resort Land Development Partnerships exceeds the carrying value of the investment in affiliates by approximately $284,000 as of September 30, 2020, which is attributable to differences in the value of capitalized development costs and a note receivable. The basis difference will be recognized as the partnerships sell lots and recognize the associated costs and sell memberships for the Kuki`o Golf and Beach Club for which the receivable relates. The basis difference adjustments of $13,000 and $18,000, for the years ended September 30, 2020 and 2019, respectively, increased equity in income of affiliates.

Summarized financial information for the Kukio Resort Land Development Partnerships is as follows:


	Year ended September 30,
	2020		2019
Revenue	$	7,911,000	$	7,507,000
Gross profit	$	4,071,000	$	3,157,000
Net earnings (loss)	$	618,000	$	(1,095,000)

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 the following percentages of the gross receipts from KD I’s sales of single-family residential lots in Increment I: 10% of such aggregate gross proceeds greater than $100,000,000 up to $300,000,000; and 14% of such aggregate gross proceeds in excess of $300,000,000. In fiscal 2020, two single-family lots in Increment I were sold bringing the total amount of gross proceeds from single-family lot sales through September 30, 2020 to $219,700,000. As of the date of this report, with the inclusion of the November 2020 lot sale mentioned above, 16 single-family lots, of the 80 lots developed within Increment I, remained to be sold.

Under the terms of the former Increment II agreement with KD II, Kaupulehu Developments was entitled to receive payments from KD II resulting from the sale of lots and/or residential units by KD II within Increment II. Through March 6, 2019, the payments were based on a percentage of gross receipts

from KD II's sales ranging from 8% to 10% of the price of improved or unimproved lots or 2.60% to 3.25% of the price of units constructed on a lot, to be determined in the future depending upon a number of variables, including whether the lots are sold prior to improvement. 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.

Through March 6, 2019, Kaupulehu Developments was also entitled to receive 50% of distributions otherwise payable from KD II to its members after the members of KD II have received distributions equal to the original basis of capital invested in the project, up to $8,000,000. Through March 6, 2019, a cumulative total of $3,500,000 was received from KD II under this arrangement, out of the $8,000,000 maximum. The former arrangement also included the rights to three single-family residential lots in Phase 2 of Increment II when developed, at no cost to Barnwell, with a commitment by Barnwell to begin to construct a residence upon each lot within six months of transfer.

Concurrent with the transaction whereby KD II admitted Replay as a new development partner, Kaupulehu Developments entered into new agreements with KD II whereby the aforementioned terms of the former Increment II arrangement were eliminated and Kaupulehu Developments will instead be entitled to 15% of the 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 will not have any partnership interests in KD II or KDK through its interest in Kaupulehu Developments. The new arrangement also gives Barnwell rights to three single-family residential lots in Phase 2A of Increment II, and four single-family residential lots in phases subsequent to Phase 2A when such lots are developed by KD II, all at no cost to Barnwell. Barnwell is committed to commence construction of improvements within 90 days of the transfer of the four lots in the phases subsequent to Phase 2A as a condition of the transfer of such lots. Also, in addition to Barnwell’s existing obligations to pay professional fees to certain parties based on percentages of its gross receipts, Kaupulehu Developments is now also obligated to pay an amount equal to 0.72% and 0.20% of the cumulative net profits of KD II to KD Development, LLC and a pool of various individuals, respectively, all of whom are partners of KKM and are unrelated to Barnwell, in compensation for the agreement of these parties to admit the new development partner for Increment II. Such compensation will be reflected as the obligation becomes probable and the amount of the obligation can be reasonably estimated. The new agreements also specify that Kaupulehu Developments was to be paid $1,000,000 by KD II prior to admission of Replay as a partner. This $1,000,000 payment had already been received in June 2018 and is included in the $3,500,000 cumulative total as of March 6, 2019 discussed above.

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

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


	Year ended September 30,
	2020		2019
Sale of interest in leasehold land:
Revenues - sale of interest in leasehold land	$	325,000	$	165,000
Fees - included in general and administrative expenses	(40,000)		(20,000)
Sale of interest in leasehold land, net of fees paid	$	285,000	$	145,000

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. Due to recent uncertainty regarding the timing of future development and potential use of water rights within Lot 4C prior to the expiration of the lease term, management determined there was an impairment in the carrying value of Lot 4C and the Company recorded a $50,000 write-off in its investment in leasehold land interest in Lot 4C, which is included in “Impairment of assets” in the accompanying Consolidated Statements of Operations for the year ended September 30, 2020.

7. OIL AND NATURAL GAS PROPERTIES

Dispositions

Acquisitions

There were no significant amounts paid for oil and natural gas property acquisitions during the year ended September 30, 2020.

Impairment of Oil and Natural Gas Properties

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. Prior to the quarter ended March 31, 2020, the ceiling test calculation included management’s estimation that the Company had the ability to fund all of the future capital expenditures necessary over the next five years to develop proved undeveloped reserves in the Twining area of Alberta, Canada. However, due to the impact on oil prices and the extreme uncertainties created by the COVID-19 pandemic on the Company's financial outlook, management is no longer reasonably certain that the Company will have the financial resources necessary to make any of the capital expenditures necessary to develop the proved undeveloped reserves. Therefore, the proved undeveloped reserves were excluded from the quarterly ceiling test calculations subsequent to December 31, 2019.

8. PROPERTY AND EQUIPMENT AND ASSET RETIREMENT OBLIGATION

Barnwell’s property and equipment is detailed as follows:


	Estimated Useful Lives	Gross Property and Equipment		Accumulated Depletion, Depreciation, Amortization, and Impairment		Net Property and Equipment
At September 30, 2020:
Land		$	—	$	—	$	—
Oil and natural gas properties
(full cost accounting)		64,142,000		(61,839,000)		2,303,000
Drilling rigs and equipment	3 – 10 years	8,244,000		(6,793,000)		1,451,000

Other property and equipment	3 – 17 years	1,045,000		(1,025,000)		20,000
Total		$	73,431,000	$	(69,657,000)	$	3,774,000


	Estimated Useful Lives	Gross Property and Equipment		Accumulated Depletion, Depreciation, Amortization, and Impairment		Net Property and Equipment
At September 30, 2019:
Land		$	200,000	$	—	$	200,000
Oil and natural gas properties
(full cost accounting)		62,205,000		(55,972,000)		6,233,000
Drilling rigs and equipment	3 – 10 years	7,882,000		(6,484,000)		1,398,000
Office	40 years	857,000		(338,000)		519,000
Other property and equipment	3 – 17 years	1,378,000		(1,340,000)		38,000
Total		$	72,522,000	$	(64,134,000)	$	8,388,000

See Note 7 for discussion of acquisitions and divestitures of oil and natural gas properties in fiscal 2020 and 2019.

