Tamboran Resources Corp

(UNAUDITED)

Note 1 – Business and Basis of Preparation

General

Tamboran is an early-stage growth-oriented natural gas company with a vision of supporting the netzero CO 2 energy

transition in Australia and Asia-Pacific through developing low CO 2 unconventional gas resources in the Northern

Territory(“NT”) of Australia. The Group is in the exploration and appraisal stage with a current focus on exploiting its

primary assets, which are rights to working interests (“Tenements”) in exploration acreage in the Beetaloo sub-basin

(“Beetaloo” or “Beetaloo Basin”), NT Australia. To date, the Group has not determined whether the Tenements contain any

natural gas reserves that are economically recoverable. Further, the Group had no revenues from its gas operations as of

December 31, 2025.

Going Concern and Management’s Liquidity Plan

The accompanying condensed consolidated financial statements have been prepared on the basis that the Group will

continue as a going concern which contemplates the realization of assets and the satisfaction of liabilities in the ordinary

and usual course of business.

As of December 31, 2025, the Group had:

•not generated revenues since inception, and will not generate earnings in the next 12 months sufficient to

satisfy all liabilities in the ordinary and usual course of business;

•a working capital surplus of $38.4 million arising from an increase in cash and cash equivalents subsequent to

the capital raise activities during the period;

•long-term debt drawn down of$32.6 million related to the construction of the Sturt Plateau Compression

Facility (“SPCF”) plus associated financing costs;

•an accumulated deficit of$182.1 million since inception; and

•significant expenditures planned for natural gas properties in the next 12 months.

While these factors raise substantial doubt regarding the Group’s ability to continue as a going concern for the 12

months following the date these condensed consolidated financial statements were available for issuance, there have been

milestones recently satisfied by the Company that indicate progress towards eliminating this substantial doubt in future

periods. These include reaching Final Investment Decision (“FID”) for the Shenandoah South Pilot Project, which is

currently on track to commence first gas sales from the second half of calendar year 2026 and the completion of a public

offering in October 2025, the share purchase plan in November 2025, and the Private Investment in Public Equity (“PIPE”)

in January 2026.

The continuation of the Group as a going concern is dependent upon the ability of the Group to obtain necessary

additional capital to fund ongoing exploration, appraisal and development projects and/or obtain gas producing properties

to attain future profitable operations. No assurance can be given that the Group will be successful in these efforts in the

future, however, Management is actively pursuing several plans to mitigate this uncertainty, including:

•Assessment of farm-down partners and completion of those arrangements, including the need to raise further

equity for EP161, SS1 Pilot expenditure, and the phase 2 development;

•Continuation of SPCF construction during the wet season in the NT, progressing toward revenue from gas

production in the second half of calendar year 2026; and

•Research & Development tax incentives from Australian government bodies.

As a result, these condensed consolidated financial statements donot include any adjustments related to the

recoverability and classification of recorded assets and liabilities that might be necessary should the Group be unable to

continue as a going concern.

Basis of Presentation of Condensed Consolidated Financial Statements

The accompanying condensed consolidated financial statements have been prepared in conformity with the

accounting principles generally accepted in the United States of America (“U.S. GAAP”) and rules and regulations of the

Securities and Exchange Commission (“SEC”) applicable to interim financial statements. Pursuant to such rules and

regulations, certain disclosures and information required by U.S. GAAP for complete consolidated financial statements

have been condensed or omitted. The accompanying condensed consolidated financial statements and notes therein should

be read in conjunction with the financial statements and notes included in our consolidated financial statements for the year

ended June 30, 2025 (“Group’s Annual Financial Statements”).

These condensed consolidated financial statements reflect all adjustments, in the opinion of management, which

include normal and recurring adjustments necessary to fairly state the Group’s consolidated financial position, results of

operations, and cash flows for the periods presented herein. The interim results are not necessarily indicative of results for

any other future annual or interim period. The June 30, 2025 condensed consolidated balance sheet was derived from the

audited Group’s Annual Financial Statements but doesnot include all disclosures required by U.S. GAAP for annual

financial statements.

