Announcement PDF ASX Announcement For Immediate Release 10 June 2025 Company Presentation Material Australis Oil & Gas Ltd (“Australis” or “Company”) is pleased to provide shareholders with an update to the Company’s asset information presentation that is used as part of our ongoing efforts to secure a partner for our position in the Tuscaloosa Marine Shale. Australis continues to engage with potential partners and discuss various partnering models and structures. This ASX announcement was authorised for release by the Australis Disclosure Committee. For further information, please contact either: Ian Lusted Managing Director Australis Oil & Gas Limited +61 8 9220 8700 Graham Dowland Finance Director Australis Oil & Gas Limited +61 8 9220 8700 A UST RA LI S O I L & GA S LI MI T E D ABN 34 609 262 937 Level 2, 215 Hay Street Subiaco WA 6008 • PO Box 8225 Subiaco East WA 6008 T +61 (8) 9220 8700 • F +61 (8) 9220 8799 www.australisoil.com ASX: ATS Corporate Presentation 10 June 2025 Important Notice and Disclaimer This presentation has been prepared by Australis Oil & Gas Limited ACN 609 262 937 (ASX: ATS) (Australis). Summary of information: This presentation contains general and background information about Australis’ activities current as at the date of the presentation and should not be considered to be comprehensive or to comprise all the information that an investor should consider when making an investment decision. The information is provided in summary form, has not been independently verified, and should not be considered to be comprehensive or complete. The information in this presentation remains subject to change without notice. Australis is not responsible for providing updated information and assumes no responsibility to do so. Not financial product advice: This presentation is not financial product, investment advice or a recommendation to acquire Australis securities and has been prepared without taking into account the objectives, financial situation or needs of individuals. Before making an investment decision prospective investors should consider the appropriateness of the information having regard to their own objectives, financial situation and needs, and seek legal, taxation and financial advice appropriate to their jurisdiction and circumstances. Australis is not licensed to provide financial product advice in respect of its securities or any other financial products. Cooling off rights do not apply to the acquisition of Australis securities. Australis assumes that the recipient is capable of making its own independent assessment, without reliance on this document, of the information and any potential investment and will conduct its own investigation. Disclaimer: Australis and its related bodies corporate and each of their respective directors, agents, officers, employees and advisers expressly disclaim, to the maximum extent permitted by law, all liabilities (however caused, including negligence) in respect of, make no representations regarding, and take no responsibility for, any part of this presentation and make no representation or warranty as to the currency, accuracy, reliability or completeness of any information, statements, opinions, conclusions or representations contained in this presentation. In particular, this presentation does not constitute, and shall not be relied upon as, a promise, representation, warranty or guarantee as to the past, present or the future performance of Australis. Future performance: This presentation contains certain forward-looking statements and opinion. Generally, words such as “anticipates”, “expects”, “intends”, “plans”, “believes”, “seeks”, “estimates”, “potential” and similar expressions are intended to identify forward-looking statements. The forward-looking statements, opinion and estimates provided in this presentation are based on assumptions and contingencies which are subject to change without notice, as are statements about market and industry trends, which are based on interpretations of current market conditions. Forward-looking statements, including projections, forecasts and estimates, are provided as a general guide only and should not be relied on as an indication or guarantee of future performance and involve known and unknown risks, uncertainties and other factors, many of which are outside the control of Australis. Past performance is not necessarily a guide to future performance and no representation or warranty is made as to the likelihood of achievement or reasonableness of any forward-looking statements or other forecast. Not an offer: This presentation is for information purposes only. This presentation is not, and should not be considered as, an offer or an invitation to acquire securities in Australis or any other financial products and neither this document nor any of its contents will form the basis of any contract or commitment. This presentation is not a