Annual Report 2025 Melbana Energy Limited ABN 43 066 447 952
About Melbana Energy Melbana Energy is an Australian ASX listed, independent oil and gas company that has a portfolio of attractive exploration, appraisal and development stage opportunities in Cuba and Australia. Our mission is to create a world class E&P company by using the skills of our people to identify and successfully develop attractive oil and gas exploration and development opportunities. 02 Chairman’s Letter 04 Highlights 06 Operating Review 10 Board of Directors 12 Directors’ Report 37 Governance and Risk 42 Auditor’s Independence Declaration 43 Consolidated Statement of Profit or Loss and Other Comprehensive Income 44 Consolidated Statement of Financial Position 45 Consolidated Statement of Changes in Equity 46 Consolidated Statement of Cash Flows 47 Notes to the Consolidated Financial Statements 74 Consolidated Entity Disclosure Statement 75 Directors’ Declaration 76 Independent Auditor’s Report 82 Shareholder Information 85 Glossary of Key Terms 86 Corporate Directory Contents 01 Melbana Energy Limited Annual Report 2025
Building Momentum It is with pleasure that I present to you the 2025 Annual Report for Melbana Energy Limited, a year that marked our transition from explorer to producer. Cuba remains the main near-term value catalyst for the Company. During the reporting period we completed the workover of Alameda-2 and commenced full-time production. This was the first step in commercialising the 46 million barrels1 Contingent Resource2 in the shallow Amistad sheet of the greater Alameda oilfield we discovered in our onshore Block 9 PSC. We will continue to focus on the development of oil from the Amistad section, given it’s quicker and cheaper to access and contains a relatively higher quality of crude oil. It is important to remember, though, that we have also discovered energetic and freely flowing oil in the lower geologically independent Alameda and Marti sections that provide us with plenty of running room for additional field development. While progress towards increasing production this year has been slower than anticipated, for several reasons outside of our control, the technical insights gained - particularly around reservoir sensitivity - have informed our proprietary drilling fluid design and simplified well architecture, positioning us for success. Preparations for the drilling of our first dedicated production well, Amistad-2, are complete and the rig is currently mobilising to site at the time of writing. This well targets a structurally promising zone expected to deliver enhanced flow rates 200 metres up-dip of the original 1,235 bopd zone discovered in the same sheet by Alamada-2. 1 Independent best estimate (2C), 100% share. 2 See ASX announcement dated 25 March 2024. Chairman’s Letter 02 Melbana Energy Limited Annual Report 2025
To accelerate the rate at which we can produce oil from our contract area in Cuba requires us to gain better and more direct control of our operational inputs without increasing well costs. If our planned future production wells allow us to keep growing production and if these production volumes can be commercialised regularly then we will have taken some important steps towards achieving this goal. We are better prepared to achieve both these things in the year ahead. We are appraising and developing a very large oilfield, one that is comprised of not just one anticline but of several, which together form a very large anticlinal structure, termed an anticlinorium. The scale of the Alameda anticlinorium can be difficult to comprehend. Turning to Australia, over the last decade or so we have seen increased regulatory and social headwinds against exploring for then developing Australia’s natural energy advantage. As I foreshadowed last year, economic reality has forced a rethink of the importance of natural gas as a component of our energy mix, and recent events suggest that this tide may be starting to turn with signs the realisation of the essential contribution of gas toward net zero targets may be sinking in. If so, Melbana is well placed to capitalise with the Company’s portfolio of high-quality gas exploration permits offshore Western Australia. During the reporting period, our Geoscience team interpreted and mapped 3D seismic we had reprocessed, resulting in our maiden resource estimates for the historical Vesta and Swan gas and oil discoveries and adjacent prospects. We have since had good engagement from several potentially interested farminees with proximate activities and an interest in securing more qualified exploration opportunities. Finally, I commend our team for their continued diligence and scientific approach to problem solving. We have had a year of challenges and frustrations, but this didn’t stop them continuing to push toward our goal of delivering an increase in shareholder value. Andrew Purcell Executive Chairman 03 Melbana Energy Limited Annual Report 2025
04 Melbana Energy Limited Annual Report 2025 Highlights Cuba Block 9 Cuba Cuba The Alameda-1 exploration well, completed in 2022, identified multiple vertically stacked and geologically independent oil-bearing structures (called Amistad, Alameda and Marti). The appraisal program consisting of Alameda-2 and Alameda-3 in 2023 and 2024 respectively, led to the independent assessment of a 2C Contingent Resource3 of 46 million barrels in Unit 1B of the Amistad sheet and an upgrade to the Prospective Resources of the Unit 1A (Best Case 32 million barrels) and Unit 1B (Best Case 90 million barrels). During the year, the Company commenced development operations including the workover of Alameda-2 and design, procurement and site construction for the Amistad-2 and Amistad-3 wells. ALAMEDA-24 was completed in Unit 1 of the Amistad structure in FY2024 and subject to a workover in 2025.This workover was designed to remediate near-well formation damage of the Amistad Unit 1B reservoir and the first step in the establishing full-time production and development of the field. Workover highlights include: First use of the service rig, primarily under 12-hour operations. Addition of new perforation intervals in both the upper and lower Unit 1B. Acid-squeeze resulted in significant acid and completion fluid losses to the reservoir. Block 9 Development Scope Commenced 3 Independent best estimate (2C), 100% share, as per ASX announcement 25 March 2024. 4 Also referred to sometimes as Amistad-1. During clean-up flows static gradient and a memory production log (MPLT) survey were run. The MPLT confirmed that a pump would accelerate recovery of the heavy-weight completion brine used to control the well. A down-hole pump was run and a second acid treatment conducted. After further cleanup flow, the well was shut-in for 12 hours before a 12-hour test was conducted and the service rig rigged-down and released. The well was handed to production, all completion brine recovered and the well-produced continuously for the remainder of the period. A closing crude inventory of 22,863 barrels was established at the end of the financial year. ALAMEDA-2 AND ALAMEDA-3 STUDIES The Alameda-2 and Alameda-3 wells were multi-objective appraisal wells which gathered large amounts of data and samples, all requiring analyses. Studies of these samples and data were largely completed during the year. Results highlights include: Completion of biostratigraphic studies now allows for more direct comparison of the units encountered with the local analogous oil fields; Identification of carbonate facies in individual core samples recovered, providing important information for future well targeting; and Observation of plugging of some pore spaces with barite and precipitation of minerals in fractures leading to studies defining the best composition of nondamaging fluids.