In the current fiscal year, the Group changed the presentation of unaudited condensed consolidated financial

statements to thousands and, as a result, any necessary rounding adjustments have been made to prior year disclosed

amounts. Certain amounts in the Group's unaudited condensed consolidated financial statements may not add up or

recalculate due to rounding.

Significant Judgments and Accounting Estimates

The preparation of these condensed consolidated financial statements in conformity with U.S. GAAP requires

management to make certain estimates and assumptions that affect the amounts of assets and liabilities, revenue and

expenses and related disclosures of contingent assets and liabilities reported in the condensed consolidated financial

statements and the accompanying notes. There have beenno significant changes to the Group’s accounting estimates from

those disclosed in the Group’s Annual Financial Statements.

Significant Accounting Policies

The Group’s significant accounting policies are described in the notes included in the Group’s Annual Financial

Statements. There have beenno significant changes in accounting policies during the six months ended December 31,

Cash and Cash Equivalents and Restricted Cash

Cash represents cash deposits held at financial institutions. Cash equivalents include short-term highly liquid

investments of sufficient credit quality that are readily convertible to known amounts of cash and have original maturities

of three months or less.

Restricted cash as of December 31, 2025 represents amounts held in a payment reserve account that serves as a

security for servicing of expected future interest and commitment fee payments over the term of the long-term debt.

Restricted cash as of June 30, 2025 represents amounts related to proceeds received in advance in respect of the common

stock pending issuance on that date. The following table is a reconciliation of the total cash and cash equivalents and

restricted cash in the accompanying consolidated statements of cash flows and their corresponding balance sheet

presentation:

Foreign Currency Translation

These condensed consolidated financial statements are presented in US dollars (“$” or “dollars”) and the functional

currency of the Group is the Australian Dollar (“A$”). Adjustments resulting from the translation of functional currency

financial statements to reporting currency are accumulated and reported as a part of “Accumulated Other Comprehensive

Loss”, a separate component of stockholders’ equity.

Foreign Currency Transactions

Foreign currency transactions are translated into the Company’s functional currency using the exchange rates

prevailing at the dates of the transactions. Foreign exchange gains and losses resulting from the settlement of such

transactions and from the translation at fiscal year-end exchange rates of monetary assets and liabilities denominated in

foreign currencies are recognized in the condensed consolidated statements of operations and comprehensive loss.

Leases

As a Lessee

The Group accounts for leases under ASC 842, Leases(“ASC 842”). The Group determines if an arrangement is a

lease at inception of the arrangement and if such lease will be classified as an operating lease or a finance lease. The

Group’s leases represent its right to use an underlying asset for the lease term. Right-of-use (“ROU”) assets and liabilities

are recognized at the lease commencement date based on the present value of lease payments over the lease term. As the

Group’s leases do not provide an implicit rate, the Group used a proxy for its incremental borrowing rate, which is the rate

incurred to borrow on a collateralized basis over a similar term, an amount equal to the lease payments in a similar

economic environment.

The Group has elected to account for lease and non-lease components in its contracts as a single lease component for

all asset classes except for office premises.

Operating leases are included in “Operating lease right-of-use assets” within the Group’s condensed consolidated

balance sheet. The Group’s related obligation to make lease payments are included in “Current portion of operating lease

obligations” and “Operating lease obligations” within the Group’s condensed consolidated balance sheet. Operating lease

expense for lease payments is recognized on a straight-line basis over the lease term.

Finance leases are included in “Finance lease right-of-use assets” within the Group’s condensed consolidated balance

sheet. The Group’s related obligation to make lease payments are included in “Current portion of finance lease obligations”

and “Finance lease obligations” within the Group’s condensed consolidated balance sheet. Finance lease expense includes

amortization of the ROU assets and interest on lease liabilities. The Group capitalizes the finance lease expense as a part of

unproved properties when the leased asset is directly involved in the drilling of wells (i.e. the finance lease expense is a

direct cost of drilling wells).

Leases with a lease term of 12 months or less are not recorded on the condensed consolidated balance sheet and are

recognized as lease expense on a straight-line basis over the lease term. When it is reasonably certain the Group will

exercise an option to extend the short-term lease beyond 12 months, the cost will be capitalized.