prospectus and does not contain all the information which would be required to be contained in a prospectus. Offers of securities in Australis will only be made in places in which, or to persons to whom it would be lawful to make such offers. Neither this presentation nor any of its contents may be reproduced or used for any other purpose without the prior written consent of Australis. No Distribution in the US: This presentation is not an offer of securities for sale in the United States. Securities of Australis are not registered under the US Securities Act of 1933, as amended (the "US Securities Act") and may not be offered or sold in the United States absent registration or an exemption from registration under the US Securities Act. No public offer of the securities is being made in the United States and the information contained herein does not constitute an offer of securities for sale in the United States. Monetary values: Unless otherwise stated, all dollar values are in United States Dollars (US$). The information in this presentation remains subject to change without notice. 2 Tuscaloosa Marine Shale - Background   Tuscaloosa Marine Shale is a cretaceous shallow marine play of a similar age to the Eagle Ford.  The unconventional shale was first explored in 2007 – 2011 and whilst there were some encouraging results it developed a reputation as being deep, hot, difficult to drill with variable productivity.   There has only been limited industry activity or interest in the play since 2015.   What was considered on the limit of drilling technology has become routine in the last 10 years.  Standalone “single” well economic model has an IRR at $65/bbl ~ 33% having been updated based on current costs and has significant upside.  The play benefits from existing infrastructure, proximity to markets, premium crude pricing and supportive regulatory environment. It is distributed over some 14 million acres in central Louisiana/Mississippi and is the known source rock for the conventional upper and lower Tuscaloosa Sand plays in the area. Production results within a delineated area (“TMS Core”) are consistent or better than established plays whose well designs have been refined over many thousands of wells. Australis holds ~50,000 acres (160 net future locations) within the TMS Core, this is scalable with Australis having held over 120,000 acres in the past and has a unique land data base to re-lease in a competitive environment. 3 US Unconventional Oil – Market Status  US domestic oil production has grown dramatically since 2010, largely due to unconventional shale’s contribution growing from <1 million bbls/day to ~9 million bbls/day over that period. The EIA estimates this accounted for 81% of total onshore production in the lower 48 States in 2024.  Over 80% of this oil comes from three plays, the Eagle Ford, Bakken and Permian, with the Permian alone accounting for 63% of that and, in fact, accounting for 51% of the lower 48 States production in 2024.  The Eagle Ford and Bakken are mature (i.e. majority of Tier 1 wells have been drilled and are on declining production), with limited remaining quality acreage and lower rock productivity in the remaining undrilled areas which is only partially offset by technology and longer laterals. Production from these areas has declined from their peaks and now plateaued at lower levels.  The Permian production is plateauing and has seen many of the same indicators as the other key plays and significant consolidation activity has moved remaining inventory into larger portfolios.  This has driven the acquisition valuation for new drilling locations to new highs, for instance Diamondback allocated $6.7 millionA per future location in the Midland basin on their purchase of Double EagleB. A Enverus Intelligence Research data quoted in Hart Energy article 18 February 2025 B Deal announced 18 February 2025 - $3 billion cash and ~$1 billion in Diamondback stock, 40,000 net acres, 27,000 bbl/d 4 US Unconventional Oil Production     Over 86% of US unconventional oil production still sourced from three plays. The Eagle Ford and Bakken, at ~1 MMbbls/d have never recovered to pre COVID volumes, are mature assets with limited Tier 1 drilling locations remaining. Practically all of the growth since 2020 has originated from the Permian but has now plateaued and significant consolidation has occurred ~$350 billion since 2023. Most large private companies in the Permian have been acquired and associated inventory is in the hands of public companies. 5 US Unconventional Oil Production The monthly production and rig count from each of the three key oil plays is shown below. The data is taken the EIA data base. The chart (right) shows the Permian production flattening in recent years (unchanged in last 7 months). Rig count reduced in each oil price driven cycle. The second chart (above) shows the Eagle Ford peaking in 2015 and effectively flat since COVID despite rig count increase. The lower chart (right) shows the Bakken production. Note the play has declined since Sept 2023 and rig count never recovered after 2015 oil price drop. 6 US Permian Unconventional Oil Production Has well performance in the Permian reduced over time?        