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, 20202021
or
☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission File Number 1-5103
BARNWELL INDUSTRIES, INC.
(Exact name of registrant as specified in its charter)
| | | | | | | | |
| Delaware | | 72-0496921 |
| (State or other jurisdiction of incorporation or organization) | | (I.R.S. Employer Identification No.) |
| | | | | | | | |
1100 Alakea Street, Suite 2900,500, Honolulu, Hawaii | | 96813-2840 |
| (Address of principal executive offices) | | (Zip code) |
Registrant’s telephone number, including area code: (808) 531-8400
Securities registered pursuant to Section 12(b) of the Act:
| | | | | | | | |
| Title of each class | Trading Symbol(s) | Name of each exchange on which registered |
| Common Stock, $0.50 par value | BRN | NYSE American |
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, 20202021 (the last business day of the registrant’s most recently completed second fiscal quarter) was $1,990,000.$9,903,000.
As of December 9, 202010, 2021 there were 8,277,1609,445,625 shares of common stock outstanding.
Documents Incorporated by Reference
1. Proxy statement, to be forwarded to stockholders on or about January 15, 2021,14, 2022, is incorporated by reference in Part III hereof.
TABLE OF CONTENTS
GLOSSARY OF TERMS
Defined below are certain terms used in this Form 10-K:
| | | | | | | | |
| Terms | | Definitions |
| AER | - | Alberta Energy Regulator |
| ARO | - | Asset retirement obligation |
| ASC | - | Accounting Standards Codification |
| ASU | - | Accounting Standards Update |
| Barnwell of Canada | - | Barnwell of Canada, Limited |
| Bbl(s) | - | stock tank barrel(s) of oil equivalent to 42 U.S. gallons |
| Boe | - | barrel of oil equivalent at the rate of 5.8 Mcf per Bbl of oil or NGL |
| FASB | - | Financial Accounting Standards Board |
| GAAP | - | U.S. generally accepted accounting principles |
| Gross | - | Total number of acres or wells in which Barnwell owns an interest; includes interests owned of record by Barnwell and, in addition, the portion(s) owned by others; for example, a 50% interest in a 320 acre lease represents 320 gross acres and a 50% interest in a well represents 1 gross well. In the context of production volumes, gross represents amounts before deduction of the royalty share due others. |
| InSite | - | InSite Petroleum Consultants Ltd. |
| KD I | - | KD Acquisition, LLLP, formerly known as WB KD Acquisition, LLC |
| KD II | - | KD Acquisition II, LP, formerly known as WB KD Acquisition, II, LLC |
| KD Development | | KD Development, LLC |
| KD Kona | - | KD Kona 2013 LLLP |
| KKM Makai | - | KKM Makai, LLLP |
| Kukio Resort Land Development Partnerships | - | The following partnerships in which Barnwell owns non-controlling interest:
KD Kukio Resorts, LLLP (“KD Kukio Resorts”)
KD Maniniowali, LLLP (“KD Maniniowali”)
KD Kaupulehu, LLLP, which consists of KD I and KD II (“KDK”) |
| LGX | - | LGX Oil & Gas Ltd. |
| LLR | - | Licensee Liability Rating |
| LMR | - | Liability Management Ratio |
| 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 |
| OWA | | Orphan Well Association |
| SEC | - | United States Securities and Exchange Commission |
| VIE | - | Variable interest entity |
| Water Resources | - | Water Resources International, Inc. |
| WIP | | Working Interest Partners |
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 20202021 represented Barnwell’s 64th65th 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.Canada and in the U.S. state of Oklahoma.
•Land Investment Segment - Barnwell invests in land interests in Hawaii.
•Contract Drilling Segment - Barnwell provides well drilling services and water pumping system installation and repairs in Hawaii.
Oil and Natural Gas Segment
Overview
Barnwell acquires and develops crude oil and natural gas assets in the province of Alberta, Canada via two corporate entities, Barnwell of Canada and Octavian Oil. Barnwell of Canada is a U.S. incorporated company that has been active in Canada for over 50 years, primarily as a non-operator participating in exploration projects operated by others. Octavian Oil is a Canadian company incorporated in 2016 to achieve growth through the acquisition of crude oil reserves and development of those reservesreserves. Additionally, through horizontal well drillingits wholly-owned subsidiary BOK Drilling, LLC (“BOK”), established in February 2021, Barnwell is indirectly involved in oil and completion techniques.natural gas investments in Oklahoma.
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 littlea lower 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. WithSince 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 10390 Bbls of oil and 8481 Boe of natural gas and NGL per day.day and has made cumulative production of 68,000 Boe since initial production. Barnwell endeavorscontinues to work 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 CompanyCompany's Canadian oil and natural gas assets not in the Twining area. Thesearea, as well as the new U.S. wells in Oklahoma. The Canadian non-operated assets are diverse in location and attributes, being located throughout Alberta, Canada, and producingproduce shallow gas and conventional oil from a variety of pools. They are mostlyThese non-operated and theyCanadian assets have been accumulated
over decades of Barnwell activity in the basin.activity. Barnwell is continually evaluatingcontinues to evaluate opportunities to either divest thesethe legacy Canadian assets, or add to them depending on technical and economic evaluations. The majority of thesethe Canadian assets were puthave been up for sale inon and off since January 2019, but COVID-19 and the resulting oil price collapse resulted in no reasonable offers being received. However, in April 2021, the Company re-initiated marketing for the sale of these assets and sold some properties.
Barnwell believes that market conditions are rightIn Oklahoma, the Company commenced participation in an eight-well drilling program with non-operated working interests for seven wells varying from 1.2% 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 agents4.2% and a consultant to pursue these opportunities. However, our ability to fund such investments is currently uncertain.minor overriding royalty interest, 0.07%, in one well. Additional drilling opportunities in the U.S. are being investigated, however no definitive plans have yet been developed.
At September 30, 2021, Barnwell’s Canadian reserves were approximately 64% operated and 56% conventional oil and natural gas liquids and 44% natural gas. Proved oil and natural gas reserves located in the United States were not significant at September 30, 2021, as most of the wells drilled were still undergoing evaluation. 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% operatedliquids and 65% conventional oil and43% natural gas liquids.gas.
Operations
All acquisitions, operational and developmental activities in the Twining area are the responsibility of the President and Chief Operating Officer of Octavian Oil with approvals for major expenditures secured from Barnwell’s executive management and 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 obtainingthe Company’s ability to use its current cash, obtain external financing or generate 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 hashave negatively impacted our past operating results, cash flows and liquidity. Credit and capital markets for oil and natural gas companies have been negatively affected as well, resulting in a decline in sources of financing as compared to previous years. By divesting significant oilOil and natural gas assetsprices have recovered significantly from the prior to the 2015 decline in commodity prices, Barnwell was able to repay allyear which could improve sources of its debt, use funds for general corporate purposes, and fund its acquisition investments.external finances.
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.
OnIn 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 hadreported no proved undeveloped reserves related to Twining as oil prices fell
significantly this yearin the second quarter of fiscal 2020 making the drilling of proved undeveloped reserves uneconomic at current prices. Asand as a result, the Company suspended its development of proved undeveloped reserves in the Twining area.
The Company currently does not haveis planning to drill a definitive plannew 100% working interest, operated horizontal well in the Twining area in the first half of fiscal 2022. Additionally, the Company is participating in the drilling of 2.0 gross (0.6 net) non-operated horizontal wells in the area over the same period. The results of these wells will help determine the quality and pace of future development.
As stated above, the Company commenced participation in an eight-well drilling program in Oklahoma with non-operated working interests in seven wells varying from 1.2% to develop4.2% and a minor overriding royalty interest, 0.07%, in one well. One well began production in late May 2021 and the reserves.Company’s share of net production, after royalties, from this well was 1,000 barrels of oil, 4,000 MCF of natural gas and 1,000 barrels of natural gas liquids through September 30, 2021. The remaining wells started production in September 2021.
Preparation of Reserve Estimates
Barnwell’s Canadian 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 Canadian 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 iswas 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 on2021, for all properties located in Canada in which Barnwell has an interest. Proved oil and natural gas reserves located in the United States are not yet significant and are therefore not included in the table below. 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, 2019.2020.
| | | As of September 30, 2020 | | As of September 30, 2021 |
| | Estimated Net Proved Developed Reserves | | Estimated Net Proved Undeveloped Reserves | | Estimated Net Proved Reserves | | Estimated Net Proved Developed Reserves | | Estimated Net Proved Undeveloped Reserves | | Estimated Net Proved Reserves |
| Oil, including natural gas liquids (Bbls) | Oil, including natural gas liquids (Bbls) | 530,000 | | | 5,000 | | | 535,000 | | Oil, including natural gas liquids (Bbls) | 636,000 | | | 4,000 | | | 640,000 | |
| Natural gas (Mcf) | Natural gas (Mcf) | 2,310,000 | | | — | | | 2,310,000 | | Natural gas (Mcf) | 2,913,000 | | | — | | | 2,913,000 | |
| Total (Boe) | Total (Boe) | 928,000 | | | 5,000 | | | 933,000 | | Total (Boe) | 1,138,000 | | | 4,000 | | | 1,142,000 | |
During fiscal 2020,2021, Barnwell’s total net proved developed reserves of oil and natural gas liquids increased by 1,000106,000 Bbls (essentially unchanged)(20%) and total net proved developed reserves of natural gas increased by 410,000603,000 Mcf (22%(26%), for a combined increase of 72,000210,000 Boe (8%(23%). The increase in natural gas reserves were primarily the result of minor acquisitionshigher oil 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 Canadian oil and natural gas net reserves at September 30, 2020,2021, 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, 2020.2021. 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, 2020,2021, the date of the projection.
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| 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 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| As of September 30, 2021 | | For the year ended September 30, 2021 |
| 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 | 22 | | | 12 | | | 30 | | | 28 | | | 6 | | | 5 | | | $ | 276,000 | | | $ | 9,000 | |
| Hillsdown | — | | | — | | | — | | | — | | | 2 | | | 18 | | | 76,000 | | | 44,000 | |
| Kaybob | 36 | | | 122 | | | 36 | | | 122 | | | 5 | | | 19 | | | 233,000 | | | 54,000 | |
| Medicine River | 61 | | | 510 | | | 61 | | | 510 | | | 7 | | | 21 | | | 236,000 | | | 56,000 | |
| Spirit River | — | | | — | | | — | | | — | | | 8 | | | 44 | | | 345,000 | | | 107,000 | |
| Thornbury | — | | | 471 | | | — | | | 471 | | | — | | | 72 | | | — | | | 155,000 | |
| Twining | 408 | | | 1,516 | | | 461 | | | 1,719 | | | 118 | | | 456 | | | 5,931,000 | | | 1,289,000 | |
| Wood River | 52 | | | 60 | | | 52 | | | 60 | | | 22 | | | 18 | | | 1,116,000 | | | 59,000 | |
| Other properties | — | | | 2 | | | — | | | 3 | | | 1 | | | 37 | | | 64,000 | | | 86,000 | |
| Canada Total | 579 | | | 2,693 | | | 640 | | | 2,913 | | | 169 | | | 690 | | | $ | 8,277,000 | | | $ | 1,859,000 | |
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, 2020.2021. 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. Proved oil, natural gas and natural gas liquids reserves located in the United States are not significant and are therefore not included in the table below.
| | Year ending September 30, | Year ending September 30, | | Year ending September 30, | |
| 2021 | | $ | 1,285,000 | | | |
| 2022 | 2022 | | 571,000 | | | 2022 | | $ | 2,440,000 | | |
| 2023 | 2023 | | (34,000) | | | 2023 | | 1,795,000 | | |
| 2024 | | 2024 | | 859,000 | | |
| Thereafter | Thereafter | | (12,476,000) | | | Thereafter | | (10,047,000) | | |
| Undiscounted future net cash flows, after income taxes | Undiscounted future net cash flows, after income taxes | | $ | (10,654,000) | | | | Undiscounted future net cash flows, after income taxes | | $ | (4,953,000) | | | |
| | Standardized measure of discounted future net cash flows | Standardized measure of discounted future net cash flows | | $ | (1,685,000) | | | * | Standardized measure of discounted future net cash flows | | $ | 2,645,000 | | | * |
* 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$2.23 per Mcf and an oil price of $33.26$49.73 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 2021 was derived primarily in Alberta, Canada and to a lesser extent in Oklahoma. All of Barnwell's net production in fiscal 2020 2019 and 20182019 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, | | Year ended September 30, |
| | | 2020 | | 2019 | | 2018 | | 2021 | | 2020 | | 2019 |
| Annual net production: | Annual net production: | | | | | | Annual net production: | | | | | |
| Natural gas (Mcf) | Natural gas (Mcf) | 649,000 | | | 628,000 | | | 328,000 | | Natural gas (Mcf) | 694,000 | | | 649,000 | | | 628,000 | |
| Oil (Bbls) | Oil (Bbls) | 153,000 | | | 123,000 | | | 62,000 | | Oil (Bbls) | 147,000 | | | 153,000 | | | 123,000 | |
| Natural gas liquids (Bbls) | Natural gas liquids (Bbls) | 21,000 | | | 18,000 | | | 5,000 | | Natural gas liquids (Bbls) | 24,000 | | | 21,000 | | | 18,000 | |
| Total (Boe) | Total (Boe) | 286,000 | | | 250,000 | | | 123,000 | | Total (Boe) | 291,000 | | | 286,000 | | | 250,000 | |
| Total (Mcfe) | Total (Mcfe) | 1,658,000 | | | 1,446,000 | | | 717,000 | | Total (Mcfe) | 1,685,000 | | | 1,658,000 | | | 1,446,000 | |
| Annual average sales price per unit of production: | Annual average sales price per unit of production: | | Annual average sales price per unit of production: | |
| Mcf of natural gas* | Mcf of natural gas* | $1.64 | | $1.15 | | $1.12 | Mcf of natural gas* | $2.62 | | $1.64 | | $1.15 |
| Bbl of oil** | Bbl of oil** | $33.85 | | $41.84 | | $51.53 | Bbl of oil** | $51.74 | | $33.85 | | $41.84 |
| Bbl of natural gas liquids** | Bbl of natural gas liquids** | $17.16 | | $25.84 | | $43.02 | Bbl of natural gas liquids** | $31.92 | | $17.16 | | $25.84 |
| Annual average production cost per Boe produced*** | Annual average production cost per Boe produced*** | $16.79 | | $20.64 | | $21.08 | Annual average production cost per Boe produced*** | $22.40 | | $16.79 | | $20.64 |
| Annual average production cost per Mcfe produced*** | Annual average production cost per Mcfe produced*** | $2.89 | | $3.56 | | $3.63 | Annual average production cost per Mcfe produced*** | $3.86 | | $2.89 | | $3.56 |
* 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 $2,217,000 in oil and natural gas properties during fiscal 2021, including accrued capital expenditures and acquisitions of oil and natural gas properties and excluding additions and revisions to estimated asset retirement obligations. Barnwell’s capital expenditures were mostly for the acquisition of additional working interests in several wells and equipment in the Twining area and the drilling of wells in Oklahoma that began in the third quarter of fiscal 2021.
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
The Company participated in the drilling of seven gross (0.20 net) non-operated wells in Oklahoma during the year ended September 30, 2021. Capital expenditures incurred by the Company for these Oklahoma wells totaled $1,178,000 for the year ended September 30, 2021. One gross (0.04 net) well was completed, the well began flowback production in late May 2021 and the Company’s share of net production, after royalties, from this well was 1,000 barrels of oil, 4,000 MCF of natural gas and 1,000 barrels of natural gas liquids through September 30, 2021. The remaining six gross (0.16 net) wells were all producing in October 2021.
The Company did not drill or participate in the drilling of wells in Canada during the year ended September 30, 2021. Drilling opportunities in the Company's core Twining area are being investigated for potential investment in the forthcoming months.
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 2020.2020 and was temporarily shut-in from mid-April 2020 to mid-May 2020 due to decreased oil prices. 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 fromIn fiscal 2021, this well wascontributed approximately 10334,200 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.representing 23% total net oil production.
Producing Wells
As of September 30, 2020,2021, Barnwell had interests in 134139 gross (50.4(49.7 net) producing wells in Alberta, Canada, of which 6982 gross (42.2(42.0 net) were oil wells and 6557 gross (8.2(7.7 net) were natural gas wells. All
As of September 30, 2021, Barnwell had interests in seven gross (0.20 net) producing oil wells were in Alberta, Canada.Oklahoma.
Developed Acreage and Undeveloped Acreage
The following table sets forth the gross and net acres of both developed and undeveloped oil and natural gas leases in Canada which Barnwell held as of September 30, 2020.2021. Proved oil and natural gas reserves located in the United States are not significant and are therefore not included in the table below.
| | | | Developed Acreage* | | Undeveloped Acreage* | | Total | | Developed Acreage* | | Undeveloped Acreage* | | Total |
| Location | Location | Gross | | Net | | Gross | | Net | | Gross | | Net | Location | Gross | | Net | | Gross | | Net | | Gross | | Net |
| Canada | Canada | 180,030 | | 36,710 | | 74,177 | | 12,600 | | 254,207 | | 49,310 | Canada | 156,980 | | 32,400 | | 36,230 | | 8,730 | | 193,210 | | 41,130 |
* “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-nineEighty-five percent of Barnwell’s undeveloped acreage is not subject to expiration at September 30, 2020. Eleven2021. Fifteen 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%6% expire during fiscal 2022; 5%7% expire during fiscal 2023; no expirations during fiscal 2024 and fiscal 2025.2025; and 2% expire during fiscal 2026. 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 (5,279Twining area (2,164 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 2020,2021, 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 20202021 and 2019,2020, 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.province. The province of Alberta and the 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 orremoval; currently all our 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.sold within Alberta.
All of Barnwell’s Canadian gross revenues were derived from properties located within Alberta, which charges oil and natural gas producers a royalty for production within the province. Provincial royalties are calculated as a percentage of revenue and vary depending on production volumes, selling prices and the date of discovery. Barnwell also pays gross overriding royalties and leasehold royalties on a portion of its oil and natural gas sales to parties other than the province of Alberta.
In January 2016, the Alberta Royalty Panel recommended a new modernized Alberta royalty framework which applies to wells drilled on or after January 1, 2017. The previous royalty framework will continue to apply to wells drilled prior to January 1, 2017 for a period of ten years, after which they will fall under the current royalty framework. Under the current royalty framework the same royalty calculation applies to both oil and natural gas wells, whereas the previous royalty framework had different royalties applicable to each category, and royalties are determined on a revenue minus cost basis where producers pay a flat royalty rate of 5% of gross revenues until a well reaches payout after which an increased post-payout royalty applies. Post payout royalties vary with commodity prices and are adjusted down for cost increases as wells age.
In fiscal 2021 and 2020, 45% and 2019, 44% and 47%, respectively, of royalties related to Alberta government charges, and 56%55% and 53%56%, respectively, of royalties related to freehold, override and other charges which are not directly affected by the Alberta royalty framework.
In fiscal 2020,2021, the weighted-average royalty rate paid on all of Barnwell’s natural gas was 7%8%, and the weighted-average royalty rate paid on oil was 11%12%.
Barnwell's oil and natural gas segment is currently subject to the provisions of the Alberta Energy Regulator's (“AER”) Licensee Liability Rating (“LLR”)AER’s LLR program. Under the LLR program the AER calculates a Liability Management Ratio (“LMR”)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, 2020,2021, 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 interest in the wells and facilities in the Manyberries area is included in “Asset retirement obligation” in the Consolidated Balance Sheets. Many 100% LGX ownedLGX-owned wells are to be reclaimed by the Orphan Well Association (“OWA”).OWA. However, as next largest interest holder in 78 of the82 wells and 67 facilities formerly operated by LGX, averaging 11%, the Company is required to take care and custody of those properties and to coordinate their closure.
OnIn 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. Theand the plan includesincluded 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 proposesproposed and intends 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
Recently, the OWA created a WIP program for specific areas where there are a significant number of orphaned wells to abandon. The OWA has the ability and expertise to abandon wells using its internal resources and network of service providers resulting in efficiencies that companies such as Barnwell, would not be able to obtain on its own. Under the WIP program, the Company would be required to provide payment for only Barnwell’s working interest share, however, all WIP’s would have to participate in the program for the OWA to begin its work. In March 2021, the Company was notified by the OWA that Barnwell’s Manyberries wells were confirmed to be incurred currently arein the WIP program.
Under the new agreement with the OWA, the Company is required to pay the abandonment and reclamation costs in advance through a cash deposit. The total cash deposit amount was calculated to be approximately $500,000,$1,525,000 and the Company paid $888,000 of the total deposit in July and August 2021 and will need to pay the remaining balance of $637,000 by August 2022. The Company revised its Manyberries ARO liability based on the OWA’s revised abandonment and reclamation estimates, which resulted in an increase of approximately $55,000 net$213,000 in the current year. The increase in the ARO liability was a result of higher reclamation and remediation costs than anticipated, partially offset by lower abandonment estimates. Based on a review of the details of the cash deposit calculation provided by the OWA, which includes amounts added for possible contingencies, the Company believes the required cash deposit amount by the OWA is higher than the actual costs of the asset retirement obligation for the Manyberries wells and that any excess of the deposit over actual asset retirement costs for the first phase
of the work would be credited toward the second phase of the work. A remaining excess deposit, if any, would ultimately be refunded to the Company 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% portionupon completion 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 closureall 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.work.
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. FifteenSixteen 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$303,000 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 $75,000amounting to $114,000.
The Company began participating in activities approved to date.non-operated oil and natural gas investments in Oklahoma in fiscal 2021, however such operations were not significant as they were only in the initial stages of development and production.
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, 6371 of which were sold from 2006 to 20202021 and of which 17nine 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. The remaining 420 developable acres at Increment II are entitled for up to 350 homesites. No definitive development plans have been made by the developer of Increment II as of the date of this report.
Kaupulehu Developments is entitled to receive payments from KD I based on 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, two2021, eight single-family lots in Increment I were sold bringing the total amount of gross proceeds from single-family lot sales through September 30, 20202021 to $219,700,000.$237,038,000.
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,II and Barnwell has a 10.8% indirect non-controlling ownership interest in KD II through KDK, as of that date that will continue to bewhich is accounted for using the equity method of accounting. Barnwell continues to have an indirect 19.6% non-controlling ownership interest in KD Kukio Resorts, KD Maniniowali, and KD I.
Concurrent withUnder the transaction whereby KDterms of the Increment II admitted Replay as a new development partner, Kaupulehu Developments entered into new agreementsagreement with KD II, whereby the aforementioned terms of
the former Increment II arrangement were eliminated and Kaupulehu Developments will instead beis entitled to 15% of the cumulative net profitsdistributions 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 willdoes 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%0.2% 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 2020,2021, the Kukio Resort Land Development Partnerships sold twoeight lots in Increment I and as a result of the lot sales, made cash distributions to its partners of which Barnwell received $360,000,$6,011,000, after distributing $20,000$683,000 to minority interests. Of the $360,000$6,011,000 net cash distribution received from the Kukio Resort Land Development Partnerships, $197,000$459,000 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, 2020.2021. See Note 64 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 Trillium Flow Technologies, previously known as 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 2020,2021, Water Resources started one well drilling and threefive pump installation and repair contracts and completed threesix pump and repair contracts. No well drilling contracts. No pump installation and repair contracts were completed in fiscal 2020. All of2021. Of the threesix completed well drillingpump and repair contracts, one was started in fiscal 2019, two were started in fiscal 2019. Sixty-five2020 and three were started in the current year. Fifty-six percent of well drilling and pump installation and repair jobs, representing 9%48% of total contract drilling revenues in fiscal 2020,2021, have been pursuant to government contracts.
At September 30, 2020,2021, there was a backlog of foursix well drilling and thirteenten pump installation and repair contracts, of which all fourfive well drilling and tennine pump installation and repair contracts were in progress as of September 30, 2020.2021.
The approximate dollar amount of Water Resources’ backlog of firm well drilling and pump installation and repair contracts at December 1, 20202021 and 20192020 was as follows:
| | | | December 1, | | December 1, |
| | | 2020 | | 2019 | | 2021 | | 2020 |
| Well drilling | Well drilling | $ | 4,700,000 | | | $ | 8,800,000 | | Well drilling | $ | 8,000,000 | | | $ | 4,700,000 | |
| Pump installation and repair | Pump installation and repair | 2,500,000 | | | 1,200,000 | | Pump installation and repair | 1,500,000 | | | 2,500,000 | |
| | | $ | 7,200,000 | | | $ | 10,000,000 | | | $ | 9,500,000 | | | $ | 7,200,000 | |
Of the contracts in backlog at December 1, 2020, $4,400,0002021, $5,900,000 is expected to be recognized in fiscal 20212022, $2,436,000 pertains to a government contract that expires in 2022 and may not be extended, 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 20202021 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, 2020,2021, Barnwell employed 4336 individuals; 4235 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. OnIn 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 ongoing global health crisis (including resurgences) resulting from the pandemic have, and continue to, disrupt 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 followingWhile the recommendationsoutbreak recently appeared to be trending downward, particularly as vaccination rates increased, new variants of localCOVID-19 continue emerging, including the highly transmissible Delta variant and federal health authorities to minimize exposure risk for its various stakeholders, including employees.
the newly-discovered Omicron variant (currently a “variant of concern”), spreading throughout the U.S. and globally and causing significant uncertainty. The global economy, our markets and our business have been, and may continue to be, materially and adversely affected by COVID-19. In the first calendar quarter of 2020, the
The COVID-19 outbreak caused significant reductions inmaterially and adversely affected our business operations and financial condition as a result of the deteriorating market outlook, the global economic recession and weakened liquidity. Although demand for oil and oil prices which madehas recovered from the Company's developmentlows of its proven undeveloped reserves uneconomicalMarch through May of the prior year, uncertainty regarding future oil prices has impacted and negatively impactedcontinues to impact 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 2021 and continues to work, the continuing potential impact of COVID-19 on the health of our contract drilling segment's crews and 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. Though availability of vaccines and reopening of state and local economies has improved the outlook for recovery from COVID-19's impacts, the impact of the Delta or Omicron variant or other new, more contagious or lethal variants that may emerge, the effectiveness of COVID-19 vaccines against the Delta or Omicron variant or such other variants and the related responses by governments, including reinstated government-imposed lockdowns or other measures, cannot be predicted at this time. Both the health and economic aspects of the COVID-19 pandemic remain highly fluid and the future course of each is uncertain. We cannot foresee whether the outbreak of COVID-19 will be effectively contained on a sustained basis, nor can we predict the severity and duration of its impact. If the outbreak of COVID-19 is not effectively and timely controlled on a sustained basis going forward, 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 orby 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 rulesIn order to maintain this listing, we must maintain certain share prices, financial and share distribution targets, including maintaining a minimum amount of stockholders’ equity and a minimum number of public stockholders. In addition to these objective standards, the NYSE American providemay delist the securities of any issuer if, in its opinion, the issuer’s financial condition and/or operating results appear unsatisfactory; if it appears that amongthe extent of public distribution or the aggregate market value of the security has become so reduced as to make continued listing on the NYSE American inadvisable; if the issuer sells or disposes of principal operating assets or ceases to be an operating company; if an issuer fails to comply with the NYSE American’s listing requirements; if an issuer’s common stock sells at what the NYSE American considers a “low selling price” (generally trading below $0.20 per share for an extended period of time); or if any other things,event occurs or any condition exists which makes continued listing on the NYSE American, in its opinion, inadvisable.
On January 13, 2020, the Company must meet certain continued listing standards relating to stockholders’ equity as set forthreceived notice from the NYSE American that the Company was not in Part 10,compliance with Section 1003(a)(i) and Section 1003(a)(ii) 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 requiresrespectively require an issuer to have (i) stockholders’ equity of $6.0$2.0 million or more if such issuer reported losses from continuing operations and/or net losses in two of its fivethree most recent fiscal years and (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 itwe reported stockholders’ equity of $1.2 million as of September 30, 2019 and net losses in three of the last four most recent fiscal years then ended, September 30, 2019, September 30, 2018 and September 30, 2016. Thethat the Company’s failure to meet the NYSE American’s stockholders’ equity requirements and the exceptions resulted in a risk that our common stock maycould be at risk of being delisted.
In accordance with the NYSE American’s policies and procedures, the Companywe subsequently submitted a plan (the “Plan”) addressing howto the Company intendedNYSE American detailing the steps we planned to take to raise our stockholders’ equity above $4.0 million and regain compliance with Part 10, Section 10031003(a)(i) and Section 1003(a)(ii) 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.
On July 13, 2021, (the “Plan Period”). Thethe Company has beenfiled a Form 8-K report with the Securities and will continueExchange Commission announcing that the Company’s pro forma stockholders’ equity (unaudited) as of July 13, 2021 was projected to be subjectabove the $4.0 million required to periodic review by Exchange Staff duringcomply with Section 1003(a)(i) and Section 1003(a)(ii) of the Plan Period. The Plan was submitted toGuide. Accordingly, in a letter dated July 14, 2021, the NYSE American beforedetermined the startCompany had resolved the continued listing deficiency with respect to Section 1003(a)(i) and Section 1003(a)(ii) of the COVID-19 pandemic-related low commodity price environment, the oil price war between Saudi ArabiaGuide 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. Ifnotified 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 inthat it had successfully regained compliance with the NYSE American continued listing standards relatingstandards.
Accordingly, the Company continues to stockholders’ equity to which the Plan relates; specifically Section 1003(a)(i) and Section 1003(a)(ii). The Company submitted updatesbe subject to the Plan, as required or requested bynormal continued listing criteria of the NYSE American. However, if the company, within 12 months of July 14, 2021, is again determined to be below any of the continued listing standards, the NYSE American in July 2020, August 2020 and September 2020. The September 2020 Plan updates presented initiatives which, if allstaff will examine the relationship between the two incidents 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’sfalling below continued listing standards. There is no assurance thatstandards and re-evaluate the presented initiatives will in fact be achieved. The Company has not yet received any correspondenceCompany's method of financial recovery from the NYSE American regardingfirst incident. It will then take appropriate action, which, depending upon the September 2020 Plan updates.circumstances, may include truncating the procedures described above or immediately initiating delisting proceedings. 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, 2020,2021, the CEO, who is a member of the Board of Directors, and two othersother stockholders hold approximately 36%39% of our outstanding common stock. The interests of one or more of these stockholders may not always coincide with the interests of other stockholders. These stockholders have significant influence over all matters submitted to our stockholders, including the election of our directors, and could accelerate, delay, deter or prevent a change of control of the Company. 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 7882 wells and 67 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 AERAER’s 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, 2020,2021, 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%57% in fiscal 2020.2021.
