As filed with the Securities and Exchange Commission on June 5, 2024

Registration No. 333-279119

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

Amendment No. 1

to

Form S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

 

 

Tamboran Resources Corporation

(Exact name of registrant as specified in its charter)

 

 

 

Delaware		1311		93-4111196
(State or other jurisdiction of incorporation or organization)		(Primary Standard Industrial Classification Code Number)		(I.R.S. Employer Identification No.)

Suite 01, Level 39, Tower One, International Towers Sydney

100 Barangaroo Avenue, Barangaroo NSW 2000

Australia +61 2 8330 6626

(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)

 

 

C T Corporation System

1209 Orange Street, Wilmington, County of New Castle, Delaware 19801

(302) 658-7581

(Name, address, including zip code, and telephone number, including area code, of agent for service)

 

 

Copies to:

 

Michael Chambers David J. Miller Latham & Watkins LLP 300 Colorado St., Suite 2400 Austin, Texas 78701 (737) 910-7300		Trevor Lavelle Andrew S. Epstein Clifford Chance US LLP 845 Texas Ave. Houston, TX 77002 (713) 821-2800

 

 

Approximate date of commencement of proposed sale of the securities to the public:

As soon as practicable after the effective date of this Registration Statement.

If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box: ☐

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ☐

If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ☐

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ☐

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 7(a)(2)(B) of the Securities Act.  ☐

 

 

The registrant hereby amends this registration statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment that specifically states that this registration statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933, as amended, or until this registration statement shall become effective on such date as the U.S. Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

 

 

 

The information in this preliminary prospectus is not complete and may be changed. These securities may not be sold until the registration statement filed with the Securities and Exchange Commission is effective. This preliminary prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any jurisdiction where the offer or sale is not permitted.

 

Subject to Completion, dated     , 2024

Preliminary Prospectus

Shares

 

Tamboran Resources Corporation

Common Stock

 

 

This is the initial public offering of common stock of Tamboran Resources Corporation, a Delaware corporation. We are offering      shares of our common stock. We have granted the underwriters a 30-day option to purchase up to      additional shares from us at the initial public offering price, less the underwriting discounts and commissions.

Depositary interests, referred to as CHESS Depository Interests (“CDIs”), each representing beneficial interests of 1/200th of a share of our common stock, are listed on the Australian Stock Exchange (“ASX”) under the symbol “TBN.” This prospectus does not constitute an offer to sell, or the solicitation of any offer to buy, any CDIs.

We anticipate that the initial public offering price of our common stock will be between $     and $     per share. We have applied to list our common stock on the New York Stock Exchange (the “NYSE”) under the symbol “TBN.” The closing of this offering is contingent upon approval for listing by the NYSE.

We are an “emerging growth company” as the term is used in the Jumpstart Our Business Startups Act of 2012 (“JOBS Act”) and, as such, have elected to comply with certain reduced public company reporting requirements. See “Prospectus Summary—Emerging Growth Company Status.”

 

 

Investing in our common stock involves risks, including those described under “Risk Factors” beginning on page 21 of this prospectus.

 

		Per Share		Total
Public offering price		$		$
Underwriting discount and commissions(1)		$		$
Proceeds to us before expenses		$		$

 

(1)	The underwriters will also be reimbursed for certain expenses incurred in this offering. See “Underwriting” for additional information regarding underwriting compensation.

Neither the U.S. Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

 

 

The underwriters expect to deliver the shares of our common stock on or about     , 2024.

Joint Book-Running Managers

 

BofA Securities		Citigroup		RBC Capital Markets

Co-Managers

 

Johnson Rice & Company				Piper Sandler

The date of this prospectus is     , 2024

 

 

 

TABLE OF CONTENTS

 

		Page
PROSPECTUS SUMMARY			1
SUMMARY CONSOLIDATED FINANCIAL DATA			19
RISK FACTORS			21
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS			61
USE OF PROCEEDS			64
DIVIDEND POLICY			65
CAPITALIZATION			66
DILUTION			67
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			69
INDUSTRY			84
BUSINESS			93
MANAGEMENT			125
EXECUTIVE AND DIRECTOR COMPENSATION			131
PRINCIPAL STOCKHOLDERS			142
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS			145
DESCRIPTION OF CAPITAL STOCK			148
SHARES ELIGIBLE FOR FUTURE SALE			156
CERTAIN ERISA CONSIDERATIONS			158
MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES TO NON-U.S. HOLDERS OF OUR COMMON STOCK			161
UNDERWRITING			165
LEGAL MATTERS			173
EXPERTS			174
WHERE YOU CAN FIND MORE INFORMATION			175
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY INFORMATION			F-1

 

 

Through and including    , 2024 (the 25^th day after the date of this prospectus), all dealers that effect transactions in our common stock, whether or not participating in this offering, may be required to deliver a prospectus. This delivery requirement is in addition to a dealer’s obligation to deliver a prospectus when acting as an underwriter and with respect to unsold allotments or subscriptions.

You should rely only on the information contained in this prospectus or in any free writing prospectus that we authorize to be distributed to you. We and the underwriters have not authorized anyone to provide you with any information other than that contained in this prospectus or in any free writing prospectus prepared by or on behalf of us or to which we have referred you, and neither we, nor the underwriters take responsibility for any other information others may give you. We are offering to sell, and seeking offers to buy, shares of our common stock only in jurisdictions where such offers and sales are permitted. The information in this prospectus or any free writing prospectus is accurate only as of its date, regardless of its time of delivery or the time of any sale of shares of our common stock. Our business, financial condition, results of operations and prospects may have changed since that date.

For investors outside the United States: We and the underwriters have not done anything that would permit a public offering of the securities offered hereby or possession or distribution of this prospectus, any amendment or supplement to this prospectus, or any applicable free writing prospectus in any jurisdiction where action for that purpose is required, other than in the United States. Persons outside the United States who come into possession of this prospectus, any amendment or supplement to this prospectus, or any applicable free writing prospectus

 

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must inform themselves about, and observe any restrictions relating to, the offering of the securities and the distribution of this prospectus, any amendment or supplement to this prospectus, or any applicable free writing prospectus outside of the United States.

This prospectus, the registration statement of which this prospectus forms a part and the offering have not been, nor will they need to be, lodged with the Australian Securities & Investments Commission. This prospectus and the registration statement of which this prospectus forms a part are not a “Prospectus” under Chapter 6D of the Corporations Act 2001 (Cth) of Australia, or the Australian Corporations Act. Any offer of shares of our common stock in Australia is made only to persons to whom it is lawful to offer shares of our common stock without disclosure under one or more of certain of the exemptions set out in section 708 of the Australian Corporations Act, or an “exempt person.” Further details of the exemptions are set out below in “Underwriting—Notice to Prospective Investors—Australia.” By accepting this prospectus, an offeree in Australia represents that the offeree is an exempt person. No shares of our common stock will be issued or sold in this offering in circumstances that would require the giving of a “Prospectus” under Chapter 6D of the Australian Corporations Act.

Industry and Market Data

In this prospectus, we present certain market and industry data. This information is based on third-party sources that we believe to be reliable as of their respective dates. Neither we nor the underwriters have independently verified any third-party information. Some data is also based on our good faith estimates. Expectations of our and our industry’s future performance are necessarily subject to a high degree of uncertainty and risk due to a variety of factors, including those described in “Risk Factors.” These and other factors could cause future performance to differ materially from our expectations. See “Cautionary Statement Regarding Forward-Looking Statements.”

Presentation of Financial and Operating Data

Our fiscal year ends on June 30. Unless otherwise noted, any reference to a year preceded by the words “fiscal year” refers to the twelve months ended June 30 of that year. For example, references to “fiscal year 2022” refer to the twelve months ended June 30, 2022. References to “dollars,” “$,” “U.S. dollars” and “US$” refer to United States dollars; and references to “Australian dollars” and “A$” refer to Australian dollars.

Tamboran Resources Corporation (“Tamboran”) was incorporated on October 3, 2023 and does not have financial operating results prior to the corporate reorganization effective December 13, 2023. As a result of the corporate reorganization, Tamboran became the parent company of Tamboran Resources Limited (“TR Ltd.”), and for financial reporting purposes, the financial statements of TR Ltd. became the financial statements of Tamboran. As a result of the corporate reorganization, Tamboran issued to eligible shareholders of TR Ltd. one CDI of its common stock for every one ordinary share of TR Ltd., with each CDI representing 1/200th of a share of Tamboran’s common stock. For purposes of this prospectus, the historical financial statements of Tamboran have been presented as though the corporate reorganization had taken place on July 1, 2021 and Tamboran had existed as the parent of TR Ltd. as of that date. All share and per share data presented in this prospectus have been retroactively adjusted to reflect a one for two hundred (1:200) exchange ratio and all options over ordinary shares in the predecessor have been retroactively presented as options over CDIs in Tamboran. See “Corporate Reorganization” included elsewhere in this prospectus. Unless otherwise indicated, information presented in this prospectus (i) assumes that the underwriters’ option to purchase additional common stock is not exercised and (ii) assumes that the initial public offering price of the shares of our common stock will be $   per share (which is the midpoint of the estimated price range set forth on the cover page of this prospectus).

Our operating and financial data may not be comparable between periods presented in this prospectus and to future periods. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

 

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Trademarks and Trade Names

We own or have rights to various trademarks, service marks and trade names that we use in connection with the operation of our business. This prospectus may also contain trademarks, service marks and trade names of third parties, which are the property of their respective owners. Our use or display of third parties’ trademarks, service marks, trade names or products in this prospectus is not intended to, and does not imply a relationship with, or endorsement or sponsorship by us. Solely for convenience, the trademarks, service marks and trade names referred to in this prospectus may appear without the ^®,^™ or ^SM symbols, but such references are not intended to indicate, in any way, that we will not assert, to the fullest extent under applicable law, our rights or the rights of the applicable licensor to these trademarks, service marks and trade names.

Rounding and Percentages

The financial information and certain other information presented in this prospectus have been rounded to the nearest whole number or the nearest decimal. Therefore, the sum of the numbers in a column may not conform exactly to the total figure given for that column in certain tables in this prospectus. In addition, certain percentages presented in this prospectus reflect calculations based upon the underlying information prior to rounding and, accordingly, may not conform exactly to the percentages that would be derived if the relevant calculations were based upon the rounded numbers or may not sum due to rounding.

Currency Exchange Rate Data

Our functional currency is the Australian dollar and our consolidated financial statements are presented in the U.S. dollar. The functional currency is the currency of the primary economic environment in which an entity’s operations are conducted. We translate our consolidated financial statements into the presentation currency using exchange rates in effect on the relevant balance sheet date for assets and liabilities and average exchange rates for the period for statement of operations accounts, with the difference recognized as a separate component of stockholders’ equity.

The following exchange rates were used to translate our consolidated financial statements and other financial and operational data shown in constant currency:

 

		Average for the Nine Months ended March 31,								Average for the Fiscal Year
		2024				2023				2023				2022
A$1.00		$	0.65			$	0.68			$	0.67			$	0.73

The following table lists, for each period presented, the high and low exchange rates, the average of the exchange rates on each business day during the period indicated and the exchange rates at the end of the period for one Australian dollar, expressed in U.S. dollars, based on the closing midrate as reported by FactSet.

 

Nine Months ended March 31,

Fiscal Year

2024

2023

2023

2022

High for the period

0.689x

0.712x

0.712x

0.762x

Low for the period

0.629x

0.622x

0.622x

0.688x

End of the period

0.652x

0.670x

0.666x

0.688x

Average for the period(1)

0.655x

0.675x

0.673x

0.726x

 

(1)	Average represents the average of the rates on each business day during the period.

The above rates may differ from the actual rates used in the preparation of the financial statements and other financial information appearing in this prospectus. Our inclusion of these exchange rates is not meant to suggest

 

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that the Australian dollar amounts actually represent such U.S. dollar amounts or that such amounts could have been converted into U.S. dollars at any particular rate, if at all.

Other Considerations

This prospectus contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control. See “Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statements” for additional information regarding these risks.

You should read this prospectus and any written communication prepared by us or on our behalf in connection with this offering, together with the additional information described in the section of this prospectus titled “Where You Can Find More Information.” We have not authorized anyone to provide you with information or to make any representation in connection with this offering other than those contained herein. If anyone makes any recommendation or gives any information or representation regarding this offering, you should not rely on that recommendation, information or representation as having been authorized by us, the underwriters or any other person on our behalf. The information contained in this prospectus is accurate only as of the date of which it is shown, or if no date is otherwise indicated, the date of this prospectus, regardless of the time of delivery of this prospectus or of any sale of our shares of common stock. We are offering to sell, and seeking offers to buy, shares of common stock only in jurisdictions where offers and sales are permitted. Our business, financial condition, results of operations and prospects may have changed since that date. Information contained on our website is not part of this prospectus.

No action is being taken in any jurisdiction outside the United States to permit a public offering of shares of common stock or possession or distribution of this prospectus in that jurisdiction. Persons who come into possession of this prospectus in jurisdictions outside the United States are required to inform themselves about and to observe any restrictions as to this offering and the distribution of this prospectus applicable to that jurisdiction.

Glossary of Natural Gas Terms

The following are abbreviations and definitions of certain terms used in this prospectus, which are commonly used in the natural gas industry:

“analogous reservoir” refers to analogous reservoirs, as used in resources assessments, having similar rock and fluid properties, reservoir conditions (depth, temperature and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an analogous reservoir refers to a reservoir that shares the following characteristics with the reservoir of interest: (i) same geological formation (but not necessarily in pressure communication with the reservoir of interest); (ii) same environment of deposition; (iii) similar geological structure; and (iv) same drive mechanism.

“appraisal well” refers to a vertical or horizontal well designed to assess the properties of the prospective formation by performing open hole logging activities, diagnostic fracture injection testing, fracture stimulation, flow testing, or any combination of the above for the purpose of formation evaluation. Our use of the term “appraisal well” correlates to the term “exploratory well” as defined in Rule 4-10(a) of Regulation S-X.

“Bcf” refers to one billion cubic feet.

“Bcf/d” refers to one billion cubic feet per day.

“Btu” refers to British thermal unit, which is the heat required to raise the temperature of one pound of liquid water by one degree Fahrenheit.

 

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“CCUS” refers to carbon capture, utilization and sequestration.

“CO₂” refers to carbon dioxide.

“CO₂e” refers to carbon dioxide equivalent.

“completion” refers to the installation of permanent equipment for production of oil or gas.

“developed acres” refers to the number of acres that are allocated or assignable to productive wells.

“development well” refers to a well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

“drilling space unit” or “DSU” refers to the area allocated to a well for the purpose of drilling for or producing oil or gas.

“estimated ultimate recovery” or “EUR” refers to the sum of reserves remaining as of a given date and cumulative production as of that date.

“exploratory well” refers to a well drilled to find or establish a new productive oil or natural gas reservoir, or to delineate the extent of a known productive reservoir.

“extension well” refers to a well drilled in an effort to extend the limits of a known productive reservoir.

“farmin agreement” refers to an agreement under which the owner of a working interest in license assigns the working interest or a portion of the working interest to another party (the “farmee”) as a means to share the costs and risks of development. Generally, the farmee agrees to pay the cost of the working interest owner (the “farmor”) to drill one or more wells. As consideration for the farmee’s services, the farmor transfers to the farmee a portion of the farmor’s interest in the license.

“frac” refers to the drilling method for extracting oil and natural gas.

“gross acres” or “gross wells” refers to the total acres or wells, as the case may be, in which a working interest is owned.

“Henry Hub” refers to a natural gas pipeline located in Erath, Louisiana that serves as the official delivery location for futures contracts on the NYMEX. The settlement prices at the Henry Hub are used as benchmarks for the North American natural gas market.

“IP30” refers to 30-day initial production.

“IP60” refers to 60-day initial production.

“IP90” refers to 90-day initial production.

“Mcf” refers to one thousand cubic feet.

“Mcf/d” refers to one thousand cubic feet per day.

“MMboe” refers to one million barrels of oil equivalent.

“MMBtu” refers to one million Btus.

“MMcf” refers to one million cubic feet.

 

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“MMcf/d” refers to one million cubic feet per day.

“Mtpa” refers to million metric tons per year.

“net acres” refers to the gross acres on which an owner holds an interest, proportionally reduced by the working interest in such acreage. For example, an owner who has 50% interest in 100 acres owns 50 net acres.

“net wells” refers to the gross wells on which an owner holds an interest, proportionally reduced by the working interest in such wells. For example, an owner who has 50% interest in 100 wells owns 50 net wells.

“ORRI” refers to overriding royalty interest.

“petrophysical analysis” refers to the integration and analysis of various data types, including well logs, core samples and fluid samples and comparison of data with other relevant geological and geophysical information to describe the reservoir properties.

“probable reserves” refers to additional reserves that are less certain to be recognized than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

“productive well” refers to an exploratory, development, or extension well that is capable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.

“prospective resources” refers to quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.

“proved reserves” refers to quantities of oil, natural gas and NGLs that, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible-from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations-prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or we must be reasonably certain that it will commence within a reasonable time. For a complete definition of proved crude oil and natural gas reserves, refer to the SEC’s Regulation S-X, Rule 4-10(a)(22).

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

“resources” refers to quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.

“royalty interest” refers to an interest in an oil and natural gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.

 

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“Scope 1 emissions” refers to direct GHG emissions that occur from sources that are controlled or owned by an organization.

“Scope 2 emissions” refers to indirect GHG emissions associated with the purchase of electricity, steam, heat or cooling.

“Scope 3 emissions” refers to GHG emissions that result from the end use of an organization’s products, as well as emissions from other business activities from assets not owned or controlled by the organization but that the organization indirectly impacts in its value chain.

“unconventional drilling” refers to the application of advanced technology, other than traditional vertical well extraction, to extract oil and natural gas resources. Unconventional drilling typically includes directional drilling across long, lateral intervals within narrow horizontal formations offering greater contact area with the producing formation, and various types of hydraulic fracturing at multiple stages to optimize production.

“unconventional natural gas” refers to natural gas that cannot be produced at economic flow rates nor in economic volumes unless the well is stimulated by a hydraulic fracture treatment, a horizontal wellbore, or by using multilateral wellbores or some other technique to expose more of the reservoir to the wellbore.

“unconventional play” refers to a set of known or postulated oil and or natural gas resources or reserves warranting further exploration which are extracted from (a) low-permeability sandstone and shale formations and (b) coalbed methane. These plays require the application of unconventional drilling to extract the oil and natural gas resources.

“unconventional resources” refers to the umbrella term for oil and natural gas that is produced by means that do not meet the criteria for conventional production. What has qualified as “unconventional” at any particular time is a complex function of resource characteristics, the available exploration and production technologies, the economic environment, and the scale, frequency and duration of production from the resource. The term is most commonly used in reference to oil and gas resources whose porosity, permeability, fluid trapping mechanism, or other characteristics differ from conventional sandstone and carbonate reservoirs. Coalbed methane, gas hydrates, shale gas, shale oil, fractured reservoirs and tight gas sands are considered unconventional resources.

“undeveloped acre” refers to acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of crude oil, NGLs, and natural gas, regardless of whether such acreage contains proved reserves. Undeveloped acres include net acres held by operations until a productive well is established in the spacing unit.

“unproved properties” refers to properties with no proved reserves.

“working interest” refers to the right granted to the lessee of a property to explore for and to produce and own natural gas or other minerals. The working interest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis.

Commonly Used Defined Terms

As used in this prospectus, unless the context indicates or otherwise requires, the terms listed below have the following meanings:

“Beetaloo” refers to the Beetaloo Basin of the Northern Territory, Australia.

“Beetaloo Joint Venture” refers to the unincorporated joint venture in respect to EPs 76, 98 and 117, between TB1 Operator (77.5% working interest) and Falcon (22.5% non-operated working interest).

 

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“bp” refers to BP Singapore Pte. Ltd, a subsidiary of BP plc.

“bylaws” refers to the bylaws of Tamboran Resources Corporation.

“CDI” refers to a CHESS Depository Interest.

“certificate of incorporation” refers to the certificate of incorporation of Tamboran Resources Corporation.

“Code” refers the Internal Revenue Code of 1986, as amended.

“Convertible Note” refers to the 5.5% Convertible Senior Note due 2029 between Helmerich & Payne International Holdings, LLC, Tamboran Resources Corporation, and the guarantors thereto dated June 4, 2024.

“corporate reorganization” refers to the transactions pursuant to which, among other things, we (i) issued to eligible shareholders of TR Ltd. one CDI of our common stock for every one ordinary share of TR Ltd., in each case, as held on the scheme record date, (ii) amended the terms of each of the outstanding options to acquire ordinary shares of TR Ltd. so that the entitlements of option holders to be issued ordinary shares in TR Ltd. instead became entitlements to be issued CDIs in the Company, (iii) maintained an ASX listing for our CDIs, with each CDI representing 1/200^th of a share of our common stock, (iv) delisted TR Ltd.’s ordinary shares from the ASX, and (v) became the parent company to TR Ltd.

“Corporations Act” refers to the Australian Corporations Act, 2001 (Cth).

“Daly Waters” or “DWE” refers to Daly Waters Energy, LP, which is 100% owned by Formentera Australia Fund, LP, which is managed by Formentera Partners, LP, a private equity firm of which Bryan Sheffield serves as managing partner.

“Daly Waters Royalty” refers to Daly Waters Royalty, LP.

“ESG” refers to environmental, social and governance.

“Falcon” or “Falcon Oil & Gas” or “FOG” refers to Falcon Oil and Gas Australia Ltd, a wholly owned subsidiary of Falcon Oil and Gas Limited (TSX.V: FOG, London AIM: FO).

“Federal Government” refers to the federal government of Australia.

“GAAP” refers to generally accepted accounting principles in the United States.

“GHG” refers to greenhouse gases.

“governing documents” refers to our certificate of incorporation and our bylaws.

“H&P” refers to Helmerich & Payne International Holdings, LLC, a subsidiary of Helmerich and Payne, Inc. (NYSE: HP).

“Northern Territory” refers to the Northern Territory of Australia.

“operational net zero” refers to the full elimination and/or offset of Scope 1 and Scope 2 emissions in our owned and operated upstream businesses.

“Origin B2” refers to Origin Energy B2 Pty Ltd., a subsidiary of Origin Energy.

“Origin Energy” refers to Origin Energy Limited (ASX: ORG).

“Origin Retail” refers to Origin Energy Retail Pty Ltd., a subsidiary of Origin Energy.

 

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“Petroleum Act” refers to the Petroleum Act 1984 (NT).

“Santos” or “Santos QNT” refers to Santos QNT Pty Ltd, a wholly owned subsidiary of Santos Ltd (ASX: STO).

“scheme of arrangement” refers to a statutory scheme of arrangement under Australian law under Part 5.1 of the Corporations Act.

“Shell” refers to Shell Eastern Trading (Pte) Ltd, a subsidiary of Shell plc (NYSE: SHEL).

“Tamboran” refers to Tamboran Resources Corporation, a Delaware corporation.

“TB1” refers to Tamboran (B1) Pty Ltd, an Australian private limited company, which is a 50 / 50 joint venture between us and Daly Waters that holds a 77.5% working interest in the Beetaloo Joint Venture through its wholly owned subsidiary, TB1 Operator.

“TB1 Operator” refers to Tamboran B2 Pty Ltd, an Australian private limited company.

“TR Ltd.” refers to Tamboran Resources Limited, an Australian limited company.

“TR West” refers to Tamboran (West) Pty Ltd, an Australian private limited company.

 

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RISK FACTORS

Investing in our common stock involves risks. You should carefully consider the information in this prospectus, including the matters addressed under “Cautionary Note Regarding Forward-Looking Statements,” the following risks and all of the other information set forth in this prospectus before making an investment decision. The risks and uncertainties described below are not the only ones we face. Additional risks not presently known to us or that we currently deem immaterial may also impair our business operations. If any of the following risks actually occur, our business, financial condition and results of operations could be materially and adversely affected, and we may not be able to achieve our goals. We cannot assure you that any of the events discussed in the risk factors below will not occur. The trading price of our common stock could decline due to any of these risks, and you may lose all or part of your investment.

Risks Related to Our Business and Industry

We are an early stage development company with no material revenue expected until 2026, at the earliest. We have a limited operating history, and our future performance is uncertain. Our ability to successfully drill and complete the wells identified for our current capital plan will depend on a variety of factors.

We are an early stage development company with no material revenues or reserves currently. To date we have drilled and completed only four wells as operator. We have observed lower normalized flow rates in one well compared to other wells that we have participated in drilling in the Beetaloo. We currently only have one well that we believe based on initial flow rates is a productive well, meaning it is capable of producing sufficient quantities of gas to justify completion. Companies in the early stages of operations face substantial business risks and may suffer significant losses. We face challenges and uncertainties in financial planning as a result of the unavailability of historical data and uncertainties regarding the nature, scope and results of our future activities. In the event that our drilling program is delayed, our operating results will be adversely affected, and our operations will differ materially from the activities described in this prospectus.

Our business strategy includes importing and successfully utilizing U.S. drilling and completion techniques to the Northern Territory. We may not be successful in implementing that strategy or in completing the development of the infrastructure necessary to conduct our business as planned. Our ability to successfully maximize the benefits of U.S. technology and techniques depends on a variety of factors, including avoiding delays in procuring equipment and the ability to attract and train employees qualified to operate with U.S. best practices. As a result, we cannot assure you that we will achieve a rate of drilling success that is in line with, or even comparable to, expectations for natural gas development in the United States.

Our business plan requires substantial additional capital, which we may be unable to raise on acceptable terms in the future, or at all, which may in turn limit our ability to execute on our plans.

We have working interests in six additional wells that we plan to drill through calendar year 2025, and estimate gross expenses of approximately $26 million to drill and complete each of those wells. Our ability to raise the capital required to fund the various phases of our development plan will depend on many factors, including:

 

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our success in attracting third party strategic and financial partners and investors to significantly fund our midstream and LNG terminal development goals;

 

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the scope, rate of progress and cost of our development activities;

 

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natural gas prices;

 

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our ability to produce natural gas from our properties;

 

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the terms and timing of any drilling and other production-related arrangements that we may enter into;

 

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the infrastructure available and developed near our properties;

 

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the cost and timing of governmental approvals and/or concessions; and

 

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the effects of competition by other companies operating in the oil and natural gas industry.

 

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We do not currently have any commitments for future external funding, and we do not expect to generate any revenue from production until 2026, at the earliest, which will depend upon successful drilling results, additional and timely capital funding, further regulatory approvals, and access to suitable infrastructure. Additional financing may not be available on favorable terms, or at all. Even if we succeed in selling additional securities to raise funds, at such time the ownership percentage of our existing stockholders would be diluted, and new investors may demand rights, preferences or privileges senior to those of existing stockholders. If we raise additional capital through debt financing, the financing may involve covenants that restrict our business activities. If we choose to farm-out interests in our property, we may lose operating control over such property.

In addition, limitations on new share issuances under Australian Securities Exchange listing rules may limit or prevent us from raising additional capital by issuing and selling shares of common stock or other securities when such additional capital is required. See “Our ability to raise additional capital may be significantly limited by listing rules of the ASX that limit the amount of common stock that we are permitted to issue without stockholder approval.”

Our business plan contemplates delivering natural gas to the Australian East Coast as well as select markets in South and East Asia. Our ability to deliver natural gas in significant quantities to these markets depends on the construction of additional pipeline capacity. We cannot assure you that we will be able to secure sufficient take-away capacity on our timing or at all.

The anticipated production from our business plan will exceed the capacity of the existing pipeline infrastructure that services the Beetaloo. Although we have preliminary agreements with APA Group whereby APA Group has agreed to evaluate the joint development and construction of two additional pipelines from the Beetaloo, any construction of additional pipelines is subject to the execution of mutually satisfactory definite documentation and the satisfaction of several conditions precedent. APA Group has no obligation to construct or dedicate funds to the construction of a pipeline, and may decline to proceed with construction. We cannot assure you that we will reach a mutually satisfactory agreement with APA Group for the construction of the required take-away capacity or the satisfaction to the conditions of any such obligation. The failure to contract for the construction of additional take-away capacity will adversely affect the ability to execute our proposed business plan. In addition, even if we are able to contract for sufficient take-away capacity, we may not be able to contract for gathering and compression services, storage facility capacity, and interconnections to the major pipelines.

We have no proved reserves at this time and areas that we decide to drill may not yield natural gas in commercial quantities or quality, or at all.

We presently have no proved reserves and have not sold any natural gas produced. Based on petrophysical analysis, we have identified locations and drilled appraisal wells that indicate prospective resources. However, our appraisal wells may not be indicative of future results. Additionally, the areas we have drilled, or may decide to drill in the future, may not yield natural gas in commercial quantities or quality, or at all. All of our current property is undeveloped and in various stages of evaluation that will require substantial additional seismic data reprocessing and interpretation. Accordingly, we do not know if our properties will contain natural gas in sufficient quantities or quality to recover drilling and completion costs or to be economically viable. Even if natural gas is found on our property in commercial quantities, construction costs of natural gas pipelines, associated infrastructure, and transportation costs may prevent such property from being economically viable.

Additionally, the analogies drawn by us from available data from other wells may not prove valid in respect of additional wells on our property. If a significant portion of our property does not prove to be successful, our business, financial condition and results of operations will be materially adversely affected.

We face substantial uncertainties in estimating the characteristics of our property, so you should not place undue reliance on any of our estimates.

In this prospectus we provide estimates of the characteristics of our properties, such as implied production volumes (including our 2.0 Bcf/d gross production goal and the normalization of initial production rates to longer

 

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lateral lengths), in the Beetaloo. These estimates may be incorrect, as the accuracy of these estimates is a function of the available data, geological interpretation and our judgment. We may not achieve our 2.0 Bcf/d gross production goal on our proposed timeline or at all, and the wells we have drilled or will drill may not achieve ultimate recoveries within the ranges we have estimated. To date, only four wells on our property have been drilled with us as an operator. Any analogies drawn by us from other wells or producing fields may not prove to be accurate indicators of the success of developing reserves from our property. Furthermore, we have no way of evaluating the accuracy of the data from analog wells or properties produced by other parties that we may use. Any significant variance between actual results and our assumptions could materially affect the quantities of natural gas attributable to any particular group of properties.

Drilling wells is speculative, often involving significant costs that may be more than our estimates, and may not result in any discoveries or additions to our future production or reserves. Any material inaccuracies in drilling costs, estimates or underlying assumptions will materially affect our business.

Exploring for and developing natural gas reserves involves a high degree of operational and financial risk, which precludes definitive statements as to the time required and costs involved in reaching certain objectives. The budgeted costs of drilling, completing and operating wells are often exceeded and can increase significantly when drilling costs rise due to a tightening in the supply of various types of natural gas field equipment and related services. Drilling may be unsuccessful for many reasons, including geological conditions, weather, cost overruns, equipment shortages and mechanical difficulties. Exploratory and appraisal wells bear a much greater risk of loss than development wells. Moreover, the successful drilling of a natural gas well does not necessarily result in a profit on investment.

Following the stimulation of the A2H well in EP 98, which is the first Beetaloo well that we have drilled and completed, we observed lower normalized flow rates than other wells we have participated in the drilling of in the Beetaloo. Laboratory testing of the recovered fluid identified a zone of reduced permeability, or a “skin,” which created an impediment to the flow of natural gas. A variety of factors, both geological and market-related, can cause a well to become uneconomic or only marginally economic. Our initial drilling sites, and any potential additional sites that may be developed, require significant additional exploration and development, regulatory approval and commitments of resources prior to commercial development. If our actual drilling and development costs are significantly more than our estimated costs, we may not be able to continue our business operations as proposed and would be forced to modify our plan of operation.

We intend to import and implement U.S. practices and technology for use in the development of our properties in the Northern Territory. There is limited experience with these practices and technology within the workforce in the areas we operate. The ability to attract and train a qualified workforce could hamper our present operations and limit our ability to grow.

Our operations are mechanically complex and must be performed in remote geographic locations. We believe that our success depends upon our ability to employ and retain a sufficient number of technical personnel who have the ability to utilize, enhance and maintain our natural gas development equipment. Our ability to maintain and expand our operations depends in part on our ability to utilize, replace, supplement and increase our skilled labor force. The supply of skilled workers is limited in the Beetaloo, and it is not guaranteed that we will be able to access a sufficient skilled labor force. A significant increase in the wages paid by competing employers domestically and abroad could result in a reduction of our skilled labor force or cause an increase in the wage rates that we must pay or both. Employee turnover may also lead to lost productivity and decrease employee engagement which could adversely impact our business.

Additionally, our ability to hire, train and retain qualified personnel may become more challenging as we grow and to the extent energy industry market conditions are competitive. Our ability to successfully implement U.S. practices and technology is dependent on finding, training and retaining qualified personnel within Australia for work in the Northern Territory. When general industry conditions are favorable, the competition for experienced operational and field technicians increases as other energy and manufacturing companies’ needs for

 

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the same personnel increases. Our ability to grow or even to continue our current level of operations could be adversely impacted if we are unable to successfully hire, train and retain these important personnel. In addition, effective succession planning for our employees and expansion planning is important to our long-term success. Failure to achieve these plans could hinder our strategic planning and execution and have a material adverse impact on our business, financial condition or results of operations.

Our inability to access appropriate equipment and infrastructure in a timely manner may hinder our access to natural gas markets and delay the phases of our business plan.

Our ability to market our natural gas will depend substantially on the availability and capacity of gathering systems, pipelines and processing facilities owned and operated by third parties not within our control. Our failure to obtain such services on acceptable terms could materially harm our business. The success of our business plan depends on importing and implementing U.S. practices and technology for use in the development of our properties in the Northern Territory. While we have contracted with H&P for H&P FlexRig^® through at least August 2025, with a 10-year option to contract for up to five additional rigs, we have not yet secured importing contracts. The delivery of the further drilling rigs may be delayed or cancelled, and we may not be able to gain continued access to suitable rigs in the future. We may be required to shut in natural gas wells because of the absence of a market or because access to pipelines, gathering systems or processing facilities may be limited or unavailable. If that were to occur, then we would be unable to realize revenue from those wells until arrangements were made to deliver the production to market, which could cause significant delays to the phases of our business plan and have a material adverse effect on our results of operations and financial condition.

In the Beetaloo, as our development is in its preliminary stage, we have no binding agreements for the gathering and processing of our potential future production. As a result, our business plan is dependent on third parties to develop the infrastructure for our natural gas gathering needs. Capital constraints could limit the construction of new pipelines and gathering systems. Until this new capacity is available, we may experience delays in producing and selling our natural gas. In such event, we might have to shut in our wells while awaiting a pipeline connection or additional capacity, which would adversely affect our results of operations. Even when available, the ultimate costs of gathering and transportation systems may prevent some of our properties from being economically viable.

A portion of our natural gas production may be interrupted, or shut in, from time to time for numerous reasons, including weather conditions, accidents, loss of pipeline or gathering system access, field labor issues or strikes, or we might voluntarily curtail production in response to market conditions. If a substantial amount of our production is interrupted at the same time, it could materially adversely affect our cash flow.

Drilling, completions, workover and hydraulic fracturing operations are operationally complex activities which present certain risks that could adversely affect our business, financial condition or results of operations.