Recent TGS Well Data AnalysisA considered the Permian well performance over the last 5 years. The Wolfcamp, Bone Spring and Sprayberry plays produce almost 99% of Permian production Production has increased by 61% in the Bone Springs, 13% in the Wolfcamp and 88% in the Sprayberry in 5 years. Well performance was evaluated on a cumulative boe/ft over 12 months and results from 2021-2022 compared to 2023 – 2024. The results are shown below for each horizon and groups by well lateral length (i.e. 1 – 3 miles) Not only has the boe/ft decreased (note this is despite an average increase in GOR of 133% during this period), but as can be seen there is a corresponding increase in the breakeven costs. Additional operational challenges in the Permian such as negative Waha gas pricing, water cuts and disposal limitations add to the cost base and make further costs savings increasingly difficult. Well performance in the established oil plays is decreasing and the limited remaining quality well inventory is heavily consolidated and prohibitively expensive. ATGS Report – 18 Feb 2025 – Incremental Increase in Breakeven Prices Signals Exhaustion of Tier 1 Acreage 7 Why TMS remains an undeveloped Tier 1 oil shale play Pre 2012 appraisal undertaken outside of TMS Core, followed by oil price decline and pandemic demand drop has been compounded by evolving business strategy of public companies  TMS is on trend with the Eagle Ford in Texas and in 2010 its exploration was the logical next step for the industry  91 horizontal wells drilled from 2010 to 2019 delineated the relatively small TMS Core (red outline) - ~ 5% of total TMS area (blue outline)  Performance from pre-2012 wells was variable and unusually binary – based on whether in or outside of the now identified TMS Core  Early entrants such as EOG and Devon built big positions outside TMS Core based on EF trend analogue, had inconsistent results and exited  Wells drilled from 2012 to 2014 delineated the TMS Core: those inside had consistently high oil productivity and downward trending well costs as operational challenges were resolved  Best results were from Encana’s 2014 drilling program, but these were not publicised while they built their lease position and traded with other operators  Oil price drop in 2014/2015 stopped all activity in play, stopping further development which added to the market’s poor perception of TMS  Australis built a TMS Core-focused position 2017 – 2018 and acquired historical data (including Encana technical and production data), but information on positive TMS Core results remained relatively unknown in US  Australis drilled wells in 2018 & 2019 further confirming productivity and economics relative to more established plays, demonstrating the underlying value of TMS Core. Reinforced by successful drilling operations by a Private Equity firm in 2022.  Industry focus on low risk established plays and shareholder return metrics has led to very limited focus on early-stage opportunities 8 US Unconventional Oil & the TMS – What next? Industry begins to expand focus outside of established plays Future quality drilling inventory is becoming increasingly scarce and expensive in the established plays and industry participants are shifting focus to earlier stage opportunities including plays that have been previously passed over by the industry:      EOG – re-entered the Utica shale, applying modern technology to the passed over oil window of what had been thought of as a gas play and have recently increased their acreage position. SM Energy – entered the Uinta shale at a cost of $2.1 billion for 80% of XCL Resources’ acreage. Had been considered by the industry as a fringe play with a ‘cap’ on export volumes due to infrastructure limitations. SM demonstrating that the play can compete with the established plays and are also focused on infrastructure bottlenecks. Powder River Basin has long been considered an evolving play, but increased focus from large participants such as Continental and Devon indicate that investment focus is switching from the established oil plays as alternatives are sought. EOG and others exploring the Pearsall shale in Texas – originally evaluated during the early phases of the Eagle Ford development but considered inferior. Now being evaluated with new wells and modern completion design. Sandridge recently announced acquisition and leasing in the Cherokee basin, a revisited area that has had little attention for many years. Australis believes that the TMS is a similar type of play that will attract industry focus and represents a timely investment opportunity “Those