05 Melbana Energy Limited Annual Report 2025 5 Internal estimate - 100% share, best estimate. 6 See ASX announcement dated 26 February 2025. Melbana was formally awarded a new offshore 516km2 exploration permit, WA552-P, in the first offshore acreage release in Australia in recent years. Hudson Prospect WA-544-P and NT/P87 (100%) – Continued a process to seek a partner to fund next stage of exploration work on a structure estimated to hold a Prospective Resource of either 466 BCF of gas or 90 million barrels of oil5. AC/P70 (100%) – Interpretation and mapping of reprocessed 3D seismic survey was completed resulting in maiden resource assessments6 for the historical Vesta and Swan gas and oil discoveries and adjacent prospects identified by the Melbana team. A marketing process was commenced with good engagement from several parties; and, WA-448-P (contingent cash and royalty interest) – Operator of the permit received environmental approval to drill an exploration well, and applied for additional time to meet drilling commitment. Significant progress with offshore exploration opportunities Australia DEVELOPMENT DRILLING PROGRAM Design, permitting, procurement and construction was completed in preparation for the drilling of Amistad-2 and Amistad-3. Highlights include: Successfully developed and lab tested a new non-damaging reservoir drilling fluid to mitigate the risk of formation damage in future Block 9 wells. A new, simplified well design for the single-target objective development wells in the shallow Amistad sheet. Construction of the Amistad-2 (Pad 9) and Amistad-3 (Pad 4) well locations and associated roads and camp. Completed procurement and delivery receipt of all equipment and materials necessary to drill Amistad-2 and Amistad-3. Completed procurement of production equipment for Amistad-2. Awaiting arrival of the drilling rig to commence drilling of Amistad-2. Tassie Shoal Methanol LNG Projects AC/P70 WA-488-P NT/P87 WA-544-P Australia WA-522-P
Operating Review “ We have undertaken the exploration, made the discovery and analysed the data. As the early stage of development is underway, the production phase has commenced for our high-impact Cuban oil discovery, and we will start seeing that impact in FY2026.” 06 Melbana Energy Limited Annual Report 2025
Cuba Block – 9 (Melbana 30%) The northern coast of Cuba is a prolific oil province. We’re constantly reminded of the fact every time we drive the Via Blanca between Havana and Varadero but it’s not just the sight of wellheads, nodding donkeys and tank farms (See Figure 1). On occasions we’ve stopped by the road and noted the natural and live oil seeps around some of the old oilfields on the coast and this is why at least some of these shallow oilfields were originally drilled and discovered. Figure 1 - Matanzas Supertanker Base We also see natural oil seeps within Block 9, some of which were mined for asphalt as was historically common, first by the indigenous Taíno people and subsequently the Spanish, who used it to caulk their ships. In Cuba an oil seep can be a reminder you’re in the right spot but when you’re chasing a higher quality product, you need to dig a little deeper. Over the course of the last year we’ve been frustrated by the rate of our progress on the ground. However, this has afforded us the ability to study in greater detail the vast amount of samples and data we have collected during the exploration phase. We’ve talked a lot about what we’ve learned in terms of formation damage and drilling fluid compatibility but we’ve also learned a lot about the geology and that is, of course, fundamental to developing the large oil discovery that we’ve made. It may sound odd, but we’ve learned a lot from very small to microscopic fossils of ancient marine critters and pollen spores. Literally getting the rock samples under the microscope has allowed us to better understand what’s happening in the macro scale with the structure and the various reservoir sheets that have been thrust one on top of another, compressing about 70km of horizontal section into about 10km. We now describe the structural reservoir sheets we’ve observed to date as the Amistad, Alameda and Marti sheets. Together they form part of a buried mountain range that is the anticlinorium of the greater Alameda field, not dissimilar to what you can see above ground if you cross the Rocky Mountains of North America. Whilst that’s helpful and interesting, this micro-scale work has also allowed us to better understand how the discoveries we’ve made relate to the numerous nearby oilfields and the local formation terminology. The shallow section of the Amistad sheet (Unit 1A and Unit 1B) is most similar to the massive Varadero field that’s produced over 200 million barrels of extra-heavy (<10° API) crude. We’re yet to properly test the shallowest Unit 1A reservoir, locally known as the Santa Teresa Formation. However, most of the Amistad sheet is made up of Unit 1B and is the core of our near-term development focus. Alameda-2 demonstrated the productive potential averaging 1,235 bopd on drill stem testing (DST) of a much lighter, less viscous (19° API) crude than is produced at Varadero. The quality of crude is important and has a significant impact on its market value. Analysis of the 19° API Amistad crude shows that it is comprised of a significant proportion of valuable middle distillates and surprisingly heavier asphaltenes, which makes it very attractive to oil traders and refiners alike. Our Alameda-2 (aka Amistad-1) oil well is now in full time production, and we are building inventory as we await our first export. We also await the return of the drilling rig to commence our first singletarget development well: Amistad-2. The Amistad Unit 1B reservoir has been assessed as containing a gross contingent resource2 of 46 million barrels (2C) in the eastern end of the field plus 90 million barrels of gross prospective resource3 (2U) in