In our drilling operations, from time to time we experience certain issues and encounter risks, including, for example, mechanical and instrument or tool failures; drilling difficulties associated with drilling in swelling clay or shales and unconsolidated formation; wellbore instability and other geological hazards; loss of well control and associated hydrocarbon release and/or natural gas clouds; loss of drilling fluids circulation; surface spills of various drilling or well fluids; subsurface collision with existing wells; proximity of adjacent water wells or aquifers; inability to establish drilling fluid circulation; loss or compromise of drill pipe or casing integrity; surface pumping operations and associated pressure and hydrocarbon hazards; stuck and lost-in-hole tools, drill pipe or casing; large drilling equipment and machinery including electrical hazards; insufficient cementing of casing causing unwanted casing pressure or fluid migration; surface overpressure events from large machinery (horsepower), equipment or well pressure; fines and violations related to relevant laws and regulations; fires and explosions; personnel safety hazards such as working at heights, driving or equipment operation, energy isolation, excavation and trenching and more; structural damage and collapse to large equipment and machinery;

 

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major damage or malfunction to key equipment or processes; in certain instances, close proximity of operations to residences and/or communities; among other typical shale basin drilling challenges and risks.

In our hydraulic fracturing, workover and completions activities, from time to time we experience certain issues and encounter risks, including, for example, mechanical and instrument or tool failures; loss of well control and associated hydrocarbon release and/or natural gas clouds; well kick or flowback during completion or fracturing operations; lost or stuck in hole wireline, coiled tubing or workover strings and tools; loss or compromise of workover string, tubing or casing integrity; large completions, wireline, coiled tubing and workover rig equipment and machinery including electrical hazards; insufficient cementing of casing causing unwanted casing pressure or fluid migration while fracturing or thereafter; proximity of adjacent water wells or aquifers and adjacent producing wells; surface spills of various fracturing, freshwater or well fluids or chemicals; surface pumping and flowback operations and associated pressure and hydrocarbon hazards; surface overpressure events from large machinery (horsepower), equipment or well pressure; fines and violations related to relevant laws and regulations; fires and explosions; personnel safety hazards such as working at heights, driving or equipment operation, energy isolation, excavation and trenching and more; structural damage and collapse to large equipment and machinery; major damage or malfunction to key equipment or processes; in certain instances, close proximity of operations to residences and/or communities; among other typical fracturing, workover and completion challenges and risks.

Our industry requires us to navigate many uncertainties that could adversely affect our financial condition and results of operations.

Our financial condition and results of operations depend on the success of the development of our assets, which are subject to numerous risks beyond our control, including the risk that development will not result in commercially viable production or uneconomic results or that various characteristics of the drilling process or the well will cause us to abandon the well prior to fully producing commercially viable quantities.

Our actual development cost for a well could significantly exceed planned “authorization for expenditure” levels. Further, many factors may curtail, disrupt, delay or cancel our scheduled drilling projects and ongoing operations, including the following:

 

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reductions or sustained declines in natural gas prices; and

 

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regulatory compliance, including limitations on wastewater disposal, discharge of greenhouse gases and hydraulic fracturing.

In addition, our assets are anticipated to be developed over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling, the scope, rate of progress and cost of our exploration and production activities. Our ability to drill and develop our assets depends on a number of factors, including the availability of equipment and capital, seasonal conditions, regulatory approvals, obtaining land access agreements for regulated operations, natural gas prices, costs and drilling results. Because of these uncertainties, we do not know if our properties will be drilled within our expected timeframe or at all or if we will be able to economically produce natural gas from these or any other potential drilling locations. As such, our actual drilling activities may be materially different from our current expectations, which could adversely affect our results of operations and financial condition.

Natural gas prices are volatile. A reduction or sustained decline in prices may adversely affect our business, financial condition or results of operations and our ability to meet our financial commitments or raise capital.

Our future growth is dependent on the continued economic importance of the natural gas development and production industry in Australia and global demand (as it relates to LNG trade). Any substantive and prolonged changes to the current economic importance of natural gas development and production industry in Australia would be likely to have an adverse effect on our business, financial condition and profits.

 

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Prevailing natural gas prices heavily influence our potential revenue, profitability, access to capital, growth rate and value of our properties. Further, although we do not produce oil, to the extent oil prices rise considerably, the cost of services we incur may also increase. As a commodity, natural gas prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the natural gas market has been volatile. Our revenue, profitability and future growth are highly dependent on the prices we receive for our natural gas production, and the levels of our production, depend on numerous factors beyond our control. These factors include, but not limited to, the following:

 

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worldwide and regional economic conditions impacting the global supply of and demand for natural gas, including economic growth expectations, inflation and hostilities in Ukraine and the Middle East;

 

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the actions of OPEC, its members and other state-controlled oil companies relating to oil price and production controls;

 

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the level of global oil and natural gas exploration and production;

 

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the level of global oil and natural gas inventories;

 

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prevailing prices on local price indexes in the areas in which we operate and expectations about future commodity prices;

 

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extent of natural gas production associated with increased oil production;

 

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the proximity, capacity, cost and availability of gathering and transportation facilities;

 

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localized and global supply and demand fundamentals and transportation availability;

 

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weather conditions across the globe;

 

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technological advances affecting energy consumption;

 

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speculative trading in natural gas markets;

 

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end-user conservation trends;

 

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petrochemical, fertilizer, ethanol, transportation supply and demand balance;

 

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the price and availability of alternative fuels;

 

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domestic, local and foreign governmental regulation and taxes; and

 

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liquefied petroleum products supply and demand balances.

In particular, because of our higher operating costs than U.S producers, our business model is dependent on the higher natural gas prices we receive from Asian and domestic Australian markets relative to U.S prices. If commodity prices decrease or we experience widening of basis differentials, our cash flows and refinancing ability will be reduced. We may be unable to obtain needed capital or financing on commercially reasonable terms. Lower commodity prices may also reduce the amount of natural gas that we can produce economically. Additionally, a significant portion of our projects could become uneconomic and require us to abandon or postpone our planned drilling. As a result, a reduction or sustained decline in natural gas prices may materially and adversely affect our financial condition, results of operations, liquidity and our ability to finance capital expenditures.

We may not be able to manage our future growth effectively, which could make it difficult to execute our business strategy.

Our expected future growth could create a strain on the organizational, administrative and operational infrastructure. Our ability to manage our growth effectively will require us to continue to improve our operational, financial and management controls, as well as reporting systems and procedures. Our current team is small and we will have to hire additional employees to achieve our expected future growth. Our business strategy

 

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will be difficult to execute, which may impact our ability to effectively attract employees. As we grow, any failure of our controls or interruption of our facilities or systems could have a negative impact on our business and financial operations. Our future development plan, including the potential development of pipelines, LNG export facility, and CCUS projects, will affect a broad range of business processes and functional areas. The time and resources required to implement these new extensions of our business are uncertain, and failure to complete these activities in a timely and efficient manner could adversely affect our operations. If we are unable to manage growth effectively, it may be difficult for us to execute our business strategy.

Our business plan contemplates the execution of midstream contracts with certain third parties in order to allow us to supply our own natural gas for export out of Darwin or directly to the Australian East Coast. We cannot assure you that we will be successful in obtaining the commercial contracts necessary to facilitate direct delivery of our natural gas production on commercially reasonable terms, or at all.

We cannot assure you that we will succeed in any effort to establish midstream contracts that would allow us to supply our own natural gas for export out of Darwin or directly to the Australian East Coast. Even when the physical infrastructure exists to supply our own natural gas directly to Darwin and the Australian East Coast, our ability to utilize that infrastructure depends on whether we can successfully negotiate and enter into midstream contracts on commercially reasonable terms or at all. If we fail to enter into such contracts on commercially reasonable terms or at all or are otherwise subject to capacity constraints, it could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Construction of midstream projects subjects us to risks of construction delays, cost over-runs, limitations on our growth and negative effects on our financial condition, results of operations, cash flows and liquidity.

The second and third phase of our business requires the construction of midstream projects, including pipelines to access the East Coast and our proposed NTLNG terminal, some of which may take a number of years before commercial operation. These projects are complex and subject to a number of factors beyond our control, including delays from third-party landowners, the permitting process, government and regulatory approval, compliance with laws, unavailability of materials, labor disruptions, environmental hazards, financing, accidents, weather and other factors. Any delay in the completion of these projects could have a material adverse effect on our financial condition, results of operations, cash flows and ability to pay dividends on our common stock. The construction of these midstream facilities requires the expenditure of significant amounts of capital, which may exceed our estimated costs. Estimating the timing and expenditures related to these development projects is very complex and subject to variables that can significantly increase expected costs. Should the actual costs of these projects exceed our estimates, our liquidity and financial condition could be adversely affected. This level of development activity requires significant effort from our management and technical personnel and places additional requirements on our financial resources and internal financial controls. We may not have the ability to attract and/or retain the necessary number of personnel with the skills required to bring complicated projects to successful conclusions.

The construction of midstream projects also requires the support of third-party strategic partners, who may have differing goals and strategies. If our strategic partners do not cooperate in the construction of the midstream projects, we may be unable to market our future natural gas production.

If our assessments of the Beetaloo are materially inaccurate, it will have a fundamental impact on our business.

Our assessment of our property may be inherently inexact and may be inaccurate, including the following:

 

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the time it takes to bring the Beetaloo to commercial development phase;

 

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the amount of recoverable reserves;

 

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timing of development of takeaway capacity and access to other infrastructure, including LNG terminals, on an economically viable basis;

 

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geological complexity;

 

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applicable governmental rules and regulations;

 

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native title holders and traditional Aboriginal owners;

 

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estimates of operating costs;

 

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estimates of future development costs;

 

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estimates of the costs and timing of plugging and abandonment; and

 

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potential environmental and other liabilities.

Our assessments will not reveal all existing or potential problems, nor will it permit us to become familiar enough with the breadth of the territory we hold license to in order to assess fully their capabilities and deficiencies. We plan to undertake further development of our properties through the use of cash flow from existing production. Therefore, a material deviation in our assessments of these factors could result in less cash flow being available for such purposes than we presently anticipate, which could either delay future development operations (and delay the anticipated conversion of reserves into cash), or cause us to seek alternative sources to finance development activities.

Numerous uncertainties exist in estimating quantities of proved and possible reserves and any such estimates may be inaccurate.

Reserve engineering is a process of estimating commercially recoverable amounts of petroleum that remain in known accumulations that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In estimating probable reserves, it should be noted that those reserve estimates inherently involve greater risk and uncertainty than estimates of proved reserves. Any estimates of proved and probable reserves presented in this prospectus have not been adjusted for risk due to their uncertainty of recovery and are not comparable to measures of proved and probable reserves that we or any other company may provide. In addition, amounts of proved and probable reserves provided by us or any other company should not be summed into total amounts due to the aforementioned uncertainties.

We are dependent on certain members of our management and technical team.

Investors in our common stock must rely upon the ability, expertise, judgment and discretion of our management and the success of our technical team in developing our future natural gas reserves. Our performance and success are dependent, in part, upon key members of our management and technical team, and their loss or departure could be detrimental to our future success. In making a decision to invest in our common stock, you must be willing to rely to a significant extent on our management’s discretion and judgment. There can be no assurance that our senior management will remain in place. The loss of any of our management and technical team members could have a material adverse effect on our results of operations and financial condition, as well as on the market price of our common stock. See “Management” and “Executive and Director Compensation.”

We have limited control over properties and investments operated by others or through joint ventures.

Certain of our properties are operated by other companies and may involve third-party working interest owners. We have limited influence and control over the operation or future development of such properties and investments, including compliance with environmental, health and safety regulations or the amount and timing of

 

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required future capital expenditures. In addition, we conduct certain of our operations through joint ventures in which we may share control with third parties, and the other joint venture participants may have interests or goals that are inconsistent with those of the joint venture or us. These limitations and our dependence on such third parties could result in unexpected future costs or liabilities and unplanned changes in operations or future development, which could adversely affect our financial condition and results of operations.

Our financial performance is subject to our counterparties’ or joint venture partners’ performance of their obligations under the relevant contracts, including the joint venture agreements. If one of our counterparties or joint venture partners fails to perform its contractual obligations, it may result in loss of earnings, termination of other related contracts, disputes and/or litigation that could impact our financial performance.

Currently, we are not the operator of EP 161, which is operated by Santos. As we carry out our exploration and development programs, we may enter into arrangements with respect to existing or future properties that result in a greater proportion of our properties being operated by others. As a result, we may have limited ability to exercise influence over the operations of the properties operated by our partners. Dependence on the operator could prevent us from realizing our target returns for those properties. Further, it may be difficult for us to pursue one of our key business strategies of minimizing the cycle time between discovery and initial production with respect to properties for which we do not operate. The success and timing of exploration and development activities operated by our partners will depend on a number of factors that will be largely outside of our control, including:

 

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the timing and amount of capital expenditures;

 

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the operator’s expertise and financial resources;

 

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approval of other participants in drilling wells;

 

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selection of technology; and

 

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the rate of production of reserves, if any.

This limited ability to exercise control over the operations of some of our properties may cause a material adverse effect on our results of operations and financial condition.

All of our assets and operations are located in the Beetaloo, making us vulnerable to risks associated with operating in one geographic area.

Our operations are geographically concentrated in the Northern Territory of Australia, and specifically the Beetaloo. As a result, we may be disproportionately exposed to the impact of regional supply and demand factors in the Beetaloo caused by significant governmental regulation, curtailment of production or interruption of the processing or transportation of natural gas produced from wells in this area. In addition, the effect of fluctuations on supply and demand may become more pronounced within a specific geographic natural gas producing area such as the Beetaloo, which may cause these conditions to occur with greater frequency or magnify the effects of these conditions. Due to the concentrated nature of our operations, we could experience any of the same conditions at the same time, resulting in a relatively greater impact on our revenue than they might have on other companies that have more geographically diverse operations.

Our business is subject to operating hazards that could result in substantial losses or liabilities for which we may not have adequate insurance coverage.

Natural gas operations are subject to many risks, including well blowouts, craterings, explosions, uncontrollable flows of natural gas or well fluids, fires, pipe, casing or cement failures, abnormal pressure, pipeline leaks, ruptures or spills, vandalism, pollution, releases of toxic gases, adverse weather conditions or

 

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natural disasters and other environmental hazards and risks. If any of these hazards occur, we could sustain substantial losses as a result of:

 

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injury or loss of life;

 

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severe damage to or destruction of property, natural resources and equipment;

 

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pollution or other environmental damage;

 

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investigatory, monitoring, and cleanup responsibilities;

 

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regulatory investigations and penalties or lawsuits;

 

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loss of, or delay in revenue;

 

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suspension or impairment of operations; and

 

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repairs to resume operations.

We maintain insurance against some, but not all, potential losses or liabilities arising from our operations in accordance with what we believe are customary industry practices and in amounts and at costs that we believe to be prudent and commercially practicable. Our insurance includes deductibles that must be met prior to recovery, as well as sub-limits and/or self-insurance. Additionally, our insurance is subject to exclusions and limitations. Our insurance does not cover every potential risk associated with our operations, including the potential loss of significant revenues. We can provide no assurance that our coverage will adequately protect us against liability from all potential consequences, damages and losses.

We maintain insurance coverage that is considered appropriate for a company of our size operating in the gas exploration phase, subject to policy terms and conditions. This includes insurance coverage related to general and product liability, property, workers compensation, cyber, terrorism and malicious acts, operator’s extra expenses for control of well, seepage and pollution, cleanup and contamination, evacuation expenses and making the well safe.

We may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented. Some forms of insurance may become unavailable in the future or unavailable on terms that we believe are economically acceptable. No assurance can be given that we will be able to maintain insurance in the future at rates that we consider reasonable, and we may elect to maintain minimal or no insurance coverage. If we incur substantial liability from a significant event and the damages are not covered by insurance or are in excess of policy limits, then we would have lower revenues and funds available to us for our operations, that could, in turn, have a material adverse effect on our business, financial condition and results of operations.

Additionally, we will rely to a large extent on transportation infrastructure owned and operated by third parties and damage to, or destruction of, those third-party infrastructure will affect our ability to process, transport and sell our production.

We are subject to numerous risks inherent to the exploration and production of natural gas.

Natural gas exploration and production activities involve many risks that a combination of experience, knowledge and careful evaluation may not be able to overcome. Our future success will depend on the success of our exploration and production activities and on the future existence of the infrastructure that will allow us to take advantage of our findings. Additionally, our natural gas properties are located in an area without significant existing infrastructure, which generally increases the capital and operating costs, technical challenges and risks associated with natural gas exploration and production activities. As a result, our natural gas exploration and production activities are subject to numerous risks, including the risk that drilling will not result in commercially viable natural gas production. Our decisions to purchase, explore, develop or otherwise exploit properties will depend in part on the evaluation of seismic data through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations.

 

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Furthermore, the marketability of expected natural gas production from our property will also be affected by numerous factors. These factors include, but are not limited to, market fluctuations of prices, proximity, capacity and availability of pipelines, the availability of processing facilities, equipment availability and government regulations (including, without limitation, regulations relating to prices, taxes, royalties, allowable production, importing and exporting of natural gas, environmental protection and climate change). The effect of these factors, individually or jointly, may result in us not receiving an adequate return on invested capital.

In the event that our drilling programs are developed and become operational, they may not produce natural gas in commercial quantities or at the costs anticipated, and our projects may cease production, in part or entirely, in certain circumstances. Drilling programs may become uneconomic as a result of an increase in operating costs to produce natural gas. Our actual operating costs may differ materially from our current estimates. Moreover, it is possible that other developments, such as increasingly strict environmental, health and safety laws and regulations and enforcement policies thereunder and claims for damages to property or persons resulting from our operations, could result in substantial costs and liabilities, delays, an inability to complete our drilling programs or the abandonment of such drilling programs, which could cause a material adverse effect on our results of operations and financial condition.

Our identified drilling locations are scheduled out over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.

Our management team has identified and scheduled drilling locations on our acreage over a multi-year period. Our ability to drill and develop these locations depends on a number of factors, including the availability of equipment and capital, seasonal conditions, regulatory approvals, natural gas prices, costs and drilling results. The final determination on whether to drill any of these drilling locations will be dependent upon the factors described above as well as, to some degree, the results of our drilling activities with respect to our appraisal wells. Because of these uncertainties, we do not know if the drilling locations we have identified will be drilled within our expected timeframe or at all. As such, our actual drilling activities may be materially different from our current expectations, which could adversely affect our results of operations and financial condition.

The development schedule of natural gas projects, including the availability and cost of drilling rigs, equipment, supplies, personnel and natural gas field services, is subject to delays and cost overruns.

Historically, some natural gas projects have experienced delays and capital cost increases and overruns due to, among other factors, the unavailability or high cost of drilling rigs and other essential equipment, supplies, personnel and natural gas field services. The cost to develop our projects has not been fixed and remains dependent upon a number of factors, including the completion of detailed cost estimates and final engineering, contracting and procurement costs. Our construction and operation schedules may not proceed as planned and may experience delays or cost overruns. Any delays may increase the costs of the projects, requiring additional capital, and such capital may not be available in a timely and cost-effective fashion.

Part of our business strategy involves using some of the latest available horizontal drilling and completion techniques, which involve risks and uncertainties in their application.

Difficulties that we face while completing our wells include:

 

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the ability to fracture stimulate the planned number of stages with the planned amount of proppant;

 

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the ability to run tools through the entire length of the wellbore during completion operations; and

 

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the ability to successfully clean out the wellbore after completion of the final fracture stimulation stage.

In addition, certain of the new techniques we are adopting may cause irregularities or interruptions in production. If our development and production results are less than anticipated, the return on our investment for a particular well may not be as attractive as we anticipated, and its value could decline in the future.

 

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We also may be subject to additional costs or shortages of equipment and labor because of the necessity of importing certain equipment or hiring talent from the United States. The unavailability or high cost of drilling rigs, completion crews, equipment, supplies, personnel and oilfield services could adversely affect our ability to execute our development plans within our budget and on a timely basis.

Shale gas completions require significant amounts of water which is subject to delays in regulatory approval from certain aquifers and the cost of utilization of aquifer water may increase over time.

The demand for drilling rigs, completion crews, pipe and other equipment and supplies, including sand and other proppant used in hydraulic fracturing operations and acid used for stimulation can fluctuate significantly, often in correlation with commodity prices or drilling activity in our area of operation and in other shale basins, causing periodic shortages of supplies and needed personnel and rapid increases in costs. Increased drilling activity could materially increase the demand for and prices of these goods and services, and we could encounter rising costs and delays in or an inability to secure the personnel, equipment, power, services, resources and facilities access necessary for us to conduct our drilling and development activities, which could result in production volumes being below our forecasted volumes. In addition, any such negative effect on production volumes, or significant increases in costs could have a material adverse effect on our future cash flow and profitability.

Our recurring losses from operations, negative cash flows and substantial cumulative net losses raise substantial doubt about our ability to continue as a going concern.

In Note 1 titled “Nature of the Organization and Business” of our audited consolidated financial statements for fiscal year 2023 and in Note 1 titled “Business and Basis of Preparation” of our unaudited consolidated financial statements for the nine months ended March 31, 2024 included elsewhere in this prospectus, we disclose that there is substantial doubt about our ability to continue as a going concern. In addition, our independent registered public accounting firm included an explanatory paragraph in its report on our consolidated financial statements for fiscal year 2023, which stated that there are factors that raise substantial doubt on our ability to continue as a going concern. We have incurred significant operating losses and negative cash flows from operations and expect to continue incurring increasing losses for the foreseeable future as we further our development program. Further, we had accumulated losses of $108.5 million as of June 30, 2023 and $121.0 million as of March 31, 2024. As of April 30, 2024, we had $19.7 million of cash and cash equivalents. These conditions raise substantial doubt about our ability to continue as a going concern. Our consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

Our ability to become a profitable operating company is dependent upon our ability to generate revenue and obtain financing adequate to fulfill our development and commercialization activities, and achieving a level of revenue adequate to support our cost structure. We have plans to obtain additional resources to fund our currently planned operations and expenditures through additional debt and equity financing, however, there is no guarantee we obtain financing at all or on commercially acceptable terms. We may not continue as a going concern if we do not raise additional capital. We believe that the proceeds raised from the private placement of our CDIs in December 2023 and January 2024 provide us with the capital necessary to continue as a going concern through fiscal year 2024, and the amount of proceeds from this offering, together with our existing cash on hand, will be sufficient to fund our planned drilling and testing program at least through the end of fiscal year 2025. Our plans are substantially dependent upon the success of commercial production at the Beetaloo, which is still in the early stages of development, and are dependent upon, among other things, the success of our drilling program and infrastructure development in the Beetaloo. If we are unable to obtain sufficient funding, our financial condition and results of operations will be materially and adversely affected and we may be unable to continue as a going concern. Future financial statements may disclose substantial doubt about our ability to continue as a going concern. If we seek additional financing to fund our business activities in the future and there remains substantial doubt about our ability to continue as a going concern, investors or other financing sources may be unwilling to provide additional funding to us on commercially reasonable terms or at all.

 

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Our long-term business plan contemplates the development of an additional LNG export terminal on the northern coast of Australia. Our ability to develop such a facility is dependent on our ability to attract a third-party partner as well as securing the necessary permits.

We anticipate commencing construction of the NTLNG project as early as 2027 with completion occurring as early as 2030. Our ability to commence construction of the NTLNG or complete the project on schedule is dependent on a number of factors outside of our control, including the willingness of potential third-party partners to commit to the project. Although we have entered into memoranda of understanding with subsidiaries of each of bp and Shell with respect to long-term contracts for the purchase of a total of 4.4 Mtpa from NTLNG, these memoranda of understanding are not binding obligations of bp or Shell and either may decide not to pursue our project. We cannot assure you we will be successful in the negotiating or execution of definitive agreements. Failure to do so could cause significant delays to the phases of our business plan and have a material adverse effect on our results of operations and financial condition.

In addition, the construction of our proposed NTLNG export facility in the Middle Arm Sustainable Development (“MASD”) precinct relies on the award of a binding land use agreement between the Company and the Northern Territory government. The MASD acreage has been allocated to us on an exclusive basis for a term extending to December 31, 2024 during which we have completed a concept selection phase and plan to present our findings to the Northern Territory government. There is no guarantee that we are awarded a binding land use agreement with respect to this land.

A financial crisis or deterioration in general economic, business or industry conditions could materially adversely affect our results of operations and financial condition.

Concerns over global economic conditions, stock market volatility, energy costs, geopolitical issues, inflation and U.S. Federal Reserve interest rate increases in response, the availability and cost of credit, and slowing of economic growth in the United States and fears of a recession have contributed and may continue to contribute to economic uncertainty and diminished expectations for the global economy.

Although inflation in Australia had been relatively low for many years, inflation rose from 3.8% in June 2021 to a peak of 7.8% in December 2022 and then moderated to 5.4% in June 2023. In addition, inflation in the United States rose from 7.0% in December 2021 to a high of 9.1% in June 2022 and fell to 3.1% in November 2023. As a result, we experienced supply chain constraints and inflationary pressure on our cost structure throughout 2022 and 2023. Principally, commodity costs for steel and chemicals required for drilling, higher transportation and fuel costs and annual wage increases have increased our operating costs for fiscal year 2023 compared to fiscal year 2022. We cannot predict the future inflation rate but to the extent inflation remains elevated and supply chain constraints remain, we may experience cost increases in our operations, including costs for drill rigs, workover rigs, hydraulic fracturing fleets, tubulars and other well equipment, as well as increased labor costs. Some supply chain constraints and inflationary pressures could persist into 2024 but are expected to plateau, however we cannot accurately predict future supply chain constraints and inflation. If we are unable to manage our supply chain, our ability to procure materials and equipment in a timely and cost-effective manner, if at all, may be negatively impacted, which could materially adversely impact our results of operations and financial condition.

To mitigate supply chain and inflationary pressures, we have, for example, pre-purchased long lead materials including casing and tubulars, chemicals and downhole equipment necessary for our planned development for 2024. We have in place a 10-year option with H&P to contract for up to five additional FlexRigs^®. We are working closely with other suppliers and contractors to ensure availability of supplies on site, especially fuel, steel and chemical supplies which are critical to many of our operations and are working on diversifying suppliers. However, these mitigation efforts may not succeed or be insufficient.

Similarly, we cannot predict the impact that high market volatility and instability in the banking sector could have on economic activity and our business in particular. The failure of banks and financial institutions and measures taken, or not taken, by governments, businesses and other organizations in response to these events could adversely impact our business, financial conditions and results of operations.

 

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In addition, continued hostilities between Russia and Ukraine, the conflict between Israel and Hamas, other hostilities in the Middle East, and the occurrence or threat of terrorist attacks in Australia or other countries could adversely affect the economies of Australia and other countries. The ongoing conflict in Ukraine and Israel could continue to have repercussions globally by continuing to cause uncertainty, not only in the natural gas markets, but also in the capital markets. Such uncertainty could result in stock price volatility and supply chain disruptions, as well as higher natural gas prices which could potentially result in increased inflation worldwide and could negatively impact demand for natural gas, NGLs, oil and electricity.

Concerns about global economic growth can result in a significant adverse impact on global financial markets and commodity prices. In addition, any financial crisis may cause us to face limitations on our ability to access the debt and equity capital markets and complete asset purchases or sales.

Further, if there is a financial crisis or the economic climate in Australia or abroad deteriorates, worldwide demand for hydrocarbon-based products could materially decrease, which could impact the price at which natural gas from our properties are sold, affect the ability of vendors, suppliers and service providers associated with our properties to continue operations and ultimately materially adversely impact our results of operations, financial condition and ability to pay dividends on our common stock.

Events outside of our control, including an epidemic or outbreak of an infectious disease, terrorism, geopolitical instability, and security threats, could have a material adverse effect on our business, liquidity, financial condition, results of operations, and/or cash flows.

We face risks related to pandemics, epidemics, outbreaks or other public health events, or the threat thereof, that are outside of our control, and could significantly disrupt our business and operational plans and adversely affect our liquidity, financial condition, results of operations, cash flows and ability to pay dividends on our common stock.

The nature, scale and scope of the above-described events, combined with the uncertain duration and extent of governmental actions, prevent us from identifying all potential risks to our business. We believe that the known and potential impacts of pandemic-related events include, but are not limited to, the following:

 

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disruption in the demand for natural gas, NGLs and oil and other petroleum products;

 

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intentional project delays until commodity prices stabilize;

 

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a potential future downgrade of our credit rating and potentially higher borrowing costs in the future;

 

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a need to preserve liquidity, which could result in reductions, delays or changes in our capital expenditures;

 

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supply chain and shipping lane disruptions, resulting in shortages of, and increased pricing pressures on, among other things, equipment, services and labor;

 

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liabilities resulting from operational delays due to decreased productivity resulting from stay-at-home orders affecting our workforce or facility closures;

 

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future asset impairments, including impairment of our natural gas properties and other property and equipment; and

 

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infections and quarantining of our employees and the personnel of vendors, suppliers and other third parties.

A terrorist attack or armed conflict targeting our systems or natural gas infrastructure generally could materially adversely impact our operations.

Growing geopolitical instability and armed conflicts (including the armed conflict between Russia and Ukraine and between Israel and Hamas as well as other hostilities in the Middle East) has resulted in energy

 

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infrastructure becoming a more prominent target of attack by terrorists and conflicting countries. Natural gas, NGLs and oil related facilities, including those operated by us or our service providers, could be direct targets of physical or cyber-attacks, and, if infrastructure integral to our operations is destroyed or damaged, we may experience a significant disruption in our operations. Any such disruption could materially adversely affect our financial condition, results of operations and cash flows. Costs for insurance and other security may increase as a result of increased threats, and certain insurance coverage may become more difficult to obtain, if available at all.

Our business could be negatively affected by security threats and disruptions, including electronic, cybersecurity or physical security threats and other disruptions.

Our business faces various security threats, including cybersecurity threats to gain unauthorized access to sensitive information or to render data or systems unusable; threats to the security of our facilities and infrastructure or third-party facilities and infrastructure, such as processing plants and pipelines; and threats from terrorist acts. The potential for such security threats has subjected our operations to increased risks that could have a material adverse effect on our business. In particular, our implementation of various procedures and controls to monitor and mitigate security threats and to increase security for our information, facilities and infrastructure may result in increased capital and operating costs. Moreover, there can be no assurance that such procedures and controls will be sufficient to prevent security breaches from occurring. Security breaches could lead to losses of sensitive information, critical infrastructure or capabilities essential to our operations and could have a material adverse effect on our reputation, financial position, results of operations and cash flows. Cybersecurity attacks in particular are becoming more sophisticated and include, but are not limited to, malicious software, attempts to gain unauthorized access to data and systems and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information and corruption of data.

With the guidance of the Audit & Risk Management Committee, our Board is responsible for our risk management framework, including our strategy, policies, procedures and systems with respect to cybersecurity and information technology risks associated with us and our supply chain, suppliers and service providers. In relation to information technology and cybersecurity, an initial risk assessment was undertaken in early 2024 and the results are being compiled to present to the Audit & Risk Management Committee in mid-2024. As part of this risk assessment, we have recently completed our first cybersecurity maturity assessment using the Cybersecurity Framework developed by U.S. National Institute of Science and Technology and will shortly commence preparation of an organization cybersecurity policy including roles and responsibilities in relation to third parties, which are not yet defined.

However, although we plan to implement, and our third-party vendors and suppliers may implement, various controls, systems and processes intended to secure these information systems, there can be no assurance that our efforts to maintain the security and integrity of our information systems will be effective or that future attempted cybersecurity incidents, attacks, or disruptions would not be successful or damaging. These events could damage our reputation and lead to financial losses from remedial actions, loss of business or potential liability.

Loss of our information and computer systems could adversely affect our business.

We are heavily dependent on our information systems and computer-based programs, including our well operations information, seismic data, electronic data processing and accounting data. If any of such programs or systems were to fail or create erroneous information in our hardware or software network infrastructure, possible consequences include our loss of communication links, inability to find, produce, process and sell natural gas and inability to automatically process commercial transactions or engage in similar automated or computerized business activities. Any such consequence could have a material adverse effect on our business.

 

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We may be involved in legal proceedings that could result in substantial liabilities.

Like many energy companies, in the ordinary course of our business, we are from time to time involved in various disputes and disagreements that may lead to legal and other proceedings, such as title, royalty or contractual disputes, regulatory compliance matters, land access disputes, appeals and judicial reviews of regulatory approvals, personal injury or property damage matters. Such legal proceedings are inherently uncertain and their results cannot be predicted. Regardless of the outcome, such proceedings could have an adverse impact on us because of legal costs, diversion of management and other personnel and other factors. In addition, it is possible that a resolution of one or more such proceedings could result in liability, penalties or sanctions, as well as judgments, consent decrees or orders requiring a change in our business practices, which could materially and adversely affect our business, prospects, financial condition, results of operations, cash flows and ability to pay dividends on our common stock. Accruals for such liability, penalties or sanctions may be insufficient, and judgments and estimates to determine accruals or range of losses related to legal and other proceedings could materially change from one period to the next.

We are subject to risks related to corporate social responsibility, including the risk that our expectations or estimates regarding environmental, social and governance matters may not be achieved or may be incorrect.

Our business, as well as those of other companies, faces increasing public scrutiny related to ESG activities, which are increasingly considered to contribute to the long-term sustainability of a company’s performance.

We risk damage to our brand and reputation if we fail, or are perceived to fail, to act responsibly in a number of areas, such as environmental stewardship and corporate governance and transparency. Adverse incidents with respect to ESG activities could impact the value of our brand, the cost of our operations and relationships with investors, all of which could adversely affect our business and results of operations. For example, we have been in the past, and may in the future, be subject to claims of “greenwashing” (e.g., if our carbon footprint is alleged to be greater than what we claim, or if our ESG claims (including our claims in relation to our goals in respect of net zero equity Scope 1 and Scope 2 emissions) turn out to be false or misleading). Our expectations and estimates regarding ESG matters, including the potential environmental impact of our development and initiatives, may not be achieved or may ultimately prove to be incorrect, which may lead to additional claims or liability. The law in relation to false and misleading claims about ESG matters and statements about “net zero” emissions goals is evolving, and there continues to be risk that statements we have made could be deemed to be in breach of the Australian Consumer Law and other similar legislation in Australia or other jurisdictions. Breaches of these laws can result in significant financial penalties and other enforcement action.

Some of our ESG efforts may ultimately rely on the right to claim certain emissions offsets or other environmental attributes or to package such attributes with the natural gas we produce. This may be affected by evolving approaches to these matters, complex calculations or commercial agreements, and any disputes or ambiguities regarding such environmental attributes may negatively affect perceptions of our operations and products, subject us to litigation or stakeholder activism, require us to incur additional costs to procure replacement attributes, or otherwise adversely impact our operations.

We are also subject to evolving expectations on ESG matters from various stakeholders, including regulators, investors, customers, and business partners. For more information, see our risk factor titled “Increased attention to ESG matters and environmental conservation measures may adversely impact our business.”

 

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Risks Related to Environmental, Legal Compliance and Regulatory Matters

We are subject to complex federal, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations or expose us to significant liabilities.

Exploration and production activities in the oil and natural gas industry within Australia are subject to extensive local, state, federal and international laws and regulations. We may be required to make material expenditures to comply with governmental laws and regulations, particularly in respect of the following matters:

 

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approvals for drilling operations and other regulated activities;

 

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land access;

 

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royalties and royalty increases;

 

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drilling and development bonds;

 

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cost recovery for regulatory approvals;

 

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securities and orphan well levies;

 

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reports concerning operations;

 

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the spacing of wells;

 

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unitization of oil accumulations;

 

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tenure, landholders, native title holders and traditional Aboriginal owners;

 

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greenhouse gas emission targets and offset requirements;

 

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water extraction and disposal;

 

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remediation or investigation activities for environmental purposes; and

 

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taxation.

