TBN 10-K & 10-Q changes, risk factors and insider trading

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

We are an early stage development company with no material revenues or reserves currently. To date we have drilled andeight completed only fourhorizontal wells as operator.operator, six of which have been completed, with two wells (SS1-4H and SS1-6H) drilled and awaiting completion and a ninth well (SS1-2H) currently being drilled. We have observed lower normalized flow rates in one well compared to other wells that we have participated in drilling in the Beetaloo. We currently only have onefive wellwells thattied weinto believethe based on initial flow rates is a productive well, meaning it is capable of producing sufficient quantities of gas to justify completion.SPCF. Companies in the early stages of operations face substantial business risks and may suffer significant losses. We face challenges and uncertainties in financial planning as a result of the unavailability of historical data and uncertainties regarding the nature, scope and results of our future activities. In the event that our drilling program is delayed, our operating results will be adversely affected, and our operations will differ materially from the activities described in this report.

•our success in attracting third party strategic and financial partners and investors to significantly fund our midstreamupstream and LNG terminalmidstream development goals;

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

The anticipated production from our business plan will exceed the capacity of the existing pipeline infrastructure that services the Beetaloo. We cannot assure you that we will reach a mutually satisfactory agreement with APA Group for the construction of the required take-away capacity or the satisfaction toof the conditions of any such obligation. The delivery of the BEC Pipeline Project will be the subject of a future development agreement and the gas transport services will be the subject of a future gas transportation agreement. The failure to contract for the construction of additional take-away capacity will adversely affect the ability to execute our proposed business plan. In addition, even if we are able to contract for sufficient take-away capacity, we may not be able to contract for gathering and compression services, storage facility capacity, and interconnections to the major pipelines.

We presently have no proved reserves and have not sold any natural gas produced. We did not have any revenue during the reporting period with first gas sales commencing in September 2026. Based on petrophysical analysis, we have identified locations and drilled appraisal wells that indicate prospective resources. However, our appraisal wells may not be indicative of future results. Additionally, the areas we have drilled, or may decide to drill in the future, may not yield natural gas in commercial quantities or quality, or at all. All of our current property is undeveloped and in various stages of evaluation that will require substantial additional seismic data reprocessing and interpretation. Accordingly, we do not know if our properties will contain natural gas in sufficient quantities or quality to recover drilling and completion costs or to be economically viable. Even if natural gas is found on our property in commercial quantities, construction costs of natural gas pipelines, associated infrastructure, and transportation costs may prevent such property from being economically viable.

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

Exploring for and developing natural gas reserves involves a high degree of operational and financial risk, which precludes definitive statements as to the time required and costs involved in reaching certain objectives. The budgeted costs of drilling, completing and operating wells are often exceeded and can increase significantly when drilling costs rise due to a tightening in the supply of various types of natural gas field equipment and related services. Drilling may be unsuccessful for many reasons, including geological conditions, weather, cost overruns, equipment shortages and mechanical difficulties. Exploratory and appraisal wells bear a much greater risk of loss than development wells. Moreover, the successful drilling of a natural gas well does not necessarily result in a profit on investment. For example, during the drilling operations in the Shenandoah South Pilot Project, a downhole mechanical issue in SS-2HSS2-2H led to it being plugged and sidetracked, SS-2H-ST1,SS2-2H-ST1, despite achieving a record horizontal section in the MidMiddle Velkerri B Shale. Additionally, the completion operations for the SS2-4HSS2-5H well were paused due to detected stress in the casing connection, necessitating reinforcement activities before furtherstimulation stimulationand completion activities canwere proceedundertaken in 2026. A variety of factors, both geological and market-related, can cause a well to become uneconomic or only marginally economic. Our initial drilling sites, and any potential additional sites that may be developed, require significant additional exploration and development, regulatory approval and commitments of resources prior to commercial development. If our actual drilling and development costs are significantly more than our estimated costs, we may not be able to continue our business operations as proposed and we would be forced to modify our plan of operation.

•reductions ofor sustained declines in natural gas prices; and

Our expected future growth could create a strain on the organizational, administrative and operational infrastructure. Our ability to manage our growth effectively will require us to continue to improve our operational, financial and management controls, as well as reporting systems and procedures. Our current team is small, and we will have to hire additional employees to achieve our expected future growth. Our business strategy will be difficult to execute, which may impact our ability to effectively attract employees. As we grow, any failure of our controls or interruption of our facilities or systems could have a negative impact on our business and financial operations. Our future development plan, including the potential development of pipelines, and an LNG export facility, will affect a broad range of business processes and functional areas. The time and resources required to implement these new extensions of our business are uncertain, and failure to complete these activities in a timely and efficient manner could adversely affect our operations. If we are unable to manage growth effectively, it may be difficult for us to execute our business strategy.

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

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

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

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

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

•loss of, or delay inin, revenue;

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

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

In Note 1 titled “NatureBusiness and Basis of the Organization and BusinessPreparation” of our audited consolidated financial statements for fiscal years 20242025 and 20252026 included elsewhere in this report, we disclose that there is substantial doubt about our ability to continue as a going concern. In addition, our independent registered public accounting firm included an explanatory paragraph in its report on our consolidated financial statements for fiscal years 20242025 and 2025,2026, which stated that there are factors that raise substantial doubt on our ability to continue as a going concern. We have incurred significant operating losses and negative cash flows from operations and expect to continue incurring increasing losses for the foreseeable future as we further our development program. Further, we had accumulated a deficit of $130.4 million as of June 30, 2024 and $167.3 million as of June 30, 2025.2025 and $193.4 million as of June 30, 2026. These conditions raise substantial doubt about our ability to continue as a going concern. Our consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