As a Lessor

Sublease income is recognized on a straight-line basis over the term of the sublease agreement and is recorded within

“Other income (expense), net” in the condensed consolidated statements of operations and comprehensive loss.

Natural Gas Properties

The Group’s operations are in the exploration and appraisal stage and havenot yet realized any revenues from

operations. The Group holds a number of exploration permits that are grouped into areas of interest according to

geographical and geological attributes. Expenditure incurred in each area of interest is accounted for using the successful

efforts method, as defined within ASC 932, Extractive Activities – Oil and Gas.

Under this method, all general exploration and evaluation costs such as geological and geophysical costs are

expensed as incurred. The direct costs of 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 results of the well. If a well does not result in hydrocarbons being present, the previously capitalized

costs are immediately expensed.

The Group capitalizes borrowing costs for assets under construction. Upon the asset becoming available for use,

capitalized borrowing costs, as a portion of the total cost of the asset, are depreciated over the estimated useful life of the

related asset.

Deferred Debt Issuance Costs

The Group presents unamortized deferred debt issuance costs related to the establishment of a Performance Bond

Facility Agreement (the “Facility Agreement”) as a component of “Prepaid expenses and other non-current assets” on its

consolidated balance sheet because the outstanding balance under this Facility Agreement may fluctuate as the Group

borrows and repays the relevant amounts. The Group amortizes the deferred debt issuance costs over the remaining term of

the Facility on a straight-line basis which is reported within “interest income (expense), net” in the condensed consolidated

statements of operations and comprehensive loss.

The Group initially recognizes the establishment and commitment fees and other third party-fees related to the long-

term debt as a component of “Prepaid expenses and other non-current assets” on its consolidated balance sheet. As and

when, the Group draws down funds from the long-term debt, these costs are reclassified (on proportionate basis) and

presented as a direct deduction from the carrying amount of the debt liability. These costs are amortized to the asset under

construction over the contractual term of the debt using the effective interest rate method.

Recently Issued Accounting Standards

In December 2025, the Financial Accounting Standards Board (“FASB”) issued ASU 2025-12, Codification

Improvements (“ASU 2025-12”). ASU 2025-12 clarifies or otherwise modifies U.S. GAAP in a number of areas. The

standard is effective for all entities for annual reporting periods beginning after December 15, 2026, and for interim periods

within those annual reporting periods. Early adoption is permitted as of the beginning of an annual reporting period and

adoption can be applied on prospectively or retrospectively, as well as on an issue-by-issue basis. The Group does not

expect any material impact on itsconsolidated financial statements.

In December 2025, the FASB issued ASU 2025‑11, Interim Reporting (Topic 270): Narrow-Scope Improvements

(“ASU 2025-11”). ASU 2025-11 clarifies interim disclosure requirements, including providing a comprehensive list of

interim disclosure requirements under U.S. GAAP and a disclosure principle that requires entities to disclose events since

the last annual reporting period that have a material impact on the entity. The standard is effective for interim periods

within annual reporting periods beginning after December 15, 2027. The Group is currently evaluating ASU 2025-11 and

the impact it may have on the Group's consolidated financial statements.

In December 2025, the FASB issued ASU 2025-10, Government Grants (Topic 832): Accounting for Government

Grants Received by Business Entities (“ASU 2025-10”). ASU 2025-10 establishes authoritative guidance on how to

recognize, measure, and present government grants received by business entities. ASU 2025-10 is effective for annual

periods beginning after December 15, 2028, and interim reporting periods within those annual reporting periods. ASU

2025-10 may be applied using a modified prospective, modified retrospective or retrospective approach with early adoption

permitted in an interim or annual reporting period. If an entity early adopts in an interim reporting period, it must adopt as

of the beginning of the annual reporting period that includes that interim reporting period. The Group is evaluating the

impact of this guidance on its consolidated financial statements.