the western end of the structure. The shallow Amistad sheet also includes a further 32 million barrels (gross) prospective resource relating to Unit 1A. The government of Cuba and our joint operations partner remain supportive of the Company’s plans for development of the field, which we have commenced on a modest scale thus far. During the year the Company commenced production from the field and is now progressing as expeditiously as economically sensible towards revenue from Block 9. This is an important milestone and one on which we will build to significant scale in the coming years. The Company is fortunate to have been able to acquire such a high-quality exploration asset in such a prolific oil-prone area. Amistad production commenced Alameda-2 was spudded in June 2023, reached total depth of 1975m on 31 July 2023 and produced an average of 1,235 bopd of oil during DST-4 of Unit 1B. Extended production testing during 2023 and 2024 demonstrated that the formation had been damaged during well-kill operations following the successful DST. During the period, the well was subject to a remedial workover and acidisation. The Alameda-2 remedial workover commenced in February 2025 using a service rig, primarily on 12-hour operations, the scope included: 07 Melbana Energy Limited Annual Report 2025
Operating Review continued – Pulling the completion. – Adding new perforation intervals in both the upper and lower Unit 1B. – Undertaking an acid wash and squeeze. – Re-running the completion. – Conducting an extended clean-up flow to unload heavy-weight completion brine and spent hydrochloric acid. – Analysing of static gradient surveys and a MPLT survey to determine that a pump would be required to recover all of the heavy-weight completion brine used to control the well. – Installing a down-hole pump. – Conducting a second acid treatment. – Conducting a further clean-up flow period to recover the bulk of completion fluids. – Undertaking a short flow test prior to releasing the service rig. The remedial workover operations were completed in April 2025 and the Alameda-2 well commenced continuous production following demobilisation of the service rig from location. Total production to the end of the reporting period was 19,259 barrels, bringing the closing crude inventory to 22,863 barrels at the end of the year. Amistad development Following the observation of reducing productivity associated with formation damage, particularly in Alameda-2, the Company commenced a significant technical review to determine the most likely damage mechanisms and identify mitigation strategies to reduce this risk in future wells. This work resulted in the identification of barite (a non-reactive weighting agent in conventional drilling mud) embedment and mineral precipitation, in varying amounts on different core samples. This in turn informed the Company’s development of a proprietary reservoir drilling fluid (Melbana RDF). The Melbana RDF was designed to reduce the quantity of barite required to control high-pressure reservoirs whilst avoiding the use of chemically incompatible fluids. The company tested numerous brine-based fluids. 08 Melbana Energy Limited Annual Report 2025
After identifying the best performing fluid, extensive compatibility testing was conducted to ensure that the RDF would work within the required drilling parameters, but without damaging the formation. This laboratory testing has informed not only the chemical makeup of the fluid but also the operating procedures to ensure the quality of the RDF is maintained throughout. A further impact on the performance of Alameda-2 is believed to be the physical configuration of the wellbore and its multi-target design. For development drilling, the well design was therefore significantly simplified to a single target with open-hole completion. Procurement and delivery receipt of all equipment and materials necessary to drill Amistad-2 and Amistad-3 was completed during the period. Construction of the Amistad-2 and Amistad-3 well pads was conducted and all necessary permits to drill were received during the period. The Amistad-2 well will be directionally drilled to target the Unit 1B approximately 200m up dip and 850m to the south of Alameda-2. This location is expected to intersect the axial crest of a localised anticline and due to the combination of geological structuring, in-situ stresses and brittle formation is expected to encounter a substantially fractured and productive reservoir section. Commencement of the Amistad drilling awaits the arrival of the drilling rig. The Amistad-2 and subsequent contingent Amistad-3 wells are planned to be completed prior to testing. This is to minimise the potential for formation damage. It also means that as soon as the rig is demobilised from the location, the well will commence production. For these initial wells, each well pad will have its own small production facility, tanks and tanker loading gantry with provision to upgrade and expand as required. Commercial arrangements have continued to progress through the course of the year. The Company has identified a reliable export pathway for its crude production, enabling early sales and an efficient route to market ahead of the Company establishing more significant volumes. This solution supports timely monetisation of production contributing to development funding. 09 Melbana Energy Limited Annual Report 2025