Our ability to become a profitable operating company is dependent upon our ability to generate revenue and obtain financing adequate to fulfill our development and commercialization activities and achieving a level of revenue adequate to support our cost structure. We have plans to obtain additional resources to fund our currently planned operations and expenditures through additional debt and equity financing, however, there is no guarantee we will obtain financing at all or on commercially acceptable terms. We may not continue as a going concern if we do not raise additional capital. We believe that the proceeds raised from the privatecapital placementsraise in April 2026 and the undrawn portion of ourthe commonSPCF stockdebt in May and July 2025facility provide us with the capitalfunds necessary to continue as a going concern through calendar year 2025, andover the amountnext of12 proceeds, together with our existing cash on hand and future expected inflows, will be sufficient to fund our planned drilling and testing program at least through the end of fiscal year 2026.months. Our plans are substantially dependent upon the success of commercial production in the Beetaloo, which is still in the early stages of development, and are dependent upon, among other things, the success of our drilling program and infrastructure development in the Beetaloo. If we are unable to obtain sufficient funding, our financial condition and results of operations will be materially and adversely affected, and we may be unable to continue as a going concern. Future financial statements may disclose substantial doubt about our ability to continue as a going concern. If we seek additional financing to fund our business activities in the future and there remains substantial doubt about our ability to continue as a going concern, investors or other financing sources may be unwilling to provide additional funding to us on commercially reasonable terms or at all.

We anticipate commencing construction of the NTLNG project as early as fiscal year 2028 with completion occurring as early as 2033. Our ability to commence construction of the NTLNG project on schedule is dependent on a number of factors outside of our control, including the willingness of potential third-party partners to commit to the project. Although we have entered into memoranda of understanding with subsidiaries of each of bp and Shell with respect to long-term contracts for the purchase of a total of 4.4 MTPA from the NTLNG project, these memoranda of understanding are not binding obligations of bp or Shell and either may decide not to pursue our project. We cannot assure you we will be successful in the negotiating or execution of definitive agreements. Failure to do so could cause significant delays to the phases of our business plan and have a material adverse effect on our results of operations and financial condition.

Concerns over global economic conditions, stock market volatility, energy costs, geopolitical issues, supply chain issues, changing regulatory environment and tariffs and trade policies, inflation and elevated interest rates, the availability and cost of credit, and slowing of economic growth in the United States and fears of a recession have contributed and may continue to contribute to economic uncertainty and diminished expectations for the global economy.

As a result of inflation, we experienced supply chain constraints and inflationary pressure on our cost structure throughout fiscal yearsyear 2024 and 2025.2026. Principally, commodity costs for steel and chemicals required for drilling, higher transportation and fuel costs and annual wage increases have increased our operating costs for fiscal year 20252026 compared to fiscal year 2024.2025. We cannot predict the future inflation rate but to the extent inflation remains elevated and supply chain constraints remain, we may experience cost increases in our operations, including costs for drill rigs, workover rigs, hydraulic fracturing fleets, tubulars and other well equipment, as well as increased labor costs. Some supply chain constraints and inflationary pressures could persist into fiscal year 20262027 but are expected to plateau,plateau; howeverhowever, we cannot accurately predict future supply chain constraints and inflation. If we are unable to manage our supply chain, our ability to procure materials and equipment in a timely and cost-effective manner, if at all, may be negatively impacted, which could materially adversely impact our results of operations and financial condition.

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

Our business, results of operations and financial condition may be adversely affected by uncertainty and changes in the U.S. regulatory environment and trade policies, including tariffs, trade agreements or other trade restrictions imposed by the U.S. or other governments. Tariffs or other trade restrictions may lead to continuing uncertainty and volatility in U.S. and global financial and economic conditions and commodity markets, declining consumer confidence, inflation and diminished expectations for the economy, which could impact the demand for and price of oil and natural gas, increase the price of supplies and raw materials that we rely on to conduct our business, and could impact interest rates. Changing regulatory environment and trade and tariffs policies could ultimately impact our results of operations and financial condition.

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

Growing geopolitical instability and armed conflicts (including the armed conflict between Russia and UkraineUkraine, Iran and the United States and between Israel and Hamas as well as other hostilities in the Middle East) hashave resulted in energy infrastructure becoming a more prominent target of attack by terrorists and conflicting countries. Natural gas, NGLs and oil related facilities, including those operated by us or our service providers, could be direct targets of physical or cyber-attacks, and, if infrastructure integral to our operations is destroyed or damaged, we may experience a significant disruption in our operations. Any such disruption could materially adversely affect our financial condition, results of operations and cash flows. Costs for insurance and other security may increase as a result of increased threats, and certain insurance coverage may become more difficult to obtain, if available at all.

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

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

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

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

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

We are also subject to evolving expectations on ESG matters from various stakeholders, including regulators, investors, customers, and business partners. Further, in response to the evolving regulatory environment and investor expectations, or due to our acquisitions of other companies or assets, we may, periodically, make adjustments to our environmental targets or goals. See “Increased attentionAttention to sustainability and ESG matters and environmental conservation measures may adversely impact our business.”

•drilling development and developmentdecommissioning bonds;

•remediation or investigation activities for environmental purposes; and

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

Our business is affected by government policy, which in turn may be influenced by international policies and laws. There is no guarantee that the current policy of the Australian Federal Government’sGovernment for the investment and development of Australia’s natural gas resources will not change in the future. In particular, there is a risk that the Australian Federal Government could shift its domestic or international policy. International policy developments have the potential to have an indirect impact on our operations, given that domestic policy makers might consider those developments in formulating and in setting the direction of local policy. For example, in May 2021, the International Energy Agency recently released a report in relation to its recommendations for a pathway to achieve global net zero emissions by 2050, which includes a key recommendation that no new oil and natural gas projects should be developed. It is unknown what impact the report might have, if any, on domestic policy development for natural gas. A shift in energy policy announced and adopted by the NT Government in relation to natural gas or the development of the Beetaloo would pose a similar risk. The NT Government had previously imposed a moratorium on the operations in the Beetaloo, which ended in 2018 following a scientific inquiry and the implementation of certain recommendations.

