Tamboran Resources Corp
For the period ended Jun 30, 2026. Filed Sep 25, 2026.
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A company's yearly report to the SEC, with audited financial statements. It is the fullest account a company gives of its business, its finances and the risks it sees.
FY2026 · Filed Sep 25, 2026
TBN$28.90+3.0%Stored close · as of Nov 6, 2026
What changed in Management’s Discussion and Analysis?
Read the current filingPrevious report: 10-K
Period ended 2025-06-30; filed 2025-09-25.
0001628280-25-042774
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of OperationsCurrent report: 10-K
Period ended 2026-06-30; filed 2026-09-25.
0001628280-26-063492
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of OperationsThe baseline is this issuer’s latest earlier reporting period of the same form that was filed before the current report. A previous 10-Q is a different quarter, not a year-over-year comparison. Amendments are excluded.
Compared 103 previous paragraphs and 99 current paragraphs.
56 unchanged; 33 reworded; 10 added; 14 removed; 0 previous and 0 current paragraphs rearranged.
Tables are not compared: 4 previous and 4 current tables excluded. Dates, whitespace, punctuation and numbering changes are ignored; changes to financial figures remain significant.
A changed paragraph is not evidence that risk increased or decreased. An unchanged paragraph does not establish that risk stayed the same.
Added paragraphs (10)
Current report
In July 2026, Tamboran completed the stimulation campaign on the SS2-4H, SS2-5H and SS2-3H wells in the Northern Pilot Area. The program was the first three-well zipper stimulation and the largest stimulation campaign conducted in the Beetaloo Basin, with 178 stages placed across approximately 30,000 lateral feet, including ten stages of locally produced Beetaloo Red Sand in the SS2-5H well. The 2026 three well drilling program on the SS1 pad commenced following mobilization of the H&P FlexRig® Flex 3 rig to the SS1 pad with spudding of the first well on July 2, 2026. The SS1-6H and SS1-4H wells have been drilled and cased to total depth with 9,505-foot and 9,329-foot usable lateral sections, respectively, and the SS1-2H well is currently being drilled. Stimulation of the three SS1 wells is planned for the fourth quarter of calendar year 2026.
Current report
Practical completion of the SPP occurred on July 17, 2026 and mechanical completion of the SPCF occurred on July 26, 2026. In early September 2026, Tamboran commenced the commissioning of the SPCF, with first gas sales delivered into the Northern Territory gas market on September 5, 2026 from the Company's Shenandoah South 2 pad to the NT Government at a discounted price (75% of the contract price) to the long-term Gas Sales Agreement, reflecting the interruptible nature of supply during commissioning. Two wells are currently delivering unconstrained rates into the market, with the remaining wells to be brought online as required to deliver nominated volumes, and volumes are expected to ramp up to the plateau of 40 TJ/d in accordance with the Northern Territory Government's nominations. Commissioning activities are expected to be completed in the fourth quarter of calendar year 2026.
Current report
In early September 2026, Santos, as operator of EP 161 (Tamboran 25%), spudded the Jibera South 1H well with the Ensign 971 rig, the first of a two well appraisal program in the Beetaloo East depocenter. The Jibera South 1H and Newcastle South 1H wells are planned to be drilled with 10,000-foot horizontal sections targeting the Mid Velkerri B Shale and stimulated and flow tested across up to 60 stages per well, with stimulation planned for mid-2027.
Current report
In September 2026, Tamboran and Liberty Energy entered into a non-binding Memorandum of Understanding setting out the intent to extend the hydraulic fracture stimulation and wireline services agreement covering Tamboran's Beetaloo Basin operations, under which Liberty Energy intends to begin phasing lower-emissions pumping equipment into the Beetaloo fleet from 2027. See “Items 1 and 2. Business and Properties—Our Business Plan.”
Current report
Through June 30, 2026, we had not generated any revenue from natural gas production due to the stage of our operations, which was appraisal drilling and the final stages of midstream construction. No revenue from natural gas production is reflected in our financial statements as first sales occurred after the period end.
Current report
In fiscal year 2026, the Group completed the acquisition of approximately 98.1% of the issued and outstanding equity interests of Falcon Australia and all of the issued and outstanding equity interests of (i) Falcon Hungary, (ii) Falcon Ireland, (iii) Falcon Holdings and (iv) Falcon South Africa.