10 Melbana Energy Limited Annual Report 2025 Andrew Purcell Executive Chairman Andrew Purcell founded the Lawndale Group (formerly Teknix Capital) in Hong Kong over 20 years ago, a company specialising in the development and management of projects in emerging markets across heavy engineering, petrochemical, resources and infrastructure sectors. Prior to this, Mr Purcell spent 12 years working in investment banking across the region for Macquarie Bank and then for Credit Suisse. Mr Purcell also has significant experience as a public company director, both in Australia and across Asia. Peter Stickland Non-Executive Director Peter Stickland has over 30 years’ global experience in oil and gas exploration. Mr Stickland was CEO and subsequently Managing Director of the Company from 2014 until January 2018 and then became a Non-Executive Director. Previously, Mr Stickland was CEO and subsequently Managing Director of Tap Oil Limited (ASX: TAP) from 2008 until late 2010 during which time he oversaw the evolution of the company into a Southeast Asia/Australia focused E&P company. Prior to joining Tap Oil, Mr Stickland had a successful career with BHP Petroleum (now part of Woodside) including a range of technical and management roles. Mr Stickland is also a life member of the Australian Energy Producers Limited (AEP). Michael Sandy Non-Executive Director Michael Sandy is a geologist with over 40 years’ experience in the resources industry – mostly focused on oil and gas. In the early 1990s he was Technical Manager of Oil Search Limited, based in PNG. He was involved in establishing Novus Petroleum Ltd and preparing that company for its $186m IPO in April 1995 and over 10 years, he held various senior management roles with the Company. Subsequently Mr Sandy has been the principal of energy consultancy company Sandy Associates P/L, has set up and taken companies to IPO and has built extensive experience on the boards of listed and unlisted companies, including Tap Oil, Burleson Energy and Hot Rock. Board of Directors See pages 25 to 26 for further information.
12 Directors’ Report 37 Governance and Risk 42 Auditor’s Independence Declaration 43 Consolidated Statement of Profit or Loss and Other Comprehensive Income 44 Consolidated Statement of Financial Position 45 Consolidated Statement of Changes in Equity 46 Consolidated Statement of Cash Flows 47 Notes to the Consolidated Financial Statements 74 Consolidated Entity Disclosure Statement 75 Directors’ Declaration 76 Independent Auditor’s Report 11 Melbana Energy Limited Annual Report 2025 Financial Report
Directors’ Report The Directors present their report, together with the financial statements, on the consolidated entity (referred to hereafter as the ‘Consolidated Entity’) consisting of Melbana Energy Limited (referred to hereafter as ‘Melbana’, the ‘Company’ or ‘parent entity’) and the entities it controlled at the end of, or during, the year ended 30 June 2025. Directors The following persons were Directors of Melbana Energy Limited during the whole of the financial year and up to the date of this report, unless otherwise stated: Andrew Purcell (Executive Chairman) Michael Sandy (Non-Executive Director) Peter Stickland (Non-Executive Director) Principal activities The principal activities of the Consolidated Entity during the year were oil and gas exploration in Cuba and Australia together with development concepts for the Tassie Shoal Methanol and LNG Project. Dividends There were no dividends paid or declared during the current or previous financial year. Review of operations International Operations Cuba - Block 9 (Melbana 30%) During the reporting period, the Company conducted routine and special core analysis on samples recovered from Alameda-3. These studies included investigations into the potential sources of formation damage observed in both the Alameda-2 and Alameda-3 wells. Evidence of formation damage was noted in scanning electron microscope (SEM) and computed tomography (CT) images by the presence of barite embedment and crystalline precipitates within pores and fractures and on the surface of core plugs (See Figure 2). 12 Melbana Energy Limited Annual Report 2025
These observations informed the extensive chemical analysis, development and final design of a proprietary reservoir drilling fluid (Melbana RDF) to mitigate the risk of formation damage in future drilling operations. Following development, Melbana RDF was subject to extensive fluid and rock compatibility testing, which confirmed its suitability and compatibility with the primary Unit 1B reservoir. Melbana RDF is a water-based drilling fluid that is designed to minimise the risk of formation damage whilst maintaining the ability to safely and effectively drill the well. The use of RDF is not uncommon for formations susceptible to drilling induced damage but none had previously been developed for use in Cuba (See Figure 3). Figure 3 – Melbana RDF (Sample 14, LHS) was designed to maximise production well flows by minimising the risk of formation from crystallisation of precipitates, excessive barite and emulsion formation Figure 2 – Evidence of formation damage 13 Melbana Energy Limited Annual Report 2025
A workover and acid stimulation program were conducted on Alameda-23 over a 54-day period, operating primarily on 12-hours except as dictated for operational safety and during well flow-back periods. Key steps in the program included using a service rig to pull the original completion, adding new perforations in both the upper and lower Unit 1B, undertaking an acid wash and squeeze then re-running the completion. Following completion, an extended period of clean-up flow was undertaken to unload heavy-weight completion brine and spent hydrochloric (HCl) acid lost to the formation during operations. A significant volume of heavy-weight completion brine and stimulation fluid had been lost to the formation during the workover. Static gradient surveys and a MPLT survey were run and confirmed that a pump would accelerate the recovery of the heavy-weight completion brine used to control the well. A down-hole pump was run and a second HCl acid treatment conducted. A further period of clean-up flow was conducted on Alameda-2 and the well subject to brief test prior to being handed over to production. For the remainder of the period the well was produced on a continuous basis recovering oil and lost completion fluid. Substantially all completion and stimulation fluids lost