EX-99.2
Published on November 12, 2026
Tamboran Resources Corporation ARBN 672 879 024 Tower One, International Towers Suite 1, Level 39, 100 Barangaroo Avenue, Barangaroo NSW 2000, Australia +61 2 8330 6626 www.tamboran.com First quarter activities report for period ended September 30, 2026 Highlights • During the quarter, Tamboran and Daly Waters Energy (DWE) became the first parties to sell gas from the Beetaloo Basin. Tamboran delivered total net gas sales of 0.31 Bcf and earned revenue of US$1.8 million. First cash inflows were received in early November 2026. • Delivered average flow rate of 10.2 MMcf/d over an interrupted 720-hour period over ~5,500 feet from the SS2-2H ST1 well, a material uplift in productivity following testing in 2025. After being shut in for a year, the well produced minimal water flow back and demonstrates a typical well deliverability post-clean-up. • Delivered average IP30 rates of 8.8 and 10.0 MMcf/d from the SS2-3H and -5H wells respectively, confirming performance in-line with prior testing. Both wells were tied in without soaking and are sustaining relatively high bottomhole pressures, suggesting increased deliverability as the wells continue to clean up, in-line with other US shale basins. • Three-well drilling program on the SS1 pad was completed using the Helmerich & Payne (NYSE: HP) super- spec FlexRig® Flex 3 Rig, with ~29,000 feet of combined usable lateral. Stimulation activities using the Liberty Energy (NYSE: LBRT) frac fleet are planned for 4Q 2026. • Santos (ASX: STO) commenced a two-well appraisal program in EP 161, in which Tamboran holds a 25% non-operated interest. The Jibera South 1H DW1 (JS-DW1) pilot hole reached TD and logged all Velkerri Shale formations in-line with expectations. • Cash balance and near-term inflows totaling US$180 million as of September 30, including Tamboran’s 50% share of restricted cash. Net drawn debt of US$37 million, associated with the construction of the SPCF, with undrawn debt of US$26 million (net Tamboran) remaining. Key metrics 1Q FY26 4Q FY26 1Q FY27 Change (%) Production Bcf - - 0.31 100% Sales Revenue(1) US$m - - 1.8 100% EBITDAX(2) US$m (6.1) (5.7) (14.5) 154% Cash Balance(3) US$m 40 225 165 (27%) (1) Sales Revenue and direct costs for the Pilot Project were capitalized to the balance sheet during the quarter as the Project has not reached Practical Completion of the SPCF nor Commercial Operations Date under the GSA. Not yet reflected in the EBITDAX. (2) EBITDAX is a non-US GAAP metric which means Earnings Before Interest Tax Depreciation Amortization and Exploration Expense and is a proxy for operating cash flows. (3) Cash balance includes Tamboran’s net portion of restricted cash of US$4.8 million. ANNOUNCEMENT November 12, 2026 Tamboran Resources Corporation (NYSE: TBN; ASX: TBN)
2 Tamboran Resources Corporation Managing Director and Chief Executive Officer, Mr. Todd Abbott, said: “This quarter Tamboran and Daly Waters Energy made history by becoming the first companies to sell gas from the Beetaloo Basin. Gas from the Beetaloo is now a major contributor to the domestic Northern Territory market. “During our first period of gas sales, we delivered 0.31 Bcf and generated US$1.8 million in revenue. These numbers are expected to increase as we complete the commissioning phase and enter the take-or-pay contract with the Northern Territory Government in early 2027. “Long duration flow testing of wells on the SS2 pad commenced in September. Initial