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;costs and which could delay or prevent development of the real estate held by the land development partnerships; and
•certain underlying partnership data is not accessible to us, therefore we depend on the general partner to provide us with reliable accounting information.
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%48% in fiscal 2020.2021. 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.
The occurrence of a natural disaster in Hawaii such as, but not limited to, earthquakes, landslides, hurricanes, tornadoes, tsunamis, volcanic activity, droughts and floods, could have a material adverse effect on our ability to complete our contracts.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 2. PROPERTIES
Oil and Natural Gas and Land Investment Properties
The location and character of Barnwell’s oil and natural gas properties and its land investment properties, are described above under Item 1, “Business.”
Corporate Offices
Barnwell, through a wholly-owned subsidiary, owns the 29th floor ofBarnwell's corporate headquarters is located in Honolulu, Hawaii, in a commercial office building under a lease that expires in downtown Honolulu that it uses as its corporate office and is currently available for sale.February 2024.
ITEM 3. LEGAL PROCEEDINGS
Barnwell is routinely involved in disputes with third parties that occasionally require litigation. In addition, Barnwell is required to maintain compliance with all current governmental controls and regulations in the ordinary course of business. Barnwell’s management is not aware of any claims or litigation involving Barnwell that are likely to have a material adverse effect on its results of operations, financial position or liquidity.
ITEM 4. MINE SAFETY DISCLOSURES
Disclosure is not applicable to Barnwell.
PART II
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Market Information
The principal market on which Barnwell’s common stock is being traded is the NYSE American under the ticker symbol “BRN.” The following tables present the quarterly high and low sales prices, on the NYSE American, for Barnwell’s common stock during the periods indicated:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 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 |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Quarter Ended | | High | | Low | | Quarter Ended | | High | | Low |
| December 31, 2019 | | $1.11 | | $0.30 | | December 31, 2020 | | $1.99 | | $0.76 |
| March 31, 2020 | | $2.68 | | $0.30 | | March 31, 2021 | | $6.99 | | $1.25 |
| June 30, 2020 | | $2.10 | | $0.44 | | June 30, 2021 | | $4.34 | | $2.02 |
| September 30, 2020 | | $1.64 | | $0.66 | | September 30, 2021 | | $3.59 | | $2.00 |
Holders
As of December 3, 2020,10, 2021, there were 8,277,1609,445,625 shares of common stock, par value $0.50, outstanding. As of December 3, 2020,10, 2021, there were approximately 80 shareholders of record and approximately 1,000 beneficial owners.
Dividends
No dividends were declared or paid during fiscal years 20202021 or 2019.2020. 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.expenditures and any other investments.
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, 20202021 and 2019,2020, and the related Consolidated Statements of Operations, Comprehensive Loss,Income (Loss), Equity (Deficit), and Cash Flows for the years ended September 30, 20202021 and 2019.2020. 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
OnIn 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 ongoing global health crisis (including resurgences) resulting from the pandemic have, and continue to, disrupt 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. While the outbreak recently appeared to be trending downward, particularly as vaccination rates increased, new variants of COVID-19 continue emerging, including the highly transmissible Delta variant and the newly-discovered Omicron variant (currently a “variant of concern”), spreading throughout the U.S. and globally and causing significant uncertainty. The global economy, our markets and our business have been, and may continue to be, materially and adversely affected by COVID-19.
The COVID-19 outbreak has causedmaterially and continues to cause significant reductions inadversely affected our business operations and financial condition as a result of the deteriorating market outlook, the global economic recession and weakened liquidity. Although demand for oil and oil prices which has causedrecovered from the Company to suspendlows of March through May of the development of proved undeveloped reserves andprior year, uncertainty regarding future oil prices 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 2021 and continues to work, the continuing potential impact of COVID-19 on the health of our contract drilling segment's crews and 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. Though availability of vaccines and reopening of state and local economies has improved the outlook for recovery from COVID-19's impacts, the impact of the Delta or Omicron variant or other new, more contagious or lethal variants that may emerge, the effectiveness of COVID-19 vaccines against the Delta or Omicron variant or such other variants and the related responses by governments, including reinstated government-imposed lockdowns or other measures, cannot be predicted at this time. Both the health and economic aspects of the COVID-19 pandemic remain highly fluid and the future course of each is uncertain. We cannot foresee whether the outbreak of COVID-19 will be effectively contained on a sustained basis, nor can we predict the severity and duration of its impact. If the outbreak of COVID-19 is not effectively and timely controlled on a sustained basis going forward, 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 orby 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
Our ability to sustain our business in the future will depend on sufficientthe sufficiency of our cash on hand, 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 and 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. In addition, as discussed in the "Asset Retirement Obligation" section of "Liquidity and Capital Resources," a significant amount of funds will be required to be put on deposit with Canadian regulatory authorities to fund abandonments at the Company's oil and natural gas properties in the Manyberries area. Other sources and potential sources of funding are discussed below.
In fiscal 2020, the Company listed its corporate office on the 29th floor of a commercial office building in downtown Honolulu, Hawaii for sale and on September 30, 2021, the Company’s Honolulu corporate office was sold for approximately $1,864,000, net of related costs.
On March 16, 2021, the Company initiated an at-the-market offering program (“ATM”) pursuant to which the Company may offer and sell, from time to time, shares of its common stock under price and volume guidelines set by the Company's Board of Directors and the terms and conditions described in the Registration Statement. The sale of shares under the ATM began in May 2021 and as of September 30, 2021, the Company sold 1,167,987 shares of common stock resulting in net proceeds of $3,784,000 after commissions and fees of $123,000.
In April 2021, the Company re-initiated the marketing of its non-core oil and natural gas properties in the Spirit River, Wood River, Medicine River, Kaybob, Bonanza, Balsam and Thornbury areas for sale. On July 8 2021, Barnwell entered into and completed a purchase and sale agreement with an independent third party and sold its interests in certain natural gas and oil properties located in the Spirit River area of Alberta, Canada. The sales price per the agreement was adjusted for customary purchase price adjustments to $1,047,000 in order to, among other things, reflect an economic effective closing date of sale of July 8, 2021. From Barnwell's net proceeds, $526,000 was withheld for remittance by the buyers to the Canada Revenue Agency for potential amounts due for Barnwell’s Canadian income taxes related to the sale. Negotiations regarding the potential sales of other non-core oil and natural gas properties is ongoing, however there is no assurance that the sale of any of the other non-core properties will occur.
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 duringDuring 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 as2021, continuing uncertainties regarding the potential duration and depth of the impacts of the COVID-19 pandemic on our business and the sufficiency of our cash balances and future cash inflows as described above raised substantial doubt about our ability to meet our estimated cash outflows or continue as a going concern. However, due to the $3,784,000 of net proceeds raised by the ATM through September 30, 2021, the proceeds received from the sale of the Company's corporate office and its interests in certain natural gas and oil properties in the Spirit River area, as well as the $7,156,000 of net cash inflows in the year ended September 30, 2021 from land segment percentage of sales proceeds and distributions from the Kukio Resort Land Development Partnerships, substantial doubt about our ability to meet our estimated cash outflows or continue as a going concern for one year from the date of the filing of this report exists.has been overcome.
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.properties . The ceiling limitation is the sum of 1) the discounted present value (at 10%), using average first-day-of-the-month prices during the 12-month period ending as of the balance sheet date held constant over the life of the reserves, of Barnwell’s estimated future net cash flows from estimated production of proved oil and natural gas reserves, less estimated future expenditures to be incurred in developing and producing the proved reserves but excluding future cash outflows associated with settling asset retirement obligations with the exception of those associated with proved undeveloped reserves from wells that are to be drilled in the future; plus 2) the cost of major development projects and unproven properties not subject to depletion, if any; plus 3) the lower of cost or estimated fair value of unproven
properties included in costs subject to depletion; less 4) related income tax effects. If net capitalized costs exceed this limit, the excess is expensed.
All items classified as unevaluated and unproved properties are assessed on a quarterly basis for possible impairment or reduction in value. Properties are assessed on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of various factors, including, but not limited to, the following: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; assignment of proved reserves; and economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and become subject to amortization.
Judgments and Assumptions
The estimate of our oil and natural gas reserves is a major component of the ceiling calculation and represents the component that requires the most subjective judgments. Estimates of reserves are forecasts based on engineering data, historical data, projected future rates of production and the timing of future expenditures. The process of estimating oil and natural gas reserves requires substantial judgment, resulting in imprecise determinations, particularly for new discoveries. Our reserve estimates are prepared at least annually by independent petroleum reserve engineers. The passage of time provides more quantitative and qualitative information regarding estimates of reserves, and revisions are made to prior estimates to reflect updated information. A portion of the revisions are attributable to changes in the rolling 12-month average first-day-of-the-month prices, which impact the economics of producible reserves. In the last three fiscal years, annual revisions to our reserve volume estimates have averaged 27%
36% 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 2020,2021, the ceiling limitation would have decreased approximately $141,000$398,000 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 20202021 of approximately $500,000.$5,716,000.
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 2020,2021, depletion for fiscal 20202021 would have increased by approximately $82,000.$26,000.
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
Management evaluates the performance of contracts on an individual basis. In the ordinary course of business, but at least quarterly, we prepare updated estimates that may impact the cost and profit or loss for each contract based on actual results to date plus management’s best estimate of costs to be incurred to complete each performance obligation. Increases or decreases in the estimated costs to complete a performance obligation without a change to the contract price has the impact to decrease or increase,
respectively, the contract completion percentage applied to the contract price to calculate the cumulative contract revenue to be recognized to date. Changes in the cost estimates can have a material impact on our contract revenue and are reflected in the results of operations when they become known. The nature of accounting for these contracts is such that refinements of the estimated costs to complete may occur and are characteristic of the estimation process due to changing conditions and new developments. Many factors and assumptions can and do change during a contract performance obligation period which can result in a change to contract profitability including unforeseen underground geological conditions (to the extent that contract remedies are unavailable), the availability and costs of skilled contract labor, the performance of major material suppliers, the performance of major subcontractors, unusual weather conditions and unexpected changes in material costs, changes in the scope and nature of work to be performed, and unexpected construction execution errors, among others. Any revisions to estimated costs to complete the performance obligation from period to period as a result of changes in these factors can materially affect revenue and operating results in the period such revisions are necessary. In addition, many contracts give the customer a unilateral right to cancel for convenience or other than for cause. In accordance with FASB ASC 606-10-32-4, our estimates are based on the assumption that the existing contract will not be cancelled. Any unforeseen cancellation of a contract may result in a material revision to our estimates.
We have a long history of working with multiple types of projects and preparing cost estimates, and we rely on the expertise of key personnel to prepare what we believe are reasonable best estimates
given available facts and circumstances. Due to the nature of the work involved, however, judgment is involved to estimate the costs to complete and the amounts estimated could have a material impact on the revenue we recognize in each accounting period. We can not estimate unforeseen events and circumstances which may result in actual results being materially different from previous estimates.
Income Taxes
Policy Description
Income taxes are determined using the asset and liability method. Deferred tax assets and liabilities are recognized for the estimated future tax impacts of differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the year in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.
Deferred income tax assets are routinely assessed for realizability. A valuation allowance is provided when it is more likely than not that some portion or all of the deferred tax asset will not be realized.
Barnwell recognizes the financial statement effects of tax positions when it is more likely than not that the position will be sustained by a taxing authority.
Judgments and Assumptions
We make estimates and judgments in determining our income tax expense for each reporting period. Significant changes to these estimates could result in an increase or decrease in our tax provision in future periods. We are also required to make judgments about the recoverability of deferred tax assets and when it is more likely than not that all or a portion of deferred tax assets will not be realized, a
valuation allowance is provided. We consider available positive and negative evidence and available tax planning strategies when assessing the realizability of deferred tax assets. Accordingly, changes in our business performance and unforeseen events could require a further increase in the valuation allowance or a reversal in the valuation allowance in future periods. This could result in a charge to, or an increase in, income in the period such determination is made, and the impact of these changes could be material.
In addition, Barnwell operates within the U.S. and Canada and is subject to audit by taxing authorities in these jurisdictions. Barnwell records accruals for the estimated outcomes of these audits, and the accruals may change in the future due to new developments in each matter. Tax benefits are recognized when we determine that it is more likely than not that such benefits will be realized. Management evaluates its potential exposures from tax positions taken that have or could be challenged by taxing authorities. These potential exposures result because taxing authorities may take positions that differ from those taken by management in the interpretation and application of statutes, regulations and rules. Management considers the possibility of alternative outcomes based upon past experience, previous actions by taxing authorities (e.g., actions taken in other jurisdictions) and advice from tax experts. Where uncertainty exists due to the complexity of income tax statutes and where the potential tax amounts are significant, we generally seek independent tax opinions to support our positions. If our evaluation of the likelihood of the realization of benefits is inaccurate, we could incur additional income tax and interest expense that would adversely impact earnings, or we could receive tax benefits greater than anticipated which would positively impact earnings, either of which could be material.
Overview
Barnwell is engaged in the following lines of business: 1) acquiring, developing, producing and selling oil and natural gas in Canada and Oklahoma (oil and natural gas segment), 2) investing in land interests in Hawaii (land investment segment), and 3) drilling wells and installing and repairing water pumping systems in Hawaii (contract drilling segment).
Oil and Natural Gas Segment
Barnwell is involved in the acquisition and development of oil and natural gas properties 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. Additionally, through its wholly-owned subsidiary BOK, Barnwell is indirectly involved in several non-operated oil and natural gas investments in Oklahoma.
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. Inventory of unsold lots at Increment I is an area zoned for approximately 80were nine 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.2021.
•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,Barnwell. Two developed single-family lots were sold in compensationIncrement II in prior years and the remaining 420 developable acres at Increment II are entitled for up to 350 homesites. The remaining acreage within Increment II is not yet under development, and there is no assurance that development of such acreage will in fact occur. No definitive development plans have been made by the agreementdeveloper of these parties to admitIncrement II as of the new development partner for Increment II.date of this report.
•Prior to March 7, 2019, we had anAn 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 haveKD I and 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 Kaupulehu Lot 4A Increments I and II. The partnerships derive income from the sale of residential parcels as well as from commissioncommissions on real estate sales by the real estate sales office. KD I has engaged Replay as a consultant to assist withoffice and revenues resulting from the sales and marketing strategysale of Increment I. Replay does not have an ownership interest in KD I.private club memberships.
•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 statestates of Hawaii.Hawaii and Oklahoma. Accordingly, our business performance is directly affected by macroeconomic conditions in those areas, as well as general economic conditions of the U.S. domestic and world economies.
Oil and Natural Gas Segment
Barnwell realized an average price for oil of $33.85$51.74 per barrel during the year ended September 30, 2020, a decrease2021, an increase of 19%53% from $41.84$33.85 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 recordthe significant lows of March and May of the prior year, 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$2.62 per Mcf during the year ended September 30, 2020,2021, an increase of 43%60% from $1.15$1.64 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 17nine residential lots within Increment I by KD I and potential future development or sale of the remaining portion of Increment II by KD II of Kaupulehu Lot 4A. The amount and timing of future land investment segment proceeds from percentage of sales payments and cash distributions from the Kukio Resort Land Development Partnerships are highly uncertain and out of our control, and there is no assurance with regards to the amounts of future sales of residential lots within Increments I and II. No definitive development plans have been made by the developer of Increment II as of the date of this report.
Barnwell estimates that it will be heavilypartially reliant upon land investment segment proceeds in order to provide sufficient liquidity to fund our operations in 20212022 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 20212022 will be significantly lower than fiscal 20202021 based upon the number and value of contracts in backlog.
Results of Operations
Summary
Net lossearnings attributable to Barnwell for fiscal 20202021 totaled $4,756,000, a $7,658,000$6,253,000, an $11,009,000 increase in operating results from a net loss of $12,414,000$4,756,000 in fiscal 2019.2020. 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$6,653,000 improvement in contract drillingoil and natural gas 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$4,326,000 in the prior year period, compared to $4,326,000a ceiling test impairment of $630,000 in the current year period, and $287,000 higher revenues and $363,000 lower operating expenses and
period. Also contributing to the increase was a $933,000 decreasesignificant increase in the oil and natural gas depletionprices in the current year period as compared to the same period in the prior year; and
•A $628,000$5,441,000 increase in equity in income from affiliates as a result of increased operating results of the Kukio Resort Land Development Partnerships.Partnerships;
45
•A $1,463,000 increase in land investment segment operating results, before non-controlling interests’ share of such profits, due to the sale of eight lots in the current period, whereas there were only two lot sales in the same period in the prior year;
•A $2,341,000 gain recognized in the current year period from the termination of the Company’s Post-retirement Medical plan and $1,982,000 in gains from the sales of assets in the current year period;
•A $3,214,000 decrease in contract drilling segment operating results, before income taxes, primarily resulting from decreased activity attributable to a significant well drilling contract as this contract was essentially completed as of December 31, 2020;
•A $1,268,000 increase in general and administrative expenses primarily due to increases in share-based compensation expense, bonuses and director fees, and costs related to the cooperation and support agreement with the MRMP Stockholders in the current year period as compared to the same period in the prior year, partially offset by a reduction in legal fees in the current year period as compared to the same period in the prior year; and
•A $1,336,000 gain recognized in the prior 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, whereas there was no such gain in the current period.
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%increased 6% in fiscal 2020,2021, as compared to fiscal 2019,2020, and the exchange rate of the Canadian dollar to the U.S. dollar remained relatively the same rateincreased 5% at September 30, 2020,2021, as compared to September 30, 2019.2020. 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 assetsliabilities are greater than its Canadian dollar liabilities;assets; therefore, increases or decreases in the value of the Canadian dollar to the U.S. dollar generate other comprehensive incomeloss or loss,income, respectively. Other comprehensive income and losses are not included in net loss.earnings (loss). Other comprehensive loss due to foreign currency translation adjustments, net of taxes, for fiscal 20202021 was $146,000, an $88,000 decrease$283,000, a $137,000 change from other comprehensive loss due to foreign currency translation adjustments, net of taxes, of $234,000$146,000 in fiscal 2019.2020. There were no taxes on other comprehensive loss due to foreign currency translation adjustments in fiscal 20202021 and 20192020 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 20202021 as compared to fiscal 2019.2020. Production amounts reported are net of royalties.
| | | | Annual Average Price Per Unit | | Annual Average Price Per Unit |
| | | | | | | Increase (Decrease) | | | | | | Increase (Decrease) |
| | | 2020 | | 2019 | | $ | | % | | 2021 | | 2020 | | $ | | % |
| Natural gas (Mcf)* | Natural gas (Mcf)* | $ | 1.64 | | | $ | 1.15 | | | $ | 0.49 | | | 43% | Natural gas (Mcf)* | $ | 2.62 | | | $ | 1.64 | | | $ | 0.98 | | | 60% |
| Oil (Bbls) | Oil (Bbls) | $ | 33.85 | | | $ | 41.84 | | | $ | (7.99) | | | (19)% | Oil (Bbls) | $ | 51.74 | | | $ | 33.85 | | | $ | 17.89 | | | 53% |
| Liquids (Bbls) | Liquids (Bbls) | $ | 17.16 | | | $ | 25.84 | | | $ | (8.68) | | | (34)% | Liquids (Bbls) | $ | 31.92 | | | $ | 17.16 | | | $ | 14.76 | | | 86% |
| | | | Annual Net Production | | Annual Net Production |
| | | | | | | Increase (Decrease) | | | | | | Increase (Decrease) |
| | | 2020 | | 2019 | | Units | | % | | 2021 | | 2020 | | Units | | % |
| Natural gas (Mcf) | Natural gas (Mcf) | 649,000 | | | 628,000 | | | 21,000 | | | 3% | Natural gas (Mcf) | 694,000 | | | 649,000 | | | 45,000 | | | 7% |
| Oil (Bbls) | Oil (Bbls) | 153,000 | | | 123,000 | | | 30,000 | | | 24% | Oil (Bbls) | 147,000 | | | 153,000 | | | (6,000) | | | (4)% |
| Liquids (Bbls) | Liquids (Bbls) | 21,000 | | | 18,000 | | | 3,000 | | | 17% | Liquids (Bbls) | 24,000 | | | 21,000 | | | 3,000 | | | 14% |
* Natural gas price per unit is net of pipeline charges.
The oil and natural gas segment generated a $4,230,000$2,423,000 operating lossprofit in fiscal 20202021 before general and administrative expenses, an increase in operating results of $2,967,000$6,653,000 as compared to
$7,197,000 $4,230,000 of operating loss in fiscal 2019.2020. There was a $4,326,000$630,000 ceiling test impairment included in the operating lossprofit in the current year as compared to a $5,710,000$4,326,000 ceiling test impairment in the prior year.
Oil and natural gas revenues increased $287,000 (4%$3,561,000 (53%) from $6,406,000 in fiscal 2019 to $6,693,000 in fiscal 2020 to $10,254,000 in fiscal 2021, primarily due to an increasesignificant increases in oil, production from new wells drilled in fiscal 2020 in the Spirit River and Twining areas, and an increase in natural gas and natural gas liquids prices in the current year period as compared to the prior year period. The increase in oil production from the two new wellssame periods in the Spirit River and Twining areas and oil production from minor acquisitions inprior as prior year's commodity prices were impacted by 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.COVID-19 pandemic.
Oil and natural gas operating expenses decreased $363,000 (7%increased $1,706,000 (35%) from $5,213,000 in fiscal 2019 to $4,850,000 in fiscal 2020 to $6,556,000 in fiscal 2021, primarily due to significant repairequalization of operating costs related to processing facilities and maintenance costs at the Twining property includedworkovers in the priorcurrent year period and to a lesser degree due to carbon taxes, whereas there were no such costs in the currentprior year period. The decrease was alsoperiod, as well as due to shut-in of wells with relatively highlower operating costs and reductions in operator time and discounted costs obtained from vendors that were negotiated in light of the extremelyprior year period due to the aforementioned low oilcommodity prices.
Oil and natural gas segment depletion decreased $933,000$1,102,000 from $2,680,000 in fiscal 2019 to $1,747,000 in fiscal 2020 to $645,000 in fiscal 2021, 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.year.
The well drilled in the Spirit River area commencedNet oil 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 net2021 decreased 4% due largely to a natural decline in oil production from this well averaged over 200 barrels per day during the first month of production but has since declinedSpirit River area as compared 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 producingprior year period. In addition, the Company sold its oil and natural gas properties in January 2020. This well contributed approximately 15,900 barrels of net oilthe Spirit River area in July 2021. The
decrease was partially offset by an increase in production from January through September 2020, representing 10% total net oilthe Twining area due largely to the acquisition of additional wells in the area. Net natural gas and natural gas liquids production forincreased 7% and 14%, respectively, as compared to the same period of the prior year, ended September 30, 2020. The well was temporarily shut-in from mid-April 2020also due largely to mid-May 2020the acquisition of additional wells in the Twining area, partially offset by a decrease in production due to decreasedthe sale of oil prices. Recent net oil production from this well was approximately 103 barrels per day.and natural gas properties in the Hillsdown area in April 2021.
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 recordthe significant lows of March through May of the prior year, 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, | | Year ended September 30, |
| | | 2020 | | 2019 | | 2021 | | 2020 |
| Sale of interest in leasehold land: | Sale of interest in leasehold land: | | | | Sale of interest in leasehold land: | | | |
| Revenues - sale of interest in leasehold land | Revenues - sale of interest in leasehold land | $ | 325,000 | | | $ | 165,000 | | Revenues - sale of interest in leasehold land | $ | 1,738,000 | | | $ | 325,000 | |
| Fees - included in general and administrative expenses | Fees - included in general and administrative expenses | (40,000) | | | (20,000) | | Fees - included in general and administrative expenses | (212,000) | | | (40,000) | |
| Sale of interest in leasehold land, net of fees paid | Sale of interest in leasehold land, net of fees paid | $ | 285,000 | | | $ | 145,000 | | Sale of interest in leasehold land, net of fees paid | $ | 1,526,000 | | | $ | 285,000 | |
During the year ended September 30, 2021, Barnwell received $1,738,000 in percentage of sales payments from KD I from the sale of eight single-family lots within Phase II of Increment I. 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, subsequentSubsequent to the close of the year ended September 30, 2020,2021, Kaupulehu Developments received a percentage of sales payment of $170,000payments totaling $600,000 from the sale of one lotthree lots within Phase II of Increment I. Financial results from the receipt of thisthese payment will be reflected in Barnwell's quarter ending December 31, 2020.2021. Accordingly, with the inclusion of the lot sale in November 2020, 16sales subsequent to September 30, 2021, six 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.II, or that the remaining acreage within Increment II will be developed. No definitive development plans have been made by the developer of Increment II as of the date of this report.
Contract drilling
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%decreased $5,185,000 (47%) to $5,809,000 in fiscal 2021, as compared 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%decreased $1,958,000 (26%) to $5,555,000 in fiscal 2021, as compared to $7,513,000 in fiscal 2020, as compared to $4,973,000 in fiscal 2019.2020. The contract drilling segment generated a $3,125,000an $89,000 operating profitloss before general and administrative expenses during fiscal 2020, an increase2021, a decrease in operating
results of $3,036,000$3,214,000 as compared to an operating profit before general and administrative expenses of $89,000$3,125,000 in fiscal 2019.2020. The increasedecrease in operating results was primarily due to a significant well drilling contract in the prior year period. The significant well drilling contract was for multiple wells that isand was 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 currentprior year period with crews working extended hours. The current period increaseHowever, activity related to this contract was essentially completed 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 yearquarter ended September 30,December 31, 2020 has declined since September 30, 2020,
as the aforementioned significant well drilling contract is nearing completion, such thatand thus contract drilling revenues are anticipated to declineand costs have decreased in fiscal 2021the current year period as compared to fiscal 2020 based on the number and valuesame period of contracts in backlog.the prior year.
At September 30, 2020,2021, there was a backlog of foursix well drilling and thirteenten pump installation and repair contracts, of which all fourfive well drilling and tennine pump installation and repair contracts were in progress as of September 30, 2020.2021. The backlog of contract drilling revenues as of December 1, 20202021 was approximately $7,200,000,$9,500,000, of which $4,400,000$5,900,000 is expected to be realized in fiscal 20212022 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 lowerhigher in fiscal 20212022 as compared to fiscal 2020.2021.
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, the estimated total rework costs to remediate the situation have beenwas accrued at September 30, 2020. As a result of allIn January 2021, the broken drill string was retrieved from the well borehole and drilling 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.replacement well recommenced.
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, 20202021 as there is no probable or estimable contingent liability.
In 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 werewas 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 settlementdropped in lieu of the penalties and fines whereby the named parties would be responsible for providing the Commission with assistanceentering into an agreement to monitor the aquifer, at no cost to the Commission, to aid in the Commission’s efforts to monitorperform a water quality in the subject area. The Companystudy 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.repurpose a current well into a monitoring well. Accordingly, the Company recorded a contingent liability of approximately $300,000 at September 30, 2020.2020 and no subsequent revision to the accrual has been recorded as of September 30, 2021.
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 remained operational throughout fiscal 2020 and 2021 and continues to work, the continuing potential impact of COVID-19 on the health of our contract drilling segment's crew and 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%$1,268,000 (22%) to $7,088,000 in fiscal 2021, as compared to $5,820,000 in fiscal 2020, as compared to $5,524,000 in fiscal 2019.2020. The increase was primarily due to increased proxy legalincreases in share-based compensation expense, bonuses and director fees, and costs proxy solicitation, proxy advisory, public relations costsrelated to the cooperation and bad debt expensesupport agreement with the MRMP Stockholders as discussed below, in the current year period as compared to the same period in the prior year. The increase was partially offset by lower compensationa reduction in fees related to legal services, proxy solicitation, proxy advisory, and public relation costs in the current year period as compared to the same period in the prior year.
In January 2021, the Company entered into a cooperation and support agreement with MRMP-Managers LLC, Ned L. Sherwood Revocable Trust, Ned L. Sherwood and Bradley M. Tirpak (collectively, the “MRMP Stockholders”), with respect to the potential proxy contest pertaining to the election of directors to our Board of Directors. Pursuant to the terms of the agreement, among other things, the Company and the MRMP Stockholders agreed on certain nominations and voting with respect to the directors nominated to stand for reelection to the Board of Directors at the 2021 annual meeting of stockholders, which was held on April 20, 2021. The Company agreed to reimburse the MRMP Stockholders for their reasonable, documented out-of-pocket fees and expenses (including legal expenses) of up to a maximum of $300,000 in connection with the MRMP Stockholders’ election contest at the Company’s 2020 annual meeting of stockholders and the negotiation of this agreement and accordingly, incurred approximately $296,000 in expenses related to this agreement in the year ended September 30, 2021.
Depletion, depreciation, and amortization
Depletion, depreciation, and amortization decreased $875,000 (29%$1,184,000 (55%) in fiscal 20202021 as compared to fiscal 20192020 primarily due to thea decrease in the oil and natural gas depletion rates as a result of ceiling test impairment write-downs in the prior year 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$630,000 during the year ended September 30, 2020.2021. There was a $5,710,000$4,326,000 ceiling test impairment during the year ended September 30, 2019.2020.
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
In September 2021, the Company haddesignated a contract drilling segment drilling rig and related ancillary equipment, with an aggregate net carrying value of $725,000, as assets held for sale and recorded an impairment of $38,000 to reduce the abilityvalue of these assets to fund allits fair value, less estimated selling costs. The fair value of the future capital expenditures necessary over the next five years to develop proved undeveloped reservesthese assets in the Twining areaaggregate amount of Alberta, Canada. However, due to the impact on oil prices and the extreme uncertainties created by the COVID-19 pandemic$687,000 is recorded as “Assets held for sale” 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 remainConsolidated Balance Sheet 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.September 30, 2021.
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 termination of Post-Retirement Medical plan
In June 2021, the Company terminated its Post-retirement Medical plan, which covered officers of the Company who had attained at least 20 years of service of which at least 10 years were at the position of Vice President or higher, their spouses and qualifying dependents, effective June 4, 2021. Pursuant to the Post-retirement Medical plan document, the Company, as the sponsor of the Post-retirement Medical plan, had the right to terminate the plan within sixty days’ notice to each participant and the plan may be terminated by the resolution of the Board of the Directors of the Company. Further, under the terms of the plan document, the participants in the Post-retirement Medical plan were not entitled to any unpaid vested benefits thereunder upon plan termination. The Post-retirement Medical plan was an unfunded plan and the Company funded benefits when payments were made. As a result of the plan termination, the Company recognized a non-cash gain of $2,341,000 during the year ended September 30, 2021.