industry participants who are short on high quality inventory now must consider opportunities outside of the established areas. We are now seeing transactions where new or emerging plays are being added to public company portfolios, such as EOG Resources Inc.’s re-entry into the Utica basin, this time in the emerging oil window, and SM Energy’s new entry into the Uinta basin. The industry has also seen increased development activity in basins with mixed levels of historical success, such as the SCOOP/STACK in Oklahoma and the Powder River in addition to the Utica and Uinta, which are benefitting from modern subsurface analysis and drilling and completion techniques.” I.Lusted, CEO Australis Oil & Gas 9 TMS Core Substantially De-risked Future development of TMS Core has been substantially de-risked across the major project categories Land & Location Subsurface  TMS ideally located for existing infrastructure & markets  Supportive regulatory environment  Substantial high WI operated PUD inventory  Focused acreage  Delineated TMS Core  Custodian of available information and data  Subsurface model validated  Key drivers for performance Drilling & Completions Well Performance & Economics  Historical learning curve  Geomechanical model validated  Defined casing points, landing zone and operating window  Completion design TMS specific  Hybrid (2014 vintage) design works, but significant opportunity to optimise.  Well productivity and costs comparable to established plays  Solid well economics at early phase  Quality product with low burdens realising premium over other plays  Multiple layered upside 10 TMS Core – Land & Location TMS play benefits from low-cost land accumulation, existing infrastructure and operator-friendly regulation Location Infrastructure State and Field Rules  Straddles the Mississippi and Louisiana state line  Located only 60 miles from refining capacity at Baton Rouge  Significant historical oil and gas activity and close proximity to support & service centers in Louisiana, the Haynesville play and the greater Houston area  Low leasing costs  Multiple oil pipelines cross the TMS Core (green), including the Calpine  Plains-operated terminal at pipeline nexus (star on map)  Three gas pipelines cross the TMS Core (red)  Legacy gas gathering systems (Frio developments) on the western side of the TMS Core  Mississippi and Louisiana state laws and administrations are supportive of oil and gas operations  Large ~2,000 acre production units with force pooling  Regular charge permitting allows for non HBP acreage control  Low royalty rates  Low severance taxes 11 TMS Core Substantially De-risked Future development of TMS Core has been substantially de-risked across the major project categories Land & Location Subsurface  TMS ideally located for existing infrastructure & markets  Supportive regulatory environment  Substantial high WI operated PUD inventory  Focused acreage  Delineated TMS Core  Custodian of available information, knowledge and data  Subsurface model validated  Key drivers for performance Drilling & Completions Well Performance & Economics  Historical learning curve  Geomechanical model validated  Defined casing points, landing zone and operating window  Completion design TMS specific  Hybrid (2014 vintage) design works, but significant opportunity to optimise.  Well productivity and costs comparable to established plays  Solid well economics at early phase  Quality product with low burdens realising premium over other plays  Multiple layered upside 12 Subsurface – TMS Core Area Definition TMS Core area has been defined through production results and multiple subsurface methodologies Average: 11.7 bbl/ft Average: 23.5 bbl/ft Average: 30.1 bbl/ft TMS Core defined through production results  Best performing wells first delineated the TMS Core  Data from 90 TMS wells used: − 62 wells inside TMS Core (blue) − 28 outside TMS Core (orange)  15 wells drilled by Encana in 2014 (the "ATS 2014 TMS wells") averaged 216,000 bbls over first 24 months, or 30.1 bbls/ft TMS Core definition validated and refined through geological characterisation  Australis has generated multiple high-grade maps, using a variety of subsurface screening parameters  All result in a similar high-grade area as our public TMS Core  This is the simplest heatmap using three grids with equal weighting: − TOC: for hydrocarbon generation potential − Resistivity X-over: proxy for potential natural fractures − Isopach: for hydrocarbon potential 13 TMS Core Substantially De-risked Future development of TMS Core has been substantially de-risked across the major project categories Land & Location Subsurface  TMS ideally located for existing infrastructure & markets  Supportive regulatory environment  Substantial high WI operated PUD inventory  Focused acreage  Delineated TMS Core  Custodian of available information and data  Subsurface model validated  Key drivers for performance Drilling & Completions Well Performance & Economics  Historical learning curve  Geomechanical model validated  Defined casing points, landing zone and operating window  Completion design TMS specific  Hybrid frac (2014 vintage) design works, but significant opportunity to optimise.  