In November 2024, the FASB issued ASU 2024-03, Income Statement - Reporting Comprehensive Income -

Expense Disaggregation Disclosures (“ASU 2024-03”), and in January 2025, the FASB issued ASU 2025-01, Income

Statement - Reporting Comprehensive Income - Expense Disaggregation Disclosures (Subtopic 220-40): Clarifying the

Effective Date (“ASU 2025-01”). ASU 2024-03 requires public business entities to provide detailed disclosures in the notes

to financial statements disaggregating specific expense categories, including employee compensation, depreciation, and

intangible asset amortization, as well as certain other disclosures to provide enhanced transparency into the nature and

function of expenses on an interim and annual basis. ASU 2024-03, as clarified by ASU 2025-01 is effective for annual

periods beginning after December 15, 2026, and interim periods within fiscal years beginning after December 15, 2027,

with early adoption permitted. The Group is currently evaluating ASU 2024-03 and the impact it may have on the Group's

consolidated financial statements.

In December 2023, the FASB issued ASU 2023-09, Improvements to Income Tax Disclosures (“ASU 2023-09”), a

final standard on improvements to income tax disclosures. The standard requires disaggregated information about a

reporting entity's effective tax rate reconciliation as well as information on income taxes paid. The standard is intended to

benefit investors by providing more detailed income tax disclosures that would be useful in making capital allocation

decisions and apply to all entities subject to income taxes. The new standard is effective for annual periods beginning after

December 15, 2024. The Group adopted ASU 2023-09 prospectively during the three months ended September 30, 2025.

The adoption did not have a material impact on the Group’s interim condensed consolidated financial statements but is

expected to result in expanded annual income tax disclosures beginning with the Group’s Form 10-K for the fiscal year

ending June 30, 2026.

Note 2 – Variable Interest Entities

TB1

Tamboran (B1) Pty Ltd (“TB1”) is a 50/50 joint venture between the Company, through its wholly owned subsidiary

Tamboran (West) Pty Ltd (“TR West”), and Daly Waters Energy, LP (“DWE”) governed by the terms of an amended and

restated joint venture and shareholders agreement dated June 3, 2024 (the “TB1 Joint Venture Agreement”). In determining

the primary beneficiary of TB1, the Company considered those activities which most significantly impact the economic

performance of TB1, including, for example, which entity serves as the manager, determination of the strategy and

direction of TB1, and the power to create a budget.

The Group is the sole manager of TB1, responsible for managing the day-to-day operations of TB1. The Group, as

manager, also prepares the work plans and budget of TB1. As such, the Group has the power to direct those activities

which most significantly impact TB1’s economic performance and therefore is the primary beneficiary of TB1. As a result,

the results of TB1 have been included in the accompanying condensed consolidated financial statements. TB1 hasno assets

that are collateral for or restricted solely to settle its obligations. The creditors of TB1 donot have recourse to the Group’s

general credit.

The Group also assessed which party to the TB1 Joint Venture Agreement has the obligation to absorb losses or the

right to receive the benefits of the VIE that could potentially be significant to the VIE. The future profits and losses of TB1

are shared by the Group and DWE in proportion to their respective equity interest in TB1, however, to date the Group has

contributed a greater proportion of the capital and has no ability to recoup any of the excess funding the Group has made to

TB1 from DWE and therefore has a greater exposure to absorb losses.

In 2022, Tamboran Resources Pty Ltd (formerly known as Tamboran Resources Limited) (“TR Ltd.”), a wholly

owned subsidiary of the Company, made a loan to TR West for purposes of funding TR West’s acquisition of its interest in

TB1. On November 9, 2022, TB1 completed the acquisition of a 77.5% share of Beetaloo Basin assets, EP 76, EP 98, and

EP 117. The Company and DWE each beneficially own a 38.75% interest in the permits for the total undivided interest of

77.5%. Falcon Oil & Gas Australia Limited (“FOGA”) holds the remaining undivided interest of 22.5% in the assets

(collectively known as the “Beetaloo Joint Venture”).

On March 4, 2024, FOGA, the owner of the remaining 22.5% interest in the Beetaloo Joint Venture assets, capped its

participation to 5% in the Beetaloo Joint Venture’s second Shenandoah South well pad (“SS2”). On March 21, 2024,

Tamboran B2 Pty Ltd (“TB1 Operator”) (a wholly owned subsidiary of TB1 in which the Company has a 50% interest)

agreed to acquire FOGA’s interest, increasing TB1 Operator’s working interest to at least 95% in the wells drilled from the

SS2 well pad.