Gain on sale of assets
On July 8, 2021, Barnwell entered into and completed a purchase and sale agreement with an independent third party and sold its interests in certain natural gas and oil properties located in the Spirit River area of Alberta, Canada. The sales price per the agreement was adjusted for customary purchase price adjustments to $1,047,000 in order to, among other things, reflect an economic effective closing date of sale of July 8, 2021. From Barnwell's net proceeds, $526,000 was withheld for remittance by the buyers
to the Canada Revenue Agency for potential amounts due for Barnwell’s Canadian income taxes related to the sale.
The difference in the relationship between capitalized costs and proved reserves of the Spirit River properties sold as compared to the properties retained by Barnwell was significant as there was a 93%difference in capitalized costs divided by proved reserves if the gain was recorded versus the gain being credited against the full-cost pool. Accordingly, Barnwell recorded a gain on the sale of Spirit River of $818,000 in the year ended September 30, 2021 in accordance with the guidance in Rule 4-10(c)(6)(i) of Regulation S-X of the rules and regulations of the SEC, which requires an allocation of capitalized costs to the reserves sold and reserves retained on the basis of the relative fair values of the properties as there was a substantial economic difference between the properties sold and those retained. Also included in the gain calculation were asset retirement obligations of $77,000 assumed by the purchaser.
On September 30, 2021, the Company’s Honolulu corporate office was sold for approximately $1,864,000, net of related costs, resulting in a gain of $1,164,000, which was recognized in the year ended September 30, 2021.
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$5,793,000 in fiscal 2020,2021, as compared to allocated lossesincome of $276,000$352,000 in fiscal 2019.2020. The increase in the allocated partnership income is primarily due to the Kukio Resort Land Development Partnerships' sale of twoeight lots during the current year, whereas there was onewere two lot salesales in the prior year, and anyear. In addition, there was a significant increase in real estate resale activity in the current year period for which the Kukio Resort Land Development Partnerships' real estate sales office earns commissions revenue, as comparedwell as an increase in the Kukio Resort Land Development Partnerships' revenues related to the prior year period. Additionally, thean increase in club memberships sold.
The increase is also attributed to a $197,000 partial payment distributions received from the Kukio Resort Land Development Partnerships in excess of our investment balance of $654,000 which was recorded as income during the year ended September 30, 2021 and $459,000 in preferred return payments received from KKM in the year ended September 30, 2021.
During the year ended September 30, 2021, the Company received cumulative distributions from the Kukio Resort Land Development Partnerships in excess of our investment balance and in accordance with applicable accounting guidance, the Company suspended its equity method earnings recognition and reduced its Kukio Resort Land Development Partnership investment balance to zero as of September 30, 2021. In addition, the Company recorded the distributions received in excess of our investment balance of $654,000 as equity in income of affiliates during the year ended September 30, 2021. The Company records the distributions in excess of our investment in the Kukio Resort Land Development Partnerships as income because the distributions are not refundable by agreement or by law and the Company is not liable for the obligations of or otherwise committed to provide financial support to the Kukio Resort Land Development Partnerships. The Company will record future equity method earnings only after our share
of the preferred return from KKM, as discussed below.Kukio Resort Land Development Partnership’s cumulative earnings during the suspended period exceeds our share of the Kukio Resort Land Development Partnership’s income recognized for the excess distributions.
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.ratios of 75% and 34.45%, respectively. Additionally, Barnwell iswas 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 Augustthe quarter ended December 31, 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.I. Accordingly, Barnwell received a $197,000 partial paymenttotal of the$459,000 in preferred return in August 2020,payments, 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, 2020.2021. The preferred return payments received after September 30,in the quarter ended December 31, 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 September 30, 2021.
During the dateyear ended September 30, 2021, Barnwell received net cash distributions in the amount of this report.$6,011,000 from the Kukio Resort Land Development Partnerships after distributing $683,000 to non-controlling interests. Of the $6,011,000 net cash distribution received from the Kukio Resort Land Development Partnerships, $459,000 represented a partial payment of the preferred return from KKM, as discussed above.
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.KKM.
DuringSubsequent to the close of the year ended September 30, 2019, Barnwell2021, Kaupulehu Developments received net cash distributions in the amountpercentage of $314,000sales payments totaling $600,000 from the Kukio Resort Land Development Partnerships after distributing $38,000sale of three lots within Phase II of Increment I. Financial results from the receipt of these payment will be reflected in Barnwell's quarter ending December 31, 2021. Accordingly, with the inclusion of the lot sales subsequent to non-controllingSeptember 30, 2021, six single-family lots of the 80 lots developed within Increment I remained to be sold as of the date of this report. The Company does not have a controlling interest in Increments I and II, and there is no assurance with regards to the amounts of future sales from Increments I and II, or that the remaining acreage within Increment II will be developed. No definitive development plans have been made by the developer of Increment II as of the date of this report.
Income taxes
The components of lossearnings (loss) before income taxes, after adjusting the lossearnings (loss) for non-controlling interests, are as follows:
| | | | Year ended September 30, | | Year ended September 30, |
| | | 2020 | | 2019 | | 2021 | | 2020 |
| United States | United States | $ | 1,518,000 | | | $ | (3,039,000) | | United States | $ | 5,436,000 | | | $ | 1,518,000 | |
| Canada | Canada | (6,271,000) | | | (9,606,000) | | Canada | 1,149,000 | | | (6,271,000) | |
| | | $ | (4,753,000) | | | $ | (12,645,000) | | | $ | 6,585,000 | | | $ | (4,753,000) | |
Barnwell’s effective consolidated income tax benefit rate for fiscal 2020,2021, after adjusting lossearnings (loss) before income taxes for non-controlling interests, was nil5% as compared to 2%nil 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 beenwas enacted as of September 30,in the quarter ended December 31, 2020. Canadian deferred tax assets and liabilities have been measured using the enacted tax rates in effect for the year in which the differences are expected to reverse. Alberta rate changes 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$950,000 in fiscal 2020,2021, as compared to net lossearnings attributable to non-controlling interests of $3,000$79,000 in fiscal 2019.2020. The $82,000 (2,733%$871,000 (1,103%) increase is primarily due to an increaseincreases in the amount of Kaupulehu Developments' and Kukio Resort Land Development Partnerships’Partnerships' income and percentage of sales proceeds received 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.proceeds, and starting in fiscal 2021, funds generated by the ATM program. At September 30, 2020,2021, Barnwell had $3,123,000$12,134,000 in working capital.
Cash Flows
Cash flows provided by operating activities totaled $750,000$831,000 for fiscal 2020,2021, as compared to cash flows usedprovided by operating activities of $2,133,000$750,000 for the same period in fiscal 2019.2020. This $2,883,000$81,000 change in operating cash flows was primarily due to a significant increase in distributions of income from the Kukio Resort Land Development Partnerships in the current year period, as compared to the prior year, and higher operating results, before non-cash impairment expenses, for the oil and natural gas segment, which was partially offset by significantly higherlower operating results for the contract drilling segment in the current year period as compared to the prior year period and changesperiod. The change was also due to fluctuations in working capital, primarily attributed to fluctuations in contract liabilitiesother current assets and accounts payable in the current period as compared to the prior year period.
Net cash provided by investing activities totaled $3,686,000 for fiscal 2021, as compared to net cash used in investing activities totaledof $833,000 for fiscal 2020, as compared to net cash provided by investing activities of $905,000 for fiscal 2019.2020. The $1,738,000 decrease$4,519,000 increase in investing cash flows was primarily due to $741,000 in maturitiesa decrease 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$1,193,000 in cash usedpaid for oil and natural gas capital expenditures, mainly attributed to two new wells drilleda $1,241,000 increase in the Twining and Spirit River areas in the current period, as compared to the prior year period. These items were partially offset bypercentage of sales proceeds received, net of fees, an increase of $1,100,000$1,344,000 received in distributions from equity investees in excess of earnings, and a net increase of $764,000 in proceeds from the sale of assets related to the sale of the Company's Honolulu corporate office in the current year period attributed toand 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$2,192,000 for fiscal 2020,2021, as compared to cash used inflows provided by financing activities of $110,000$60,000 for fiscal 2019.2020. The $170,000$2,132,000 change in financing cash flows was primarily attributed to an increase$3,179,000 in proceeds from issuance of $147,000 in long-term debt borrowings attributedstock, net of costs, related to the PPP loan received duringCompany's ATM offering in the current year period. This changeperiod as compared to none in the prior year period, which was partially offset by $87,000an increase of $947,000 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 CARESCoronavirus Aid, Relief, and Economic Security Act (“CARES”) that was signed into law in March 2020. The note matureswas to mature two years after the date of the loan disbursement and bearswith interest at a fixed annual rate of 1.00%, and with the first six months of principal and interest deferred. Underpayments deferred until ten months after the termslast day 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.
covered period. In October 2020,April 2021, the Company was notified by the lender of our PPP loan that the entire PPP loan amount and related accrued interest was forgiven by the Small Business Administration. As a result of changesthe loan forgiveness, the Company recognized a gain on debt extinguishment of $149,000 during the year ended September 30, 2021.
Canada Emergency Business Account Loan
In the quarter ended December 31, 2020, the Company’s Canadian subsidiary, Barnwell of Canada, received a loan of CAD$40,000 under the Canada Emergency Business Account (“CEBA”) loan program for small businesses. In the quarter ended March 31, 2021, the Company applied for an increase to our CEBA loan and received an additional CAD$20,000 for a total loan amount received of CAD$60,000 ($47,000) under the program. The CEBA loan is interest-free with no principal payments required until December 31, 2022, after which the remaining loan balance is converted to a three year term loan at 5% annual interest paid monthly. If the Company repays 66.6% of the principal amount prior to December 31, 2022, there will be loan forgiveness of 33.3% up to a maximum of CAD$20,000.
At The Market Offering
On March 16, 2021, the Company entered into a Sales Agreement with A.G.P./Alliance Global Partners (“A.G.P,”), with respect to the ATM pursuant to which the Company may offer and sell, from time to time, shares of its common stock, par value $0.50 per share, having an aggregate sales price of up to $25 million (subject to certain termslimitations at any time our public float remains under $75 million), through or to A.G.P as the Company’s sales agent or as principal. Sales of our PPP loancommon stock under the ATM, if any, will be made by any methods deemed to conform withbe “at the amendmentsmarket offerings” as defined in Rule 415(a)(4) under the Securities Act, including sales made directly on the NYSE American, on any other existing trading market for our Common Stock, or to the CARES Act implemented by the Flexibility Act which included, but was not limited to, the extensionor through a market maker. Shares of the initial deferment period of the loan’scommon stock
principalsold under the ATM are offered pursuant to the Company’s Registration Statement on Form S-3 (File No. 333-254365), filed with the Securities and interest payments from six months to ten months afterExchange Commission on March 16, 2021, and declared effective on March 26, 2021 (the "Registration Statement”), and 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 isprospectus dated March 26, 2021, included 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.Registration Statement.
Canada Emergency Wage Subsidy
DuringThe sale of shares under the year endedATM began in May 2021 and as of 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,2021, the Company received a totalsold 1,167,987 shares of approximately $82,000common stock resulting 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.net proceeds of $3,784,000 after commissions and fees of $123,000.
Going Concern
Our ability to sustain our business in the future will depend on sufficientthe sufficiency of our cash on hand, 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 and 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. In addition, as discussed in the "Asset Retirement Obligation" section of "Liquidity and Capital Resources," a significant amount of funds will be required to be put on deposit with Canadian regulatory authorities to fund abandonments at the Company's oil and natural gas properties in the Manyberries area. Other sources and potential sources of funding are discussed below.
In fiscal 2020, the Company listed its corporate office on the 29th floor of a commercial office building in downtown Honolulu, Hawaii for sale and on September 30, 2021, the Company’s Honolulu corporate office was sold for approximately $1,864,000, net of related costs.
On March 16, 2021, the Company initiated an at-the-market offering program (“ATM”) pursuant to which the Company may offer and sell, from time to time, shares of its common stock under price and volume guidelines set by the Company's Board of Directors and the terms and conditions described in the Registration Statement. The sale of shares under the ATM began in May 2021 and as of September 30, 2021, the Company sold 1,167,987 shares of common stock resulting in net proceeds of $3,784,000 after commissions and fees of $123,000.
In April 2021, the Company re-initiated the marketing of its non-core oil and natural gas properties in the Spirit River, Wood River, Medicine River, Kaybob, Bonanza, Balsam and Thornbury areas for sale. On July 8 2021, Barnwell entered into and completed a purchase and sale agreement with an independent third party and sold its interests in certain natural gas and oil properties located in the Spirit River area of Alberta, Canada. The sales price per the agreement was adjusted for customary purchase price adjustments to $1,047,000 in order to, among other things, reflect an economic effective closing date of sale of July 8, 2021. From Barnwell's net proceeds, $526,000 was withheld for remittance by the buyers to the Canada Revenue Agency for potential amounts due for Barnwell’s Canadian income taxes related to the sale. Negotiations regarding the potential sales of other non-core oil and natural gas properties is ongoing, however there is no assurance that the sale of any of the other non-core properties will occur.
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 duringDuring 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 as2021, continuing uncertainties regarding the potential duration and depth of the impacts of the COVID-19 pandemic on our business and the sufficiency of our cash balances and future cash inflows as described
above raised substantial doubt about our ability to meet our estimated cash outflows or continue as a going concern. However, due to the $3,784,000 of net proceeds raised by the ATM through September 30, 2021, the proceeds received from the sale of the Company's corporate office and its interests in certain natural gas and oil properties in the Spirit River area, as well as the $7,156,000 of net cash inflows in the year ended September 30, 2021 from land segment percentage of sales proceeds and distributions from the Kukio Resort Land Development Partnerships, substantial doubt about our ability to meet our estimated cash outflows or 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 letternotice from the Exchange Staff indicatingNYSE American that the Company was not in compliance with Part 10, SectionsSection 1003(a)(i) and (a)Section 1003(a)(ii) of the NYSE American Company Guide (the “Guide”), which respectively require an issuer to have (i) 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 and (ii) 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, since itwe reported stockholders’ equity of $1.2 million as of September 30, 2019 and net losses in three of the last four most recent fiscal years then ended, September 30, 2019, September 30, 2018 and September 30, 2016. Thethat the Company’s failure to meet the NYSE American’s stockholders’ equity requirements and the exceptions resulted in a risk that our common stock maycould be at risk of being delisted.
In accordance with the NYSE American’s policies and procedures, we subsequently submitted a plan (the “Plan”) to the Company submitted its Plan addressing howNYSE American detailing the Company intendedsteps we planned to take to raise our stockholders’ equity above $4.0 million and regain compliance with Part 10, Section 10031003(a)(i) and Section 1003(a)(ii) 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 duringuntil July 13, 2021.
On July 13, 2021, the Plan Period. The Company has beenfiled a Form 8-K report with the Securities and will continueExchange Commission announcing that the Company’s pro forma stockholders’ equity (unaudited) as of July 13, 2021 was projected to be subjectabove the $4.0 million required to periodic review by Exchange Staff duringcomply with Section 1003(a)(i) and Section 1003(a)(ii) of the Plan Period. The Plan was submitted toGuide. Accordingly, in a letter dated July 14, 2021, the NYSE American beforedetermined the startCompany had resolved the continued listing deficiency with respect to Section 1003(a)(i) and Section 1003(a)(ii) of the COVID-19 pandemic-related low commodity price environment, the oil price war between Saudi ArabiaGuide 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. Ifnotified 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 inthat it had successfully regained 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.
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 $2,522,000decreased $934,000 from $629,000 in fiscal 2019 to $3,151,000 in fiscal 2020.2020 to $2,217,000 in fiscal 2021.
Due toThe Company participated in the uncertainties createddrilling of seven gross (0.20 net) non-operated wells in Oklahoma during the year ended September 30, 2021. Capital expenditures incurred by the COVID-19 pandemic, investmentsCompany for these Oklahoma wells totaled $1,178,000 for the year ended September 30, 2021. One gross (0.04 net) well was completed and the well began flowback production in late May 2021 and the Company’s share of net production, after royalties, from this well was 1,000 barrels of oil, and4,000 MCF of natural gas properties have been suspended pending suitable market opportunities and sufficient sources1,000 barrels of funding.natural gas liquids through September 30, 2021. The remaining six gross (0.16 net) wells were all producing in October 2021.
The Company did not drill or participate in the drilling of wells in Canada during the year ended September 30, 2021. Drilling opportunities in the Company's core Twining area are being investigated for potential investment in the forthcoming months.
Oil and Natural Gas Property Acquisitions and Dispositions
Dispositions
In April 2021, Barnwell entered into a purchase and sale agreement with an independent third party and sold its interests in properties located in the Hillsdown area of Alberta, Canada. The sales price per the agreement was adjusted for customary purchase price adjustments to $132,000 in order to, among other things, reflect an economic effective date of October 1, 2020. $72,000 of the sales proceeds was withheld by the buyers for potential amounts due for Barnwell’s Canadian income taxes related to the sale. The final determination of the customary adjustments to the purchase price has not yet been made, however it is not expected to result in a material adjustment. The proceeds were credited to the full cost pool, with no gain or loss recognized, as the sale did not result in a significant alteration of the relationship between capitalized costs and proved reserves.
In April 2021, the Company re-initiated the marketing of its non-core oil and natural gas properties in the Spirit River, Wood River, Medicine River, Kaybob, Bonanza, Balsam and Thornbury areas for sale. On July 8, 2021, Barnwell entered into and completed a purchase and sale agreement with an independent third party and sold its interests in certain natural gas and oil properties located in the Spirit River area of Alberta, Canada. The sales price per the agreement was adjusted for customary purchase price adjustments to $1,047,000 in order to, among other things, reflect an economic effective closing date of sale of July 8, 2021. From Barnwell's net proceeds, $526,000 was withheld for remittance by the buyers to the Canada Revenue Agency for potential amounts due for Barnwell’s Canadian income taxes related to the sale.
The difference in the relationship between capitalized costs and proved reserves of the Spirit River properties sold as compared to the properties retained by Barnwell was significant as there was a 93%difference in capitalized costs divided by proved reserves if the gain was recorded versus the gain being credited against the full-cost pool. Accordingly, Barnwell recorded a gain on the sale of Spirit River of $818,000 in the year ended September 30, 2021 in accordance with the guidance in Rule 4-10(c)(6)(i) of Regulation S-X of the rules and regulations of the SEC, which requires an allocation of capitalized costs to the reserves sold and reserves retained on the basis of the relative fair values of the properties as there was a substantial economic difference between the properties sold and those retained. Also included in the gain calculation were asset retirement obligations of $77,000 assumed by the purchaser.
Negotiations regarding the potential sales of other non-core oil and natural gas properties is ongoing, however there is no assurance that the sale of any of the other non-core properties will occur.
In the quarter ended December 31, 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
Acquisitions
In April 2021, Barnwell acquired additional working interests in oil and natural gas properties includedlocated in the Consolidated StatementTwining area of Cash FlowsAlberta, Canada for cash consideration of $348,000. The purchase price per the year ended September 30, 2019 primarily representsagreement was adjusted for customary purchase price adjustments to reflect the refundeconomic activity from the effective date to the closing date. The final determination of income taxes previously withheld from what otherwise would havethe customary adjustments to the purchase price has not yet been proceeds on prior years' oil and natural gas property sales.made, however it is not expected to result in a material adjustment.
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 /closureabandonment/closure order for all wells and facilities in the Manyberries area which had been largely operated by LGX.LGX, an operating company that went into receivership in 2016. The estimated asset retirement obligation for the Company's interest in the wells and facilities in the Manyberries area is included in “Asset retirement obligation” in the Consolidated Balance Sheets. Many 100% LGX ownedLGX-owned wells are to be reclaimed by the OWA. However, as next largest interest holder in 7882 of the wells and 67 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, to protect the Sage Grouse.Act. Access is limited to a window of mid-September to the end of November each year.
Recently, the OWA created a WIP program for specific areas where there are a significant number of orphaned wells to abandon. The planOWA has the ability and expertise to abandon wells using its internal resources and network of service providers resulting in efficiencies that companies such as Barnwell, would not be able to obtain on its own. Under the WIP program, the Company has submitted began in October 2019 with field inspections, securing wells, and equipment inventory,would be required to provide payment for which minor expenses were expended. The plan includes further field activity beginningonly Barnwell’s working interest share, however, all WIP’s would have to participate in the fall of 2020, our fiscal 2021 first quarter, which has been initiated and initially
involves removal and salvage ofprogram for the surface equipment; these costs are estimatedOWA to be minimal due in part to the salvage value of the equipment. Beyond fiscalbegin its work. In March 2021, the Company proposes to perform seven to ten well abandonments per year over an estimated ten-year period as well as abandonwas notified by the facilities inOWA that time period. Annual gross costs estimatedBarnwell’s Manyberries wells were confirmed to be incurred currently are approximately $500,000, approximately $55,000 net toin 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.WIP program.
As an alternative toUnder the above plan,new agreement with the OWA, the Company is required to pay the abandonment and reclamation costs in discussionsadvance through a cash deposit. The total cash deposit amount was calculated to allowbe approximately $1,525,000 and the Company paid $888,000 of the total deposit in July and August 2021 and will need to pay the remaining balance of $637,000 by August 2022. The Company revised its Manyberries ARO liability based on the OWA’s revised abandonment and reclamation estimates, which resulted in an increase of approximately $213,000 in the current year. The increase in the ARO liability was a result of higher reclamation and remediation costs than anticipated, partially offset by lower abandonment estimates. Based on a review of the details of the cash deposit calculation provided by the OWA, to perform well abandonments and reclamations onwhich includes amounts added for possible contingencies, the company’s behalf. This would eliminateCompany believes the need for Barnwell to carry LGX’s average 85% portion of Barnwell interest in wells in Manyberries. Barnwell would also benefit fromrequired cash deposit amount by the OWA’s extensive experience and scale of operations in this area. This could allow Barnwell to accelerate closureOWA is higher than the actual costs of the asset retirement obligation for the Manyberries areawells and that any excess of the deposit over actual asset retirement costs for the first phase of the work would be credited toward the second phase of the work. A remaining excess deposit, if any, would ultimately be refunded to 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 toupon completion of all of 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 1718 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 Board of Stockholders and Board of Directors of
Barnwell Industries, Inc.
Opinion on the Consolidated Financial Statements
We have audited the accompanying consolidated balance sheetsheets of Barnwell Industries, Inc. and subsidiaries (the Company) as of September 30, 2021 and 2020, and the related consolidated statementstatements of operations, comprehensive loss,income (loss), equity (deficit), and cash flows for the yearyears then ended, and the related notes (collectively referred to as the “consolidated financial“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, 2021 and 2020, and the results of its operations and its cash flows for the yearyears 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’sentity’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audit.audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) ("PCAOB") and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the 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 auditaudits 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’sentity’s internal control over financial reporting. Accordingly, we express no such opinion.
Our auditaudits 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 auditaudits 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 providesaudits provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters
does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
Estimation of Proved Reserves Impacting the Recognition and Valuation of Depletion Expense and Impairment and Oil and Gas Properties
Critical Audit Matter Description
As described in Note 1 to the financial statements, the Company accounts for its oil and gas properties using the full cost method of accounting which requires management to make estimates of proved reserve volumes and future revenues and expenses to calculate depletion expense and measure its oil and gas properties for potential impairment. To estimate the volume of proved reserves and future revenues, management makes significant estimates and assumptions, including forecasting the production decline rate of producing properties and forecasting the timing and volume of production associated with the Company’s development plan for proved undeveloped properties. In addition, the estimation of proved reserves is also impacted by management’s judgments and estimates regarding the financial performance of wells associated with proved reserves to determine if wells are expected, with reasonable certainty, to be economical under the appropriate pricing assumptions required in the estimation of depletion expense and potential impairment measurements. We identified the estimation of proved reserves of oil and gas properties, due to its impact on depletion expense and impairment evaluation, as a critical audit matter.
The principal consideration for our determination that the estimation of proved reserves is a critical audit matter is that changes in certain inputs and assumptions, which require a high degree of subjectivity necessary to estimate the volume and future revenues of the Company’s proved reserves could have a significant impact on the measurement of depletion expense or the impairment assessment. In turn, auditing those inputs and assumptions required subjective and complex auditor judgement.
How the Critical Audit Matter was Addressed in the Audit
We obtained an understanding of the design and implementation of management’s controls and our audit procedures related to the estimation of proved reserves included the following, among others.
•We evaluated the level of knowledge, skill, and ability of the Company’s reservoir engineering specialists and their relationship to the Company, made inquiries of those reservoir engineers regarding the process followed and judgments made to estimate the Company’s proved reserve volumes, and read the reserve report prepared by the Company’s specialists.
•To the extent key, sensitive inputs and assumptions used to determine proved reserve volumes and other cash flow inputs and assumptions are derived from Company’s accounting records, such as commodity pricing, historical pricing differentials, operating costs, estimated capital costs and working and net revenue interests, we tested management’s process for determining the assumptions, including examining the underlying support, on a sample basis. Specifically, our audit procedures involved testing management’s assumptions as follows:
◦Compared the estimated pricing differentials used in the reserve report to realized prices related to revenue transactions recorded in the current year and examined contractual support for the pricing differentials;
◦Evaluated the models used to estimate the operating costs at year-end compared to historical operating costs;
◦Compared the models used to determine the future capital expenditures and compared estimated future capital expenditures used in the reserve report to amounts expended for recently drilled and completed wells with similar locations;
◦Evaluated the working and net revenue interests used in the reserve report by inspecting a sample of ownership interests, historical pricing differentials, and operating costs to underlying support from the Company’s accounting records;
◦Evaluated the Company’s evidence supporting the amount of proved undeveloped properties reflected in the reserve report by examining support for the Company’s or the operator’s ability and intent to develop the proved undeveloped properties;
◦Applied analytical procedures to the reserve report by comparing to historical actual results and to the prior year reserve report.
Revenue Recognition Based on the Percentage of Completion Method
Critical Audit Matter Description
As described further in Note 1 to the financial statements, revenues derived from contract drilling contracts are recognized over time, as performance obligations are satisfied, due to the continuous transfer of control to the customer, using the percentage-of-completion method of accounting, based primarily on contract cost incurred to date compared to total estimated contract cost. Revenue recognition under this method is judgmental, particularly on lump-sum contracts, as it requires the Company to prepare estimates of total contract revenue and total contract costs, including costs to complete in-process contracts.
Auditing the Company’s estimates or total contract revenue and costs used to recognize revenue on contract drilling contracts involved significant auditor judgment, as it required the evaluation of subjective factors such as assumptions related to project schedule and completion, forecasted labor, and material and subcontract costs. These assumptions involved significant management judgment, which affects the measurement of revenue recognized by the Company.
How the Critical Audit Matter was Addressed in the Audit
We obtained an understanding of the design and implementation of management’s controls and our audit procedures related to the estimation of proved reserves included the following, among others.
•We obtained an understanding of the Company’s estimation process that affected revenue recognized on engineering and construction contracts. This included controls over management’s monitoring and review of project costs, including the Company’s procedures to validate the completeness and accuracy of data used to determine the estimates.
•We selected a sample of projects and, among other procedures, obtained and inspected the contract agreements, amendments and change orders to test the existence of customer arrangements and understand the scope of pricing of the related contracts;
•Evaluated the Company’s estimated revenue and costs to complete by obtaining and analyzing supporting documentation of management’s estimates of variable consideration and contract costs;
•Compared contract profitability estimates in the current year to historical estimates and actual performance.
Calculation of Gain Associated with Sale of Oil and Gas Properties
Critical Audit Matter Description
As described further in Note 7 to the consolidated financial statements, the Company recorded a gain to the statement of operations from sale of certain oil and gas properties. Determination of the accounting for
this transaction is challenging as it requires the Company to prepare significant assumptions and estimates regarding the associated fair value of the oil and gas reserves sold as compared to costs capitalized. The fair value estimate allows the Company to determine if the sale of the oil and gas assets are significant to the total full cost pool to record a gain on sale under the full cost method of accounting.
Auditing the Company’s estimates and assumptions used to calculate the fair value of the oil and gas reserves used to determine the relationship between capitalized costs and proved reserves of the Spirit River properties sold as compared to the properties retained by the Company, as it required the evaluation of the significant inputs and assumptions used in the reserve reports prepared by a third party reserve engineer (the Company’s specialist). Further, such fair values determined by the Company’s specialist also determined the gain calculation under the full cost method of accounting used by the Company.
How the Critical Audit Matter was Addressed in the Audit
We obtained an understanding of the design and implementation of management’s controls and our audit procedures related to the fair value of oil and gas reserves sold in relationship with the capitalized costs utilized in the calculation of the gain associated with the sale of oil and gas properties included the following:
•We evaluated the level of knowledge, skill, and ability of the Company’s reservoir engineering specialists and their relationship to the Company, made inquiries of those reservoir engineers regarding the process followed and judgments made to estimate the Company’s proved reserve volumes, and read the reserve report prepared by the Company’s specialists.
•Utilized the support of auditor’s specialists to recalculate independently of reserve engineer the fair value of oil and gas reserves sold vs. retained based on reserve information provided by the Company’s through their third party reserve engineer;
•We evaluated management’s application of gain accounting under full cost method related to the sale of the oil and gas properties to determine proper treatment was applied.
•Compared the calculation inputs for the gain recorded to the purchase and sale agreement.
/s/ WEAVER AND TIDWELL, L.L.P.
