Tamboran Resources Corp

(UNAUDITED)

Note 1 – Business and Basis of Preparation

General

Tamboran Resources Corporation (the “Company” or “Tamboran” and together with its consolidated subsidiaries,

the “Group”) 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

March 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 March 31, 2025, the Group had:

•not generated revenues since inception, and is unlikely to generate earnings in the immediate or foreseeable

future;

•a working capital surplus of$3,570,400, arising from proceeds of our United States Initial Public Offering

(“IPO”), the net rig 403 sale proceeds and the refund for 2023 Research and Development (“R&D”) tax

credit;

•an accumulated deficit of$157,098,288 since inception; and

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

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. 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.

Management has several plans in various stages of progress to source additional funding to provide operating capital

for the continued growth of the Group. 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, 2024 (“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, 2024 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.

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 nine months ended March 31, 2025.

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 financial 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 hasnot 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.

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 sheets 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, net” in the condensed consolidated statements

of operations and comprehensive loss.

Recently Issued Accounting Standards

In November 2024, the Financial Accounting Standards Board (“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.

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 and Gas Australia limited (“Falcon”) holds the remaining undivided interest of 22.5% in the assets

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

On March 4, 2024, Falcon, 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 Falcon’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 are 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 is 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$7,500,000; or

◦issue CHESS Depository Interests (“CDIs”) to DWE with a value of$15,000,000, 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 IPO, DWE agreed to waive the$7,500,000 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$7,500,000 divided by the common stock price at the IPO of$24.00 per share), subject to shareholders'

approval (Refer Note 7), which was granted in November 2024. The obligation to implement the Checkerboard Strategy

does not cease with this issuance of shares.

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

condensed consolidated balance sheet as of March 31, 2025 and June 30, 2024:

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 Sturt Plateau Compression Facility

(“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 units within the SPCF Sub Trust structure were issued in October 2024. The assets were transferred tothe SPCF

Sub Trust during thethree months ended March 31, 2025.

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 March 31, 2025:

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

Natural Gas Properties

The Group held unproved natural gas properties as of March 31, 2025 and June 30, 2024, amounting to

$303,320,471 and$230,119,448, 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 thenine months

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

production and then subsequently depleted.

In October 2024, the Group lodged an amended income tax return for the year ended June 30, 2024 claiming eligible

R&D expenditure for EP 136, which resulted in a cash refund of$6,168,698 in December 2024.

During thenine months ended March 31, 2025 and March 31, 2024, the Group recognizedno impairment related to

unproved natural gas properties.

Property, Plant and Equipment

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

June 30, 2024, amounting to$236,000 and$102,244, respectively.

Assets Under Construction

In April 2024, the Group began to execute agreements for long lead items required for the SPCF in the Beetaloo

Basin. These items included essential plant components comprising oftwo compressors and a dehydration unit that would

convert future raw gas to sales gas quality, subject to the terms of definitive development agreements. During thenine

months ended March 31, 2025, the Group completed detailed design of the SPCF and received approval of the

Environmental Management Plan (EMP). The Group held total assets under construction related to the SPCF as of

March 31, 2025 and June 30, 2024 of$17,567,615 and$7,542,064, respectively.

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.

Assets Classified as Held for Sale

In October 2024, the Group completed the disposal of rig 403 at a price of$8,500,000, on which the Group paid a

sales commission of 6%. During thenine months ended March 31, 2025, the Group recognized a loss on assets held for

sale of$376,000 to reduce the asset to the lower of its carrying amount and the fair value less costs to sell (determined

based on the sales price above). No gain or loss was recognized on the sale of the rig during the three months ended

March 31, 2025 as it had already been reduced to the fair value less costs to sell in the prior quarters.

No other assets remain held for sale as of March 31, 2025.

Note 4 – Leases

As a Lessee

The Group’s operating lease activities consist of leases for office premises.