Current report
Exploration expense. Exploration expense decreased by $0.8 million during fiscal year 2026, as compared to fiscal year 2025, as the prior period had increased activity for topographical, geographical and geophysical studies and other indirect expenditures while the current period had increased indirect expenditure related to our non-operated permits while the operated permits focused on the flow test for SS2-1H and preparation of the stimulation programs of SS2-4H, SS2-5H, and SS2-3H, the costs of which are capitalized.
Current report
Camp expense recoveries, net. During the year ended June 30, 2026, expenses for the field camp of $2.5 million were recognized primarily related to camp utilization, camp services, and related consumables. These costs are offset by recoveries from external parties who utilize the camp.
Current report
As of June 30, 2026, we had $219.1 million in cash and cash equivalents. This balance represents an increase of $179.7 million from June 30, 2025, as a result of proceeds from cash calls, capital raising activities and the Syndicated Facility Agreement offset by consideration paid for the Falcon Acquisition and spending related to operations on the SS2-5H, SS2-3H and SS2-1H pilot wells, construction of the SPCF and other corporate expenditures in the fiscal period.
Current report
As of June 30, 2026, the Group had contractual commitments of approximately $23.0 million relating to the remaining construction and commissioning of the SPCF project, compared to $9.1 million as of June 30, 2025. As of June 30, 2026, construction of the facility was approximately 90% complete and overall project completion was approximately 93%. Given the advanced stage of the project, substantially all of the remaining forecast expenditure required to complete the facility has been contracted and is reflected in the contractual commitment amount above. The $13.9 million increase from the prior year principally reflects the contracting during fiscal year 2026 of the entirety of the commissioning phase and remaining construction, which had not been contracted as of June 30, 2025. All of the committed amount is expected to be settled within six months of the balance sheet date.
Removed paragraphs (14)
Previous report
Following a special meeting of stockholders, on July 22, 2025, the second tranche of the Company’s sale of approximately $55.4 million of common stock in a private investment in public equity closed and the Company issued 940,729 shares of common stock at a price per share of $17.74. Additionally, on July 22, 2025, the Company issued 112,740 shares of Common Stock at a price of $17.74 per share to Macquarie Bank Limited as prepayment for certain fees that will become due under the Performance Bond Facility Agreement between Tamboran (West) Pty Limited, as borrower, Tamboran Resources Pty Ltd, as guarantor, and Macquarie Bank Limited, as lender, dated December 19, 2024.
Previous report
On July 27, 2025, we entered into a Cooperation Agreement (the “Cooperation Agreement”) with Bryan Sheffield, Sheffield Holdings, LP and certain other affiliated entities party thereto (collectively, the “Sheffield Group”). In connection with the Cooperation Agreement, the Company agreed, among other things, to appoint (i) Scott D. Sheffield as a Class II director to the board of directors, effective immediately upon the execution of the Cooperation Agreement, with a term expiring at the Company’s 2025 annual meeting of stockholders and (ii) Phillip Z. Pace as a Class III director to the board of directors, effective upon the execution of the Cooperation Agreement with a term expiring at the Company’s 2026 annual meeting of stockholders. In connection with the Cooperation Agreement, the members of the Sheffield Group have agreed to abide by certain customary standstill restrictions and voting commitments that will remain effective from July 27, 2025 until the earlier of (i) the Company’s 2028 annual meeting of stockholders and (ii) December 31, 2028, unless earlier expired in accordance with the terms of the Cooperation Agreement.
Previous report
On July 28, 2025, the employment of Joel Riddle, the former Chief Executive Officer and board member of the Company, was terminated and consequently Mr. Riddle resigned from the board. Additionally, John Bell Sr. retired from the board effective upon the execution of the Cooperation Agreement. The board appointed Dick Stoneburner, Chairman of the board, as interim Chief Executive Officer. Mr. Stoneburner was an independent member of the board prior to the appointment and will continue to serve on the board.