We have served as the Company'sCompany’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, | | September 30, |
| | | 2020 | | 2019 | | 2021 | | 2020 |
| ASSETS | ASSETS | | | | ASSETS | | | |
| Current assets: | Current assets: | | | | Current assets: | | | |
| Cash and cash equivalents | Cash and cash equivalents | $ | 4,584,000 | | | $ | 4,613,000 | | Cash and cash equivalents | $ | 11,279,000 | | | $ | 4,584,000 | |
| | 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 | | |
| Accounts and other receivables, net of allowance for doubtful accounts of: $391,000 at September 30, 2021; $341,000 at September 30, 2020 | | Accounts and other receivables, net of allowance for doubtful accounts of: $391,000 at September 30, 2021; $341,000 at September 30, 2020 | 3,069,000 | | | 2,176,000 | |
| Income taxes receivable | Income taxes receivable | 472,000 | | | 386,000 | | Income taxes receivable | 530,000 | | | 472,000 | |
| Asset held for sale | 699,000 | | | 0 | | |
| Assets held for sale | | Assets held for sale | 687,000 | | | 699,000 | |
| | Other current assets | Other current assets | 1,556,000 | | | 1,821,000 | | Other current assets | 2,470,000 | | | 1,556,000 | |
| Total current assets | Total current assets | 9,487,000 | | | 8,704,000 | | Total current assets | 18,035,000 | | | 9,487,000 | |
| Income taxes receivable, net of current portion | 0 | | | 230,000 | | |
| | | Asset for retirement benefits | Asset for retirement benefits | 771,000 | | | 0 | | Asset for retirement benefits | 2,229,000 | | | 771,000 | |
| Investments | Investments | 901,000 | | | 980,000 | | Investments | — | | | 901,000 | |
| Operating lease right-of-use assets | Operating lease right-of-use assets | 249,000 | | | — | | Operating lease right-of-use assets | 296,000 | | | 249,000 | |
| Property and equipment, net | 3,774,000 | | | 8,388,000 | | |
| Oil and natural gas properties, full cost method of accounting: | | Oil and natural gas properties, full cost method of accounting: | | | |
| Proved properties, net | | Proved properties, net | 2,423,000 | | | 2,303,000 | |
| Unproved properties | | Unproved properties | 962,000 | | | — | |
| Total oil and natural gas properties, net | | Total oil and natural gas properties, net | 3,385,000 | | | 2,303,000 | |
| Drilling rigs and other property and equipment, net | | Drilling rigs and other property and equipment, net | 490,000 | | | 1,471,000 | |
| Total assets | Total assets | $ | 15,182,000 | | | $ | 18,302,000 | | Total assets | $ | 24,435,000 | | | $ | 15,182,000 | |
| LIABILITIES AND EQUITY | LIABILITIES AND EQUITY | | | | LIABILITIES AND EQUITY | | | |
| Current liabilities: | Current liabilities: | | | | Current liabilities: | | | |
| Accounts payable | Accounts payable | $ | 2,104,000 | | | $ | 1,223,000 | | Accounts payable | $ | 1,416,000 | | | $ | 2,104,000 | |
| Accrued capital expenditures | Accrued capital expenditures | 542,000 | | | 287,000 | | Accrued capital expenditures | 909,000 | | | 542,000 | |
| Accrued compensation | Accrued compensation | 408,000 | | | 205,000 | | Accrued compensation | 1,073,000 | | | 408,000 | |
| Accrued operating and other expenses | Accrued operating and other expenses | 1,325,000 | | | 1,079,000 | | Accrued operating and other expenses | 1,171,000 | | | 1,325,000 | |
| Current portion of operating lease liabilities | 111,000 | | | — | | |
| | Current portion of asset retirement obligation | Current portion of asset retirement obligation | 647,000 | | | 330,000 | | Current portion of asset retirement obligation | 713,000 | | | 647,000 | |
| Other current liabilities | Other current liabilities | 1,227,000 | | | 1,644,000 | | Other current liabilities | 619,000 | | | 1,338,000 | |
| Total current liabilities | Total current liabilities | 6,364,000 | | | 4,768,000 | | Total current liabilities | 5,901,000 | | | 6,364,000 | |
| Deferred rent | 0 | | | 193,000 | | |
| | Long-term debt | Long-term debt | 58,000 | | | 0 | | Long-term debt | 47,000 | | | 58,000 | |
| Operating lease liabilities | Operating lease liabilities | 143,000 | | | — | | Operating lease liabilities | 180,000 | | | 143,000 | |
| Liability for retirement benefits | Liability for retirement benefits | 4,829,000 | | | 5,785,000 | | Liability for retirement benefits | 2,101,000 | | | 4,829,000 | |
| Asset retirement obligation | Asset retirement obligation | 5,547,000 | | | 6,059,000 | | Asset retirement obligation | 6,340,000 | | | 5,547,000 | |
| Deferred income tax liabilities | Deferred income tax liabilities | 194,000 | | | 168,000 | | Deferred income tax liabilities | 359,000 | | | 194,000 | |
| Total liabilities | Total liabilities | 17,135,000 | | | 16,973,000 | | Total liabilities | 14,928,000 | | | 17,135,000 | |
| Commitments and contingencies (Note 17) | | | | |
| Commitments and contingencies (Note 18) | | Commitments and contingencies (Note 18) | 0 | | 0 |
| Equity: | Equity: | | | | Equity: | | | |
| Common stock, par value $0.50 per share; authorized, 20,000,000 shares: | Common stock, par value $0.50 per share; authorized, 20,000,000 shares: | | | | 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 | | |
| 9,613,525 issued at September 30, 2021; 8,445,060 issued at September 30, 2020 | | 9,613,525 issued at September 30, 2021; 8,445,060 issued at September 30, 2020 | 4,807,000 | | | 4,223,000 | |
| Additional paid-in capital | Additional paid-in capital | 1,350,000 | | | 1,350,000 | | Additional paid-in capital | 4,590,000 | | | 1,350,000 | |
| (Accumulated deficit) retained earnings | (3,897,000) | | | 859,000 | | |
| Accumulated other comprehensive loss, net | (1,435,000) | | | (2,917,000) | | |
| Retained earnings (accumulated deficit) | | Retained earnings (accumulated deficit) | 2,356,000 | | | (3,897,000) | |
| Accumulated other comprehensive income (loss), net | | Accumulated other comprehensive income (loss), net | 32,000 | | | (1,435,000) | |
| Treasury stock, at cost: | Treasury stock, at cost: | | | | 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 | | |
| 167,900 shares at September 30, 2021 and 2020 | | 167,900 shares at September 30, 2021 and 2020 | (2,286,000) | | | (2,286,000) | |
| Total stockholders’ equity (deficit) | | Total stockholders’ equity (deficit) | 9,499,000 | | | (2,045,000) | |
| Non-controlling interests | Non-controlling interests | 92,000 | | | 100,000 | | Non-controlling interests | 8,000 | | | 92,000 | |
| Total (deficit) equity | (1,953,000) | | | 1,329,000 | | |
| Total equity (deficit) | | Total equity (deficit) | 9,507,000 | | | (1,953,000) | |
| Total liabilities and equity | Total liabilities and equity | $ | 15,182,000 | | | $ | 18,302,000 | | Total liabilities and equity | $ | 24,435,000 | | | $ | 15,182,000 | |
See Notes to Consolidated Financial Statements
BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
| | | | Year ended September 30, | | Year ended September 30, |
| | | 2020 | | 2019 | | 2021 | | 2020 |
| Revenues: | Revenues: | | | | Revenues: | | | |
| Oil and natural gas | Oil and natural gas | $ | 6,693,000 | | | $ | 6,406,000 | | Oil and natural gas | $ | 10,254,000 | | | $ | 6,693,000 | |
| Contract drilling | Contract drilling | 10,994,000 | | | 5,349,000 | | Contract drilling | 5,809,000 | | | 10,994,000 | |
| Sale of interest in leasehold land | Sale of interest in leasehold land | 325,000 | | | 165,000 | | Sale of interest in leasehold land | 1,738,000 | | | 325,000 | |
| | Gas processing and other | Gas processing and other | 335,000 | | | 155,000 | | Gas processing and other | 312,000 | | | 335,000 | |
| | | 18,347,000 | | | 12,075,000 | | | 18,113,000 | | | 18,347,000 | |
| Costs and expenses: | Costs and expenses: | | | | Costs and expenses: | | | |
| Oil and natural gas operating | Oil and natural gas operating | 4,850,000 | | | 5,213,000 | | Oil and natural gas operating | 6,556,000 | | | 4,850,000 | |
| Contract drilling operating | Contract drilling operating | 7,513,000 | | | 4,973,000 | | Contract drilling operating | 5,555,000 | | | 7,513,000 | |
| | General and administrative | General and administrative | 5,820,000 | | | 5,524,000 | | General and administrative | 7,088,000 | | | 5,820,000 | |
| Depletion, depreciation, and amortization | Depletion, depreciation, and amortization | 2,147,000 | | | 3,022,000 | | Depletion, depreciation, and amortization | 963,000 | | | 2,147,000 | |
| Impairment of assets | Impairment of assets | 4,376,000 | | | 5,710,000 | | Impairment of assets | 668,000 | | | 4,376,000 | |
| Interest expense | Interest expense | 3,000 | | | 5,000 | | Interest expense | 13,000 | | | 3,000 | |
| Gain on sale of asset | (1,336,000) | | | 0 | | |
| Gain on debt extinguishment | | Gain on debt extinguishment | (149,000) | | | — | |
| Gain on termination of post-retirement medical plan | | Gain on termination of post-retirement medical plan | (2,341,000) | | | — | |
| Gain on sale of assets | | Gain on sale of assets | (1,982,000) | | | (1,336,000) | |
| | | 23,373,000 | | | 24,447,000 | | | 16,371,000 | | | 23,373,000 | |
| Loss before equity in income (loss) of affiliates and income taxes | (5,026,000) | | | (12,372,000) | | |
| Earnings (loss) before equity in income of affiliates and income taxes | | Earnings (loss) before equity in income of affiliates and income taxes | 1,742,000 | | | (5,026,000) | |
| | 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 | | | | |
| Equity in income of affiliates | | Equity in income of affiliates | 5,793,000 | | | 352,000 | |
| Earnings (loss) before income taxes | | Earnings (loss) before income taxes | 7,535,000 | | | (4,674,000) | |
| Income tax provision | | Income tax provision | 332,000 | | | 3,000 | |
| Net earnings (loss) | | Net earnings (loss) | 7,203,000 | | | (4,677,000) | |
| Less: Net earnings attributable to non-controlling interests | | Less: Net earnings attributable to non-controlling interests | 950,000 | | | 79,000 | |
| Net earnings (loss) attributable to Barnwell Industries, Inc. stockholders | | Net earnings (loss) attributable to Barnwell Industries, Inc. stockholders | $ | 6,253,000 | | | $ | (4,756,000) | |
| Basic net earnings (loss) per common share | | Basic net earnings (loss) per common share | | | |
| attributable to Barnwell Industries, Inc. stockholders | attributable to Barnwell Industries, Inc. stockholders | $ | (0.57) | | | $ | (1.50) | | attributable to Barnwell Industries, Inc. stockholders | $ | 0.73 | | | $ | (0.57) | |
| Diluted net loss per common share | | | | |
| Diluted net earnings (loss) per common share | | Diluted net earnings (loss) per common share | | | |
| attributable to Barnwell Industries, Inc. stockholders | attributable to Barnwell Industries, Inc. stockholders | $ | (0.57) | | | $ | (1.50) | | attributable to Barnwell Industries, Inc. stockholders | $ | 0.73 | | | $ | (0.57) | |
| Weighted-average number of common shares outstanding: | Weighted-average number of common shares outstanding: | | | | Weighted-average number of common shares outstanding: | | | |
| Basic | Basic | 8,277,160 | | | 8,277,160 | | Basic | 8,592,154 | | | 8,277,160 | |
| Diluted | Diluted | 8,277,160 | | | 8,277,160 | | Diluted | 8,592,154 | | | 8,277,160 | |
See Notes to Consolidated Financial Statements
BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSSINCOME (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 | | | 0 | |
| 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) | |
| | | | | | | | | | | |
| | Year ended September 30, |
| | 2021 | | 2020 |
| Net earnings (loss) | $ | 7,203,000 | | | $ | (4,677,000) | |
| Other comprehensive income (loss): | | | |
| Foreign currency translation adjustments, net of taxes of $0 | (283,000) | | | (146,000) | |
| Retirement plans: | | | |
| Amortization of accumulated other comprehensive loss into net periodic benefit cost, net of taxes of $0 | 101,000 | | | 120,000 | |
| Net actuarial gain (loss) arising during the period, net of taxes of $0 | 1,108,000 | | | (218,000) | |
| Curtailment gain, net of taxes of $0 | — | | | 1,726,000 | |
| Gain on termination of post-retirement medical plan, net of taxes of $0 | 541,000 | | | — | |
| Total other comprehensive income | 1,467,000 | | | 1,482,000 | |
| Total comprehensive income (loss) | 8,670,000 | | | (3,195,000) | |
| Less: Comprehensive income attributable to non-controlling interests | (950,000) | | | (79,000) | |
| Comprehensive income (loss) attributable to Barnwell Industries, Inc. | $ | 7,720,000 | | | $ | (3,274,000) | |
See Notes to Consolidated Financial Statements
BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF EQUITY (DEFICIT)
Years ended September 30, 2021 and 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) | | Shares
Outstanding | | Common
Stock | | Additional
Paid-In
Capital | | Retained
Earnings (Accumulated Deficit) | | Accumulated
Other
Comprehensive Income (Loss) | | Treasury
Stock | | Non-controlling
Interests | | Total
Equity
(Deficit) |
| Balance at September 30, 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 | 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 | | 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 | Net (loss) earnings | — | | | — | | | — | | | (4,756,000) | | | — | | | — | | | 79,000 | | | (4,677,000) | | Net (loss) earnings | — | | | — | | | — | | | (4,756,000) | | | — | | | — | | | 79,000 | | | (4,677,000) | |
| | Foreign currency translation adjustments, net of taxes of $0 | Foreign currency translation adjustments, net of taxes of $0 | — | | | — | | | — | | | — | | | (146,000) | | | — | | | — | | | (146,000) | | Foreign currency translation adjustments, net of taxes of $0 | — | | | — | | | — | | | — | | | (146,000) | | | — | | | — | | | (146,000) | |
| Distributions to non-controlling interests | | Distributions to non-controlling interests | — | | | — | | | — | | | — | | | — | | | — | | | (87,000) | | | (87,000) | |
| Retirement plans: | Retirement plans: | | | | | | | | | | | | | | | | Retirement plans: | | | | |
| Amortization of accumulated other comprehensive loss into net periodic benefit cost, net of taxes of $0 | Amortization of accumulated other comprehensive loss into net periodic benefit cost, net of taxes of $0 | — | | | — | | | — | | | — | | | 120,000 | | | — | | | — | | | 120,000 | | 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 | Net actuarial loss arising during the period, net of taxes of $0 | — | | | — | | | — | | | — | | | (218,000) | | | — | | | — | | | (218,000) | | Net actuarial loss arising during the period, net of taxes of $0 | — | | | — | | | — | | | — | | | (218,000) | | | — | | | — | | | (218,000) | |
| Curtailment gain, net of taxes of $0 | Curtailment gain, net of taxes of $0 | — | | | — | | | — | | | — | | | 1,726,000 | | | — | | | — | | | 1,726,000 | | Curtailment gain, net of taxes of $0 | — | | | ��� | | | — | | | — | | | 1,726,000 | | | — | | | — | | | 1,726,000 | |
| Balance at September 30, 2020 | 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) | | Balance at September 30, 2020 | 8,277,160 | | | 4,223,000 | | | 1,350,000 | | | (3,897,000) | | | (1,435,000) | | | (2,286,000) | | | 92,000 | | | (1,953,000) | |
| | Net earnings | | Net earnings | — | | | — | | | — | | | 6,253,000 | | | — | | | — | | | 950,000 | | | 7,203,000 | |
| Foreign currency translation adjustments, net of taxes of $0 | | Foreign currency translation adjustments, net of taxes of $0 | — | | | — | | | — | | | — | | | (283,000) | | | — | | | — | | | (283,000) | |
| Distributions to non-controlling interests | | Distributions to non-controlling interests | — | | | — | | | — | | | — | | | — | | | — | | | (1,034,000) | | | (1,034,000) | |
| Share-based compensation | | Share-based compensation | — | | | — | | | 643,000 | | | — | | | — | | | — | | | — | | | 643,000 | |
| Issuance of common stock, net of costs | | Issuance of common stock, net of costs | 1,167,987 | | | 583,000 | | | 2,596,000 | | | — | | | — | | | — | | | — | | | 3,179,000 | |
| Issuance of common stock for services | | Issuance of common stock for services | 478 | | | 1,000 | | | 1,000 | | | — | | | — | | | — | | | — | | | 2,000 | |
| Retirement plans: | | Retirement plans: | | | | | | | | | | | | | | | |
| Amortization of accumulated other comprehensive loss into net periodic benefit cost, net of taxes of $0 | | Amortization of accumulated other comprehensive loss into net periodic benefit cost, net of taxes of $0 | — | | | — | | | — | | | — | | | 101,000 | | | — | | | — | | | 101,000 | |
| Net actuarial gain arising during the period, net of taxes of $0 | | Net actuarial gain arising during the period, net of taxes of $0 | — | | | — | | | — | | | — | | | 1,108,000 | | | — | | | — | | | 1,108,000 | |
| Gain on termination of post-retirement medical plan, net of taxes $0 | | Gain on termination of post-retirement medical plan, net of taxes $0 | — | | | — | | | — | | | — | | | 541,000 | | | — | | | — | | | 541,000 | |
| Balance at September 30, 2021 | | Balance at September 30, 2021 | 9,445,625 | | | $ | 4,807,000 | | | $ | 4,590,000 | | | $ | 2,356,000 | | | $ | 32,000 | | | $ | (2,286,000) | | | $ | 8,000 | | | $ | 9,507,000 | |
See Notes to Consolidated Financial Statements
BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
| | | | Year ended September 30, | | Year ended September 30, |
| | | 2020 | | 2019 | | 2021 | | 2020 |
| Cash flows from operating activities: | Cash flows from operating activities: | | | | 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 | | |
| Net earnings (loss) | | Net earnings (loss) | $ | 7,203,000 | | | $ | (4,677,000) | |
| Adjustments to reconcile net earnings (loss) to net cash provided by operating activities: | | Adjustments to reconcile net earnings (loss) to net cash provided by operating activities: | | | |
| Equity in income of affiliates | | Equity in income of affiliates | (5,793,000) | | | (352,000) | |
| Depletion, depreciation, and amortization | Depletion, depreciation, and amortization | 2,147,000 | | | 3,022,000 | | Depletion, depreciation, and amortization | 963,000 | | | 2,147,000 | |
| Impairment of assets | Impairment of assets | 4,376,000 | | | 5,710,000 | | Impairment of assets | 668,000 | | | 4,376,000 | |
| | Gain on sale of asset | (1,336,000) | | | 0 | | |
| Gain on sale of oil and natural gas properties | | Gain on sale of oil and natural gas properties | (818,000) | | | — | |
| Gain on sale of other assets | | Gain on sale of other assets | (1,164,000) | | | (1,336,000) | |
| Sale of interest in leasehold land, net of fees paid | Sale of interest in leasehold land, net of fees paid | (285,000) | | | (124,000) | | Sale of interest in leasehold land, net of fees paid | (1,526,000) | | | (285,000) | |
| Distributions of income from equity investees | Distributions of income from equity investees | 75,000 | | | 0 | | Distributions of income from equity investees | 5,045,000 | | | 75,000 | |
| Retirement benefits (income) expense | (60,000) | | | 177,000 | | |
| Income tax receivable, noncurrent | 0 | | | (31,000) | | |
| Retirement benefits income | | Retirement benefits income | (88,000) | | | (60,000) | |
| | Accretion of asset retirement obligation | Accretion of asset retirement obligation | 561,000 | | | 608,000 | | Accretion of asset retirement obligation | 580,000 | | | 561,000 | |
| Deferred income tax expense (benefit) | 26,000 | | | (144,000) | | |
| Deferred income tax expense | | Deferred income tax expense | 165,000 | | | 26,000 | |
| Asset retirement obligation payments | Asset retirement obligation payments | (498,000) | | | (372,000) | | Asset retirement obligation payments | (421,000) | | | (498,000) | |
| Share-based compensation benefit | 0 | | | (42,000) | | |
| Non-cash rent expense | 48,000 | | | 86,000 | | |
| Share-based compensation expense | | Share-based compensation expense | 643,000 | | | — | |
| Common stock issued for services | | Common stock issued for services | 1,000 | | | — | |
| Non-cash rent (income) expense | | Non-cash rent (income) expense | (4,000) | | | 48,000 | |
| Retirement plan contributions and payments | Retirement plan contributions and payments | (8,000) | | | (124,000) | | Retirement plan contributions and payments | (14,000) | | | (8,000) | |
| | Bad debt expense | Bad debt expense | 285,000 | | | 0 | | Bad debt expense | 32,000 | | | 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) | | |
| Gain on debt extinguishment | | Gain on debt extinguishment | (149,000) | | | — | |
| Gain on termination of post-retirement medical plan | | Gain on termination of post-retirement medical plan | (2,341,000) | | | — | |
| (Decrease) increase from changes in current assets and liabilities | | (Decrease) increase from changes in current assets and liabilities | (2,151,000) | | | 448,000 | |
| Net cash provided by operating activities | | Net cash provided by operating activities | 831,000 | | | 750,000 | |
| Cash flows from investing activities: | Cash flows from investing activities: | | | | Cash flows from investing activities: | | | |
| | Proceeds from the maturity of certificates of deposit | 0 | | | 741,000 | | |
| | | Distributions from equity investees in excess of earnings | Distributions from equity investees in excess of earnings | 305,000 | | | 352,000 | | Distributions from equity investees in excess of earnings | 1,649,000 | | | 305,000 | |
| Proceeds from sale of interest in leasehold land, net of fees paid | Proceeds from sale of interest in leasehold land, net of fees paid | 285,000 | | | 124,000 | | Proceeds from sale of interest in leasehold land, net of fees paid | 1,526,000 | | | 285,000 | |
| Proceeds from sale of oil and natural gas assets | 608,000 | | | 1,519,000 | | |
| Proceeds from final acquisition purchase price adjustments | 0 | | | 172,000 | | |
| Proceeds from the sale of oil and natural gas assets | | Proceeds from the sale of oil and natural gas assets | 581,000 | | | 608,000 | |
| | Proceeds from the sale of asset | 1,100,000 | | | 0 | | |
| | Proceeds from the sale of other assets, net of closing costs | | Proceeds from the sale of other assets, net of closing costs | 1,864,000 | | | 1,100,000 | |
| Payments to acquire oil and natural gas properties | Payments to acquire oil and natural gas properties | 0 | | | (355,000) | | Payments to acquire oil and natural gas properties | (348,000) | | | — | |
| Capital expenditures - oil and natural gas | Capital expenditures - oil and natural gas | (2,716,000) | | | (385,000) | | Capital expenditures - oil and natural gas | (1,523,000) | | | (2,716,000) | |
| Capital expenditures - all other | Capital expenditures - all other | (415,000) | | | (1,263,000) | | Capital expenditures - all other | (63,000) | | | (415,000) | |
| Issuance of note receivable | 0 | | | (300,000) | | |
| Proceeds from repayment of note receivable | 0 | | | 300,000 | | |
| Net cash (used in) provided by investing activities | (833,000) | | | 905,000 | | |
| | Net cash provided by (used in) investing activities | | Net cash provided by (used in) investing activities | 3,686,000 | | | (833,000) | |
| Cash flows from financing activities: | Cash flows from financing activities: | | | | Cash flows from financing activities: | | | |
| | Borrowings on long-term debt | Borrowings on long-term debt | 147,000 | | | 0 | | Borrowings on long-term debt | 47,000 | | | 147,000 | |
| Distributions to non-controlling interests | Distributions to non-controlling interests | (87,000) | | | (110,000) | | Distributions to non-controlling interests | (1,034,000) | | | (87,000) | |
| Net cash provided by (used in) financing activities | 60,000 | | | (110,000) | | |
| Proceeds from issuance of stock, net of costs | | Proceeds from issuance of stock, net of costs | 3,179,000 | | | — | |
| Net cash provided by financing activities | | Net cash provided by financing activities | 2,192,000 | | | 60,000 | |
| Effect of exchange rate changes on cash and cash equivalents | Effect of exchange rate changes on cash and cash equivalents | (6,000) | | | (14,000) | | Effect of exchange rate changes on cash and cash equivalents | (14,000) | | | (6,000) | |
| Net decrease in cash and cash equivalents | (29,000) | | | (1,352,000) | | |
| Net increase (decrease) in cash and cash equivalents | | Net increase (decrease) in cash and cash equivalents | 6,695,000 | | | (29,000) | |
| Cash and cash equivalents at beginning of year | Cash and cash equivalents at beginning of year | 4,613,000 | | | 5,965,000 | | Cash and cash equivalents at beginning of year | 4,584,000 | | | 4,613,000 | |
| Cash and cash equivalents at end of year | Cash and cash equivalents at end of year | $ | 4,584,000 | | | $ | 4,613,000 | | Cash and cash equivalents at end of year | $ | 11,279,000 | | | $ | 4,584,000 | |
See Notes to Consolidated Financial Statements
BARNWELL INDUSTRIES, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED SEPTEMBER 30, 20202021 AND 20192020
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Description of Business
Barnwell is engaged in the following lines of business: 1) acquiring, developing, producing and selling oil and natural gas in Canada and Oklahoma, 2) investing in land interests in Hawaii, and 3) drilling wells and installing and repairing water pumping systems in Hawaii.
Principles of Consolidation
The consolidated financial statements include the accounts of Barnwell Industries, Inc. and all majority-owned subsidiaries (collectively referred to herein as “Barnwell,” “we,” “our,” “us,” or the “Company”), including a 77.6%-owned land investment general partnership (Kaupulehu Developments) and, a 75%-owned land investment partnership (KD Kona)., and a variable interest entity (Teton Barnwell Fund I, LLC) for which the Company is deemed to be the primary beneficiary. All significant intercompany accounts and transactions have been eliminated.
Undivided interests in oil and natural gas exploration and production joint ventures are consolidated on a proportionate basis. Barnwell’s investments in both unconsolidated entities in which a significant, but less than controlling, interest is held and in VIEs in which the Company is not deemed to be the primary beneficiary are accounted for by the equity method.
Use of Estimates in the Preparation of Consolidated Financial Statements
The preparation of the consolidated financial statements in conformity with U.S. GAAP requires management of Barnwell to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Actual results could differ significantly from those estimates. Significant assumptions are required in the valuation of deferred tax assets, asset retirement obligations, share-based payment arrangements, obligations for retirement plans, contract drilling estimated costs to complete, proved oil and natural gas reserves, and the carrying value of other assets, and such assumptions may impact the amount at which such items are recorded.
Revenue Recognition
Barnwell operates in and derives revenue from the following 3 principal business segments:
•Oil and Natural Gas Segment - Barnwell engages in oil and natural gas development, production, acquisitions and sales in Canada.Canada and Oklahoma.
•Land Investment Segment - Barnwell invests in land interests in Hawaii.
•Contract Drilling Segment - Barnwell provides well drilling services and water pumping system installation and repairs in Hawaii.
Oil and Natural Gas - Barnwell’s investments in oil and natural gas properties are located in Alberta, Canada.Canada and Oklahoma. These property interests are principally held under governmental leases or licenses. Barnwell sells the large majority of its oil, natural gas and natural gas liquids production under short-term contracts between itself and marketers based on prices indexed to market prices and recognizes revenue at a point in time when the oil, natural gas and natural gas liquids are delivered, as this is where Barnwell’s performance obligation is satisfied and title has passed to the customer.
Land Investment - Barnwell is entitled to receive contingent residual payments from the entities that previously purchased Barnwell’s land investment interests under contracts entered into in prior years. The residual payments under those contracts become due when the entities sell lots and/or residential units in the areas that were previously sold under the aforementioned contracts or when a preferred payment threshold is achieved. The residual payments received by Barnwell are recognized as revenue when it is probable that a significant reversal in the amount of cumulative revenue recognized will not occur.
Contract Drilling - Through contracts which are normally less than twelve months in duration, Barnwell drills water and water monitoring wells and installs and repairs water pumping systems in Hawaii. Barnwell recognizes revenue from well drilling or the installation of pumps over time based on total costs incurred on the projects relative to the total expected costs to satisfy the performance obligation as management believes this is an accurate representation of the percentage of completion as control is continuously transferred to the customer. Uninstalled materials, which typically consists of well casing or pumps, are excluded in the costs-to-costs calculation for the duration of the contract as including these costs would result in a distortion of progress towards satisfaction of the performance obligation due to the resulting cumulative catch-up in margin in a single period. An equal amount of cost and revenue is recorded when uninstalled materials are controlled by the customer, which is typically when Barnwell has the right to payment for the materials and when the materials are delivered to the customer’s site or location and such materials have been accepted by the customer. Uninstalled materials are held in inventory and included in “Other current assets” on the Company’s Consolidated Balance Sheets until control is transferred to the customer. When the estimate on a contract indicates a loss, Barnwell records the entire estimated loss in the period the loss becomes known.
The contract price may include variable consideration, which includes such items as increases to the transaction price for unapproved change orders and claims for which price has not yet been agreed by the customer. The Company estimates variable consideration using either the most likely amount or expected value method, whichever is a more appropriate reflection of the amount to which it expects to be entitled based on the characteristics and circumstances of the contract. Variable consideration is included in the estimated transaction price to the extent it is probable that a significant reversal of cumulative recognized revenue will not occur.
Contract price and cost estimates are reviewed periodically as work progresses and adjustments proportionate to the costs incurred to date to total estimated costs at completion are reflected in contract revenues in the reporting period when such estimates are revised. The nature of accounting for these contracts is such that refinements of the estimated costs to complete may occur and are characteristic of the estimation process due to changing conditions and new developments. Many factors and assumptions can and do change during a contract performance obligation period which can result in a change to contract profitability including unforeseen underground geological conditions (to the extent that contract remedies are unavailable), the availability and costs of skilled contract labor, the performance of major material suppliers, the performance of major subcontractors, unusual weather conditions and unexpected changes in material costs, changes in the scope and nature of the work to be performed, and unexpected
construction execution errors, among others. These factors may result in revisions to costs and income and
are recognized in the period in which the revisions become known. Revenue and profit in future periods of contract performance are recognized using the adjusted estimate.
Management evaluates the performance of contracts on an individual basis. In the ordinary course of business, but at least quarterly, we prepare updated estimates that may impact the cost and profit or loss for each contract based on actual results to date plus management's best estimate of costs to be incurred to complete each performance obligation. The cumulative effect of revisions in estimates of the total forecasted revenue and costs, including any unapproved change orders and claims, during the course of the contract is reflected in the accounting period in which the facts that caused the revision become known. Changes in the cost estimates can have a material impact on our consolidated financial statements and are reflected in the results of operations when they become known.
Unexpected significant inefficiencies that were not considered a risk at the time of entering into the contract, such as design or construction execution errors that result in significant wasted resources, are excluded from the measure of progress toward completion and the costs are expensed as incurred.
To the extent a contract is deemed to have multiple performance obligations, the Company allocates the transaction price of the contract to each performance obligation using its best estimate of the standalone selling price of each distinct good or service in the contract.