Pursuant to the TB1 Joint Venture Agreement, the parties were required to implement an approach to dividing the

permits whereby Tamboran and DWE pursue a division of TB1 Operator’sinterest in the permits such that the title and

ownership of the permits will be split evenly between Tamboran and DWE in the specific area in terms of equity interest

and number of operated blocks (“Checkerboard Strategy”). The TB1 Joint Venture Agreement provided that if the

Checkerboard Strategy was not implemented by December 31, 2024, due to either:

•the failure to obtain the requisite ministerial approval to effectuate the Checkerboard Strategy; or

•a New Area Joint Venture is not approved by the parties to the Joint Operating Agreement (“JOA”) with respect to

joint operations of the subject areas, then, by February 15, 2025,

then, the Company must either:

◦pay DWE a cash amount of $7.5 million; or

◦issue CHESS Depository Interests (“CDIs”) to DWE with a value of$15 million, based on the volume

weighted average price of CDIs traded on the Australian Stock Exchange (“ASX”) at the time during the

30 days on which sales in CDIs were recorded prior to December 31,2024.

At the time of the Company's Initial Public Offering (“IPO”) in June 2024, DWE agreed to waive the$7.5 million

payment obligation in respect of the Checkerboard Strategy in exchange for Tamboran’s issue to DWE, or its nominee, of

312,500 shares of common stock (calculated based on the obligation of $7.5 million divided by the common stock price at

the IPO of $24.00 per share), subject to shareholders' approval, which was granted in November 2024. The obligation to

implement the Checkerboard Strategy does not cease with this issuance ofshares.

On May 12, 2025, TR West, as seller, and the Company, as seller guarantor, and DWE entered into an Asset Sale

Agreement – Beetaloo Acreage Position (the “Asset Sale Agreement”) with Elliot Energy I Pty Ltd (“Elliot Energy”).

Pursuant to the Asset Sale Agreement, DWE will acquire a non-operating and non-controlling interest withintwo areas of

Tamboran's post-checkerboard acreage position for a consideration of$15.0 million. The transaction is subject to

regulatory approvals and other conditions precedent. As of December 31, 2025, this transaction has not been completed.

On May 12, 2025, the Company, TR West, TR Ltd., DWE and TB1 (collectively, the “parties”) entered into a second

amended and restated joint venture and shareholders agreement (the “TB1 A&R JVSA”). The following summarizes the

material changes in the Amended and Restated JVSA from the amended and restated joint venture and shareholders

agreement filed as Exhibit 10.18 to the Company’s Annual Report on Form 10-K for the year ended June 30, 2024:

•The Company and DWE have signed a binding agreement to finalize the checkerboard of the joint acreage

position across EPs 76, 98 and 117.

•The Checkerboarding Strategy is divided into three tranches:

◦In Tranche 1, Tamboran and Daly Waters must apply for retention licenses for both the North and South

First Strategic Development Areas (“FSDAs”) by February 14, 2026 (as extended in a letter dated

December 11, 2025). The North FSDA will remain with TB1, while the current plan for the South FSDA

will be split equally (38.75% each) between Tamboran and DWE, with DWE (or its nominee) acting as

Operator. In a letter signed by DWE on February 10, 2026, both Tamboran and DWE have agreed to

extend the February 14, 2026, deadline to February 27, 2026 for the retention licenses to be applied for in

the FSDAs. Subject to the terms and conditions in the TB1 A&R JVSA, DWE has the right to take over

as Manager in the South FSDA if this February 27, 2026 deadline is missed.

◦In Tranche 2, the parties must apply for retention licenses over the Dev A++ and Dev B areas by March

31, 2026, with the grants and transfers to be completed by September 30, 2026. After the retention

licenses are granted, Tamboran will remain the operator of Dev A++, and DWE will become the operator

of Dev B. If these deadlines are not met, DWE has the same rights as in Tranche 1: to replace the

Manager and/or acquire Tamboran’s interest.

◦Tranche 3 covers the remaining “Checkerboard” permit areas. Tamboran and DWE will take turns

selecting paired blocks and applying for Retention or Production Licenses until all acreage is allocated.

Tamboran must select the Checker 10 area as its first choice.