to the formation had been recovered to surface by the end of the period. Crude oil produced from Alameda-2 undergoes primary separation and storage on site. This stored production is regularly transported to facilities managed by the national oil company for further processing. The Company continues to increase its stored oil volume and inventory closed at 22,863 barrels at period end (See Figure 4). Preparations for the drilling of the first purpose designed development well on Block 9, Amistad-2, were conducted throughout the period. The contingent Amistad-3 well is planned to follow. Well permitting was conducted for four new well pads during the period, each sized to accommodate at least two wells per drilling pad. Amistad-2 is to be drilled from Pad 9, located approximately 850 metres to the southwest of the Alameda-2 well. All Amistad-2 civil works, comprising well pad, access road and production equipment area, were completed during the period and all non-rig equipment and materials to drill the well received. The Amistad-2 well was designed considering all lessons learned to date to maximise its flow potential. These design requirements included planning to intersect as many fracture zones as possible, a significantly simplified single-target well design with no cement in the production hole and use of a non-damaging drilling fluid. Figure 4 – Alameda-2 has been on continuous production since the completion of workover activities in April 2025 Directors’ Report continued 14 Melbana Energy Limited Annual Report 2025
To meet these design requirements, Amistad-2 will target an area near the crestal axis of one of the discovery’s localised anticlines, approximately 200 metres updip of the top reservoir in Alameda-2, to a total depth (TD) of 1125 metres MD. The well path will orthogonally traverse a series of localised fault and fracture zones and encounter all of the Unit 1B but no further. Drilling will be conducted utilising the company’s proprietary Melbana RDF at the minimum fluid weight required to safely drill and the well will be completed open-hole with a contingent slotted liner available if circumstances require. Civil construction of the Amistad-3 well-pad, access road and rig-camp locations were nearing completion and awaiting final levelling and compaction at the end of the period. The permit to drill is in hand and all necessary material drilling equipment and materials were received. The contingent Amistad-3 well has been planned under the same design requirements as Amistad-2. Amistad-3 targets the Unit 1B in a similar geological architecture from the Pad-4 location on the next parallel anticline to the south of Amistad-2. Amistad-3 is planned to be drilled to a TD of 1625 metres MD, shallower than the deepest known oil in the Amistad sheet (See Figure 5). Confirmation of oil saturation to the toe of the well may de-risk the adjacent oil prospect to the southwest. Subsurface development planning continued to progress throughout the course of the year and a focused effort made on defining suitable surface locations which allow the targeting of primarily Amistad sheet reservoirs based on the existing 2D seismic (See Figure 6). This process yielded 30 well concepts which may be justified to continue to appraise and develop the field. This subsurface development plan is based on revised interpretation of the greater Alameda structure and was reviewed with the Joint Operation partner and the Cuban regulator in April 2025. Our understanding of the stratigraphy observed in the Alameda wells drilled to date has been improved by an extensive biostratigraphic study of microscopic fossils preserved in the rocks and recovered as core and drill cuttings to date. Critically, this work permitted the understanding of the accurate Cuban formation names rather than the generic unit names that had been previously assigned. Figure 5 - Trajectory of Amistad-3 showing long intercept of fractured reservoir section 15 Melbana Energy Limited Annual Report 2025
Work on the surface development planning was also progressed during the year, with an engineering study of the existing Alameda-2 temporary facility being conducted. The study recommended modifications to facilitate safe production operations over a longer term than the original temporary test facility had been designed to accommodate. These recommendations will also be carried over to future well-site facilities until such time as a central production processing and storage facility is justified, designed and constructed. The Joint Operation remains focused on near-term commercialisation of the PSC, taking a pragmatic approach to the simultaneous appraisal and development of the field. This methodology is often used onshore and will allow oil to flow to market quickly, continue to de-risk and upgrade the contingent and prospective resources, and with revenues supporting future field development costs. Initially, the development drilling activities are planned and proposed within the Unit 1B reservoir in the eastern area of the field in which McDaniel & Associates Consultants LLC (McDaniel), a Canadian based independent certifier of oil and gas reserves and resources with experience of Cuban geology, assessed the Company’s Block 9 contingent resource. Continued success in these wells will then lead to further drilling to the west in the adjacent Unit 1B area currently defined by McDaniel and Associates as a prospective resource. Figure 6 - Planned Unit 1B wells targeting 1C resource in eastern part of Amistad field With our oil inventory building following the establishment of continuous production from Alameda-2 it remains our goal to deliver our first export in 2025. It is hoped that Amistad-2 will contribute to the volume of oil that is exported. Directors’ Report continued 16 Melbana Energy Limited Annual Report 2025