When the Company receives consideration, or such consideration is unconditionally due, from a customer prior to transferring goods or services to the customer under the terms of a sales contract, the Company records deferred revenue, which represents a contract liability. Such deferred revenue typically results from billings in excess of costs and estimated earnings on uncompleted contracts. Contract liabilities are included in “Other current liabilities” on the Company’s Consolidated Balance Sheets. Costs and estimated earnings in excess of billings represent certain amounts under customer contracts that were earned and billable, but yet not invoiced, and are included in contract assets and reported in “Other current assets” on the Company’s Consolidated Balance Sheets.
Cash and Cash Equivalents
Cash and cash equivalents include cash on hand and short-term investments with original maturities of three months or less.
Concentration of Credit Risk
Financial instruments that potentially subject the Company to concentrations of credit risk consist primarily of cash and cash equivalents. We maintain bank account balances with high quality financial institutions which often exceed insured limits. We have not experienced any losses with these accounts and believe that we are not exposed to any significant credit risk on cash.
Accounts and Other Receivables
Accounts receivable are recorded at the invoiced amount and do not bear interest. The allowance for doubtful accounts is Barnwell’s best estimate of the amount of probable credit losses in Barnwell’s existing accounts receivable and is based on historical write-off experience and the application of the specific identification method. Account balances are charged off against the allowance after all means of
collection have been exhausted and the potential for recovery is considered remote. Barnwell does not have any off-balance sheet credit exposure related to its customers.
Investments in Real Estate
Barnwell accounts for sales of Increment I and Increment II leasehold land interests under the full accrual method. Gains from such sales were recognized when the buyer’s investments were adequate to demonstrate a commitment to pay for the property, risks and rewards of ownership transferred to the buyer, and Barnwell did not have a substantial continuing involvement with the property sold. With regard to payments Kaupulehu Developments is entitled to receive from KD I and KD II, the percentage of sales payments from KD I and KD II and percentage of distributions from KD II are contingent future profits which will be recognized when they are realized. All costs of the sales of Increment I and Increment II leasehold land interests were recognized at the time of sale and were not deferred to future periods when any contingent profits will be recognized.
Variable Interest Entities
The consolidation of VIEs is required when an enterprise has a controlling financial interest and is therefore the VIE’s primary beneficiary. A controlling financial interest will have both of the following characteristics: (a) the power to direct the activities of a VIE that most significantly impact the VIE’s economic performance and (b) the obligation to absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE. The determination of whether an entity is a VIE and, if so, whether the Company is the primary beneficiary, may require significant judgment.
Barnwell analyzes its entities in which it has a variable interest to determine whether the entities are VIEs and, if so, whether the Company is the primary beneficiary. This analysis includes a qualitative review based on an evaluation of the design of the entity, its organizational structure, including decision making ability and financial agreements, as well as a quantitative review. Entities that have been determined to be VIEs and for which we have a controlling financial interest and are therefore the VIE’s primary beneficiary are consolidated (see Note 5). Entities that have been determined to be VIEs and for which we do not have a controlling financial interest and are therefore not the VIE’s primary beneficiary are not consolidated. These unconsolidated entities are accounted for under the equity method (see Note 4).
Equity Method Investments
Affiliated companies, which are limited partnerships or similar entities, in which Barnwell holds more than a 3% to 5% ownership interest and does not control, are accounted for as equity method investments. Equity method investment adjustments include Barnwell’s proportionate share of investee income or loss, adjustments to recognize certain differences between Barnwell’s carrying value and Barnwell’s equity in net assets of the investee at the date of investment, impairments and other adjustments required by the equity method. Gains or losses are realized when such investments are sold. Barnwell classifies distributions received from equity method investments using the cumulative earnings approach in the Consolidated Statements of Cash Flows. Under the cumulative earnings approach, distributions received up to the amount of cumulative equity in earnings recognized are treated as returns on investment and are classified within operating cash flows and those in excess of that amount are treated as returns of investment and are classified within investing cash flows.
Investments in equity method investees are evaluated for impairment as events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If the carrying amounts of the assets exceed their respective fair values, additional impairment tests are performed to measure the amounts of the impairment losses, if any. When an impairment test demonstrates that the fair value of an investment is less than its carrying value, management will determine whether the impairment 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.
The capitalized costs of oil and gas properties, excluding unevaluated and unproved properties, are amortized as depreciation, depletion and amortization expense using the units-of-production method based on estimated proved recoverable oil and gas reserves.
Costs associated with unevaluated and unproved properties, initially excluded from the amortization base, relate to unproved leasehold acreage, wells and production facilities in progress and wells pending determination of the existence of proved reserves. Unproved leasehold costs are transferred to the amortization base with the costs of drilling the related well once a determination of the existence of proved reserves has been made or upon impairment of a lease. Costs associated with wells in progress and completed wells that have yet to be evaluated are transferred to the amortization base once a determination is made whether or not proved reserves can be assigned to the property. Costs of dry wells are transferred to the amortization base immediately upon determination that the well is unsuccessful.
All items classified as unevaluated and unproved properties are assessed on a quarterly basis for possible impairment or reduction in value. Properties are assessed on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of various factors, including, but not limited to, the following: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; assignment of proved reserves; and economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and become subject to amortization.
Under the full cost method of accounting, we review the carrying value of our oil and natural gas properties, on a country-by-country basis, each quarter in what is commonly referred to as the ceiling test. Under the ceiling test, capitalized costs, net of accumulated depletion and oil and natural gas related deferred income taxes, may not exceed an amount equal to the sum of 1) the discounted present value (at 10%), using average first-day-of-the-month prices during the 12-month period ending as of the balance sheet date held constant over the life of the reserves, of Barnwell’s estimated future net cash flows from
estimated production of proved oil and natural gas reserves as determined by independent petroleum reserve engineers, less estimated future expenditures to be incurred in developing and producing the proved reserves but excluding future cash outflows associated with settling asset retirement obligations with the exception of those associated with proved undeveloped reserves from wells that are to be drilled in the future; plus 2) the cost of major development projects and unproven properties not subject to depletion, if any; plus 3) the lower of cost or estimated fair value of unproven properties included in costs subject to depletion; less 4) related income tax effects. If net capitalized costs exceed this limit, the excess is expensed. Depletion is computed using the units-of-production method whereby capitalized costs, net of estimated salvage values, plus estimated future costs to develop proved reserves and satisfy asset retirement obligations, are amortized over the total estimated proved reserves on a country-by-country basis. Investments in major development projects are not depleted until either proved reserves are associated with the projects or impairment has been determined. Proceeds from the disposition of oil and natural gas properties are credited to the full cost pool, with no gain or loss recognized, unless such a sale would significantly alter the relationship between capitalized costs and the proved reserves in a particular country.
Given the volatility of oil and gas prices, it is reasonably possible that the estimate of discounted future net cash flows from proved oil and gas reserves could change in the near term. If oil and gas prices decline in the future, even if only for a short period of time, it is possible that impairments of oil and gas properties could occur. In addition, it is reasonably possible that impairments could occur if costs are incurred in excess of any increases in the present value of future net cash flows from proved oil and gas reserves, or if properties are sold for proceeds less than the discounted present value of the related proved oil and gas reserves.
Barnwell’s sales reflect its working interest share after royalties. Barnwell’s production is generally delivered and sold at the plant gate. Barnwell does not have transportation volume commitments with pipelines and does not have natural gas imbalances related to natural gas balancing arrangements with its partners.
Acquisitions
In accordance with the guidance for business combinations, Barnwell determines whether an acquisition is a business combination, which requires that the assets acquired and liabilities assumed constitute a business. Each business combination is then accounted for by applying the acquisition method of accounting. If the assets acquired are not a business, the Company accounts for the transaction as an asset acquisition. Under both methods purchase prices are allocated to acquired assets and assumed liabilities based on their estimated fair value at the time of the acquisition. For transactions that are business combinations, the Company evaluates the existence of goodwill or a gain from a bargain purchase. The Company capitalizes acquisition-related costs and fees associated with asset acquisitions and immediately expenses acquisition-related costs and fees associated with business combinations.
Long-lived Assets
Long-lived assets to be held and used, other than oil and natural gas properties, are evaluated for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be fully recoverable. Recoverability is measured by comparing the carrying amount of the asset to the future net cash flows expected to result from use of the asset (undiscounted and without interest charges). If it is determined that the asset may not be recoverable, impairment loss is measured as the
amount by which the carrying amount of the asset exceeds the fair value of the asset. Long-lived assets to be disposed of are reported at the lower of the asset carrying value or fair value, less cost to sell.
Water well drilling rigs, office and other property and equipment are depreciated using the straight-line method based on estimated useful lives.
Share-based Compensation
Share-based compensation cost is measured at fair value. Barnwell utilizes a closed-form valuation model to determine the fair value of each option award. Expected volatilities are based on the historical volatility of Barnwell’s stock over a period consistent with that of the expected terms of the options. The expected terms of the options represent expectations of future employee exercise and are estimated based on factors such as vesting periods, contractual expiration dates, historical trends in Barnwell’s stock price, and historical exercise behavior. If the Company does not have sufficient historical data regarding employee exercise behavior, the “simplified method” as permitted by the SEC’s Staff Accounting Bulletin No. 110, Share-Based Payment is utilized to estimate the expected terms of the options. The risk-free rates for periods within the contractual life of the options are based on the yields of U.S. Treasury instruments with terms comparable to the estimated option terms. Expected dividends are based on 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 postretirementpost-retirement medical insurance benefits plan, which was terminated in June 2021, by recognizing the over-funded or under-funded status as an asset or liability in its Consolidated Balance Sheets and recognizes changes in that funded status in the year in which the changes occur through comprehensive income. See further discussion at Note 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$62,000 based on the assets of the plan at September 30, 2020.2021.
The effects of changing assumptions are included in unamortized net gains and losses, which directly affect accumulated other comprehensive income. These unamortized gains and losses in excess of certain thresholds are amortized and reclassified to (loss) income over the average remaining service life of active employees.
Asset Retirement Obligation
Barnwell accounts for asset retirement obligations by recognizing the fair value of a liability for an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made. Barnwell estimates the fair value of asset retirement obligations based on the projected discounted future cash outflows required to settle abandonment and restoration liabilities. Such an estimate requires assumptions and judgments regarding the existence of liabilities, the amount and timing of cash outflows required to settle the liability, what constitutes adequate restoration, inflation factors, credit adjusted discount rates, and consideration of changes in legal, regulatory, environmental and political environments. Abandonment and restoration cost estimates are determined in conjunction with Barnwell’s reserve engineers based on historical information regarding costs incurred to abandon and restore similar well sites, information regarding current market conditions and costs, and knowledge of subject well sites and properties. These assumptions represent Level 3 inputs.
Barnwell’s estimated site restoration and abandonment costs of its oil and natural gas properties are capitalized as part of the carrying amount of oil and natural gas properties and depleted over the life of the related reserves. When the assumptions used to estimate a recorded asset retirement obligation change, a revision is recorded to both the asset retirement obligation and the capitalized cost of asset retirements. The liability is accreted at the end of each period through charges to oil and natural gas operating expense.
Income Taxes
Income taxes are determined using the asset and liability method. Deferred tax assets and liabilities are recognized for the estimated future tax impacts of differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the year in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. A valuation allowance is provided when it is more likely than not that some portion or all of the deferred tax asset will not be realized.
Management evaluates its potential exposures from tax positions taken that have been or could be challenged by taxing authorities. These potential exposures result because taxing authorities may take positions that differ from those taken by management in the interpretation and application of statutes, regulations and rules. Management considers the possibility of alternative outcomes based upon past experience, previous actions by taxing authorities (e.g., actions taken in other jurisdictions) and advice from tax experts. Recognized tax positions are initially and subsequently measured as the largest amount of tax benefit that is more likely than not of being realized upon ultimate settlement with a taxing authority on a jurisdiction-by-jurisdiction basis. Liabilities for unrecognized tax benefits related to such tax positions are included in long-term liabilities unless the tax position is expected to be settled within the
upcoming year, in which case the liabilities are included in current liabilities. Interest and penalties related to uncertain tax positions are included in income tax expense.
Environmental
Barnwell is subject to extensive environmental laws and regulations. These laws, which are constantly changing, regulate the discharge of materials into the environment and maintenance of surface conditions and may require Barnwell to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefit are expensed. Liabilities for expenditures of a noncapital nature are recorded when environmental assessment and/or remediation is probable, and the costs can be reasonably estimated.
Barnwell recognizes an insurance receivable related to environmental expenditures when collection of the receivable is deemed probable. Any recognition of an insurance receivable is recorded by crediting and offsetting the original charge. Any differential arising between insurance recoveries and insurance receivables is expensed or capitalized, consistent with the original treatment.
Foreign Currency 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,income (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,August 2018, the FASB issued ASU No. 2016-02, “Leases (Topic 842),2018-13, “Fair Value Measurement: Disclosure Framework-Changes to the Disclosure Requirements for Fair Value Measurement,” which requires an entityprovides changes 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.certain fair value disclosure requirements. 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, 2019.2020. The adoption of this update did not have an impact on Barnwell's consolidated financial statements.
In JulyAugust 2018, the FASB issued ASU No. 2018-09, “Codification Improvements,2018-14, “Compensation - Retirement Benefits-Defined Benefit Plans - General: Disclosure Framework-Changes to the Disclosure Requirements for Defined Benefit Plans,” which provides further clarificationchanges to the codification literature. certain pension and postretirement plan disclosures.
The Company adopted the provisions of this ASU effective October 1, 2019.2020. The adoption of this update did not have an impact on Barnwell's consolidated financial statements.
ImpactIn 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. The Company adopted the provisions 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 operationsthis ASU effective October 1, 2020. The adoption 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 isthis update did 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 effectimpact 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,Barnwell's consolidated financial condition and results of operations.statements.
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.
Our ability to sustain our business in the future will depend on sufficientthe sufficiency of our cash on hand, 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 and 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. In addition, as discussed in the "Asset Retirement Obligation" section of "Liquidity and Capital Resources," a significant amount of funds will be required to be put on deposit with Canadian regulatory authorities to fund abandonments at the Company's oil and natural gas properties in the Manyberries area. Other sources and potential sources of funding are discussed below.
In fiscal 2020, the Company listed its corporate office on the 29th floor of a commercial office building in downtown Honolulu, Hawaii for sale and on September 30, 2021, the Company’s Honolulu corporate office was sold for approximately $1,864,000, net of related costs.
On March 16, 2021, the Company initiated an at-the-market offering program (“ATM”) pursuant to which the Company may offer and sell, from time to time, shares of its common stock under price and volume guidelines set by the Company's Board of Directors and the terms and conditions described in the Registration Statement. The sale of shares under the ATM began in May 2021 and as of September 30, 2021, the Company sold 1,167,987 shares of common stock resulting in net proceeds of $3,784,000 after commissions and fees of $123,000.
In April 2021, the Company re-initiated the marketing of its non-core oil and natural gas properties in the Spirit River, Wood River, Medicine River, Kaybob, Bonanza, Balsam and Thornbury areas for sale. On July 8, 2021, Barnwell entered into and completed a purchase and sale agreement with an independent third party and sold its interests in certain natural gas and oil properties located in the Spirit River area of Alberta, Canada. The sales price per the agreement was adjusted for customary purchase price adjustments to $1,047,000 in order to, among other things, reflect an economic effective closing date of sale of July 8, 2021. From Barnwell's net proceeds, $526,000 was withheld for remittance by the buyers to the Canada Revenue Agency for potential amounts due for Barnwell’s Canadian income taxes related to the sale.
Negotiations regarding the potential sales of other non-core oil and natural gas properties is ongoing, however there is no assurance that the sale of any of the other non-core properties will occur.
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 duringDuring 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 as2021, continuing uncertainties regarding the potential duration and depth of the impacts of the COVID-19 pandemic on our business and the sufficiency of our cash balances and future cash inflows as described above raised substantial doubt about our ability to meet our estimated cash outflows or continue as a going concern. However, due to the $3,784,000 of net proceeds raised by the ATM through September 30, 2021, the proceeds received from the sale of the Company's corporate office and its interests in certain natural gas and oil properties in the Spirit River area, as well as the $7,156,000 of net cash inflows in the year ended September 30, 2021 from land segment percentage of sales proceeds and distributions from the Kukio Resort Land Development Partnerships, substantial doubt about our ability to meet our estimated cash outflows or 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.has been overcome.
3. LOSSEARNINGS (LOSS) PER COMMON SHARE
Basic lossearnings (loss) per share is computed using the weighted-average number of common shares outstanding for the period. Dilutedloss earnings (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 lossearnings (loss) per share if their effect is anti-dilutive.
There were 0 options outstanding at September 30, 2020. Options to purchase 318,750615,000 shares of common stock waswere excluded from the computation of diluted shares for the year ended September 30, 2019,2021, as their inclusion would have been antidilutive. There were no options outstanding at September 30, 2020.
Reconciliations between net lossearnings (loss) attributable to Barnwell stockholders and common shares outstanding of the basic and diluted net lossearnings (loss) per share computations are detailed in the following tables:
| | | | | Year ended September 30, 2021 |
| | | | Net Earnings | | Shares | | Per-Share |
| | | | (Numerator) | | (Denominator) | | Amount |
| Basic net earnings per share | | Basic net earnings per share | $ | 6,253,000 | | | 8,592,154 | | | $ | 0.73 | |
| Effect of dilutive securities - common stock options | | Effect of dilutive securities - common stock options | — | | | — | | | |
| Diluted net earnings per share | | Diluted net earnings per share | $ | 6,253,000 | | | 8,592,154 | | | $ | 0.73 | |
| | | | Year ended September 30, 2020 | | Year ended September 30, 2020 |
| | | Net Loss | | Shares | | Per-Share | | Net Loss | | Shares | | Per-Share |
| | | (Numerator) | | (Denominator) | | Amount | | (Numerator) | | (Denominator) | | Amount |
| Basic net loss per share | Basic net loss per share | $ | (4,756,000) | | | 8,277,160 | | | $ | (0.57) | | Basic net loss per share | $ | (4,756,000) | | | 8,277,160 | | | $ | (0.57) | |
| Effect of dilutive securities - common stock options | Effect of dilutive securities - common stock options | — | | | 0 | | | | Effect of dilutive securities - common stock options | — | | | — | | | |
| Diluted net loss per share | Diluted net loss per share | $ | (4,756,000) | | | 8,277,160 | | | $ | (0.57) | | 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 | — | | | 0 | | | | |
| 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 | $ | 0 | | | $ | (42,000) | |
| Income tax effect | $ | 0 | | | $ | 0 | |
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 0 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 0 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 | 0 | | | 0 | | | | | |
| Exercised | 0 | | | 0 | | | | | |
| Expired/Forfeited | (30,000) | | | 3.01 | | | | | |
| Outstanding at September 30, 2020 | 0 | | | $ | 0 | | | — | | | $ | 0 | |
| Exercisable at September 30, 2020 | 0 | | | $ | 0 | | | — | | | $ | 0 | |
There was 0 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 | — | | NaN |
| Expected term (in years) | — | | 0.2 to 0.5 |
| Risk-free interest rate | — | | 1.8% to 1.9% |
| Expected forfeitures | — | | NaN |
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 | 0 | | | 0 | | | | | |
| Exercised | 0 | | | 0 | | | | | |
| Expired/Forfeited | (288,750) | | | 4.18 | | | | | |
| Outstanding at September 30, 2020 | 0 | | | $ | 0 | | | — | | | $ | 0 | |
| Exercisable at September 30, 2020 | 0 | | | $ | 0 | | | — | | | $ | 0 | |
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 | $ | 0 | | | $ | 0 | |
| Due to remeasurement | 0 | | | (42,000) | |
| Total share-based compensation benefit for liability-based awards | $ | 0 | | | $ | (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.
6.4. 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 | 0 | | | 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 2 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 areis 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. NaN ocean front parcels approximately 2 to 3 acres in size fronting the ocean were developed within Increment II by KD II, of which 1 was sold in fiscal 2017 and 1 was sold in fiscal 2016. The remaining acreage within Increment II is not yet under development, and there is no assurance that development of such acreage will in fact occur. No definitive development plans have been made by the developer of Increment II as of the date of this report.
In March 2019, KD II admitted a new development partner, Replay, a party unrelated to Barnwell, in an effort to move forward with development of the remainder of Increment II at Kaupulehu. Effective March 7, 2019, KDK and Replay hold ownership interests of 55% and 45%, respectively, of KD II. Accordingly,II and Barnwell has a 10.8% indirect non-controlling ownership interest in KD II through KDK, as of that date that will continue to bewhich is accounted for using the equity method of accounting. Barnwell continues to have an indirect 19.6% non-controlling ownership interest in KD Kukio Resorts, KD Maniniowali, and KD I.
Barnwell has the right to receive distributions from the Kukio Resort Land Development Partnerships via its non-controlling interests in KD Kona and KKM, based on its respective partnership sharing ratios.ratios of 75% and 34.45%, respectively. Additionally, Barnwell iswas 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 Augustthe quarter ended December 31, 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.I. Accordingly, Barnwell received a $197,000 partial paymenttotal of the$459,000 in preferred return in August 2020,payments, 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 1 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, 2020.2021. The preferred return payments received after Septemberin the quarter ended December 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.
During the year ended September 30, 2021, Barnwell received net cash distributions in the amount of $6,011,000 from the Kukio Resort Land Development Partnerships after distributing $683,000 to non-controlling interests. Of the $6,011,000 net cash distribution received from the Kukio Resort Land Development Partnerships, $459,000 represented a payment of the preferred return from KKM, as discussed above. 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 interests.KKM.
Barnwell's share of the operating results of its equity affiliates was income of $352,000 for the year ended September 30, 2020,$5,793,000, which includes the $197,000 partial$459,000 payment of the preferred return from KKM discussed above, as compared to a loss of $276,000 for the year ended September 30, 2019.2021, as compared to income of $352,000, which includes a preferred return payment of $197,000 from KKM, for the year ended September 30, 2020. 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$138,000 as of September 30, 2020,2021, 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$146,000 and $18,000,$13,000, for the years ended September 30, 20202021 and 2019,2020, respectively, increased equity in income of affiliates.
Summarized financial information for the Kukio Resort Land Development Partnerships is as follows:
| | | | Year ended September 30, | | Year ended September 30, |
| | | 2020 | | 2019 | | 2021 | | 2020 |
| Revenue | Revenue | $ | 7,911,000 | | | $ | 7,507,000 | | Revenue | $ | 43,013,000 | | | $ | 7,911,000 | |
| Gross profit | Gross profit | $ | 4,071,000 | | | $ | 3,157,000 | | Gross profit | $ | 24,759,000 | | | $ | 4,071,000 | |
| Net earnings (loss) | $ | 618,000 | | | $ | (1,095,000) | | |
| Net earnings | | Net earnings | $ | 20,612,000 | | | $ | 618,000 | |
During the year ended September 30, 2021, the Company received cumulative distributions from the Kukio Resort Land Development Partnerships in excess of our investment balance and in accordance with applicable accounting guidance, the Company suspended its equity method earnings recognition and reduced its Kukio Resort Land Development Partnership investment balance to zero as of September 30, 2021. In addition, the Company recorded the distributions received in excess of our investment balance of $654,000 as equity in income of affiliates during the year ended September 30, 2021. The Company records the distributions in excess of our investment in the Kukio Resort Land Development Partnerships as income because the distributions are not refundable by agreement or by law and the Company is not liable for the obligations of or otherwise committed to provide financial support to the Kukio Resort Land Development Partnerships. The Company will record future equity method earnings only after our share of the Kukio Resort Land Development Partnership’s cumulative earnings during the suspended period exceeds our share of the Kukio Resort Land Development Partnership’s income recognized for the excess distributions.
At September 30, 2020, the Company’s investment in the Kukio Resort Land Development Partnerships was $901,000.
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)20).
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, 22021, 8 single-family lots in Increment I were sold bringing the total amount of gross proceeds from single-family lot sales through September 30, 20202021 to $219,700,000.$237,038,000. As of the date of this report, with the inclusion of the November 2020 lot sale mentioned above, 16September 30, 2021, 9 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. NaN ocean front parcels approximately 2 to 3 acres in size fronting the ocean were developed within Increment II by KD II, of which 1 was sold in fiscal 2017 and 1 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 3 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 willdoes not have any partnership interests in KD II or KDK through its interest in Kaupulehu Developments. The new arrangement also gives Barnwell rights to 3 single-family residential lots in Phase 2A of Increment II, and 4 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 4 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 1718 “Commitments and Contingencies - Other Matters”):
| | | | Year ended September 30, | | Year ended September 30, |
| | | 2020 | | 2019 | | 2021 | | 2020 |
| Sale of interest in leasehold land: | Sale of interest in leasehold land: | | | | Sale of interest in leasehold land: | | | |
| Revenues - sale of interest in leasehold land | Revenues - sale of interest in leasehold land | $ | 325,000 | | | $ | 165,000 | | Revenues - sale of interest in leasehold land | $ | 1,738,000 | | | $ | 325,000 | |
| Fees - included in general and administrative expenses | Fees - included in general and administrative expenses | (40,000) | | | (20,000) | | Fees - included in general and administrative expenses | (212,000) | | | (40,000) | |
| Sale of interest in leasehold land, net of fees paid | Sale of interest in leasehold land, net of fees paid | $ | 285,000 | | | $ | 145,000 | | Sale of interest in leasehold land, net of fees paid | $ | 1,526,000 | | | $ | 285,000 | |
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 1 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. There is no assurance with regards to the amounts of future payments from Increment I or Increment II to be received.received, or that the remaining acreage within Increment II will be developed. No definitive development plans have been made by the developer of Increment II as of the date of this report.
Investment in Leasehold Land Interest – Lot 4C
Kaupulehu Developments holds an interest in an area of approximately 1,000 acres of vacant leasehold land zoned conservation located adjacent to Lot 4A, which currently has no development potential without both a development agreement with the lessor and zoning reclassification. The lease terminates in December 2025. Due to recent
In 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 the uncertainty regarding the timing of future development and potential use of water rights within Lot 4C prior to the expiration of the lease term,term.
5. CONSOLIDATED VARIABLE INTEREST ENTITY
In February 2021, Barnwell Industries, Inc. established a new wholly-owned subsidiary named BOK Drilling, LLC (“BOK”) for the purpose of indirectly investing in oil and natural gas exploration and development in Oklahoma. BOK and Gros Ventre Partners, LLC (“Gros Ventre”), an entity affiliated with the Company, entered into the Limited Liability Agreement (the “Agreement”) of Teton Barnwell Fund I, LLC (“Teton Barnwell”), an entity formed for the purpose of directly entering into such oil and natural gas investments. Under the terms of the Agreement, the profits of Teton Barnwell are split between BOK and Gros Ventre at 98% and 2%, respectively, and as the manager of Teton Barnwell, Gros Ventre is paid an annual asset management fee equal to 1% of the cumulative capital contributions made to Teton Barnwell as compensation for its management services. BOK is responsible for 100% of the capital contributions made to Teton Barnwell and as of September 30, 2021, the Company made a total of $750,000 in capital contributions to Teton Barnwell to fund its oil and natural gas investments in Oklahoma.
The Company has determined there was an impairmentthat Teton Barnwell is a VIE as the entity is structured with non-substantive voting rights and that the Company is the primary beneficiary. This is due to the fact that even though Teton Barnwell has a unanimous consent voting structure, BOK is responsible for 100% of the capital contributions required to fund Teton Barnwell’s future oil exploration and development investments pursuant to the Agreement and thus, BOK has the power to steer the decisions that most significantly impact Teton Barnwell’s economic performance and has the obligation to absorb any potential losses that could be significant to Teton Barnwell. As BOK is the primary beneficiary of the VIE, Teton Barnwell’s operating results, assets and liabilities are consolidated by the Company.
Mr. Colin R. O'Farrell, a member of the Board of Directors of the Company effective July 12, 2021, is the sole member of Four Pines Operating LLC which owns a 25% interest in Gros Ventre. Mr. O'Farrell's influence as a member of the Board of Directors of the Company further supports the consolidation of Teton Barnwell's operating results, assets and liabilities as discussed above.
The following table summarizes the carrying value of Lot 4Cthe assets and liabilities of Teton Barnwell that are consolidated by the Company. Intercompany balances are eliminated in consolidation and thus, are not reflected in the table below.
| | | | | |
| September 30,
2021 |
| ASSETS | |
| Cash and cash equivalents | $ | 136,000 | |
| Accounts and other receivables | 118,000 | |
| Oil and natural gas properties, full cost method of accounting: | |
| Proved properties, net | 203,000 | |
| Unproved properties | 962,000 | |
| Total assets | $ | 1,419,000 | |
| |
| LIABILITIES | |
| Accounts payable | $ | 3,000 | |
| Accrued capital expenditures | 581,000 | |
| Accrued operating and other expenses | 20,000 | |
| Total liabilities | $ | 604,000 | |
6. ASSETS HELD FOR SALE
Honolulu Corporate Office
The Company’s Honolulu corporate office was designated as an asset held for sale and the Company recorded a $50,000 write-offcarrying value in its investment in leasehold land interest in Lot 4C, which isthe aggregate amount of $699,000 was included in “Impairment“Asset held for sale” on the Company's Consolidated Balance Sheet at September 30, 2020. On September 30, 2021, the Company’s Honolulu corporate office was sold for approximately $1,864,000, net of assets”related costs, resulting in the accompanying Consolidated Statementsa gain of Operations for$1,164,000, which was recognized in the year ended September 30, 2020.2021.
Contract Segment Drilling Rig and Equipment
In September 2021, the Company designated a contract drilling segment drilling rig and related ancillary equipment, with an aggregate net carrying value of $725,000, as assets held for sale and recorded an impairment of $38,000 to reduce the value of these assets to its fair value, less estimated selling costs. The fair value of these assets in the aggregate amount of $687,000 is recorded as “Assets held for sale” on the Company's Consolidated Balance Sheet at September 30, 2021.
7. OIL AND NATURAL GAS PROPERTIES
Dispositions
In April 2021, Barnwell entered into a purchase and sale agreement with an independent third party and sold its interests in properties located in the Hillsdown area of Alberta, Canada. The sales price per the agreement was adjusted for customary purchase price adjustments to $132,000 in order to, among other things, reflect an economic effective date of October 1, 2020. $72,000 of the sales proceeds was withheld by the buyers for potential amounts due for Barnwell’s Canadian income taxes related to the sale. The final determination of the customary adjustments to the purchase price has not yet been made, however it is not expected to result in a material adjustment. The proceeds were credited to the full cost pool, with no gain or loss recognized, as the sale did not result in a significant alteration of the relationship between capitalized costs and proved reserves.