Our operations are also subject to the Petroleum Act 1984 (NT), which, among other maters,matters, allows for the unitization of a petroleum pool that extends beyond a license area, but which is desirable for efficiency and avoiding wasteful and harmful development and practices.

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

We are required to comply with the Native Title Act 1993 (Cth), and we operate on areas in which native title has been judicially determined to exist. Consultation and negotiations have occurred, leading to the development of exploration agreements with native title holders. Further agreements will be required for any production phase, but the exploration agreements anticipate production and provide the parameters for those negotiations and outcomes. We will also be required to comply with the ALRA for tenement applications over Aboriginal land (i.e., freehold land held by an Aboriginal Land Trust under the ALRA, or land subject to a deed of grant held in escrow by an Aboriginal Land Council under the ALRA). Compliance with either legislative regime and their respective requirements for negotiation and agreement can significantly delay the grant of exploration and production tenements, and substantial compensation may be payable as part of any agreement reached. Applications for exploration tenements over Aboriginal land can also be placed into moratorium for five years at a time under the ALRA (unless the Governor-General of Australia declares by proclamation that the Australian national interest requires that the license be granted). These legislative regimes may impact our existing or future activities, ability to develop projects and operational and financial performance. Additionally, we cannot guarantee that all stakeholders will agree that our negotiations have been conducted consistent with the principle recognized in the UNUnited Nations Declaration ofon the Rights of Indigenous Peoples (UNDRIP) and People of Free, Prior and Informed Consent,Consent (FPIC), which may result in operational, reputational, or other adverse impacts to our business.

Upon commencemententering ofthe commercialSafeguard production,Mechanism, when facility operated Scope 1 emissions exceed 100,000 t-CO2-e per annum, we are required by the Australian government to produce natural gas in the Beetaloo on a Scope 1 net zero basis. We also have set an internal net zero goal with respect to natural gas production. Meeting these requirements and goals may increase our costs of production, and we may be unable to meet these requirements and goals.

Australian lawlaw, which includes the National Greenhouse and Energy Reporting Act 2007 (Cth) and the National Greenhouse and Energy Reporting (Safeguard Mechanism) Rule 2015 (Cth) requires that, upon commencementa of commercial production andfacility reaching the relevant threshold of 100,000 t-CO2-e Scope 1 emissions per fiscal year, we produce natural gas in the Beetaloo on a Scope 1 net zero basis. We also have set an internal net zero goal with respect to natural gas production. To achieve this,these goals, we intend tomay utilize renewables and batteries to supply our upstream operational power needs and to integrate carbon capture and sequestration with our upstream production activities as well as purchase carbon creditsoffsets as required, however there is no guarantee we will achieve such plans. If we are unable to utilize renewables and batteries to supply our upstream operation power needs and integrate carbon capture and sequestration with our upstream production activities to the extent we currently expect, if the price of carbon creditsoffsets increases or if we have otherwise underestimated the amount of Scope 1 or Scope 2 emissions,emissions that we will need offsetto offset, our costs of production will increase further which could have a material adverse effect on the results of operations. The Australian government has announced a review of the Safeguard Mechanism, which is due to commence in the second half of calendar year 2026 and conclude during calendar year 2027. The review will consider key settings including the baseline decline rate beyond 2030 and the threshold for covered facilities.

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

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

IncreasingEvolving investorexpectations from regulators, investors, lenders, customers, employees and societalother attentionstakeholders toconcerning climate changechange, sustainability and ESG, rising expectations for companies to address climate change and develop voluntary ESG initiatives,matters, and growing consumer demand for alternative forms of energy may result in increased costs (including but not limited to increased costs related to compliance, stakeholder engagement, contracting and insurance), reduced demand for our products, reduced profits, increased investigations and litigation and negative impacts on our access to capital markets. Increasing attention to climate change, environmental justice and environmental conservation, for example, may result in demand shifts for natural gas products and additional governmental investigations and private litigation against us. To the extent that societal, political, or other factors are involved, including factors associated with geopolitical considerations, it is possible that we could be subject to changing market conditions, liability, or loss of certain assets without regard to our ultimate role in the causation of or contribution to the asserted events or damages, or to other mitigating factors.

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

Our voluntary initiatives (such as voluntary disclosures, certifications, or goals, among others) to improve the sustainability and ESG profile of our company and/or products or to respond to stakeholder expectations may be costly and may not have the desired effect. For example, we may ultimately be unable to complete certain initiatives or targets, either on the timelines initially announced or at all, due to technological or legal cost, or other constraints, which may be within or outside of our control. For example, we may undertake initiatives or disclosures based on estimates, assumptions, methodologies, or third-party information that is subsequently determined to be inaccurate, unreasonable, or to not align with best practices. Our approaches to such matters may evolve as well, but we cannot guarantee that it will necessarily align with the expectations of any particular stakeholder.

If we fail to, or are perceived to fail to, comply with or advance certain sustainability and ESG initiatives (including the timeline and manner in which we complete such initiatives), we may be subject to various adverse impacts, including reputational damage and potential stakeholder engagement and/or litigation, even if such initiatives are currently voluntary. For example, there have been increasing allegations of greenwashing against companies making significant ESG claims due to a variety of perceived deficiencies in disclosure, methodology, or performance, including as stakeholder perceptions of sustainability continue to evolve.