In 2024, McDaniel assessed a gross (100%) 2C2 Contingent Resource of 46 MMbbl with a Sub-Categorisation of Development Pending (80% Chance of Development) for Amistad Unit 1B in the eastern part of the structure. McDaniel also assessed a gross (P50) best estimate Prospective Resource of 90 MMbbl (with a Chance of Discovery of 70% if an appraisal well was drilled) for Amistad Unit 1B in the western part of the structure. McDaniel also assessed a gross (100%) P50 – Best Estimate - Prospective Resource of 32 MMbbl for Amistad Unit 1A (with a Chance of Discovery of 70%) that could be similarly derisked by drilling an additional appraisal well and testing on pump in that area. Melbana’s estimates of Contingent and Prospective Resources have not changed during the period. Australian Operations WA-488-P (Melbana contingent cash and royalty interest) The Company sold its 100% interest in permit area WA-488-P to the Australian subsidiary of a US oil major in November 20217. The purchaser became the Operator and made a country entry to drill the giant Beehive Prospect located within the WA-488-P exploration permit. The Beehive Prospect was independently estimated to contain a Prospective Resource of 388 million barrels of oil equivalent (Best Estimate, 100% basis)8 and a high estimate of 1.6 billion boe. Melbana revised these estimates9 to a Prospective Resource of 416 million boe (Best Estimate, 100% basis) with a high estimate of 1.4 billion boe following its assessment of the 3D seismic data acquired across the prospect in 2018. Under the terms of the sale and purchase agreement, the Company is entitled to receive contingent future payments of USD5.0 million (subject to the purchaser making certain future elections with regards to the permit) and USD10.0 million for each 25 million barrels of oil equivalent in the event oil is produced from the permit area should the exploration well be a commercial success. Beehive received approval of its environmental plan for the drilling of up to three wells during the reporting period. The new Operator also applied for and received a suspension of the Permit Year 3 work program obligation to drill one well until October 2026. The Company has no exposure to the cost of this exploration well. Beehive will test a large Carbonate Platform Prospect similar to that defined by the Company in the adjacent exploration permits NT/P87 and WA-544-P. WA-544-P and NT/P87 (Melbana 100%) These permit areas, containing the undeveloped Turtle and Barnett oil discoveries, were granted to the Company in 2020 under the Australian Government’s 2019 Offshore Petroleum Exploration Acreage Release. They are in shallow water (20 to 40 metres deep) and located about 300 kilometres southwest of Darwin, Australia. The Blacktip gas field lies to the northwest and its pipeline transects the northern boundary of NT/P87, allowing potential access to the Darwin LNG facility and/or the east coast gas market. The exploration permits host Carbonate Platform opportunities with similar resource potential as the adjacent WA-488-P exploration permit, which contains the Beehive drilling Prospect (See Figure 7). During the reporting period the Company continued its efforts to identify a farm-in partner for the exploration permit. The permit areas include a Prospective Resource of over 466 BCF of gas or 90 million barrels of oil (unrisked best estimate, 100%) for the Hudson Prospect. 7 See ASX announcement dated 23 April 2021. 8 See ASX announcement dated 14 August 2018. 9 See ASX announcement dated 24 August 2020. 17 Melbana Energy Limited Annual Report 2025
Figure 7 – The location of the Company’s Exploration Permits WA-544-P and NT/P87 relative to WA-488-P AC/P70 (Melbana 100%) On 16 February 2022, the Company announced that it had been granted petroleum exploration permit AC/P70, located in the Territory of Ashmore and Cartier Islands, for an initial period of six years. Melbana made an application for this permit under the Australian Government’s 2020 Offshore Petroleum Exploration Acreage Release (See Figure 8). Since being awarded the permit, the Company has licensed various datasets and undertaken considerable work to better understand what exploration opportunities might exist there. The undeveloped Vesta-1 oil discovery (drilled in 2005) lies within the permit area and an appraisal well drilled in 2007 identified a gas cap. During the reporting period the Company completed interpretation of the reprocessed 500km2 legacy Pantheon 3D seismic survey. The reprocessing significantly improved the seismic data quality allowing the identification and mapping of significantly larger exploration targets within and adjacent to the working petroleum systems of the greater Swan and Vesta discoveries. Some of these areas are updip to the old discovery wells, further increasing the chance of success. The combined unrisked gross best estimate Prospective Resource for the permit is 2,754 Bcf and 43 MMbbl5, 6. AC/P70 contains the undeveloped Swan gas field, discovered by Arco in 1973 while exploring for oil and which was further appraised by an additional two wells by BHP in 1991. Wireline pressure data and recovered gas samples from several sands of the Cretaceous Puffin sandstone confirmed a common pressure regime and the presence of mobile gas. The Vesta oil and gas field was discovered by ENI in 2005, also whilst exploring for oil, and was appraised by a second well. Three DST confirmed the presence of producible oil and gas from the Jurassic “Spec Di” reservoir but the field has not been developed. Significant and relatively high probability-of-geologic success (Pg) prospective resources are interpreted within untested compartments up-dip of the discovery wells. Directors’ Report continued 18 Melbana Energy Limited Annual Report 2025