rates confirm the successful deliverability demonstrated in prior testing of wells in the basin. These results support our view that declines remain relatively low and rates should rise as the wells continue to clean up. “Importantly, the SS2-2H ST1 well shows what we believe these wells can deliver once cleaned up. The well was reopened with minimal water flow back and delivered an average rate of 10.2 million cubic feet per day over 720 hours of interrupted production. This is a material step up in productivity from the initial 90-day flow period in 2025 and in-line on a normalized basis with the SS-1H result from 2024. “The SS2-3H and SS2-5H wells have delivered average IP30 rates of 8.8 and 10.0 MMcf/d respectively over 10,000 feet. Both wells were tied in without soaking and are sustaining relatively high bottomhole pressures, which suggests there is more deliverability to come as the wells continue to clean up. “The 2027 calendar year is about building the resource across our 2.8 million net prospective acre Beetaloo Basin position. This includes step-out drilling and flow testing within the Beetaloo Central Development Area (BCDA) and EP 161 acreage positions. We expect to undertake additional wells in our Orion acreage once we finalize our strategic partnership.” Capital Expenditure Incurred capital expenditure of US$56.9 million relating primarily to drilling and stimulation activity on the SS2 pad, drilling activity on the SS1 pad, drilling in the EP 161 permit and construction of the Sturt Plateau Compression Facility (SPCF) (inclusive of financing costs). Key metrics 1Q FY26 4Q FY26 1Q FY27 Change (%) Exploration & Evaluation US$m 17.1 34.2 48.6 42% Assets Under Construction US$m 5.1 7.2 8.1 13% Land & Buildings US$m - - 0.2 100% Total Capital Expenditure US$m 22.2 41.4 56.9 37% Note: Capital expenditure is Tamboran’s net share of costs, with net revenue and costs of the Pilot Project offset against the Exploration & Evaluation asset. Reported GAAP financials include the share of Daly Waters Energy, LP and Daly Waters Infrastructure, LP.
3 Liquidity Key metrics 1Q FY26 4Q FY26 1Q FY27 Change (%) Cash Balance US$m 40 225 165 (27%) Drawn Debt US$m - (30) (37) 23% Net Cash / (Debt) US$m 40 195 128 (34%) Note: Cash balance differs from the GAAP financials due to removal of Daly Waters Infrastructure, LP net share of restricted cash. Capital Structure No new shares have been issued since the release of the 4Q FY26 report. Minor transfer of CHESS Depositary Interests (CDIs) to Common Stock. Key metrics 1Q FY26 4Q FY26 1Q FY27 Change (%) Common Stock 12,922,097 28,280,039 28,337,692 0.2% CHESS Depositary Interests (CDI) 1,514,354,400 1,335,993,400 1,324,462,800 (0.9%) Total Common Stock (Equivalent) 20,493,869 34,960,006 34,960,006 - Restricted Stock Units - 848,724 848,724 - Options 179,250(1) 369,084 369,084 - Fully Diluted Stock (Common Stock) 20,673,119 36,177,814 36,177,814 - Note: CHESS Depositary Interests 200:1. (1) 179,250 Common Stock equivalent options (35,850,000 unlisted CDI options) expired on May 26, 2026, as disclosed in the Company's Appendix 3H lodged with ASX on June 15, 2026. Webcast details Tamboran’s Managing Director and Chief Executive Officer, Mr. Todd Abbott will host a webcast commencing at 5:00pm EST on Thursday November 12, 2026 (9:00am AEDT on Friday November 13, 2026). Access to the live audio webcast for the conference call is available via Tamboran’s website at https://ir.tamboran.com/.