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

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

The transition and physical risks associated with climate change (including also regulatory responses to such issues and associated costs) may significantly affect our operating and financial performance. For example, the Australian government announced its policy to target net zero carbonGHG emissions economy-wide by 2050. In connection with that announcement, the Australian government designated that shale natural gas facilities in the Beetaloo that exceed the relevant threshold of 100,000 gross tonnes of CO2-e emissions per fiscal year will be given a “Zero” GHG baseline. Accordingly, once a shale natural gas producerfacility has exceeded the 100,000 gross t-CO2-e Scope 1 threshold, the Company must demonstrate that it has achieved Scope 1 net zero emissions, either through operational measures (such as carbon capture and storage) or by purchasing carbon offsets. Various policymakers have also adopted, or are considering adopting, rules to require companies to provide significantly expanded climate-related disclosures. For more information, see our risk factor titled “Increased attentionAttention to sustainability and ESG matters and environmental conservation measures may adversely impact our business.” In addition, theclimate change may give rise to physical risks to our operations, including an increased frequency or severity of natural disasters and weather eventsevents, duesuch toas climatebushfires, changecyclones, flooding, and extreme heat, as well as chronic shifts in temperature and precipitation patterns and water availability in the Northern Territory, any of which could delay or prevent our ability to conduct our activities, which could negatively impact our financial performance.

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

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%61.25% working interest in EPs 76, 98 and 117, where we are the operator, and (iii) a 100% working interest in EPs 136, 143136 and EP(A) 197,143, 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.

Global, industry-wide supply chain disruptions have resulted in widespread shortages of labor, materials and services. Such shortages have resulted in our facing significant cost increases for labor, materials and services. Principally, commodity costs for steel and chemicals required for drilling, higher transportation and fuel costs and annual wage increases have increased our operating costs for fiscal years 20242025 and 2025.2026. Typically, as the price for natural gas increases, so do associated costs. Conversely, in a period of declining prices, associated cost declines are likely to lag and may not adjust downward in proportion to prices. Some supply chain constraints and inflationary pressures could persist into fiscal year 20262027 but are expected to plateau,plateau; howeverhowever, we cannot accurately predict future supply chain constraints and inflation. We cannot predict the future inflation rate but to the extent inflation remains elevated, we may experience cost increases in our operations, including costs for drill rigs, workover rigs, hydraulic fracturing fleets, tubulars and other well equipment, as well as increased labor costs. If we are unable to recover higher costs through higher commodity prices, our future revenue stream would be significantly impacted.

We are taking actions to mitigate supply chain and inflationary pressures. We are monitoring the situation and assessing its impact on our business, including with respect to our partners. For example, we pre-purchased long lead materials including casing and tubulars, chemicals and downhole equipment necessary for our planned development for fiscal year 2026.2027. We have in place a 10-year optionoption, 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.

WeThrough haveJune 30, 2026, we had not generated any revenue from natural gas production since inception due to the current stage of our operations, which iswas explorationappraisal drilling and the final stages of ourmidstream assets to test their commercial viability. If and when we do commence natural gas production, we expect to generate revenue from such production.construction. No revenue from natural gas production is reflected in our financial statements.statements as first sales occurred after the period end.

WeDuring havethe notfiscal yetyear commencedended June 30, 2026, natural gas production.production had not commenced. The initial gas sales in September 2026 should be construed as initial test sales. If and when we do commence production,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 20242026 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,stock in fiscal year 2025, and general and administrative expenses.

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-UkraineRussia-Ukraine war, the Iran-United States war and the broader Middle East conflict, the changing U.S. regulatory environment and trade and tariffs policies, andthe relatedAustralian erosiondomestic ofgas demandmarket forreservation natural gas,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. Since we have not generated revenues, theseThese key factors will only affect us when we produce and sell natural gas.

Revenue and other operating income. WeThe havecommissioning notphase yetof the Pilot Project commenced naturalin gasSeptember production.2026 (subsequent to fiscal year 2026). Therefore, we did not realize any revenue and other operating income during fiscal years 20252026 and 2024,2025, respectively.

Compensation and benefits, including stock basedstock-based compensation. Compensation and benefits, including stock based compensation, increased by $4.0$3.1 million during fiscal year 2025,2026, as compared to fiscal year 20242025 largely due primarilyto period on period increase in headcount, the transition to restricteda stockcalendar unitsyear grantedemployee inbonus August 2024schedule, and increasedcompensation headcount as comparedawarded to the priorinterim period.and new CEO.

Loss on saleremeasurement 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 2025,2025 primarily due to the write down of rig 403 to the fair value less costs to sell. InTamboran contrast,disposed aof loss onall assets classified as held for sale amounting to $0.03 million was recognized duringin fiscal year 2024, primarily due to the sale of a smaller rig, rig 301.2025.

Accretion of asset retirement obligations expense. For fiscal year 20252026, an expense for accretion of asset retirement obligations of $1.0$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. As the Company drilled two additional wells and established the SPCF site, there was an incremental expense for accretion during the period.pad.

LNG feasibility study expense. ForIn fiscal year 2025, the CompanyGroup incurred expenses of $6.0 million related to certain studies and pre-front-end engineering and design services related to the proposed NT LNGNTLNG facility. These studies were substantially completed in fiscal year 2025, therefore, the expense related to these studies was de minimis in fiscal year 2026.

Checkerboard fee. For fiscal year 2025, the CompanyGroup 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.

Interest Income, net. Interest income, net increased by $0.9$1.1 million during fiscal year 2025,2026, as compared to fiscal year 2024,2025, primarily due to interest received from cash at bank and term deposits during the period.

Foreign currency translation. In fiscal year 20252026, 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. 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.

Income Tax Expense. We have no income tax expense primarily due to operating losses incurred for fiscal years 20252026 and 2024.2025. 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 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.

We are aan developmentexploration 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 2026,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, net proceeds of the private placements received in July 2025,hand and funds from future private and public equity placements, debt funding and asset sales.