•In the event that retention license conditions referred to above are not met and DWE elects to exercise its right to

take over as Manager, the Group will lose the power to direct those activities which most significantly impact

TB1’s economic performance and therefore, will no longer be the primary beneficiary of TB1. Should this occur,

the conditions required to continue consolidating TB1 would no longer be satisfied. The Group would be required

to de-consolidate TB1 and recognize its remaining interest in TB1 as an equity accounted investment.

•In conjunction with the checkerboard, the Company and DWE entered into the Asset Sale Agreement whereby

DWE will acquire a non-operating and non-controlling interest in 100,000 acres withintwo areas for a

consideration of$15.0 million, or$150 per acre. The transaction is subject to regulatory approvals and other

conditions precedent.

•On completion, the Company will have retained approximately 1.9 million net prospective, development-ready

acres across the Beetaloo Basin.

•The Company has reserved 406,693 gross acres as the Phase 2 Development Area, located immediately north of

the proposed Pilot Area, where the Company plans to focus development on supplying gas into Australia’s East

Coast domestic gas market.

•On completion of the sale to DWE, the Company is expected to hold 236,370 net acres (58.12% operated interest)

over the Phase 2 Development Area, with DWE (19.38%) and FOGA (22.5%) holding the remaining interest.

•The Company has engaged RBC Capital Markets, LLC to commence a formal farm-down of the Phase 2

Development Area. As of December 31, 2025, the formal process has commenced and DWE will have

participation rights to any transaction on the same terms.

•Ownership of the Pilot Area which includes the North FSDA and South FSDA, the focus for initial gas production

in the NT, remains unchanged (the Company 47.5% operatorin the Northern FSDA, DWE 47.5% operator in the

Southern FSDA and FOGA 5%).

•The Company will hold 77.5% operating interest in the ex-EP 76, 98 and 117 acreage, with FOGA holding the

remaining 22.5% interest.

The following table summarizes the carrying amounts of TB1’s assets and liabilities included in the Group’s

condensed consolidated balance sheet as of December 31, 2025 and June 30, 2025 (in thousands):

Tamboran SPCF Pty Ltd

In October 2024, the Company, through its wholly owned subsidiary Tamboran SPCF Pty Ltd (“TR SPCF”), entered

into a Unit Holders and Shareholders Deed with Daly Waters Infrastructure, LP (“DWI”) for the establishment of a trust

(“SPCF Sub Trust”) to be owned 50%/50% by the Group and DWI to own the SPCF. In determining the primary

beneficiary of the SPCF Sub Trust, the Company considered those activities that most significantly impact the economic

performance of the SPCF, including, for example, which entity serves as the manager, determination of the strategy and

direction of the SPCF, and the power to create a budget.

The Group was appointed as manager of the SPCF Sub Trust responsible for managing the day-to-day operations of

the SPCF. The Group, as manager, also prepares the work plans and budget of the SPCF Sub Trust. As such, the Group has

the power to direct those activities that most significantly impact the SPCF’s economic performance and therefore is the

primary beneficiary of the SPCF Sub Trust. As a result, the results of SPCF Sub Trust have been included in the

accompanying condensed consolidated financial statements. SPCF Sub Trust hasno assets that are collateral for or

restricted solely to settle its obligations. The creditors of SPCF Sub Trust donot have recourse to the Group’s general

credit.

The Group also assessed which party to the SPCF Sub Trust has the obligation to absorb losses or the right to receive

the benefits of the VIE that could potentially be significant to the VIE. The future profits and losses of SPCF Sub Trust are

shared by the Group and DWI in proportion to their respective equity interest in SPCF Sub Trust, and both parties have no

ability to recoup any funding the Group has made to SPCF.

The following table summarizes the carrying amounts of SPCF Sub Trust’s assets and liabilities included in the

Group’s condensed consolidated balance sheet as of December 31, 2025 and June 30, 2025 (in thousands):

Note 3 – Property, Plant and Equipment & Natural Gas Properties

Natural Gas Properties

The Group held unproved natural gas properties as of December 31, 2025 and June 30, 2025 amounting to$415.6

million and$342.3 million, respectively. These amounts reflect the Group’s exploration and evaluation projects, which are

pending the determination of proven and probable reserves and werenot being depleted for thesix months ended

December 31, 2025, and 2024. These assets will be reclassified to proven gas properties upon commencement of

production and then subsequently depleted.