During the period, the Company assessed the combined best estimate (2C) Contingent Resource volume for the Swan and Vesta fields was 276 Bcf and 34 MMbbl5. The permit is adjacent to existing production and facilities offering a clear pathway to commercialisation of any significant discovery. The Company commenced efforts to identify a farm in partner for the exploration permit during the reporting period. Figure 8 – Location of AC/P70 and reprocessed 3D seismic volume outline 19 Melbana Energy Limited Annual Report 2025
Field Hydrocarbon 1C 2C 3C Vesta – (Spec Di) Gas (Bcf) 39 105 199 Oil (MMbbl) 10 30 47 Swan – (Puffin) Gas (Bcf) 132 171 211 Oil (MMbbl) 3 4 5 Rec Gas Arithmetic Totals Gas (Bcf) 171 276 410 Rec Oil Arithmetic Totals Oil (MMbbl) 13 34 53 Table 1 – AC/P70 gross un-risked Contingent Resource Summary Prospect Hydrocarbon Pg Mean Low 1U Best 2U High 3U Vesta Deep (Plover) Gas (Bcf) 16% 338 71 231 730 Vesta North (Spec Di) (Gas Cap on Oil rim) Gas (Bcf) 42% 200 116 195 287 Oil (MMbbl) 42% 45 22 43 71 Swan Deep (Spec Di) Gas (Bcf) 23% 222 112 206 352 Swan Deep (Plover) Gas (Bcf) 16% 143 55 126 253 Swan North-West Gas (Bcf) 44% 198 155 196 243 East Swan Deep (Triassic) Gas (Bcf) 18% 702 200 569 1397 East Swan Deep (Permian) Gas (Bcf) 24% 1402 337 1231 2695 Rec Gas Arithmetic Totals Gas (Bcf) 3205 1046 2754 5957 Rec Oil Arithmetic Totals Oil (MMbbl) 45 22 43 71 Table 2 – AC/P70 gross un-risked Prospective Resource Summary WA-552-P (Melbana 100%) During the period the Company was granted petroleum permit WA-552-P10, located offshore Western Australia in the Dampier Sub-basin of the Northern Carnarvon basin (See Figure 9). The permit was applied for under the 2022 Offshore Petroleum Exploration Acreage Release and Melbana was one of only five companies to be awarded a new permit, with the other four all being major oil and gas companies. The permit was granted for an initial six-year period, with the primary term (first three years) work commitments comprising only desktop studies. Progressing beyond the primary term is at Melbana’s election. The permit area contains several small oil discoveries including Tusk, Okapi, Brocket, Oryx and Chamois and is immediately to the west of the Stag oil field, which has been producing oil since 1998. Melbana’s exploration thesis is that the Dampier Sub-basin may share a similar geological history to the Canning Basin, Petrel and Vulcan Sub-basins by way of salt seal deposition and carbonate reservoir architecture. The Company has been actively pursuing such plays in association with salt tectonics in its other exploration permits, WA-544-P and NT/P87. 10 See ASX announcement dated 19 September 2024. Directors’ Report continued 20 Melbana Energy Limited Annual Report 2025
NORTHERN CARNARVON BASIN | DAMPIER SUB-BASIN W22-5 industry.gov.au/2022 OFFSHORE PETROLEUM EXPLORATION ACREAGE RELEASE | AUSTRALIA 2022 Figure 9 - Location of WA-522-P (formerly W22-5) Tassie Shoal (Melbana 100%) The Company has Australian Government environmental approvals to construct, install and operate two stand-alone world scale 1.75 Mtpa methanol plants - collectively referred to as the Tassie Shoal Methanol Project - and a single 3 Mtpa LNG plant - known as the Tassie Shoal LNG Project - on Tassie Shoal, an area of shallow water in the Australian waters of the Timor Sea approximately 275 km northwest of Darwin, Australia (See Figure 10). These environmental approvals are valid until 2052. These projects uniquely provide a development option for discovered but undeveloped gas resources in the region. Progress for these projects is dependent on securing access to proximate gas supply on suitable commercial terms. No material progress was made in this regard during the reporting period. Figure 10 - Location of the Tassie Shoal Projects 21 Melbana Energy Limited Annual Report 2025
Results for the year The net loss after tax of the Consolidated Entity for the financial year was $4,151,446 (2024: net profit after tax of $3,259,760). The loss for the year represents the support costs of the corporate function for Melbana as the majority of the costs are recovered from the Block 9 project. During the year, the Consolidated Entity incurred net operating cash outflows of $3,623,620 (2024: outflows of $3,670,961), net investing cash outflows of $3,796,677 (2024: outflows of $18,666,009 ) and net financing cash inflows of $nil (2024: inflows of $nil). The successful drilling and commercialisation of any oil and gas discoveries in Cuban and Australian exploration permits and/or the development/sale of the Consolidated Entity’s methanol and LNG Projects could ultimately lead to the establishment of a profitable business or result in a profit to the Company if an asset sale occurs. While the Consolidated Entity is in the exploration/appraisal stage of drilling for hydrocarbons in its offshore Australian exploration permits and overseas acreage, and in the project development phase for its other offshore Australian interests, funding will be provided by asset sales, equity capital raised from the issue of new shares, and/or farm-out or joint development arrangements with other companies. Review of financial position The net assets remained relatively flat year on year with an end of year balance of $55,926,331 at 30 June 2025 (30 June 2024: $55,931,168). During the year, the Consolidated Entity capitalised $2,795,726 (2024: $26,044,200) on exploration, mainly in relation to Block 9 in Cuba. The balance capitalised to exploration costs for Block 9 was lower than in prior years, reflecting a change in accounting treatment as the Company prepares for multi-well drilling operations during the field development stage. Inventory purchases are no longer fully charged to drilling costs at the time of purchase but are now expensed to drilling costs, and consequently capitalised to exploration costs, when utilised. This change resulted in Drilling Supplies and Material inventory of $12,060,045 at 30 June 2025 (30 June 2024: $nil). In addition, the Company held $634,142 (at cost) of crude inventory in storage tanks from production at the Amistad-1 well. This crude inventory has been valued on a