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 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 Gap Period consumed, additional days are added to the fixed minimum

term. As of March 31, 2025, the end date of the drilling contract for the current rig is mid-April 2027. 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 12.76% p.a., 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:

For the three months and nine months ended March 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 thenine months ended

March 31, 2025, and 2024:

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

ended March 31, 2025, and 2024:

As of March 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.

As a Lessor

On October 15, 2023, the Group entered into an agreement with a third party to sublease its former office premises in

Manly, Australia (the “Manly lease”). The commencement date of the sublease was October 1, 2023, with a lease term of

17 months. The Manly lease, and sublease expired on March 10, 2025 with no renewal. Sublease income for the three

months andnine months ended March 31, 2025, was$68,207 and$239,811, respectively, and is included within “Other

income (expense), net” on the Group’s condensed consolidated statements of operations and comprehensive loss. There

have beenno indications of impairment related to the underlying right-of-use asset.

Note 5 – Accounts Payable and Accrued Expenses

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

Note 6 – Asset Retirement Obligations

The Group recognizes the liability for an asset retirement obligation at their estimated fair value in the period in

which the obligation originates. Fair value is estimated using the present value technique (level 2) based on a number of

observable inputs including estimates and assumptions such as future retirement costs, future inflation rates and the

Group’s credit-adjusted risk-free interest rate.

The Group capitalized the present value of the estimated asset retirement obligations as a part of the carrying amount

of the related natural gas properties. The liability has been accreted to its present value fornine months ended March 31,

The reconciliation of changes in asset retirement obligations for thenine months ended March 31, 2025, is as

Note 7 – Stockholders’ Equity

Movement in Common Stock

July 2024 Greenshoe Option

Subsequent to the IPO in June 2024, the underwriters exercised the greenshoe option granted to them to purchase

additional shares of common stock of the Company. Under this option, underwriters purchased a total of 308,750 shares of

common stock of the Company on July 30, 2024. The net proceeds from the IPO and from the issuance under the

greenshoe option will be used for natural gas exploration and appraisal activities, progressing the Group’s three phases of

development and other general corporate purposes.

November 2024

At the time of the IPO, DWE agreed to waive the$7,500,000 payment obligation in respect of the Checkerboard

Strategy provided that Tamboran issue to DWE, or its nominee,312,500 shares of common stock. The number of shares to

be issued to satisfy the obligation was calculated as$7,500,000 divided by the IPO share price of$24.00. The issuance of

these shares in satisfaction of the obligation was subject to shareholder approval.

Shareholder approval took place at the Annual General Meeting on November 4, 2024, which was determined to be

the grant date for the purpose of valuing the common stock. From the time of the IPO in June 2024 to shareholder approval

in November 2024, the fair market value of the shares decreased from$24.00 to$19.04, while the number of shares to be

issued remained the same. The issuance of these shares completed the satisfaction of the above obligation in respect of the

Checkerboard Strategy (the “Checkerboard fee”) (Refer Note 2).

Note 8 – Stock-Based Compensation

Milestone Options

During thenine months ended March 31, 2025, the Group didnot grant any new milestone options to its employees

andno milestone options were forfeited.

The Company accelerated the recognition of the remaining expense for milestone options during thenine months

ended March 31, 2025. The Group recognized$138,996 (inclusive of accelerated expense) and$429,661, as stock-based

compensation expense related to milestone options for thenine months ended March 31, 2025, and March 31, 2024,

respectively. No expense was recognized for thethree months ended March 31, 2025, while$162,056 was recognized for

thethree months ended March 31, 2024.

Restricted Stock Units

On August 6, 2024, the Group adopted the 2024 Incentive Award Plan (the“2024 Plan”). As of March 31, 2025, the

maximum number of shares of common stock that may be issued under the 2024 Plan was 1,600,000 shares.

The 2024 Plan, allows, among other things, for the grant of Restricted Stock Units (“RSUs”). On August 6, 2024, the

Group issued RSUs to certain eligible service providers, employees and executive officers (the “participants”) to provide

them an opportunity to participate in the growth and profits of the Group and to attract, motivate, and retain their services

to promote the long-term success of the Group.