Previous report
On August 14, 2025, the lease of modular buildings and related equipment (“Stage 1 and 2 Hire Goods”) commenced pursuant to the Hire Terms and Conditions (the “Hire Conditions”) entered into with Northern Transportables Pty Ltd on June 9, 2025 to support the on-site operations. Pursuant to the Hire Conditions, Tamboran is required to pay A$223,826 per month for Stage 1 and 2 Hire Goods witha minimum hire period of 18 months. The Hire Conditions also provide an option for Tamboran to hire additional assets (“Stage 3 Hire Goods”) at a hire rate of A$395,536 per month for a minimum hire period of seven months.
Previous report
On September 2, 2025, the Beetaloo Joint Venture received approval from the NT Government to sell appraisal gas from its exploration permits in the Beetaloo Basin under the Beneficial Use of Gas (“BUG”) legislation. This is the first approval granted by the NT Government through the new BUG legislation and follows the recent consent from Native Title Holders for the sale of up to 60 TJ per day from the Shenandoah South Pilot Project over a three-year period. The Beetaloo Joint Venture now holds all necessary approvals to sell gas from the Shenandoah South Pilot Project. The project aims to begin gas sales of up to 40 TJ per day under the NTGGSA commencing in mid-2026, subject to weather condition.
Previous report
Recent Events and Formation Transactions
Previous report
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 “Business and Properties—General Development of Business and Corporate Reorganization.”
Previous report
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.
Previous report
U.S. Reporting Company Expenses
Previous report
Prior to our Corporate Reorganization, the ordinary shares of TR Ltd. were listed on the ASX. Following our IPO, and the listing of our common stock on the NYSE, we are 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.
Previous report
Exploration expense. Exploration expense increased by $2.0 million during fiscal year 2025, as compared to fiscal year 2024 due primarily to the increase in activity of our non-operated permits in preparation for the next drilling program and additional subsurface expenses. Our exploration expense consisted of costs related to topographical, geographical and geophysical studies and other indirect expenditure.
Previous report
Loss on extinguishment of debt. For fiscal year 2024, an expense for loss on extinguishment of debt of $3.9 million was recognized. The recognition of such an expense was due primarily to the extinguishment of payables to H&P in exchange of the issuance of the 5.5% Convertible Senior Note due in 2029 between Helmerich & Payne International Holdings, LLC, Tamboran Resources Corporation, and the guarantors thereto dated June 4, 2024, which was converted to common stock upon the IPO. There was no extinguishment of debt for fiscal year 2025.
Previous report
As of June 30, 2025, we had $39.4 million in cash and cash equivalents. This balance represents a decrease of $35.3 million from June 30, 2024, primarily due to incoming funds from the greenshoe option exercised in July 2024, the sale of rig 403 in October 2024, R&D tax credits received in December 2024, cash calls received throughout the period, proceeds from our subscription agreements to institutional investors in May 2025, offset primarily by spending on operations on the SS-2H, SS-2H side track, and SS-3H pilot wells, SPCF facility long lead items and civil works, NT LNG pre-front-end engineering and design services, and other corporate expenditure in the fiscal period.
Previous report
Committed spend for the SPCF project as of June 30, 2025, was $9.1 million which was related to the engineering, procurement, and construction management for the detailed design, engineering, planning, construction, testing, inspection and commissioning of the facility and major equipment procurement.
Reworded paragraphs (33)
Previous wording
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 hold approximately 1.9 million net prospective acres and are the largest acreage holder in the Beetaloo Basin. We intend to continue to develop our resources and regularly review acquisition opportunities that meet our strategic and financial objectives.
Current wording
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 hold approximately 2.8 million net prospective acres and are the largest acreage holder in the Beetaloo Basin. We intend to continue to develop our resources and regularly review acquisition opportunities that meet our strategic and financial objectives.
Previous wording
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, 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.
Current wording
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 61.25% working interest in EPs 76, 98 and 117, where we are the operator, and (iii) a 100% working interest in EPs 136 and 143, where we are the operator, all of which are located in the Beetaloo. Refer to our working interest following the completion of several transactions in “Items 1 and 2. Business and Properties” for additional information.
Previous wording
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 pre-purchased long lead materials including casing and tubulars, chemicals and downhole equipment necessary for our planned development for fiscal year 2026. We have in place a 10-year option with H&P to contract for up to four 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.