On July 8, 2021, Barnwell entered into and completed a purchase and sale agreement with an independent third party and sold its interests in certain natural gas and oil properties located in the Spirit River area of Alberta, Canada. The sales price per the agreement was adjusted for customary purchase price adjustments to $1,047,000 in order to, among other things, reflect an economic effective closing date of sale of July 8, 2021. From Barnwell's net proceeds, $526,000 was withheld for remittance by the buyers to the Canada Revenue Agency for potential amounts due for Barnwell’s Canadian income taxes related to the sale.
The difference in the relationship between capitalized costs and proved reserves of the Spirit River properties sold as compared to the properties retained by Barnwell was significant as there was a 93%difference in capitalized costs divided by proved reserves if the gain was recorded versus the gain being credited against the full-cost pool. Accordingly, Barnwell recorded a gain on the sale of Spirit River of $818,000 in the year ended September 30, 2021 in accordance with the guidance in Rule 4-10(c)(6)(i) of Regulation S-X of the rules and regulations of the SEC, which requires an allocation of capitalized costs to the reserves sold and reserves retained on the basis of the relative fair values of the properties as there was a substantial economic difference between the properties sold and those retained. Also included in the gain calculation were asset retirement obligations of $77,000 assumed by the purchaser.
In the quarter ended December 31, 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,April 2021, Barnwell acquired additional working interests in oil and natural gas properties located in the Wood River and Twining areasarea of Alberta, Canada for cash consideration of $355,000.$348,000. The purchase pricesprice per the agreements wereagreement was adjusted for customary purchase price adjustments to reflect the economic activity from the effective date to the closing date. The final determination of the customary adjustments to the purchase prices were finalizedprice has not yet been made, however it is not expected to result in the quarter ended June 30, 2019 and resulted in an immateriala material adjustment.
There were no othersignificant amounts paid for oil and natural gas working interestproperty acquisitions during the year ended September 30, 2019.2020.
Impairment of Oil and Natural Gas Properties
Under the full cost method of accounting, the Company performs quarterly oil and natural gas ceiling test calculations. There was a ceiling test impairment of $4,326,000$630,000 during the year ended September 30, 2020.2021. There was a $5,710,000$4,326,000 ceiling test impairment during the year ended September 30, 2019.2020.
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.
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.
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 | | | $ | 0 | | | $ | — | | | $ | 0 | |
| 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, 2021: | | | | | | | |
| | | | | | | |
Oil and natural gas properties:
(full cost accounting) | | | | | | | |
| Proved properties | | | $ | 58,490,000 | | | $ | (56,067,000) | | | $ | 2,423,000 | |
| Unproved properties | | | 962,000 | | | — | | | 962,000 | |
| Total oil and natural gas properties | | | 59,452,000 | | | (56,067,000) | | | 3,385,000 | |
| Drilling rigs and equipment | 3 – 10 years | | 7,273,000 | | | (6,789,000) | | | 484,000 | |
| | | | | | | |
| Other property and equipment | 3 – 10 years | | 687,000 | | | (681,000) | | | 6,000 | |
| Total | | | $ | 67,412,000 | | | $ | (63,537,000) | | | $ | 3,875,000 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| 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 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Estimated
Useful
Lives | | Gross
Property and
Equipment | | Accumulated
Depletion,
Depreciation, Amortization, and Impairment | | Net
Property and
Equipment |
| At September 30, 2020: | | | | | | | |
| | | | | | | |
Oil and natural gas properties:
(full cost accounting) | | | | | | | |
| Proved properties | | | $ | 64,142,000 | | | $ | (61,839,000) | | | $ | 2,303,000 | |
| Unproved properties | | | — | | | — | | | — | |
| Total oil and natural gas properties | | | 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 | |
See Note 7 for discussion of acquisitions and divestitures of oil and natural gas properties in fiscal 20202021 and 2019.2020.
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, | | Year ended September 30, |
| | | 2020 | | 2019 | | 2021 | | 2020 |
| Asset retirement obligation as of beginning of year | Asset retirement obligation as of beginning of year | $ | 6,389,000 | | | $ | 7,122,000 | | Asset retirement obligation as of beginning of year | $ | 6,194,000 | | | $ | 6,389,000 | |
| Obligations incurred on new wells drilled or acquired | Obligations incurred on new wells drilled or acquired | 227,000 | | | 203,000 | | Obligations incurred on new wells drilled or acquired | 532,000 | | | 227,000 | |
| Liabilities associated with properties sold | Liabilities associated with properties sold | (169,000) | | | (43,000) | | Liabilities associated with properties sold | (375,000) | | | (169,000) | |
| Revision of estimated obligation | Revision of estimated obligation | (279,000) | | | (958,000) | | Revision of estimated obligation | 279,000 | | | (279,000) | |
| Accretion expense | Accretion expense | 561,000 | | | 608,000 | | Accretion expense | 580,000 | | | 561,000 | |
| Payments | Payments | (498,000) | | | (372,000) | | Payments | (421,000) | | | (498,000) | |
| Foreign currency translation adjustment | Foreign currency translation adjustment | (37,000) | | | (171,000) | | Foreign currency translation adjustment | 264,000 | | | (37,000) | |
| Asset retirement obligation as of end of year | Asset retirement obligation as of end of year | 6,194,000 | | | 6,389,000 | | Asset retirement obligation as of end of year | 7,053,000 | | | 6,194,000 | |
| Less current portion | Less current portion | (647,000) | | | (330,000) | | Less current portion | (713,000) | | | (647,000) | |
| Asset retirement obligation, long-term | Asset retirement obligation, long-term | $ | 5,547,000 | | | $ | 6,059,000 | | Asset retirement obligation, long-term | $ | 6,340,000 | | | $ | 5,547,000 | |
Asset retirement obligations were reduced by $169,000$375,000 and $43,000,$169,000, in fiscal 20202021 and 2019,2020, respectively, for those obligations that were assumed by purchasers of Barnwell's oil and natural gas properties. Asset retirement obligations were also reducedincreased by $279,000 and $958,000in fiscal 2021 as compared to a reduction of $279,000 in fiscal 2020 and 2019, respectively,primarily due to downwardupward revisions related to deferralsfrom acceleration in the estimated timing of future abandonments as a result of changes in the estimated economic life of certain wells and changes in management's discretionary timing of abandonment projects due to an increase in estimated funds available to develop the Company's reservesas well as an increase in the Twining area.estimated cost of abandonments at the Manyberries area, as further discussed below. Asset retirement obligations increased by $227,000$532,000 and $203,000$227,000 in fiscal 20202021 and 2019,2020, 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%.
In September 2019, the AER issued an abandonment/closure order for all wells and facilities in the Manyberries area which had been largely operated by LGX, an operating company that went into receivership in 2016. The estimated asset retirement obligation for the Company's interest in the wells and facilities in the Manyberries area is included in “Asset retirement obligation” in the Consolidated Balance Sheets.
Recently, the OWA created a WIP program for specific areas where there are a significant number of orphaned wells to abandon. The OWA has the ability and expertise to abandon wells using its internal resources and network of service providers resulting in efficiencies that companies such as Barnwell, would not be able to obtain on its own. Under the WIP program, the Company would be required to provide payment for only Barnwell’s working interest share, however, all WIP’s would have to participate in the program for the OWA to begin its work. In March 2021, the Company was notified by the OWA that Barnwell’s Manyberries wells were confirmed to be in the WIP program.
Under the new agreement with the OWA, the Company is required to pay the abandonment and reclamation costs in advance through a cash deposit. The total cash deposit amount was calculated to be approximately $1,525,000 and the Company paid $888,000 of the total deposit in July and August 2021
and will need to pay the remaining balance of $637,000 by August 2022. The deposit balance at September 30, 2021, less draw-downs by the OWA for OWA-performed abandonments, was $809,000 and is reflected in "Other current assets" in the Consolidated Balance Sheet as of September 30, 2021. There is no right of offset between the deposit with the OWA and the Company's ARO liability balance. The Company revised its Manyberries ARO liability based on the OWA’s revised abandonment and reclamation estimates, which resulted in an increase of approximately $213,000 in the current year. The increase in the ARO liability was a result of higher reclamation and remediation costs than anticipated, partially offset by lower abandonment estimates. A remaining excess deposit, if any, would ultimately be refunded to the Company upon completion of all of the work.
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 previously sponsored a postretirementpost-retirement medical insurance benefits plan (“PostretirementPost-retirement Medical”) covering officers of Barnwell Industries, Inc., the parent company, who have attained at least 20 years of service of which at least 10 years were at the position of Vice President or higher, their spouses and qualifying dependents.
In 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.
In June 2021, the Company terminated its Post-retirement Medical plan effective June 4, 2021. Pursuant to the Post-retirement Medical plan document, the Company, as the sponsor of the Post-retirement Medical plan, had the right to terminate the plan within sixty days’ notice to each participant and the plan may be terminated by the resolution of the Board of the Directors of the Company. Further, under the terms of the plan document, the participants in the Post-retirement Medical plan were not entitled to any unpaid vested benefits thereunder upon termination of the plan. The Post-retirement Medical plan was an unfunded plan and the Company funded benefits when payments were made. As a result of the plan termination, the Company recognized a non-cash gain of $2,341,000 during the year ended September 30, 2021.
The following tables detail the changes in benefit obligations, fair values of plan assets and reconciliations of the funded status of the retirement plans:
| | | | Pension | | SERP | | Postretirement Medical | | Pension | | SERP | | Post-retirement Medical |
| | | September 30, | | September 30, |
| | | 2020 | | 2019 | | 2020 | | 2019 | | 2020 | | 2019 | | 2021 | | 2020 | | 2021 | | 2020 | | 2021 | | 2020 |
| Change in Projected Benefit Obligation: | Change in Projected Benefit Obligation: | | | | | | | | | | | Change in Projected Benefit Obligation: | | | | | | | | | | |
| Benefit obligation at beginning of year | Benefit obligation at beginning of year | $ | 10,971,000 | | | $ | 9,164,000 | | | $ | 2,385,000 | | | $ | 2,039,000 | | | $ | 2,633,000 | | | $ | 2,382,000 | | Benefit obligation at beginning of year | $ | 10,280,000 | | | $ | 10,971,000 | | | $ | 2,031,000 | | | $ | 2,385,000 | | | $ | 2,839,000 | | | $ | 2,633,000 | |
| Service cost | Service cost | 50,000 | | | 189,000 | | | 3,000 | | | 32,000 | | | 0 | | | 0 | | Service cost | — | | | 50,000 | | | — | | | 3,000 | | | — | | | — | |
| Interest cost | Interest cost | 304,000 | | | 372,000 | | | 63,000 | | | 78,000 | | | 80,000 | | | 99,000 | | Interest cost | 258,000 | | | 304,000 | | | 51,000 | | | 63,000 | | | 48,000 | | | 80,000 | |
| Actuarial loss (gain) | 504,000 | | | 1,426,000 | | | (90,000) | | | 236,000 | | | 134,000 | | | 161,000 | | |
| Actuarial (gain) loss | | Actuarial (gain) loss | (15,000) | | | 504,000 | | | 63,000 | | | (90,000) | | | — | | | 134,000 | |
| Benefits paid | Benefits paid | (153,000) | | | (180,000) | | | 0 | | | 0 | | | (8,000) | | | (9,000) | | Benefits paid | (158,000) | | | (153,000) | | | (9,000) | | | — | | | (5,000) | | | (8,000) | |
| | Curtailments | Curtailments | (1,396,000) | | | 0 | | | (330,000) | | | 0 | | | — | | | — | | Curtailments | — | | | (1,396,000) | | | — | | | (330,000) | | | — | | | — | |
| Termination of post-retirement medical plan | | Termination of post-retirement medical plan | — | | | — | | | — | | | — | | | (2,882,000) | | | — | |
| Benefit obligation at end of year | Benefit obligation at end of year | 10,280,000 | | | 10,971,000 | | | 2,031,000 | | | 2,385,000 | | | 2,839,000 | | | 2,633,000 | | Benefit obligation at end of year | 10,365,000 | | | 10,280,000 | | | 2,136,000 | | | 2,031,000 | | | — | | | 2,839,000 | |
| Change in Plan Assets: | Change in Plan Assets: | | | | | | | | | | | | Change in Plan Assets: | | | | | | | | | | | |
| Fair value of plan assets at beginning of year | Fair value of plan assets at beginning of year | 10,192,000 | | | 10,012,000 | | | — | | | — | | | — | | | — | | Fair value of plan assets at beginning of year | 11,051,000 | | | 10,192,000 | | | — | | | — | | | — | | | — | |
| Actual return on plan assets | Actual return on plan assets | 1,012,000 | | | 245,000 | | | — | | | — | | | — | | | — | | Actual return on plan assets | 1,701,000 | | | 1,012,000 | | | — | | | — | | | — | | | — | |
| Employer contributions | Employer contributions | 0 | | | 115,000 | | | 0 | | | 0 | | | 8,000 | | | 9,000 | | Employer contributions | — | | | — | | | — | | | — | | | 5,000 | | | 8,000 | |
| Benefits paid | Benefits paid | (153,000) | | | (180,000) | | | 0 | | | 0 | | | (8,000) | | | (9,000) | | Benefits paid | (158,000) | | | (153,000) | | | — | | | — | | | (5,000) | | | (8,000) | |
| | Fair value of plan assets at end of year | Fair value of plan assets at end of year | 11,051,000 | | | 10,192,000 | | | — | | | — | | | — | | | — | | Fair value of plan assets at end of year | 12,594,000 | | | 11,051,000 | | | — | | | — | | | — | | | — | |
| Funded status | Funded status | $ | 771,000 | | | $ | (779,000) | | | $ | (2,031,000) | | | $ | (2,385,000) | | | $ | (2,839,000) | | | $ | (2,633,000) | | Funded status | $ | 2,229,000 | | | $ | 771,000 | | | $ | (2,136,000) | | | $ | (2,031,000) | | | $ | — | | | $ | (2,839,000) | |
| | | | Pension | | SERP | | Postretirement Medical | | Pension | | SERP | | Post-retirement Medical |
| | | September 30, | | September 30, |
| | | 2020 | | 2019 | | 2020 | | 2019 | | 2020 | | 2019 | | 2021 | | 2020 | | 2021 | | 2020 | | 2021 | | 2020 |
| Amounts recognized in the Consolidated Balance Sheets: | Amounts recognized in the Consolidated Balance Sheets: | | | Amounts recognized in the Consolidated Balance Sheets: | | |
| Noncurrent assets | Noncurrent assets | $ | 771,000 | | | $ | 0 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | Noncurrent assets | $ | 2,229,000 | | | $ | 771,000 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
| Current liabilities | Current liabilities | — | | | — | | | (32,000) | | | (2,000) | | | (9,000) | | | (10,000) | | Current liabilities | — | | | — | | | (35,000) | | | (32,000) | | | — | | | (9,000) | |
| Noncurrent liabilities | Noncurrent liabilities | 0 | | | (779,000) | | | (1,999,000) | | | (2,383,000) | | | (2,830,000) | | | (2,623,000) | | Noncurrent liabilities | — | | | — | | | (2,101,000) | | | (1,999,000) | | | — | | | (2,830,000) | |
| Net amount | Net amount | $ | 771,000 | | | $ | (779,000) | | | $ | (2,031,000) | | | $ | (2,385,000) | | | $ | (2,839,000) | | | $ | (2,633,000) | | Net amount | $ | 2,229,000 | | | $ | 771,000 | | | $ | (2,136,000) | | | $ | (2,031,000) | | | $ | — | | | $ | (2,839,000) | |
| Amounts recognized in accumulated other comprehensive loss (income) before income taxes: | | | |
| Amounts recognized in accumulated other comprehensive income (loss) before income taxes: | | Amounts recognized in accumulated other comprehensive income (loss) before income taxes: | | |
| Net actuarial loss | Net actuarial loss | $ | 1,681,000 | | | $ | 2,939,000 | | | $ | 72,000 | | | $ | 497,000 | | | $ | 721,000 | | | $ | 667,000 | | Net actuarial loss | $ | 471,000 | | | $ | 1,681,000 | | | $ | 135,000 | | | $ | 72,000 | | | $ | — | | | $ | 721,000 | |
| Prior service cost (credit) | Prior service cost (credit) | 0 | | | 54,000 | | | 0 | | | (54,000) | | | 0 | | | 0 | | Prior service cost (credit) | — | | | — | | | — | | | — | | | — | | | — | |
| Accumulated other comprehensive loss | Accumulated other comprehensive loss | $ | 1,681,000 | | | $ | 2,993,000 | | | $ | 72,000 | | | $ | 443,000 | | | $ | 721,000 | | | $ | 667,000 | | Accumulated other comprehensive loss | $ | 471,000 | | | $ | 1,681,000 | | | $ | 135,000 | | | $ | 72,000 | | | $ | — | | | $ | 721,000 | |
Currently, 0no contributions will be made to the Pension Plan during fiscal 2021.2022. The SERP and Postretirement Medical plans areplan is unfunded and Barnwell funds benefits when payments are made. Expected payments under the Postretirement Medical plan and SERP for fiscal 2021 are2022 is not material.
Fluctuations in actual market returns as well as changes in general interest rates will result in changes in the market value of plan assets and may result in increased or decreased retirement benefits costs and contributions in future periods.
The Pension Plan actuarial gains in fiscal 2021 were primarily due to an increase in the discount rate and actual investment returns that were greater than the assumed rate of return. The SERP actuarial losses in fiscal 2021 were primarily due to an updated mortality projection scale and adjustments due to experience, partially offset by an increase in the discount rate.
The 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 PostretirementPost-retirement 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 | | Pension | | SERP | | Post-retirement Medical |
| | | Year ended September 30, | | Year ended September 30, |
| | | 2020 | | 2019 | | 2020 | | 2019 | | 2020 | | 2019 | | 2021 | | 2020 | | 2021 | | 2020 | | 2021 | | 2020 |
| Assumptions used to determine fiscal year-end benefit obligations: | Assumptions used to determine fiscal year-end benefit obligations: | | | | | Assumptions used to determine fiscal year-end benefit obligations: | | | | |
| Discount rate | Discount rate | 2.54% | | 3.06% | | 2.54% | | 3.06% | | 2.54% | | 3.06% | Discount rate | 2.84% | | 2.54% | | 2.84% | | 2.54% | | N/A | | 2.54% |
| Rate of compensation increase | Rate of compensation increase | N/A | | 4.00% | | N/A | | 4.00% | | N/A | | N/A | Rate of compensation increase | N/A | | N/A | | N/A | | N/A | | N/A | | N/A |
| Assumptions used to determine net benefit costs (years ended): | Assumptions used to determine net benefit costs (years ended): | | | | | | | Assumptions used to determine net benefit costs (years ended): | | | | | | |
| Discount rate | Discount rate | 3.06% / 3.15%* | | 4.15% | | 3.06% / 3.15%* | | 4.15% | | 3.06% | | 4.15% | Discount rate | 2.54% | | 3.06% / 3.15%(1) | | 2.54% | | 3.06% / 3.15%(1) | | 2.54% / 3.00%(2) | | 3.06% |
| Expected return on plan assets | Expected return on plan assets | 6.50% | | 6.50% | | N/A | | N/A | | N/A | | N/A | Expected return on plan assets | 5.00% | | 6.50% | | N/A | | N/A | | N/A | | N/A |
| Rate of compensation increase | Rate of compensation increase | 4.00% | | 4.00% | | 4.00% | | 4.00% | | N/A | | N/A | Rate of compensation increase | N/A | | 4.00% | | N/A | | 4.00% | | N/A | | N/A |
*(1) 3.06% as of September 30, 2019 and 3.15% as of December 31, 2019 remeasurement.
(2) 2.54% as of September 30, 2020 and 3.00% as of May 31, 2021 termination.
We select a discount rate by reference to yields available on the 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 | | Pension | | SERP | | Post-retirement Medical |
| | | Year ended September 30, | | Year ended September 30, |
| | | 2020 | | 2019 | | 2020 | | 2019 | | 2020 | | 2019 | | 2021 | | 2020 | | 2021 | | 2020 | | 2021 | | 2020 |
| Net periodic benefit (income) cost for the year: | Net periodic benefit (income) cost for the year: | | | Net periodic benefit (income) cost for the year: | | |
| Service cost | Service cost | $ | 50,000 | | | $ | 189,000 | | | $ | 3,000 | | | $ | 32,000 | | | $ | 0 | | | $ | 0 | | Service cost | $ | — | | | $ | 50,000 | | | $ | — | | | $ | 3,000 | | | $ | — | | | $ | — | |
| Interest cost | Interest cost | 304,000 | | | 372,000 | | | 63,000 | | | 78,000 | | | 80,000 | | | 99,000 | | Interest cost | 258,000 | | | 304,000 | | | 51,000 | | | 63,000 | | | 48,000 | | | 80,000 | |
| Expected return on plan assets | Expected return on plan assets | (680,000) | | | (648,000) | | | 0 | | | 0 | | | 0 | | | 0 | | Expected return on plan assets | (546,000) | | | (680,000) | | | — | | | — | | | — | | | — | |
| Amortization of prior service cost (credit) | Amortization of prior service cost (credit) | 1,000 | | | 6,000 | | | (1,000) | | | (6,000) | | | 0 | | | 0 | | Amortization of prior service cost (credit) | — | | | 1,000 | | | — | | | (1,000) | | | — | | | — | |
| Amortization of net actuarial loss | Amortization of net actuarial loss | 35,000 | | | 2,000 | | | 5,000 | | | 0 | | | 80,000 | | | 53,000 | | Amortization of net actuarial loss | 39,000 | | | 35,000 | | | — | | | 5,000 | | | 62,000 | | | 80,000 | |
| Curtailment cost (income) | Curtailment cost (income) | 53,000 | | | 0 | | | (53,000) | | | 0 | | | 0 | | | 0 | | Curtailment cost (income) | — | | | 53,000 | | | — | | | (53,000) | | | — | | | — | |
| Net periodic benefit (income) cost | Net periodic benefit (income) cost | $ | (237,000) | | | $ | (79,000) | | | $ | 17,000 | | | $ | 104,000 | | | $ | 160,000 | | | $ | 152,000 | | Net periodic benefit (income) cost | $ | (249,000) | | | $ | (237,000) | | | $ | 51,000 | | | $ | 17,000 | | | $ | 110,000 | | | $ | 160,000 | |
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) | $ | 0 | | | $ | 0 | | | $ | — | |
| Net actuarial loss | 39,000 | | | 0 | | | 94,000 | |
| | $ | 39,000 | | | $ | 0 | | | $ | 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$10,365,000 and $9,600,000$10,280,000 at September 30, 20202021 and 2019,2020, respectively. The accumulated benefit obligation for the SERP was $2,031,000$2,136,000 and $2,032,000$2,031,000 at September 30, 20202021 and 2019,2020, respectively.
The benefits expected to be paid under the retirement plans as of September 30, 20202021 are as follows:
| | | Pension | | SERP | | Postretirement
Medical | | Pension | | SERP |
| Expected Benefit Payments: | Expected Benefit Payments: | | | | | | Expected Benefit Payments: | | | |
| Fiscal year ending September 30, 2021 | $ | 272,000 | | | $ | 32,000 | | | $ | 9,000 | | |
| Fiscal year ending September 30, 2022 | Fiscal year ending September 30, 2022 | $ | 391,000 | | | $ | 63,000 | | | $ | 20,000 | | Fiscal year ending September 30, 2022 | $ | 320,000 | | | $ | 35,000 | |
| Fiscal year ending September 30, 2023 | Fiscal year ending September 30, 2023 | $ | 455,000 | | | $ | 90,000 | | | $ | 33,000 | | Fiscal year ending September 30, 2023 | $ | 470,000 | | | $ | 97,000 | |
| Fiscal year ending September 30, 2024 | Fiscal year ending September 30, 2024 | $ | 517,000 | | | $ | 117,000 | | | $ | 50,000 | | Fiscal year ending September 30, 2024 | $ | 533,000 | | | $ | 123,000 | |
| Fiscal year ending September 30, 2025 | Fiscal year ending September 30, 2025 | $ | 508,000 | | | $ | 116,000 | | | $ | 69,000 | | Fiscal year ending September 30, 2025 | $ | 526,000 | | | $ | 122,000 | |
| Fiscal years ending September 30, 2026 through 2030 | $ | 2,653,000 | | | $ | 590,000 | | | $ | 391,000 | | |
| Fiscal year ending September 30, 2026 | | Fiscal year ending September 30, 2026 | $ | 519,000 | | | $ | 121,000 | |
| Fiscal years ending September 30, 2027 through 2031 | | Fiscal years ending September 30, 2027 through 2031 | $ | 2,840,000 | | | $ | 636,000 | |
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, | | Target | | September 30, |
| Asset Category | Asset Category | Allocation | | 2020 | | 2019 | Asset Category | Allocation | | 2021 | | 2020 |
| Cash and other | Cash and other | 0% - 15% | | 0% | | 0% | Cash and other | 0% - 15% | | —% | | —% |
| Fixed income securities | Fixed income securities | 25% - 55% | | 52% | | 38% | Fixed income securities | 15% - 40% | | 31% | | 52% |
| Equity securities | Equity securities | 40% - 60% | | 48% | | 62% | Equity securities | 45% - 75% | | 69% | | 48% |
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,
2021 | | Quoted
Prices in
Active
Markets
(Level 1) | | Significant
Other
Observable
Inputs
(Level 2) | | Significant
Unobservable
Inputs
(Level 3) |
| Financial Assets: | | Financial Assets: | | | | | | | |
| Cash | | Cash | $ | 25,000 | | | $ | 25,000 | | | $ | — | | | $ | — | |
| | Corporate bonds | | Corporate bonds | 1,000 | | | 1,000 | | | — | | | — | |
| Fixed income exchange-traded funds | | Fixed income exchange-traded funds | 3,809,000 | | | 3,809,000 | | | — | | | — | |
| Preferred securities | | Preferred securities | 48,000 | | | 48,000 | | | — | | | — | |
| Equity securities exchange-traded funds | | Equity securities exchange-traded funds | 459,000 | | | 459,000 | | | — | | | — | |
| Equities | | Equities | 8,252,000 | | | 8,252,000 | | | — | | | — | |
| Total | | Total | $ | 12,594,000 | | | $ | 12,594,000 | | | $ | — | | | $ | — | |
| | | | | | Fair Value Measurements Using: | | | | 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) | | 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: | Financial Assets: | | | | | | | | Financial Assets: | | | | | | | |
| | Corporate bonds | Corporate bonds | $ | 1,000 | | | $ | 1,000 | | | $ | — | | | $ | — | | Corporate bonds | $ | 1,000 | | | $ | 1,000 | | | $ | — | | | $ | — | |
| Fixed income exchange-traded funds | Fixed income exchange-traded funds | 5,762,000 | | | 5,762,000 | | | — | | | — | | Fixed income exchange-traded funds | 5,762,000 | | | 5,762,000 | | | — | | | — | |
| | Equity securities exchange-traded funds | Equity securities exchange-traded funds | 352,000 | | | 352,000 | | | — | | | — | | Equity securities exchange-traded funds | 352,000 | | | 352,000 | | | — | | | — | |
| Equities | Equities | 4,936,000 | | | 4,936,000 | | | — | | | — | | Equities | 4,936,000 | | | 4,936,000 | | | — | | | — | |
| Total | Total | $ | 11,051,000 | | | $ | 11,051,000 | | | $ | — | | | $ | — | | 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 lossearnings (loss) before income taxes, after adjusting the lossearnings (loss) for non-controlling interests, are as follows:
| | | Year ended September 30, | | Year ended September 30, |
| | 2020 | | 2019 | | 2021 | | 2020 |
| United States | United States | $ | 1,518,000 | | | $ | (3,039,000) | | United States | $ | 5,436,000 | | | $ | 1,518,000 | |
| Canada | Canada | (6,271,000) | | | (9,606,000) | | Canada | 1,149,000 | | | (6,271,000) | |
| | $ | (4,753,000) | | | $ | (12,645,000) | | | $ | 6,585,000 | | | $ | (4,753,000) | |
The components of the income tax provision (benefit) related to the above lossearnings (loss) are as follows:
| | | Year ended September 30, | | Year ended September 30, |
| | 2020 | | 2019 | | 2021 | | 2020 |
| Current benefit: | | | | |
| Current provision (benefit): | | Current provision (benefit): | | | |
| United States – Federal | United States – Federal | $ | 0 | | | $ | (31,000) | | United States – Federal | |
| Before operating loss carryforwards | | Before operating loss carryforwards | $ | 60,000 | | | $ | — | |
| Benefit of operating loss carryforwards | | Benefit of operating loss carryforwards | (60,000) | | | — | |
| After operating loss carryforwards | | After operating loss carryforwards | — | | | — | |
| United States – State | United States – State | (23,000) | | | (52,000) | | United States – State | | | |
| Before operating loss carryforwards | | Before operating loss carryforwards | 174,000 | | | (23,000) | |
| Benefit of operating loss carryforwards | | Benefit of operating loss carryforwards | (7,000) | | | — | |
| After operating loss carryforwards | | After operating loss carryforwards | 167,000 | | | (23,000) | |
| Canadian | Canadian | 0 | | | (4,000) | | Canadian | — | | | — | |
| Total current | Total current | (23,000) | | | (87,000) | | Total current | 167,000 | | | (23,000) | |
| Deferred provision (benefit): | | | | |
| Deferred provision: | | Deferred provision: | | | |
| | United States – State | United States – State | 26,000 | | | (24,000) | | United States – State | 165,000 | | | 26,000 | |
| Canadian | Canadian | 0 | | | (120,000) | | Canadian | — | | | — | |
| Total deferred | Total deferred | 26,000 | | | (144,000) | | Total deferred | 165,000 | | | 26,000 | |
| | $ | 3,000 | | | $ | (231,000) | | | $ | 332,000 | | | $ | 3,000 | |
Consolidated taxes do not bear a customary relationship to pretax results due primarily to the fact that the Company is taxed separately in Canada based on Canadian source operations and in the U.S. based on consolidated operations, and essentially all deferred tax assets, net of relevant offsetting deferred tax liabilities, are not estimated to have a future benefit as tax credits or deductions. Income from our non-controlling interest in the Kukio Resort Land Development Partnerships is treated as non-unitary for state of Hawaii unitary filing purposes, thus unitary Hawaii losses provide limited sheltering of such non-unitary income. Income from our investment in the Oklahoma oil venture is 100% allocable to Oklahoma, and therefore, receives no benefit from consolidated or unitary losses.