On August 6, 2024, the Company granted 47,400 Restricted Stock Units (“Retention Awards”) to its employees in

Australia and U.S. The Retention Awards granted to Australian employees entitle them to CDIs representing 39,250 shares

of common stock (each CDI represents 1/200 th of a share of common stock). Similarly, the Retention Awards granted to

U.S. employees entitle them to 8,150 shares of common stock. The vesting conditions state that all Retention Awards will

vest in full on December 31, 2025, provided the employee remain in service as of the vesting date. The fair value at grant

date of the Retention Awards was$21.73 per common stock and$0.109 per CDI.

On August 6, 2024, the Company also granted 795,000 Restricted Stock Units (“IPO Awards”) to its employees in

Australia and U.S. The IPO Awards granted to Australian employees entitle them to CDIs representing 620,000 shares of

common stock. Similarly, the IPO Awards granted to U.S. employees entitle them to 175,000 shares of common stock. The

IPO Awards will vest in following three tranches:

•Tranche 1 –397,500 IPO Awards granted to Australian and U.S. employees will vest in full on July 3, 2027,

provided the employee remains in service as of the vesting date. The fair value at grant date of Tranche 1 was

$21.73 per common stock and$0.109 per CDI.

•Tranche 2 –98,750 IPO Awards granted to Australian and U.S. employees will vest subject to the completion

of the Group’s Phase 1 Development Plan to establish first production of the Shenandoah South Pilot Project

and establish first production of 40 TJ/d measured by completion of the milestones (“Vesting Trigger

Conditions”). Full vesting of Tranche 2 may occur at any time between July 3, 2027, and July 3, 2029, should

the Vesting Trigger Conditions be satisfied, or unless otherwise determined by the Board of the Company. The

fair value at grant date of Tranche 2 was$21.73 per common stock and$0.109 per CDI.

•Tranche 3 –298,750 IPO Awards granted to Australian and U.S. employees will vest subject to the Company’s

Total Shareholder Return (“TSR”) reaching or exceeding the 75th percentile of the Benchmark Index TSR

between July 3, 2027, and July 3, 2029. TSR will be measured against the S&P SmallCap 600 Energy (or any

other market index determined by the Board in their sole discretion) (“Benchmark Index”) over the same

performance measurement period. The fair value at grant date of Tranche 3 was$19.64 per common stock and

$0.098 per CDI.

The grant date fair value of the Tranche 3 RSUs were determined through the use of the Monte Carlo simulation

method. This method requires the use of subjective assumptions such as the price and the expected volatility of the

Company’s common stock and its self-determined peer group companies’ stock, risk free rate of return, and cross-

correlations between the Company and its peer group companies. Expected volatilities for the Company and each peer

company utilized in the model are estimated using a historical period consistent with the awards’ remaining performance

period as of the grant date. The risk-free interest rate is based on the yield on U.S. Treasury Constant Maturity for a term

consistent with the remaining performance period. The valuation model assumes dividends, if any, are immediately

reinvested.

The following table summarizes the assumptions used to calculate the grant date fair value of the Tranche 3 RSUs

granted on August 6, 2024:

The Retention Awards and IPO Awards entitle the participants to receive the equivalent value (in cash or shares of

common stock/CDIs) of dividends paid on shares of common stock and CDIs, respectively.

The RSUs are not transferable. There are no participation rights or entitlements inherent in the RSUs and the

participants will not be entitled to participate in new issues of capital offered to stockholders or holders of CDIs.

If the Company makes a bonus issue of common stock, CDIs, or other securities to existing stockholders or holders

of CDIs (other than an issue in lieu or in satisfaction of dividends or by way of dividend reinvestment), the number of

shares of common stock or CDIs that must be issued on the exercise of a Retention Award or IPO Award, respectively, will

be increased by the number of shares of common stock or CDIs that the participant would have received if the participant

had exercised the RSUs before the record date for the bonus issue.