Under these and other laws and regulations, we could be liable for personal injuries, property damage and other types of damages, penalties, and costs. Accordingly, non-compliance may impact our ability to commercialize or retain its assets, which may in turn impact its operational and financial performance. Failure to comply with these laws and regulations also may result in the suspension or termination of our operations, loss of permits and subject us to administrative, civil and criminal penalties. Moreover, these laws and regulations could change in ways that could substantially increase our costs. Any such liabilities, penalties, suspensions, or terminations or regulatory changes could have a material adverse effect on our financial condition and results of operations.

Our business is affected by government policy, which in turn may be influenced by international policies and laws. While we consider the Federal Government’s current policy to be supportive of the investment and development of Australia’s natural gas resources, there is no guarantee that this stance will not change in the future. In particular, there is a risk that the Federal Government could shift its domestic or international policy. International policy developments have the potential to have an indirect impact on our operations, given that domestic policy makers might consider those developments in formulating and in setting the direction of local policy. For example, the International Energy Agency recently released a report in relation to its recommendations for a pathway to achieve global net zero emissions by 2050, and includes a key recommendation that no new oil and natural gas projects should be developed. It is unknown what impact the report might have, if any, on domestic policy development for natural gas. A shift in energy policy announced and adopted by the NT Government in relation to natural gas or the development of the Beetaloo would pose a similar risk. The NT Government had previously imposed a moratorium on the operations in the Beetaloo, which ended in 2018 following a scientific inquiry and certain recommendations.

 

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Shifts in government policy could have varying degrees of impact on our operations and its profitability and could range from loss or reduction in industry incentives, preventing infrastructure development to moratoriums on future natural gas development in specific areas or across the Beetaloo.

We must comply with relevant laws and regulations in each jurisdiction in which we operate as it applies to the environment, tenure, land access, landholders, native title holders and traditional Aboriginal owners. Non-compliance with these laws and regulations and any special license conditions could result in suspension of operations, loss of permits or financial penalties. Non-compliance may impact our ability to commercialize or retain our assets, which may in turn impact our operational and financial performance. The relevant environmental, tenure, land access, landholder, native title, land rights and cultural heritage laws and regulations applicable to our operations are described in “Business—Environmental Matters and Regulation.”

Changes to these requirements (including, for example, new requirements relating to climate change, environmental protection and energy policy, and the government of the Northern Territory’s commitment to implement the recommendations from the Final Report of The Scientific Inquiry into Hydraulic Fracturing) may restrict or affect our right or ability to conduct our activities.

Our exploration of the Beetaloo is dependent upon the maintenance (including renewal) of the relevant permits. Maintenance of the permits is dependent on, among other things, meeting the permit conditions imposed by the relevant authorities including compliance with work program and expenditure requirements. No assurance can be given that such title and access rights are not subject to unregistered, undetected or other claims or interests which could be materially adverse to our interests in the Beetaloo. Further titles or access rights may be disputed, which could result in costly litigation or disruption of the Company’s operations.

Our exploration and production operations are subject to various types of federal, state, territorial and local laws and regulations, and may be restricted or subject to conditions in relation to certain environmental features (such as watercourses or sites of conservation significance). Applicable law regulates the location of wells; the method of drilling, well construction, well stimulation, hydraulic fracturing and casing design; water withdrawal and procurement from designated aquifers for well stimulation purposes; well production; spill prevention plans; the use, transportation, storage and disposal of water and other fluids and materials, including solid and hazardous wastes, incidental to natural gas and oil operations; surface usage and the reclamation of properties upon which wells or other facilities have been located; the plugging and abandoning of wells; the calculation, reporting and disbursement of royalties and taxes; and the gathering of production in certain circumstances.

Our production operations are subject to the discovery of commercially exploitable petroleum and the discretion of the Minister to grant a production license. Specifically, we will only be entitled to apply for a production license once a commercially exploitable petroleum discovery is made. Further, the Minister may grant the production license subject to such conditions as the Minister determines to be appropriate at any time, the Minister may direct the holder of a production license to maintain, increase or reduce the rate of recovery of petroleum from the area. The grant of any future production license to the Company over areas that are subject to native title rights and interests or are Aboriginal land will require engagement with the relevant native title holders and land councils in accordance with the Native Title Act and the ALRA as relevant. Any delays or costs in engaging with the relevant native title holders in negotiating new arrangements in respect of a production license may adversely impact the Company’s ability to carry out petroleum extraction activities within the affected areas.

Our operations are also subject to the Petroleum Act, which allows for the unitization of a petroleum pool that extends beyond a license area but which is desirable for efficiency and avoiding wasteful and harmful development and practices.

Environmental and occupational health and safety laws and regulations govern discharges of substances into the air, ground and water; the management and disposal of hazardous substances and wastes; the clean-up of

 

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contaminated sites; groundwater quality and availability; plant and wildlife protection; locations available for drilling; environmental impact studies and assessments required for permitting; restoration of drilling properties upon completion of drilling activities; and work practices related to employee health and safety.

To conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. Complying with the laws, regulations and other legal requirements applicable to our business and any delays in obtaining related authorizations may affect the costs and timing of developing our natural gas resources. These requirements could also subject us to claims for personal injuries, property damage, penalties, costs and other damages. In addition, our costs of compliance may increase if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations. Such costs could materially adversely affect our results of operations, cash flows and financial position. Our failure to comply with the laws, regulations and other legal requirements applicable to our business, even as a result of factors beyond our control, could result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties and damages as well as corrective action costs.

We face community opposition from certain parties with respect to our development of the Beetaloo and related operations, which could result in significant costs and delays and could impede our ability to obtain the government approvals required for such operations.

We have been the target of protests and adverse publicity from certain parties due to concerns with environmental issues or Indigenous rights, and there is a risk from existing or future community opposition to our operations. For example, two pastoralists whose pastoral leases are subject, in part, to our petroleum interests refused to enter into access agreements for us to conduct certain regulated activities which require an access agreement, and we were required to make applications to the relevant tribunal to obtain access agreements for such regulated activities. Additionally, the Central Australian Frack Free Alliance has sought judicial review of the Minister’s decision to approve one of our environment management plans to conduct certain petroleum exploration activities. The matter is yet to be determined by the courts, but the courts’ decisions could result in a redetermination of the subject environment management plan.

Disapproval from local communities or other interested parties may lead to direct action that could impede our ability to carry out our operations, resulting in project delay, reputational damage and increased costs, and thus impact our financial performance. Such community opposition may include undertaking legal proceedings (including challenges to required governmental approvals), media campaigns and protests, which could result in significant legal costs and delays. If such community members were successful in their campaigns, we may not be able to obtain the permits and approvals we will need to carry out our commercial operations.

The exploration and development of natural gas in the Beetaloo can pose native title and heritage risks, potentially leading to legal disputes, operational disruptions, and reputational damage.

We are required to comply with the Native Title Act 1993 (Cth) and we operate on areas in which native title has been judicially determined to exist. Consultation and negotiations have occurred, leading to exploration agreements. Further agreements will be required for any production phase, but the exploration agreements anticipate production and provide the parameters for those negotiations and outcomes. We will also be required to comply with the Aboriginal Land Rights (Northern Territory) Act 1976 (Cth) (“ALRA”) for tenement applications over Aboriginal land (i.e., freehold land held by an Aboriginal Land Trust under the ALRA, or land subject to a deed of grant held in escrow by an Aboriginal Land Council under the ALRA). Compliance with either legislative regime and their respective requirements for negotiation and agreement can significantly delay the grant of exploration and production tenements, and substantial compensation may be payable as part of any agreement reached. Applications for exploration tenements over Aboriginal land can also be placed into moratorium for five years at a time under the ALRA (unless the Governor-General of Australia declares by proclamation that the Australian national interest requires that the license be granted). These legislative regimes

 

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may impact our existing or future activities, ability to develop projects and operational and financial performance.

In addition, we will also need to comply with the Northern Territory Aboriginal Sacred Sites Act 1989 (NT) (“SSA”), the Heritage Act 2011 (NT), the Aboriginal and Torres Strait Islander Heritage Protection Act 1984 (Cth) and the ALRA in relation to sacred sites and certain Aboriginal cultural heritage. Sacred sites and Aboriginal cultural heritage have been identified within areas covered by the tenements in which we have an interest, and other such sites may exist. It is an offense under Part IV of the SSA to enter onto or remain on, carry out work on or use, or desecrate a sacred site without authority. All Sacred Sites are protected under the SSA, regardless of whether or not they are included on the register maintained under the SSA. Destruction, disturbance or harming protected sites and artifacts may result in us incurring significant civil and/or criminal penalties, which may adversely impact or delay our activities. In addition, in the event of damage to sacred sites and Aboriginal cultural heritage, remediation costs may be substantive. Compliance with these laws requires significant expenditure and non-compliance may potentially result in fines and requests for improvement action from the regulator all of which may result in limitations on actions and project delays or cost overruns.

Upon commencement of commercial production, we are required by the Australian government to produce natural gas in the Beetaloo on a Scope 1 net zero basis. We also have set an internal goal of producing natural gas with net zero equity Scope 1 and 2 emissions. Meeting these requirements and goals may increase our costs of production, and we may be unable to meet these requirements and goals.

Australian law requires that, upon commencement of commercial production and reaching the relevant threshold of 100,000 t-CO₂-e emissions per financial year, we produce natural gas in the Beetaloo on a Scope 1 net zero basis. We also have set an internal goal of producing natural gas with net zero equity Scope 1 and 2 emissions. To achieve this, we intend to utilize renewables to supply our upstream operation power needs and integrate carbon capture and sequestration with our upstream production activities as well as purchase carbon credits as required, however there is no guarantee we will achieve such plans. If we are unable to utilize renewables to supply our upstream operation power needs and integrate carbon capture and sequestration with our upstream production activities to the extent we currently expect, if the price of carbon credits increases or if we have otherwise underestimated the amount of Scope 1 or Scope 2 emissions that we will need offset, then our costs of production will increase further which could have a material adverse effect on our results of operations.

We may not achieve, and there are potential risks associated with, our growth strategy and vision to become a net zero equity emissions producer for our equity share of Scope 1 and Scope 2 emissions. Achievement of our vision of becoming a net zero equity emissions producer of gas is presently uncertain and depends on us being able to economically manage our carbon emissions, which could, for example, be impacted by availability of future revenues to fund various carbon initiatives, market pricing of carbon offsets, technological developments affecting operations and costs of implementing sustainable practices. Failure, or perceived failure, to meet these or other goals or commitments regarding the ESG characteristics of our offerings may subject us to litigation or stakeholder activism (which may be costly) or otherwise adversely impact our business. For more information, see our risk factor titled “We are subject to risks related to corporate social responsibility, including the risk that our expectations or estimates regarding environmental, social and governance matters may not be achieved or may be incorrect.”

Increased attention to ESG matters and environmental conservation measures may adversely impact our business.

Increasing investor and societal attention to climate change and ESG, rising expectations for companies to address climate change and develop voluntary ESG initiatives, and growing consumer demand for alternative forms of energy may result in increased costs (including but not limited to increased costs related to compliance, stakeholder engagement, contracting and insurance), reduced demand for our products, reduced profits, increased investigations and litigation and negative impacts on our access to capital markets. Increasing attention to climate

 

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change, environmental justice and environmental conservation, for example, may result in demand shifts for natural gas products and additional governmental investigations and private litigation against us. To the extent that societal, political, or other factors are involved, including factors associated with geopolitical considerations, it is possible that we could be subject to changing market conditions, liability, or loss of certain assets without regard to our ultimate role in the causation of or contribution to the asserted events or damages, or to other mitigating factors.

Opposition toward natural gas drilling and development activity has been growing globally. Companies in the natural gas industry are often the target of activist efforts from both individuals and non-governmental organizations regarding safety, environmental compliance and business practices. Anti-development activists are working to, among other things, reduce access to federal and state government lands and delay or cancel certain projects such as the development of natural gas shale plays.

While we have in the past engaged in, and expect in the future to continue to engage in, voluntary initiatives (such as voluntary disclosures, certifications, or goals, among others) to improve the ESG profile of our company and/or products or to respond to stakeholder expectations, such initiatives may be costly and may not have the desired effect. For example, we may ultimately be unable to complete certain initiatives or targets, either on the timelines initially announced or at all, due to technological or legal cost, or other constraints, which may be within or outside of our control. In some cases, our statements or actions are based on hypothetical expectations and assumptions that may or may not be representative of current or actual risks or events or forecasts of expected risks or events, including the costs associated therewith. Such expectations and assumptions are necessarily uncertain and may be prone to error or subject to misinterpretation given the long timelines involved and the lack of an established single approach to identifying, measuring and reporting on many ESG matters. Such disclosures may also be at least partially reliant on third-party information that we have not verified, or cannot verify, independently.

Our actions or statements based on expectations, assumptions or third-party information may subsequently be determined to be erroneous, unreasonable, or otherwise inappropriate. If we fail to, or are perceived to fail to, comply with or advance certain ESG initiatives (including the timeline and manner in which we complete such initiatives), we may be subject to various adverse impacts, including reputational damage and potential stakeholder engagement and/or litigation, even if such initiatives are currently voluntary. For example, there have been increasing allegations of greenwashing against companies making significant ESG claims due to a variety of perceived deficiencies in performance, including as stakeholder perceptions of sustainability continue to evolve.

In addition, we expect there will likely be increasing levels of regulation, disclosure-related and otherwise, with respect to ESG matters. For example, various policymakers, such as the SEC and the Australian Treasury, have adopted, or are considering adopting, rules to require companies to provide significantly expanded climate-related disclosures in their periodic reporting, which may require us to incur significant additional costs to comply, including the implementation of significant additional internal controls, processes and procedures regarding matters that have not been subject to such controls in the past, and impose increased oversight obligations on our management and board of directors. Simultaneously, there are efforts by some stakeholders to reduce companies’ efforts on certain ESG-related matters. Both advocates and opponents to certain ESG matters are increasingly resorting to a range of activism forms, including media campaigns and litigation, to advance their perspectives. To the extent we are subject to such activism, it may require us to incur costs or otherwise adversely impact our business. In addition, we note that standards and expectations regarding carbon accounting and the processes for measuring and counting GHG emissions and GHG emission reductions are evolving, and it is possible that our approach to measuring both our emissions and our approaches to reduce emissions may be, either currently or in the future, considered inconsistent with common or best practices with respect to measuring and accounting for such matters, reducing overall emissions and/or achieving “net zero.” If our approaches to such matters fall out of step with common or best practice, we may be subject to additional scrutiny, criticism, regulatory and investor engagement or litigation, any of which may adversely impact our business, financial

 

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condition or results of operations. This and other stakeholder expectations will likely lead to increased compliance costs as well as scrutiny that could heighten all of the risks identified in this risk factor.

Organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG matters. Such ratings are used by some investors to inform their investment and voting decisions. Unfavorable ESG ratings and recent activism directed at shifting funding away from companies with fossil fuel-related assets could lead to increased negative investor sentiment toward us and our industry and to the diversion of investment to other industries, which could have a negative impact on our access to and costs of capital. Also, institutional lenders may decide not to provide funding for fossil fuel energy companies based on climate change and natural capital related concerns, which could affect our access to capital for potential growth projects. Moreover, to the extent ESG matters negatively impact our reputation, we may not be able to compete as effectively to recruit or retain employees, customers, or business partners. Such ESG matters may also impact our suppliers or service providers, which may adversely impact our business, financial condition, or results of operations.

Federal and local legislative and regulatory initiatives relating to hydraulic fracturing as well as governmental reviews of such activities could result in increased costs and additional operating restrictions or delays in the completion of natural gas wells and adversely affect our production.

Public debate exists regarding the potential sub surface and surface impact of unconventional drilling, including concern about the impacts of unconventional drilling water. In addition, there are many regulatory requirements for us to adhere to including, but not limited to, those specified in the Petroleum Act, Petroleum Regulations (NT), Petroleum (Environment) Regulations 2016 (NT), Water Act (NT), Environment Protection Act 2019 (NT), Environment Protection and Biodiversity Conservation Act 1999 (Cth) and the Work Health and Safety (National Uniform Legislation) Act (NT) and Work Health and Safety (National Uniform Legislation) Regulations (NT). Unconventional drilling requires large volumes of water (the availability and regulation of which may change over time) and there are costs associated with water disposal that may be required should we produce water in our wells. As more impacts of unconventional drilling are fully understood, it may be subject to additional regulations or restrictions from local, state, or federal governmental authorities, resulting in increased compliance costs. Any modification to the current requirements may adversely impact the value of our assets and future financial performance.

For example, on April 17, 2018, the NT Government announced that it accepted all 135 of the recommendations set out in the ‘The Scientific Inquiry into Hydraulic Fracturing in the Northern Territory’ (Fracking Inquiry Report). The implementation of the recommendations has resulted in a more rigorous regulatory regime by placing additional obligations on oil and natural gas companies including the introduction of a stricter code of practice for decommissioning onshore shale gas wells, requiring tenement holders to provide a non-refundable levy prior to granting any further production approvals and introducing no go zones where a person cannot explore or drill for petroleum resources.

A number of the recommendations may affect the Company’s tenements. In particular, some key recommendations include but are not limited to: (a) decommissioning wells to implement a stricter code of practice setting out the minimum requirements for the decommissioning of onshore shale natural gas wells in respect of cement integrity tests, the repair of defects prior to abandonment, and cement plugs to be placed to isolate critical formations; (b) objections to allow for any person to object to the proposed grant of an EP; (c) compensation to landowners, a land access agreement must be negotiated and signed by the pastoral lessee and the natural gas company; (d) accountable industry practice to allow for the NT Government to develop and implement a financial assurance framework for the onshore shale natural gas industry prior to the grant of any further production approvals; (e) non-refundable levy for appropriate monitoring and remediation activities; (f) merits review to allow for a range of third parties to have standing to seek merits review in relation to decisions under the petroleum statue and regulations prior to the granting of production approvals; and

 

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(g) reserved blocks or no go zones, where certain areas must be declared reserved blocks (areas where a person cannot explore or drill for petroleum resources), each with an appropriate buffer zone.

Our operations are subject to risks relating to climate change that could increase compliance or operating costs, limit natural gas exploration and production areas, and reduce demand for the natural gas we produce.

Climate change continues to attract considerable public and scientific attention. As a result, numerous proposals have been adopted, been considered for adoption, and are likely to continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of carbon dioxide, methane and other GHGs. These efforts have included consideration of cap-and-trade programs, carbon taxes, GHG reporting and tracking programs and regulations that directly limit GHG emissions from certain sources. As a natural gas development company, we are exposed to both transition risks and physical risks associated with climate change. Transitioning to a lower-carbon economy may entail extensive policy, legal, technology and market changes and, if demand for gas declines, we will find it difficult to commercialize any resources we discover.

The transition and physical risks associated with climate change (including also regulatory responses to such issues and associated costs) may significantly affect our operating and financial performance. For example, the Australian government announced its policy to target net zero carbon emissions economy-wide by 2050. In connection with that announcement, the Australian government designated that shale natural gas facilities in the Beetaloo that exceed the relevant threshold of 100,000 gross tonnes of CO₂e emissions per financial year will be given a “Zero” GHG baseline. Accordingly, once a natural gas producer has exceeded the 100,000 gross t-CO2e Scope 1 threshold, the Company must demonstrate that it has achieved Scope 1 net zero emissions, either through operational measures (such as carbon capture and storage) or by purchasing carbon offsets. Various policymakers have also adopted, or are considering adopting, rules to require companies to provide significantly expanded climate-related disclosures. For more information, see our risk factor titled “Increased attention to ESG matters and environmental conservation measures may adversely impact our business.” In addition, the increased frequency or severity of natural disasters and weather events due to climate change could delay or prevent our ability to conduct our activities, which could negatively impact our financial performance.

Increasing attention to global climate change has resulted in increased risk of public and private litigation, which could increase our costs or otherwise adversely affect our business. A number of parties have sought to bring suit against oil and natural gas companies in state or federal court, alleging, among other things, that such companies contributed to climate impacts by producing, handling or marketing fossil fuels, or violate citizens’ rights by contributing to climate change, or alleging that companies have been aware of the adverse effects of climate change for some time but failed to adequately disclose those impacts. In some jurisdictions, litigation has also been brought to establish legal mandates for particular entities to take certain climate-related actions, such as pursuing aggressive emissions reductions for their Scope 3 emissions reductions, regardless of whether entities have established any such goals already. The ultimate outcome and impact to us of any such litigation cannot be predicted with certainty, and we could incur substantial legal costs associated with defending these and similar lawsuits in the future. Shareholder activism related to climate change has also recently been increasing in our industry, and shareholders may attempt to effect changes to our business or governance, whether by stockholder proposals, public campaigns, proxy solicitations or otherwise. Any of these risks could result in unexpected costs, negative sentiments about us, disruptions in our operations, increases to our operating expenses and reduced demand for our products, which in turn could have an adverse effect on our business, financial condition and results of operations.

There are also increasing financial risks for fossil fuel producers as various capital providers may elect in the future to shift some or all of their investments into non-fossil fuel energy related sectors. Many capital providers have also incorporated more substantial assessments of climate-related matters into their funding considerations, including how such funding may impact such capital providers’ own Scope 3 emissions, and may elect not to provide, or to continue not to provide, funding to fossil fuel energy companies. For example, at

 

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COP26, the Glasgow Financial Alliance for Net Zero (“GFANZ”) announced that commitments from over 650 firms across over 50 countries had capital committed to net zero goals. The various sub-alliances of GFANZ generally require participants to set short-term, sector-specific targets to transition their financing, investing, and/or underwriting activities to net zero emissions by 2050. There is also a risk that financial institutions will be required to adopt policies that have the effect of reducing the funding provided to the fossil fuel sector. Limitation of investments in and financings for fossil fuel energy companies could result in the restriction, delay or cancellation of drilling programs or development or production activities.

Significant physical effects of climatic change have the potential to damage our facilities, disrupt our production activities and cause us to incur significant costs in preparing for or responding to those effects. Climate change could have an effect on the frequency or severity of weather events (including hurricanes, wildfires, droughts and floods), sea levels, the arability of farmland, changes in temperature and other meteorological patterns, and water availability and quality. If such effects were to occur, our development and production operations have the potential to be adversely affected. Potential adverse effects could include damages to our facilities from powerful winds or rising waters in low lying areas, disruption of our production activities either because of climate related damages to our facilities or in our costs of operation potentially arising from such climatic effects, less efficient or non-routine operating practices necessitated by climate effects or increased costs (or decreased availability) for insurance coverage in the aftermath of such effects. Additionally, in response to changing climatic conditions, certain policymakers have proposed increased restrictions on the withdrawal and use of water for fossil fuel production or other industrial uses, which may either delay or prohibit our access to certain bodies of water; to the extent we do not have sufficient local water sources available, we may be required to incur substantial costs or curtail operations, which may become more significant in periods of drought or other water scarcity. Significant physical effects of climate change could also have an indirect effect on our financing and operations by disrupting the transportation or process-related services provided by midstream companies, service companies or suppliers with whom we have a business relationship. We may not be able to recover through insurance some or any of the damages, losses or costs that may result from potential physical effects of climate change. While we may take various actions to mitigate our business risks associated with climate change, this may require us to incur substantial costs and may not be successful, due to, among other things, the uncertainty associated with the longer-term projections associated with managing climate risks.

Our ability to pursue our business strategies may be adversely affected if we incur costs and liabilities due to a failure to comply with environmental, health and safety laws or regulations or a release into the environment.

Despite efforts to conduct activities in an environmentally responsible manner and in accordance with applicable laws, there is a risk that gas activities may cause harm to the environment which could impact production or delay future development timetables.

We are subject to laws and regulations to minimize the environmental impact of our operations and rehabilitation of any areas affected by our operations. Changes to environmental laws may result in the cessation or reduction of our activities, materially increase development or production costs or otherwise adversely impact our operations, financial performance or prospects. Penalties for failure to adhere to requirements and, in the event of environmental damage, remediation costs can be substantial and may not, in their entirety, be insurable. Compliance with these laws requires significant expenditure and non-compliance may potentially result in fines or requests for improvement action from the regulator.

In addition, if we were to be held responsible for environmental damage, in addition to remediation costs, we may suffer reputational damage, possible suspension or cessation of operations, revocation of permits or financial penalties.

We may incur significant costs and liabilities as a result of environmental, health and safety laws and regulations applicable to the operation of our wells, gathering systems and other facilities including, for example,

 

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the following laws, as amended from time to time. Further details of these legislative instruments are described in the section entitled “Business—Environmental Matters and Regulation”:

 

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Petroleum Act 1984 (NT);

 

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Petroleum Regulations 2020 (NT);

 

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Petroleum (Environment) Regulations 2016 (NT);

 

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Water Act 1992 (NT);

 

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Environment Protection Act 2019 (NT);

 

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Environment Protection and Biodiversity Conservation Act 1999 (Cth);

 

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Northern Territory Aboriginal Sacred Sites Act 1989 (NT);

 

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Heritage Act 2011 (NT);

 

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Aboriginal and Torres Strait Islander Heritage Protection Act 1984 (Cth);

 

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Native Title Act 1993 (Cth);

 

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Aboriginal Land Rights (Northern Territory) Act 1976 (NT);

 

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The National Greenhouse and Energy Reporting Act 2007 (Cth); and

 

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Work Health and Safety (National Uniform Legislation) Act 2011 (NT).

These laws and their implementing regulations, as well as state counterparts, generally restrict the level of pollutants emitted to ambient air, discharges to surface water and disposals or other releases or threats of release to surface, soils and groundwater. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil and criminal penalties, the imposition of investigatory, remedial and corrective action obligations, the incurrence of capital expenditures, the occurrence of delays in the permitting, development or expansion of projects and the issuance of orders enjoining some or all of our future operations in a particular area. Certain environmental laws impose strict joint and several liability, without regard to fault or legality of conduct, for costs required to clean up and restore sites where hazardous substances or other wastes have been disposed of or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, wastes or other materials into the environment. In addition, these laws and regulations may restrict the rate of natural gas production or underground injection, disposal, and sequestration of carbon dioxide. Historically, our environmental compliance costs have not had a material adverse effect on our results of operations; however, there can be no assurance that such costs will not be material in the future or that such future compliance will not have a material adverse effect on our business and operating results.

In addition, as a result of these environmental, health and safety laws and regulations, and their impact on our operations, we rely on specialized contracted companies to perform the majority of the specialized services inherent in the oil and natural gas industry. As such, we rely on the ability of these contractors to provide trained labor and properly designed and maintained equipment unique to their services. With the cyclical nature of the oil and natural gas business, the personnel used by these specialized contractors to perform these services may differ significantly in experience levels. From time to time, these specialized contractors may use new personnel that are still in training or may further sub-contract these services to other companies or personnel. There is a risk that these sub-contractors are unqualified or under-trained or that their equipment is not properly designed or maintained, which could result in work being performed inadequately or unsafely.

Moreover, public interest in the protection of the environment has increased dramatically in recent years. The trend of more expansive and stringent environmental legislation and regulations applied to the oil and natural gas industry could continue, resulting in increased costs of doing business and consequently affecting profitability. To the extent laws are enacted or other governmental action is taken that restricts drilling or

 

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production or imposes more stringent and costly operating, waste handling, disposal and cleanup requirements, our business, prospects, financial condition or results of operations could be materially adversely affected.

Our future gathering systems and processing, treating and fractionation facilities will be subject to regulation by the Northern Territory that could have a material adverse effect on our operations and cash flows.

NT Government regulation of gathering systems and processing, treating and fractionation facilities includes safety and environmental requirements. In addition, several of our future gas gathering systems will be subject to non-discriminatory take requirements and complaint-based regulation with respect to our rates and terms and conditions of service. Northern Territory regulation may cause us to incur additional costs or limit our operations, any or all of which could have a material adverse effect on our operations and revenue.

We may face unanticipated water and other waste disposal costs as a result of increased water-related regulations.

We may be subject to regulation that restricts our ability to discharge water produced as part of our natural gas production operations. Productive zones frequently contain water that must be removed for the natural gas to produce, and our ability to remove and dispose of sufficient quantities of water from the various zones will determine whether we can produce natural gas in commercial quantities. The produced water must be transported from the leasehold and/or injected into disposal wells. The availability of disposal wells with sufficient capacity to receive all of the water produced from our wells may affect our ability to produce our wells. Also, the cost to transport and dispose of that water, including the cost of complying with regulations concerning water disposal, may reduce our profitability. Where water produced from our projects fails to meet the quality requirements of applicable regulatory agencies, our wells produce water in excess of the applicable volumetric permit limits, the disposal wells fail to meet the requirements of applicable regulatory agencies, or we are unable to secure access to disposal wells with sufficient capacity to accept all of the produced water, we may have to shut in wells, reduce drilling activities, or upgrade facilities for water handling or treatment. The costs to dispose of this produced water may increase if any of the following occur:

 

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we cannot obtain future permits from applicable regulatory agencies; water of lesser quality or requiring additional treatment is produced;

 

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our wells produce excess water;

 

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new laws and regulations require water to be disposed in a different manner; or

 

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costs to transport the produced water to the disposal wells increase.

Restrictions on drilling, completion, production or related activities intended to protect certain species of wildlife may adversely affect our ability to conduct drilling activities in some of the areas where we operate.

Natural gas operations in our operating areas can be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife, such as those restrictions imposed under the Environment Protection Act 2019 (NT) or Environment Protection and Biodiversity Conservation Act 1999 (Cth) (the “EPBC Act”). Seasonal restrictions may limit our ability to operate in certain protected areas and can intensify competition for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages when drilling is allowed. These constraints and the resulting shortages or high costs could delay our operations and materially increase our operating and capital costs. Permanent restrictions imposed to protect endangered species could prohibit drilling in certain areas or require the implementation of expensive mitigation measures. The designation of previously unprotected species in areas where we operate as threatened or endangered could cause us to incur increased costs arising from species protection measures or could result in limitations on our exploration, development and production activities that could have an adverse impact on our ability to develop and produce our reserves. To the extent species are listed or re-designated under

 

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the EPBC Act, or previously unprotected species are designated as threatened or endangered in areas where our properties are located, operations on those properties could incur increased costs arising from species protection measures and face delays or limitations with respect to production activities thereon. There is also increasing interest in nature-related matters beyond protected species, such as general biodiversity, which may similarly require us to incur costs or take other measures which may materially impact our business or operations.

Our business is subject to complex and evolving laws and regulations regarding privacy and data protection.

The regulatory environment surrounding data privacy and protection is constantly evolving and can be subject to significant change. New laws and regulations governing data privacy and the unauthorized disclosure of personal or confidential information pose increasingly complex compliance challenges and could potentially elevate our costs. Any failure to comply with these laws and regulations could result in significant penalties and legal liability. We continue to monitor and assess the impact of these laws, which in addition to penalties and legal liability, could impose significant costs for investigations and compliance, require us to change our business practices and carry significant potential liability for our business should we fail to comply with any such applicable laws.

Risks Related to our Corporate Structure

We are a holding company. Our sole material asset is our equity interest in TR Ltd. and we will be accordingly dependent upon distributions from TR Ltd. to pay taxes and cover our corporate and other overhead expenses.

We are a holding company and have no material assets other than our equity interest in TR Ltd. See “Corporate Reorganization.” We have no independent means of generating revenues. To the extent TR Ltd. has available cash, we intend to cause TR Ltd. to make distributions to us, in an amount at least sufficient to allow us to pay our taxes and reimburse us for our corporate and other overhead expenses. We may be limited, however, in our ability to cause TR Ltd. and its subsidiaries to make these and other distributions or payments to us due to certain limitations, including the cash requirements and financial condition of TR Ltd. and restrictions in any relevant debt instruments entered into by TR Ltd. or its subsidiaries and/other entities in which it directly or indirectly holds an equity interest. To the extent that we need funds and TR Ltd. or its subsidiaries are restricted from making such distributions or payments under applicable laws or regulations or under the terms of any future financing arrangements, or are otherwise unable to provide such funds, our liquidity and financial condition could be materially adversely affected.

The unaudited financial information included in this prospectus is preliminary and the actual financial condition and results of operations may differ materially.

The unaudited financial information included in this prospectus is presented for illustrative purposes only and is not necessarily indicative of what our actual financial position or results of operations would be. The preparation of the financial information is based upon available information and certain assumptions and estimates that we believe are reasonable. The unaudited condensed financial information does not consider any impacts of integration costs, potential revenue enhancements, anticipated cost savings and expense efficiencies, or other synergies that may or may not result from the corporate reorganization or any strategies that management may consider in order to continue to efficiently manage our operations. See “Selected Consolidated Financial Data” for more information.

We may be unable to achieve some or all of the benefits that we expect to achieve from the corporate reorganization, which could materially adversely affect our business, financial condition and results of operations.

We may not be able to achieve the full strategic and financial benefits expected to result from the corporate reorganization, or such benefits may be delayed or not occur at all. We may not achieve these and other

 

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anticipated benefits for a variety of reasons, including, among others, because we may experience unanticipated competitive developments, including changes in the conditions of industry and the markets in which we operate, including fluctuations in the prices of natural gas that could negate some or all of the expected benefits from the corporate reorganization.

If we do not realize some or all of the benefits expected to result from the corporate reorganization, or if such benefits are delayed, our business, expected future financial and operating results and our prospects could be adversely affected.

Risks Related to the Offering, our Common Stock and our CDIs

The requirements of being a public company, including compliance with the reporting requirements of the ASX listing rules and the Exchange Act, and the requirements of the SOX, may strain our resources, increase our costs and distract management, and we may be unable to comply with these requirements in a timely or cost-effective manner.

As our CDIs are publicly traded in Australia and our common stock will be publicly traded in the United States, we will need to comply with new laws, regulations and requirements, certain corporate governance provisions of SOX, related regulations of the SEC and the requirements of the ASX and NYSE, with which we were not required to comply as an unlisted or private company. Complying with these statutes, regulations and requirements will occupy a significant amount of our time and will significantly increase our costs and expenses. We will need to:

 

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institute a more comprehensive compliance function to test and conclude on the sufficiency of our internal controls around financial reporting;

 

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comply with rules promulgated by the ASX and the NYSE;

 

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prepare and distribute periodic public reports;

 

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establish new internal policies, such as those relating to insider trading; and

 

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involve and retain to a greater degree outside professionals in the above activities.

Furthermore, while we generally must comply with Section 404 of the SOX, we are not required to have our independent registered public accounting firm attest to the effectiveness of our internal controls until our first annual report subsequent to our ceasing to be an “emerging growth company.” We may not be required to have our independent registered public accounting firm attest to the effectiveness of our internal controls until as late as our annual report for the fiscal year ending June 30, 2029. At any time, we may conclude that our internal controls, once tested, are not operating as designed or that the system of internal controls does not address all relevant financial statement risks. Once required to attest to control effectiveness, our independent registered public accounting firm may issue a report that concludes it does not believe our internal controls over financial reporting are effective. Compliance with SOX requirements may strain our resources, increase our costs and distract management; and we may be unable to comply with these requirements in a timely or cost-effective manner.