Well productivity and costs comparable to established plays  Solid well economics at early phase  Quality product with low burdens realising premium over other plays  Multiple layered upside 14 Drilling & Completions - Australis TMS Well Construction Plan Drilling Operations – Simple design, designated landing zone and operating window Completion Operations – Same zone yields best results and Type Curve wells use 2014 Hybrid frac design Geomechanical model defines 17.5” Open Hole  Preferred drilling/completion zone 13-3/8” Surface set @ ~3,250’ 12.25” Open Hole  Drilling operating window – geosteering, hole cleaning, tripping speed and MPD requirements. landing and completion zone. It also defines operating window which influences engineering parameters. Surface and Production - Water Base Mud 9-5/8” Intermediate Casing Set @ ~11,900’ 8.5” Open Hole Oil Based Mud ~7,500’ Drilled Lateral 5-1/2” Production Casing Set @ ~20,000’ 15 TMS Core Substantially De-risked Future development of TMS Core has been substantially de-risked across the major project categories Land & Location Subsurface  TMS ideally located for existing infrastructure & markets  Supportive regulatory environment  Substantial high WI operated PUD inventory  Focused acreage  Delineated TMS Core  Custodian of available information and data  Subsurface model validated  Key drivers for performance Drilling & Completions Well Performance & Economics  Historical learning curve  Geomechanical model validated  Defined casing points, landing zone and operating window  Completion design TMS specific  Hybrid (2014 vintage) design works, but significant opportunity to optimise.  Well productivity and costs comparable to established plays  Solid well economics at early phase  Quality product with low burdens realising premium over other plays  Multiple layered upside 16 Well Performance & Economics – updated as at Q2 2025 Attractive base-case well economics established with significant upside Updated ATS Base Case Type Curve2  Based on the 16 wells drilled by ECA and ATS in the drilling target zone.  EUR 538 Mbbls of oil (75 bbls/ft)A.  Recovery in other basins have increased by 26% since 2014B as more wells are drilled and with application of modern completion techniques – creates an upside case for the TMS. TMS Premium  95% oil achieves premium pricing to WTI (LTM $3.25/bbl)  Low royalty (~20% avg) and production taxes  Proximity to market with abundant infrastructure leads to low transportation costs Economic Assumptions  Base well costC – US$10.4 million and LTM LOE averages  Development Case well costD – US$9.6 million and reduced LOE based on scale and efficiency with base case type curve. Upside opportunities include further Capex and Opex reductions and longer 10,000 ft laterals SINGLE WELL ECONOMICS AT $65/bbl WTI Base Wells PV10 - $4.27MM IRR – 33% Payout 23 months Development Wells PV10 - $5.92MM IRR – 48% Payout 17 months 47,500 acres 160 net locations 125 net HBP locations Well Inventory A Based on a 300 bbl/month cut off and a completed lateral length of 7,200 ft B Based on analysis of Permian, Eagle Ford, Williston and DJ basin between 2014 – 2024 on a boe/100ft 12 month cumulative basis. C Well cost includes drill & complete, pad, facilities, power, land/title and salt water disposal costs D Capex based on 40% increase in ROP and 20% decrease in flat time, LOE reductions based on lower fixed cost per well as well count increases 17 Strategic Position with Scale in TMS Core – as at Q1 2025 Australis controls the core area and is largest lease holder in the play TMS Asset Profile Mississippi and Louisiana, USA  Large contiguous land position in the TMS Core with ~47,500 net acres (none on federal lands) providing strategic control and operational benefits. − Limits new entrants acquiring large blocks in Core. − ATS has unique experience in leasing and accumulated an invaluable land database.  Ideal geography in Gulf of Mexico, with proximity to midstream infrastructure and refineries (~60 miles)  Development flexibility – large production units, favourable field rules and opportunity to take new 5 year leases  Significant inventory - 160 net well locations  Opportunity to grow acreage position - additional 100,000 acres has been identified; Australis positioned to act swiftly to implement a focused leasing campaign Net Acres ~47,500 (39,900 HBP) Producing Wells 30 operated 17 non-operated Net new well locations ~160 Reserves (1P)1 1,644 Mbbls Contingent Resources (2C) 1 62,560 Mbbls Acreage Expiry Profile 31 March 2025 18 TMS Core – A Unique Strategic Opportunity  Proven core with Tier 1 oil productivity delineated by over 90 wells  Contiguous and scalable acreage position in core with long lease life, providing materiality and control over future development  Attractive base-case well economics established, with significant upside identified  TMS benefits from existing infrastructure, low royalties, premium commodity pricing, operator-supportive field rules and regulator  Access to all basin wide historical data, records and work to retain lessons learned from early activity in TMS Core  Unique opportunity for targeted, low-risk accumulation of proven Tier 1 inventory at an entry cost similar to exploration plays with a clear path to significant asset value growth.  