During thesix months ended December 31, 2025 and December 31, 2024, the Group recognizedno impairment

related to unproved natural gas properties.

On September 30, 2025, the Beetaloo Joint Venture made a FID for the Shenandoah South Pilot Project in EP 98 and

EP 117.

Property, Plant and Equipment

The Group held property, plant and equipment, including leasehold improvements, as of December 31, 2025 and

June 30, 2025, amounting to$0.5 million and$0.3 million, respectively.

Assets Under Construction

In April 2024, the Group began to execute agreements for the SPCF in the Beetaloo Basin which would deliver a

plant that would convert future raw gas to sales gas quality, subject to the terms of definitive development agreements. As

of December 31, 2025, construction of the facility is well underway. The Group held total assets under construction related

to the SPCF as of December 31, 2025 and June 30, 2025 of$47.8 million and$24.4 million, respectively. These costs of

construction include$1.7 million of capitalized borrowing costs for thethree months ended andsix months ended

December 31, 2025, respectively. Refer to Note 6 for additional discussion.

The 40 TJ/d (39 MMcf/d) SPCF is expected to be connected to the Amadeus Gas Pipeline (“AGP”) via the

construction of the 35-kilometer Sturt Plateau Pipeline (“SPP”) subject to achieving project milestones.

Falcon Acquisition

On September 30, 2025, it was announced that Tamboran, Tamboran (Beetaloo) Pty Ltd, a company organized under

the laws of Australia and an indirect wholly owned subsidiary of Tamboran (“Australia Sub”), Tamboran Resources

Investments Holding Corporation, a Delaware corporation and an indirect wholly owned subsidiary of Tamboran (“U.S.

Sub”) and Falcon Oil & Gas Ltd., a corporation incorporated under the Business Corporations Act (British Columbia)

(“Falcon”), entered into an Arrangement Agreement (the “Arrangement Agreement”), pursuant to which, on the terms and

subject to the conditions set forth therein, (a) Australia Sub will acquire from Falcon approximately 98.1% of the issued

and outstanding equity interests (the “Falcon Interests”) of FOGA and (b) U.S. Sub will acquire from Falcon all of the

issued and outstanding equity interests (together with the Falcon Interests, the “Subject Interests”) of TXM Oil and Gas

Exploration Kft., Falcon Oil & Gas Ireland Limited, Falcon Oil & Gas Holdings Ireland Limited and Falcon Exploration

and Production South Africa (Pty) Ltd (collectively, the “Falcon Acquisition”). In exchange for the Subject Interests,

Tamboran will issue to Falcon 6,537,503 shares of common stock (the “Falcon Parent stock consideration”) and pay$23.7

million in cash.

The closing of the Falcon Acquisition (the “Closing”) is subject to certain conditions, including, among others, (a)

the approval of the Transactions by at least 66 ⅔% of the votes cast by Falcon shareholders and, if required by applicable

Canadian securities laws, a simple majority of the votes cast by Falcon shareholders, excluding Falcon common shares held

by persons required to be excluded under such laws, at a meeting of Falcon shareholders, (b) the approval of the issuance

of the Stock Consideration by a majority of the votes cast by Tamboran stockholders at a meeting of Tamboran

stockholders, (c) the approval of the Falcon Acquisition by the Supreme Court of British Columbia on terms consistent

with the Arrangement Agreement and otherwise reasonably satisfactory to the parties, (d) the authorization for listing of the

Stock Consideration on the New York Stock Exchange and (e) the absence of any law or order enjoining, restricting or

prohibiting the consummation of the transactions contemplated by the Falcon Acquisition.

On December 30, 2025, FOGA secured necessary approval from its minority shareholders for the sale of Falcon's

98.1% interest in FOGA to Tamboran.

Upon completion of the Falcon Acquisition, the Group will also enter into consulting agreements with certain

directors and officers of Falcon, pursuant to which the Group will issue to those directors and officers an aggregate of up to

369,084 share options with an exercise price of$21.94 per share.