If, however, we do not follow those procedures and policies, or they are not sufficient to prevent non-compliance, we could be subject to liability, fines and lawsuits. These laws, regulations and standards are subject to varying interpretations and, as a result, their application in practice may evolve over time as new guidance is provided by regulatory and governing bodies. We intend to invest resources to comply with evolving laws, regulations and standards, and this investment may result in increased general and administrative expenses and a diversion of management’s time and attention from revenue generating activities to compliance activities. If, notwithstanding our efforts to comply with new laws, regulations and standards, we fail to comply, regulatory authorities may initiate legal proceedings against us and our business may be harmed.

 

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The initial public offering price of our common stock in the United States may not be indicative of the market price of our common stock after this offering on the NYSE. In addition, an active, liquid and orderly trading market for our CDIs on the ASX and common stock on the NYSE may not develop or be maintained, and our stock price may be volatile.

Prior to this offering, our common stock was not traded on the NYSE or any other U.S. market (only CDIs since December 13, 2023, and before that ordinary shares of TR Ltd. were traded on the ASX). An active, liquid and orderly trading market for our common stock may not develop or be maintained after this offering. Active, liquid and orderly trading markets usually result in less price volatility and more efficiency in carrying out investors’ purchase and sale orders. The market price of our CDIs and common stock could vary significantly as a result of a number of factors, some of which are beyond our control. In the event of a drop in the market price of our CDIs and common stock, you could lose a substantial part or all of your investment in our CDIs or common stock. The initial public offering price will be negotiated between us and representatives of the underwriters, based on numerous factors which we discuss in “Underwriting,” and may not be indicative of the market price of our CDIs or common stock after this offering. Consequently, you may not be able to sell shares of our common stock at prices equal to or greater than the price paid by you in this offering.

The following factors could affect our stock price:

 

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our operating and financial performance and drilling locations, including reserve estimates;

 

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quarterly variations in the rate of growth of our financial indicators, such as net income per share, net income and revenues;

 

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the public reaction to our press releases, our other public announcements and our filings with the ASX and the SEC;

 

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strategic actions by our competitors;

 

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changes in revenue or earnings estimates, or changes in recommendations or withdrawal of research coverage, by equity research analysts;

 

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speculation in the press or investment community;

 

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the failure of research analysts to cover our CDIs or common stock;

 

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sales of our CDIs or common stock by us or our stockholders, or the perception that such sales may occur;

 

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changes in accounting principles, policies, guidance, interpretations or standards;

 

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additions or departures of key management personnel;

 

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actions by our stockholders;

 

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announcements or events that impact our assets, competitors or markets;

 

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general market conditions, including fluctuations in commodity prices;

 

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domestic and international economic, legal and regulatory factors unrelated to our performance; and

 

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the realization of any risks described under this “Risk Factors” section.

The stock markets in general have experienced extreme volatility that has often been unrelated to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of our CDIs and common stock. Securities class action litigation has often been instituted against companies following periods of volatility in the overall market and in the market price of a company’s securities. Such litigation, if instituted against us, could result in very substantial costs, divert our management’s attention and resources and harm our business, operating results and financial condition.

 

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Changes in foreign currency exchange rates could materially adversely affect our business, results of operations or financial condition.

In our operations, there are transactions and balances denominated in currencies other than the U.S. dollar (which is the currency used to report our results of operations and financial condition in our financial statements), consisting primarily of the Australian dollar. To the extent our assets and liabilities denominated in Australian dollars as of March 31, 2024 are not hedged, we estimate that a 5% change in the exchange rate versus the U.S. dollar would expose us to foreign currency gains or losses of $10.7 million.

In addition, all of our facilities are located in Australia, a majority of our officers and employees are residents in Australia and substantially all of our expenses are payable in Australian dollars. In the event that the U.S. dollar weakens compared with the Australian dollar, our results of operations or financial condition may be adversely affected, perhaps substantially.

We have engaged in transactions with our affiliates and expect to do so in the future. The terms of such transactions and the resolution of any conflicts that may arise may not always be in our or our stockholders’ best interests.

We have engaged in transactions and expect to continue to engage in transactions with affiliated companies. Related party transactions can create the possibility of conflicts of interest with regard to our management. Such a conflict could cause an individual in our management to seek to advance his or her economic interests above ours. Further, the appearance of conflicts of interest created by related party transactions could impair the confidence of our investors. Once established, our Audit & Risk Management Committee will review related party transactions in accordance with our related party transaction policy; however, review of related party transactions by our Audit & Risk Management Committee does not mean such transactions will have the expected benefits and, as such, could have an adverse impact on our financial condition or results of operations.

Certain of our affiliates are participants in joint ventures or may have other rights with respect to properties in which we have interests. For instance, Daly Waters, which is controlled by Bryan Sheffield, is an equal owner of TB1 that owns our interests in EPs 76, 98 and 117. Certain actions, such as a sale of property or incurrence of indebtedness, will require the approval of Daly Waters or its representatives on the board of TB1. In addition, we have granted Daly Waters Royalty, which is controlled by Bryan Sheffield, and certain of our directors ORRIs in certain of the permits we have interests in. See “Certain Relationships and Related Party Transactions” and “Business—Our Assets within the Beetaloo.”

Our certificate of incorporation and bylaws, as well as Delaware law, contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our CDIs and common stock.

Our certificate of incorporation authorizes our board of directors to issue preferred stock without stockholder approval. If our board of directors elects to issue preferred stock, it could be more difficult for a third-party to acquire us. In addition, some provisions of our certificate of incorporation and bylaws could make it more difficult for a third-party to acquire control of us, even if the change of control would be beneficial to our stockholders, including:

 

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limitations on the removal of directors;

 

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our classified board of directors with directors serving staggered three-year terms;

 

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limitations on the ability of our stockholders to call special meetings;

 

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establishing advance notice provisions for stockholder proposals and nominations for elections to the board of directors to be acted upon at meetings of stockholders;

 

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the requirement that the affirmative vote of the holders of at least 662⁄3% in voting power of all the then-outstanding shares of our stock be obtained to amend and restate our existing bylaws or to remove directors;

 

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the requirement that the affirmative vote of the holders of at least 662⁄3% in voting power of all the then-outstanding shares of our stock be obtained to amend our certificate of incorporation;

 

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providing that the board of directors is expressly authorized to adopt, or to alter or repeal our bylaws; and

 

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establishing advance notice and certain information requirements for nominations for election to our board of directors or for proposing matters that can be acted upon by stockholders at stockholder meetings.

Our certificate of incorporation designates the Court of Chancery of the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our stockholders, which could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, employees or agents.

Our certificate of incorporation provides that, to the fullest extent permitted by law, and unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware (or, in the event that the Chancery Court does not have jurisdiction, the Superior Court of the State of Delaware (Complex Commercial Litigation Division) or the federal district court for the District of Delaware) will be the sole and exclusive forum for any claims that (i) are based upon a violation of a duty by a current or former director or officer or stockholder in such capacity or (ii) as to which Title 8 of the Delaware Code confers jurisdiction upon the Court of Chancery, in each such case subject to such Court of Chancery having personal jurisdiction over the indispensable parties named as defendants therein. Section 22 of the Securities Act creates concurrent jurisdiction for federal and state courts over all suits brought to enforce any duty or liability created by the Securities Act or the rules and regulations thereunder. However, our certificate of incorporation provides that federal district courts of the United States of America will be the sole and exclusive forum for claims under the Securities Act. Section 27 of the Exchange Act creates exclusive federal jurisdiction over all suits brought to enforce any duty or liability created by the Exchange Act or the rules and regulations thereunder. As a result, the forum provision in our certificate of incorporation will not apply to suits brought to enforce any duty or liability created by the Exchange Act or any other claim for which the federal courts have exclusive jurisdiction. We will inform our investors in each report filed in accordance with the Exchange Act in which we describe the terms of our common stock that the forum provision in our certificate of incorporation will not apply to suits brought to enforce any duty or liability created by the Exchange Act or any other claim for which the federal courts have exclusive jurisdiction.

These provisions may have the effect of discouraging lawsuits against us or our directors, officers, employees or agents. Any person or entity purchasing or otherwise acquiring any interest in shares of capital stock of the Company will be deemed to have notice of and consented to the forum provisions in our certificate of incorporation. However, the enforceability of similar forum provisions in other companies’ certificates of incorporation has been challenged in legal proceedings, and it is possible that a court could find these types of provisions to be unenforceable. In this regard, stockholders may not be deemed to have waived our compliance with the federal securities laws and the rules and regulations thereunder, including Section 22 of the Securities Act. If a court were to find these provisions of our certificate of incorporation inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our business, financial condition or results of operations.

 

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If securities or industry analysts do not publish research reports or publish unfavorable research about our business, the price and trading volume of our CDIs and common stock could decline.

The trading market for our CDIs and common stock depends in part on the research reports that securities or industry analysts publish about us or our business. We do not currently have and may never obtain research coverage by securities and industry analysts. If no securities or industry analysts commence coverage of us, the trading price for our CDIs and common stock and other securities would be negatively affected. In the event we obtain securities or industry analyst coverage, if one or more of the analysts who covers us downgrades our securities, the price of our securities would likely decline. We do not have any control over these analysts. If one or more of these analysts cease to cover us or fail to publish regular reports on us, interest in the purchase of our securities could decrease, which could cause the price of our CDIs and common stock and other securities and their trading volume to decline.

Investors in this offering will experience immediate and substantial dilution of $    per share.

Based on an assumed initial public offering price of $    per share (the midpoint of the range set forth on the cover of this prospectus), purchasers of our common stock in this offering will experience an immediate and substantial dilution of $    per share in the as adjusted net tangible book value per share of common stock from the initial public offering price, and our as adjusted net tangible book value as of March 31, 2024 after giving effect to this offering would be $    per share. This dilution is due in large part to earlier investors having paid substantially less than the initial public offering price when they purchased their shares. See “Dilution.”

We may invest or spend the proceeds of this offering in ways with which you may not agree or in ways which may not yield a return.

The net proceeds from this offering are expected to be used for working capital and other general corporate purposes and to fund our growth strategies discussed in this prospectus. Our management will have considerable discretion in the application of the net proceeds, and you will not have the opportunity, as part of your investment decision, to assess whether the proceeds are being used appropriately. The net proceeds may be used for corporate purposes that do not increase our operating results or market value. Until the net proceeds are used, they may be placed in investments that do not produce significant income or that may lose value.

We do not expect to generate positive cash flow until at least 2026. As a result we do not expect to make dividends on our CDIs or common stock in the foreseeable future. Consequently, the ability of CDI holders and common stockholders to achieve a return on investment will depend on appreciation in the trading price of our CDIs and common stock.

We do not anticipate generating positive cash from operations until 2026, at the earliest. Additionally, at such time we do generate positive cash flow, we anticipate that we will retain all of our future earnings for use in the operation of our business and for general corporate purposes. As a result we do not expect to make dividends on our CDIs or common stock in the foreseeable future. Any determination to pay dividends in the future will be at the sole discretion of our board of directors. Accordingly, investors must rely on sales of their CDIs or common stock after price appreciation, which may never occur, as the only way to realize any future gains on their investments.

Future sales of our CDIs and common stock in the public market, or the perception that such sales may occur, could reduce our stock price, and any additional capital raised by us through the sale of equity or convertible securities may dilute your ownership in us.

We may issue additional CDIs or shares of common stock or securities convertible into our CDIs or common stock in subsequent public offerings. After the completion of this offering, we will have    

 

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outstanding shares of common stock. This number includes   shares of common stock that we are selling in this offering and the shares of common stock that we may sell in this offering if the underwriters’ option to purchase additional shares is fully exercised, which may be resold immediately in the public market, as well as shares issuable upon conversion of the Convertible Note. Following the completion of this offering, TR Ltd.’s former shareholders will hold an economic interest equivalent to     % of the Company’s outstanding common stock, assuming none of such shareholders participate in this offering. A portion of such shares are restricted from immediate resale under the federal securities laws and are subject to the lock-up agreements between such parties and the underwriters described in “Underwriting,” but may be sold into the market in the future. We expect that Sheffield will be party to a registration rights agreement with us that will require us to effect the registration of Sheffield’s shares in certain circumstances no earlier than the expiration of the lock-up period contained in the underwriting agreement entered into in connection with this offering. In addition, H&P will be granted certain registration rights pursuant to the Convertible Note. See “Shares Eligible for Future Sale”, “Certain Relationships and Related Party Transactions—H&P Convertible Note” and “Certain Relationships and Related Party Transactions—Registration Rights Agreement.” Officers and directors will be subject to certain restrictions on the sale of their shares for 180 days after the date of this prospectus; however, after such period, and subject to compliance with the Securities Act or exemptions therefrom, these individuals may sell such shares into the public market. See “Shares Eligible for Future Sale.”

In connection with this offering, we intend to file a registration statement with the SEC on Form S-8 providing for the registration of 1,600,000 shares of our common stock issued or reserved for issuance under the 2024 Incentive Award Plan (the “2024 Plan”) and 272,506 shares of our common stock underlying awards granted under the 2021 Equity Incentive Plan (the “2021 EIP”). See “Executive and Director Compensation—Equity Incentive Plans.” Subject to the satisfaction of vesting conditions and the expiration of lock-up agreements, shares registered under the registration statement on Form S-8 will be available for resale immediately in the public market without restriction.

We cannot predict the size of future issuances of our CDIs, common stock or securities convertible into common stock or the effect, if any, that future issuances and sales of CDIs or shares of our common stock will have on the market price of our CDIs or common stock. Sales of substantial amounts of our CDIs or common stock (including shares issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices of our CDIs or common stock.

The representatives of the underwriters of this offering may waive or release parties to the lock-up agreements entered into in connection with this offering, which could adversely affect the price of our common stock.

Our directors and executive officers have entered into lock-up agreements with respect to their common stock, pursuant to which they are subject to certain resale restrictions for a period of 180 days following the effectiveness date of the registration statement of which this prospectus forms a part. The representatives of the underwriters at any time and without notice, may release all or any portion of the common stock subject to the foregoing lock-up agreements. If the restrictions under the lock-up agreements are waived, then common stock will be available for sale into the public markets, which could cause the market price of our common stock to decline and impair our ability to raise capital.

We may issue preferred stock whose terms could adversely affect the voting power or value of our CDIs and common stock.

Our certificate of incorporation authorizes us to issue, without the approval of our stockholders, one or more classes or series of preferred stock having such designations, preferences, limitations and relative rights, including preferences over our common stock respecting dividends and distributions, as our board of directors may determine. The terms of one or more classes or series of preferred stock could adversely impact the voting power or value of our common stock. For example, we might grant holders of preferred stock the right to elect some number of our directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of preferred stock could affect the residual value of our common stock.

 

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We will incur increased costs as a result of being a publicly traded company in the United States.

We have no history of operating as a publicly traded company in the United States (only in Australia on the ASX). As a publicly traded company in the United States, we will incur significant legal, accounting and other expenses that we did not incur prior to this offering. In addition, the Sarbanes-Oxley Act, as well as rules implemented by the ASX, SEC and the NYSE, requires publicly traded entities to adopt various corporate governance practices that will further increase our costs.

Prior to this offering, we have not filed reports with the SEC. Following this offering, we will become subject to the public reporting requirements of the Exchange Act. We expect these rules and regulations to increase certain of our legal and financial compliance costs and to make activities more time-consuming and costly. For example, as a result of becoming a publicly traded company, we are required to adopt policies regarding internal controls and disclosure controls and procedures, including the preparation of reports on internal controls over financial reporting. In addition, we will incur additional costs associated with our SEC reporting requirements.

We also expect to incur significant expense to obtain director and officer liability insurance. Because of the limitations in coverage for directors, it may be more difficult for us to attract and retain qualified persons to serve on our board of directors or as executive officers.

We estimate that we will incur incremental costs associated with being a publicly traded company.

We have identified a material weakness in our internal control over financial reporting. Any material weakness may cause us to fail to timely and accurately report our financial results or result in a material misstatement of our financial statements.

Subject to applicable reporting requirement exemptions we take advantage of as an emerging growth company, we are required to comply with the SEC rules implementing Sections 302 and 404 of the SOX, which require management to certify financial and other information in our quarterly and annual reports and provide an annual management report on the effectiveness of controls over financial reporting. Effective internal control over financial reporting is necessary for us to provide reliable and timely financial reports and, together with adequate disclosure controls and procedures, are designed to reasonably detect and prevent fraud. We are also required to report any material weaknesses in such internal control. A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting such that there is a reasonable possibility that a material misstatement of our financial statements will not be prevented or detected on a timely basis.

In connection with the audit of our financial statements for fiscal years 2023 and 2022, and the review of our unaudited condensed consolidated financial statements for the nine months ended March 31, 2024, we identified deficiencies in our internal control over financial reporting, which in the aggregate, constituted a material weakness. We determined that in both fiscal years and the nine month period, we had deficiencies relating to insufficiently designed and operating internal controls over financial reporting, including: i) lack of sufficient evidence retained of the performance of internal controls, ii) insufficient resources in key accounting and finance roles leading to inadequate segregation of duties, iii) lack of manage access and manage change IT general controls over the cloud-based enterprise resource planning system, and iv) accounting for complex transactions in accordance with US GAAP, which in the aggregate constitute a material weakness.

As part of our plan to address this material weakness, we are performing a full review of our processes and internal controls. We have implemented, and plan to continue to implement, new controls and processes. We will also provide training to control owners in support of an effective internal control framework, including how to sufficiently document and evidence the operation of internal controls. Finally, we are also evaluating our current enterprise resource planning system and considering options for replacing it with a new system to better support our financial reporting, including any related internal controls. While we have begun implementing a plan to

 

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remediate this material weakness, we cannot predict the success of such plan or the outcome of our assessment of this plan at this time. If our steps are insufficient to successfully remediate the material weakness and otherwise establish and maintain an effective system of internal control over financial reporting, the reliability of our financial reporting, investor confidence in us, and the value of our common stock could be materially and adversely affected. We can give no assurance that this implementation will remediate this deficiency in internal control or that additional material weaknesses in our internal control over financial reporting will not be identified in the future. Our failure to implement and maintain effective internal control over financial reporting could result in errors in our financial statements that could result in a restatement of our financial statements, or cause us to fail to meet our periodic reporting obligations. For as long as we are an “emerging growth company” under the JOBS Act, our independent registered public accounting firm will not be required to attest to the effectiveness of our internal control over financial reporting pursuant to Section 404.

Once we no longer qualify as an “emerging growth company,” we will be required to have our independent registered public accounting firm provide an attestation report on the effectiveness of our internal control over financial reporting. An independent assessment of the effectiveness of our internal control over financial reporting could detect problems that our management’s assessment might not. Undetected material weaknesses in our internal control over financial reporting could lead to financial statement restatements and require us to incur the expense of remediation. An adverse report may be issued if our independent registered public accounting firm is not satisfied with the level at which our controls are documented, designed or operating.

We cannot be certain that our efforts to develop and maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to comply with our obligations under Section 404 of the SOX. Any failure to develop or maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our CDIs and common stock.

For as long as we are an emerging growth company, we will not be required to comply with certain reporting requirements, including those relating to accounting standards and disclosure about our executive compensation, that apply to other public companies.

We are classified as an “emerging growth company” under the JOBS Act. For as long as we are an emerging growth company, which may be up to five full fiscal years, unlike other public companies, we will not be required to, among other things, (i) provide an auditor’s attestation report on management’s assessment of the effectiveness of our system of internal control over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act, (ii) comply with any new requirements adopted by the Public Company Accounting Oversight Board requiring mandatory audit firm rotation or a supplement to the auditor’s report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer, (iii) provide certain disclosure regarding executive compensation required of larger public companies or (iv) hold nonbinding advisory votes on executive compensation. We will remain an emerging growth company for up to five years, although we will lose that status sooner if we have more than $1.235 billion of revenues in a fiscal year, have more than $700.0 million in market value of our common stock held by non-affiliates or issue more than $1.0 billion of non-convertible debt over a three-year period.

To the extent that we rely on any of the exemptions available to emerging growth companies, you will receive less information about our executive compensation and internal control over financial reporting than issuers that are not emerging growth companies. If some investors find our common stock to be less attractive as a result, there may be a less active trading market for our common stock and our stock price may be more volatile.

 

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Because we have elected to take advantage of the extended transition period pursuant to Section 107 of the JOBS Act, our financial statements may not be comparable to those of other public companies.

Section 107 of the JOBS Act provides that an emerging growth company can use the extended transition period provided in Section 7(a)(2)(B) of the Securities Act for complying with new or revised accounting standards. This permits an emerging growth company to delay the adoption of certain accounting standards until those standards would otherwise apply to private companies. We are choosing to take advantage of this extended transition period and, as a result, we will comply with new or revised accounting standards on the relevant dates on which adoption of such standards is required for private companies. Accordingly, our financial statements may not be comparable to companies that comply with public company effective dates, and our stockholders and potential investors may have difficulty in analyzing our operating results by comparing us to such companies.

Investors purchasing shares of our common stock in this offering may not be able to freely sell those shares in Australia during the 12 months after the issue date of those shares in this offering and therefore will not be able to take advantage of any liquidity that may be available for CDIs traded on the ASX during that period, unless an exception applies or the Company is able to rely on applicable legislative relief and lodges a cleansing notice in accordance with regulatory requirements with the ASX.

Although we expect that our shares of common stock will be listed on the NYSE, the shares sold in this offering may not be freely tradable in Australia during the 12 months after their issue date in this offering. In general, shares purchased in this offering may be resold in Australia during that period only to certain “sophisticated investors” and “professional investors” (as defined in the Australian Corporations Act) and certain persons associated with us under Section 708(12) of the Australian Corporations Act, and any subsequent resale of those shares will also be subject to the same restrictions during the 12 months after their issue date in this offering. See “Underwriting—Notice to Prospective Investors in Australia.” So long as those restrictions are in effect, to the extent that investors who purchase shares in this offering are able to resell those shares in Australia, the price they receive may be different than the market price of our common stock. Likewise, while investors purchasing shares in this offering will be entitled to exchange those shares for CDIs, which are listed on the ASX, sales of those newly-issued CDIs in Australia will be subject to the same restrictions that are applicable to the underlying shares of common stock as described above. Although we expect that the majority of the shares of common stock outstanding immediately after this offering will be represented by CDIs that are traded on the ASX, investors purchasing shares in this offering may not be able to freely sell those shares, or CDIs representing those shares, in Australia during the 12 months after the issue date of those shares in this offering. To the extent those newly issued CDIs are not freely tradeable, investors may not be able to take advantage of any liquidity which may be available for CDIs traded on the ASX during that period. Notwithstanding the foregoing, the Australian Securities and Investments Commission has granted Class Order Instrument 14/827 (“Class Order”) which permits the issue and on sale of CDIs within the first 12 months of issue provided the Company has lodged a cleansing notice on ASX within applicable time limits after those such CDIs are issued. Accordingly, if the Company is able to rely on the Class Order and has lodged a cleansing notice in respect to those CDIs, those CDIs that have been issued on conversion of the Company’s common stock (including common stock that is issued as a result of the Company’s initial public offering) may be freely tradable on ASX.

Our outstanding CDIs will be listed on the ASX and will be freely tradable in the public markets in Australia. Trading in our CDIs may have a material adverse effect on the trading price of our common stock on the NYSE.

Our common stock will be traded on the NYSE and our CDIs will be traded on ASX. The CDIs are, in general, the economic equivalent of shares of our common stock and, as a result, the trading price of the CDIs on the ASX will likely affect the trading price of our common stock on the NYSE, and vice versa. The trading price of the CDIs may be influenced by factors different from those that affect the trading price of our common stock on the NYSE and, as discussed below in these risk factors, may be influenced by arbitrage activities. In addition, holders of shares of our common stock, including shares sold in this offering, may deliver those shares to the

 

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depositary for the CDIs in exchange for CDIs. If a significant number of the shares of our common stock that are sold in the offering are exchanged for CDIs, it may have an adverse effect, which could be material, on the liquidity and trading price of our common stock on the NYSE.

Trading in our securities on these markets will take place in different currencies (U.S. dollars on NYSE and Australian dollars on the ASX), and at different times (resulting from different time zones, trading days and public holidays in the United States and Australia). The trading prices of our securities on these two markets may differ due to these and other factors, including the fact that ASX and NYSE have different criteria for trading halts as well as different listing rules and disclosure requirements. Any decrease in the price of our CDIs on the ASX could cause a decrease in the trading price of our common stock on the NYSE.

All of the shares of our common stock outstanding following this offering will be freely tradable in the U.S. public markets and a substantial majority of the shares of our common stock and the CDIs representing those shares will not be subject to lock-up agreements.

Upon completion of this offering, we will have outstanding an aggregate of approximately     shares of common stock. Of these outstanding shares, all of such shares will be freely tradeable in the United States without restriction or further registration under the Securities Act, unless such shares are held by our directors, executive officers or any of our affiliates, as that term is defined in Rule 144 under the Securities Act.

In connection with this offering, our directors, executive officers, and certain of our shareholders have each agreed to enter into “lock-up” agreements with the underwriters and thereby are subject to a lock-up period, meaning that they and their permitted transferees will not be permitted to sell any shares of common stock for 180 days after the date of this prospectus, subject to certain customary exceptions, without the prior consent of the representatives of the underwriters. Although we have been advised that there is no present intention to do so, the representatives may, in their sole discretion, release all or any portion of the shares from the restrictions in any of the lock-up agreements described above. See the section entitled “Underwriting” for more information. Possible sales of these shares in the market following the waiver or expiration of such agreements could exert significant downward pressure on our share price.

Also, in the future, we may issue our securities in connection with investments or acquisitions. The amount of common stock issued in connection with an investment or acquisition could constitute a material portion of our then outstanding common stock.

The different characteristics of the capital markets in Australia and the United States may negatively affect the trading prices of our CDIs and common stock, and may limit our ability to take certain actions typically performed by a U.S. company.

We are subject to ASX listing with respect to our CDIs, and associated Australian regulatory requirements, and intend to concurrently list our shares on the NYSE as well, which has its own listing and regulatory requirements. Such exchanges have different trading hours, trading characteristics (including trading volume and liquidity), trading and listing rules, and investor bases (including different levels of retail and institutional participation). As a result of these differences, the trading prices of our CDIs and our common stock may not be the same, even allowing for currency differences. Fluctuations in the price of our common stock due to circumstances peculiar to the U.S. capital markets could materially and adversely affect the price of the CDIs, or vice versa. Certain events having significant negative impact specifically on the Australian capital markets may result in a decline in the trading price of our common stock notwithstanding that such event may not impact the trading prices of securities listed in the United States generally or to the same extent, or vice versa.

Our ability to list our common stock on the NYSE is subject to us meeting applicable initial listing criteria.

In the event we are unable to list our common stock on the NYSE, our common stock will continue to trade on the ASX (as CDIs). Our failure to list our common stock on the NYSE could make it more difficult for U.S.

 

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persons to trade our common stock, could prevent our common stock trading on a frequent and liquid basis in the U.S., and could result in the value of our common stock being less than it would be if we were able to list our common stock on the NYSE.

Our ability to raise additional capital may be significantly limited by listing rules of the ASX that limit the amount of common stock that we are permitted to issue without stockholder approval.

Limitations on new share issuances under ASX listing rules may significantly limit or prevent us from raising additional capital by issuing and selling shares of our common stock or other securities when such additional capital is required. In particular, the ASX listing rules will prohibit us from issuing, during any 12-month period, shares of our common stock in an amount greater than 15% of the total number of shares of our common stock then outstanding without the affirmative vote of the holders of a majority of the outstanding shares of our common stock. We have received the approval of our shareholders to permit us to issue up to 25% of the total number of shares of our common stock then outstanding during the 12-month period commencing on the date we are admitted to the official list of the ASX; however, this increase is only effective for that 12-month period and may still limit or prevent us from raising additional capital when such additional capital is required. As discussed elsewhere in this prospectus, we will require substantial additional financing to develop and commercialize our resources and execute our strategy and, because we do not have any revenues from natural gas sales and would likely be unable to raise capital by borrowing funds, we will be dependent primarily upon issuing and selling additional shares of common stock to obtain such financing. The foregoing listing rule of the ASX is substantially more restrictive than the comparable NYSE rule and, even with the approval of our shareholders to permit us to issue up to 25% of the total number of shares of our common stock then outstanding during the 12-month period commencing on the date we are admitted to the official list of the ASX, this rule may significantly limit or prevent us from raising funds by issuing and selling shares of our common stock, which may have a material adverse effect on our results of operations, financial condition and the development of our business. Moreover, seeking shareholder approval to issue common stock is likely to take considerable time and expense and there can be no assurance that any such approval will be given in the future.

An investor may have limited ability to bring an action against us or against our directors and officers, or to enforce a judgment against us or them, because we conduct a majority of our operations in Australia, and many of our directors and officers reside outside the United States.

We conduct substantially all of our operations in Australia. Many of our directors and officers and certain other persons named in this prospectus are citizens and residents of countries other than the United States and a portion of the assets of the directors and officers and certain other persons named in this prospectus and substantially all of our assets are located outside of the United States. As a result, it may not be possible or practicable for you to effect service of process within the United States upon such persons or to enforce against them or against us judgments obtained in U.S. courts predicated upon the civil liability provisions of the federal securities laws of the United States. Even if you are successful in bringing such an action, there is doubt as to whether Australian courts would enforce certain civil liabilities under U.S. securities laws in original actions or judgments of U.S. courts based upon these civil liability provisions. In addition, awards of punitive damages in actions brought in the United States or elsewhere may be unenforceable in Australia or elsewhere outside the United States. An award for monetary damages under U.S. securities laws would be considered punitive if it does not seek to compensate the claimant for loss or damage suffered and is intended to punish the defendant. The enforceability of any judgment in Australia will depend on the particular facts of the case as well as the laws and treaties in effect at the time. The United States and Australia do not currently have a treaty or statute providing for recognition and enforcement of the judgments of the other country (other than arbitration awards) in civil and commercial matters. As a result, our holders of our common stock may have more difficulty in protecting their interests through actions against us, our management or our directors than would shareholders of a corporation operating within the United States.

 

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As a result of listing CDIs on the ASX, we will be subject to the listing rules of the ASX, which may strain our resources, divert management’s attention and affect our ability to manage our business or raise additional capital.

As a result of listing CDIs on the ASX, we will be subject to the listing rules of the ASX, which may strain our resources, divert management’s attention and affect our ability to manage our business or raise additional capital. The listing rules of the ASX differ from, and in some cases are more restrictive than, the rules and requirements of the NYSE, including restrictions that:

 

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limit non-executive director compensation to a maximum amount approved by shareholders at a general meeting;

 

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require that the terms of every class of our securities, including any preferred stock, be approved by the ASX;

 

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prohibit us from removing or changing the voting rights or dividend rights (if any) of our securities, except in certain circumstances;

 

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specify certain terms and conditions of options and rights plans;

 

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prohibit issuing equity securities without shareholder approval in the three months after we receive any notice in writing that a person proposes to make a takeover bid;

 

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limit the issuance of restricted (escrowed) securities; and

 

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prohibit “golden parachutes” or other termination benefits for officers upon a change in ownership or control of us.

These listing rules may, in some cases, limit our ability to take certain actions that would otherwise be permitted by NYSE rules and may affect our ability to manage our business and to attract and retain key management and scientific personnel. In addition, the listing rules of the ASX include approval and reporting requirements that differ from the requirements under the NYSE rules, such as requirements to:

 

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comply with required timetables for issuance of equity securities;

 

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deliver notice to the ASX prior to the release of restricted (escrowed) securities;

 

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file quarterly, half-yearly and annual periodic reports that include specific disclosure required by the listing rules of the ASX;

 

•

obtain stockholder approval for certain related-party transactions and for securities issuances to directors;

 

•

deliver drafts to the ASX of charter documents, debt and convertible securities documents, certain meeting notices and documents sent to certain holders of securities; and

 

•

prior to release to any other person, release announcements through the ASX as the central collection point for market sensitive information.

Compliance with these additional rules will increase our legal and financial compliance costs, make some activities or transactions more difficult, time-consuming or costly, may limit or prevent us from raising additional capital by issuing and selling shares of our common stock or other securities and increase demand on our systems and resources. We applied to the ASX for, and received, certain waivers from the application of some of its listing rules; however, such waivers will not afford us relief from all of the increased restrictions and requirements imposed by such listing rules. Increases in our costs and expenses associated with compliance with the ASX listing rules will adversely impact our results of operations and financial condition. In addition, limitations on new share issuances under ASX listing rules may limit or prevent us from raising additional capital by issuing and selling shares of our common stock or other securities when such additional capital is required, which may have a material adverse effect on our results of operations, financial condition and the development of

 

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our business. See “—Our ability to raise additional capital may be significantly limited by listing rules of the Australian Securities Exchange that limit the amount of common stock that we are permitted to issue without stockholder approval.”

The market price of our common stock may be adversely affected by arbitrage activities.

Investors may seek to profit by exploiting the difference, if any, in the price of our shares of common stock as reflected by the trading price of our CDIs, which will represent shares of our common stock, on the ASX and the trading price of our shares of common stock on the NYSE. Such arbitrage activities could cause the price of our common stock or the CDIs representing our common stock, as the case may be, in the market with the higher value to decrease to the price set by the market with the lower value or could otherwise adversely affect the market price of our common stock. These arbitrage risks may be increased by the fact that our common stock will be quoted in U.S. dollars on the NYSE while our CDIs will be quoted in Australian dollars on the ASX, which may also give investors the opportunity to exploit the impact of fluctuations in currency exchange rates on the market price of our common stock and the CDIs.

Changes in accounting standards issued by the Financial Accounting Standards Board (“FASB”) or other standard-setting bodies may adversely affect our financial statements.

Our financial statements are prepared in accordance with GAAP as defined in the Accounting Standards Codification (“ASC”) of the FASB. From time to time, we are required to adopt new or revised accounting standards or guidance that are incorporated into the ASC. It is possible that future accounting standards we are required to adopt could change the current accounting treatment that we apply to our consolidated financial statements and that such changes could have a material adverse effect on our financial condition and results of operations.

In addition, the FASB is working on several projects with the International Accounting Standards Board, which could result in significant changes as GAAP converges with International Financial Reporting Standards (“IFRS”), including how our financial statements are presented. Furthermore, the SEC is considering whether and how to incorporate IFRS into the U.S. financial reporting system. The accounting changes being proposed by the FASB will be a complete change to how we account for and report significant areas of our business. The effective dates and transition methods are not known; however, issuers may be required to or may choose to adopt the new standards retrospectively. In this case, issuers would report results under the new accounting method as of the effective date, as well as for all periods presented. Any such changes to GAAP or conversion to IFRS would impose special demands on issuers in the areas of governance, employee training, internal controls and disclosure and would likely affect how we manage our business.

 

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

This prospectus contains certain forward-looking statements. All statements, other than statements of historical fact included in this prospectus, regarding our strategy, future operations, financial position, estimated revenue and losses, projected costs, prospects, plans and objectives of management and dividend policy are forward-looking statements. When used in this prospectus, words such as “expect,” “project,” “estimate,” “believe,” “anticipate,” “intend,” “budget,” “plan,” “seek,” “envision,” “forecast,” “target,” “predict,” “may,” “should,” “would,” “could,” “will,” the negative of these term and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on our current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under “Risk Factors.” These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events.