The following table presents the stock-based compensation costs recognized related to our RSUs for the three months

and nine months ended March 31, 2025:

2025 Director Restricted Stock Units

On January 1, 2025, the Company granted 27,281 Director RSUs for which each awarded RSU represented an

unfunded, unsecured right to receive a share of the Company’s common stock. These awards have a cliff-vesting period of

one year. The fair value on grant date of the RSUs was$20.99 per unit. All Director RSUs remained outstanding as of

March 31, 2025. The Company recognized$144,175 in stock-based compensation expense related to these Director awards

for thethree months ended March 31, 2025.

Note 9 – Income Taxes

The effective tax rates for the three months and nine months ended March 31, 2025, and 2024 werenil. The Group’s

effective tax rate differed from the applicable statutory income tax rate due to operating losses incurred for the three

months and nine months ended March 31, 2025, and 2024. The Group has accumulated losses for tax purposes as of

March 31, 2025, in the amount of$322,399,763, which may be carried forward and offset against taxable income in the

future for an indefinite period, subject to meeting Australian tax rules around continuity of ownership or business

continuity test.

As of March 31, 2025, and June 30, 2024, the Group didnot have any uncertain tax positions.

Note 10 – Loss Per Share

Basic net loss per share applicable to common stockholders is computed by dividing earnings applicable to common

stockholders by the weighted average number of common shares outstanding. Diluted loss per share assumes the

conversion of any convertible securities using the treasury stock method.

The computations for basic and diluted loss per share are as follows:

The Company’s potentially dilutive shares, which include outstanding milestone options and RSUs, havenot been

included in the computation of diluted net loss per share for the three months and nine months ended March 31, 2025, and

2024 as the result would be anti-dilutive.

Note 11 – Commitments and Contingencies

From time to time, the Group may be subject to various claims, title matters and legal proceedings arising in the

ordinary course of business, including environmental contamination claims, personal injury and property damage claims,

claims related to joint interest billings and other matters under natural gas operating agreements and other contractual

disputes. The Group maintains general liability and other insurance to cover some of these potential liabilities. All known

liabilities are fully accrued based on the Group’s best estimate of the potential settlement amount. While the outcome and

impact on the Group cannot be predicted with certainty, the Group believes that its ultimate liability with respect to any

such matters will not have a significant impact or material adverse effect on its financial positions, results of operations or

cash flows. Results of operations and cash flows, however, could be significantly impacted in the reporting periods in

which such matters are resolved.

Capital Commitments

Sweetpea

Sweetpea’s committed spend as of March 31, 2025, was$21,972,265, which was related totwo licenses, EP 136

with total commitments of$13,283,375 and EP 143 with total commitments of$8,688,890.

A renewal application for EP 136 was submitted to the Department of Mining and Energy (“DME”) (formerly the

Department of Industry, Tourism and Trade) in September 2023, and approved in July 2024, granting afive-year extension

for the period July 24, 2025 to July 23, 2030 with a minimum work program commitment of $13,283,375.

A variation application for EP 143 was submitted to DME in August 2024, and approved in October 2024. The total

minimum work program commitments remain the same at$8,688,890 with activity and associated spend being transferred

within the license term.

EP 161

For the EP 161 working interest, we are obligated to contribute our share of expenses to uphold our stake in this

permit, for which Santos Limited is the operator. Our commitment through March 2026 is expected to be$2,500,400 based

on the minimum work requirements. There areno minimum commitment requirements after March 2026.

Beetaloo Joint Venture

An application was submitted to DME in September 2024 to vary the year 2 and 3 work program, and was approved

in November 2024. The terms of the Beetaloo Joint Venture continue to necessitate specific minimum work obligations

through May 2028. These commitments include an expected spend of$70,761,319 related to drilling and multi-stage

hydraulic fracturing offour wells, 3D seismic survey, and subsurface studies, with expenditure across EP 76 of

$10,173,502, EP 98 of$49,566,523 and EP 117 of$11,021,294.