4 Operations Overview Shenandoah South Pilot Project Tamboran 44.375 per cent working interest in 20,239 acres and operator of the Northern Pilot Area(1) In July 2026, Tamboran and DWE (together the Beetaloo Joint Venture (BJV)) completed stimulation, cleanout and completion activities on the SS2-3H, -4H and -5H wells on the SS2 pad. The program was the first three-well zipper stimulation and the largest campaign conducted in the Beetaloo Basin to date, with 178 stages placed across ~30,000 lateral feet within the Mid Velkerri B Shale using the Liberty Energy frac fleet. The campaign averaged 6.7 stages per day and set Beetaloo Basin records, with pumping operations exceeding 20 hours per day and 12 stages completed in a single day. The BJV also placed locally produced Beetaloo Red Sand (BRS) in 10 stages along the lateral of the SS2-5H well, the first deployment of BRS in the basin. Tracers were deployed to compare the performance of these stages against stages using imported sand. Long-duration flow testing of wells on the SS2 pad commenced in September 2026. Initial rates confirm the positive deliverability demonstrated in prior testing of wells in the basin. The SS2-2H ST1 well delivered an average rate of 10.2 MMcf/d over 720 hours of interrupted production across ~5,500 feet of lateral, materially better than the initial 90-day flow period. The well normalized to 18.4 MMcf/d over a 10,000-foot horizontal, in-line with the original SS-1H well, which was flow tested in 2024. The SS2-2H ST1 well demonstrates deliverability potential of a cleaned-up well. The SS2-3H and SS2-5H wells delivered average IP30 rates of 8.8 and 10.0 MMcf/d, respectively, and both continue to produce 300 to 500 barrels of water per day, as the wells were tied into the SPCF immediately following the stimulation campaign earlier this year. Both wells are sustaining relatively high calculated bottomhole pressures, which suggests further deliverability to come as the wells clean up. Observations from subsurface work indicate that well delivery materially increases as water used in the stimulation program is recovered or imbibes into the formation over time. Based on these initial results, Netherland, Sewell & Associates, or NSAI, has estimated a P50 EUR of 17 Bcf per 10,000-foot lateral. The SS2-5H well included 10 stages stimulated with BRS. Early performance shows no degradation in deliverability from using local sand, providing confidence in its deployment in future wells. The BJV plans to further test BRS on at least one well during the SS1 pad stimulation program. Tamboran 44.375 per cent working interest in 20,230 acres of the Southern Pilot Area(1) During the quarter, Tamboran and DWE commenced the three-well drilling program on the SS1 pad using the Helmerich & Payne (H&P) super-spec FlexRig® Flex 3 Rig. (1)Working interests include impact of farmout to Daly Waters Energy, LP, announced in March 2026.
5 The SS1-6H and SS1-4H wells were successfully drilled and cemented to total depth (TD) over 32 and 24 days, including 9,434 and 9,635-foot usable horizontal section within the Mid Velkerri B Shale, respectively. The SS1-2H well encountered a downhole issue after drilling a lateral section of 12,631 feet, which required a side- track. The side-track well was drilled in early November 2026, with a usable lateral section of 9,989 feet. The program remains within the contingency capital expenditure budget. The BJV plans to stimulate the three wells on the SS1 pad using the Liberty frac fleet during the December 2026 quarter and over the wet season. The wells are expected to be tied back to the SPCF during 1Q 2027. Sturt Plateau Compression Facility (Tamboran 50%, Daly Waters Infrastructure (DWI) 50%) Construction of the SPCF, a 50/50 joint venture with Daly Waters Infrastructure (DWI), was completed in August 2026. The SPCF was constructed on time and is forecasted to come in ~US$10 million below budget when it reaches Practical Completion. The facility commenced processing gas and delivered first gas sales into the Northern Territory gas market in early September 2026. The facility is currently undergoing commissioning activities, including tuning control systems and refining equipment settings. Tamboran and DWE receive a discounted price (75% of the contract gas price) until the take-or-pay gas sales contract commences, reflecting the interruptible nature of supply during the current period. EP 161 Santos 75 per cent working interest and operator, Tamboran 25 per cent working interest During the September quarter, Santos, the operator of the EP 161 permit, commenced the two-well drilling program to delineate further resources across the Beetaloo East depocenter. The JS-DW1 well spudded in early September using the Ensign 971 rig, reaching a TD of ~11,300 feet on the pilot vertical hole. The well successfully intersected all Velkerri Shale formations in October, with results in-line with Tamboran’s expectations. Drilling of the 10,000-foot horizontal section within the Velkerri B Shale has since commenced. On completion of the JS- DW1 well, the rig is planned to mobilize to the Newcastle South DW1 (NS- DW1) location ~11 miles to the southeast for the drilling of a second 10,000-foot horizontal well. Both wells are planned to be stimulated across up to 60 stages per well and flow tested during 2027.