Increasingly relevant and valuable in an inventory constrained industry. 19 Footnotes 1. Estimates from the independent Ryder Scott report, effective 31 December 2024 and dated 29 January 2025 which was initially disclosed in the announcement titled "Quarterly Activities Report" issued on 31 January 2025. The report was prepared in accordance with the definitions and disclosure guidelines contained in the Society of Petroleum Engineers (SPE), World Petroleum Council (WPC), American Association of Petroleum Geologists (AAPG), and Society of Petroleum Evaluation Engineers (SPEE) Petroleum Resources Management (SPE-PRMS) as revised in June 2018. Ryder Scott generated their independent reserve and contingent resource estimates using deterministic methods. The achieved price and NPV(10) values quoted are for the project only, they do not include any impact from the existing oil price hedges that Australis has entered into. Australis is not aware of any new information or data that materially affects the information included in the referenced announcement and all the material assumptions and technical parameters underpinning the estimates in the original announcement continue to apply and have not materially changed. The figures quoted are the 1P developed and producing reserve and the 2C contingent resource recoverable estimate as reported in the Ryder Scott reserve report dated 29 January 2025. That report included the following reserve and resource estimates of oil. Net Oil Reserves (Mbbls) 1P 2P 3P 1,644 2,109 2,719 1C 2C 3C Contingent Oil Resources (Mbbls) 19,333 62,560 113,233 The 1P, 2P and 3P figures provided are the arithmetic summation by category and are referenced to the individual well oil metering at each producing well location. The 1C, 2C and 3C figures provided are the arithmetic summation by category. 20 Footnotes - continued 2. Comparison of updated ATS Type Curves to Ryder Scott Reserve Type Curves from YE2020 reserve estimates (last RS update) 21 Glossary Unit Measure Unit Measure B Prefix - Billions bbl Barrel of oil MM or mm Prefix - Millions boe Barrel of oil equivalent (1bbl = 6 mscf) M or m Prefix - Thousands scf Standard cubic foot of gas /d Abbreviation TMS TMS Core Suffix - per day Bcf Billion standard cubic foot of gas Description Abbreviation Description Tuscaloosa Marine Shale D, C & T Drilling, Completion, Tie in and Artificial Lift The Australis designated productive core area of the TMS EBITDA Net loss / profit for the period before income tax expense or delineated by production history benefit, finance costs, depreciation, depletion, amortisation and WI Working Interest impairment provision C Contingent Resources – 1C/2C/3C – low/most likely/high Net Acres Working Interest before deduction of Royalty Interests NRI Net Revenue Interest (after royalty) IP24 The peak oil production rate over 24 hours of production Net Working Interest after deduction of Royalty Interests TMS Type The history matched production performance of 16 wells drilled NPV (10) Net Present Value (discount rate), before income tax Curve in the TMS by Encana in 2014 and ATS in 2018. Corresponds to HBP Held by Production (lease obligations met) an average treated horizontal length of 7,200ft. EUR Estimated Ultimate Recovery per well IRR Internal Rate of Return WTI West Texas Intermediate Oil Benchmark Price NPT Non Productive Time LLS Louisiana Light Sweet Oil Benchmark Price Reinvestment Percentage of free cash flow used for asset development Opex Operating Costs Rate operations Capex Capital Costs F&D Cost The cost to find and develop a boe of reserve PDP Proved Developed Producing Replacement Reserve replacement rate PUD Proved Undeveloped Producing Rate 2P Proved plus Probable Reserves LTM Last Twelve Months – typically refers to a cost or variable being 3P Proved plus Probable plus Possible Reserves quoted or used. EOR Enhanced Oil Recovery G&A General & Administrative Royalty Interest Interest in a leasehold area providing the holder with the or Royalty right to receive a share of production associated with the leasehold area Field Netback Oil and gas sales net of royalties, production and state taxes, inventory movements, field based production expenses, hedging gains or losses but exclude