Midstream

Committed spend for the SPCF project as of March 31, 2025, was$4,955,806 which was related tothe engineering,

procurement, and construction management for the detailed design, engineering, planning, construction, testing, inspection

and commissioning of the facility and major equipment procurement.

Environmental

The Group’s operations are subject to risks normally associated with drilling, completion and production of oil and

gas, including blowouts, fires, and environmental risks such as oil spills or gas leaks that could expose the Group to

liabilities associated with these risks.

In the Group’s acquisition of existing or previously drilled well bores, the Group may not be aware of prior

environmental safeguards, if any, that were taken at the time such wells were drilled or during such time the wells were

operated. The Group maintains comprehensive insurance coverage that it believes 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 or restoration, the

liability to cure such a violation could still fall upon the Group. No claim has been made, nor is the Group aware of any

liability which the Group may have, as it relates to any environmental cleanup, restoration, or the violation of any rules or

regulations relating thereto except for the matter discussed above.

Legal Proceedings

The Group is a party to legal proceedings encountered in the ordinary course of its business. While the ultimate

outcome and impact to the Group cannot be predicted with certainty, in the opinion of management, it is remote that these

legal proceedings will have a material adverse impact on the Group’s condensed consolidated financial condition, results of

operations or cash flows.

Other Commitments and Contingencies

As part of its ongoing business and operations, the Group is required to provide bank letters of credit and bank

guarantees for various purposes, including environmental remediation, reclamation, construction costs and other general

corporate purposes.

On December 19, 2024, TR Ltd., as guarantor, entered into the Facility Agreement with TR West, as borrower, each

a wholly-owned subsidiary of the Company, as obligors, and Macquarie Bank Limited (“Macquarie”), as lender. The

Facility Agreement provides TR West with A$25,000,000 in availability (“Facility A”) for letters of credit and bank

guarantees (“performance bonds”), and includestwo potential additional performance bond facilities, each in the amount of

A$5,000,000 (“Facility B” and “Facility C,” respectively, and collectively, the “Facilities”). Availability under the Facility

B and Facility C is subject, among other conditions, to the Company raising additional capital in the amounts of at least

A$62,500,000 and A$75,000,000, respectively. All Facilities terminate on December 19, 2027. The obligations under the

Facility Agreement are unconditionally guaranteed on a senior secured basis by TR Ltd.

The Facilities are subject to customary representations, warranties and ongoing affirmative and negative covenants

and agreements. The Group is required to maintain Minimum Liquidity of A$20,000,000 and have a current ratio of at least

1:1. The Facility Agreement provides for events of default that include, among others, nonpayment of any amount due

under the Facility Agreement, breach of covenants and certain events of bankruptcy or insolvency. If an event of default

occurs, Macquarie will be able to, among other things, terminate the commitments immediately, declare any amounts

outstanding to be due and payable in whole or in part, and exercise other rights and remedies. The Group was in

compliance with all terms of the Facility Agreement as of March 31, 2025.

In relation to Facility A, the Group incurred an establishment fee of A$500,000. The outstanding letters of credit and

bank guarantees under the Facilities are subject to a drawdown fee of 10% per annum, payable quarterly in arrears. The

Group is also required to pay a commitment fee of 4% per annum, payable quarterly in arrears, on the average monthly

unused amount of the Facilities. If the borrower fails to pay any amount payable under the Facility Agreement by the due

date, interest accrues on the overdue amount at a rate of 12% per annum, payable quarterly in arrears.

As of March 31, 2025, there was A$7,684,129 of letters of credits issued under the Facility Agreement. As of

March 31, 2025 there was A$17,315,872 of unused credit under Facility A and A$10,000,000 of unused credit under

Facility B and Facility C.

Costs incurred in connection with securing the Facility Agreement, including fees paid to legal advisors and third

parties, are deferred and amortized to interest expense over the term of the Facility Agreement. As of March 31, 2025, total

unamortized debt issuance costs were A$770,142. During the three months and nine months ended March 31, 2025, the

Group recorded A$72,201 and A$96,268, respectively, as amortization of deferred debt issuance costs as a part of interest

expense.