Further, following completion of the Falcon Acquisition, upon Australia Sub owning the Australia Interests,

Australia Sub will become entitled to compulsorily acquire the remaining 1.9% of the issued and outstanding equity

interests of FOGA (the “FOGA minority stock”) held by the shareholders other than Australia Sub (the “FOGA minority

holders”). Australia Sub will proceed with the compulsory acquisition of the FOGA minority stock for cash consideration

at a price per share no less than the price paid to Falcon for the Australia Interests. To the extent that any FOGA minority

holders notify Australia Sub that they wish to receive shares of Tamboran common stock in lieu of cash, Tamboran and

Australia Sub will consider and may agree to such requests. If Tamboran and Australia Sub agree to issue shares of

Tamboran common stock in lieu of cash to such requesting FOGA minority holders, Tamboran may issue to the FOGA

minority holders up to an aggregate of 147,508 shares of Tamboran common stock.

The Falcon Acquisition is expected to be completed during the three months ended March 31, 2026.

Note 4 – Leases

As a Lessee

The Group’s operating lease activities consist of leases for office premises and modular buildings at the camp pad

site.

Commencing on October 1, 2025 the Group entered into the use of additional bunkhouses and accommodation

verandahs pursuant to the lease arrangement entered into with Northern Transportables on August 14, 2025 (the “Stage 3

Hire of Goods”). The term of the lease arrangement isfifteen months, with an option to further renew the lease (as needed).

Commencing on August 14, 2025, the Group entered into a new lease arrangement with Northern Transportables for

the hire of modular buildings and related equipment (the “Stage 1 and 2 Hire of Goods”). The term of the lease

arrangement isseventeen months, with an option to further renew the lease (as needed).

Commencing May 24, 2025, the Group entered into a new lease arrangement with Mackwell 33 Queen Pty Ltd for

their office premises in Brisbane, Australia. The term of the lease isfive years.

Commencing July 1, 2024, the Group entered into a new lease agreement with Drecom Pty Ltd ATF English Family

Trust for their office premises in Darwin, Australia. The term of the lease isthree years, with an option to further renew the

lease fortwo years.

On October 1, 2023, the Group entered into a new lease agreement with Lendlease IMT (OITST ST) Pty Ltd for their

office premises in Barangaroo, Australia. The term of the lease isfour years, with no option to renew.

On September 9, 2022, Sweetpea Petroleum Pty Ltd (“Sweetpea”), a wholly owned subsidiary of Tamboran, entered

into a drilling contract with Helmerich & Payne International Holdings LLC (“H&P”) for H&P to assist the Group in

carrying out its onshore drilling operations in Australia. The drilling contract grants Tamboran the right to use the drilling

rig from H&P over the initial non-cancellable contract term of 25 months starting from July 1, 2023. Under the terms of the

agreement, the Group has the right to place the drilling rig on a temporary suspension rate between wells for a period up to

270 days (the “Gap Period”). For each day of the original Gap Period consumed, and subsequent suspension periods

negotiated, additional days are added to the fixed minimum term. As of December 31, 2025, the end date of the drilling

contract for the current rig is early January 2028 (inclusive of additional days). The drilling contract is recognized as a

finance lease under ASC 842 (“H&P Rig Lease”).

The present value of the minimum future obligations was calculated based on an interest rate of 15.60% per annum,

which was recognized in finance lease liabilities in the condensed consolidated balance sheet.

The following table presents the classification and location of the Group’s leases on the condensed consolidated

balance sheets (in thousands):

For the three months and six months ended December 31, 2025, and 2024, the components of the lease costs were as

The following table presents the cash flow information related to lease payments for thesix months ended

December 31, 2025, and 2024 (in thousands):

The following table presents supplemental information for the Group’s non-cancellable leases for thesix months

ended December 31, 2025, and 2024:

As of December 31, 2025, the Group’s undiscounted minimum cash payment obligations for its lease liabilities are as

1 Includes both current and long-term portion of the lease liabilities.

Note 5 – Accounts Payable and Accrued Expenses

Accounts payable and accrued expenses included in current liabilities consist of the following (in thousands):