Forward-looking statements may include statements about, among other things:

 

•

our business strategy and the successful implementation of our business strategy;

 

•

our future reserves;

 

•

our financial strategy, liquidity and capital required for our development programs;

 

•

estimated natural gas prices;

 

•

our dividend policy;

 

•

the timing and amount of future production of natural gas;

 

•

our drilling and production plans;

 

•

competition and government regulation;

 

•

our ability to obtain and retain permits and governmental approvals;

 

•

legal, regulatory or environmental matters;

 

•

marketing of natural gas;

 

•

business or leasehold acquisitions and integration of acquired businesses;

 

•

our ability to develop our properties;

 

•

the availability and cost of developing appropriate infrastructure around and transportation from our properties to market;

 

•

the availability and cost of drilling rigs, production equipment, supplies, personnel and oilfield services;

 

•

costs of developing our properties and of conducting our operations;

 

•

our ability to reach FID and execute and complete our planned pipeline or planned LNG export projects;

 

•

our anticipated Scope 1 and Scope 2 emissions from our businesses and our plans to offset our Scope 1 and Scope 2 emissions from our business;

 

•

our ESG strategy and initiatives, including those relating to the generation and marketing of environmental attributes or new products seeking to benefit from ESG-related activities;

 

•

general economic conditions, including cost inflation;

 

•

credit markets and the ability to obtain future financing on commercially acceptable terms;

 

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•

our ability to expand our business, including through the recruitment and retention of skilled personnel;

 

•

our dependence on our key management personnel;

 

•

our future operating results; and

 

•

our plans, objectives, expectations and intentions.

The forward-looking statements included in this prospectus are based on current expectations and involve numerous risks and uncertainties, most of which are difficult or impossible to predict and many of which are beyond our control, incident to the exploration for and development, production and sale of natural gas. Assumptions relating to these forward-looking statements involve judgments, risks and uncertainties with respect to, among other things, market factors (including competition and inflation), market prices (including geographic basis differentials) of natural gas, results of future drilling and marketing activity, future production and costs (including availability of drilling and production equipment and services), legislative and regulatory initiatives, electronic, cyber or physical security breaches, drilling and other operating risks, environmental risks (including climate change and weather-related events), future business decisions, the uncertainty inherent in estimating natural gas reserves and the other risks described under “Risk Factors.”

Reserve engineering is a process of estimating underground accumulations of natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of natural gas that are ultimately recovered.

Although we believe that the assumptions underlying these forward-looking statements are reasonable, should one or more of the risks or uncertainties described in this prospectus occur, or should underlying assumptions prove incorrect, actual outcomes and our results and financial condition may differ materially from those indicated in any forward-looking statements. In light of the significant uncertainties inherent in these forward-looking statements, the inclusion of such information should not be regarded as a representation by us or any other person that our objectives and plans will be achieved.

All forward-looking statements, expressed or implied, included in this prospectus are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.

All forward-looking statements, expressed or implied, in this prospectus are based only on information currently available to us and speak only as of the date on which they are made. Except as otherwise required by applicable law, we disclaim any duty to publicly update any forward-looking statement, each of which is expressly qualified by the statements in this section, to reflect events or circumstances after the date of this prospectus.

Additionally, our discussion of ESG assessments, goals and relevant issues herein, including the mitigation of the risks associated with climate change and the energy transition, are informed by various ESG standards and frameworks (including standards for the measurement of underlying data) and the interests of various stakeholders. Any references to “materiality” in the context of such discussions and any related assessment of ESG “materiality” may differ from the definition of “materiality” under the federal securities laws for SEC reporting purposes. Similarly, we cannot guarantee strict adherence to standard recommendations, and our disclosures based on any standards may change due to revisions in framework or legal requirements, availability

 

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of information, changes in our business or applicable government policies, or other factors, some of which may be beyond our control. Separately, the standards and performance metrics used, and the expectations and assumptions they are based on, should not be assumed, unless otherwise expressly specified, to have been verified by us or any third party.

 

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USE OF PROCEEDS

We estimate the net proceeds to us from the sale of our common stock in this offering, after deducting underwriting discounts and commissions and estimated offering expenses payable by us, will be $    million (or $    million if the underwriters exercise in full their option to purchase additional shares), based on an assumed initial public offering price of $    per share (the midpoint of the price range set forth on the cover page of this prospectus).

Each $1.00 increase (decrease) in the assumed initial public offering price of $    per share (the midpoint of the price range set forth on the cover page of this prospectus) would increase (decrease) the net proceeds to us from this offering by $    million, assuming that the number of shares offered by us, as set forth on the cover page of this prospectus, remains the same and after deducting underwriting discounts and commissions and estimated offering expenses payable by us. We may also increase or decrease the number of shares we are offering. Each increase (decrease) of 1.0 million shares in the number of shares we are offering would increase (decrease) the net proceeds to us from this offering by $    million, assuming that the assumed initial public offering price of $    per share (the midpoint of the price range set forth on the cover page of this prospectus) remains the same, and after deducting underwriting discounts and commissions and estimated offering expenses payable by us.

We intend to use all the net proceeds of this offering to fund our development plan, and for working capital and other general corporate purposes.

We estimate the capital required to deliver the first development phase to production will be approximately $125 million to $165 million net to Tamboran. We expect to spend approximately $70 million to $80 million net on drilling and completion costs, $10 million to $13 million net on costs related to the development of the compression facility, $23 million to $30 million net on related pad construction and gathering infrastructure and $26 million to $40 million net on transaction and general and administrative expenses.

The expected use of net proceeds from this offering represents our intentions based upon our present plans and business conditions. We cannot specify with certainty the particular uses of the net proceeds that we will receive from this offering or the amounts we actually spend on the uses set forth above. The timing and amount of our actual expenditures will be based on many factors, including the anticipated growth of our business. Pending the use of proceeds from this offering as described above, we plan to invest a portion of the net proceeds that we receive in this offering in short-term and intermediate-term interest-bearing obligations, investment-grade investments, certificates of deposit, or direct or guaranteed obligations of the U.S. government. Our management will have broad discretion in the application of the net proceeds from this offering and investors will be relying on the judgment of our management regarding the application of the proceeds.

 

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DIVIDEND POLICY

We have not declared, or paid to date, a cash dividend to holders of ordinary shares of TR Ltd. or holders of our common stock. We currently intend to retain any future earnings, if any, to fund the development and expansion of our business and do not expect to pay any dividends in the foreseeable future. Any future dividends will be subject to the sole discretion of our board of directors and the considerations discussed below.

Any future determination to declare and pay a regular or special dividend, as well as the amount of any such dividends, will depend on our board of directors’ consideration of general economic and business conditions, our financial condition and results of operations, capital requirements, restrictions under our indebtedness, potential acquisition opportunities and other current and anticipated cash needs and any other factors our board of directors deems relevant.

Our dividend policy may change from time to time, and there can be no assurance that we will declare any regular or special cash dividends at all or in any particular amounts.

 

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CAPITALIZATION

The following table shows our capitalization as of March 31, 2024:

 

•

on an actual basis; and

 

•

on an as adjusted basis, after giving effect to the sale of    shares of our common stock in this offering (which assumes that the underwriters do not exercise their option to purchase additional shares), at an assumed initial public offering price of $    per share (the midpoint of the price range set forth on the cover page of this prospectus), the conversion of the Convertible Note into an aggregate of     shares of common stock (assuming an initial public offering price of $     per share) our receipt of the estimated net proceeds of this offering and after deducting underwriting discounts and commissions and estimated offering expenses payable by us and the application of such net proceeds as described under “Use of Proceeds.”

The as adjusted information set forth in the table below is illustrative only and will adjust based on the actual initial public offering price and other terms of this offering determined when the initial public offering price is determined. You should read the following table together with “Selected Consolidated Financial Data,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and our consolidated financial statements and the related notes thereto included elsewhere in this prospectus.

 

		As of March 31, 2024
		Actual				As Adjusted
		(in thousands)
Cash and cash equivalents(1)		$	25,909
Total long term debt			—
Stockholders’ equity:
Common stock, $0.001 par value, 10,000,000,000 shares authorized at March 31, 2024, 10,301,436 shares issued and outstanding at March 31, 2024			10
Additional paid-in capital			330,110
Total stockholders’ equity			228,207
Total capitalization			228,207

 

(1)	As of April 30, 2024, we had $19.7 million of cash and cash equivalents

The number of shares of our common stock set forth in the table above excludes an aggregate of 1,600,000 additional shares of our common stock reserved for future awards pursuant to the 2024 Plan (and which excludes any potential evergreen increases pursuant to the terms of the 2024 Plan), including     shares of common stock that may be issued upon vesting of equity awards that we expect to be granted in connection with this offering.

 

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DILUTION

Purchasers of the common stock in this offering will experience immediate and substantial dilution in the net tangible book value per share of the common stock for accounting purposes. Our net tangible book value as of March 31, 2024 was $    million, or $    per share. Net tangible book value per share is determined by dividing our tangible net worth (tangible assets less total liabilities) by the total number of shares of common stock that were outstanding as of March 31, 2024. After giving effect to the sale of the shares in this offering, the conversion of the Convertible Note into an aggregate of     shares of common stock (assuming an initial public offering price of $     per share), and further assuming the receipt of the estimated net proceeds (after deducting estimated underwriting discounts and commissions and estimated offering expenses), our as adjusted net tangible book value as of March 31, 2024 would have been $    million, or $    per share. This represents an immediate increase in the net tangible book value of $    per share to our existing stockholders and an immediate dilution (i.e., the difference between the initial public offering price per share of our common stock and the as adjusted net tangible book value per share of our common stock after this offering) to new investors purchasing shares of common stock in this offering of $    per share.

The following table illustrates the per share dilution to new investors purchasing shares of common stock in this offering:

 

Assumed initial public offering price per share		$
Net tangible book value per share as of March 31, 2024		$
Increase in net tangible book value per share attributable to new investors in this offering
Less: As adjusted net tangible book value per share of common stock after giving effect to this offering
Dilution in as adjusted net tangible book value per share to new investors from this offering		$

A $1.00 increase (decrease) in the assumed initial public offering price of $    per share (the midpoint of the price range set forth on the cover page of this prospectus), would increase (decrease) the as adjusted net tangible book value per share after this offering by $    per share and increase (decrease) the dilution in net tangible book value per share to new investors in this offering by $    per share, in each case assuming the number of shares of common stock offered by us, as set forth on the cover page of this prospectus, remains the same and less estimated underwriting discounts and commissions and estimated offering expenses payable by us (and if the underwriters exercise in full their option to purchase additional shares, the as adjusted net tangible book value per share would be $    per share, and the dilution in net tangible book value per share to new investors in this offering would be $    per share).

The following table summarizes, as of March 31, 2024, the differences between the number of shares issued as a result of this offering, the total amount paid by existing shareholders and the average price per share to be paid by investors in this offering, based upon an assumed initial public offering price of $    per share (the midpoint of the price range set forth on the cover page of this prospectus).

 

		Shares								Total Consideration								Average Price per Share
		Number				Percent				Amount				Percent
Existing stockholders							%								%			$
New investors							%								%			$
Total							100	%							100	%		$

The above tables and related discussion are based on the number of shares of our common stock to be outstanding as of the closing of this offering and the conversion of the Convertible Note. If the underwriters’

 

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option to purchase additional shares is exercised in full, the number of shares held by new investors will be increased to    , or     % of the total number of shares of common stock. The above tables and related discussion exclude an aggregate 1,600,000 of shares of our common stock reserved for future awards pursuant to the 2024 Plan (and which excludes any potential annual evergreen increases pursuant to the terms of the 2024 Plan), including     shares of common stock that may be issued upon vesting of equity awards that we expect to be granted in connection with this offering.

 

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and related notes included elsewhere in this prospectus. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expectations. “Cautionary Statement Regarding Forward-Looking Statements,” “Risk Factors” and the consolidated financial statements and the related notes thereto (included elsewhere in this prospectus) contain important information you should reference. We disclaim any duty to publicly update any forward-looking statements except as otherwise required by applicable law. Our historical results are not necessarily indicative of the results that may be expected for any period in the future.

Unless the context otherwise requires, the terms “we,” “us” and “our” refer to (i) Tamboran Resources Limited, an Australian public company formed in 2009, and its subsidiaries (“TR Ltd.”), the entity before the completion of our corporate reorganization described in this prospectus and (ii) Tamboran Resources Corporation, a Delaware corporation formed in 2023, and its subsidiaries (“Tamboran”), the issuer of the shares in this offering and the entity resulting from our corporate reorganization described in this prospectus. For more information on our organizational structure, see the section entitled “Corporate Reorganization” and “Note 1 — General Information” to our consolidated financial statements included elsewhere in this prospectus.

Corporate Reorganization

On December 13, 2023, we acquired all of the issued and outstanding ordinary shares of TR Ltd. pursuant to a scheme of arrangement under Australian law (the “corporate reorganization”). As part of the corporate reorganization, we issued to the shareholders of TR Ltd. one CDI (representing an interest in 1/200^th of a share of our common stock) in exchange for one ordinary share of TR Ltd. then issued and outstanding. Prior to the corporate reorganization, we had no business or operations, and following the corporate reorganization, our business and operations consist solely of the business and operations of TR Ltd. and its subsidiaries.

TR Ltd. was established in 2009 and is headquartered in Sydney, Australia. TR Ltd. completed its initial public offering in Australia in July 2021 and was publicly listed on the Australian Securities Exchange under the ticker “TBN.” TR Ltd. was removed from the ASX following the corporate reorganization, at which time CDIs representing an interest in 1/200th of a share of common stock of Tamboran were listed on the ASX under the same ticker “TBN.” Tamboran was incorporated in the State of Delaware on October 3, 2023 for the purposes of effecting the corporate reorganization.

As a result of the corporate reorganization, Tamboran became the parent company of TR Ltd., and for financial reporting purposes, the financial statements of TR Ltd. became the financial statements of Tamboran. The results of operations discussed in this “Management’s Discussion and Analysis of Financial Condition and Results of Operations” includes the results of Tamboran and its consolidated subsidiaries. See “Presentation of Financial and Operating Data.”

Overview

We are an early stage, growth-driven independent natural gas exploration and production company focused on an integrated approach to the commercial development of the natural gas resources in the Beetaloo located within the Northern Territory of Australia. We and our working interest partners have EPs to approximately 4.7 million contiguous gross acres (1.9 million net acres to Tamboran) and are currently the largest acreage holder in the Beetaloo.

We are focused on developing early stage, unconventional gas resources within our portfolio. Our key assets are (i) a 25% non-operated working interest in EP 161, (ii) a 38.75% working interest in EPs 76, 98 and 117,

 

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where we are the operator, and (iii) a 100% working interest in EPs 136, 143 and EP(A) 197, where we are the operator, all of which are located in the Beetaloo.

Recent Developments

Beetaloo Joint Venture

On March 4, 2024, Falcon capped its participation to 5% in the Beetaloo Joint Venture’s SS2 and the two wells in the 2024 drilling program. On March 21, 2024, TB1 Operator agreed to pick up Falcon’s interest, increasing our working interest to at least 47.5% in SS2 and the two wells in the 2024 drilling program. The two wells in the 2024 drilling program will create two DSUs totaling 51,200 gross acres around the new SS2 well pad. The 51,200 gross acre area has the potential to accommodate 23 well pads, or 138 total wells based on six wells drilled per pad. We believe the two DSUs will be more than enough to accommodate all wells associated with the Shenandoah South Pilot Project and over 100 wells for future development phases.

Capital Raising

In July and August 2023, we successfully completed a private placement of ordinary shares of TR Ltd. for $36.2 million (A$54.1 million) in gross proceeds, including a $10.0 million investment from Mr. Sheffield. Concurrently, we agreed to issue up to $9.0 million of five-year unsecured convertible notes from time to time to H&P for purposes of funding reimbursement of the mobilization and related reimbursable costs for Rig 469 as well as other working capital requirements. In June 2024, we issued the Convertible Note to H&P with an original principal amount of $9.4 million. The Convertible Note was issued in exchange for all undrawn existing convertible note obligations with H&P. See “Liquidity and Capital Resources—H&P Convertible Note.”

On December 14, 2023, we successfully completed a private placement of our CDIs for $27.7 million (A$40.8 million) in gross proceeds, including a $10.2 million (A$15.3 million) strategic investment from Liberty Energy and an additional $5.0 million (A$7.6 million) investment from Mr. Sheffield.

In connection with the private placement, we made an offer to retail holders of existing CDIs to purchase CDIs at the same price as the purchasers in the December 14, 2023 private placement. The retail offer was completed on January 14, 2024 and raised $9.3 million (A$14.2 million).

The funds from the capital raises will support our Beetaloo development activities.

SS1H Well Drilling

In early July 2023, H&P’s FlexRig^® was successfully mobilized to the SS1H well location targeting the deeper Middle Velkerri B Shale in EP 117. We successfully commenced drilling of the SS1H well in early August 2023 and intersected a 295-foot interval of Middle Velkerri B Shale, the thickest recorded section in the Beetaloo depocenter to date. SS1H delivered an average IP30 flow rate of 3.2 MMcf/d over the 1,644-foot, 10-stage stimulated length within the Middle Velkerri B Shale, an IP60 flow rate of 3.0 MMcf/d, and an IP90 flow rate of 2.9 MMcf/d. Normalizing the production rate for a 10,000-foot horizontal lateral, the IP30 flow rate in SS1H would have been approximately 19.5 MMcf/d, the IP60 flow rate would have been approximately 18.4 MMcf/d, and the IP90 flow rate would have been approximately 17.8 MMcf/d.

Market Outlook

We believe natural gas can play a key role in supporting the emissions reduction targets of many regional markets through the transition of coal-to-gas fired power plants. To date the increasing global demand for LNG, as well as under-investment in new supply, is expected to lead to LNG supply shortages.

 

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We have the potential, subject to achieving commercial viability in the Beetaloo, to supply natural gas to both Australian domestic and international LNG markets, which would support countries in the region in achieving their GHG emission reduction targets and help reduce global GHG emissions if LNG is adopted as an alternative to coal fired power. We are in the initial phase of development of our operations. Successful commercialization of the Beetaloo will require the development of the infrastructure necessary to conduct our business as planned on commercially acceptable terms. In addition, success of our business will rely on the Australian East Coast and the Asian LNG markets maintaining elevated prices relative to North America to offset the higher costs associated with developing infrastructure in the Beetaloo.

The natural gas industry is cyclical and commodity prices are highly volatile. During the period from 2021 through 2023, the natural gas continuous futures price on JKM reached a high of $69.96 per MMBtu on August 25, 2022 and a low of $5.81 per MMBtu on February 25, 2021.

We expect the natural gas markets will continue to be volatile in the future. Our future revenue, profitability and future growth are highly dependent on the prices we will receive for natural gas production. See “Risk Factors—Natural gas prices are volatile. A reduction or sustained decline in prices may adversely affect our business, financial condition or results of operations and our ability to meet our financial commitments or raise capital.”

Although inflation globally had been relatively low for many years, there was a significant increase in inflation beginning in the second half of calendar year 2022, which continued through calendar years 2023 and 2024, due to a substantial increase in the money supply by central banks (including the US Federal Reserve, and the Reserve Bank of Australia), a stimulation focused global fiscal policy, a significant rebound in consumer demand as COVID-19 restrictions were relaxed, the Russia-Ukraine war and worldwide supply chain disruptions resulting from the economic contraction caused by COVID-19 and lockdowns followed by a rapid recovery. Inflation rose in the United States from 6.1% in 2022 to 6.6% in 2023 and in Australia from 4.1% in 2022 to 8.0% in 2023. Global, industry-wide supply chain disruptions have resulted in widespread shortages of labor, materials and services. Such shortages have resulted in our facing significant cost increases for labor, materials and services. Principally, commodity costs for steel and chemicals required for drilling, higher transportation and fuel costs and annual wage increases have increased our operating costs for fiscal year 2023 and the nine months ended March 31, 2024 compared to the same periods in 2022 and 2023, respectively. Typically, as the price for natural gas increases, so do associated costs. Conversely, in a period of declining prices, associated cost declines are likely to lag and may not adjust downward in proportion to prices. Some supply chain constraints and inflationary pressures could persist into 2024 but are expected to plateau, however we cannot accurately predict future supply chain constraints and inflation. We cannot predict the future inflation rate but to the extent inflation remains elevated, we may experience cost increases in our operations, including costs for drill rigs, workover rigs, hydraulic fracturing fleets, tubulars and other well equipment, as well as increased labor costs. If we are unable to recover higher costs through higher commodity prices, our future revenue stream, would be significantly impacted.

We are taking actions to mitigate supply chain and inflationary pressures. We are monitoring the situation and assessing its impact on our business, including with respect to our partners. For example, we have pre-purchased long lead materials including casing and tubulars, chemicals and downhole equipment necessary for our planned development for 2024. We have in place a 10-year option with H&P to contract for up to five additional FlexRigs®. We are working closely with other suppliers and contractors to ensure availability of supplies on site, especially fuel, steel and chemical supplies which are critical to many of our operations and are working on diversifying suppliers. However, these mitigation efforts may not succeed or be insufficient.

 

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Factors that Affect Comparability of Future Results

Our financial condition and results of operations for the periods presented and future periods may not be comparable, either from period to period or going forward primarily for the following reasons:

Recent events and formation transactions

Tamboran was incorporated as a Delaware corporation on October 3, 2023 and does not have historical financial operating results prior to the corporate reorganization effective December 13, 2023. As a result of the corporate reorganization, Tamboran became the parent company of TR Ltd., and for financial reporting purposes, the financial statements of TR Ltd. became the financial statements of Tamboran. See “Corporate Reorganization.”

Success in our development of our natural gas properties

Because we have no operating history in the production of natural gas, our future results of operations and financial condition will be directly affected by our ability to develop and commercialize our assets through our drilling programs and future sales and marketing.

Natural gas revenue

We have not generated any revenue from natural gas production since inception due to the current stage of our operations, which is exploration drilling of our assets to test their commercial viability. If and when we do commence natural gas production, we expect to generate revenue from such production. No revenue from natural gas production is reflected in our financial statements.

Operating costs and expenses

We have not yet commenced natural gas production. If and when we do commence production, we will incur additional operating costs and expenses, which may include lease operating expenses, workover costs, taxes and royalty fees. Our operating costs and expenses consisted of the following during fiscal years 2022 and 2023 and the nine months ended March 31, 2023 and 2024: salaries, share based compensation, and related taxes and benefits of personnel employed by us, professional fees for consultants, auditors, tax advisors and legal services, depreciation and amortization of natural gas properties, impairment of our natural gas properties, the loss on sale of assets due to the sale of rigs in fiscal year 2023, exploration expenses, and general and administrative expenses.

Acquisitions

We may continue to grow our operations and financial results through strategic acquisition opportunities that may arise relevant to our Beetaloo strategy. Additionally, we may from time to time effect divestitures of certain of our non-core assets.

Supply, demand, market risk and the impact on natural gas prices

As discussed above in “—Market Outlook,” the natural gas industry historically has been cyclical with highly volatile commodity prices. Natural gas prices are subject to large fluctuations in response to relatively minor changes in the demand for natural gas. Prices are affected by current and expected supply and demand dynamics, including the market disruptions resulting from the Russian-Ukraine war, the impact of the COVID-19 pandemic and related erosion of demand for natural gas, supply growth driven by advances in drilling and completion technologies, resulting in increased supply in the global market. Other factors impacting supply and demand include weather conditions (including severe weather events), pipeline capacity constraints, inventory storage levels, basis differentials, export capacity, supply chain quality and availability, as well as other factors, the majority of which are outside of our control. These commodity prices are likely to remain volatile in the future. Sustained periods of low natural gas prices could materially and adversely affect our financial condition, our results of operations, the quantities of natural gas that we can economically produce and our ability to access capital. Since we have not generated revenues, these key factors will only affect us when we produce and sell natural gas.

 

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U.S. reporting company expenses

Prior to our corporate reorganization, the ordinary shares of TR Ltd. were listed on the ASX. Concurrently with the closing of this offering, our common stock is expected to be listed on NYSE and we will be subject to the periodic reporting requirements of the Exchange Act. Although we have been listed on the ASX and have been required to file financial information and make certain other filings with the ASX, our status as a U.S. reporting company under the Exchange Act will cause us to incur additional legal, accounting and other expenses that we have not previously incurred, including costs related to compliance with the requirements of the Sarbanes-Oxley Act. These incremental legal and financial compliance expenses are not included in our historical results of operations; therefore, our results of operations for future periods may not be comparable to our results of operations for the periods under review.

Results of Operations

Our functional currency is the Australian dollar and our reporting currency is the U.S. dollar. For revenues and expenses reported in any period, we use the average currency exchange rate between U.S. dollars and Australian dollars for the period. For assets and liabilities, we use the current currency exchange rate as at the end of the period, based on the same source. Given the fluctuations in currency exchange rates, we may experience changes in reported amounts from period to period that occur primarily as a result of these fluctuations and that are not reflective of actual changes in our business or operations.

Currently, we are exposed to foreign exchange risk, particularly with the U.S. dollar and Australian dollar, as a result of revenue and expenses that are denominated in each currency. It is our policy to limit the use of financial derivatives and seek risk mitigation through natural hedges. These natural hedges include the maintenance of U.S. dollar and Australian bank accounts and deposits. Because our functional currency is the Australian dollar, our reported financial results are subject to fluctuation resulting from changes in the U.S. dollar to Australian dollar exchange rate.

The following tables present selected financial information for the periods presented:

 

		Nine Months ended March 31,								Year ended June 30,
		2024				2023				2023				2022
		(in thousands)
Revenue and other operating income / Revenues		$	—			$	—			$	—			$	—
Operating costs and expenses:
Compensation and benefits, including stock based compensation			(3,703	)			(4,996	)			(6,341	)			(3,684	)
Consultancy, legal and professional fees			(4,863	)			(5,727	)			(6,818	)			(2,708	)
Depreciation and amortization			(90	)			(89	)			(118	)			(128	)
Loss on assets classified as held for sale			(26	)			—				(12,585	)			—
Accretion of asset retirement obligations			(661	)			(328	)			(601	)			(79	)
Exploration expense			(2,964	)			(1,713	)			(2,793	)			(1,707	)
General and administrative			(2,302	)			(2,048	)			(2,763	)			(1,637	)
Total operating costs and expenses			(14,608	)			(14,901	)			(32,020	)			(9,943	)
Other income:
Interest expense, net			503				64				31				(6	)
Foreign exchange gain, net			385				80				130				471
Other expenses			(200	)			(302	)			(337	)			(144	)
Total other (expense)/income			688				(158	)			(176	)			321
Net loss			(13,920	)			(15,059	)			(32,196	)			(9,622	)
Foreign currency translation			(3,866	)			4,325				1,633				(7,278	)
Total comprehensive loss attributable to noncontrolling interest			(1,956	)			479				108				—
Total comprehensive loss attributable to Tamboran			(15,830	)			(11,213	)			(30,671	)			(16,900	)

 

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Nine Months ended March 31, 2023 and March 31, 2024

Revenue and other operating income. We have not yet commenced natural gas production. Therefore, we did not realize any revenue and other operating income during the nine months ended March 31, 2023 and March 31, 2024, respectively.

Compensation and benefits, including stock based compensation. Compensation and benefits, including stock based compensation, decreased by $1.3 million during the nine months ended March 31, 2024, as compared to the nine months ended March 31, 2023 due primarily to forfeiture of options during the period and increased capitalization of compensation and short-term incentive awards in the nine months ended March 31, 2024.

Consultancy, legal and professional fees. Consultancy, legal and professional fees decreased by $0.9 million during the nine months ended March 31, 2024, as compared to the nine months ended March 31, 2023 due primarily to increased capitalization of consultancy, legal and professional fees related to significant capital raising activities, and related transactions, in the period ended March 31, 2024.

Accretion of asset retirement obligations expense. For the nine months ended March 31, 2024, an expense for accretion of asset retirement obligations of $0.7 million was recognized. The recognition of such an expense was due to the accretion of asset retirement obligation liabilities in relation to all EPs, inclusive of EPs 76, 98, 117, 136 and 161 for the full nine months ended March 31, 2024, including for the two new wells drilled during the period.

Exploration expense. Exploration expense increased by $1.3 million during the nine months ended March 31, 2024, as compared to the nine months ended March 31, 2023 due to expenses associated with drilling our SS1H and A3H wells. Our exploration expense consisted of costs related to topographical, geographical and geophysical studies and other indirect expenditure during the nine months ended March 31, 2023 and March 31, 2024.

General and administrative. General and administrative costs increased by $0.3 million during the nine months ended March 31, 2024, as compared to the nine months ended March 31, 2023 due primarily to increased insurance costs during the period. Our general and administrative expense consisted of the following during the nine months ended March 31, 2023 and March 31, 2024: expenses related to travel, insurance, and office and administrative fees.

Interest Income. Interest income increased by $0.4 million during the nine months ended March 31, 2024, as compared to the nine months ended March 31, 2023 due to interest received from term deposits during the period.

Foreign currency translation. In the nine months ended March 31, 2024, we recognized a foreign currency translation loss of $3.9 million, primarily due to slight weakening of the Australian Dollar as of March 31, 2024, as compared to July 1, 2023. In the nine months ended March 31, 2023, we recognized a foreign currency translation gain of $4.3 million, primarily due to the acquisition of assets from Origin Energy amounting to A$81.9 million on November 9, 2023 and significant strengthening of Australian Dollar from that date to March 31, 2023. Foreign exchange gains and losses resulting from the settlement of foreign currency transactions and from the translation at fiscal year-end exchange rates of monetary assets and liabilities denominated in foreign currencies are recognized on our income statement.

Income Tax Expense. We have no income tax expense due to operating losses incurred for the nine months ended March 31, 2023 and March 31, 2024. We have provided a full valuation allowance on our net deferred tax asset because management has determined that it is more-likely-than-not that we will not earn income sufficient to realize the deferred tax assets during a foreseeable future period. Management will continue to assess the potential for realizing deferred tax assets based upon income forecast data and the feasibility of future tax planning strategies and may record adjustments to the valuation allowance against deferred tax assets in future periods, as appropriate, that could have a material impact on the statement of operations.

 

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Fiscal Years Ended June 30, 2022 and June 30, 2023

Revenue and other operating income. We have not yet commenced natural gas production. Therefore, we did not realize any revenue and other operating income during fiscal years 2022 and 2023, respectively.

Compensation and benefits, including stock based compensation. Compensation and benefits, including stock based compensation, increased by $2.7 million during fiscal year 2023, as compared to fiscal year 2022 due to increased headcount, higher salaries for skilled workers, and short term incentive payments made to personnel.

Consultancy, legal and professional fees. Consultancy, legal and professional fees increased by $4.1 million during fiscal year 2023, as compared to fiscal year 2022 due to preparation for a U.S. initial public offering including expenses related to corporate restructuring, and legal and professional expenses associated with capital raises in addition to consulting costs related to government and community relations and midstream activities.

Loss on assets classified has held for sale. We recognized a $12.6 million loss during fiscal year 2023 due to a loss on the sale of one rig of $3.3 million and the write down of two rigs held for sale to be the lower of carrying amount and fair value less costs. We bought the two rigs for $15.9 million and incurred $2 million in additional capitalizable expenses, while the fair value less costs to sell was $8.8 million. The two rigs remain unsold as of June 30, 2023. The remaining difference relates to the foreign exchange impact of consolidation.

Accretion of asset retirement obligations expense. For fiscal year 2023, an expense for accretion of asset retirement obligations of $0.6 million was recognized. The recognition of such an expense was due to the initial recognition of an asset retirement obligation in relation to EPs 76, 98, 117 and 136 on December 31, 2022.

Exploration expense. Exploration expense increased by $1.1 million during fiscal year 2023, as compared to fiscal year 2022 due to expenses associated with drilling our SSIH and A3H wells. Our exploration expense consisted of costs related to topographical, geographical and geophysical studies and other indirect expenditure during fiscal years 2022 and 2023.

General and administrative. General and administrative costs increased by $1.1 million during fiscal year 2023, as compared to fiscal year 2022 due to increased travel subsequent to the easing of COVID-19 restrictions and an increase in insurance premiums. Our general and administrative expense consisted of the following during fiscal years 2022 and 2023: expenses related to travel, insurance, and office and administrative fees.

Foreign currency translation. Foreign currency transactions are translated into our functional currency using the exchange rates prevailing at the dates of the transactions. We recognized a foreign currency translation gain of $1.6 million during fiscal year 2023, as compared to a loss of $7.3 million during fiscal year 2022 due primarily to the acquisition of assets from Origin Energy at a period during the year when the Australian Dollar had strengthened in comparison to end position as of June 30, 2023. Foreign exchange gains and losses resulting from the settlement of foreign currency transactions and from the translation at fiscal year-end exchange rates of monetary assets and liabilities denominated in foreign currencies are recognized on our income statement.

Income Tax Expense. We have no income tax expense due to operating losses incurred for fiscal years 2022 and 2023. We have provided a full valuation allowance on our net deferred tax asset because management has determined that it is more-likely-than-not that we will not earn income sufficient to realize the deferred tax assets during a foreseeable future period. Management will continue to assess the potential for realizing deferred tax assets based upon income forecast data and the feasibility of future tax planning strategies and may record adjustments to the valuation allowance against deferred tax assets in future periods, as appropriate, that could have a material impact on the statement of operations.

Liquidity and Capital Resources

We are a development stage enterprise and will continue to be so until commencement of substantial production from our natural gas properties. We do not expect to generate any revenue from production until

 

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2026, at the earliest, which will depend upon successful drilling results, additional and timely capital funding, and access to suitable infrastructure. Until then our primary sources of liquidity are expected to be cash on hand at the time of this offering, net proceeds from this offering and funds from future private and public equity placements, debt funding and asset sales.

We expect to incur substantial expenses and generate significant operating losses as we continue to develop our natural gas prospects and as we:

 

•

complete our current appraisal drilling and testing program;

 

•

develop and commercialize our assets, including development of pipelines, the proposed NTLNG facility and other infrastructure;

 

•

opportunistically invest in additional natural gas assets adjacent to our current positions;

 

•

incur expenses related to operating as a public company and compliance with regulatory requirements.

Our future financial condition and liquidity will be impacted by, among other factors, the success of our exploration and appraisal drilling program, the number of commercially viable natural gas discoveries made, the quantities of natural gas discovered, the speed with which we can bring such discoveries to production, and the actual cost of exploration, appraisal and development of our prospects.

We estimate that we will need to invest approximately $57 million for the remainder of calendar year 2024 in order to progress our development plans. We expect the proceeds of this offering, together with our existing cash on hand, to be sufficient to fund our planned drilling and testing program at least through the end of fiscal year 2025. However, we may require significant additional funds earlier than we currently expect in order to execute our strategy as planned. We may seek additional funding through asset sales or public or private financings. Additional funding may not be available to us on acceptable terms or at all. In addition, the terms of any financing may adversely affect the holdings or the rights of our stockholders. For example, if we raise additional funds by issuing additional equity securities, further dilution to our existing stockholders will result. If we are unable to obtain funding on a timely basis, we may be required to significantly curtail one or more of our planned activities. We also could be required to seek funds through arrangements with collaborators or others that may require us to relinquish rights to some of our assets which we would otherwise develop on our own, or with a majority working interest.

Cash and Cash Equivalents

The following table summarizes our key measures of liquidity for the periods indicated (all dollars amounts are presented in thousands).