In December 2024, Tamboran B1 Operator signed a Development Agreement (“DA”) with APA Group (“APA”) that

defines the conditions under which APA will design and construct the SPP. Under the DA, Tamboran B1 Operator is

required to put in place bank guarantees that cover approximately two-thirds of APA’s projected construction cost.

Tamboran’s share of the bank guarantees over the next three months is estimated to be A$10.7 million. Pursuant to the Gas

Transportation Agreement (“GTA”) signed with APA, the bank guarantees will be released by APA once certain

performance conditions are met and first gas has been delivered to the NT Government under the Gas Sales Agreement

(“GSA”). APA may call on the bank guarantees if certain defaults under the DA or GTA remain unremedied, which in turn

triggers a requirement by Tamboran B1 Operator to deposit cash amounts sufficient to cover the bank guarantees under the

Facility Agreement with Macquarie.

Note 12 – Related Party Transactions

The Group transacts withtwo shareholders identified as related parties, H&P and Mr. Bryan Sheffield (“Mr.

Sheffield”). The transactions during thenine months ended March 31, 2025 are as follows.

H&P

During the year ended June 30, 2023, the Group entered into a strategic alliance with H&P and secured a

$15,000,000 equity investment from H&P (and as a consequence, a member of the H&P Executive Leadership Team was

appointed as a director of the Group). The strategic alliance resulted in H&P supporting the Group’s development plans in

the Beetaloo Basin through their equity investment in the Company while at the same time executing on H&P’s strategy to

gain more international exposure through the use of drilling rigs in Australia.

On July 1, 2023, the lease commenced with H&P for the use of the FlexRig® for a 25-month period (Refer Note 4).

During the three months and nine months ended March 31, 2025, the Group incurred cost of$2,125,323 and$10,224,710

relating to a combination of site mobilization, standby, drilling, labor and rig move costs,$1,466,155 ofwhich remained

invoiced and unpaid as of March 31, 2025.

Mr. Sheffield

During thethree months ended and thenine months ended March 31, 2025, the Group transacted with DWE and

DWI, which are wholly owned by Formentera Australia Fund, LP, which is managed by Formentera Partners, LP, a private

equity firm of which Mr. Sheffield serves as managing partner. Given the equity investments made by Mr. Sheffield in

prior periods, an individual employed by Formentera Partners, LP, was appointed director of the group in September 2023.

Subsequent to March 31, 2025, this individual advised the Group's Board of Directors of their resignation effective April

15, 2025. Mr. Sheffield has been a shareholder in the Company since November 2021.

The Group and DWE jointly own a 50/50 joint venture referred to as TB1 and the Group and DWI jointly own a

50/50 joint venture referred to as SPCF Sub Trust (Refer Note 2).

During thethree months ended March 31, 2025, DWE's share of expenditure for the Beetaloo Joint Venture for

which contributions were due was$19,786,665. During thenine months ended March 31, 2025, DWE's share of

expenditure for the Beetaloo Joint Venture for which contributions were due was$44,778,280. As of March 31, 2025, the

Group had unpaid cash calls owing from DWE in the amount of$5,843,608.

During the three months ended March 31, 2025, the SPCF assets were transferred from TB1 to the SPCF Sub Trust

(Refer Note 2). Subsequent to the transfer, cash calls were issued to DWI.

During the three months and nine months ended March 31, 2025, DWI's share of expenditure for SPCF for which

contributions were due was$1,474,968. As of March 31, 2025, the Group had unpaid cash calls owing from DWI in the

amount of$921,332.

During thenine months ended March 31, 2025, the Company issued 312,500 shares of Common Stock in satisfaction

of the Group's obligation towards the Checkerboard fee (Refer Note 2 and Note 7).