Current wording
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 pre-purchased long lead materials including casing and tubulars, chemicals and downhole equipment necessary for our planned development for fiscal year 2027. We have in place a 10-year option, of which six years remain, with H&P to contract for up to four 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.
Previous wording
We have not yet commenced natural gas production. If and when we do commence production, we will incur additional operating costs and expenses, workover costs, taxes and royalty fees. Our operating costs and expenses consisted of the following during fiscal years 2024 and 2025: 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 corporate assets, the loss on sale of assets due to the sale of rigs in fiscal year 2024 and 2025, accretion of asset retirement obligations, exploration expenses, LNG feasibility studies, a Checkerboard fee that was settled in shares of common stock, and general and administrative expenses.
Current wording
During the fiscal year ended June 30, 2026, natural gas production had not commenced. The initial gas sales in September 2026 should be construed as initial test sales. If and when we do commence natural gas production in quantities to generate regular revenue, we will incur additional operating costs and expenses, workover costs, taxes and royalty fees. Our operating costs and expenses consisted of the following during fiscal years 2026 and 2025: 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 corporate assets, the loss on sale of assets due to the sale of rigs in fiscal year 2025, accretion of asset retirement obligations, exploration expenses, LNG feasibility studies, a Checkerboard fee that was settled in shares of common stock in fiscal year 2025, and general and administrative expenses.
Previous wording
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 and the Middle East conflict, the changing U.S. regulatory environment and trade and tariffs policies, 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.
Current wording
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 Russia-Ukraine war, the Iran-United States war and the broader Middle East conflict, the changing U.S. regulatory environment and trade and tariffs policies, the Australian domestic gas market reservation policy, 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. These key factors will only affect us when we produce and sell natural gas.
Previous wording
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 2025 and 2024, respectively.
Current wording
Revenue and other operating income. The commissioning phase of the Pilot Project commenced in September 2026 (subsequent to fiscal year 2026). Therefore, we did not realize any revenue and other operating income during fiscal years 2026 and 2025, respectively.
Previous wording
Compensation and benefits, including stock based compensation. Compensation and benefits, including stock based compensation, increased by $4.0 million during fiscal year 2025, as compared to fiscal year 2024 due primarily to restricted stock units granted in August 2024 and increased headcount as compared to the prior period.
Current wording
Compensation and benefits, including stock-based compensation. Compensation and benefits, including stock based compensation, increased by $3.1 million during fiscal year 2026, as compared to fiscal year 2025 largely due to period on period increase in headcount, the transition to a calendar year employee bonus schedule, and compensation awarded to the interim and new CEO.
Previous wording
Consultancy, legal and professional fees. Consultancy, legal and professional fees decreased by $2.9 million during fiscal year 2025, as compared to fiscal year 2024 due primarily to professional fees related to implementation of the scheme of arrangement and IPO readiness incurred in the comparative period which did not recur in 2025.
Current wording
Consultancy, legal and professional fees. Consultancy, legal and professional fees remained fairly consistent period-over-period.
Previous wording
Loss on sale of assets classified as held for sale. Tamboran recognized a loss on assets classified as held for sale amounting to $0.4 million during fiscal year 2025, primarily due to the write down of rig 403 to the fair value less costs to sell. In contrast, a loss on assets classified as held for sale amounting to $0.03 million was recognized during fiscal year 2024, primarily due to the sale of a smaller rig, rig 301.
Current wording
Loss on remeasurement of assets classified as held for sale. Tamboran recognized a loss on assets classified as held for sale amounting to $0.4 million during fiscal year 2025 primarily due to the write down of rig 403 to the fair value less costs to sell. Tamboran disposed of all assets held for sale in fiscal year 2025.
Previous wording
Accretion of asset retirement obligations expense. For fiscal year 2025 an expense for accretion of asset retirement obligations of $1.0 million was recognized. The recognition of such an expense was primarily due to the accretion of asset retirement obligation liabilities in relation to all EPs, inclusive of EPs 76, 98, 117, 136 and 161, as well as the SPCF. As the Company drilled two additional wells and established the SPCF site, there was an incremental expense for accretion during the period.