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


	Year ended September 30,
	2020		2019
Asset retirement obligation as of beginning of year	$	6,389,000	$	7,122,000
Obligations incurred on new wells drilled or acquired	227,000		203,000
Liabilities associated with properties sold	(169,000)		(43,000)
Revision of estimated obligation	(279,000)		(958,000)
Accretion expense	561,000		608,000
Payments	(498,000)		(372,000)
Foreign currency translation adjustment	(37,000)		(171,000)
Asset retirement obligation as of end of year	6,194,000		6,389,000
Less current portion	(647,000)		(330,000)
Asset retirement obligation, long-term	$	5,547,000	$	6,059,000

Asset retirement obligations were reduced by $169,000 and $43,000, in fiscal 2020 and 2019, respectively, for those obligations that were assumed by purchasers of Barnwell's oil and natural gas properties. Asset retirement obligations were also reduced by $279,000 and $958,000 in fiscal 2020 and 2019, respectively, due to downward revisions related to deferrals in the estimated timing of future abandonments as a result of changes in the estimated funds available to develop the Company's reserves in the Twining area. Asset retirement obligations increased by $227,000 and $203,000 in fiscal 2020 and 2019, respectively, due primarily to our acquisitions (see Note 7 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%.

9. RETIREMENT PLANS

Barnwell sponsors a noncontributory defined benefit pension plan (“Pension Plan”) covering substantially all of its U.S. employees, with benefits based on years of service and the employee’s highest consecutive 5 years average earnings. Barnwell’s funding policy is intended to provide for both benefits attributed to service to date and for those expected to be earned in the future. In addition, Barnwell sponsors a Supplemental Executive Retirement Plan (“SERP”), a noncontributory supplemental retirement benefit plan which covers certain current and former employees of Barnwell for amounts exceeding the limits allowed under the Pension Plan, and a postretirement medical insurance benefits plan (“Postretirement 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 December 2019, the Company’s Board of Directors approved a resolution to freeze all future benefit accruals for all participants under the Company’s Pension Plan and SERP effective December 31, 2019. Consequently, current participants in the Pension Plan and SERP no longer accrue new benefits under the plans and new employees of the Company are no longer eligible to enter the Pension Plan and SERP as participants after December 31, 2019. The freezing of the Pension Plan and SERP triggered a

curtailment which required a remeasurement of the projected benefit obligations of the Pension Plan and SERP and resulted in a $1,726,000 reduction in unrecognized pension benefit costs that were previously included in accumulated other comprehensive loss, with a corresponding curtailment gain in other comprehensive income which was recorded during the year ended September 30, 2020.

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


	Pension				SERP				Postretirement Medical
	September 30,
	2020		2019		2020		2019		2020		2019
Change in Projected Benefit Obligation:
Benefit obligation at beginning of year	$	10,971,000	$	9,164,000	$	2,385,000	$	2,039,000	$	2,633,000	$	2,382,000
Service cost	50,000		189,000		3,000		32,000		—		—
Interest cost	304,000		372,000		63,000		78,000		80,000		99,000
Actuarial loss (gain)	504,000		1,426,000		(90,000)		236,000		134,000		161,000
Benefits paid	(153,000)		(180,000)		—		—		(8,000)		(9,000)

Curtailments	(1,396,000)		—		(330,000)		—		—		—
Benefit obligation at end of year	10,280,000		10,971,000		2,031,000		2,385,000		2,839,000		2,633,000
Change in Plan Assets:
Fair value of plan assets at beginning of year	10,192,000		10,012,000		—		—		—		—
Actual return on plan assets	1,012,000		245,000		—		—		—		—
Employer contributions	—		115,000		—		—		8,000		9,000
Benefits paid	(153,000)		(180,000)		—		—		(8,000)		(9,000)

Fair value of plan assets at end of year	11,051,000		10,192,000		—		—		—		—
Funded status	$	771,000	$	(779,000)	$	(2,031,000)	$	(2,385,000)	$	(2,839,000)	$	(2,633,000)


	Pension				SERP				Postretirement Medical
	September 30,
	2020		2019		2020		2019		2020		2019
Amounts recognized in the Consolidated Balance Sheets:
Noncurrent assets	$	771,000	$	—	$	—	$	—	$	—	$	—
Current liabilities	—		—		(32,000)		(2,000)		(9,000)		(10,000)
Noncurrent liabilities	—		(779,000)		(1,999,000)		(2,383,000)		(2,830,000)		(2,623,000)
Net amount	$	771,000	$	(779,000)	$	(2,031,000)	$	(2,385,000)	$	(2,839,000)	$	(2,633,000)
Amounts recognized in accumulated other comprehensive loss (income) before income taxes:
Net actuarial loss	$	1,681,000	$	2,939,000	$	72,000	$	497,000	$	721,000	$	667,000
Prior service cost (credit)	—		54,000		—		(54,000)		—		—
Accumulated other comprehensive loss	$	1,681,000	$	2,993,000	$	72,000	$	443,000	$	721,000	$	667,000

Currently, no contributions will be made to the Pension Plan during fiscal 2021. The SERP and Postretirement Medical plans are unfunded and Barnwell funds benefits when payments are made. Expected payments under the Postretirement Medical plan and SERP for fiscal 2021 are 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 losses in fiscal 2020 were primarily due to a decrease in the discount rate. The SERP actuarial gains in fiscal 2020 were primarily due to the freezing of the plan benefit accruals which decreased the net periodic cost and improved the funded position. The Postretirement Medical plan actuarial losses in fiscal 2020 were primarily due to a decrease in the discount rate.

The Pension Plan actuarial losses in fiscal 2019 were primarily due to a decrease in the discount rate and actual investment returns that were lower than the assumed rate of return. The SERP actuarial losses in fiscal 2019 were primarily due to a decrease in the discount rate. The Postretirement Medical plan actuarial losses in fiscal 2019 were primarily due to a decrease in the discount rate and an increase in the medical insurance premium assumptions.