•complete our current appraisal drilling, testing program and SPCF facility constructioncommissioning;

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

For the fiscal year endedending June 30, 2026,2027, we estimate that we will need to invest approximately $57$113.3 million to progress our upstreamPilot Project development plans. We expect thecash trancheon twohand proceedsand available funds from the privatecommitted placementundrawn receivedportion inof Julythe 2025,SPCF togetherdebt with our existing cash on hand,facility to be sufficient to fund drillingthe stimulation and tie-in costs of SS-4H,the SS-5HSS2-3H, SS2-4H and SS-6HSS2-5H wells (completed in July and completeAugust flow2026 testingahead of SS-2Hproduction ST1.start-up), However,drilling weand maystimulation requirecosts significantof additionalSS1-6H, fundsSS1-4H earlierand thanSS1-2H wefor currentlyproduction expecttie-in induring order2027, tolong executeleads ourfor strategyfurther asproduction planned.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.

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

As of June 30, 2025,2026, we had $39.4$219.1 million in cash and cash equivalents. This balance represents aan decreaseincrease of $35.3$179.7 million from June 30, 2024,2025, primarilyas duea to incoming funds from the greenshoe option exercised in July 2024, the saleresult of rig 403 in October 2024, R&D tax credits received in December 2024, cash calls received throughout the period, proceeds from ourcash subscriptioncalls, agreementscapital toraising institutionalactivities investorsand inthe MaySyndicated 2025,Facility Agreement offset primarilyby byconsideration paid for the Falcon Acquisition and spending onrelated to operations on the SS-2H,SS2-5H, SS-2H side track,SS2-3H and SS-3HSS2-1H pilot wells, construction of the SPCF facility long lead items and civil works, NT LNG pre-front-end engineering and design services, and other corporate expenditureexpenditures in the fiscal period.

As of June 30, 2025,2026, Sweetpea committed to spend $23.1$24.0 million related to two licenses, EP 136 with total commitments of $14.0$14.5 million and EP 143 with total commitments of $9.1$9.6 million over the following five years.million.

A renewal application for EP 136 was submitted to the Department of Mining and Energy (“DME”) in SeptemberNovember 2023,2025, andrequesting approvedan extension of the permit for a period of 18 months to January 2031. DME replied in July 2024,2026 grantingand agreed to a five-yearpermit extension foronly through July 2030. As such, the periodGroup July 24, 2025 to July 23, 2030 withmaintains a minimum work program commitment of $14.0$14.5 million.

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 20262027 is $2.3expected to be $6.0 million based on the minimum work requirements. There are no minimum commitment requirements after March 2026.2027.

AnA variation application was submitted to DME in September 20242025 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 obligationsprogram throughfor Mayyears 2028.3, 4 and 5. Refer to Note 17 for further details. These commitments include an expected spend of $75.6$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 $10.7$14.1 million, EP 98 of $53.3$43.7 million and EP 117 of $11.6$15.5 million as well as subsurface studies.million.

For fiscal year 2025,2026, net cash used in operating activities was $29.6$34.6 million during which we incurred a net loss of $39.6$30.5 million, compared to net cash used in operating activities for fiscal year 20242025 of $11.4$29.6 million, during which we incurred a net loss of $23.9$39.6 million. The net loss for fiscal year 20252026 included the non-cash impacts of depreciation and amortization, stock-based compensation, lossperformance onbond remeasurementfacility of assets classified as held for sale,fees, accretion of asset retirement obligations, interest expense, Checkerboard feeexpense and foreign exchange differences. Additionally, in the year ended June 30, 2025,2026, net unfavorable changes in operating assets and liabilities totaled $4.8$12.5 million, primarily consisting of aan $3.3$8.3 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$7.8 million increase in prepaid expenses and other assets.assets, partially offset by a $2.9 million decrease in trade and other receivables.

For fiscal year 2025,2026, net cash used in investing activities was $98.8$187.6 million compared to $66.1$98.8 million for fiscal year 2024.2025. In the current period there was spend on exploration and evaluation activities of $94.2$112.0 million in connection with the drilling, completion and stimulationdrilling of the 2025SS2-5H, drillingSS2-3H program,and $15.6SS2-1H pilot wells, $37.3 million of spend related to SPCF, $0.3$0.4 million of spend related to sand mining, $2.8$3.4 million related to interest on financing lease liabilities, offset$5.0 bymillion proceedsrelated fromto interest on borrowings under our Syndicated Facility Agreement, $12.1 million in connection with the saleFalcon of property, plantAcquisition and equipment of $8.0$17.4 million duerelated to the saleassignment of riga 403note andreceivable, partially offset by the receipt of the R&D tax incentive of $6.2$0.1 million.

For fiscal year 2025,2026, net cash received from financing activities was $101.1$412.3 million compared to $146.4$101.1 million received for fiscal year 2024.2025. This decreaseincrease was primarily due to $42.9$291.0 million in net proceeds from the issue of shares in connection with the Company’s capital raises in fiscal year 20252026 in comparison to net proceeds of $134.6$42.9 million received in 2024.fiscal Theyear 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.2025. Other activity in the fiscal year 2026 included $61.5$74.5 million attributable to contributions from noncontrolling interest holders to fund their share of cash calls compared to $61.5 million in connectionthe withprior investmentsperiod, by Daly Waters, $0.5$58.9 million of advance contributions receivedproceeds from noncontrollingthe interestSyndicated holders,Facility, payment of debt issuance costs of $3.6 million, repayments of finance lease liabilities of $7.8$8.2 million,million and $0.5$0.3 million related to the payment of the performance bond facility establishment fee.fees.

Some of the Company’sGroup’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 CompanyGroup 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.

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.

Deferred income tax relating to timing differencedifferences 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.

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 includeincludes 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.

Except as provided below, there have been no material changes in risk factors for the quarterly period ended DecemberMarch 31, 20252026 from those described in the Company’s Annual Report on Form 10-K for the fiscal year ended June 30, 2025.