Current wording
Accretion of asset retirement obligations expense. For fiscal year 2026, an expense for accretion of asset retirement obligations of $1.2 million was recognized. The recognition of such an expense was primarily due to the accretion of asset retirement obligation liabilities in relation to all EPs, inclusive of EPs 76, 98, 117, 136 and 161, as well as the SPCF pad.
Previous wording
LNG feasibility study expense. For fiscal year 2025, the Company incurred expenses of $6.0 million related to certain studies and pre-front-end engineering and design services related to the proposed NT LNG facility.
Current wording
LNG feasibility study expense. In fiscal year 2025, the Group incurred expenses of $6.0 million related to certain studies and pre-front-end engineering and design services related to the NTLNG facility. These studies were substantially completed in fiscal year 2025, therefore, the expense related to these studies was de minimis in fiscal year 2026.
Previous wording
Checkerboard fee. For fiscal year 2025, the Company incurred an expense of $6.0 million related to the satisfaction of certain payment obligations to DWE under the TB1 Joint Venture Agreement. This obligation was satisfied through the issuance of common stock, subsequent to shareholder approval received in November 2024.
Current wording
Checkerboard fee. For fiscal year 2025, the Group incurred an expense of $6.0 million related to the satisfaction of certain payment obligations to DWE under the TB1 Joint Venture Agreement. This obligation was satisfied through the issuance of common stock, subsequent to shareholder approval received in November 2024. No such expense was incurred in fiscal year 2026.
Previous wording
General and administrative. General and administrative costs increased by $3.3 million during fiscal year 2025, as compared to fiscal year 2024 primarily as a result of increased expenses related to insurance, headcount, travel, and other office and administrative fees.
Current wording
General and administrative. General and administrative costs increased by $0.9 million during fiscal year 2026, as compared to fiscal year 2025, primarily as a result of increased expenses related to insurance, headcount, travel, and other office and administrative fees.
Previous wording
Interest Income, net. Interest income, net increased by $0.9 million during fiscal year 2025, as compared to fiscal year 2024, primarily due to interest received from term deposits during the period.
Current wording
Interest Income, net. Interest income, net increased by $1.1 million during fiscal year 2026, as compared to fiscal year 2025, primarily due to interest received from cash at bank and term deposits during the period.
Previous wording
Foreign currency translation. In fiscal year 2025 we recognized a foreign currency translation gain of $2.8 million, primarily due to the strengthening of the Australian Dollar as of June 30, 2025 in comparison to the average rate during the period. In fiscal year 2024, we recognized a foreign currency translation loss of $0.4 million, primarily due to slight weakening of the Australian Dollar as of June 30, 2024, as compared to July 1, 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.
Current wording
Foreign currency translation. In fiscal year 2026, we recognized a foreign currency translation gain of $11.9 million, primarily due to the strengthening of the Australian Dollar as of June 30, 2026 in comparison to the average rate during the fiscal year 2026. In fiscal year 2025, we recognized a foreign currency translation gain of $2.8 million, primarily due to the strengthening of the Australian Dollar as of June 30, 2025 in comparison to the average rate during the period. 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.
Previous wording
Income Tax Expense. We have no income tax expense primarily due to operating losses incurred for fiscal years 2025 and 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.
Current wording
Income Tax Expense. We have no income tax expense primarily due to operating losses incurred for fiscal years 2026 and 2025. 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 sufficient income 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.
Previous wording
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 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, net proceeds of the private placements received in July 2025, and funds from future private and public equity placements, debt funding and asset sales.
Current wording
We are an exploration and appraisal 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 substantial revenue from production until early calendar year 2027, at the earliest, which will depend upon successful drilling results, completion of commissioning of the gas processing facility, additional and timely capital funding, and access to suitable infrastructure. Until then our primary sources of liquidity are expected to be cash on hand and funds from future private and public equity placements, debt funding and asset sales.
Previous wording
•complete our current appraisal drilling, testing program and SPCF facility construction;
Current wording
•complete our current appraisal drilling, testing program and SPCF commissioning;
Previous wording
•develop and commercialize our assets, including development of pipelines, the proposed NT LNG facility and other infrastructure;
Current wording
•develop and commercialize our assets, including development of pipelines, the proposed NTLNG facility and other infrastructure;
Previous wording
For the fiscal year ended June 30, 2026, we estimate that we will need to invest approximately $57 million to progress our upstream development plans. We expect the tranche two proceeds from the private placement received in July 2025, together with our existing cash on hand, to be sufficient to fund drilling of SS-4H, SS-5H and SS-6H and complete flow testing of SS-2H ST1. 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.