6 Commercial and Corporate Update MOU with Liberty Energy to extend Beetaloo partnership In September 2026, Tamboran signed a non-binding Memorandum of Understanding (MOU) with Liberty Energy (NYSE: LBRT) to extend its hydraulic fracture stimulation and wireline services agreement in the Beetaloo Basin. The proposed extension covers an initial three-year term from 2026 to 2029, with a mutual option to extend by a further two years to 2031. The parties are now documenting the terms, and any extension is subject to final agreements being signed. Liberty plans to start introducing lower-emissions pumping equipment to the Beetaloo fleet from 2027. The companies also plan to jointly assess a next-generation, lower-emissions completions fleet over the term of the extension. The MOU also provides Tamboran with priority access to other Liberty services as they are introduced to Australia. These include gas processing and conditioning and remote gas-fired power generation through Liberty Power Innovations, PropX sand slurry delivery and collaboration on the development of local proppant supply. Falcon Australia minority interests On November 10, 2026, Tamboran paid A$4.1 million into the Falcon Oil & Gas Australia Limited (Falcon Australia) account and became the sole shareholder of Falcon Australia. These funds, which represent the payment due to former Falcon Australia shareholders, are held on trust for those shareholders. Falcon Australia’s registrar, Boardroom, has written to each former shareholder requesting bank account details and payment instructions. Former shareholders will be paid A$1.77994 per share, in proportion to their previous holdings. Tamboran will keep records of all payments and work with ASIC on any unclaimed funds, as required under the Corporations Act 2001 (Cth). Managing Director appointment On October 19, 2026, Mr. Todd Abbott was appointed Managing Director of Tamboran, in addition to his role as Chief Executive Officer. The appointment follows his appointment as Chief Executive Officer in January 2026 and formalizes his executive leadership at Board level as the Company moves from appraisal into development. Notice of Annual General Meeting Tamboran will host its 2026 Annual Meeting of Stockholders on Thursday November 19, 2026 at 4:00pm Central Standard Time (Friday November 20, 2026 at 9:00am AEDT). The meeting will be held online and be completely virtual via http://www.virtualshareholdermeeting.com/TBN2026
7 Permits At the end of the quarter, Tamboran and its subsidiaries held the following prospective acreage positions. Permits Gross Prospective Acres Interest Net Prospective Acres Northern Pilot Area 20,239 44.38%* 8,982 Southern Pilot Area 20,230 44.38% 8,978 Orion Block 493,229 78.00%* 384,719 Beetaloo Central Development Area (BCDA) 316,131 10.00% 31,613 Andromeda Block 218,176 92.00%* 200,722 Pegasus Block 536,669 100.00%* 536,669 Draco Block 914,839 100.00%* 914,839 DW OTD Area 813,460 22.50% 183,029 DW Plains Area 281,633 12.50% 35,204 DW Arnold Area 525,740 22.50% 118,292 DW Carpentaria Area 202,931 22.50% 45,659 EP 161 512,000 25.00% 128,000 Maverick Block (EP 136) 207,000 100.00%* 207,000 Total 5,062,277 2,803,705 *Denotes operator interest following the completion of the Checkerboard. Note: Working interests also include impact of (i) the Acreage Sale to Daly Waters Energy, LP, announced in May 2025 and subject to completion of certain conditions precedent, (ii) Acreage Realignment Agreement with Daly Waters Energy, LP, announced in November 2025, and (iii) the farmout to Daly Waters Energy, LP, announced in March 2026.
8 This announcement was approved and authorized for release by Todd Abbott, the Managing Director and Chief Executive Officer of Tamboran Resources Corporation. For further information, please contact: Investor enquiries: Chris Morbey, Vice President – Corporate Development and Investor Relations +61 2 8330 6626 Investors@tamboran.com Media enquiries: +61 2 8330 6626 Media@tamboran.com About Tamboran Resources Corporation Tamboran Resources Corporation (NYSE/ASX: TBN) is a growth-driven independent natural gas exploration and production company. Tamboran is focused on an integrated approach to the commercial development of the natural gas resources in the Beetaloo Basin located within the Northern Territory of Australia. Through its subsidiaries, Tamboran holds approximately 2.8 million net prospective acres and is the largest acreage holder in the Beetaloo Basin depocenter.
9 Figure 1: Tamboran’s Beetaloo Basin asset location map Note: Working interests include impact of the Acreage Sale to Daly Waters Energy, LP, announced in May 2025 and subject to completion of certain conditions precedent.