Tamboran anticipates issuing 6,537,503 shares of Tamboran common stock to Falcon in exchange for Falcon’s equity interests in the Falcon Entities. FollowingBased on 28,318,909 shares of common stock issued and outstanding as of May 1, 2026, following the completion of the Falcon Acquisition, it is anticipated that persons who were stockholders and shareholders of Tamboran and Falcon, respectively, immediately prior to the Falcon Acquisition will own approximately 77.6%81.2% and 22.4%18.8% of the combined company, respectively, with Tamboran maintaining control over the combined company. As a result, Tamboran’s current stockholders and Falcon’s current shareholders will have less influence on the policies of the combined company than they currently have on Tamboran’s policies and Falcon’s policies, respectively.

The price of Tamboran common stock at the completion of the Falcon Acquisition will vary from its price on the date the Arrangement Agreement was executed, the date of this proxy statement, the date of the special meeting and the effective date. As a result, the market value represented by the number of shares issued to Falcon will also vary. For example, based on the range of closing prices of Tamboran common stock during the period from September 29, 2025, the trading day before the date of the public announcement of the Falcon Acquisition, through JanuaryApril 26,30, 2026, the latest practicable date before the date of this proxy statement, the total Falcon Parent stock consideration represented a market value ranging from a low of $147,747,567.80 to a high of $199,001,591.32.$326,787,279.47.

Tamboran’s and Falcon’s respective obligations to consummate the Falcon Acquisition are subject to the satisfaction (or waiver by all parties, to the extent permissible under applicable laws) of a number of conditions described in the Arrangement Agreement,Agreement. including the approval by Tamboran stockholders of the issuance of the Falcon Parent stock consideration to Falcon, the approval and adoption of the arrangement resolution by the Falcon shareholders, the approval of the arrangement by the Court on terms consistent with the Arrangement Agreement and otherwise reasonably satisfactory to the parties and receipt of certain regulatory clearances and approvals. ManySome of the conditions to completion of the arrangement are not within Tamboran’s control and Tamboran cannot predict when, or if, these conditions will be satisfied. If any of these conditions are not satisfied or waived prior to the termination date, it is possible that the Arrangement Agreement may be terminated. The Arrangement Agreement provides that, upon termination of the Arrangement Agreement under certain circumstances, Tamboran or Falcon would be required to pay the other party a termination fee of $3.75 million and $1.62 million, respectively. In addition, Falcon would be required to reimburse Tamboran for its documented out-of-pocket expenses incurred in connection with the arrangement under certain circumstances.

Although the parties have agreed to use reasonable best efforts, subject to certain limitations, to complete the arrangement promptly, these and other conditions may fail to be satisfied. In addition, completion of the arrangement may take longer and could cost more than we expect. The requirements for obtaining the regulatory approvals, including approval of the TSX Venture Exchange (the “TSXV”), could delay the completion of the Falcon Acquisition for a significant period of time or prevent them from occurring. Any delay in completing the Falcon Acquisition may adversely affect the benefits that Tamboran expects to achieve if the Falcon Acquisition and the integration of businesses were to be completed within the expected timeframe.

If the Falcon Acquisition is not completed for any reason, including as a result of failure to obtain all requisite Regulatory Approvals, approval of the TSXV or if the Tamboran stockholders or Falcon shareholders fail to approve the stock issuance proposal, the ASX capacity proposal and the Falcon Acquisition resolution, respectively, the ongoing businesses of Tamboran may be materially adversely affected and, without realizing any of the benefits of having completed the Falcon Acquisition, Tamboran would be subject to a number of risks, including the following:

Falcon shareholders have the right to exercise dissent rights and demand payment equal to the fair value of their Falcon common shares.shares and certain Falcon shareholders have exercised such rights. If dissent rights are properly exercised in respect of a significant number of Falcon common shares, a substantial payment may be required to be made to such Falcon shareholders, which could have an adverse effect on the combined company’s financial condition and cash flows.

Results of Operations for the Three Months Ended DecemberMarch 31, 20252026 and 20242025

Revenue and other operating income. We have not yet commenced natural gas production; therefore, we did not earn any revenue and other operating income during the three months ended DecemberMarch 31, 20252026 and 2024,2025, respectively.

Compensation and benefits, including stock-based compensation. Compensation and benefits, including stock-based compensation, increased by $1.6$1.2 million during the three months ended DecemberMarch 31, 2025,2026, as compared to the three months ended DecemberMarch 31, 2024,2025, largely due to theincreased transitionheadcount in relation to athe calendarcomparative year employee bonus schedule andquarter, compensation awarded to the interimnew CEO.CEO during the quarter, and the payout of bonuses during the quarter for the 2025 calendar year at a higher payout percentage than that accrued in the same quarter of fiscal year 2025.

Accretion of asset retirement obligations expense. For the three months ended DecemberMarch 31, 2025,2026, an expense for accretion of asset retirement obligations of $0.3 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. The incremental expense period over period is driven by the three wells drilled in Q1 which had a full quarter of accretion in the current period.

Exploration expense. For the three months ended DecemberMarch 31, 2025,2026, the exploration expense decreased by $1.0$0.5 million as compared to the three months ended DecemberMarch 31, 20242025 as the currentprior period washad heavilyincreased focusedactivity on the drilling of SS-4H, SS-5H, and SS-6H, resulting in a larger portion of costs capitalized and less costs incurred related tofor topographical, geographical and geophysical studies.studies and other indirect expenditures while the current period focused on the flow test for SS-6H and preparation of the stimulation programs of SS-3H, SS-4H, and SS-5H, the costs of which are capitalized.

Camp expense recoveries, net. For the three months ended DecemberMarch 31, 2025,2026, expenses for the newly established field camp of $1.0$0.6 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.

LNG feasibility study expense. During the three months ended DecemberMarch 31, 2025, the Group incurred2026, expenses of $0.1 million related to certain studies and pre-front-end engineering and design services related to the proposed NT LNG facility.facility Thesewere de minimis as these studies were substantially completed in the prior period.periods.