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


	Pension		SERP		Postretirement Medical
	Year ended September 30,
	2020	2019	2020	2019	2020	2019
Assumptions used to determine fiscal year-end benefit obligations:
Discount rate	2.54%	3.06%	2.54%	3.06%	2.54%	3.06%
Rate of compensation increase	N/A	4.00%	N/A	4.00%	N/A	N/A
Assumptions used to determine net benefit costs (years ended):
Discount rate	3.06% / 3.15%*	4.15%	3.06% / 3.15%*	4.15%	3.06%	4.15%
Expected return on plan assets	6.50%	6.50%	N/A	N/A	N/A	N/A
Rate of compensation increase	4.00%	4.00%	4.00%	4.00%	N/A	N/A

_______________________________________________

* 3.06% as of September 30, 2019 and 3.15% as of December 31, 2019 remeasurement.

We select a discount rate by reference to yields available on the FTSE High Grade Credit Index at our consolidated balance sheet date. The expected return on plan assets is primarily based on historical rates of return.

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


	Pension				SERP				Postretirement Medical
	Year ended September 30,
	2020		2019		2020		2019		2020		2019
Net periodic benefit (income) cost for the year:
Service cost	$	50,000	$	189,000	$	3,000	$	32,000	$	—	$	—
Interest cost	304,000		372,000		63,000		78,000		80,000		99,000
Expected return on plan assets	(680,000)		(648,000)		—		—		—		—
Amortization of prior service cost (credit)	1,000		6,000		(1,000)		(6,000)		—		—
Amortization of net actuarial loss	35,000		2,000		5,000		—		80,000		53,000
Curtailment cost (income)	53,000		—		(53,000)		—		—		—
Net periodic benefit (income) cost	$	(237,000)	$	(79,000)	$	17,000	$	104,000	$	160,000	$	152,000

The amounts that are estimated to be amortized from accumulated other comprehensive loss into net periodic benefit (income) cost in the next fiscal year are as follows:


	Pension		SERP		Postretirement Medical
Prior service cost (credit)	$	—	$	—	$	—
Net actuarial loss	39,000		—		94,000
	$	39,000	$	—	$	94,000

The accumulated benefit obligation differs from the projected benefit obligation in that it assumes future compensation levels will remain unchanged. The accumulated benefit obligation for the Pension Plan was $10,280,000 and $9,600,000 at September 30, 2020 and 2019, respectively. The accumulated benefit obligation for the SERP was $2,031,000 and $2,032,000 at September 30, 2020 and 2019, respectively.

The benefits expected to be paid under the retirement plans as of September 30, 2020 are as follows:


	Pension		SERP		Postretirement Medical
Expected Benefit Payments:
Fiscal year ending September 30, 2021	$	272,000	$	32,000	$	9,000
Fiscal year ending September 30, 2022	$	391,000	$	63,000	$	20,000
Fiscal year ending September 30, 2023	$	455,000	$	90,000	$	33,000
Fiscal year ending September 30, 2024	$	517,000	$	117,000	$	50,000
Fiscal year ending September 30, 2025	$	508,000	$	116,000	$	69,000
Fiscal years ending September 30, 2026 through 2030	$	2,653,000	$	590,000	$	391,000

The following table provides the assumed health care cost trend rates related to the measurement of Barnwell’s postretirement medical obligations.


	Year ended September 30,
	2020	2019
Health care cost trend rates assumed for next year	6.75%	7.00%
Ultimate cost trend rate	5.00%	5.00%
Year that the rate reaches the ultimate trend rate	2028	2028

A 7.00% annual rate of increase in the per capita cost of covered health care benefits was assumed for fiscal 2020. This assumption is based on the plans’ recent experience. It is assumed that the rate will decrease gradually to 5% for fiscal 2028 and remain level thereafter. The assumed health care cost trend rates have a significant effect on the amounts reported for the postretirement medical obligations. A one-percentage-point change in the assumed health care cost trend rates would have the following effects:


	1-Percentage Point Increase		1-Percentage Point (Decrease)
Effect on total service and interest cost components	$	18,000	$	(14,000)
Effect on accumulated postretirement benefit obligations	$	620,000	$	(488,000)

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, 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:


	Target	September 30,
Asset Category	Allocation	2020	2019
Cash and other	0% - 15%	—%	—%
Fixed income securities	25% - 55%	52%	38%
Equity securities	40% - 60%	48%	62%

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:


			Fair Value Measurements Using:
	Carrying Amount as of September 30, 2020		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Financial Assets:


Corporate bonds	$	1,000	$	1,000	$	—	$	—
Fixed income exchange-traded funds	5,762,000		5,762,000		—		—

Equity securities exchange-traded funds	352,000		352,000		—		—
Equities	4,936,000		4,936,000		—		—
Total	$	11,051,000	$	11,051,000	$	—	$	—

			Fair Value Measurements Using:
	Carrying Amount as of September 30, 2019		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Financial Assets:
Cash	$	4,000	$	4,000	$	—	$	—

Corporate bonds	1,000		1,000		—		—
Fixed income exchange-traded funds	3,859,000		3,859,000		—		—

Equity securities exchange-traded funds	547,000		547,000		—		—
Equities	5,781,000		5,781,000		—		—
Total	$	10,192,000	$	10,192,000	$	—	$	—

10. INCOME TAXES

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


	Year ended September 30,
	2020		2019
United States	$	1,518,000	$	(3,039,000)
Canada	(6,271,000)		(9,606,000)
	$	(4,753,000)	$	(12,645,000)

The components of the income tax provision (benefit) related to the above loss are as follows:


	Year ended September 30,
	2020		2019
Current benefit:
United States – Federal	$	—	$	(31,000)
United States – State	(23,000)		(52,000)
Canadian	—		(4,000)
Total current	(23,000)		(87,000)
Deferred provision (benefit):

United States – State	26,000		(24,000)
Canadian	—		(120,000)
Total deferred	26,000		(144,000)
	$	3,000	$	(231,000)

On June 28, 2019, the Canadian province of Alberta enacted legislation that decreased the provincial general corporate tax rate from 12% to 11% effective July 1, 2019, with further 1% rate reductions on January 1 of every year until the provincial general corporate tax rate is 8% on January 1, 2022, bringing Barnwell of Canada’s and Octavian Oil’s total Canadian statutory tax rates from 30.65% and 27.00%, respectively, to 29.70% and 26.00%, respectively, effective July 1, 2019 and to 26.85% and 23.00%, respectively, effective 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, however, had not been enacted as of September 30, 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 have no significant impact to earnings/loss as a result of a full valuation allowance being applied to Canadian deferred tax assets.

On March 27, 2020, the CARES Act was signed into law to provide economic relief to businesses that were negatively impacted by the COVID-19 pandemic. Key tax provisions of the CARES Act impacting the Company include the modification of rules related to corporate AMT credits and NOLs, as discussed further below.