 

		March 31,				June 30,				June 30,
		2024				2023				2022
Balance Sheet Statistics:
Cash & cash equivalents		$	25,909			$	6,426			$	18,470

As of March 31, 2024, we had $25.9 million of cash and cash equivalents. This balance represents an increase of $19.5 million from June 30, 2023, due to capital raises during the period of $70.4 million, net of fees, offset primarily by spending on operations, particularly drilling two appraisal wells in the nine month period. As of June 30, 2023, we had $6.4 million of cash and cash equivalents. This period balance represented a decrease of $12 million from the same date in fiscal year 2022. The reason for this decrease was primarily due to costs associated with our operations, particularly drilling our appraisal wells. As of April 30, 2024, we had $19.7 million of cash and cash equivalents.

 

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H&P Convertible Note

In June 2024, we issued the Convertible Note to H&P with an original principal amount of $9.4 million. The Convertible Note was issued in exchange for all undrawn existing convertible note obligations with H&P and is guaranteed by all of our wholly-owned subsidiaries. The Convertible Note accrues interest at a rate of 5.5% per annum, which is payable at our option in cash or in-kind, on a quarterly basis.

The Convertible Note is our senior unsecured indebtedness, ranking equally in right of payment with any present and future senior indebtedness of ours, and ranking senior in right of payment to any present and future subordinated indebtedness of ours.

In connection with the consummation of a bona fide underwritten public offering of our common stock (a) in which such stock is listed on the NYSE or the NASDAQ Stock Market, and (b) the gross proceeds of which are equal to or greater than $100,000,000 (a “Qualifying IPO”), the full principal amount of the Convertible Note will automatically convert into a number of shares of common stock equal to the quotient obtained by dividing (a) the principal amount of Convertible Note, plus accrued but unpaid interest, by (b) the product of (i) the initial public offering price per share of our common stock and (ii) 0.8 (such number of shares of common stock, the “Conversion Shares”). If we consummate an initial public offering that is not a Qualifying IPO, the holder of the Convertible Note may, at its option, convert all of its Convertible Note into a number of shares of common stock equal to the Conversion Shares. Except in connection with an initial public offering, the Convertible Note will not be convertible.

To the extent the Convertible Note is not converted in connection with an initial public offering, we may redeem the Convertible Note in full at any time after the closing date of the initial public offering, at a redemption price equal to the principal amount of Convertible Note, plus accrued but unpaid interest to the date of redemption.

The Convertible Note contains transfer restrictions and has customary provisions relating to events of default. The Convertible Note also grants the holder thereof certain information and registration rights.

Capital Commitments

We had the following five-year capital commitments as of March 31, 2024 and June 30, 2023 which are not recognized as liabilities or payable in the consolidated statement of financial position (all dollar amounts are presented in thousands):

 

		March 31,				June 30,
		2024				2023				Change
Capital commitments:
Sweetpea Petroleum Pty Ltd (“Sweetpea”)			$23,221			$	42,465			$	(19,244	)
EP 161			2,613				2,652				(39	)
Beetaloo Joint Venture			53,407				54,209				(802	)

Sweetpea Commitments

As of March 31, 2024, Sweetpea committed to spend $23.2 million related to two licenses, EP 136 with total commitments of $13.9 million and EP 143 with total commitments of $9.3 million over the following five years.

Sweetpea’s current five-year minimum work requirements in EP 136 included the re-entry of a vertical well, sidetrack to drill a horizontal well, stimulate and test one exploration well, plus the assessment of petroleum resources by December 31, 2023. The application to vary the minimum work commitments, by removing this requirement to drill the horizontal well was submitted on September 1, 2023, to the Department of Industry,

 

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Tourism and Trade (“DITT”), was approved during the period. A renewal application for EP 136 was submitted to DITT on September 28, 2023, with a proposed expected work program commitment of $13.9 million, for the next exploration term (five years from January 2024 to December 2028). The renewal application remains under review by the DITT during which time the Company continues to have the right to explore. We have no reason to believe that the renewal will not be approved.

Sweetpea has current Year 1 minimum work requirements in EP 143 which include various desktop evaluations including subsurface studies, environmental assessments, design and planning of 2D seismic survey and progress of land access negotiations with pastoralist for regulated activities. The remaining committed spend for EP 143 of $9.1 million relates to Year 2 to Year 5 minimum work requirements over the period from May 2024 to April 2028.

EP 161

For the McArthur working interest in EP 161, we are obligated to contribute our share of expenses to uphold our stake in EP 161. Our commitment through March 2026 is $2.6 million based on the minimum work requirements. There are no minimum commitment requirements after March 2026.

Beetaloo Joint Venture

The terms of the Beetaloo Joint Venture necessitate specific work obligations through May 2028. These commitments include an expected spend of $53.4 million related to drilling and multi-stage hydraulic fracturing of five wells across EP 76 of $21.1 million, EP 98 of $11.3 million and EP 117 of $21.0 million as well as subsurface studies.

Cash Flows

The following table summarizes our cash flows for the periods indicated (in thousands):

 

		Nine Months ended March 31,												Year Ended June 30,
		2024				2023				Change				2023				2022				Change
Statement of Cash Flows:
Net cash used in operating activities		$	(10,494	)		$	(11,346	)		$	852			$	(12,804	)		$	(10,011	)		$	(2,793	)
Net cash used in investing activities			(45,362	)			(97,077	)			51,715				(107,465	)			(38,746	)			(68,719	)
Net cash from financing activities			76,145				105,554				(29,409	)			106,183				23,740				82,443

Net Cash Used in Operating Activities

Net cash used in operating activities for the nine months ended March 31, 2024 was $10.5 million, as compared to $11.3 million for the nine months ended March 31, 2023. In the nine months ended March 31, 2024, cash used in operating activities resulted from a net loss of $13.9 million and non-cash adjustments of $0.8 million pertaining to depreciation and amortization, stock-based compensation, accretion of asset retirement obligations and foreign exchange differences. Additionally, in the nine months ended March 31, 2024, net favorable changes in operating assets and liabilities totaled $2.6 million, primarily consisting of a $2.7 million increase in accounts payable and accrued expenses due to timing of our pay cycle during nine months ended March 31, 2024, a $0.2 million decrease in trade and other receivables, a $0.2 million increase in other non-current liabilities and $0.4 million increase in prepaid expenses and other assets.

In the nine months ended March 31, 2023, cash used in operating activities resulted from a net loss of $15.1 million and non-cash adjustments of $1.3 million pertaining to depreciation and amortization, stock-based compensation, accretion of asset retirement obligations and foreign exchange differences. Additionally, in the nine

 

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months ended March 31, 2023, net favorable changes in operating assets and liabilities totaled $2.4 million, primarily consisting of a $3.3 million increase in accounts payable and accrued expenses after acquisition of assets from Origin Energy during the nine months ended March 31, 2023, a $0.3 million increase in trade and other receivables, a $0.2 million increase in other non-current liabilities and $0.8 million increase in prepaid expenses and other assets.

Net cash used in operating activities for fiscal year 2023, totaled $12.8 million during which we incurred a net loss of $32.2 million, compared to net cash used in operating activities for fiscal year 2022 of $10.0 million, during which we incurred a net loss of $9.6 million. The net loss for fiscal year 2023 included the non-cash impacts of depreciation and amortization, loss on assets classified as held for sale, share based payments, and foreign exchange differences. The adjustments to reconcile cash flows for operating activities to net loss reflected $12.6 million in loss on assets classified as held for sale in fiscal year 2023 compared to none the prior year period. This loss was primarily due to a write down in value of two rigs held for sale and $5.7 million in accounts payable and accrued expenses for fiscal year 2023 compared to $(0.5) million the prior year primarily due to mobilization costs that have accrued in connection with the operation of the H&P FlexRig^®.

Net Cash Used in Investing Activities

For the nine months ended March 31, 2024, net cash used in investing activities was $45.4 million compared to $97.1 million for the nine months ended March 31, 2023. This change was primarily due to the acquisition of EPs 76, 98 and 117 in November 2022 and the remaining payments of three US-based rigs, transactions which did not recur in the nine months ended March 31, 2024.

For fiscal year 2023, net cash used in investing activities was $107.5 million compared to $38.7 million for fiscal year 2022. This change was primarily due to increased spend on exploration and evaluation activities of $73.7 million in connection with the drilling, completion and stimulation of our initial appraisal wells and the completion of the purchase of US based rigs and other investments, which increase was offset by proceeds from the sale of property, plant and equipment of $2.5 million due to the sale of one rig and $4.2 million from proceeds from government grants for exploration.

Net Cash From Financing Activities

For the nine months ended March 31, 2024, net cash received in financing activities was $76.1 million compared to $105.6 million for the nine months ended March 31, 2023. This change was primarily due to our completion of multiple capital raises in the nine months ended March 31, 2024, totaling $73.1 million and contributions from noncontrolling interest holders of $12.5 million in comparison to a completion of a private placement of ordinary shares of TR Ltd. for $88.7 million in gross proceeds on October 31, 2022 and contributions from noncontrolling interest holders of $20.9 million during the nine months ended March 31, 2023.

For fiscal year 2023, net cash received in financing activities was $106.2 million compared to $23.7 million received for fiscal year 2022. This change was primarily due to $88.7 million in proceeds from the issue of shares in connection with the Company’s capital raises in fiscal year 2023, compared to $25.0 million the prior year, along with $20.9 million attributable to contributions from noncontrolling interest holders in connection with investments by Daly Waters, compared to none the prior year.

Internal Controls and Procedures

As an emerging growth company, we are not currently required to comply with the SEC’s rules implementing Section 404 of the Sarbanes-Oxley Act, and therefore are not required to make a formal assessment of the effectiveness of our internal control over financial reporting for that purpose. Upon becoming a public company, we will be required to comply with the SEC’s rules implementing Section 302 of the SOX, which will require our management to certify financial and other information in our quarterly and annual reports and provide an annual management report on the effectiveness of our internal control over financial reporting.

 

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Though we will be required to disclose material changes made to our internal controls and procedures on a quarterly basis, we will not be required to make our first annual assessment of our internal control over financial reporting pursuant to Section 404 of the SOX until the year following our first annual report required to be filed with the SEC. We will not be required to have our independent registered public accounting firm attest to the effectiveness of our internal controls over financial reporting until our first annual report subsequent to our ceasing to be an “emerging growth company” within the meaning of Section 2(a)(19) of the Securities Act. See “Prospectus Summary—Emerging Growth Company Status.”

In connection with the audit of our financial statements for the fiscal years 2023 and 2022, and the review of our unaudited condensed consolidated financial statements for the nine months ended March 31, 2024, we identified deficiencies in our internal control over financial reporting, which in the aggregate, constituted a material weakness. We determined that in both fiscal years and the nine month period, we had deficiencies relating to insufficiently designed and operating internal controls over financial reporting, including: i) lack of sufficient evidence retained of the performance of internal controls, ii) insufficient resources in key accounting and finance roles leading to inadequate segregation of duties, iii) lack of manage access and manage change IT general controls over the cloud-based enterprise resource planning system, and iv) accounting for complex transactions in accordance with US GAAP, which in the aggregate constitute a material weakness.

As part of our plan to address this material weakness, we are performing a full review of our processes and internal controls. We have implemented, and plan to continue to implement, new controls and processes. We will also provide training to control owners in support of an effective internal control framework, including how to sufficiently document and evidence the operation of internal controls. Finally, we are also evaluating our current enterprise resource planning system and considering options for replacing it with a new system to better support our financial reporting, including any related internal controls. While we have begun implementing a plan to remediate this material weakness, we cannot predict the success of such plan or the outcome of our assessment of this plan at this time. If our steps are insufficient to successfully remediate the material weakness and otherwise establish and maintain an effective system of internal control over financial reporting, the reliability of our financial reporting, investor confidence in us, and the value of our common stock could be materially and adversely affected. We can give no assurance that this implementation will remediate this deficiency in internal control or that additional material weaknesses in our internal control over financial reporting will not be identified in the future. Our failure to implement and maintain effective internal control over financial reporting could result in errors in our financial statements that could result in a restatement of our financial statements, or cause us to fail to meet our periodic reporting obligations. For as long as we are an “emerging growth company” under the JOBS Act, our independent registered public accounting firm will not be required to attest to the effectiveness of our internal control over financial reporting pursuant to Section 404.

Critical Accounting Policies and Estimates

Management’s discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of our financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of certain assets, liabilities and related disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The following critical accounting policies relate to the more significant estimates and assumptions used in preparing the consolidated financial statements.

Accounting for Natural Gas Properties

We are in the exploration stage and have not yet realized any revenues from our operations. We group our EPs into areas of interest according to geographical and geological attributes. We use the successful efforts method of accounting for expenditure incurred in each area of interest. Under this method, all general exploration and evaluation costs such as geological and geophysical costs are expensed as incurred. The direct costs of

 

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acquiring the rights to explore, drilling exploratory wells and evaluating the results of drilling are capitalized as exploration and evaluation assets (as a part of unproved properties) pending the determination of the success of the well. If a well does not result in a successful discovery, the previously capitalized costs are immediately expensed.

Impairment of Natural Gas Properties

Where an indicator of impairment exists for an unproved property and it is determined that future appraisal drilling or development activities are unlikely to occur, an impairment expense is recorded. Upon approval of the commercial development of a project, the exploration and evaluation asset is classified as a development asset. Once production commences, development assets are transferred to property, plant and equipment and are depleted using the unit-of-production method based upon estimates of proved developed reserves.

Joint Interest Activities

Some of the Company’s exploration, development and production activities are conducted jointly with other entities whereby each party holds an undivided interest in each asset and is proportionately liable for each liability in the scope of such arrangement. The Company has recognized its proportionate share of assets, liabilities, revenues and expenses in respect of such arrangements. These have been incorporated in the consolidated financial statements under the appropriate classifications.

Asset Retirement Obligations

Our asset retirement obligations (“AROs”) consist primarily of estimated future costs associated with the plugging, dismantling, removal, site reclamation and similar activities of natural gas properties in accordance with the requirements of respective EPs and with applicable local, state and federal laws. The discounted fair value of an ARO liability is required to be recognized in the period in which it is incurred, with the associated asset retirement cost capitalized as part of the carrying cost of the related long-lived asset. The recognition of an ARO requires numerous assumptions to be made by management regarding such factors as the estimated probabilities, amounts and timing of settlements; the credit-adjusted risk-free rate to be used; inflation rates; and future advances in technology. In periods subsequent to the initial measurement of the ARO, we recognize period-to-period changes in the liability resulting from the passage of time and revisions to either the timing or the amount of the original estimate of undiscounted cash flows. Increases in the ARO liability due to passage of time impact net income as accretion expense. The related capitalized cost, including revisions thereto, is charged to expense through depreciation and amortization over the life of the related asset.

Litigation and Environmental Contingencies

In the ordinary course of business, we may at times be subject to claims and legal actions. Management does not believe the impact of such matters will have a material adverse effect on our financial position or results of operations. We are subject to extensive federal, state, and local environmental laws and regulations, which may materially affect our operations. These laws, which are constantly changing, regulate the discharge of materials into the environment and may require us to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites.

In our acquisition of existing assets, we may not be aware of what environmental safeguards were taken during the time such assets were operated or the environmental liabilities associated with such assets.

We maintain comprehensive insurance coverage that we believe is adequate to mitigate the risk of any adverse financial effects associated with these risks. However, should it be determined that a liability exists with respect to any environmental cleanup, remediation, or restoration, the liability to cure such a violation could still fall upon us. No claim has been made, nor are we aware of any liability which we may have, as it relates to any material environmental cleanup, remediation, restoration, or the material violation of any rules or regulations relating thereto.

 

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Environmental expenditures are expensed or capitalized depending on their future economic benefit. Those related to an existing condition caused by past operations and that have no future economic benefits are expensed as incurred. Liabilities for expenditures of a noncapital nature are recorded when environmental assessment and/or remediation is probable, and the cost can be reasonably estimated.

Income Taxes

Income taxes are accounted for under the asset-and-liability method. Deferred tax assets and liabilities occur when differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carryforwards exist and are recognized for future tax consequences. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards 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. Current income tax recognized in the profit or loss is the tax payable or receivable on taxable income calculated using applicable income tax rates enacted as at reporting date. Current tax liabilities or assets are measured at the amounts expected to be paid or recovered from the relevant tax authority.

In assessing the probability that a deferred tax asset will be realized management considers whether it is more likely than not that all or some portion of the deferred tax assets will not be realized. We provide valuation allowances against deferred tax assets that are not considered more likely than not to be realized. The valuation of the deferred tax asset is dependent on, among other things, our ability to generate a sufficient level of future taxable income, in estimating future taxable income, we consider both positive and negative evidence in our assessment. If our estimate of future taxable income or tax strategies changes at any time in the future, we would record an adjustment to our valuation allowance. Recording such an adjustment could have a material effect on our financial condition or results of operations.

Deferred income tax relating to timing difference and unused tax losses are only recognized to the extent that it is probable that future tax profit will be available against which the benefits of the deferred tax asset can be utilized.

Stock-Based Compensation

We measure and recognize compensation expense related to our share-based compensation based on the estimated fair value of the awards. The fair value of the award is measured at the grant date and is recognized as an expense over the course of the award’s vesting period. The fair value of the stock options granted is estimated using either the Black-Scholes (for awards that vest based on service conditions) or the Monte-Carlo option-pricing model (for awards that vest based on market conditions). Each of these models include the share price at grant date, exercise price, the term of the right, expected price volatility of the underlying share, the expected dividend yield and the risk-free interest rate for the term of the right. The Monte Carlo model also incorporates a probability-based value impact of the market condition.

Recent Accounting Pronouncements

See “Note 2—Summary of Significant Accounting Policies” to our consolidated financial statements included elsewhere in this prospectus for more information about recent accounting pronouncements, the timing of their adoption, and our assessment, to the extent we have made one, of their potential impact on our financial condition and our results of operations.

Emerging Growth Company Status

Section 107 of the JOBS Act provides that an “emerging growth company” can take advantage of the extended transition period provided in Section 7(a)(2)(B) of the Securities Act of 1933 for complying with new or revised accounting standards. In other words, an “emerging growth company” can delay the adoption of

 

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certain accounting standards until those standards would otherwise apply to private companies. We intend to take advantage of all of the reduced reporting requirements and exemptions, including the longer phase-in periods for the adoption of new or revised financial accounting standards under Section 107 of the JOBS Act until we are no longer an emerging growth company. Our election to use the phase-in periods permitted by this election may make it difficult to compare our financial statements to those of non-emerging growth companies and other emerging growth companies that have opted out of the longer phase-in periods under Section 107 of the JOBS Act and who will comply with new or revised financial accounting standards. If we were to subsequently elect instead to comply with these public company effective dates, such election would be irrevocable pursuant to Section 107 of the JOBS Act.

Quantitative and Qualitative Disclosure About Market Risk

Commodity Price Risk

If and when we commence production, we will have market risk exposure in the price we receive for our natural gas production. Pricing is primarily driven by spot market prices applicable to Australia and East and South Asia. Pricing for natural gas and NGLs has historically been volatile and unpredictable, and we expect this volatility to continue in the future. The prices we will receive for our production depend on many factors outside of our control, including volatility in the differences between product prices at sales points and the applicable index price.

Due to the historical volatility of commodity prices, we may in the future enter into various derivative instruments to manage our exposure to volatility of commodity market prices. We may use options (including floors and collars) and fixed price swaps to mitigate the impact of downward swings in commodity prices to our cash flow. All contracts will be settled with cash and would not require the delivery of physical volumes to satisfy settlement. While in times of higher commodity prices this strategy may result in our having lower net cash inflows than we would otherwise have if we had not utilized these instruments, management believes the risk reduction benefits of such a strategy would outweigh the potential costs.

Foreign Currency Risk

Our financial results are reported in U.S. dollars. As our functional currency is the Australian dollar, we are exposed to foreign exchange risk, mainly with the U.S. dollar, which is the currency in which we receive much of our revenue and incur many of our expenses. As of June 30, 2023, 90% of our $7.1 million cash and cash equivalents were denominated in currencies other than the U.S. dollar. We have not historically used financial derivatives and we endeavor to achieve risk mitigation through natural hedges. These natural hedges may include the maintenance of a U.S. dollar bank account and bank accounts in any other currency to which we may have significant exposure in the future to facilitate the settlement of invoices in these currencies.

Interest Rate Risk

There are no material interest rate risk exposures as of the date of this prospectus. We may borrow under fixed rate and variable rate debt instruments that give rise to interest rate risk. Our objective in borrowing under fixed or variable rate debt is to satisfy capital requirements while minimizing our costs of capital.

Counterparty and Customer Credit Risk

If and when we commence production, we will sell our natural gas to a limited group of customers. If any significant customer of ours should have credit or financial problems resulting in an inability to purchase natural gas, it could have a material adverse effect on our business, financial condition, results of operations and cash flows. Additionally, if any significant vendor, joint venture partner or strategic partner of ours should have financial problems or operational delays, it could have a material adverse effect on our business, financial condition, results of operations and cash flows.

 

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INDUSTRY

The production of oil, natural gas and natural gas liquids plays a vital role in Australia’s present-day economy. Australia is a net exporter of energy, exporting approximately three-quarters of its domestic gas production. Australia’s geographic proximity to the large growing economies of South and East Asia, especially India and China, provide a logistical advantage and often higher commodity prices versus other commodity exporting nations like the United States. Australia’s status as a developed OECD economy also enables the participants in the oil and gas sector to attract capital investment, skilled labor and technology. This dual attraction of political and economic stability and economic security built on the export of natural resources creates an attractive jurisdiction for investment. According to the Australian Government Department of Foreign Affairs and Trade, in 2022, natural gas was the third largest export product of Australia valued at over A$90 billion during calendar year 2022.

Australian Natural Gas and Natural Gas Liquids Reserves

Australia’s hydrocarbon reserves are weighted towards natural gas. According to Geoscience Australia, Australia had ~19,439 Mmboe of proved plus probable natural gas reserves as of December 2021, of which 74% was conventional and 26% unconventional and, it is the seventh largest gas producer in the world by volume.

Geoscience Australia uses definitions promulgated by the Petroleum Resources Management System, under which, “proved reserves” are those with a reasonable certainty of being recovered, which means a high degree of confidence that the volumes will be recovered, and “probable reserves” are volumes that are defined as “less likely to be recovered than proved, but more certain to be recovered than “possible reserves.” These definitions are not comparable to the definitions of “proved reserves” and “probable reserves” used by us and the SEC, which definitions are available herein under the headings “Glossary of Certain Natural Gas Terms.” See “Risk Factors—Risks Related to Our Business and Industry—Numerous uncertainties exist in estimating quantities of proved and possible reserves and any such estimates may be inaccurate.”

Below is a map of the primary oil and natural gas basins in Australia as well as the key LNG projects:

 

Source: Australia: a Review of Gas Transfer Pricing Arrangements—Global LNG Hub (2023).

According to Geoscience Australia, about 93% of conventional gas resources are located on the North West Shelf with gas produced from the Northern Carnarvon, Browse and Bonaparte basins providing feedstock to seven LNG projects (Gorgon, Wheatstone, North West Shelf, Pluto, Prelude, Ichthys and Darwin) as well as the domestic market. These figures reflect only conventional reserves and offshore discoveries and do not include the Beetaloo. The Beetaloo is an unconventional gas basin and while the results to date have been promising, the Beetaloo has yet to book any meaningful reserves.

 

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The following diagram illustrates the sources of Australia’s total natural gas production in petajoules and how it was consumed during 2022.

 

Note: Components may not sum due to rounding. Natural gas power plants include some generation by other economic sectors.

Source: DCCEEW (2023) Australian Energy Statistics.

The Australian Domestic Natural Gas Market

Historically, the Australian domestic natural gas market has consisted of three separate regional markets, separated on the basis of productive natural gas basins and pipelines that supply them, which include:

 

•

East Coast Domestic Gas Market: The East Coast domestic market consists of Australia’s eastern and southern states and territories (including Queensland, New South Wales, Victoria, South Australia, Tasmania and the Australian Capital Territory), which are connected by a single natural gas grid. The East Coast accounted for approximately 51.3% of domestic natural gas consumption in 2022. The natural gas basins that currently supply this market approximately contain around one-third of Australia’s natural gas reserves.

 

•

The Northern Territory Domestic Market: The Northern Territory market is Australia’s smallest domestic market and accounted for 6.9% of domestic natural gas consumption in 2022. The Northern Territory natural gas market was connected to the East Coast market in 2019 when the Northern Gas Pipeline was opened between Tennant Creek in the Northern Territory and Mt. Isa in Queensland. Prior to this, there was no interconnectivity between these markets. The majority of natural gas used in the Northern Territory is supplied from the offshore Blacktip gas field and onshore Mereenie gas/condensate field. Recently, production from Blacktip, which is the largest supplier to the Territory, has declined and been unable to recover to historic levels following a 2023 appraisal program. This provides Tamboran with an immediate domestic opportunity.

 

•

West Coast Domestic Gas Market: The West Coast domestic market accounted for 41.8% of domestic natural gas consumption in 2022. Demand in the West Coast market is predominantly driven by industrial users such as mining operations.

The growth in LNG exports has resulted in higher natural gas prices and concerns of domestic natural gas shortfalls, particularly on the East Coast of Australia.

 

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East Coast Gas Market Overview

The competitive landscape for domestic natural gas supply in the East Coast natural gas market has been significantly impacted by the development of three LNG export terminals in Gladstone, Queensland over the past decade (GLNG, APLNG, and QCLNG). Prior to these facilities coming online, domestic producers had drilled a significant number of coal seam gas wells in Queensland to meet anticipated demand, lowering the prevailing market price for domestic consumers to approximately A$3 per Mcf. However, after the facilities came online and began exporting gas, domestic consumers saw a price increase of 3-5x and the risk of shortages became prevalent.

The following chart illustrates the Australian Electricity Market Operator’s (AEMO) natural gas consumption forecast, broken down by consumer type for all Australian states (except Western Australia), which demonstrates the vast majority of domestic natural gas production throughout the forecasted 2042 period being exported as LNG, resulting in potential supply shortages on the East Coast. These supply shortages may be exacerbated by potential increases in natural gas-powered electricity generation.

Actual and forecast total annual natural gas consumption, all sectors, Orchestrated Step Change (1.8°C)

 

Note: The 2022 GSOO did not include the Northern Territory as a participating GSOO jurisdiction. The Northern Territory is included in actual natural gas consumption from 2020 onwards and in the 2023 forecasts. Source: Actual and forecast total annual natural gas consumption, all sectors, Orchestrated Step Change scenario (1.8°C), 2016-42 (PJ), AEMO, Gas Statement of Opportunities, March 2023.

East Coast Gas Market Pricing

Natural gas prices have remained high in Australia relative to other OECD countries. Most domestic natural gas is typically sold under contracts with fixed pricing indexed to inflation. Spot natural gas prices reflect the balance between demand and supply of natural gas at a particular delivery point supplying the market at a particular time. Because the volumes available for spot sales are typically small, wholesale prices can be volatile and can be an unreliable indicator of underlying natural gas supply and demand fundamentals.

Since the commencement of LNG exports from Queensland in 2015, East Coast wholesale domestic natural gas prices have been broadly consistent with the ‘LNG netback price’, which is defined as the price an LNG seller receives minus the costs of liquefying and transporting the natural gas to the buyer (Wallumbilla is the principal natural gas supply hub in Queensland). The East Coast LNG facilities have excess capacity, so any oversupply of natural gas in the East Coast market has potential access to the Asian LNG market via spot LNG sales, helping to stabilize prices.

 

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The following chart illustrates the domestic gas price between producers and retailers in the Australian East Coast for the years 2022 and 2023:

Gas commodity prices (2024$/GJ) in the east coast gas market

 

Source: ACCC Gas Inquiry 2017-2040 Interim update on east coast gas market December 2023

The following chart illustrates the LNG netback and Wallumbilla prices from January 2016 to October 2023:

LNG Netback and Wallumbilla Prices (A$/GJ)

 

Source: LNG netback price data from ACCC Gas Inquiry 2017-2030, LNG netback price series (October 2023); Wallumbilla price data from Australian Energy Regulator, Wallumbilla Gas Supply Hub – trade volume and VWA prices by pipeline.

East Coast Gas Market Supply / Demand Deficit

These market fundamentals indicate a shortage of identifiable natural gas available to both fully utilize existing LNG capacity and to meet projected domestic energy needs.

 

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As highlighted in the AEMO’s 2023 GSOO, new supply options are forecast to be required to meet demand from 2027 through the end of the projected period, with a forecasted supply gap in 2027 to be between 0 Mmboe and 1.96 Mmboe, depending on weather conditions. In AEMO’s assessment, to maintain adequate domestic supply, natural gas supply that would otherwise be contracted for LNG export would be required to be diverted to domestic consumers from 2027, which in turn would cause LNG supply shortages that would necessitate development of new supply options.

The below chart illustrates this fundamental supply gap, including the assumption that natural gas is diverted from LNG export to the East Coast.

Projected annual adequacy in southern regions Orchestrated Step Change (1.8°C) scenario, with existing, committed and anticipated developments, 2023-42 (PJ)

 

Source: AEMO, 2023 Gas Statement of Opportunities.

Potential additional domestic sources of natural gas that would supply the eastern Australian natural gas market over the next ten to fifteen years, outside of LNG diversions, include additional coal seam gas (“CSG”) from Queensland, CSG from New South Wales, the Beetaloo/McArthur shales of the Northern Territory/Queensland and South Nicholson shales. In addition, several domestic energy suppliers have proposed LNG regasification terminals on the East Coast, which would enable additional supply to be sourced from LNG cargoes either from the Northern Australia exporters or overseas. Notably, contracts for these volumes into the East Coast market are not subject to the Federal Government price cap (see the section entitled Business—Environmental Matters and Regulation), which supports the viability of these projects. Albeit, to date all LNG regasification terminal projects have been delayed by availability of equipment and regulatory approvals.

 

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East Coast Gas Market Infrastructure

The following chart illustrates Australia’s East Coast natural gas market infrastructure:

 

 

Source: DISR National Gas Infrastructure Plan Interim Report 2021. ACCC Gas Inquiry 2017-2040 Interim update on east coast gas market December 2023.

 

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The East Coast transmission pipeline system is an interconnected grid covering Queensland, New South Wales, Victoria, South Australia, Tasmania and the Australian Capital Territory. In recent years, most transmission pipelines in the East Coast grid have been made bi-directional which means that gas produced in Queensland can be used in Tasmania and gas produced in the south of Australia can be sent to Gladstone for export. This interconnectedness has enabled more flexible arrangements for trading in gas, resulting in gas being supplied where needed.

The Northern Territory has the AGP which takes gas from fields in the Amadeus Basin near Alice Springs to Darwin. The Northern Gas Pipeline in the Northern Territory connects its gas fields to the East Coast network, linking the AGP to the Carpentaria pipeline near Mount Isa in Queensland.

The Liquefied Natural Gas Industry

LNG involves natural gas being cooled to lower than -260° Fahrenheit (-161.5 Celsius) and converted to a liquid that is 1/600th of its original size to enable it to be transported efficiently by ship to an import destination, where it is regasified for use. Historically, the largest customers for LNG have been the large north Asian economies such as China, Japan, South Korea and Taiwan, which use natural gas for both electricity generation and in various industrial processes, but have limited domestic natural gas supplies.

Since the Russian invasion of Ukraine, LNG has assumed new significance to Europe as an alternative source of natural gas originating from Russia that has historically been transported to Europe via pipeline. The Russian invasion of Ukraine and other recent geopolitical developments have highlighted the importance to energy-importing nations of securing reliable energy supplies, and LNG imports from reliable exporters can be a key contributor to energy security.

According to EIA and CEDIGAZ, global trade in LNG set a record high in 2022, averaging 388 Mtpa, a 5% increase compared with 2021. The International Energy Agency (“IEA”) forecasts global LNG trade to grow at an average annual rate of just under 4% between 2021 and 2025 to 437 Mtpa. The IEA forecasts that LNG imports into Europe will grow by 51% (or 39 Mtpa) over this period as European nations attempt to reduce their dependence on Russian gas, while Asian imports will grow 11% (or 29 Mtpa) over the same period.

Australia’s Liquefied Natural Gas Industry

Australia was the world’s largest volume exporter of LNG in 2022, overtaking Qatar. Given Australia’s relative geographic proximity to major Asian markets, Asian energy demand continues to be the main driver of Australia’s LNG industry. In 2023, Japan was the top export destination, by value, for Australian LNG (37% of Australian liquid natural gas export value), followed by China (22%) and Korea (20%).

 

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The following chart illustrates the world’s largest LNG producers in 2022:

2022 LNG exports and market share by export market (million tons)

 

Source: International Gas Union 2023 World LNG Report

Today, Australia has three geographically separate hubs for LNG exports – Gladstone, Darwin and the North West Shelf. The North West Shelf and Darwin LNG export terminals have historically been supplied by offshore conventional gas fields while the three LNG export terminals in Gladstone have been supplied with both conventional and unconventional sources (i.e., coal seam gas).

The relative geographic proximity of the existing and planned LNG export terminals in northern Australia to Asian markets provides Northern Territory operators with competitive advantages over current LNG suppliers from the Middle East and the United States. For example, LNG can be delivered from Darwin to Singapore in less than four days, and to China and Japan within six days. Shipments from the Middle East must travel through the Red Sea, while shipments from United States must travel around the southern cape of Africa or through the Panama Canal, all of which often result in delays or higher costs. The cost to ship LNG from Darwin to Japan is approximately 40% lower than the cost to ship LNG from Qatar. Additionally, spot prices in certain South and East Asian regional markets have historically been significantly higher than spot prices at Henry Hub. For example, during the calendar year ended 2023, spot prices for natural gas delivered to Henry Hub averaged $2.54 per MMBtu while over that same period the JKM continuous futures price for LNG averaged $14.45 per MMBtu.

Recent Policy Updates

Temporary Pause on Certain Authorizations to Export LNG from the United States

In January 2024, the Biden Administration announced a temporary pause on the U.S. Department of Energy’s (“DOE”) review of pending applications for authorization to export LNG to countries that have not entered into free trade agreements (“FTAs”) with the United States (so-called non-FTA countries). The temporary pause will last until the DOE can update its underlying analyses for authorizations using more current data to account for considerations like potential energy cost increases for consumers and manufacturers or the latest assessment of the impact of GHG. The temporary pause is not expected to affect LNG exports that have already been authorized but may have a material impact on the operations of U.S.-based LNG exporters.

 

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Australian Domestic Gas Security Mechanism

In 2017, in response to a serious risk of a natural gas supply shortfall in the domestic market, the Commonwealth Government established the Australian Domestic Gas Security Mechanism (“ADGSM”). The ADGSM allows Australia’s Minister for Resources to restrict LNG exports if the Minister has reasonable grounds to believe that there will not be a sufficient supply of natural gas for Australian consumers during the year unless exports are controlled and that exports of LNG would contribute to that lack of supply. In April 2023, a number of reforms to the ADGSM were introduced, including that the Commonwealth Government can now consider whether to activate the ADGSM quarterly, rather than annually. As of today, the ADGSM has not been activated.