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 beenwas enacted as of September 30,in the quarter ended December
31, 2020. Canadian deferred tax assets and liabilities have been measured using the enacted tax rates in effect for the year in which the differences are expected to reverse. Alberta rate changes have no significant impact to earnings/loss as a result of a full valuation allowance being applied to Canadian deferred tax assets.
On MarchDecember 27, 2020, the CARES Act wasthen President Donald Trump signed into law the Consolidated Appropriations Act (the “Act”), an omnibus spending bill to provide economicfund the federal government that also includes an array of COVID-related tax relief to businesses that were negatively impactedfor individuals and businesses. The tax-related measures contained in the Act revise and expand provisions enacted earlier in the year by the COVID-19 pandemic. KeyFamilies First Coronavirus Response Act and the Coronavirus Aid, Relief, and Economic Security Act. The Act also extends a number of expiring tax provisionsprovisions. Additionally, the Act provides for a 100% deduction for certain business meals incurred in calendar years 2021 and 2022. The Company determined that income tax effects related to the passage of the CARESConsolidated Appropriations Act impactingwere not material to 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 mechanismfinancial statements 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 ofyear ended 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.
A reconciliation between the reported income tax expense (benefit) and the amount computed by multiplying the lossearnings (loss) attributable to Barnwell before income taxes by the U.S. federal tax rate of 21% is as follows:
| | | Year ended September 30, | | Year ended September 30, |
| | 2020 | | 2019 | | 2021 | | 2020 |
| Tax benefit computed by applying statutory rate | $ | (998,000) | | | $ | (2,655,000) | | |
| Tax provision (benefit) computed by applying statutory rate | | Tax provision (benefit) computed by applying statutory rate | $ | 1,383,000 | | | $ | (998,000) | |
| Impact of TCJA limitation on post-TCJA net operating loss carryforwards | Impact of TCJA limitation on post-TCJA net operating loss carryforwards | (260,000) | | | 260,000 | | Impact of TCJA limitation on post-TCJA net operating loss carryforwards | — | | | (260,000) | |
| Increase in the valuation allowance | 1,978,000 | | | 3,003,000 | | |
| Impact of TCJA on alternative minimum tax credit carryovers | 0 | | | (31,000) | | |
| (Decrease) increase in the valuation allowance | | (Decrease) increase in the valuation allowance | (1,482,000) | | | 1,978,000 | |
| | Additional effect of the foreign tax provision on the total tax provision | Additional effect of the foreign tax provision on the total tax provision | (762,000) | | | (736,000) | | Additional effect of the foreign tax provision on the total tax provision | 87,000 | | | (762,000) | |
| | U.S. state tax provision, net of federal benefit | U.S. state tax provision, net of federal benefit | 3,000 | | | (76,000) | | U.S. state tax provision, net of federal benefit | 332,000 | | | 3,000 | |
| Other | Other | 42,000 | | | 4,000 | | Other | 12,000 | | | 42,000 | |
| | $ | 3,000 | | | $ | (231,000) | | | $ | 332,000 | | | $ | 3,000 | |
The changes in the valuation allowance shown in the table above exclude the impact of changes in state taxes and refundable alternative minimumforeign tax credit carryovers,expiries, the valuation allowance impacts of which are incorporated within the respective reconciliation line items elsewhere in the table.
The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities are as follows:
| | | | September 30, | | September 30, |
| | | 2020 | | 2019 | | 2021 | | 2020 |
| Deferred income tax assets: | Deferred income tax assets: | | | | Deferred income tax assets: | | | |
| Foreign tax credit carryover under U.S. tax law | Foreign tax credit carryover under U.S. tax law | $ | 2,421,000 | | | $ | 2,421,000 | | Foreign tax credit carryover under U.S. tax law | $ | 1,197,000 | | | $ | 2,421,000 | |
| | U.S. federal net operating loss carryover | U.S. federal net operating loss carryover | 8,874,000 | | | 8,366,000 | | U.S. federal net operating loss carryover | 8,846,000 | | | 8,874,000 | |
| U.S. state unitary net operating loss carryovers | U.S. state unitary net operating loss carryovers | 877,000 | | | 873,000 | | U.S. state unitary net operating loss carryovers | 939,000 | | | 877,000 | |
| Canadian net operating loss carryovers | Canadian net operating loss carryovers | 1,351,000 | | | 850,000 | | Canadian net operating loss carryovers | 1,411,000 | | | 1,351,000 | |
| Tax basis of investment in land in excess of book basis under U.S. tax law | Tax basis of investment in land in excess of book basis under U.S. tax law | 306,000 | | | 296,000 | | Tax basis of investment in land in excess of book basis under U.S. tax law | 305,000 | | | 306,000 | |
Property and equipment accumulated book depreciation and depletion in excess of tax under Canadian tax law
| 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 Canadian tax law
| 1,091,000 | | | 1,421,000 | |
| Property and equipment accumulated book depreciation and depletion in excess of tax under U.S. tax law | Property and equipment accumulated book depreciation and depletion in excess of tax under U.S. tax law | 931,000 | | | 945,000 | | Property and equipment accumulated book depreciation and depletion in excess of tax under U.S. tax law | 699,000 | | | 931,000 | |
| Liabilities accrued for books but not for tax under U.S. tax law | 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 U.S. tax law | 1,225,000 | | | 1,894,000 | |
| Liabilities accrued for books but not for tax under Canadian tax law | Liabilities accrued for books but not for tax under Canadian tax law | 1,591,000 | | | 1,641,000 | | Liabilities accrued for books but not for tax under Canadian tax law | 1,813,000 | | | 1,591,000 | |
| Other | Other | 345,000 | | | 294,000 | | Other | 170,000 | | | 345,000 | |
| Total gross deferred income tax assets | Total gross deferred income tax assets | 20,011,000 | | | 18,244,000 | | Total gross deferred income tax assets | 17,696,000 | | | 20,011,000 | |
| Less valuation allowance | Less valuation allowance | (19,357,000) | | | (17,687,000) | | Less valuation allowance | (16,398,000) | | | (19,357,000) | |
| Net deferred income tax assets | Net deferred income tax assets | 654,000 | | | 557,000 | | Net deferred income tax assets | 1,298,000 | | | 654,000 | |
| Deferred income tax liabilities: | Deferred income tax liabilities: | | | | Deferred income tax liabilities: | | | |
| | Book basis of investment in land development partnerships in excess of tax basis under U.S. tax law | 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. tax law | (1,156,000) | | | (654,000) | |
| Book basis of investment in land development partnerships in excess of tax basis under U.S. state non-unitary tax law | 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) | | Book basis of investment in land development partnerships in excess of tax basis under U.S. state non-unitary tax law | (352,000) | | | (194,000) | |
| | U.S. oil and gas property and equipment accumulated tax depreciation and depletion in excess of book under U.S. tax law | | U.S. oil and gas property and equipment accumulated tax depreciation and depletion in excess of book under U.S. tax law | (142,000) | | | — | |
| U.S. oil and gas property and equipment accumulated tax depreciation and depletion in excess of book under U.S. state tax law | | U.S. oil and gas property and equipment accumulated tax depreciation and depletion in excess of book under U.S. state tax law | (7,000) | | | — | |
| Total deferred income tax liabilities | Total deferred income tax liabilities | (848,000) | | | (725,000) | | Total deferred income tax liabilities | (1,657,000) | | | (848,000) | |
| Net deferred income tax liability | Net deferred income tax liability | $ | (194,000) | | | $ | (168,000) | | Net deferred income tax liability | $ | (359,000) | | | $ | (194,000) | |
| Reported as: | Reported as: | | | | Reported as: | | | |
| Deferred income tax assets | Deferred income tax assets | 0 | | | 0 | | Deferred income tax assets | — | | | — | |
| Deferred income tax liabilities | Deferred income tax liabilities | (194,000) | | | (168,000) | | Deferred income tax liabilities | (359,000) | | | (194,000) | |
| Net deferred income tax liability | Net deferred income tax liability | $ | (194,000) | | | $ | (168,000) | | Net deferred income tax liability | $ | (359,000) | | | $ | (194,000) | |
The total valuation allowance increased $1,670,000decreased $2,959,000 for the year ended September 30, 2020.2021. The increasedecrease was primarily due to a $1,540,000 increase$1,225,000 decrease in the U.S. federal tax law valuation allowance related to U.S. federal net operating loss carryforwards, a $1,224,000 decrease in the U.S. federal tax law valuation allowance related to foreign tax credit carryovers, and a $257,000 decrease 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.realizable. Of the total net increasedecrease in the valuation allowance for fiscal 2020, $1,978,0002021, $2,830,000 was recognized as an income tax expensebenefit and $308,000$129,000 was credited to accumulated other comprehensive loss.
Net deferred tax assets at September 30, 20202021 of $654,000$1,298,000 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 PartnershipPartnerships' excess of book income over taxable income.income and the Oklahoma oil venture's book basis of property and equipment in excess of tax basis.
At September 30, 2020,2021, 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$1,197,000, $42,125,000, $14,674,000 and $5,506,000,$5,716,000, respectively. All four items were fully offset by valuation allowances at September 30, 2020,2021, 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 2037-2040,2037-2041, and the foreign tax credit carryovers expire in fiscal years 2021-2025.2022-2025. The U.S. federal net operating loss carryovers generated in the years ended September 30, 2021, 2020 and 2019 and the U.S. state net operating loss carryovers generated in the years ended September 30, 2021, 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 0no uncertain tax positions as of September 30, 20202021 or 2019.2020.
Included below is a summary of the tax years, by jurisdiction, that remain subject to examination by taxing authorities at September 30, 2020:2021:
| | | | | |
| Jurisdiction | Fiscal Years Open |
| U.S. federal | 20172018 – 20192020 |
| Various U.S. states | 20172018 – 20192020 |
| Canada federal | 20132014 – 20192020 |
| Various Canadian provinces | 20132014 – 20192020 |
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, 20202021 and 2019.2020.
| | | Year ended September 30, 2020 | | Year ended September 30, 2021 |
| | Oil and natural gas | | Contract drilling | | Land investment | | Other | | Total | | Oil and natural gas | | Contract drilling | | Land investment | | Other | | Total |
| Revenue streams: | Revenue streams: | | | | | | | | | | Revenue streams: | | | | | | | | | |
| | Oil | $ | 5,214,000 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 5,214,000 | | | Oil | $ | 7,617,000 | | | $ | — | | | $ | — | | | $ | — | | | $ | 7,617,000 | |
| | Natural gas | 1,119,000 | | | 0 | | | 0 | | | 0 | | | 1,119,000 | | | Natural gas | 1,871,000 | | | — | | | — | | | — | | | 1,871,000 | |
| | Natural gas liquids | 360,000 | | | 0 | | | 0 | | | 0 | | | 360,000 | | | Natural gas liquids | 766,000 | | | — | | | — | | | — | | | 766,000 | |
| | Drilling and pump | 0 | | | 10,994,000 | | | 0 | | | 0 | | | 10,994,000 | | | Drilling and pump | — | | | 5,809,000 | | | — | | | — | | | 5,809,000 | |
| | Contingent residual payments | 0 | | | 0 | | | 325,000 | | | 0 | | | 325,000 | | | Contingent residual payments | — | | | — | | | 1,738,000 | | | — | | | 1,738,000 | |
| | Other | 0 | | | 0 | | | 0 | | | 317,000 | | | 317,000 | | | Other | — | | | — | | | — | | | 304,000 | | | 304,000 | |
| | Total revenues before interest income | $ | 6,693,000 | | | $ | 10,994,000 | | | $ | 325,000 | | | $ | 317,000 | | | $ | 18,329,000 | | | Total revenues before interest income | $ | 10,254,000 | | | $ | 5,809,000 | | | $ | 1,738,000 | | | $ | 304,000 | | | $ | 18,105,000 | |
| Geographical regions: | Geographical regions: | | | | | | | | | | Geographical regions: | | | | | | | | | |
| | United States | $ | 0 | | | $ | 10,994,000 | | | $ | 325,000 | | | $ | 6,000 | | | $ | 11,325,000 | | | United States | $ | 118,000 | | | $ | 5,809,000 | | | $ | 1,738,000 | | | $ | 35,000 | | | $ | 7,700,000 | |
| | Canada | 6,693,000 | | | 0 | | | 0 | | | 311,000 | | | 7,004,000 | | | Canada | 10,136,000 | | | — | | | — | | | 269,000 | | | 10,405,000 | |
| | Total revenues before interest income | $ | 6,693,000 | | | $ | 10,994,000 | | | $ | 325,000 | | | $ | 317,000 | | | $ | 18,329,000 | | | Total revenues before interest income | $ | 10,254,000 | | | $ | 5,809,000 | | | $ | 1,738,000 | | | $ | 304,000 | | | $ | 18,105,000 | |
| Timing of revenue recognition: | Timing of revenue recognition: | | | | | | | | | | Timing of revenue recognition: | | | | | | | | | |
| | Goods transferred at a point in time | $ | 6,693,000 | | | $ | 0 | | | $ | 325,000 | | | $ | 317,000 | | | $ | 7,335,000 | | | Goods transferred at a point in time | $ | 10,254,000 | | | $ | — | | | $ | 1,738,000 | | | $ | 304,000 | | | $ | 12,296,000 | |
| | Services transferred over time | 0 | | | 10,994,000 | | | 0 | | | 0 | | | 10,994,000 | | | Services transferred over time | — | | | 5,809,000 | | | — | | | — | | | 5,809,000 | |
| | Total revenues before interest income | $ | 6,693,000 | | | $ | 10,994,000 | | | $ | 325,000 | | | $ | 317,000 | | | $ | 18,329,000 | | | Total revenues before interest income | $ | 10,254,000 | | | $ | 5,809,000 | | | $ | 1,738,000 | | | $ | 304,000 | | | $ | 18,105,000 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Year ended September 30, 2019 |
| | Oil and natural gas | | Contract drilling | | Land investment | | Other | | Total |
| Revenue streams: | | | | | | | | | |
| Oil | $ | 5,146,000 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 5,146,000 | |
| Natural gas | 795,000 | | | 0 | | | 0 | | | 0 | | | 795,000 | |
| Natural gas liquids | 465,000 | | | 0 | | | 0 | | | 0 | | | 465,000 | |
| Drilling and pump | 0 | | | 5,349,000 | | | 0 | | | 0 | | | 5,349,000 | |
| Contingent residual payments | 0 | | | 0 | | | 165,000 | | | 0 | | | 165,000 | |
| Other | 0 | | | 0 | | | 0 | | | 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 | $ | 0 | | | $ | 5,349,000 | | | $ | 165,000 | | | $ | 1,000 | | | $ | 5,515,000 | |
| Canada | 6,406,000 | | | 0 | | | 0 | | | 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 | | | $ | 0 | | | $ | 165,000 | | | $ | 93,000 | | | $ | 6,664,000 | |
| Services transferred over time | 0 | | | 5,349,000 | | | 0 | | | 0 | | | 5,349,000 | |
| Total revenues before interest income | $ | 6,406,000 | | | $ | 5,349,000 | | | $ | 165,000 | | | $ | 93,000 | | | $ | 12,013,000 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 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 | |
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 | |
| | | |
| | | |
| | | |
| | | | | | | | | | | |
| September 30, |
| 2021 | | 2020 |
| Accounts receivables from contracts with customers | $ | 2,797,000 | | | $ | 1,772,000 | |
| Contract assets | 581,000 | | | 413,000 | |
| Contract liabilities | 455,000 | | | 1,097,000 | |
| | | |
| | | |
| | | |
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, 20202021 and 2019,2020, the Company had $1,097,000$455,000 and $1,633,000,$1,097,000, 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, 20202021 and 2019,2020, the amount of revenue recognized that was previously included in contract liabilities as of the beginning of the respective period was $1,054,000$1,013,000 and $31,000,$1,054,000, respectively.
Contracts are sometimes modified for a change in scope or other requirements. The Company considers contract modifications to exist when the modification either creates new or changes the existing enforceable rights and obligations. Most of the Company’s contract modifications are for goods and services that are not distinct from the existing performance obligations. The effect of a contract modification on the transaction price, and the measure of progress for the performance obligation to which it relates, is recognized as an adjustment to revenue (either as an increase or decrease) on a cumulative catchup basis.
Performance Obligations
The Company’s remaining performance obligations for drilling and pump installation contracts (hereafter referred to as “backlog”) represent the unrecognized revenue value of the Company’s contract commitments. The Company’s backlog may vary significantly each reporting period based on the timing of major new contract commitments. In addition, our customers have the right, under some infrequent circumstances, to terminate contracts or defer the timing of the Company’s services and their payments to us. Nearly all of the Company's contract drilling segment contracts have original expected durations of one year or less. At September 30, 2020,2021, the Company had threefour contract drilling jobs with original expected durations of greater than one year. For these contracts, approximately 7%13% of the remaining performance obligation of $2,416,000$2,817,000 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, 20202021 and 2019,2020, the Company had $145,000$326,000 and $296,000,$145,000, respectively, in unamortized preconstruction costs related to contracts that were not completed. During the years ended September 30, 20202021 and 2019,2020, the amortization of preconstruction costs related to contracts was $163,000$224,000 and $204,000,$163,000, respectively. These amounts have been included in “Contract drilling operating” costs and expenses in the accompanying Consolidated Statements of Operations. Additionally, 0no impairment charges in connection with the Company’s preconstruction costs were recorded during the years ended September 30, 20202021 and 2019.2020.
Water Well Re-drill
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, the estimated total rework costs to remediate the situation have beenwas accrued at September 30, 2020. As a result of allIn January 2021, the broken drill string was retrieved from the well borehole and drilling 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.replacement well recommenced.
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 | |
| | | | | | | | | | | |
| September 30, 2021 | | September 30, 2020 |
| Uninstalled materials | 226,000 | | | 489,000 | |
12. SEGMENT AND GEOGRAPHIC INFORMATION
Barnwell operates the following segments: 1) acquiring, developing, producing and selling oil and natural gas in Canada and Oklahoma (oil and natural gas); 2) investing in land interests in Hawaii (land investment); and 3) drilling wells and installing and repairing water pumping systems in Hawaii (contract drilling).
The following table presents certain financial information related to Barnwell’s reporting segments. All revenues reported are from external customers with 0no 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 | | | 0 | |
| | | |
| 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 | | | 0 | |
| 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) | |
| | | | | | | | | | | |
| | Year ended September 30, |
| | 2021 | | 2020 |
| Revenues: | | | |
| Oil and natural gas | $ | 10,254,000 | | | $ | 6,693,000 | |
| Contract drilling | 5,809,000 | | | 10,994,000 | |
| Land investment | 1,738,000 | | | 325,000 | |
| | | |
| Other | 304,000 | | | 317,000 | |
| Total before interest income | 18,105,000 | | | 18,329,000 | |
| Interest income | 8,000 | | | 18,000 | |
| Total revenues | $ | 18,113,000 | | | $ | 18,347,000 | |
| Depletion, depreciation, and amortization: | | | |
| Oil and natural gas | $ | 645,000 | | | $ | 1,747,000 | |
| Contract drilling | 305,000 | | | 356,000 | |
| Other | 13,000 | | | 44,000 | |
| Total depletion, depreciation, and amortization | $ | 963,000 | | | $ | 2,147,000 | |
| Impairment: | | | |
| Oil and natural gas | $ | 630,000 | | | $ | 4,326,000 | |
| Contract drilling | 38,000 | | | — | |
| Land investment | — | | | 50,000 | |
| | | |
| Total impairment | $ | 668,000 | | | $ | 4,376,000 | |
| Operating profit (loss) (before general and administrative expenses): | | | |
| Oil and natural gas | $ | 2,423,000 | | | $ | (4,230,000) | |
| Contract drilling | (89,000) | | | 3,125,000 | |
| Land investment | 1,738,000 | | | 275,000 | |
| | | |
| Other | 291,000 | | | 273,000 | |
| Gain on sale of assets | 1,982,000 | | | 1,336,000 | |
| Total operating profit | 6,345,000 | | | 779,000 | |
| Equity in income of affiliates: | | | |
| Land investment | 5,793,000 | | | 352,000 | |
| General and administrative expenses | (7,088,000) | | | (5,820,000) | |
| Interest expense | (13,000) | | | (3,000) | |
| | | |
| Interest income | 8,000 | | | 18,000 | |
| Gain on debt extinguishment | 149,000 | | | — | |
| Gain on termination of post-retirement medical plan | 2,341,000 | | | — | |
| Earnings (loss) before income taxes | $ | 7,535,000 | | | $ | (4,674,000) | |
Capital Expenditures:
| | | | Year ended September 30, | | Year ended September 30, |
| | | 2020 | | 2019 | | 2021 | | 2020 |
| Oil and natural gas | Oil and natural gas | $ | 3,099,000 | | | $ | 46,000 | | Oil and natural gas | $ | 3,028,000 | | | $ | 3,099,000 | |
| Contract drilling | Contract drilling | 408,000 | | | 1,262,000 | | Contract drilling | 62,000 | | | 408,000 | |
| Other | Other | 7,000 | | | 1,000 | | Other | 1,000 | | | 7,000 | |
| Total | Total | $ | 3,514,000 | | | $ | 1,309,000 | | Total | $ | 3,091,000 | | | $ | 3,514,000 | |
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, | | September 30, |
| | | 2020 | | 2019 | | 2021 | | 2020 |
Oil and natural gas (1) | Oil and natural gas (1) | $ | 3,613,000 | | | $ | 7,415,000 | | Oil and natural gas (1) | $ | 6,401,000 | | | $ | 3,613,000 | |
Contract drilling (2) | Contract drilling (2) | 3,838,000 | | | 3,793,000 | | Contract drilling (2) | 4,071,000 | | | 3,838,000 | |
Land investment (2) | Land investment (2) | 901,000 | | | 980,000 | | Land investment (2) | — | | | 901,000 | |
| Other: | Other: | | | | Other: | | | |
| Cash and cash equivalents | Cash and cash equivalents | 4,584,000 | | | 4,613,000 | | Cash and cash equivalents | 11,279,000 | | | 4,584,000 | |
| | Corporate and other | Corporate and other | 2,246,000 | | | 1,501,000 | | Corporate and other | 2,684,000 | | | 2,246,000 | |
| Total | Total | $ | 15,182,000 | | | $ | 18,302,000 | | Total | $ | 24,435,000 | | | $ | 15,182,000 | |
______________
(1) LPrimarily locatedocated primarily in the province of Alberta, Canada.Canada with a minor portion in Oklahoma.
(2) Located in Hawaii.
Long-Lived Assets By Geographic Area:
| | | | September 30, | | September 30, |
| | | 2020 | | 2019 | | 2021 | | 2020 |
| United States | United States | $ | 3,393,000 | | | $ | 3,366,000 | | United States | $ | 4,180,000 | | | $ | 3,393,000 | |
| Canada | Canada | 2,302,000 | | | 6,232,000 | | Canada | 2,220,000 | | | 2,302,000 | |
| Total | Total | $ | 5,695,000 | | | $ | 9,598,000 | | Total | $ | 6,400,000 | | | $ | 5,695,000 | |
Revenue By Geographic Area:
| | | | Year ended September 30, | | Year ended September 30, |
| | | 2020 | | 2019 | | 2021 | | 2020 |
| United States | United States | $ | 11,325,000 | | | $ | 5,515,000 | | United States | $ | 7,700,000 | | | $ | 11,325,000 | |
| Canada | Canada | 7,004,000 | | | 6,498,000 | | Canada | 10,405,000 | | | 7,004,000 | |
| Total (excluding interest income) | Total (excluding interest income) | $ | 18,329,000 | | | $ | 12,013,000 | | Total (excluding interest income) | $ | 18,105,000 | | | $ | 18,329,000 | |
13. ACCUMULATED OTHER COMPREHENSIVE LOSSINCOME (LOSS)
Components of accumulated other comprehensive loss,income (loss), net of taxes, are as follows:
| | | | Year ended September 30, | | Year ended September 30, |
| | | 2020 | | 2019 | | 2021 | | 2020 |
| Foreign currency translation: | Foreign currency translation: | | | | Foreign currency translation: | | | |
| Beginning accumulated foreign currency translation | Beginning accumulated foreign currency translation | $ | 691,000 | | | $ | 925,000 | | Beginning accumulated foreign currency translation | $ | 545,000 | | | $ | 691,000 | |
| Change in cumulative translation adjustment before reclassifications | Change in cumulative translation adjustment before reclassifications | (146,000) | | | (234,000) | | Change in cumulative translation adjustment before reclassifications | (283,000) | | | (146,000) | |
| | Income taxes | Income taxes | 0 | | | 0 | | Income taxes | — | | | — | |
| Net current period other comprehensive loss | Net current period other comprehensive loss | (146,000) | | | (234,000) | | Net current period other comprehensive loss | (283,000) | | | (146,000) | |
| Ending accumulated foreign currency translation | Ending accumulated foreign currency translation | 545,000 | | | 691,000 | | Ending accumulated foreign currency translation | 262,000 | | | 545,000 | |
| Retirement plans: | Retirement plans: | | | | Retirement plans: | | | |
| Beginning accumulated retirement plans benefit cost | Beginning accumulated retirement plans benefit cost | (3,608,000) | | | (1,439,000) | | Beginning accumulated retirement plans benefit cost | (1,980,000) | | | (3,608,000) | |
| Amortization of net actuarial loss and prior service cost | Amortization of net actuarial loss and prior service cost | 120,000 | | | 55,000 | | Amortization of net actuarial loss and prior service cost | 101,000 | | | 120,000 | |
| Net actuarial gain (loss) arising during the period | 1,508,000 | | | (2,224,000) | | |
| Net actuarial gains arising during the period | | Net actuarial gains arising during the period | 1,108,000 | | | 1,508,000 | |
| Gain on termination of post-retirement medical plan | | Gain on termination of post-retirement medical plan | 541,000 | | | — | |
| Income taxes | Income taxes | 0 | | | 0 | | Income taxes | — | | | — | |
| Net current period other comprehensive income (loss) | 1,628,000 | | | (2,169,000) | | |
| Net current period other comprehensive income | | Net current period other comprehensive income | 1,750,000 | | | 1,628,000 | |
| Ending accumulated retirement plans benefit cost | Ending accumulated retirement plans benefit cost | (1,980,000) | | | (3,608,000) | | Ending accumulated retirement plans benefit cost | (230,000) | | | (1,980,000) | |
| Accumulated other comprehensive loss, net of taxes | $ | (1,435,000) | | | $ | (2,917,000) | | |
| Accumulated other comprehensive income (loss), net of taxes | | Accumulated other comprehensive income (loss), net of taxes | $ | 32,000 | | | $ | (1,435,000) | |
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
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
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 PPP pursuant to the CARES Act that was signed into law in March 2020. The note matureswas to mature two years after the date of the loan disbursement and bearswith interest at a fixed annual rate of 1.00%, and with the first six months of principal and interest deferred. Underpayments deferred until ten months after the termslast day 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.
covered period. In October 2020,April 2021, the Company was notified by the lender of our PPP loan of changes to certain terms of ourthat the entire PPP loan to conform with the amendments to the CARES Act implementedamount and related accrued interest was forgiven 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 portionsSmall Business Administration. As a result of the loan asforgiveness, the Company recognized a gain on debt extinguishment of $149,000 during the year ended September 30, 2021.
Canada Emergency Business Account Loan
In the quarter ended December 31, 2020, were not adjustedthe Company’s Canadian subsidiary, Barnwell of Canada, received a loan of CAD$40,000 (in Canadian dollars) under the Canada Emergency Business Account (“CEBA”) loan program for this October 2020small businesses. In the quarter ended March 31, 2021, the Company applied for an increase to our CEBA loan modification by our lender.and received an additional CAD$20,000 for a total loan amount received of CAD$60,000 ($47,000) under the program. The CEBA loan is interest-free with no principal payments required until December 31, 2022, after which the remaining loan balance is converted to a three year term loan at 5% annual interest paid monthly. If the Company repays 66.6% of the principal amount prior to December 31, 2022, there will be loan forgiveness of 33.3% up to a maximum of CAD$20,000.
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 leaseCompany’s 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.
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 quarter ended March 31, 2020.
The Company’s remaining ROU assets and lease liabilities at September 30, 2020,2021, primarily relate to non-cancelable operating leases for our Hawaii corporate and Canadian office spacespaces 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 | |
| | | | | | | | | | | | | | |
| | September 30, |
| | 2021 | | 2020 |
| Assets: | | | |
| Operating lease right-of-use assets | $ | 296,000 | | | $ | 249,000 | |
| Total right-of-use assets | $ | 296,000 | | | $ | 249,000 | |
| Liabilities: | | | |
| Current portion of operating lease liabilities | $ | 117,000 | | | $ | 111,000 | |
| Operating lease liabilities | 180,000 | | | 143,000 | |
| Total lease liabilities | $ | 297,000 | | | $ | 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 | |
| | | | | | | | | | | |
| Year ended September 30, |
| 2021 | | 2020 |
| Operating lease cost | $ | 130,000 | | | $ | 334,000 | |
| Short-term lease cost | 254,000 | | | 69,000 | |
| Variable lease cost | 103,000 | | | — | |
| Total lease cost | $ | 487,000 | | | $ | 403,000 | |
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% |
| | | | | | | | | | | | | | |
| | September 30, |
| | 2021 | | 2020 |
| Cash paid for amounts included in the measurement of lease liabilities: | | | |
| Operating cash flows from operating leases | $ | 133,000 | | | $ | 189,000 | |
| Operating leases: | | | |
| Weighted-average remaining lease term (in years) | 2.9 | | 3.4 |
| Weighted-average discount rate | 5.19% | | 5.85% |
The remaining lease payments for our operating leases as of September 30, 2020,2021, are as follows:
| | Fiscal year ending: | Fiscal year ending: | | Fiscal year ending: | |
| 2021 | $ | 123,000 | | |
| 2022 | 2022 | 61,000 | | 2022 | $ | 129,000 | |
| 2023 | 2023 | 30,000 | | 2023 | 97,000 | |
| 2024 | 2024 | 30,000 | | 2024 | 58,000 | |
| 2025 | 2025 | 30,000 | | 2025 | 30,000 | |
| Thereafter through 2026 | 7,000 | | |
| 2026 | | 2026 | 7,000 | |
| Thereafter through 2027 | | Thereafter through 2027 | — | |
| Total lease payments | Total lease payments | 281,000 | | Total lease payments | 321,000 | |
| Less: amounts representing interest | Less: amounts representing interest | (27,000) | | Less: amounts representing interest | (24,000) | |
| Present value of lease liabilities | Present value of lease liabilities | $ | 254,000 | | Present value of lease liabilities | $ | 297,000 | |
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.