The repeal of the corporate AMT by the TCJA provided a mechanism for the refund over time of any unused AMT credit carryovers. Under the TCJA, 50% of the Company's total credit ($230,000 = $460,000 x 50%) was refundable effective for tax years beginning after December 31, 2017 (i.e., our fiscal 2019) and was reclassified to current taxes receivable as of September 30, 2019. The CARES Act subsequently provided for an election to take the entire refundable credit in the Company’s 2018 tax year (fiscal year 2019 return). As such, the Company reclassified the remaining 50% from non-current to current taxes receivable as of March 31, 2020 as a result of the CARES Act legislation.

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


	Year ended September 30,
	2020		2019
Tax benefit computed by applying statutory rate	$	(998,000)	$	(2,655,000)
Impact of TCJA limitation on post-TCJA net operating loss carryforwards	(260,000)		260,000
Increase in the valuation allowance	1,978,000		3,003,000
Impact of TCJA on alternative minimum tax credit carryovers	—		(31,000)
Additional effect of the foreign tax provision on the total tax provision	(762,000)		(736,000)

U.S. state tax provision, net of federal benefit	3,000		(76,000)
Other	42,000		4,000
	$	3,000	$	(231,000)

The changes in the valuation allowance shown in the table above exclude the impact of changes in state taxes and refundable alternative minimum tax credit carryovers, 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:


	September 30,
	2020		2019
Deferred income tax assets:
Foreign tax credit carryover under U.S. tax law	$	2,421,000	$	2,421,000

U.S. federal net operating loss carryover	8,874,000		8,366,000
U.S. state unitary net operating loss carryovers	877,000		873,000
Canadian net operating loss carryovers	1,351,000		850,000
Tax basis of investment in land in excess of book basis under U.S. tax law	306,000		296,000
Property and equipment accumulated book depreciation and depletion in excess of tax under Canadian tax law	1,421,000		308,000
Property and equipment accumulated book depreciation and depletion in excess of tax under U.S. tax law	931,000		945,000
Liabilities accrued for books but not for tax under U.S. tax law	1,894,000		2,250,000
Liabilities accrued for books but not for tax under Canadian tax law	1,591,000		1,641,000
Other	345,000		294,000
Total gross deferred income tax assets	20,011,000		18,244,000
Less valuation allowance	(19,357,000)		(17,687,000)
Net deferred income tax assets	654,000		557,000
Deferred income tax liabilities:

Book basis of investment in land development partnerships in excess of tax basis under U.S. tax law	(654,000)		(557,000)
Book basis of investment in land development partnerships in excess of tax basis under U.S. state non-unitary tax law	(194,000)		(168,000)

Total deferred income tax liabilities	(848,000)		(725,000)
Net deferred income tax liability	$	(194,000)	$	(168,000)
Reported as:
Deferred income tax assets	—		—
Deferred income tax liabilities	(194,000)		(168,000)
Net deferred income tax liability	$	(194,000)	$	(168,000)

The total valuation allowance increased $1,670,000 for the year ended September 30, 2020. The increase was primarily due to a $1,540,000 increase in the valuation allowance for deferred tax assets under Canadian law related to property and equipment accumulated book depletion in excess of tax and Canadian jurisdiction net operating loss carryforwards that may not be realizable and a $438,000 increase in the U.S. federal tax law valuation allowance related to U.S. federal net operating loss carryforwards. Of the total net increase in the valuation allowance for fiscal 2020, $1,978,000 was recognized as an income tax expense and $308,000 was credited to accumulated other comprehensive loss.

Net deferred tax assets at September 30, 2020 of $654,000 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 Partnership excess of book income over taxable income.

At September 30, 2020, 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 $2,421,000, $42,257,000, $13,810,000 and $5,506,000, respectively. All four items were fully offset by valuation allowances at September 30, 2020, 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 2037-2040, and the foreign tax credit carryovers expire in fiscal years 2021-2025. The U.S. federal net operating loss carryovers generated in the years ended September 30, 2020 and 2019 and the U.S. state net operating loss carryovers generated in the years ended September 30, 2020, 2019 and 2018 have no expiry, however utilization of the U.S. state net operating loss carryovers generated in fiscal 2018 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. The Company has no uncertain tax positions as of September 30, 2020 or 2019.

Included below is a summary of the tax years, by jurisdiction, that remain subject to examination by taxing authorities at September 30, 2020:


Jurisdiction			Fiscal Years Open
U.S. federal			2017 – 2019
Various U.S. states			2017 – 2019
Canada federal			2013 – 2019
Various Canadian provinces			2013 – 2019

11. REVENUE FROM CONTRACTS WITH CUSTOMERS

Disaggregation of Revenue

The following tables provide information about disaggregated revenue by revenue streams, reportable segments, geographical region, and timing of revenue recognition for the years ended September 30, 2020 and 2019.


		Year ended September 30, 2020
		Oil and natural gas		Contract drilling		Land investment		Other		Total
Revenue streams:
	Oil	$	5,214,000	$	—	$	—	$	—	$	5,214,000
	Natural gas	1,119,000		—		—		—		1,119,000
	Natural gas liquids	360,000		—		—		—		360,000
	Drilling and pump	—		10,994,000		—		—		10,994,000
	Contingent residual payments	—		—		325,000		—		325,000
	Other	—		—		—		317,000		317,000
	Total revenues before interest income	$	6,693,000	$	10,994,000	$	325,000	$	317,000	$	18,329,000
Geographical regions:
	United States	$	—	$	10,994,000	$	325,000	$	6,000	$	11,325,000
	Canada	6,693,000		—		—		311,000		7,004,000
	Total revenues before interest income	$	6,693,000	$	10,994,000	$	325,000	$	317,000	$	18,329,000
Timing of revenue recognition:
	Goods transferred at a point in time	$	6,693,000	$	—	$	325,000	$	317,000	$	7,335,000
	Services transferred over time	—		10,994,000		—		—		10,994,000
	Total revenues before interest income	$	6,693,000	$	10,994,000	$	325,000	$	317,000	$	18,329,000