Price Cap / Mandatory Code of Conduct

In response to a period of high domestic natural gas prices, largely driven by unusually high demand from electricity generators due to the underperformance of coal fired generation, in December 2022, the Federal Government imposed a price cap of A$12.00 per GJ of natural gas for new wholesale natural gas supply agreements between East Coast and Northern Territory natural gas producers and commercial and industrial users for a period of 12 months. In July 2023, the government introduced a mandatory code of conduct for natural gas producers, which, among other things, extends the price cap until at least July 2025, subject to a number of exemptions that are designed to incentivize additional supply to the domestic market on reasonable terms. The government has provided several exemptions to industry producers and the operators of new gas projects like Tamboran. Tamboran has applied and been granted an exemption from the gas price cap.

Carbon Safeguard Mechanism

With effect from July 1, 2023, the Federal Government has reformed Australia’s National Greenhouse and Energy Reporting (Safeguard Mechanism) Rule 2015 (Cth) (the “Safeguard Mechanism”), which sets emissions limits (known as baselines) on facilities emitting greater than 100,000 tons of CO2-e annually. The reforms include a requirement that all emissions from the Beetaloo be offset once the 100,000 tons CO2-e trigger is exceeded. For more information see “Business–Environmental Matters and Regulation.”

 

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BUSINESS

Overview

We are an early stage, growth-driven independent natural gas exploration and production company focused on an integrated approach to the commercial development of the natural gas resources in the Beetaloo located within the Northern Territory of Australia. We and our working interest partners have EPs to approximately 4.7 million contiguous gross acres (1.9 million net acres to Tamboran), and are currently the largest acreage holder in the Beetaloo. We believe natural gas will play a significant role in the transition to cleaner energy and are committed to supporting the global energy transition by developing commercial production of natural gas in the Beetaloo with net zero equity Scope 1 and 2 emissions.

Corporate History and Corporate Reorganization

TR Ltd. was founded in 2009 and is headquartered in Sydney, Australia. Previously, we held interests in EPs and applications in the Northern Territory, South Australia, Western Australia, Northern Ireland, Republic of Ireland and Botswana. Joel Riddle become the Managing Director and CEO during 2013, and the Company chose to focus on the Northern Territory and relinquished or divested its rights to explore in other jurisdictions. TR Ltd. subsequently admitted its ordinary shares for official quotation on the ASX in July 2021.

We were incorporated in the State of Delaware on October 3, 2023 for the purposes of effecting the corporate reorganization. We received all the issued and outstanding shares of TR Ltd. pursuant to a statutory scheme of arrangement under Part 5.1 of the Australian Corporations Act. The scheme of arrangement was approved by the shareholders of TR Ltd. at a general meeting of shareholders held on December 1, 2023. Following shareholder approval, the scheme of arrangement was approved by the Federal Court of Australia on December 6, 2023.

Pursuant to the corporate reorganization, we issued to the shareholders of TR Ltd. one CHESS Depositary Interest for each ordinary share of TR Ltd. Additionally, we amended the terms of each of the outstanding options to acquire ordinary shares of TR Ltd. so that the entitlements of option holders to be issued ordinary shares in TR Ltd. instead became entitlements to be issued CDIs in the Company. We maintain an ASX listing for our CDIs, with each CDI representing beneficial ownership in 1/200^th of a share of our common stock. Holders of CDIs are able to trade their CDIs on the ASX. Following completion of the corporate reorganization, TR Ltd. became a wholly owned subsidiary of the Company.

 

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The Beetaloo

The Beetaloo, an area of approximately seven million acres (10,800 square miles), is believed to contain significant quantities of unconventional natural gas resources and has geological properties believed to be comparable to that found in the Marcellus Shale of the Appalachian Basin in the northeastern United States. The Beetaloo is a structural component of the Greater McArthur Basin in the Northern Territory and is located approximately 300 miles southeast of Darwin, Northern Territory. The following image illustrates the location of the Beetaloo:

 

Located in the Greater McArthur Basin, the Beetaloo is structurally subdivided into three geographical areas and two major structural highs. The north-south trending, structurally complex Daly Waters Arch (west) and the structurally benign Arnold Arch (east) divide the area into three major depocenters, referred to here as the Sever Sub-Basin, the Core area, and the OT Downs Sub-Basin from west to east, respectively.

The Northern Territory owns all petroleum resources, both onshore and in coastal waters in that jurisdiction. The Northern Territory Department of Industry, Tourism and Trade administers and regulates petroleum permit tenures and activities in these areas, including natural gas resource exploration and development permitting as well as permits for the construction and operation of oil and gas facilities and transmission pipelines.

Historical E&P Activity in the Beetaloo

In 1984, CRA Exploration, a subsidiary of Pacific Oil and Gas (“POG”), acquired acreage north of the core of the Beetaloo on the basis of the identification of “live” oil in stratigraphic wells and geological mapping that proved the existence of at least one working petroleum system. POG subsequently picked up permits farther south over the core of the Beetaloo, and, from 1987 to 1993, drilled 12 wells close to the core of the Beetaloo, providing multiple penetrations of the primary source rock in the Proterozoic Roper Group, the Velkerri Formation (“Velkerri”), and organic rich shales within the Velkerri. POG also completed 2D seismic surveys over a number of areas during this period.

Early drilling targeting conventional structures met limited success, but these early wells did confirm the extent of the organic rich rocks in the Velkerri (subsequently named the Amungee Member). Eventually POG withdrew from all permits and interest in the Beetaloo waned among operators for the remainder of the 1990s. Sweetpea Corporation (“Sweetpea”) believed the Beetaloo remained an economically viable drilling location,

 

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and, accordingly, applied for EPs in many of the same areas previously covered by POG’s permits. In the 2000s, Sweetpea was granted permits over the vast majority of the prospective core. Sweetpea’s strategy included a combination of conventional oil and gas plays, and tight gas and basin-centered gas plays (prior to the widespread recognition of the potential of “shale gas” that Mitchell Energy demonstrated in the Barnett Shale in Texas).

Sweetpea, later acquired by TR Ltd. in July 2020, collected over 400 miles of 2D seismic data before drilling an initial well, Shenandoah 1 in 2007, to a depth of approximately 5,000 feet, which was ultimately suspended. Falcon eventually became operator of four of the “Sweetpea exploration permits” (EPs 76, 98, 99, and 117) in 2009. Falcon re-entered and deepened Shenandoah 1 (deepened well re-named Shenandoah 1A) to approximately 8,900 feet in 2009 and completed the first hydraulic fracture stimulation of a shale gas target in Australia in 2011, and successfully flow-tested two zones within the Amungee Member of the Velkerri and one zone in the Kyalla.

In 2011, Falcon partnered with Hess Corporation (“Hess”) as a farminee for works on EPs 76, 99, 98 and 117. The Hess-Falcon joint venture proceeded to collect over 2,000 miles of 2D seismic data in 2011 and 2012.

A subsequent joint venture with Sasol (the “Beetaloo Joint Venture”) drilled four key wells in 2015 and 2016; three vertical wells (Kalala S-1, Amungee NW-1 (“A1V”), and Beetaloo W-1) and one horizontal well (Amungee NW-1H (“A1H”)), from the A1V vertical appraisal well. The vertical wells all penetrated the oldest prospective interval of the Amungee Member, the A Shale, to the youngest and shallowest, the C Shale.

The Beetaloo W-1 well was drilled around 60 miles south of previous key intersections. The Beetaloo Joint Venture subsequently drilled, completed and tested the A1H well during 2015 and 2016, providing evidence of a material volume of moveable gas lay within that portion of the Beetaloo and made the Amungee area a target for further appraisal.

From 2014 to 2015, Pangaea Resources also acquired 2D seismic data and drilled a number of wells in the western most extents of the Beetaloo. The well drilled by Pangaea Resources in this area demonstrated continuity of the Amungee Member to the west of the core, although substantially shallower than at Tanumbirini-#1 (“T1V”).

Around the same time, TR Ltd. farmed-out 75% of EP 161 to Santos. In 2014, Santos drilled the T1V well to a depth of almost 13,000 feet in one of the deepest parts of the Beetaloo, informally known as the OT Downs Sub-basin. The T1V well provided a new eastern stratigraphic control point and demonstrated continuity of the source rock properties of the Amungee Member of the Velkerri.

On September 14, 2016 the NT Government announced a moratorium on hydraulic fracturing of onshore unconventional reservoirs including the use of hydraulic fracturing for exploration, extraction, and production. As a result, between 2016 and 2020, minimal activity was undertaken in the Beetaloo as the independent Scientific Inquiry into Hydraulic Fracturing of Onshore Unconventional Reservoirs in the Northern Territory was undertaken. However, since 2020, EP 161 and Beetaloo Joint Venture have again become active with the drilling of key wells providing further evidence of the potential commerciality of the Velkerri.

Our Assets Within the Beetaloo

We currently hold interests in six EPs and one EP(A), all of which are contiguous to one another and located in the Beetaloo in the Northern Territory in Australia. Our key assets are (i) a 25% non-operated working interest in EP 161, (ii) a 38.75% working interest in EPs 76, 98 and 117, where we are the operator, and (iii) a 100% working interest in EPs 136, 143 and EP(A) 197, where we are the operator. We have an undivided 50% interest in EPs covering 4 million gross (1.5 million net) acres through TB1, EPs 76, 98 and 117. The deepest portions of the Beetaloo, and our strategic near-term focus are those areas covered by EPs 76, 98, 117, 136, 143 and 161.

 

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The following is a summary of the gross and net undeveloped acres we have interests in, along with the associated expiration dates of such permits, as of March 31, 2024. All of our acreage is undeveloped. We consider all of our acreage as undeveloped, since even though we classify one of our appraisal wells as “productive,” acreage has not been allocated or assigned to such well.

 

Exploration Permit		Gross / Net Acres		Expiration Date
EP 76		346,700 / 134,346		May 30, 2028
EP 98		2,312,262 / 896,000		May 30, 2028
EP 117		1,380,864 / 535,085		May 30, 2028
EP 136		207,000 / 207,000		Pending extension
EP 143		512,000 / 512,000		March 4, 2028
EP 161		512,000 / 128,000		March 20, 2026
EP(A) 197		192,000 / 192,000		N/A

Our assets are depicted by the colored areas in the map of the Beetaloo below, with the deepest “core” regions of the Beetaloo (the darker blues) in the west being the focus of our development:

 

We have participated in six appraisal wells over the last three fiscal years, four of which we drilled as the operator:

 

Well Name

Operator

Non-Operator(s)

Exploration Permit

Date Drilled

Tamboran Working Interest

Tanumbirini #2 (“T2H”)

Santos

Tamboran

161

May 2021

25

%

Tanumbirini #3 (“T3H”)

Santos

Tamboran

161

August 2021

25

%

Maverick 1V (“M1V”)

Tamboran

N/A

136

August 2022

100

%

Amungee NW-2H (“A2H”)

Tamboran

DWE & FOG

98

November 2022

38.75

%

Shenandoah South 1H (“SS1H”)

Tamboran

DWE & FOG

117

August 2023

38.75

%

Amungee NW 3H (“A3H”)

Tamboran

DWE & FOG

98

September 2023

38.75

%

 

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As of March 31, 2024, we operate four gross natural gas wells (approximately 2.2 net natural gas wells) and are non-operated partners on two gross natural gas wells (approximately 0.5 net natural gas wells). In the last three fiscal years, we have drilled, as operator, one gross (approximately 0.4 net) natural gas well that we believe is currently productive, the SS1H. We also drilled, as operator, three gross (approximately 1.8 net) and participated in the drilling, as non-operator, of two gross (0.5 net) wells that we do not currently believe are productive. None of our wells drilled in the past three fiscal years were development wells. We successfully completed a stimulation program on the SS1H well in December 2023 and the well is currently undergoing flow testing. The A3H well is capable of being stimulated but is currently drilled but uncompleted. No additional wells are undergoing or awaiting completion.

Exploration Permits 76, 98 and 117

On November 9, 2022, TB1, an entity 50/50 owned by TR West (our wholly owned subsidiary), and Daly Waters and governed by a joint venture and shareholders agreement, completed the purchase of a 77.5% working interest in EPs 76, 98 and 117 for upfront cash consideration of A$60 million plus a future production royalty, providing us an undivided 50% (i.e., 38.75% working interest) in each these EPs. Falcon Oil and Gas Australia Ltd holds the remaining 22.5% non-operating working interest. The operation and management of TB1 is governed by a joint venture and shareholders agreement. See “—EPs 76, 96, and 117 Joint Venture and Shareholders Agreement” for a description of the material terms of the agreement governing TB1.

Following completion of the acquisition, we successfully drilled and cased the A2H well in the EP 98 permit. The well reached a total depth of approximately 12,700 feet in 38 days (spud to total depth). The well included an approximately 4,200 foot horizontal section within the target formation of the Middle Velkerri B Shale. The A2H well intersected the formation at approximately 8,000 feet (vertical depth) and encountered significant natural gas shows within the formation, in line with pre-drill expectations.

The A2H well is the first well in the Beetaloo targeting the Middle Velkerri B Shale to have been drilled and cased with 5-¹⁄₂ inch casing. We believe this is the optimal casing size to place a high intensity stimulation and is comparable to modern U.S. unconventional drilling designs. We successfully completed a stimulation program in March 2023. A total of 25 stages were successfully stimulated across an approximately 3,350-foot horizontal section within the Middle Velkerri B Shale.

In March 2023, we contracted Silver City Drilling to undertake completion operations at the A2H well, including the installation of production tubing. Operations to install production tubing were completed in late-April 2023 and the well was re-opened in preparation to commence flow testing.

In June 2023, we announced interim results from A2H. Modelling and independent third-party analysis of fluids recovered from the well identified a potential zone of reduced permeability, or a “skin” inhibiting natural gas and water flow resulting from water contamination. In late June 2023, the well was flowing at 0.83 MMcf/d and averaged 0.97 MMcf/d over the first 50 days. The well was shut-in during July 2023 in preparation for potential remediation activities, subject to joint venture approval.

In early July 2023, H&P’s FlexRig^® was successfully mobilized to the SS1H well location targeting the deeper Middle Velkerri B Shale in EP 117. We commenced drilling of the SS1H well in early August 2023 and intersected a 295-foot interval of Middle Velkerri B Shale. This represents the thickest section of Middle Velkerri B Shale seen in the Beetaloo depocenter to date. Logging of the well also showed high quality Middle Velkerri B Shale with strong dry gas shows. Logging of the Middle Velkerri B Shale formation also indicated higher porosity and gas saturation relative to offset wells, consistent with the Marcellus Shale of the Appalachian Basin in the U.S. In February 2024, SS1H delivered an IP30 flow rate of 3.2 MMcf/d over the 1,644-foot, 10-stage stimulated length within the Middle Velkerri B Shale, an IP60 flow rate of 3.0 MMcf/d, and an IP90 flow rate of 2.9 MMcf/d. Normalizing the production rate for a 10,000-foot horizontal lateral, the IP30 flow rate in SS1H would have been approximately 19.5 MMcf/d, the IP60 flow rate would have been approximately 18.4 MMcf/d, and the IP90 flow rate would have been approximately 17.8 MMcf/d.

 

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During the drilling activities at SS1H, the Company completed its capital commitments under the Farmin Agreement with Falcon (as defined below) to earn title to a 77.5% working interest (38.75% each) and operatorship of the EP 76, 98 and 117 permits. Falcon elected to fund their 22.5% share of ongoing costs in the SS1H and A3H drilling activities. On March 4, 2024, Falcon, the owner of the remaining 22.5% interest in the assets, capped its participation to 5% in the Beetaloo Joint Ventures’ SS2 and the two wells in the 2024 drilling program. The two wells in the 2024 drilling program will create two DSUs totaling 51,200 gross acres around the new SS2 well pad. The 51,200 gross acre area has the potential to accommodate 23 well pads, or 138 total wells based on six wells drilled per pad. We believe the two DSUs will be more than enough to accommodate all wells associated with the Shenandoah South Pilot Project and over 100 wells for future development phases. On March 21, 2024, TB1 Operator agreed to pick up Falcon’s interest, increasing the Company’s working interest to at least 47.5% in SS2 and the two wells in the 2024 drilling program. TB1 Operator will carry Falcon for up to A$3.75 million gross (A$1.875 million net) for SS2 after June 30, 2024. For further information regarding the Beetaloo Joint Operating Agreement between TB1 Operator and Falcon see “—Agreements Relating to the Development of our Assets—Falcon Agreements.”

In September 2023, we commenced drilling of the A3H well from the same well pad as the A2H well to follow up earlier drilling results. The well was successfully drilled in less than 18 days, the fastest well drilled with a horizontal section in the Beetaloo to date. The activities were completed 20 days faster than the shallower A2H well and approximately 30% lower cost, demonstrating the increased drilling efficiency of the H&P FlexRig®. The A3H well is capable of being stimulated but is currently drilled and uncompleted.

Daly Waters Royalty holds an ORRI of 2.3% of the petroleum produced from the land over which the EP 76, 98 and 117 was originally granted.

EP 76 will remain in effect until at least May 30, 2028; EP 98 will remain in effect until at least May 30, 2028; and EP 117 will remain in effect until May 30, 2028.

Exploration Permit 161

EP 161 is a polygonal shaped tract that spans north-south with varying widths having a total area of approximately 2.5 million acres (4,000 square miles). We estimate a prospective fairway acreage in EP 161, which is located on the eastern portion of the Beetaloo, of approximately 512,000 acres (800 square miles). We hold a non-operated 25% working interest in EP 161 through our wholly-owned subsidiary Tamboran (McArthur) Pty Ltd, with Santos holding the remaining 75% working interest as operator. Pursuant to our joint operating agreement with Santos QNT, we are required to contribute our proportionate share of expenditures in order to maintain our interest in EP 161.

In the fourth quarter of 2019, the T1V vertical well was successfully fracture stimulated and flow tested. A “Declaration of Discovery” was submitted to the NT Government on December 19, 2019 and accepted by the NT Government in April 2020. In 2020, a 130-day flow test conducted for EP 161 exceeded 1.2 MMcf/d and settled at .4 MMcf/d with minimal decline. The flow test was ended prematurely due to the shelter-in-place orders in the Northern Territory during the COVID-19 pandemic. After being shut in for over 160 days, the well was reopened in the last quarter of 2020 and initially flowed 10 MMcf/d ultimately achieving an average flow rate of 2.3 MMcf/d during the first 90 hours of testing.

In 2021, Santos successfully drilled and fracture stimulated the T2H and T3H short lateral wells into the Middle Velkerri B shale. The T2H well delivered an average IP30 flow rate of 2.1 MMcf/d over a 2,200 foot completed horizontal section (normalized at 9.5 MMcf/d over 10,000-foot lateral lengths). The T2H well had already produced 0.27 Bcf prior to the installation of production tubing.

In December 2022, Santos completed IP90 testing of the T2H and T3H wells following the installation of production tubing. Each reached IP90 of 1.6 and 2.1 MMcf/d, respectively (normalized at 7.4 and 10.7 MMcf/d, respectively, over 10,000-foot lateral lengths). Operations were subsequently suspended following the completion of the on-site activities.

 

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In July 2023, we completed analysis of two Tanumbirini flow tests. The productivity of the wells, which flow tested the Middle Velkerri B Shale at depths of more than 11,000 feet total vertical depth, exhibited higher flowing tubing pressures, thus continuing to validate our internal view that the “core” deeper areas of the Beetaloo will be more productive and validate further evaluation.

We have capitalized $23.5 million of expenditures with respect to the exploration and development of EP 161 as of March 31, 2024. We anticipate minimal spending for the remainder of the fiscal year.

A native title agreement for EP 161 exists in the form of a Co-Operation and Exploration Agreement for Exploration Permit EP(A)161, between Tamboran Resources Pty Ltd, the Native Title Parties, and NLC dated April 4, 2012 (“EP 161 Exploration Agreement”). Elements of the EP 161 Exploration Agreement include but are not limited to Native Title Parties’ consent for the underlying petroleum exploration permit application (“EP(A)”), and assignment and confidentiality provisions. Further elements of the EP 161 Exploration Agreement provide for exploration payments, environmental protection and rehabilitation, and Aboriginal employment, training and business opportunities. It does not authorize production. Further agreement with the Native Title Party will be required, but the EP 161 Exploration Agreement sets out a process for negotiation of a production agreement and a baseline agreement as to royalties and compensation for production.

Daly Waters Royalty holds an ORRI of 2.3% of the petroleum produced from the land over which the EP 161 was originally granted.

EP 161 will remain in effect until at least March 20, 2026.

Exploration Permit 136 and 143; Exploration Permit Application 197

On July 25, 2020, we entered into the Share Exchange Agreement with Longview Petroleum LLC and Tamboran McArthur under which the Company, through its wholly owned subsidiary, acquired 100% of the issued share capital of Sweetpea from Longview. That transaction was completed on May 21, 2021 after receiving approval from TR Ltd.’s shareholders and Ministerial approval. Sweetpea is the registered holder of 100% of the working interests in EPs 136 and 143, and has also applied for EP(A) 197 (“Sweetpea Assets”).

EP 136 lies adjacent to EP 161 in the core of the Beetaloo and based on seismic data has geology we believe is comparable to EP 161’s successful T1V discovery well. EP 136 is comprised of approximately 1 million acres (1,600 square miles) within a mostly rectangular shaped tract that spans north-south with the greatest extent approximately 100 miles and as much as 16 miles in width. EP 136 is 100% owned and operated by Tamboran. During 2023, Ensign rig 970 was mobilized to the M1V well pad in EP 136. The M1V well was spudded in mid-September 2022 and reached a total depth of 10,000 feet in early October 2023, in 18.3 days. Following the completion of logging, the M1V well was successfully cased and suspended to enable potential future re-entry and side track for multi-stage stimulation work. The Ensign 970 was rigged down and released in mid-December 2022.

EP 143 is an irregular block that is comprised of approximately 512,000 acres (800 square miles) that extends approximately 27 miles west to east and 34 miles north to south. Development of EP 143 is not the current focus of our development plan. Accordingly, we intend to expend only such capital as is required for the maintenance of the permit for future assessment. We will assess prospectivity of EP 143 to determine future development opportunities. EP 143 is 100% owned and operated by Tamboran.

EP(A) 197 adjoins a portion of the northern boundary of EP 143. The irregular rectangular block contains approximately 192,000 acres (300 square miles). As with EP 143, the development of EP(A) 197 is not the current focus of our development plan. Our plans for EP(A) 197 consist of completing the acquisition of the EP, obtaining its grant and then maintenance of the permit for future assessment of petroleum resources. We have until October 31, 2025 to negotiate and receive the consent of the traditional Aboriginal owners of the land and

 

99

progress agreements with the relevant land council representing the traditional Aboriginal owners, as required under the Aboriginal Land Rights (Northern Territory) Act 1976 (Cth), as described further in “Business—Environmental Matters and Regulation.” Once we receive such consent for exploration then we can apply formally for the grant of an EP. Like EP 143, we will assess prospectivity of the EP(A) 197 to determine future development opportunities. EP(A)197 is 100% owned by Tamboran.

On July 23, 2020, as part of our acquisition of Sweetpea, we granted an ORRI equal to an undivided 8% of 8/8ths of all petroleum produced from EP 136, 143 and EP(A) 197 (and the land over which each of those permits was originally granted), the area of mutual interest (“AMI”) to Tom Dugan Family Limited Partnership, LLP, Territory Oil & Gas, LLC; and Malcolm John Gerrard (together the Bayless Group) and Longview (“Bayless ORRIs”). On July 23, 2020, Sweetpea, the Bayless Group and Longview entered into an ORRI Termination Agreement (“Termination Agreement”). Under the Termination Agreement, the Bayless Group and Longview granted Sweetpea three options to require the Bayless Group to progressively reduce the 8% ORRI as follows: (i) upon payment by Sweetpea of an “Initial Option Fee” of $732,025 and the issue of 3,095,475 fully paid shares in Tamboran by July 1, 2021, the 8% ORRI would reduce to a 4% ORRI (“Initial Option”); and (ii) upon payment by Sweetpea of an “Additional Option Fee” of $250,000 and: (A) $7,000,000 by July 1, 2023, the 4% ORRI would reduce to 2%; and (B) $7,000,000 by July 1, 2025, the 2% ORRI would reduce to a 1% ORRI. As of the date of this prospectus, the Additional Option Fee of $250,000 has been paid. However, the payments of $7,000,000 by July 1, 2023 and $7,000,000 by July 1, 2025 have not been made.

On or around May 19, 2021, Sweetpea exercised the Initial Option and the 8% ORRI reduced to 4%. The reduction in the 8% ORRI was formalized by execution of certain Amendment Agreements dated May 19, 2021 by the Bayless Group and Sweetpea. On or around May 19, 2021, the Additional Option Fee was paid. Each of the Bayless ORRIs was coupled with the obligation relating to the AMI, to grant additional ORRIs where additional acreage is acquired by Sweetpea within the AMI (the “AMI Obligation”). The Company as purchaser of the Sweetpea Assets is required to assume the AMI Obligation. On July 23, 2020, the Bayless Group, Sweetpea and Longview entered into a Limited Waiver Agreement under which the Bayless Group and Longview granted to Sweetpea an option to purchase a “Limited Waiver” in respect to the AMI Obligation. The effect of the Limited Waiver was that, except where clause 3(c) of the Limited Waiver Agreement applies, no person will be obliged to comply with the AMI Obligation or require that any other person assume the AMI Obligation. Clause 3(c) of the Limited Waiver Agreement provides that the Limited Waiver will never apply for the benefit of a “Longview Entity.” A “Longview Entity” is defined to mean: (i) Longview; (ii) any entity in which Longview, David N. Siegel and Robert L. Telles individually collectively, directly or indirectly, hold or are the beneficial owns of 35% or more of the equity securities; or (iii) David N. Siegel or Robert L. Telles individually. On or around July 1, 2021, Sweetpea purchased the Limited Waiver and exercised its option to cancel the AMI Obligation.

Sweetpea has granted PetroHunter Energy Corporation (“Petrohunter”) an ORRI of 2% (“Petrohunter ORRI”) of the petroleum produced from the land over which the EP 136 and EP 143 were originally granted and EP(A) 197 was applied for. The Petrohunter ORRI contains an option for Sweetpea to reduce the royalty to 1% on payment of $1,000,000 to Petrohunter by June 17, 2023 and further extinguish by agreement the remaining 1% for an amount equal to 3% of the consideration paid by the Company for Sweetpea. As of the date of this prospectus no such payments have been made.

Sweetpea has granted an undivided 1% ORRI in favor of Jeffrey J Rooney as trustee of the Siegel Dynasty Trust of all petroleum produced from the Sweetpea Assets and the land subject to the Sweetpea Assets. The beneficiaries of the Siegel Dynasty Trust are Emily Siegel and Robert Siegel, who are the children of David N. Siegel, who is a director of Longview, a director of TR Ltd. and a director of the Company. The ORRI extends to all extensions or renewals of each Sweetpea Assets (as applicable) and to any production licenses or subsequent rights to produce petroleum, from those lands, that are granted or issued to Sweetpea, its successors or assignees.

Daly Waters Royalty holds an ORRI of 2.3% of the petroleum produced from the land over which the EP 136, 143, and EP(A) 197 was originally granted.

 

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An EP renewal application to extend EP 136 for a further five years was submitted to the DITT on September 28, 2023 and is pending approval. The permit is deemed to continue in force until the Minister makes a determination on the renewal application. EP 143 will remain in effect until at least March 4, 2028.

Middle Arm Development

In early June 2023, we announced the NT Government awarded us exclusive use of over an approximately 420 acre site for construction of an LNG export terminal within the MASD. The MASD acreage was allocated to us on an exclusive basis for a term extending to December 31, 2024, allowing us to progress a Concept Select engineering phase, which commenced in July 2023, and was completed in the first quarter of 2024. We believe the associated infrastructure at MASD provides us the opportunity to initially export up to 6.9 Mtpa through our proposed NTLNG development. We intend to seek strategic partners in financing and developing the proposed NTLNG development.

In June 2023, we announced two non-binding MOUs with bp and Shell to each purchase up to 2.2 Mtpa over a 20-year period from the proposed NTLNG development.

Our Business Plan

Our business plan consists of three distinct phases in the development of the Beetaloo. The focus of the first phase will be on the transition from exploration activities to the commercialization of our Beetaloo properties. In furtherance of that goal, we expect to drill and complete an additional two wells in 2024, four wells in 2025, progress a project to design and construct a 40 MMcf/d compression and dehydration plant, and progress a ~20 mile pipeline to the existing gas pipeline network (collectively, the “Shenandoah South Pilot Project”). Our goal is joint venture approval of the Shenandoah South Pilot Project in mid-2024 and believe we can achieve ~40 MMcf/d (gross) plateau production in 1H 2026. Based on our petrophysical analysis from completed appraisal wells, we have already identified what we believe to be the most productive acreage and shale benches to target for our first stage wells. The two wells in the 2024 drilling program will create two DSUs totaling 51,200 gross acres around the new SS2 well pad. The 51,200 gross acre area has the potential to accommodate 23 well pads, or 138 total wells based on six wells drilled per pad. We believe the two DSUs will be more than enough to accommodate all wells associated with the Shenandoah South Pilot Project and over 100 wells for future development phases.

Beginning in 2026, subject to approval by the Minister responsible for the Petroleum Act, we plan to market the gas produced from our initial wells in the Northern Territory. While the natural gas production from these wells will be modest, the revenue generated from sales of these volumes is expected to offset our overhead (but not operating) expenses. The Beetaloo is currently serviced by two open-access pipelines that are sized to accommodate the ~60 MMcf/d local market and also provide access to the deeper Australian East Coast market. We have early development agreements with APA Group, Australia’s largest gas infrastructure company by volume whereby APA has committed to evaluate a project to build, own, and operate, and subject to the definitive terms of development agreements, to construct, a new ~20 mile pipeline to connect our wells to the existing gas transmission network through the AGP and the 40 MMcf/d compression facility at Shenandoah South that would upgrade the raw gas to meet sales gas quality. We estimate the capital required to deliver the first development phase to production will be approximately $125 million (A$195 million) to $165 million (A$250 million) net to Tamboran. We expect to spend approximately $70 million (A$105 million) to $80 million (A$125 million) net on drilling and completion costs, $10 million (A$15 million) to $13 million (A$20 million) net on costs related to the development of the compression facility, $23 million (A$35 million) to $30 million (A$45 million) net on related pad construction and gathering infrastructure and $26 million (A$40 million) to $40 million (A$60 million) net on transaction and general and administrative expenses. We intend to fund these costs with the proceeds of this offering, cash on hand, as well as additional future capital raising efforts, if required. Gas sales are expected to commence from our wells in the first quarter of 2026. Through the course of the completion of the additional six wells, we believe we can reduce costs through greater efficiency while simultaneously providing us sufficient data to confirm the estimated ultimate recovery (“EUR”) for wells drilled in the Beetaloo. Our development plan seeks to efficiently drill from pad wells,

 

101

utilizing long laterals and modern completion techniques employed by U.S. onshore operators. We expect the cost structure and production profiles achieved with our initial wells to lead to a financial investment decision (“FID”) for an initial large scale drilling program in our second phase.

 

 

102

The second phase of our business plan involves building our drilling program to produce natural gas to supply the Australian East Coast and Northern Territory markets. We anticipate drilling as many as 100 to 200 wells during this second phase, which may commence as early as 2026, subject to the completion of certain third-party infrastructure projects. The current pipeline infrastructure, the AGP in the Northern Territory, can export ~50 MMcf/d northbound and ~50 MMcf/d to the East Coast. We have a set of early development agreements with APA whereby APA has committed to evaluate a project to build, own, and operate, and subject to the definitive terms of development agreements, to construct, a new approximately 1,000 mile pipeline to connect the Beetaloo to the main trunk line of the East Coast Gas Grid. The new pipeline is anticipated to reduce the cost of transporting gas from the Northern Territory to the East Coast by up to 50%. We have non-binding letters of intent from six of Australia’s largest energy retailers with respect to the purchase of natural gas from us, with an aggregate volume of 875 MMcf/d for a period of up to 10 to 15 years.

 

 

In the third phase of our business plan, following commercialization of the Beetaloo, we intend to drill additional wells with the intent to supply natural gas for export through the existing plants in Darwin and our proposed 6.9 Mtpa NTLNG project to South and East Asian markets. Depending on the volume of unused capacity then available at the existing LNG plants in Darwin, this phase may occur before or in parallel with the second phase. In consideration of our proposed NTLNG project, the government of the Northern Territory of Australia has awarded us exclusive use of an approximately 420 acre site for a term extending to December 31, 2024 for a concept select study with respect to our proposed NTLNG project within the MASD precinct. We completed the concept select study in the first quarter of 2024, which affirmed the feasibility of commencement of commissioning of the first LNG train in 2030, and are progressing toward binding land agreements with the NT Government. The MASD, an industrial complex adjacent to the city of Darwin, seeks to provide infrastructure focused on low emissions operations, for the export, processing, storage, shipping and rail transportation of LNG and other hydrocarbons. The MASD precinct is currently home to an export hub with two existing and operational LNG export terminals, the Darwin LNG terminal with a capacity of 3.7 Mtpa and the

 

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Ichthys LNG terminal with a capacity of 8.9 Mtpa. The Australian government has committed A$1.5 billion in investments commencing in 2025 to further develop MASD infrastructure and access, including dredging of the deepwater port, construction of road and rail access and distribution of electricity. We estimate total time required for construction of the NTLNG project to be between three to five years and have a non-binding memorandum of understanding with each of bp and Shell for 20-year LNG purchase contracts. We could additionally sell our future production if, for example, our NTLNG project faces any delays, through the two existing and operational LNG terminals near Darwin, subject to capacity constraints. We intend to seek additional strategic partners for the financing and development of these and other infrastructure projects.

Our business and development plans include the continuous focus on reducing cost while increasing production efficiencies. We believe that importing U.S. unconventional drilling and completion techniques, best-practices and technology, together with the right personnel, will reduce the incremental cost to drill and complete each subsequent well. We currently have on contract one H&P FlexRig^® until August 2025 with a 10-year option to contract for up to five additional rigs. We have entered into a two-year preferred arrangement with Liberty Energy to provide us dedicated frac fleets and personnel on market terms (as reasonably determined by the Beetaloo Joint Venture). The drilling and stimulation costs for our most recent SS1H well was $19.4 million (A$28.9 million), and we expect an additional $5.1 million (A$7.7 million) is required to fund the 90-day extended production test. We estimate the drilling and completion costs of each of the remainder of our initial wells will be approximately $26 million gross as a result of our application of U.S. practices, longer lateral lengths and increased number of stimulated stages. We are targeting long-term development well costs of $16 million per well at depths of approximately 9,800 feet with 60 stages. We believe by taking advantage of efficiencies related to economies of scale, continued infrastructure development in the Beetaloo and resource maturation, over time we will significantly reduce the cost to drill and complete our wells.

Agreements Relating to the Development of our Assets

Falcon Agreements

The TB1 Operator is a party to a farmin agreement with Falcon (the “Falcon Agreement”) pursuant to which the TB1 Operator owns a 77.5% operated working interest and Falcon owns a 22.5% non-operated working interest in EPs 76, 98, and 117. Under the terms of the Falcon Agreement, the TB1 Operator will undertake operations on the properties and bear the costs of the work program up to an overall spending cap of A$263.8 million, following which the parties shall contribute in respect of their proportionate interests in TB1. In August 2023, the spending cap was reached.