Note 13 – Subsequent Events

Entry into a Material Definitive Agreement

Subscription Agreements

On May 12, 2025, the Company entered into subscription agreements (the “Subscription Agreements”) with certain

investors (the “Investors”), pursuant to which, among other things, the Investors agreed to subscribe for and purchase from

the Company, and the Company agreed to issue and sell to the Investors, an aggregate of approximately 3.1 million newly

issued shares of the Company’s common stock, par value$0.001 (“Common Stock”), for an aggregate purchase price of

approximately$55 million, on the terms and subject to the conditions set forth therein (the “Offering”). Of the Offering,

$44 million is expected to close on May 16, 2025, subject to the satisfaction of customary closing conditions. The closing

of the remaining$11 million is subject to approval by Tamboran’s shareholders and the satisfaction of other customary

closing conditions.

Pursuant to the Subscription Agreements, the Company has agreed to use commercially reasonable efforts to file

with SEC, within 30 calendar days after May 12, 2025, a registration statement registering the resale of the shares of

Common Stock (the “Registrable Securities”). The Company shall use its commercially reasonable efforts to have such

registration statement declared effective as soon as practicable after filing, but no later than the 60th calendar day (or 90th

calendar day if the SEC notifies the Company that it will review the registration statement) following the Closing. The

Company is also obligated to maintain the effectiveness of the registration statement for a period ending on the earlier of

(A) the date the Investor ceases to hold any Registrable Securities, (B) the date all Registrable Securities held by the

Investor may be sold without restriction under Rule 144, or (C)three years from the effective date of the registration

statement.

The foregoing description of the Subscription Agreements does not purport to be complete and is qualified in its

entirety by reference to the copy of the forms of Subscription Agreements, copies of which will be filed as exhibits to our

Annual Report on Form 10-K for the year ending June 30, 2025.

Asset Sale Agreement – Beetaloo Acreage Position

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 approximately 12.5% of TR West’s 77.5% interest in the

applicable retention licenses for$15 million.

The foregoing description of the Asset Sale Agreement does not purport to be complete and is qualified in its entirety

by the text of the Asset Sale Agreement, a copy of which will be filed as an exhibit to our Annual Report on Form 10-K for

the year ending June 30, 2025.

Second Amended and Restated Joint Venture and Shareholders Agreement

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 “Second Amended and Restated 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.

•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 million, or$150 per acre. The transaction is subject to regulatory approvals.

•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 Falcon Oil & Gas (Australia) Limited (Falcon)

(22.5%) holding the remaining interest.

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

Area. The formal process will commence on release of the IP30 flow test from the Shenandoah South 2H

sidetrack (SS-2H ST1) well, planned for June 2025. DWE will have participation rights to any transaction on the

same terms.

•Ownership of the Pilot Area, the focus for initial gas production in the Northern Territory, remains unchanged (the

Company 47.5% operator, DWE 47.5% and Falcon 5%).

•The Company will hold 77.5% operating interest in the ex-EP 76, 98 and 117 acreage, with Falcon Oil & Gas

(Australia) Limited holding the remaining 22.5% interest.

The foregoing description of the Amended and Restated JVSA does not purport to be complete and is qualified in its

entirety by the text of the Amended and Restated JVSA, a copy of which will be filed as an exhibit to our Annual Report

on Form 10-K for the year ending June 30, 2025.

Unregistered Sale of Equity Securities.

PIPE Transaction

The Common Stock to be issued and sold to the Investors pursuant to the Subscription Agreements will not be

registered under the Securities Act of 1933, as amended (the “Securities Act”), and will be issued in reliance on the

exemption from registration requirements thereof provided by Section 4(a)(2) of the Securities Act as a transaction by an

issuer not involving a public offering. The disclosure set forth above in relation to the Subscription Agreements is

incorporated by reference here.

The Group has evaluated its subsequent events occurring after March 31, 2025, through May 13, 2025, which

represents the date these condensed consolidated financial statements were available to be issued. No further subsequent

events have been identified that would require disclosure in these condensed consolidated financial statements.