		Year ended September 30, 2019
		Oil and natural gas		Contract drilling		Land investment		Other		Total
Revenue streams:
	Oil	$	5,146,000	$	—	$	—	$	—	$	5,146,000
	Natural gas	795,000		—		—		—		795,000
	Natural gas liquids	465,000		—		—		—		465,000
	Drilling and pump	—		5,349,000		—		—		5,349,000
	Contingent residual payments	—		—		165,000		—		165,000
	Other	—		—		—		93,000		93,000
	Total revenues before interest income	$	6,406,000	$	5,349,000	$	165,000	$	93,000	$	12,013,000
Geographical regions:
	United States	$	—	$	5,349,000	$	165,000	$	1,000	$	5,515,000
	Canada	6,406,000		—		—		92,000		6,498,000
	Total revenues before interest income	$	6,406,000	$	5,349,000	$	165,000	$	93,000	$	12,013,000
Timing of revenue recognition:
	Goods transferred at a point in time	$	6,406,000	$	—	$	165,000	$	93,000	$	6,664,000
	Services transferred over time	—		5,349,000		—		—		5,349,000
	Total revenues before interest income	$	6,406,000	$	5,349,000	$	165,000	$	93,000	$	12,013,000

Contract Balances

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


	September 30,
	2020		2019
Accounts receivables from contracts with customers	$	1,772,000	$	1,322,000
Contract assets	413,000		344,000
Contract liabilities	1,097,000		1,633,000

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, 2020 and 2019, the Company had $1,097,000 and $1,633,000, 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, 2020 and 2019, the amount of revenue recognized that was previously included in contract liabilities as of the beginning of the respective period was $1,054,000 and $31,000, respectively.

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, 2020, the Company had three contract drilling jobs with original expected durations of greater than one year. For these contracts, approximately 7% of the remaining performance obligation of $2,416,000 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, 2020 and 2019, the Company had $145,000 and $296,000, respectively, in unamortized preconstruction costs related to contracts that were not completed. During the years ended September 30, 2020 and 2019, the amortization of preconstruction costs related to contracts was $163,000 and $204,000, 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, 2020 and 2019.

Water Well Re-drill

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:


	September 30, 2020	September 30, 2019
Uninstalled materials	489,000	729,000

100

12. SEGMENT AND GEOGRAPHIC INFORMATION

Barnwell operates the following segments: 1) acquiring, developing, producing and selling oil and natural gas in Canada (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.


	Year ended September 30,
	2020		2019
Revenues:
Oil and natural gas	$	6,693,000	$	6,406,000
Contract drilling	10,994,000		5,349,000
Land investment	325,000		165,000

Other	317,000		93,000
Total before interest income	18,329,000		12,013,000
Interest income	18,000		62,000
Total revenues	$	18,347,000	$	12,075,000
Depletion, depreciation, and amortization:
Oil and natural gas	$	1,747,000	$	2,680,000
Contract drilling	356,000		287,000
Other	44,000		55,000
Total depletion, depreciation, and amortization	$	2,147,000	$	3,022,000
Impairment:
Oil and natural gas	$	4,326,000	$	5,710,000
Land investment	50,000		—

Total impairment	$	4,376,000	$	5,710,000
Operating profit (loss) (before general and administrative expenses):
Oil and natural gas	$	(4,230,000)	$	(7,197,000)
Contract drilling	3,125,000		89,000
Land investment	275,000		165,000

Other	273,000		38,000
Gain on sales of asset	1,336,000		—
Total operating profit (loss)	779,000		(6,905,000)
Equity in income (loss) of affiliates:
Land investment	352,000		(276,000)
General and administrative expenses	(5,820,000)		(5,524,000)
Interest expense	(3,000)		(5,000)

Interest income	18,000		62,000
Loss before income taxes	$	(4,674,000)	$	(12,648,000)

101

Capital Expenditures:


	Year ended September 30,
	2020		2019
Oil and natural gas	$	3,099,000	$	46,000
Contract drilling	408,000		1,262,000
Other	7,000		1,000
Total	$	3,514,000	$	1,309,000

Oil and natural gas capital expenditures include acquisitions as well as changes to capitalized asset retirement obligations, including revisions of asset retirement obligations (see Note 8 for additional details).

Assets By Segment:


	September 30,
	2020		2019
Oil and natural gas (1)	$	3,613,000	$	7,415,000
Contract drilling (2)	3,838,000		3,793,000
Land investment (2)	901,000		980,000
Other:
Cash and cash equivalents	4,584,000		4,613,000


Corporate and other	2,246,000		1,501,000
Total	$	15,182,000	$	18,302,000

______________

(1) Primarily located in the province of Alberta, Canada.

(2) Located in Hawaii.

Long-Lived Assets By Geographic Area:


	September 30,
	2020		2019
United States	$	3,393,000	$	3,366,000
Canada	2,302,000		6,232,000
Total	$	5,695,000	$	9,598,000

Revenue By Geographic Area:


	Year ended September 30,
	2020		2019
United States	$	11,325,000	$	5,515,000
Canada	7,004,000		6,498,000
Total (excluding interest income)	$	18,329,000	$	12,013,000

102

13. ACCUMULATED OTHER COMPREHENSIVE LOSS

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


	Year ended September 30,
	2020		2019
Foreign currency translation:
Beginning accumulated foreign currency translation	$	691,000	$	925,000
Change in cumulative translation adjustment before reclassifications	(146,000)		(234,000)

Income taxes	—		—
Net current period other comprehensive loss	(146,000)		(234,000)
Ending accumulated foreign currency translation	545,000		691,000
Retirement plans:
Beginning accumulated retirement plans benefit cost	(3,608,000)		(1,439,000)
Amortization of net actuarial loss and prior service cost	120,000		55,000
Net actuarial gain (loss) arising during the period	1,508,000		(2,224,000)
Income taxes	—		—
Net current period other comprehensive income (loss)	1,628,000		(2,169,000)
Ending accumulated retirement plans benefit cost	(1,980,000)		(3,608,000)
Accumulated other comprehensive loss, net of taxes	$	(1,435,000)	$	(2,917,000)

The amortization of net actuarial loss and prior service cost for the retirement plans are included in the computation of net periodic benefit (income) cost which is a component of “General and administrative” expenses on the accompanying Consolidated Statements of Operations (see Note 9 for additional details).

14. FAIR VALUE MEASUREMENTS

Fair Value of Financial Instruments

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

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

The estimated fair values of oil and natural gas properties and the asset retirement obligation incurred in the drilling of oil and natural gas wells or assumed in the acquisitions of additional oil and natural gas working interests are based on an estimated discounted cash flow model and market assumptions. The 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 7 for additional information regarding oil and natural gas property acquisitions.

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

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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 8, the Company recognizes the fair value of a liability for an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made. Asset retirement obligations are not measured at fair value subsequent to initial recognition.