Current wording
For the fiscal year ending June 30, 2027, we estimate that we will need to invest approximately $113.3 million to progress our Pilot Project development plans. We expect cash on hand and available funds from the committed undrawn portion of the SPCF debt facility to be sufficient to fund the stimulation and tie-in costs of the SS2-3H, SS2-4H and SS2-5H wells (completed in July and August 2026 ahead of production start-up), drilling and stimulation costs of SS1-6H, SS1-4H and SS1-2H for production tie-in during 2027, long leads for further production wells and committed SPCF construction costs. 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.
Previous wording
The following table summarizes our key measures of liquidity for the periods indicated (all dollar amounts are presented in thousands).
Current wording
The following table summarizes our key measures of liquidity for the periods indicated (in thousands).
Previous wording
As of June 30, 2025, Sweetpea committed to spend $23.1 million related to two licenses, EP 136 with total commitments of $14.0 million and EP 143 with total commitments of $9.1 million over the following five years.
Current wording
As of June 30, 2026, Sweetpea committed to spend $24.0 million related to two licenses, EP 136 with total commitments of $14.5 million and EP 143 with total commitments of $9.6 million.
Previous wording
A renewal application for EP 136 was submitted to the Department of Mining and Energy (“DME”) in September 2023, and approved in July 2024, granting a five-year extension for the period July 24, 2025 to July 23, 2030 with a minimum work program commitment of $14.0 million.
Current wording
A renewal application for EP 136 was submitted to the Department of Mining and Energy (“DME”) in November 2025, requesting an extension of the permit for a period of 18 months to January 2031. DME replied in July 2026 and agreed to a permit extension only through July 2030. As such, the Group maintains a minimum work program commitment of $14.5 million.
Previous wording
A variation application including suspension and extension of Term 2 to December 31, 2028 for EP 143 was submitted to DME in March 2025, and approved in May 2025. The total minimum work program commitments remain the same at$9.1 million with activity and associated spend being transferred within the extended license term.
Current wording
An application for EP 143 was submitted and approved by the DME in June 2026 requesting a variation of the minimum work program for years 2 and 3. The total minimum work program commitments remained the same at$9.6 million
Previous wording
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 $2.3 million based on the minimum work requirements. There areno minimum commitment requirements after March 2026.
Current wording
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. An application was approved in December 2025 to extend the term of the exploration permit and the required work program which includes the drilling and stimulation of two horizontal wells, along with related geological and geophysical studies to March 2027. Our commitment through March 2027 is expected to be $6.0 million based on the minimum work requirements. There areno minimum commitment requirements after March 2027.
Previous wording
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$75.6 million related to drilling and multi-stage hydraulic fracturing of four wells, 3D seismic survey, and subsurface studies, with expenditure across EP 76 of$10.7 million, EP 98 of$53.3 million and EP 117 of$11.6 million as well as subsurface studies.
Current wording
A variation application was submitted to DME in September 2025 to vary the minimum work program for years 3, 4 and 5. Refer to Note 17 for further details. These commitments include an expected spend of $73.3 million related to drilling and multi-stage hydraulic fracturing of four wells, 3D seismic survey, and subsurface studies, with expenditure across EP 76 of $14.1 million, EP 98 of $43.7 million and EP 117 of $15.5 million.
Previous wording
For fiscal year 2025, net cash used in operating activities was $29.6 million during which we incurred a net loss of $39.6 million, compared to net cash used in operating activities for fiscal year 2024 of $11.4 million, during which we incurred a net loss of $23.9 million. The net loss for fiscal year 2025 included the non-cash impacts of depreciation and amortization, stock-based compensation, loss on remeasurement of assets classified as held for sale, accretion of asset retirement obligations, interest expense, Checkerboard fee and foreign exchange differences. Additionally, in the year ended June 30, 2025, net unfavorable changes in operating assets and liabilities totaled $4.8 million, primarily consisting of a $3.3 million decrease in accounts payable and accrued expenses due to timing of our pay cycle during the fiscal period, a $1.3 million increase in trade and other receivables, and a $0.2 million increase in prepaid expenses and other assets.