10 Table 1: Disclosures under ASX Listing Rule 5.30 (SS2-3H) a) The name and type of well. SS2-3H well. b) The location of the well and details of the permit or lease in which the well is located. EP 98 of Beetaloo Sub-basin, Northern Territory (future Northern Pilot Area acreage). c) The entity’s working interest in the well. Tamboran holds a 50% interest in the well (prior to farm-down to DWE) d) If the gross pay thickness is reported for an interval of conventional resources, the net pay thickness. Not applicable. This is not a conventional reservoir. e) The geological rock type of the formation drilled. Organic-rich shale. f) The depth of the zones tested. Average depth of horizontal 3,028 metres Total Vertical Depth (TVD) (9,935 feet TVD), with 3,127 metres (10,260 ft) of stimulated lateral length. g) The types of test(s) undertaken and the duration of the test(s). 30-day initial production (IP30) gas flow test. h) The hydrocarbon phases recovered in the test(s). Dry gas - mole %. Methane – 91.4, Ethane – 2.6, Propane – 0.13, Butane & higher <0.04. i) Any other recovery, such as, formation water and water, associated with the test(s) and their respective proportions. Fracture stimulation fluid is being recovered during testing. The well was producing ~222 barrels of water per day at the end of the 30-day period with a cumulative 41,300 bbls of water recovered.
11 j) The choke size used, the flow rates and, if measured, the volumes of hydrocarbon phases measured. Choke 12/64” to 52/64”; avg IP30 8.8 MMcf/d; cum. 264 MMcf; FWHP 4,176 to ~1,260 psi. k) If applicable, the number of fracture stimulation stages and the size and nature of fracture stimulation applied. 59 fracture stimulation stages and a toe stage covering over 3,127 metres (10,260 ft). Average proppant concentrations of 2,236 lbs/ft. l) Any material volumes of non-hydrocarbon gases, such as carbon dioxide, nitrogen, hydrogen sulphide or sulphur. Reported as Mol %: CO2, – 3.9, N2 – 1.9. m) Any other information that is material to understanding the reported results. The well is a production well currently meeting gas sales to the Northern Territory Government.
12 Table 2: Disclosures under ASX Listing Rule 5.30 (SS2-5H) a) The name and type of well. SS2-5H well. b) The location of the well and details of the permit or lease in which the well is located. EP 98 of Beetaloo Sub-basin, Northern Territory (future Northern Pilot Area acreage). c) The entity’s working interest in the well. Tamboran holds a 50% interest in the well (prior to farm-down to DWE) d) If the gross pay thickness is reported for an interval of conventional resources, the net pay thickness. Not applicable. This is not a conventional reservoir. e) The geological rock type of the formation drilled. Organic-rich shale. f) The depth of the zones tested. Average depth of horizontal 3,030 metres Total Vertical Depth (TVD) (9,942 feet TVD), with 3,123 metres (10,246 ft) of stimulated lateral length. g) The types of test(s) undertaken and the duration of the test(s). 30-day initial production (IP30) gas flow test. h) The hydrocarbon phases recovered in the test(s). Dry gas - mole %. Methane – 91.0, Ethane – 2.6, Propane – 0.15, Butane & higher <0.04. i) Any other recovery, such as, formation water and water, associated with the test(s) and their respective proportions. Fracture stimulation fluid is being recovered during testing. The well was producing ~134 barrels of water per day at the end of the 30-day period with a cumulative 30,560 bbls of water recovered.
13 j) The choke size used, the flow rates and, if measured, the volumes of hydrocarbon phases measured. Choke 12/64” to 52/64”; avg IP30 10.0 MMcf/d; cum. 298 MMcf; FWHP 4,253 to ~760 psi. k) If applicable, the number of fracture stimulation stages and the size and nature of fracture stimulation applied. 59 fracture stimulation stages and a toe stage covering over 3,123 metres (10,246 ft). Average proppant concentrations of 2,271 lbs/ft. l) Any material volumes of non-hydrocarbon gases, such as carbon dioxide, nitrogen, hydrogen sulphide or sulphur. Reported as Mol %: CO2, – 3.8, N2 – 2.0. m) Any other information that is material to understanding the reported results. The well is a production well currently meeting gas sales to the Northern Territory Government.