15. DEBT

On April 28, 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 matures two years after the date of the loan disbursement and bears interest at a fixed annual rate of 1.00%, with the first six months of principal and interest deferred. Under the terms of the CARES Act, as amended by the Flexibility Act, and the PPP, the Company can apply for and be granted forgiveness for all or a portion of the loan issued under the PPP and the loan is expected to be forgiven to the extent the proceeds are used in accordance with the PPP to cover payroll, mortgage interest, rent, and utility costs incurred by the Company over the 24-week period following the loan disbursement date. As of the date of this filing, the Company is in the process of applying for forgiveness and believes that its use of the loan proceeds will meet the conditions for forgiveness under the PPP and expects the loan to be recorded as income when legal forgiveness is obtained. As of September 30, 2020, the current and long-term portions of the loan were $89,000 and $58,000, respectively, and the current portion is included in “Other current liabilities” in the Company's Consolidated Balance Sheet.

In October 2020, the Company was notified by the lender of our PPP loan of changes to certain terms of our PPP loan to conform with the amendments to the CARES Act implemented by the Flexibility Act which included, but was not limited to, the extension of the initial deferment period of the loan’s principal and interest payments from six months to ten months after the last day of the covered period. The current and long-term portions of the loan as of September 30, 2020 were not adjusted for this October 2020 loan modification by our lender.

16. LEASES AND GAIN ON SALE OF ASSET

On October 1, 2019, the Company adopted ASU No. 2016-02, “Leases (Topic 842),” using the modified retrospective transition approach and applied the new standard to leases in place as of the adoption date. Results for reporting periods prior to October 1, 2019 have not been adjusted. The Company elected the package of practical expedients allowed upon adoption of ASC 842 which, among other things, allowed us to (1) not reassess whether any expired or existing contracts contain leases, (2) carry forward the historical lease classification, and (3) not have to reassess any initial direct cost of any expired or existing leases.

As a result of the adoption of ASC 842, the Company recorded operating lease right-of-use (“ROU”) assets of $2,589,000 and corresponding total operating lease liabilities of $2,589,000 in the Consolidated Balance Sheets as of October 1, 2019. There was no impact to retained earnings or the Consolidated Statements of Operations.

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The Company’s remaining ROU assets and lease liabilities at September 30, 2020, primarily relate to non-cancelable operating leases for our Canadian office space and our leasehold land interest for Lot 4C held by Kaupulehu Developments. Management determines if a contract is or contains a lease at inception of the contract or modification of the contract. A contract is or contains a lease if the contract conveys the right to control the use of the asset for a period in exchange for consideration.

Operating lease ROU assets and liabilities are recognized based on the present value of future minimum lease payments over the expected lease term at commencement date. The Company’s leases do not provide a readily determinable implicit rate; therefore, management uses the Company’s incremental borrowing rate to discount lease payments based on information available at lease commencement. Our lease terms may include options to extend or terminate the lease when it is reasonably certain we will exercise that option. Lease expense for minimum lease payments is recognized on a straight-line basis over the expected lease terms.

The Company has lease agreements with lease and non-lease components and the non-lease components are excluded in the calculation of the ROU asset and lease liability and expensed as incurred. None of the Company’s lease agreements contain material residual value guarantees or material restrictions or covenants.

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

Leases recorded on the balance sheet consist of the following:


		September 30, 2020
Assets:

	Operating lease right-of-use assets	$	249,000
	Total right-of-use assets	$	249,000
Liabilities:

	Current portion of operating lease liabilities	$	111,000
	Operating lease liabilities	143,000
	Total lease liabilities	$	254,000

The components of lease expenses are as follows:


	Year ended September 30, 2020
Operating lease cost	$	334,000
Short-term lease cost	69,000
Total lease cost	$	403,000

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Supplemental information related to leases is as follows:


		September 30, 2020
Cash paid for amounts included in the measurement of lease liabilities:
	Operating cash flows for operating leases	$	189,000
Operating leases:
	Weighted-average remaining lease term (in years)	3.4
	Weighted-average discount rate	5.85%

The remaining lease payments for our operating leases as of September 30, 2020, are as follows:


Fiscal year ending:
2021	$	123,000
2022	61,000
2023	30,000
2024	30,000
2025	30,000
Thereafter through 2026	7,000
Total lease payments	281,000
Less: amounts representing interest	(27,000)
Present value of lease liabilities	$	254,000

The lease payments for the Lot 4C leasehold land 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.

17. COMMITMENTS AND CONTINGENCIES

Incentive compensation plan

In fiscal 2020, 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 and the divestiture of oil and natural gas assets. As of September 30, 2020, Barnwell has accrued approximately $23,000 in bonus compensation under these plans and the amount is reported in “Accrued compensation” on the Consolidated Balance Sheet at September 30, 2020.

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.

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Legal and Regulatory Matters

On July 28, 2020, the Staff of the Commission circulated a draft of a proposed recommendation to the Commission under which the Company, the water utility, the water utility's independent hydrologist firm and the owner of the land on which the two aforementioned water wells were drilled would be assessed penalty fines because each of the wells were calculated to have been drilled beyond the depth permitted by the permit. The wells were drilled to a depth to penetrate certain layers of impermeable rock necessary to access the aquifer at the instructions and on the advice of the hydrologist hired by the owner of the well. The Company’s share of the proposed penalties and fines were originally calculated to approximately $1,200,000. Subsequently, the Staff of the Commission acknowledged that one well had not been drilled to a depth beyond its permitted depth and the fines on that well were eliminated. Additionally, the fines applicable to the depth of the second well were recalculated and reduced to approximately $300,000 as to the Company. The Commission and the aforementioned four parties have worked on a possible proposed alternative settlement in lieu of the penalties and fines whereby the named parties would be responsible for providing the Commission with assistance to monitor the aquifer, at no cost to the Commission, to aid in the Commission’s efforts to monitor water quality in the subject area. The Company and the other three parties are currently evaluating proposals that it believes would likely satisfy the Commission's request under the proposed alternative settlement but it is currently uncertain as to whether or not they will be acceptable to the Commission. Additionally, it is uncertain as to how the cost of the alternative settlement would be allocated to the named parties of the subject violations. Accordingly, the Company recorded a contingent liability of approximately $300,000 at September 30, 2020.

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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.

Effective March 2019, Barnwell is now also obligated to pay an amount equal to 0.72% and 0.20% of the cumulative net profits of KD II to KD Development, LLC and a pool of various individuals, respectively, all of whom are partners of KKM and are unrelated to Barnwell, in compensation for the agreement of these parties to admit the new development partner for Increment II. Such compensation will be reflected as the obligation becomes probable and the amount of the obligation can be reasonably estimated.