Current wording
For fiscal year 2026, net cash used in operating activities was $34.6 million during which we incurred a net loss of $30.5 million, compared to net cash used in operating activities for fiscal year 2025 of $29.6 million, during which we incurred a net loss of $39.6 million. The net loss for fiscal year 2026 included the non-cash impacts of depreciation and amortization, stock-based compensation, performance bond facility fees, accretion of asset retirement obligations, interest expense and foreign exchange differences. Additionally, in the year ended June 30, 2026, net unfavorable changes in operating assets and liabilities totaled $12.5 million, primarily consisting of an $8.3 million decrease in accounts payable and accrued expenses due to timing of our pay cycle during the fiscal period, and a $7.8 million increase in prepaid expenses and other assets, partially offset by a $2.9 million decrease in trade and other receivables.
Previous wording
For fiscal year 2025, net cash used in investing activities was $98.8 million compared to $66.1 million for fiscal year 2024. In the current period there was spend on exploration and evaluation activities of $94.2 million in connection with the drilling, completion and stimulation of the 2025 drilling program, $15.6 million of spend related to SPCF, $0.3 million of spend related to sand mining, $2.8 million related to interest on financing lease liabilities, offset by proceeds from the sale of property, plant and equipment of $8.0 million due to the sale of rig 403 and the receipt of the R&D tax incentive of $6.2 million.
Current wording
For fiscal year 2026, net cash used in investing activities was $187.6 million compared to $98.8 million for fiscal year 2025. In the current period there was spend on exploration and evaluation activities of $112.0 million in connection with the drilling of the SS2-5H, SS2-3H and SS2-1H pilot wells, $37.3 million of spend related to SPCF, $0.4 million of spend related to sand mining, $3.4 million related to interest on financing lease liabilities, $5.0 million related to interest on borrowings under our Syndicated Facility Agreement, $12.1 million in connection with the Falcon Acquisition and $17.4 million related to the assignment of a note receivable, partially offset by the receipt of the R&D tax incentive of $0.1 million.
Previous wording
For fiscal year 2025, net cash received from financing activities was $101.1 million compared to $146.4 million received for fiscal year 2024. This decrease was primarily due to $42.9 million in net proceeds from the issue of shares in connection with the Company’s capital raises in fiscal year 2025 in comparison to net proceeds of $134.6 million received in 2024. The Company also received $5.3 million of net proceeds from the issuance of common stock for which shares had not yet been issued as of June 30, 2025 and also made advanced payments of $0.8 million related to transaction costs. Other activity in the fiscal year included $61.5 million attributable to contributions from noncontrolling interest holders in connection with investments by Daly Waters, $0.5 million of advance contributions received from noncontrolling interest holders, repayments of finance lease liabilities of $7.8 million, and $0.5 million related to the payment of the performance bond facility establishment fee.
Current wording
For fiscal year 2026, net cash received from financing activities was $412.3 million compared to $101.1 million received for fiscal year 2025. This increase was primarily due to $291.0 million in net proceeds from the issue of shares in connection with the Company’s capital raises in fiscal year 2026 in comparison to net proceeds of $42.9 million received in fiscal year 2025. Other activity in the fiscal year 2026 included $74.5 million attributable to contributions from noncontrolling interest holders to fund their share of cash calls compared to $61.5 million in the prior period, $58.9 million of proceeds from the Syndicated Facility, payment of debt issuance costs of $3.6 million, repayments of finance lease liabilities of $8.2 million and $0.3 million related to the payment of performance bond facility establishment fees.
Previous wording
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.
Current wording
Some of the Group’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 Group 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.
Previous wording
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 remediate, remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites.
Current wording
In the ordinary course of business, we are and 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 remediate, remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites.
Previous wording
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.
Current wording
Deferred income tax relating to timing differences 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.
Previous wording
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.
Current wording
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), Binomial Lattice or the Monte-Carlo option-pricing model (for awards that vest based on market conditions). Each of these models includes 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.