General and administrative. General and administrative costs increased by $0.3 million during the three months ended DecemberMarch 31, 2025,2026, as compared to the three months ended DecemberMarch 31, 2024,2025 primarilywere asfairly aconsistent result of increased expenses related to headcount.period-over-period.

Interest income (expense), net. Interest income, net decreasedincreased by $0.5$0.6 million during the three months ended DecemberMarch 31, 2025,2026, as compared to the three months ended DecemberMarch 31, 2024,2025, primarily due to theinterest increasereceived on deposits in interestconnection expensewith onour increasedPIPE drawdownsproceeds forthat bankoccurred guarantees underduring the Facilityperiod Agreementended withMarch Macquarie31, Bank2026 Limitedwhich entereddid intonot exist in Decemberthe 2024.comparative period.

Foreign currency translation. For the three months ended March 31, 2026, we recognized a foreign currency translation gain of $15.5 million, primarily due to the significant strengthening of the Australian Dollar as of March 31, 2026, as compared to December 31, 2025. In the three months ended March 31, 2025, we recognized a foreign currency translation gain of $6.8$1.5 million, primarily due to the slight strengthening of the Australian Dollar as of DecemberMarch 31, 2025, as compared to September 30, 2025. In the three months ended December 31, 2024, we recognized a foreign currency translation loss of $29.2 million, primarily due to the significant weakening of the Australian Dollar as of December 31, 2024, as compared to September 30, 2024. 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 condensed consolidated statement of operations and comprehensive loss.

Income tax expense. We have no income tax expense due to operating losses incurred for the three months ended DecemberMarch 31, 2025,2026, and 2024.2025. 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 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 condensed consolidated statement of operations and comprehensive loss.

Results of Operations for the SixNine Months Ended DecemberMarch 31, 20252026 and 20242025

Revenue and other operating income. We have not yet commenced natural gas production; therefore, we did not earn any revenue and other operating income during the sixnine months ended DecemberMarch 31, 20252026 and 2024,2025, respectively.

Compensation and benefits, including stock-based compensation. Compensation and benefits, including stock-based compensation, increased by $1.4$2.6 million during the sixnine months ended DecemberMarch 31, 2025,2026, as compared to the sixnine months ended DecemberMarch 31, 2024,2025, largely due to increased headcount in relation to the comparative period, the transition to a calendar year employee bonus scheduleschedule, and compensation awarded to the interim and new CEO.

Accretion of asset retirement obligations expense. For the sixnine months ended DecemberMarch 31, 2025,2026, an expense for accretion of asset retirement obligations of $0.6$0.9 million was recognized. The recognition of such an expense was due to the accretion of asset retirement obligation liabilities in relation to all EPs, inclusive of EPs 76, 98, 117, 136 and 161, as well as the SPCF pad. The incremental expense period over period is driven by the three wells drilled in Q1 which had a full quarter of accretion in the current period.

Exploration expense. For the sixnine months ended DecemberMarch 31, 2025,2026, the exploration expense decreased by $1.4$1.9 million as compared to the sixnine months ended DecemberMarch 31, 20242025 as the current period was heavily focused on the drilling of SS-4H, SS-5H, and SS-6H, resulting in a larger portion of costs capitalized and less costs incurred related to topographical, geographical and geophysical studies.

Camp expense recoveries, net. For the sixnine months ended DecemberMarch 31, 2025,2026, expenses for the newly established field camp of $2.7$3.3 million were recognized primarily related to mobilization expenses of the modular buildings and related equipment to the site, camp utilization, camp services, and related consumables. These costs are offset by recoveries from external parties who utilize the camp.

LNG feasibility study expense. During the sixnine months ended DecemberMarch 31, 2025,2026, the Group incurred expenses of $0.3$0.4 million related to certain studies and pre-front-end engineering and design services related to the proposed NT LNG facility. These studies were substantially completed in the prior period.

Checkerboard fee. During the six months ended December 31, 2024, 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.JVSA. This obligation was satisfied through the issuance of common stock, subsequent to shareholder approval received in November 2024 and is a nonrecurring event.

General and administrative. General and administrative costs increased by $0.5 million during the sixnine months ended DecemberMarch 31, 2025,2026, as compared to the sixnine months ended DecemberMarch 31, 2024,2025, primarily as a result of increased expenses related to headcount.

Interest income (expense), net. Interest income, net decreased by $1.6$1.0 million during the sixnine months ended DecemberMarch 31, 2025,2026, as compared to the sixnine months ended DecemberMarch 31, 2024,2025, primarily due to the increase in interest expense on increased drawdowns for bank guarantees under the Facility Agreement with Macquarie Bank Limited entered into in December 2024.

Foreign currency translation. For the sixnine months ended DecemberMarch 31, 2026, we recognized a foreign currency translation gain of $24.0 million, primarily due to the significant strengthening of the Australian Dollar as of March 31, 2026, as compared to June 30, 2025. In the nine months ended March 31, 2025, we recognized a foreign currency translation gain of $8.5 million, primarily due to the slight strengthening of the Australian Dollar as of December 31, 2025, as compared to June 30, 2025. In the six months ended December 31, 2024, we recognized a foreign currency translation loss of $17.0$15.5 million, primarily due to the significant weakening of the Australian Dollar as of DecemberMarch 31, 2024,2025, as compared to June 30, 2024. 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 condensed consolidated statement of operations and comprehensive loss.

Income tax expense. We have no income tax expense due to operating losses incurred for the sixnine months ended DecemberMarch 31, 2025,2026, and 2024.2025. 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 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 condensed consolidated statement of operations and comprehensive loss.

We are aan developmentexploration and appraisal stage company 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 the second half of calendar year 2026, at the earliest, which will depend upon successful drilling results, additional and timely capital funding, negotiation of certain commercial agreements 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/ or asset sales.