The TB1 Operator is also a party to a joint operating agreement with Falcon (the “Beetaloo JOA”). The Beetaloo JOA establishes the respective rights and obligations of the TB1 Operator and Falcon in connection with EP 76, 98, and 117. The TB1 Operator is designated as the operator under the Beetaloo JOA. Pursuant to the Beetaloo JOA, Falcon capped its participation to 5% in the Shenandoah South Pilot Project and TB1 has agreed to pick up Falcon’s interest, increasing the Company’s working interest to at least 47.5% in the Beetaloo Joint Venture’s SS2 and the two wells in the 2024 drilling program. TB1 Operator will carry Falcon for up to A$3.75 million gross (A$1.875 million net) for SS2 after June 30, 2024.

TB1 Joint Venture Agreement

We are a member of TB1, a 50/50 joint venture, through our wholly owned subsidiary, TR West, with Daly Waters, an entity controlled by Bryan Sheffield. TB1 in turn wholly owns TB1 Operator (formerly known as Origin B2). Capitalized terms used but not defined in this section or elsewhere in this prospectus have the meanings ascribed to them in the applicable agreement.

Under the terms of TB1’s amended and restated joint venture and shareholders agreement dated June 3, 2024 (the “TB1 Joint Venture Agreement”), TB1 is governed by a board (the “TB1 Board”) of not more than six

 

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members, with the number of directors appointed by the joint venture parties in respect of their proportion of equity ownership. The parties have no right to designate directors at such time as such party’s ownership falls below 10% of the outstanding equity interests in TB1. The TB1 Board currently consists of four board members; two designated by the Company (Joel Riddle and Patrick Elliott) and two designated by Daly Waters (Stephanie Reed and Blake London).

We are the manager of TB1 with responsibility to carry out day to day operations, including managing the activities of the TB1 Operator in operating the properties and complying with the Beetaloo JOA and Falcon Agreement. The manager is also responsible for submitting work plans and budgets with respect to the development of the properties by the TB1 Operator, in accordance with the terms of the Beetaloo JOA, and submitting production and retention licenses. Under the TB1 Joint Venture Agreement, we have agreed to use all reasonable endeavors to apply for a production license for certain permit areas, where justified by appraisal results, by June 30, 2025. See “—Falcon Agreements.”

Special Approvals

Under the TB1 Joint Venture Agreement, TB1 is not permitted to take any of the following actions without the affirmative consent of 75% or more of the total number of votes cast by directors present and entitled to vote at a duly convened meeting of the TB1 Board:

 

•

entering into any partnership or joint venture;

 

•

entering into any new borrowing facility in excess of $5 million;

 

•

decisions to dispose of or vary the terms of a permit or apply for any new permit;

 

•

decisions to proceed to development or production;

 

•

sell or otherwise dispose of assets valued at A$5 million or more;

 

•

entering into any material agreement with any director, shareholder of any affiliate of the foregoing;

 

•

approval of any work program and budget, or any revision of the scope of any approved work program and budget, or approval of variances to any such work program or budget;

 

•

approval under the Beetaloo JOA of any authority for expenditure in excess of $250,000;

 

•

approval to award any contract for Joint Operations over $250,000; and

 

•

all decisions under, or any amendment or variation of, the Gas Sale Agreement between TB1 and Origin Retail dated September 18, 2022 (the “Origin GSA”).

In addition, without the prior approval of shareholders holding 75% or more of the total number of votes cast by shareholders present and entitled to vote at a duly convened meeting of the shareholders, TB1 will not take any of the following actions:

 

•

amendment of the constitution;

 

•

loans or financial accommodations with shareholders;

 

•

incurring liability under any guarantee or indemnity;

 

•

issuing new shares or other securities not contemplated by the TB1 Joint Venture Agreement;

 

•

changing the issued share capital;

 

•

cessation of or material alteration of the scale of operations;

 

•

disposal or encumbering of the shares in a subsidiary; and

 

•

seeking an initial public offering on any securities exchange.

 

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Sole Funding Period

Under the TB1 Joint Venture Agreement, we have agreed to fund TB1’s 77.5% working interest in the permits for Operations conducted during the sole funding period, including the cost to drill, multi-stage hydraulic fracture stimulate and flow-test the A2H and SS1H wells for at least 60 days. The sole funding period finalized on March 25, 2024, after completing the flow test of the SS1H well for a total of 60-days. Following the sole funding period, each of the joint venture parties is required to fund its respective equity share of working capital costs in proportion with its equity interest in TB1, in accordance with the cash call schedule described in an approved work program and budget.

Cash Call and Dilution

If a party fails to make a required cash call, the other party may elect to make the contribution on such defaulting party’s behalf and cause the contributed amount to constitute debt owing from the non-contribution party bearing interest at consistent with the Agreed Interest Rate defined in the Beetaloo JOA, defined generally as average quote rate for 90-day Australian bills of exchange plus 4%. Alternately, a party may make the contribution on such defaulting party’s behalf and cause the contributed amount to constitute additional equity, receiving additional shares in TB1 at a value of A$1.00 per share.

Technical Committee

The shareholders shall maintain a committee to supervise and be responsible for providing recommendations to the Board in respect of technical and other matters relating to the exploration, development and operation of the TB1 Operator. If the Technical Committee is split on any recommendations to be made to the Board, members of the Technical Committee representing Daly Waters shall have the right to make the final decision on which such recommendations shall be made to the TB1 Board.

Conversion to Checkerboard

Checkerboard Strategy means an approach to dealing with the Permits whereby Tamboran and Daly Waters pursue a split of 50% of TB1 Operator’s interest in the Permits such that the title and ownership of the Permits will be split evenly, as between Tamboran and Daly Waters, in terms of equity interest and operated blocks in respect of the specific area within the Permit Area.

At any time following approval of a Development Plan, either joint venture party may direct the Technical Committee to provide a recommendation to the TB1 Board in relation to the proposed Checkerboard Strategy and the Technical Committee must, acting in good faith, consider the best approach to implementing the Checkerboard Strategy.

Approximately 60 NT Graticular Blocks of roughly 22,115 acres each will be divided into Checkerboard Blocks of 10 NT Graticular Blocks each. These Checkerboard Blocks will be split between us and Daly Waters by a process where Daly Waters will have first choice of Checkerboard Block, and Tamboran and Daly Waters shall thereafter go back and forth in selecting each successive remaining Checkerboard Block. These Checkerboard Blocks will be progressed to Production Licenses by December 31, 2024 as currently agreed to in the TB1 Joint Venture Agreement.

In their respective checkerboard blocks, Daly Waters and Tamboran will each hold a direct interest in the individual Production Licenses in an equivalent proportion to TB1 Operator’s participating interests in the Beetaloo Joint Venture. By way of example, if TB1 Operator holds a 77.5% interest in the Beetaloo Joint Venture at this time, then either Daly Waters or Tamboran shall hold a direct 77.5% interest in the Production License (with Falcon holding the other 22.5%).

 

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The foregoing does not apply to the First Strategic Development Area, an area described as 4 NT Graticular Blocks of roughly 22,115 acres each that includes the SS-1 well pad and its DSU acreage of 20,480 acres, which will remain held by TB1 Operator and subject to the TB1 Joint Venture Agreement and the Beetaloo JOA.

If the Checkerboard Strategy is not implemented by December 31, 2024, due to either (i) ministerial approval to effectuate the Checkerboard Strategy having not been obtained or (ii) a new joint venture not being approved with respect to joint operations in the permit area pursuant to the Beetaloo JOA, Tamboran must, at its option, either pay Daly Waters a cash amount equal $7.5 million, issue CDIs to Daly Waters with a value of $15 million based on the weighted average price of the CDIs or issue common stock with a value of $7.5 million, where the value of each share of common stock is equal to the value of the issue price of common stock issued in an initial public offering raising gross proceeds of at least $100,000,000. The obligation to implement the Checkerboard Strategy does not cease with the payment.

Conversion of Daly Waters’ interest in Tamboran to a direct interest in the Beetaloo Joint Venture

At any time during the period beginning on the date that the sole funding period ended (March 25, 2024) until December 31, 2026, if the Checkerboard Strategy remains uncompleted Daly Waters may elect to have us buy-back or otherwise convert its 50% interest in TB1 into a 38.75% direct participating interest in the Beetaloo Joint Venture.

Following the end of any fiscal year, provided profits are available for distribution, TB1 must pay a dividend in respect of each of TB1’s members’ respective equity interest. TB1 will distribute all profits, provided that profits may be retained to meet any capital adequacy or solvency requirements and is able to pay its debts as and when they fall due, or as required by applicable law or specified in an approved work plan.

Each of the members of TB1 have certain pre-emptive rights. Each joint venture party has a right of first offer and right to match any third party offers in connection with any proposed transfer of equity interests in TB1. The TB1 Joint Venture Agreement also permits a party to “drag” the other in a sale of the joint venture if that selling party holds at least 75% of the equity interests in TB1. Each party likewise has the right to participate or tag along in any sale by the other party of 75% or more of the equity interests.

Upon the occurrence of any default under the TB1 Joint Venture Agreement (which includes the failure to pay amounts due), the other party may elect to purchase all of the defaulting party’s equity in TB1 at a price equal to 95% of fair market value.

McArthur Joint Operating Agreement

On December 11, 2012, we entered into a joint operating agreement (the “McArthur JOA”) with Santos QNT under which Santos serves as the operator of EP 161. The McArthur JOA will remain in effect as long as the permits remain in force in the names of two or more parties. Our current working interest under the McArthur JOA is 25%. We must continue to contribute our proportionate share of expenditures to maintain our interest in the underlying permits. Before incurring any commitment or expenditure greater than A$2,000,000, Santos must receive approval from an operating committee consisting of a representative from each of Tamboran and Santos. We have committed approximately $2.7 million through March 2026 based on minimum work requirements.

We hold a non-operated 25% working interest in EP 161 through our wholly owned subsidiary Tamboran (McArthur) Pty Ltd, with Santos holding the remaining 75% working interest as operator. Pursuant to our joint operating agreement with Santos QNT, we are required to contribute our proportionate share of expenditures in order to maintain our interest in EP 161.

Drilling Contract with H&P

On September 9, 2022, we, through a wholly owned subsidiary, entered into a drilling contract with H&P (as amended, the “Drilling Contract”). The term of the Drilling Contract commenced on July 1, 2023. Under the

 

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Drilling Contract, and associated agreements, we granted H&P a 10-year preferential right to provide drilling services to us in connection with our exploration and production activities in Australia. We paid H&P a mobilization fee of $15,000 per day plus all associated costs for shipping from Houston, Texas to the first location being the SS1H well pad. The total import cost for Rig 469 was $7.5 million. We will also pay an operating rate of $39,500 per day. The contract also provides for us to pay H&P a demobilization fee equal to the documented trucking and mobilization costs to a mutually-agreed location in Australia. Under the Drilling Contract we have an option to contract for up to five additional rigs. On July 31, 2023, we, through a wholly owned subsidiary, entered into a Rig Sharing and Temporary Assignment and Assumption Agreement with the wholly owned subsidiary of TB1 to utilize the Drilling Contract for the purposes of drilling the Beetaloo Joint Venture’s appraisal wells.

Strategic Arrangement with Liberty Energy Inc.

We have entered into a two-year preferred arrangement with Liberty Energy to provide us dedicated frac fleets and personnel on market terms (as reasonably determined by the Beetaloo Joint Venture), which includes Liberty Energy’s latest sand mining and handling management solution. We believe that a strategic arrangement with Liberty Energy will enable us to reduce delays typically experienced in transporting equipment to worksites, while increasing completion efficiencies and reducing costs. Liberty Energy is also partnering with us through its purchase, on December 14, 2023, of our CDIs for an aggregate consideration equal to $10.2 million (A$15.3 million). We do not have any obligations to purchase services from Liberty Energy under this arrangement.

APA Agreements

We entered into three framework agreements on December 15, 2023 with APA Group (collectively, the “APA Agreements”) to support the development of our Beetaloo assets and enable distribution of natural gas from our assets:

 

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Under the APA Partnering Agreement, we agreed to work exclusively with APA Group on pipeline projects in the Beetaloo, and subject to conditions being met, we may obtain an option to acquire up to 15% of any Beetaloo pipeline project in the lead up to a final investment decision.

 

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The Early Development Agreement Sturt Plateau Pipeline Project (the “SPP EDA”) progressed discussions relating to the construction of the Sturt Pipeline Project, a natural gas pipeline capable of transporting up to approximately 95 MMcf/d (the “SPP Pipeline Project”) from a proposed raw gas processing plant located near Shenandoah South to the AGP and the potential provision of gas transportation services on the AGP to enable connection of the Shenandoah South to the AGP. The SPP EDA contemplates completion of the SPP Pipeline Project by March of 2026. The delivery of the SPP Pipeline Project will be the subject of a future development agreement and the gas transport services will be the subject of a future gas transportation agreement. APA Group has commenced the Early Works defined in the SPP EDA, which include efforts to design and engineer the SPP Pipeline Project, obtain access and approvals, along with developing revised project schedules and estimates.

 

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The Early Development Agreement Beetaloo to East Coast Pipeline (the “BEC EDA”) progressed discussions relating to the construction of a large natural gas pipeline (the “BEC Pipeline Project”) to connect a central point in our Beetaloo acreage to the Australian east coast network of gas pipelines owned or operated by the APA Group (“East Coast Grid”) and the provision of gas transportation services on the BEC Pipeline Project to enable connection of the Beetaloo to the East Coast Grid. The delivery of the BEC Pipeline Project will be the subject of a future development agreement and the gas transport services will be the subject of a future gas transportation agreement. APA Group has commenced the Early Works defined in the BEC EDA, which include certain efforts to obtain access and approvals, along with developing revised project schedules and estimates.

Under the SPP EDA and BEC EDA, APA has agreed to continue evaluation of the proposed pipelines with early works expenditure of up to A$10 million on the basis that we continue to progress and achieve certain

 

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agreed milestones conditions, such as the availability of sufficient financial resources to drill additional wells and us taking material steps toward the drilling of additional wells. The APA Agreements are preliminary agreements related to the development of the projects, and as such, neither we nor APA Group will have material binding obligations until definitive agreements are signed.

Origin Retail Gas Sales Agreement

On September 18, 2022, the TB1 Operator entered into the Origin GSA whereby the TB1 Operator has agreed to supply, and Origin Retail has agreed to purchase up to 5.97 Mmboe per annum (2.99 Mmboe per annum net to Tamboran), gas sourced from EP 98, 76, or 117. The start date of the supply period under the Origin GSA must be between January 1, 2025 and December 31, 2028, and the end date is 10 years following the start date unless extended. Origin Retail is not obligated to perform under the Origin GSA until the TB1 Operator has satisfied certain conditions precedent, including making positive final investment decisions to proceed with the development of gas permits of a certain quantity sufficient to produce a minimum of ~30 MMcf/d; and to proceed with constructing a pipeline from those permits to any location with physical capacity to transport that volume; and all required regulatory approvals are received. We are not obligated to perform under the Origin GSA unless a quantity of ~50 MMcf/d or greater is produced.

Shell Letter of Intent

On June 23, 2023, we entered into a non-binding letter of intent with Shell, a subsidiary of Shell plc, regarding the potential purchase by Shell of up to 2.2 Mtpa of LNG from our proposed NTLNG project for a 20-year term. We intend to seek to enter into an exclusive LNG sale and purchase agreement (the “Shell SPA”). We plan to commence negotiations in July 2024, and hope to finalize the Shell SPA in 2025. The supply period under the Shell SPA would begin upon commercial production of LNG from the Beetaloo, which must begin by January 1, 2030, and effectiveness of the SPA is subject to a final investment decision of the NTLNG project by our board of directors by December 31, 2025, completion of new transportation infrastructure to enable the gas to be delivered to the East Coast market, technical and financial diligence by Shell, internal approvals from Shell’s management and board, regulatory approval, and mutually agreed upon and executed documentation.

BP Memorandum of Understanding

On May 19, 2023, we entered into a non-binding memorandum of understanding with bp regarding the potential purchase by bp of up to 2.2 Mtpa of LNG from our proposed NTLNG project for a 20-year term. We intend to seek to enter into negotiations for an exclusive LNG sale and purchase agreement (the “bp SPA”) beginning three months prior to the expected completion of the front-end engineering design and finalize the bp SPA by approximately December 2025. The supply period under the bp SPA would begin upon commercial production of LNG from the Beetaloo, and effectiveness of the bp SPA is subject to final investment decision of the NTLNG project by our board of directors by approximately December 2025.

NT Government Gas Sales Agreement

On April 23, 2024, the Beetaloo Joint Venture signed a long-term gas sales agreement (the “NT GSA”) to supply the NT Government with ~40 MMcf/d (~19 MMcf/d net to Tamboran) from the proposed Shenandoah South Pilot Project for an initial term of nine years, starting in H1 2026. The Buyer has an option to extend the NT GSA for a further 6.5 years through to 2042.

The NT GSA includes a number of conditions precedent that require satisfaction in order for the agreement to become binding. Specifically, the NT GSA is conditional on the Beetaloo Joint Venture entering into a binding gas transportation agreement with APA on the proposed Sturt Plateau Pipeline, a binding gas processing agreement for the proposed Sturt Plateau Compression Facility, reaching a final investment decision on the Shenandoah South Pilot Project which we anticipate occurring in mid-2024, and receiving key regulatory and

 

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stakeholder approvals. Once the NT GSA becomes binding, the Beetaloo Joint Venture is required to have the daily quantity of gas available each day. Should this not occur, and there is a shortfall, the Beetaloo Joint Venture may be liable to pay shortfall liquidated damages.

Other Letters of Intent

We have entered into non-binding letters of intent from six of Australia’s largest energy retailers with respect to the purchase of natural gas from us, with an aggregate 875 MMcf/d for a period of up to 10 to 15 years. We expect to negotiate definitive agreements with these counterparties as our operations further progress.

Customers and Marketing

We plan to market our natural gas under long-term agreements. Our ability to market natural gas will depend on many factors beyond our control, including the extent of domestic production and imports of oil and natural gas, available storage, the proximity of our natural gas production to pipelines and corresponding markets, the available capacity in such pipelines, the demand for natural gas and oil, the effects of weather, and the effects of state and federal regulation. There is no assurance that we will always be able to market all of our production or obtain favorable prices.

Seasonality

Weather conditions have a significant impact on the demand for natural gas used for heating loads and natural gas-fired power generation. Demand for natural gas is generally at its lowest during the spring and fall months and peaks during the summer and winter months. Demand in the winter season peaks due to residential and commercial heating load demand, while the summer season peaks due to cooling loads, which calls on increased natural gas fired power generation loads. However, seasonal anomalies such as warmer than normal winters or cooler than normal summers can lessen the magnitude of the seasonal fluctuations in demand. In addition, natural gas storage facilities are utilized to bring additional supply to the market that is utilized to meet peak demand levels during both winter and summer seasons. The Northern Territory also typically experiences greater rainfall from November to April. Although this season does present challenging conditions for operations, operators have drilled, stimulated and tested through the wet season successfully.

Competition

The oil and natural gas industry is intensely competitive, and we compete globally with other companies that have greater resources. Many of these companies not only explore for and produce natural gas, but also carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive oil and natural gas properties or to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may have a greater ability to continue exploration activities during periods of low natural gas market prices. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, because we have fewer financial and human resources than many companies in our industry, we may be at a disadvantage in evaluating and bidding for oil and natural gas properties.

There is also competition between natural gas producers and other industries producing energy and fuel, including coal, other petroleum products and renewables. Furthermore, competitive conditions may be substantially affected by various forms of energy legislation and/or regulation considered from time to time by the government of Australia. It is not possible to predict the nature of any such legislation or regulation which may ultimately be adopted or its effects upon our future operations. Such laws and regulations may substantially increase the costs of developing natural gas and may prevent or delay the commencement or continuation of a

 

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given operation. Our larger or more integrated competitors may be able to absorb the burden of existing, and any changes to, federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position.

Human Capital Resources

As of June 30, 2023, we had a total of 30 employees. We hire independent contractors on an as needed basis. We believe we have good relations with our employees. We and our employees are not members of any labor union. We prioritize local hiring for both employees and contractors, particularly in areas of field operations, to support employment opportunities in our local communities.

Safety and training

Safety is our highest priority, including the prevention of any releases from our operations. We conduct routine maintenance and inspections at our facilities, and we have established practices and operational infrastructure to control and mitigate potential spills or discharges. We also provide training to our staff and contractors that cover spill response and reporting and ensure our teams are fully trained on our response plan in the event of any releases. We believe these measures continue to strengthen our process safety culture. We have a full-time Senior Manager of Health, Safety and Environmental who is responsible for training, evaluation and risk mitigation as well as implementing safety measures.

Compensation and Benefits

We recognize that our employees are our most valuable resource and that we must provide competitive compensation to ensure we attract and retain top talent. We believe we offer competitive and comprehensive compensation and benefits packages that includes access to financial, health and wellness programs, a matched 401(k) plan, short-term and long-term incentive plans, medical, dental, and vision insurance coverage, and paid time off for holidays, sick leave, and vacation. We continue to survey and update our pay structure to stay competitive with our peers. Our compensation packages are reviewed annually by NFPCC Compensation Consulting, a leading independent global compensation consultant.

Sustainability and ESG

Sustainability is a central component of our ESG corporate strategy, including continued focus on the Company’s impact on the environment, and relationships with Traditional Owners, key stakeholders and employees. As an energy company with assets in the pre-development stage, we have the opportunity to integrate environment, community and social matters into the center of what the Company delivers. By focusing on the sustainable development of our Beetaloo natural gas project, we aim to grow local jobs, strengthen communities and deliver a positive social impact. We are committed to respecting the unique environment in the Northern Territory and working closely with the local communities to understand their diverse views on development and the impact on the environment. To highlight the importance of Sustainability and ESG, the Company has a Six-Pillar Sustainability Plan, which include: (i) Community: Partnering with local and host communities to share value through the creation of local jobs and business opportunities; (ii) Climate Change: Playing an effective role in the transition to a lower carbon economy through the production of low CO2 natural gas resources (primarily through committing to net zero equity Scope 1 and Scope 2 emissions and integrating renewable energy and carbon offsets into any development); (iii) Environment: Applying technologies to minimize environmental impacts; (iv) Health and Safety: Prioritizing the health and safety of people; (v) People: Aiming to attract, develop and retain a diverse, inclusive, and competent workforce; and (vi) Economic Sustainability: Generating economic growth and value for investors, employees, customers and communities. Under the Safeguard Mechanism (legislation.gov.au) provides regulations that shale gas facilities will have a “zero baseline” meaning they must have Net Zero Scope 1 emissions by law.

 

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Environmental Matters and Regulation

We are, and our future operations will be, subject to various stringent and complex international, foreign, federal, state and local environmental, health and safety laws and regulations governing matters including the emission and discharge of pollutants into the ground, air or water; the generation, storage, handling, use and transportation of regulated materials; and the health and safety of our employees. These laws and regulations may, among other things:

 

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require the acquisition of various approvals and permits before drilling or other regulated activities commence;

 

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enjoin some or all of the operations of facilities deemed not in compliance with permits or approvals;

 

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restrict the types, quantities and concentration of various substances that can be released into the environment in connection with natural gas drilling, production and transportation activities;

 

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limit or prohibit drilling activities in certain locations lying within protected or otherwise sensitive areas; and

 

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require remedial measures to mitigate pollution from our operations.

These laws and regulations may also restrict the rate of natural gas production below the rate that would otherwise be possible. Compliance with these laws can be costly; the regulatory burden on the natural gas industry increases the cost of doing business in the industry and consequently affects profitability.

Moreover, public interest in climate change and the protection of the environment has increased in recent years. Drilling in some areas has been opposed by activists, including environmental groups, and, in some cases, been restricted. Our operations could be adversely affected to the extent laws are enacted or other governmental action is taken that prohibits or restricts offshore drilling or imposes environmental requirements that result in increased costs to the natural gas industry in general, such as more stringent or costly waste handling, disposal or cleanup requirements.

Regulatory framework

The following is a summary of the more significant existing onshore gas laws, as amended from time to time, to which our business operations are or may be subject and for which compliance may have a material adverse impact on our capital expenditures, results of operations or financial position.

Many of these laws require us to obtain permits or other authorizations from state and/or federal agencies before initiating exploration, certain drilling, construction, production, operation, or other natural gas activities, and to maintain these permits and compliance with their requirements for on-going operations. These permits are generally subject to protest, appeal, or litigation, which can in certain cases delay or halt projects and cease production or operation of wells, pipelines, and other operations.

Regulation of our exploration activities

The Petroleum Act requires Tamboran to hold EPs in all areas where its exploration activities are proposed. The Petroleum Act is the principal legislation dealing with petroleum exploration and production activities onshore and in the territorial waters of the Northern Territory (“NT”). In particular, the Petroleum Act provides the legal framework for: (i) the grant of permits for exploration, production, and ancillary activities associated with exploiting petroleum, (ii) the renewal or transfer of those permits, (iii) the promotion of active exploration for petroleum, and (iv) the appraisal of discoveries and of the development of petroleum production if commercially viable by persons granted production licenses. Further, the Petroleum Act provides for the assessment of proposed technical works programs for the exploration, appraisal, recovery or production of petroleum, including an assessment of the financial capacity of persons proposing to carry out those programs. The Petroleum Act provides

 

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for Ministerial directions regarding resource management, approval of activity and infrastructure plans before production, audit activities by regulators, and includes a financial assurance framework that encompasses environmental securities, monitoring and compliance levies and an orphan well levy.

The objectives of the Petroleum Regulations 2020 (NT) (“Petroleum Regulations”) are to provide for land access agreements between interest holders and the owners or occupiers of land covered by petroleum interests, to support and enhance the integrity of onshore petroleum wells, petroleum surface infrastructure by ensuring that risks are reduced to as low as reasonably practicable, and the strategic management of petroleum production. In accordance with the Petroleum Regulations, Tamboran is required to enter into land access agreements with the owners or occupiers of the land on which it conducts its activities before it conducts regulated operations. The Petroleum Regulations govern the minimum conditions of entry into these access arrangements with the owners or occupiers. The Petroleum Regulations also prescribe the fees Tamboran must pay relating to the general administration of its petroleum titles, including fees for the grant, renewal and variation of EPs, retention licenses and production licenses.

The object of the Petroleum (Environment) Regulations 2016 (NT) (“Petroleum Environment Regulations”) is to ensure that regulated activities are carried out in a manner that is consistent with the principles of ecologically sustainable development, and by which the environmental impacts and risks of the activities will be reduced to a level that is as low as reasonably practicable and acceptable. The Petroleum Environment Regulations require the preparation of environment management plans for regulated activities and mandates such plans be approved by the Minister. Tamboran, as the permit holder, has environment management plans (“EMP”) in place in respect of all its regulated activities. These activities include conducting seismic surveys, the construction, operation, modification, decommissioning, dismantling or removal of a wells or other facilities, drilling, hydraulic fracturing, the release of contaminants or waste, and the storage and transportation of petroleum and hazardous waste. Tamboran’s EMPs are publicly available on the NT Government Department of Environment, Parks and Water Security website www.depws.nt.gov.au/EMPs. The EMPs describe how our regulated activities might impact the environment in which the activity occurs and establishes Tamboran’s obligations to ensure those impacts are managed to an environmentally acceptable level. Civil and criminal penalties apply under the Petroleum Environment Regulations for conduct which results in a contravention of an EMP, as well as for undertaking regulated activity for which there is no approved EMP.

The Petroleum Environment Regulations contain record-keeping and reporting requirements. Specifically in relation to our hydraulic fracturing activities, Tamboran is required to provide the Minister with a report about flowback fluid within six months of the flowback occurring. This report must contain a full human health risk assessment relating to any chemical found in the flowback fluid or water produced. Reporting is also required for incidents arising from regulated activities that have or have the potential to cause material environmental harm. Failure to comply with these reporting requirements may result in significant financial penalties.

The Code of Practice: Onshore Petroleum Activities in the NT (the “Code of Practice”) provides minimum standards that the onshore petroleum industry in the Northern Territory must adhere to. The Code of Practice applies to all of Tamboran’s regulated activities including those associated with both unconventional gas and exploration, appraisal and production activities. Tamboran’s Well Drilling, Hydraulic Fracture Stimulation and Well Testing EMPs must demonstrate compliance with the Code of Practice and will not be approved or renewed if they are not compliant with the requirements of the Code of Practice.

The Petroleum Royalty Act 2023 (NT) (“Royalty Act”) imposes a royalty rate, paid to the NT Government, for petroleum produced from a project area of 10% of the gross value of the petroleum at the well head (including petroleum produced from a production project area that is used or lost through venting or flaring or other means, but excluding petroleum used by the licensee for incidental purposes, petroleum used in the project area for processing or compression, or preparing petroleum for sale, petroleum returned or reinjected into a natural reservoir in the project area from which it was extracted/recovered, and petroleum produced from an exploration project area that is used or lost through venting or flaring or other means). “Petroleum” means a

 

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naturally occurring hydrocarbon, whether in gaseous, liquid or solid state. See “—Royalty Under the Petroleum Royalty Act.”

As onshore gas extraction moves toward production in the Northern Territory, there could be an increased risk of litigation in the form of challenges to Ministerial approvals of EMP, which could lead to costs and delays with respect to regulated activities. The failure to comply with record-keeping and reporting requirements of the Petroleum Environment Regulations can also attract financial penalties. Tamboran’s competitors in the Northern Territory are subject to the same risks and requirements that affect Tamboran’s operations.

Regulation of GHG Emissions

The National Greenhouse and Energy Reporting Act 2007 (Cth) (“NGER Act”) establishes the legislative framework for reporting greenhouse gas emissions, greenhouse gas projects and energy consumption and production by corporations in Australia. The objects of the NGER Act are to introduce a single national reporting framework for the reporting and dissemination of information related to greenhouse gas emissions, greenhouse gas projects, energy consumption and energy production of corporations and to contribute to the achievement of Australia’s greenhouse gas emissions reduction targets. Under the NGER Act, Tamboran will report Scope 1 GHG emissions from its operations to the Australian Government’s Clean Energy Regulator (CER). Furthermore, the Safeguard Mechanism, a legislative instrument sitting under the NGER Act, is designed to reduce emissions from large industrial facilities. It sets legislated limits, known as baselines, on the greenhouse gas emissions of certain facilities. The Safeguard Mechanism applies to industrial facilities emitting more than 100,000 tons of CO₂e per year and requires that all emissions form the Beetaloo be offset with Australian Carbon Credit Units or Safeguard Mechanism Credits once the 100,000 tons CO2-e trigger is exceeded.

The Safeguard Mechanism requires that all Beetaloo facilities covered by the Safeguard Mechanism have Net Zero Scope 1 emissions. Accordingly, the Safeguard Mechanism will apply to Tamboran. Tamboran’s ability to achieve Net Zero Scope 1 emissions will depend on it being able to economically manage its carbon emissions, which could, for example, be impacted by availability of future revenues to fund various carbon initiatives, market pricing of carbon offsets, technological developments affecting operations and costs of implementing sustainable practices. Under the Safeguard Mechanism, upon exceeding the 100,000 tons CO2-e trigger in a given financial year, all Scope 1 emissions in that financial year are required to be offset. The Australian federal government has established an A$75 carbon offset price cap for FY24. The offset price cap increases by CPI plus 2% each year. While we are unable to predict the future costs or impact of compliance with the Safeguard Mechanism, we do have established procedures for the ongoing evaluation of our operations to identify costs, potential exposures and to track compliance with this legislation.

On April 17, 2018, the NT Government announced that it accepted all 135 of the recommendations set out in The Scientific Inquiry into Hydraulic Fracturing in the Northern Territory. The implementation of the recommendations has resulted in a more rigorous regulatory regime by placing additional obligations on oil and gas companies including the introduction of a stricter code of practice for decommissioning onshore shale gas wells, requiring tenement holders to provide a non-refundable levy prior to granting any further production approvals and introducing no go zones where a person cannot explore or drill for petroleum resources.

Although it is not possible at this time to predict how new laws or regulations in Australia that may be adopted or issued to address GHG emissions would impact our business, any such future laws, regulations or legal requirements imposing reporting or permitting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to comply with new requirements and to reduce emissions of GHGs associated with our operations as well as delays or restrictions in our ability to permit GHG emissions from new or modified sources. In addition, substantial limitations on GHG emissions could adversely affect demand for natural gas we aim to produce.

 

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Regulation of Environmental and Occupational Safety and Health Matters

Our operations are subject to stringent Federal Government and territory laws and regulations governing occupational safety and health aspects of our operations, the discharge of materials into the environment and the protection of the environment and natural resources (including threatened and endangered species and their habitat). Numerous governmental departments have the power to enforce compliance with these laws and regulations and the permits issued under them, often requiring difficult and costly actions.

These laws and regulations may, among other things (i) require the acquisition of permits to conduct drilling and other regulated activities; (ii) restrict the types, quantities and concentration of various substances that can be released into the environment or injected into formations in connection natural gas drilling and production activities; (iii) limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; (iv) require remedial measures to mitigate pollution from former and on-going operations, such as specific waste removal requirements; (v) apply specific health and safety criteria addressing worker protection; and (vi) impose substantial liabilities for pollution resulting from drilling and other regulated activities. Any failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of corrective or remedial obligations, the occurrence of delays or restrictions in permitting or performance of projects, and the issuance of orders enjoining performance of some or all of our operations.

These laws and regulations may also restrict the rate of natural gas production below the rate that would otherwise be possible. The regulatory burden on the natural gas industry increases the cost of doing business in the industry and consequently affects profitability. The trend in environmental regulation has been to place more restrictions and limitations on activities that may affect the environment, and thus any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly well drilling, construction, completion or water management activities, or waste handling, storage transport, disposal, or remediation requirements could have a material adverse effect on our financial position and results of operations. We may be unable to pass on such increased compliance costs to our customers once we commence production. Moreover, accidental releases or leaks may occur in the course of our operations, and we cannot assure you that we will not incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for damage to property, natural resources or persons. The cost of continued compliance with existing requirements is not expected to materially affect us. However, there is no assurance that compliance costs will remain the same in the future for such existing or any new laws and regulations or that costs related to such future compliance will not have a material adverse effect on our business and operating results.

The following is a summary of the more significant existing and proposed environmental and occupational safety and health laws, as amended from time to time, to which our business operations are or may be subject and for which compliance may have a material adverse impact on our capital expenditures, results of operations or financial position.

Any of our activities which have the potential to cause a significant impact to the environment are required to be referred to the NT Environmental Protection Authority (“EPA”) for assessment under the Environmental Protection Act 2019 (NT) (“Environment Protection Act”). Tamboran has completed a self-assessment for its current environmental impact and considers its potential environmental impact to not be significant. However, it is anticipated that future developments by Tamboran could trigger a referral to, and assessment by, the EPA, and require Tamboran to obtain approvals under the Environmental Protection Act to conduct the activity (an “Environmental Approval”). Civil proceedings could be brought by any person who is affected by an alleged act or omission that contravenes the Environment Protection Act. Contraventions of an Environmental Approval can attract penalties currently ranging from $67,760 to $3,386,240. Contravention can also result in revocation of the Environmental Approval.

The Environment Protection Legislation Amendment Bill 2023 (NT) (“EPLAB”), assented to on December 6, 2023, amends the Environment Protection Legislation Amendment (Chain of Responsibility) Act 2022 (NT) (“CoR Act”) to extend chain of responsibility provisions of the CoR Act. Although the CoR Act has been assented to, its provisions have not yet commenced, but are expected to do so on July 1, 2024. The CoR

 

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