Gain on sale of leased 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.
17.STOCKHOLDERS' EQUITY (DEFICIT)
Share-based Compensation
2018 Equity Incentive Plan
The Company’s stock option plans are administered by the Compensation Committee of the Board of Directors. The stockholder-approved 2018 Equity Incentive Plan provides for the issuance of incentive stock options, nonstatutory stock options, stock options with stock appreciation rights, restricted stock, restricted stock units and performance units, qualified performance-based awards, and stock grants to employees, consultants and non-employee members of the Board of Directors. 800,000 shares of Barnwell common stock have been reserved for issuance and as of September 30, 2021, a total of 135,000 share options remain available for grant.
Barnwell currently has a policy of issuing new shares to satisfy share option exercises when the optionee requests shares.
Equity-classified Awards
On February 9, 2021, the Board of Directors of the Company granted options to purchase 665,000 shares of common stock, 310,000 shares to independent directors and 355,000 shares to employees. 605,000 shares of the stock options granted have an exercise price equal to the closing market price of Barnwell’s stock on the date of grant of $3.33, vest annually over three years, and expire in ten years from the date of grant. 60,000 shares of the stock options granted have an exercise price of $3.66 (110% of the closing market price on the date of grant for options granted to affiliates), vest annually over three years, and expire in five years from the date of grant.
A summary of the activity in Barnwell’s equity-classified share options from October 1, 2020 through September 30, 2021 is presented below:
| | | | | | | | | | | | | | | | | | | | | | | |
| Options | Shares | | Weighted-
Average
Exercise Price | | Weighted-
Average
Remaining
Contractual Term | | Aggregate
Intrinsic Value |
| Outstanding at October 1, 2020 | — | | | $ | — | | | | | |
| Granted | 665,000 | | | 3.36 | | | | | |
| Exercised | — | | | — | | | | | |
| Expired/Forfeited | (50,000) | | | 3.33 | | | | | |
| Outstanding at September 30, 2021 | 615,000 | | | $ | 3.36 | | | 8.9 | | $ | — | |
| Exercisable at September 30, 2021 | — | | | $ | — | | | — | | | $ | — | |
The following assumptions were used in estimating the fair value of the equity-classified share options granted on February 9, 2021:
| | | | | | | | | | | |
| > 10% Owner-Employee | | Others |
| Number of shares | 60,000 | | 605,000 |
| Expected volatility | 127.4% | | 105.8% |
| Expected dividends | None | | None |
| Expected term (in years) | 3.5 | | 6.0 |
| Risk-free interest rate | 0.19% | | 0.82% |
| Expected forfeitures | None | | None |
| Fair value per share | $2.51 | | $2.70 |
The application of alternative assumptions could produce significantly different estimates of the fair value of share-based compensation, and consequently, the related costs reported in the “General and administrative” expenses in the Consolidated Statements of Operations.
Compensation cost for equity-classified awards is measured at the grant date based on the fair value of the award and is recognized as an expense over the requisite service period. During the year ended September 30, 2021, the Company recognized total share-based compensation expense of $643,000. There was no share-based compensation expense recognized during the year ended September 30, 2020. Additionally, there was no impact on income taxes for the years ended September 30, 2021 and 2020 due to a full valuation allowance on the related deferred tax asset. As of September 30, 2021, the total remaining unrecognized compensation cost related to nonvested share options was $1,005,000, which is expected to be recognized over the weighted-average remaining requisite service period of 2.4 years.
At The Market Offering
On March 16, 2021, the Company entered into a Sales Agreement (the “Sales Agreement”) with A.G.P./Alliance Global Partners (“A.G.P,”), with respect to the ATM pursuant to which the Company may offer and sell, from time to time, shares of its common stock, par value $0.50 per share, having an aggregate sales price of up to $25 million (subject to certain limitations at any time our public float remains under $75 million), through or to A.G.P as the Company’s sales agent or as principal. Sales of our common stock under the ATM, if any, will be made by any methods deemed to be “at the market offerings” as defined in Rule 415(a)(4) under the Securities Act, including sales made directly on the NYSE American, on any other existing trading market for our Common Stock, or to or through a market maker. Shares of common stock sold under the ATM are offered pursuant to the Company’s Registration Statement on Form S-3 (File No. 333-254365), filed with the Securities and Exchange Commission on March 16, 2021, and declared effective on March 26, 2021 (the "Registration Statement”), and the prospectus dated March 26, 2021, included in the Registration Statement.
The sale of shares under the ATM began in May 2021 and as of September 30, 2021, the Company sold 1,167,987 shares of common stock resulting in net proceeds of $3,784,000 after commissions and fees of $123,000.
18. 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, 2020,2021, Barnwell has accrued approximately $23,000$325,000 in bonus compensation under these plans and the amount is reported in “Accrued compensation” on the Consolidated Balance Sheet at September 30, 2020.2021.
Environmental Matters
Because of the inherent uncertainties associated with environmental assessment and remediation activities, future expenses to remediate sites identified in the future, if any, could be incurred. Barnwell's management is not currently aware of any significant environmental contingent liabilities requiring disclosure or accrual.
Legal and Regulatory Matters
Barnwell is routinely involved in disputes with third parties that occasionally require litigation. In addition, Barnwell is required to maintain compliance with all current governmental controls and regulations in the ordinary course of business. Barnwell’s management is not aware of any claims or litigation involving Barnwell that are likely to have a material adverse effect on its results of operations, financial position or liquidity.
In the year ended September 30, 2019, 2 of the water wells drilled by the contract drilling segment for 1 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 1 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 2 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, 20202021 as there is no probable or estimable contingent liability.
OnIn 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 2 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 werewas 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 settlementdropped in lieu of the penalties and fines whereby the named parties would be responsible for providing the Commission with assistanceentering into an agreement to monitor the aquifer, at no cost to the Commission, to aid in the Commission’s efforts to monitorperform a water quality in the subject area. The Companystudy 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.repurpose a current well into a monitoring well. Accordingly, the Company recorded a contingent liability of approximately $300,000 at September 30, 2020.2020 and no subsequent revision to the accrual has been recorded as of September 30, 2021.
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, BarnwellKaupulehu 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.
19. 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, | | Year ended September 30, |
| | | 2020 | | 2019 | | 2021 | | 2020 |
| Increase (decrease) from changes in: | Increase (decrease) from changes in: | | | | Increase (decrease) from changes in: | | | |
| Receivables | Receivables | $ | (598,000) | | | $ | (260,000) | | Receivables | $ | (814,000) | | | $ | (598,000) | |
| Income tax receivable | Income tax receivable | 129,000 | | | 758,000 | | Income tax receivable | 457,000 | | | 129,000 | |
| Other current assets | Other current assets | 260,000 | | | (188,000) | | Other current assets | (920,000) | | | 260,000 | |
| Accounts payable | Accounts payable | 924,000 | | | (202,000) | | Accounts payable | (746,000) | | | 924,000 | |
| Accrued compensation | Accrued compensation | 203,000 | | | (317,000) | | Accrued compensation | 668,000 | | | 203,000 | |
| Other current liabilities | Other current liabilities | (470,000) | | | 1,451,000 | | Other current liabilities | (796,000) | | | (470,000) | |
| Increase from changes in current assets and liabilities | $ | 448,000 | | | $ | 1,242,000 | | |
| (Decrease) increase from changes in current assets and liabilities | | (Decrease) increase from changes in current assets and liabilities | $ | (2,151,000) | | | $ | 448,000 | |
| Supplemental disclosure of cash flow information: | Supplemental disclosure of cash flow information: | | | | Supplemental disclosure of cash flow information: | | | |
| Cash paid (received) during the year for: | Cash paid (received) during the year for: | | | | Cash paid (received) during the year for: | | | |
| | Income taxes refunded, net | Income taxes refunded, net | $ | (166,000) | | | $ | (2,302,000) | | Income taxes refunded, net | $ | (303,000) | | | $ | (166,000) | |
| Supplemental disclosure of non-cash investing activities: | | Supplemental disclosure of non-cash investing activities: | | | |
| Canadian income tax withholding on proceeds from the sale of oil and natural gas properties | | Canadian income tax withholding on proceeds from the sale of oil and natural gas properties | $ | 598,000 | | | $ | — | |
|
Capital expenditure accruals related to oil and natural gas acquisition and development increased $435,000$346,000 and $60,000$435,000 during the years ended September 30, 20202021 and 2019,2020, respectively. Additionally, capital expenditure accruals related to oil and natural gas asset retirement obligations decreased $52,000 and $755,000increased $811,000 during the yearsyear ended September 30, 20202021 and 2019, respectively.decreased $52,000 during the year ended September 30, 2020.
19.20. 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 6.4.
During the year ended September 30, 2021, Barnwell received $1,738,000 in percentage of sales payments from KD I from the sale of 8 lots within Phase II of Increment I. During the year ended September 30, 2020, Barnwell received $325,000 in percentage of sales payments from KD I from the sale of 2 lots within Phase II of Increment I. During
Mr. Colin R. O'Farrell, a member of the year ended September 30, 2019,Board of Directors of the Company effective July 12, 2021, is the sole member of Four Pines Operating LLC which owns a 25% interest in Gros Ventre. In February 2021, Gros Ventre and BOK, a wholly-owned subsidiary of Barnwell, received $165,000entered into the Agreement of Teton Barnwell, an entity formed for the purpose of directly investing in percentageoil and natural gas exploration and development in Oklahoma. Under the terms of sales payments from KD I from the saleAgreement, Gros Ventre makes no capital contributions and receives 2% of 1 lot within Phase IIthe profits of Increment I.Teton Barnwell. Additionally, as the manager of Teton Barnwell, Gros Ventre is paid an annual asset management fee equal to 1% of the cumulative capital contributions made to Teton Barnwell as compensation for its management services.
20.21. SUBSEQUENT EVENTS
In October 2020, the Company was notified by the lenderKukio Resort Land Development Partnerships and Sale 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 lawInterest 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.Leasehold Land
In November 2020,Subsequent to September 30, 2021, Kaupulehu Developments received a percentage of sales payment of $170,000payments totaling $600,000 from the sale of 1 lot3 lots within Phase II of Increment I. Financial results from the receipt of this paymentthese payments will be reflected in Barnwell's quarter ending December 31, 2020.2021.
Additionally, subsequent to September 30, 2020,2021, Barnwell received net cash distributions in the amount of $1,034,000$1,075,000 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 andFinancial results of this distribution will be recorded as an additional equity pickupreflected in theBarnwell's quarter ending December 31, 2020, as discussed in more detail in Note 6. The preferred return payments received after2021.
Contract Segment Drilling Rig and Equipment
Subsequent to September 30, 2020 brought2021, the cumulative preferred return to $656,000,Company sold a contract segment drilling rig and related ancillary equipment for proceeds of $687,000, net of related costs, which is the total amount Barnwell was entitledequivalent to and thus there is no more preferred return outstanding as of the date ofits net carrying value at September 30, 2021. Financial results from this report.sale will be reflected in Barnwell's quarter ending December 31, 2021.
21.22. SUMMARY OF SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)
Disclosure is not required as Barnwell qualifies as a smaller reporting company.
22.23. 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.Canada and in the U.S state of Oklahoma. Proved reserves are the estimated quantities of oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved producing oil and natural gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. The estimated net interests in total proved and proved producing reserves are based upon subjective engineering judgments and may be affected by the limitations inherent in such estimations. The process of estimating reserves is subject to continual revision as additional information becomes available as a result of drilling, testing, reservoir studies and production history. There can be no assurance that such estimates will not be materially revised in subsequent periods.
(A) Oil and Natural Gas Reserves
The following 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. Proved oil, natural gas liquids and natural gas reserves located in the U.S. state of Oklahoma are not significant and are therefore not included in the table below. All of the information regarding Canadian reserves in this Form 10-K is derived from the report of our independent petroleum reserve engineers, InSite, and is included as an Exhibit to this Form 10-K. 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 | | | 0 | | | 5,000 | |
| | | | | | | | | | | | | | | | | |
| OIL & NGL
(Bbls) | | GAS
(Mcf) | | Total
(Boe) |
| Proved reserves: | | | | | |
| 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) | |
| Balance at September 30, 2020 | 535,000 | | | 2,310,000 | | | 933,000 | |
| Revisions of previous estimates | 291,000 | | | 1,345,000 | | | 523,000 | |
| | | | | |
| Acquisitions of reserves | 80,000 | | | 289,000 | | | 130,000 | |
| Less sales of reserves | (97,000) | | | (341,000) | | | (156,000) | |
| Less production | (169,000) | | | (690,000) | | | (288,000) | |
| Proved Reserves, September 30, 2021 | 640,000 | | | 2,913,000 | | | 1,142,000 | |
| Proved Developed Reserves, September 30, 2021 | 636,000 | | | 2,913,000 | | | 1,138,000 | |
| Proved Undeveloped Reserves, September 30, 2021 | 4,000 | | | — | | | 4,000 | |
(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,Canada and the U.S. are summarized as follows:
| | | | September 30, | | September 30, 2021 |
| | | 2020 | | 2019 | | Canada | | United States | | Total |
| Proved properties | Proved properties | $ | 64,142,000 | | | $ | 62,075,000 | | Proved properties | $ | 58,273,000 | | | $ | 217,000 | | | $ | 58,490,000 | |
| Unproved properties | Unproved properties | 0 | | | 130,000 | | Unproved properties | — | | | 962,000 | | | 962,000 | |
| Total capitalized costs | Total capitalized costs | 64,142,000 | | | 62,205,000 | | Total capitalized costs | 58,273,000 | | | 1,179,000 | | | 59,452,000 | |
| Accumulated depletion, depreciation, and impairment | Accumulated depletion, depreciation, and impairment | 61,839,000 | | | 55,972,000 | | Accumulated depletion, depreciation, and impairment | 56,053,000 | | | 14,000 | | | 56,067,000 | |
| Net capitalized costs | Net capitalized costs | $ | 2,303,000 | | | $ | 6,233,000 | | Net capitalized costs | $ | 2,220,000 | | | $ | 1,165,000 | | | $ | 3,385,000 | |
| | | | | | | | | | | | | | | | | |
| | September 30, 2020 |
| | Canada | | United States | | Total |
| Proved properties | $ | 64,142,000 | | | $ | — | | | $ | 64,142,000 | |
| Unproved properties | — | | | — | | | — | |
| Total capitalized costs | 64,142,000 | | | — | | | 64,142,000 | |
| Accumulated depletion, depreciation, and impairment | 61,839,000 | | | — | | | 61,839,000 | |
| Net capitalized costs | $ | 2,303,000 | | | $ | — | | | $ | 2,303,000 | |
(C) Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development
| | | | Year ended September 30, | | Year ended September 30, 2021 |
| | | 2020 | | 2019 | | Canada | | United States | | Total |
| Acquisition of properties: | Acquisition of properties: | | | | Acquisition of properties: | | | | | |
| Proved | | Proved | $ | 1,032,000 | | | $ | 70,000 | | | $ | 1,102,000 | |
| Unproved | Unproved | $ | 0 | | | $ | 0 | | Unproved | — | | | — | | | — | |
| Proved | 242,000 | | | 668,000 | | |
| | Exploration costs | | Exploration costs | 255,000 | | | — | | | 255,000 | |
| Development costs | Development costs | 2,857,000 | | | (622,000) | | Development costs | 563,000 | | | 1,108,000 | | | 1,671,000 | |
| Total | Total | $ | 3,099,000 | | | $ | 46,000 | | Total | $ | 1,850,000 | | | $ | 1,178,000 | | | $ | 3,028,000 | |
| | | | | | | | | | | | | | | | | |
| | Year ended September 30, 2020 |
| | Canada | | United States | | Total |
| Acquisition of properties: | | | | | |
| Proved | $ | 242,000 | | | $ | — | | | $ | 242,000 | |
| Unproved | — | | | — | | | — | |
| | | | | |
| Development costs | 2,857,000 | | | — | | | 2,857,000 | |
| Total | $ | 3,099,000 | | | $ | — | | | $ | 3,099,000 | |
Costs incurred in the tabletables above include additions and revisions to Barnwell’s asset retirement obligation of $(52,000)$811,000 and $(755,000)$(52,000) for the years ended September 30, 20202021 and 2019,2020, respectively.
(D) Results of Operations for Oil and Natural Gas Producing Activities
| | | | Year ended September 30, | | Year ended September 30, 2021 |
| | | 2020 | | 2019 | | Canada | | United States | | Total |
| Net revenues | Net revenues | $ | 6,693,000 | | | $ | 6,406,000 | | Net revenues | $ | 10,136,000 | | | $ | 118,000 | | | $ | 10,254,000 | |
| Production costs | Production costs | (4,850,000) | | | (5,213,000) | | Production costs | (6,532,000) | | | (24,000) | | | (6,556,000) | |
| Depletion | Depletion | (1,747,000) | | | (2,680,000) | | Depletion | (631,000) | | | (14,000) | | | (645,000) | |
| Reduction of carrying value of oil and natural gas properties | Reduction of carrying value of oil and natural gas properties | (4,326,000) | | | (5,710,000) | | Reduction of carrying value of oil and natural gas properties | (630,000) | | | — | | | (630,000) | |
Pre-tax results of operations (1) | Pre-tax results of operations (1) | (4,230,000) | | | (7,197,000) | | Pre-tax results of operations (1) | 2,343,000 | | | 80,000 | | | 2,423,000 | |
Estimated income tax expense (2) | Estimated income tax expense (2) | 0 | | | (160,000) | | Estimated income tax expense (2) | — | | | — | | | — | |
Results of operations (1) | Results of operations (1) | $ | (4,230,000) | | | $ | (7,357,000) | | Results of operations (1) | $ | 2,343,000 | | | $ | 80,000 | | | $ | 2,423,000 | |
| | | | | | | | | | | | | | | | | |
| | Year ended September 30, 2020 |
| | Canada | | United States | | Total |
| Net revenues | $ | 6,693,000 | | | $ | — | | | $ | 6,693,000 | |
| Production costs | (4,850,000) | | | — | | | (4,850,000) | |
| Depletion | (1,747,000) | | | — | | | (1,747,000) | |
| Reduction of carrying value of oil and natural gas properties | (4,326,000) | | | — | | | (4,326,000) | |
Pre-tax results of operations (1) | (4,230,000) | | | — | | | (4,230,000) | |
Estimated income tax expense (2) | — | | | — | | | — | |
Results of operations (1) | $ | (4,230,000) | | | $ | — | | | $ | (4,230,000) | |
_________________
(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 and U.S. federal tax law deferred tax assets that may not be realizable.
(E) Standardized Measure, Including Year-to-Year Changes Therein, of Estimated Discounted Future Net Cash Flows
The following tables utilize reserve and production data estimated by independent petroleum reserve engineers. The information may be useful for certain comparison purposes but should not be solely relied upon in evaluating Barnwell or its performance. Moreover, the projections should not be construed as realistic estimates of future cash flows, nor should the standardized measure be viewed as representing current value. Additionally, proved oil, natural gas and natural gas liquids reserves located in the United States are not significant and are therefore not included in the tables below.
The estimated future cash flows at September 30, 20202021 and 20192020 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, 20202021 and 20192020 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, | | September 30, |
| | | 2020 | | 2019 | | 2021 | | 2020 |
| Future cash inflows | Future cash inflows | $ | 20,426,000 | | | $ | 65,720,000 | | Future cash inflows | $ | 36,130,000 | | | $ | 20,426,000 | |
| Future production costs | Future production costs | (17,860,000) | | | (41,733,000) | | Future production costs | (25,323,000) | | | (17,860,000) | |
| Future development costs | Future development costs | (73,000) | | | (13,295,000) | | Future development costs | (240,000) | | | (73,000) | |
| Future income tax expenses | Future income tax expenses | (92,000) | | | (450,000) | | Future income tax expenses | (995,000) | | | (92,000) | |
| Future net cash flows excluding abandonment, decommissioning and reclamation | Future net cash flows excluding abandonment, decommissioning and reclamation | 2,401,000 | | | 10,242,000 | | Future net cash flows excluding abandonment, decommissioning and reclamation | 9,572,000 | | | 2,401,000 | |
| Future abandonment, decommissioning and reclamation | Future abandonment, decommissioning and reclamation | (13,055,000) | | | (13,190,000) | | Future abandonment, decommissioning and reclamation | (14,525,000) | | | (13,055,000) | |
| Future net cash flows | Future net cash flows | (10,654,000) | | | (2,948,000) | | Future net cash flows | (4,953,000) | | | (10,654,000) | |
| 10% annual discount for timing of cash flows | 10% annual discount for timing of cash flows | 8,969,000 | | | 5,258,000 | | 10% annual discount for timing of cash flows | 7,598,000 | | | 8,969,000 | |
| Standardized measure of discounted future net cash flows | Standardized measure of discounted future net cash flows | $ | (1,685,000) | | | $ | 2,310,000 | | Standardized measure of discounted future net cash flows | $ | 2,645,000 | | | $ | (1,685,000) | |
Changes in the Standardized Measure of Discounted Future Net Cash Flows
| | | | Year ended September 30, | | Year ended September 30, |
| | | 2020 | | 2019 | | 2021 | | 2020 |
| Beginning of year | Beginning of year | $ | 2,310,000 | | | $ | 13,836,000 | | Beginning of year | $ | (1,685,000) | | | $ | 2,310,000 | |
| Sales of oil and natural gas produced, net of production costs | Sales of oil and natural gas produced, net of production costs | (1,843,000) | | | (1,193,000) | | Sales of oil and natural gas produced, net of production costs | (3,604,000) | | | (1,843,000) | |
| Net changes in prices and production costs, net of royalties and wellhead taxes | Net changes in prices and production costs, net of royalties and wellhead taxes | (1,876,000) | | | (15,358,000) | | Net changes in prices and production costs, net of royalties and wellhead taxes | 5,702,000 | | | (1,876,000) | |
| Extensions and discoveries | 0 | | | 891,000 | | |
| | Net change due to purchases and sales of minerals in place | Net change due to purchases and sales of minerals in place | 467,000 | | | 334,000 | | Net change due to purchases and sales of minerals in place | (882,000) | | | 467,000 | |
| Previously estimated development costs incurred | Previously estimated development costs incurred | 1,305,000 | | | 0 | | Previously estimated development costs incurred | — | | | 1,305,000 | |
| Changes in future development costs | Changes in future development costs | 7,773,000 | | | 0 | | Changes in future development costs | — | | | 7,773,000 | |
| Revisions of previous quantity estimates | Revisions of previous quantity estimates | (10,274,000) | | | (71,000) | | Revisions of previous quantity estimates | 4,217,000 | | | (10,274,000) | |
| Net change in income taxes | Net change in income taxes | 288,000 | | | 3,792,000 | | Net change in income taxes | (845,000) | | | 288,000 | |
| Accretion of discount | Accretion of discount | 230,000 | | | 1,350,000 | | Accretion of discount | (176,000) | | | 230,000 | |
| Other - changes in the timing of future production and other | Other - changes in the timing of future production and other | (63,000) | | | (932,000) | | Other - changes in the timing of future production and other | (55,000) | | | (63,000) | |
| Other - net change in Canadian dollar translation rate | Other - net change in Canadian dollar translation rate | (2,000) | | | (339,000) | | Other - net change in Canadian dollar translation rate | (27,000) | | | (2,000) | |
| Net change | Net change | (3,995,000) | | | (11,526,000) | | Net change | 4,330,000 | | | (3,995,000) | |
| End of year | End of year | $ | (1,685,000) | | | $ | 2,310,000 | | End of year | $ | 2,645,000 | | | $ | (1,685,000) | |
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, 2020,2021, 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, 20202021 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, 2020.2021.
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, 20202021 that materially affected, or is reasonably likely to materially affect, Barnwell’s internal control over financial reporting.
ITEM 9B. OTHER INFORMATION
None.
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, 2020,2021, which proxy statement is incorporated herein by reference.
Barnwell adopted a Code of Ethics that applies to its Chief Executive Officer and the Chief Financial Officer. This Code of Ethics has been posted on Barnwell’s website at www.brninc.com.
ITEM 11. EXECUTIVE COMPENSATION
The information required is omitted pursuant to General Instruction G(3) of Form 10-K, since the Registrant will file its definitive proxy statement for the Annual Meeting of Stockholders no later than 120 days after the close of its fiscal year ended September 30, 2020,2021, which proxy statement is incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
The information required is omitted pursuant to General Instruction G(3) of Form 10-K, since the Registrant will file its definitive proxy statement for the Annual Meeting of Stockholders no later than 120 days after the close of its fiscal year ended September 30, 2020,2021, which proxy statement is incorporated herein by reference.
Equity Compensation Plan Information
The following table provides information about Barnwell's common stock that may be issued upon exercise of options and rights under Barnwell's existing equity compensation plan as of September 30, 2021:
| | | | | | | | | | | | | | | | | | | | |
| | (a) | | (b) | | (c) |
| Plan Category | | Number of
securities
to be issued
upon exercise
of outstanding options, warrants
and rights | | Weighted-
average
price of
outstanding
options,
warrants
and rights | | Number of securities
remaining available
for future issuance
under equity
compensation plans
(excluding securities
reflected in column (a)) |
| Equity compensation plans approved by security holders | | 615,000 | | $3.36 | | 135,000 |
| Equity compensation plans not approved by security holders | | — | | — | | — |
| Total | | 615,000 | | $3.36 | | 135,000 |
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
The information required is omitted pursuant to General Instruction G(3) of Form 10-K, since the Registrant will file its definitive proxy statement for the Annual Meeting of Stockholders no later than 120 days after the close of its fiscal year ended September 30, 2020,2021, which proxy statement is incorporated herein by reference.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
The information required is omitted pursuant to General Instruction G(3) of Form 10-K, since the Registrant will file its definitive proxy statement for the Annual Meeting of Stockholders no later than 120 days after the close of its fiscal year ended September 30, 2020,2021, which proxy statement is incorporated herein by reference.
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
(a) Financial Statements
The following consolidated financial statements of Barnwell Industries, Inc. and its subsidiaries are included in Part II, Item 8:
Report of Independent Registered Public Accounting Firm – WEAVER AND TIDWELL, L.L.P.
Report of Independent Registered Public Accounting Firm – KPMG LLP
Consolidated Balance Sheets – September 30, 20202021 and 20192020
Consolidated Statements of Operations – for the years ended September 30, 20202021 and 20192020
Consolidated Statements of Comprehensive LossIncome (Loss) – for the years ended September 30, 20202021 and 20192020
Consolidated Statements of Equity (Deficit) – for the years ended September 30, 20202021 and 20192020
Consolidated Statements of Cash Flows – for the years ended September 30, 20202021 and 20192020
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)
|
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10.8 | | Purchase and Sale Agreement, dated July 19, 2018, between Barnwell of Canada, Limited and Octavian Oil Ltd. and Eagle Energy Inc. (11)
|
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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)(9)
|
| | | | | | | | |
| | |
10.1010.7 | | Agreement with Respect to Retained Rights, dated as of March 7, 2019 between Kaupulehu Developments and KD Acquisition II, LP (13)(10)
|
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| 10.8 | | Form of Option Agreement (11) |
| | |
| 10.9 | | Asset Purchase and Sale Agreement, dated July 8, 2021, between Barnwell of Canada, Limited and Tourmaline Oil Corp. |
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| 21 | | List of Subsidiaries |
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2323.1 | | Consent of InSite Petroleum Consultants Ltd. |
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| 23.2 | | Consent of Weaver and Tidwell, L.L.P. |
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| 31.1 | | Certification of Chief Executive Officer Pursuant To Section 302 of the Sarbanes-Oxley Act of 2002 |
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| 31.2 | | Certification of Chief Financial Officer Pursuant To Section 302 of the Sarbanes-Oxley Act of 2002 |
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| 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 31,2019.31, 2019.
(13)(10) Incorporated by reference to Exhibit 10.2 to Registrant’s Form 10-Q for the quarterly period ended March 31, 2019. Certain confidential information has been omitted from a portion of this exhibit.
(11)Incorporated by reference to Exhibit 10.1 to Registrant’s Form 10-Q for the quarterly period ended March 31, 2021.
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, 202021, 2021 |
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, 202021, 2021 | | Russell M. Gifford Executive Vice President, Chief Financial Officer, Treasurer and Secretary Date: December 16, 202021, 2021 |
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| | |
/s/ Kenneth S. Grossman | | |
Kenneth S. Grossman, Chairman of the Board
Date: December 16, 2020 | | |
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| | |
/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 |
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| | | |
| | | |
| /s/ Peter J. O’Malley | | |
Peter J. O’Malley, Chairman of the Board Date: December 21, 2021 | | |
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| /s/ Kenneth S. Grossman | | |
Kenneth S. Grossman, Vice-Chairman of the Board Date: December 21, 2021 | | |
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| | |
| /s/ Philip J. McPherson | | /s/ Colin R. O’Farrell |
Philip J. McPherson, Director Date: December 21, 2021 | | Colin R. O’Farrell, Director Date: December 21, 2021 |
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| | |
| /s/ Bradley M. Tirpak | | /s/ Doug N. Woodrum |
Peter J. O’Malley,Bradley M. Tirpak, Director
Date: December 16, 202021, 2021 | | Bradley M. Tirpak,Doug N. Woodrum, Director
Date: December 16, 202021, 2021 |
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/s/ Doug N. Woodrum | | |
Doug N. Woodrum, Director
Date: December 16, 2020 | | |
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INDEX TO EXHIBITS
| | | | | | | | |
Exhibit
Number | | Description |
| | | |
| 3.1 | | |
| | | |
| 3.2 | | |
| | | |
| 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 | | |
| | | |
| 10.3 | | |
| | | |
| 10.4 | | |
| | | |
| 10.5 | | |
| | |
| 10.6 | | |
| | |
10.7 | | |
| | |
10.8 | | |
| | |
10.9 | |
|
| | |
10.1010.7 | |
|
| | |
| 10.8 | | |
| | |
| 10.9 | | |
| | |
| 21 | | |
| | | |
2323.1 | | |
| | |
| 23.2 | | |
| | | |
| 31.1 | | |
| | | |
| 31.2 | | |
| | | |
| 32 | | |
| | | |
| 99.1 | | |
| | |
| 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 31,2019.31, 2019.
(13)(10) Incorporated by reference to Exhibit 10.2 to Registrant’s Form 10-Q for the quarterly period ended March 31, 2019. Certain confidential information has been omitted from a portion of this exhibit.
(11)Incorporated by reference to Exhibit 10.1 to Registrant’s Form 10-Q for the quarterly period ended March 31, 2021.