For the remainder of the fiscal year ending June 30, 2026, we estimate that we will need to invest approximately $45.5$30.2 million to progress our development plans. We expect the proceeds from the public offering during the current fiscal period and PIPEequity announcedraised in OctoberApril 2025 (PIPE proceeds received in January 2026),2026, together with our existing cash on hand, to be sufficient to fund remaining drilling and stimulation costs of SS-4H, SS-5H and SS-6H and tocommitted carrySPCF outconstruction flow testing of SS-5H.costs. However, we may require significant additional funds earlierafter thanJune we30, currently expect2026, in order to execute our strategy as planned. 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.

As of DecemberMarch 31, 2025,2026, we had $83.4$88.2 million of cash and cash equivalents. This balance represents an increase of $44.0$48.7 million from June 30, 2025. Cash calls received, proceeds from our subscription agreements to institutional investors and Share Purchase Plan, proceeds from the Syndicated Facility during the period were primarily offset by spending from operations on the SS-4H, SS-5H and SS-6H pilot wells, construction of the SPCF facility and other corporate expenditure in the fiscal period.

Sweetpea’s committed spend as of DecemberMarch 31, 2025,2026, was $23.3$23.9 million, which was related to two licenses, EP 136 with total commitments of $14.0$14.4 million and EP 143 with total commitments of $9.3$9.5 million.

A variation 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.months to January 2031. This application remains under review. As such, the Group maintains a minimum work program commitment of $14.0$14.4 million.

An application for EP 143 was submitted to and approved by DME in DecemberMarch 20252026 requesting toa suspendvariation of the minimum work program conditions for ayears period3, 4 and 5 and extension of sixthe monthsterm to JuneDecember 30,31, 2026.2029. The total minimum work program commitments remainremained the same at $9.3$9.5 million.

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 for twelve months to March 2027 which includes the drilling and stimulation of two horizontal wellswells, along with related geological and geophysical studies.studies, for a period of 12 months to March 2027. Our commitment through March 2027 is expected to be $5.8$6.0 million based on the minimum work requirements. There are no minimum commitment requirements after March 2027.

AnA variation application was submitted to DME in September 20242025 to vary the year 2 and 3minimum work program for years 3, 4 and was5. approvedThis inprogram Novemberremains 2024.under review. The terms of the Beetaloo Joint Venture continue to necessitate specific minimum work obligations through May 2028. These commitments include an expected spend of $76.6$65.3 million related to drilling and multi-stage hydraulic fracturing of four wells, 3D seismic survey, and subsurface studies, with expenditure across EP 76 of $10.7$11.0 million, EP 98 of $54.2$42.3 million and EP 117 of $11.7$12.0 million.

Committed spend remaining for the SPCF project as of DecemberMarch 31, 2025,2026, was $12.1$8.5 million which was related to the remaining procurement, and construction management for the detailed design, engineering, planning, construction, testing, inspection and commissioning of the facility.

As of DecemberMarch 31, 2025,2026, there was A$32.2 million of letters of credits issued under the Facility Agreement. As of DecemberMarch 31, 20252026 there was A$1.7 million of unused credit under Facility A and A$1.1 million of unused credit under Facility B and Facility C.

For the sixnine months ended DecemberMarch 31, 2025,2026, net cash used in operating activities was $14.5$27.0 million during which we incurred a net loss of $16.6$27.2 million compared to net cash used in operating activities for the sixnine months ended DecemberMarch 31, 20242025 of $8.9$23.2 million, during which we incurred a net loss of $22.3$30.4 million. The net loss for the sixnine months ended DecemberMarch 31, 2025,2026, 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 six months ended December 31, 2025, net unfavorable changes in operating assets and liabilities totaled $1.5 million, primarily consisting of a $2.2 million decrease in accounts payable and accrued expenses due to timing of our pay cycle during the fiscal period, a less than $0.1 million decrease in trade and other receivables and a $0.1 million increase in prepaid expenses and other assets.

For the sixnine months ended DecemberMarch 31, 2025,2026, net cash used in investing activities was $66.5$112.8 million compared to $35.8$73.7 million for the sixnine months ended DecemberMarch 31, 2024.2025. In the period ended DecemberMarch 31, 2025,2026, there was spend on exploration and evaluation activities of $47.2$79.7 million in connection with the drilling of the SS-4H, SS-5H and SS-6H pilot wells, expenditure of $14.2$24.4 million of spend related to SPCF, $1.8$3.0 million incurred in connection with the proposed Falcon Acquisition, $2.0$2.6 million related to interest on financing lease liabilities and $1.2$2.9 million related to interest on borrowings under our SPCF Syndicated Facility Agreement.

For the sixnine months ended DecemberMarch 31, 2025,2026, net cash received from financing activities was $133.5$194.0 million compared to $31.4$48.3 million received for the sixnine months ended DecemberMarch 31, 2024.2025. The increase was primarily due to proceeds from the issuance of common stock of $78.4$110.4 million that occurred in the current fiscal period compared to $7.4 million in gross proceeds from the greenshoe option exercised in July 2024, $32.5$44.0 million of proceeds from the Syndicated Facility, $36.4$55.4 million attributable to contributions from noncontrolling interest holders to fund their share of cash calls,calls compared to $48.5 million in the prior period, partially offset by common stock issuance transaction costs of $4.5$5.2 million, payment of debt issuance costs of $2.9$3.3 million, repayments of finance lease liabilities of $6.1$6.9 million and $0.3 million related to the payment of performance bond facility establishment fees.

For additional information on our critical accounting estimates, refer to Management's Discussion and Analysis of Critical Accounting Estimates included in Part II, Item 7 of the Group's Annual Report on Form 10-K for the year ended June 30, 2025, as filed with SEC on September 25, 2025. There have been no material changes in critical accounting estimates at DecemberMarch 31, 20252026 from those described in the Group’s Annual Report on Form 10-K for the year ended June 30, 2025.