18. INFORMATION RELATING TO THE CONSOLIDATED STATEMENTS OF CASH FLOWS

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


	Year ended September 30,
	2020		2019
Increase (decrease) from changes in:
Receivables	$	(598,000)	$	(260,000)
Income tax receivable	129,000		758,000
Other current assets	260,000		(188,000)
Accounts payable	924,000		(202,000)
Accrued compensation	203,000		(317,000)
Other current liabilities	(470,000)		1,451,000
Increase from changes in current assets and liabilities	$	448,000	$	1,242,000
Supplemental disclosure of cash flow information:
Cash paid (received) during the year for:

Income taxes refunded, net	$	(166,000)	$	(2,302,000)

Capital expenditure accruals related to oil and natural gas acquisition and development increased $435,000 and $60,000 during the years ended September 30, 2020 and 2019, respectively. Additionally, capital expenditure accruals related to oil and natural gas asset retirement obligations decreased $52,000 and $755,000 during the years ended September 30, 2020 and 2019, respectively.

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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. Through March 6, 2019, Kaupulehu Developments was also entitled to receive 50% of distributions otherwise payable from KD II to its members up to $8,000,000, of which $3,500,000 was received. 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 and percentage of distribution 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 6.

During the year ended September 30, 2020, Barnwell received $325,000 in percentage of sales payments from KD I from the sale of two lots within Phase II of Increment I. During the year ended September 30, 2019, Barnwell received $165,000 in percentage of sales payments from KD I from the sale of one lot within Phase II of Increment I.

20. SUBSEQUENT EVENTS

In October 2020, the Company was notified by the lender of our PPP loan of changes to certain terms of our PPP loan to conform with the amendments to the CARES Act implemented by the Flexibility Act that was signed into law in June 2020. Under the Flexibility Act, key changes to our PPP loan included, but were not limited to, the extension of the initial deferment period of the loan’s principal and interest payments from six months to ten months after the last day of the covered period and if the Company does not apply for forgiveness of the loan within ten months after the last day of the covered period, the PPP loan is no longer deferred and the borrower must begin paying principal and interest. As of the date of this filing, the Company is in the process of applying for forgiveness and believes that its use of the loan proceeds will meet the conditions for forgiveness under the PPP and expects the loan to be recorded as income when legal forgiveness is obtained.

In November 2020, Kaupulehu Developments received a percentage of sales payment of $170,000 from the sale of one lot within Phase II of Increment I. Financial results from the receipt of this payment will be reflected in Barnwell's quarter ending December 31, 2020.

Additionally, subsequent to September 30, 2020, Barnwell received net cash distributions in the amount of $1,034,000 from the Kukio Resort Land Development Partnerships. Of the $1,034,000 in net cash distributions received from the Kukio Resort Land Development Partnerships, $459,000 represents preferred return payments from KKM and will be recorded as an additional equity pickup in the quarter ending December 31, 2020, as discussed in more detail in Note 6. The preferred return payments received after September 30, 2020 brought the cumulative preferred return to $656,000, which is the total amount Barnwell was entitled to, and thus there is no more preferred return outstanding as of the date of this report.

21. SUMMARY OF SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)

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

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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. 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 table 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 all in Canada. All of the information regarding 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. 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.


	OIL & NGL (Bbls)	GAS (Mcf)	Total (Boe)
Proved reserves:
Balance at September 30, 2018	1,590,000	5,055,000	2,462,000
Revisions of previous estimates	(74,000)	(21,000)	(78,000)
Extensions, discoveries and other additions	14,000	33,000	20,000
Acquisitions of reserves	30,000	81,000	44,000

Less production	(141,000)	(628,000)	(250,000)
Balance at September 30, 2019	1,419,000	4,520,000	2,198,000
Revisions of previous estimates	(740,000)	(1,746,000)	(1,041,000)

Acquisitions of reserves	68,000	628,000	176,000
Less sales of reserves	(38,000)	(443,000)	(114,000)
Less production	(174,000)	(649,000)	(286,000)
Proved Reserves, September 30, 2020	535,000	2,310,000	933,000
Proved Developed Reserves, September 30, 2020	530,000	2,310,000	928,000
Proved Undeveloped Reserves, September 30, 2020	5,000	—	5,000

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

All capitalized costs relating to oil and natural gas producing activities, which were being depleted in all years, are summarized as follows:


	September 30,
	2020		2019
Proved properties	$	64,142,000	$	62,075,000
Unproved properties	—		130,000
Total capitalized costs	64,142,000		62,205,000
Accumulated depletion, depreciation, and impairment	61,839,000		55,972,000
Net capitalized costs	$	2,303,000	$	6,233,000


	Year ended September 30,
	2020		2019
Acquisition of properties:
Unproved	$	—	$	—
Proved	242,000		668,000

Development costs	2,857,000		(622,000)
Total	$	3,099,000	$	46,000

Costs incurred in the table above include additions and revisions to Barnwell’s asset retirement obligation of $(52,000) and $(755,000) for the years ended September 30, 2020 and 2019, respectively.

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


	Year ended September 30,
	2020		2019
Net revenues	$	6,693,000	$	6,406,000
Production costs	(4,850,000)		(5,213,000)
Depletion	(1,747,000)		(2,680,000)
Reduction of carrying value of oil and natural gas properties	(4,326,000)		(5,710,000)
Pre-tax results of operations (1)	(4,230,000)		(7,197,000)
Estimated income tax expense (2)	—		(160,000)
Results of operations (1)	$	(4,230,000)	$	(7,357,000)

_________________

(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 tax law deferred tax assets that may not be realizable.

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

The following tables utilize reserve and production data estimated by independent petroleum reserve engineers. The information may be useful for certain comparison purposes but should not be solely relied upon in evaluating Barnwell or its performance. Moreover, the projections should not be construed as realistic estimates of future cash flows, nor should the standardized measure be viewed as representing current value.

The estimated future cash flows at September 30, 2020 and 2019 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, 2020 and 2019 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.

In December 2018, the Society of Petroleum Evaluation Engineers and associated industry professionals updated the COGE Handbook. The updates clarify and streamline existing guidelines and offer additional guidance regarding Canadian reserves evaluations. Barnwell has included all abandonment, decommissioning and reclamation costs and inactive well costs in accordance with best practice recommendations into the Company’s September 30, 2020 and September 30, 2019 year-end reserve reports.