14 Disclaimer Tamboran makes no representation, assurance or guarantee as to the accuracy or likelihood of fulfilment of any forward-looking statement or any outcomes expressed or implied in any forward-looking statement. The forward- looking statements in this report reflect expectations held at the date of this document. Except as required by applicable law or the ASX Listing Rules, Tamboran disclaims any obligation or undertaking to publicly update any forward-looking statements, or discussion of future financial prospects, whether as a result of new information or of future events. The information contained in this announcement does not take into account the investment objectives, financial situation or particular needs of any recipient and is not financial product advice. Before making an investment decision, recipients of this announcement should consider their own needs and situation and, if necessary, seek independent professional advice. To the maximum extent permitted by law, Tamboran and its officers, employees, agents and advisers give no warranty, representation or guarantee as to the accuracy, completeness or reliability of the information contained in this announcement. Further, none of Tamboran nor its officers, employees, agents or advisers accept, to the extent permitted by law, responsibility for any loss, claim, damages, costs or expenses arising out of, or in connection with, the information contained in this announcement. Note on Forward-Looking Statements This press release contains “forward-looking” statements related to the Company within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”) and Section 27A of the Securities Act of 1933, as amended. Forward-looking statements reflect the Company’s current expectations and projections about future events at the time, and thus involve uncertainty and risk. The words “believe,” “expect,” “anticipate,” “will,” “could,” “would,” “should,” “may,” “plan,” “estimate,” “intend,” “predict,” “potential,” “continue,” “participate,” “progress,” “conduct” and the negatives of these words and other similar expressions generally identify forward-looking statements. It is possible that the Company’s future financial performance may differ from expectations due to a variety of factors, including but not limited to: our early stage of development and our limited operating history; the substantial additional capital required for our business plan, which we may be unable to raise on acceptable terms; our strategy to deliver natural gas to the Australian East Coast and select Asian markets being contingent upon constructing additional pipeline capacity, which may not be secured; the absence of proved reserves and the risk that our drilling may not yield natural gas in commercial quantities or quality; the speculative nature of drilling activities, which involve significant costs and may not result in discoveries or additions to our future production or reserves; the challenges associated with importing U.S. practices and technology to the Northern Territory, which could affect our operations and growth due to limited local experience; the critical need for timely access to appropriate equipment and infrastructure, which may impact our market access and business plan execution; the operational complexities and inherent risks of drilling, completions, workover, and hydraulic fracturing operations that could adversely affect our business; the volatility of natural gas prices and its potential adverse effect on our financial condition and operations; the risks of construction delays, cost overruns, and negative effects on our financial and operational performance associated with midstream projects; the potential fundamental impact on our business if our assessments of the Beetaloo are materially inaccurate; the concentration of all our assets and operations in the Beetaloo, making us susceptible to region-specific risks; the substantial doubt raised by our recurring operational losses, negative cash flows, and cumulative net losses about our ability to continue as a going concern; complex laws and regulations that could affect our operational costs and feasibility or lead to significant liabilities; community opposition that could result in costly delays and impede our ability to obtain necessary government approvals; exploration and development
15 activities in the Beetaloo that may lead to legal disputes, operational disruptions, and reputational damage due to native title and heritage issues; the requirement to produce natural gas on a Scope 1 net zero basis upon commencement of commercial production, with internal goals for operational net zero, which may increase our production costs; the increased attention to ESG matters and environmental conservation measures that could adversely impact our business operations; risks related to our corporate structure; risks related to our common stock and CDIs; and the other risk factors discussed in this report and the Company’s filings with the Securities and Exchange Commission. It is not possible to foresee or identify all such factors. Any forward-looking statements in this document are based on certain assumptions and analyses made by the Company in light of its experience and perception of historical trends, current conditions, expected future developments, and other factors it believes are appropriate in the circumstances. Forward-looking statements are not a guarantee of future performance and actual results or developments may differ materially from expectations. While the Company continually reviews trends and uncertainties affecting the Company’s results of operations and financial condition, the Company does not assume any obligation to update or supplement any particular forward-looking statements contained in this document.