Standardized Measure of Discounted Future Net Cash Flows


	September 30,
	2020		2019
Future cash inflows	$	20,426,000	$	65,720,000
Future production costs	(17,860,000)		(41,733,000)
Future development costs	(73,000)		(13,295,000)
Future income tax expenses	(92,000)		(450,000)
Future net cash flows excluding abandonment, decommissioning and reclamation	2,401,000		10,242,000
Future abandonment, decommissioning and reclamation	(13,055,000)		(13,190,000)
Future net cash flows	(10,654,000)		(2,948,000)
10% annual discount for timing of cash flows	8,969,000		5,258,000
Standardized measure of discounted future net cash flows	$	(1,685,000)	$	2,310,000

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Changes in the Standardized Measure of Discounted Future Net Cash Flows


	Year ended September 30,
	2020		2019
Beginning of year	$	2,310,000	$	13,836,000
Sales of oil and natural gas produced, net of production costs	(1,843,000)		(1,193,000)
Net changes in prices and production costs, net of royalties and wellhead taxes	(1,876,000)		(15,358,000)
Extensions and discoveries	—		891,000
Net change due to purchases and sales of minerals in place	467,000		334,000
Previously estimated development costs incurred	1,305,000		—
Changes in future development costs	7,773,000		—
Revisions of previous quantity estimates	(10,274,000)		(71,000)
Net change in income taxes	288,000		3,792,000
Accretion of discount	230,000		1,350,000
Other - changes in the timing of future production and other	(63,000)		(932,000)
Other - net change in Canadian dollar translation rate	(2,000)		(339,000)
Net change	(3,995,000)		(11,526,000)
End of year	$	(1,685,000)	$	2,310,000

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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, 2020, 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) were effective as of September 30, 2020 to ensure that information required to be disclosed by Barnwell in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the Securities Exchange Act of 1934 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 Securities Exchange Act of 1934. 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, 2020.

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, 2020 that materially affected, or is reasonably likely to materially affect, Barnwell’s internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

None.

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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, 2020, 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

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

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PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a) Financial Statements

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

Report of Independent Registered Public Accounting Firm – WEAVER AND TIDWELL, L.L.P.

Report of Independent Registered Public Accounting Firm – KPMG LLP

Consolidated Balance Sheets – September 30, 2020 and 2019

Consolidated Statements of Operations – for the years ended September 30, 2020 and 2019

Consolidated Statements of Comprehensive Loss – for the years ended September 30, 2020 and 2019

Consolidated Statements of Equity (Deficit) – for the years ended September 30, 2020 and 2019

Consolidated Statements of Cash Flows – for the years ended September 30, 2020 and 2019

Notes to Consolidated Financial Statements

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

(b) Exhibits


Exhibit Number						Description

3.1						Certificate of Incorporation, as amended (1)

3.2						Amended and Restated By-Laws (2)

4.0						Form of the Registrant’s certificate of common stock, par value $.50 per share (3)

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						Purchase and Sale Agreement, executed on June 8, 2017, with an as of date of May 10, 2017, between Barnwell of Canada, Limited and Anegada Oil Corp. (9)

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10.7						Purchase and Sale Agreement, dated December 14, 2017, between Barnwell of Canada, Limited and Mount Bastion Oil & Gas Corp. (10)

10.8						Purchase and Sale Agreement, dated July 19, 2018, between Barnwell of Canada, Limited and Octavian Oil Ltd. and Eagle Energy Inc. (11)

10.9						Agreement with KD Kaupulehu, LLLP to Release Retained Rights, dated as of March 7, 2019, between Kaupulehu Developments and KD Kaupulehu, LLLP (12)

10.10						Agreement with Respect to Retained Rights, dated as of March 7, 2019 between Kaupulehu Developments and KD Acquisition II, LP (13)
21						List of Subsidiaries

23						Consent of InSite Petroleum Consultants Ltd.

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.

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

__________________________________________________

(1) Incorporated by reference to Exhibit 3.1 to Registrant’s Form 10-K for the year ended September 30, 2013.

(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 1.1 to Registrant’s Form 8-K filed on June 14, 2017.

(10) Incorporated by reference to Exhibit 1.1 to Registrant’s Form 8-K filed on December 19, 2017.

(11) Incorporated by reference to Exhibit 2.1 to Registrant’s Form 8-K filed on July 25, 2018.

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

(13) 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.

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SIGNATURES

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

BARNWELL INDUSTRIES, INC.

(Registrant)


			/s/ Russell M. Gifford
By:			Russell M. Gifford Executive Vice President, Chief Financial Officer, Treasurer and Secretary
Date:			December 16, 2020

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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						/s/ Russell M. Gifford
Alexander C. Kinzler President, Chief Executive Officer, Chief Operating Officer, General Counsel and Director Date: December 16, 2020						Russell M. Gifford Executive Vice President, Chief Financial Officer, Treasurer and Secretary Date: December 16, 2020



/s/ Kenneth S. Grossman
Kenneth S. Grossman, Chairman of the Board Date: December 16, 2020



/s/ Robert J. Inglima, Jr.						/s/ Philip J. McPherson
Robert J. Inglima, Jr., Director Date: December 16, 2020						Philip J. McPherson, Director Date: December 16, 2020



/s/ Peter J. O’Malley						/s/ Bradley M. Tirpak
Peter J. O’Malley, Director Date: December 16, 2020						Bradley M. Tirpak, Director Date: December 16, 2020



/s/ Doug N. Woodrum
Doug N. Woodrum, Director Date: December 16, 2020

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INDEX TO EXHIBITS


Exhibit Number						Description

3.1						Certificate of Incorporation, as amended (1)

3.2						Amended and Restated By-Laws (2)

4.0						Form of the Registrant’s certificate of common stock, par value $.50 per share (3)

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						Purchase and Sale Agreement, executed on June 8, 2017, with an as of date of May 10, 2017, between Barnwell of Canada, Limited and Anegada Oil Corp. (9)

10.7						Purchase and Sale Agreement, dated December 14, 2017, between Barnwell of Canada, Limited and Mount Bastion Oil & Gas Corp. (10)

10.8						Purchase and Sale Agreement, dated July 19, 2018, between Barnwell of Canada, Limited and Octavian Oil Ltd. and Eagle Energy Inc. (11)

10.9						Agreement with KD Kaupulehu, LLLP to Release Retained Rights, dated as of March 7, 2019, between Kaupulehu Developments and KD Kaupulehu, LLLP (12)

10.10						Agreement with Respect to Retained Rights, dated as of March 7, 2019 between Kaupulehu Developments and KD Acquisition II, LP (13)

21						List of Subsidiaries

23						Consent of InSite Petroleum Consultants Ltd.

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.

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

__________________________________________________

(1) Incorporated by reference to Exhibit 3.1 to Registrant’s Form 10-K for the year ended September 30, 2013.

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