pre-commercial development basis, which considers only the production costs of Amistad-1 over its estimated production life to 2040. As a result, the unit cost per barrel is higher than would be the case under a full-field development valuation. The main driver of the Consolidated Entity’s financial condition is the loss after tax of $4,151,446 (2024: Profit of $3,259,760). As the Company is pre-revenue this represents the non-project support costs for the year. The Company is building crude inventory to commence commercial shipment and therefore the earnings picture will change going forward. The net current assets position as at 30 June 2025 of the Consolidated Entity results in an excess of current assets over current liabilities of $6,726,659 (30 June 2024: $10,910,423). The cash balances, including term deposits, as at 30 June 2025 were $5,115,674 (2024: $12,322,890). Corporate The Consolidated Entity’s future prospects are centred on its ability to secure quality exploration, development and producing opportunities and seeking to maximise the value to shareholders of its current portfolio, identifying and securing additional value-accretive projects, and/or undertaking a corporate transaction. At balance date, available funds were sufficient to meet the Company’s forecast corporate costs. Following the successful capital raise completed on 21 August 2025, the Company is now appropriately funded to deliver on its committed work programs for the coming year. In addition, the planned commencement of crude sales will provide an additional source of funding for the business. While funding for the coming financial year is sufficient to cover corporate costs, additional capital will be required to meet field development and other work program commitments. Discussions with potential funding partners are well advanced, and the Consolidated Entity expects to progress its planned field development activities successfully. Should the Consolidated Entity be unable to secure the required funding through the structures currently being negotiated, it may seek to raise further capital. In the event of an unsuccessful capital raise, the Consolidated Entity may be required to consider alternative measures, including the surrender of permits or potential asset sales. Directors’ Report continued 22 Melbana Energy Limited Annual Report 2025
Significant changes in the state of affairs During the financial year ended 30 June 2025, a number of events occurred that changed the state of affairs of the Consolidated Entity: On 11 September 2024, the Company reported that it had received formal approval for the development of the Amistad oil field within Block 9, Onshore Cuba. Initial development will be concentrating on Unit 1B. This represented a major milestone in moving from an exploration and appraisal focus toward production. The approvals enabled commencement of field development commencing with the remediation of the existing Alameda-2 well ahead of completing it for continuous production. This positions the Company to undertake its first trial oil exports. The approval reflected ongoing progress in Cuba and was a key step in advancing the commercialisation pathway for Block 9. On 19 September 2024, the Company was granted a new exploration permit, WA-552-P in the Dampier Sub-basin offshore Western Australia. This permit is considered prospective for gas and is located in a proven petroleum province. On 26 February 2025, the Company published its maiden prospective and contingent resource estimates for its 100% owned AC/P70 exploration permit in the Timor Sea, with a Prospective resource of 2,754 Bcf and 43 MMbbl (unrisked gross best estimate) and a Contingent Resource of 276 Bcf and 34 MMbbl (unrisked gross best estimate). On 14 May 2025, the Company provided an operations update on Block 9. The Alameda-2 well, following a workover of the Unit 1B reservoir, achieved sustained oil production from mid-April 2025. More than 15,000 barrels of oil had been produced and were in storage, with first export shipment anticipated before the end of June 2025. Civil works were completed for the Amistad-2 production well, civil works commenced for Amistad-3, a LiDAR survey was completed, and the tender for a 3D seismic survey was closed. Resource upgrades During the reporting period the Company announced the Company’s maiden Contingent and Prospective Resource assessment relating to AC/P70 (Melbana 100%, see Tables 1 and 2 above). The Company completed interpretation of the reprocessed 500km2 legacy Pantheon 3D seismic survey during the period. The reprocessing significantly improved the seismic data quality allowing the identification and mapping of significantly larger exploration targets within and adjacent to the working petroleum systems of the greater Swan and Vesta discoveries. Some of these areas are updip to the old discovery wells, further increasing the chance of success. The combined unrisked gross best estimate Prospective Resource for the permit was 2,754 Bcf and 43 MMbbl, the estimates being made probabilistically, with arithmetic aggregation. The Company assessed the combined best estimate (2C) Contingent Resource5 volume for the Swan and Vesta fields was 276 Bcf and 34 MMbbl, the estimates were made probabilistically, with arithmetic aggregation. The Swan gas field, discovered by Arco in 1973 while exploring for oil, and was further appraised by an additional two wells by BHP in 1991. The Vesta oil and gas field was discovered by ENI in 2005, also whilst exploring for oil, and was appraised by a second well. Matters subsequent to the end of the financial year On 21 August 2025, the Company announced that it had received binding firm commitments to raise approximately $7 million before costs via a placement. The placement involves issuance of 411,764,706 new Fully Paid Ordinary shares at $0.017 per share (Placement Shares), representing a 22.7% discount to the Company’s last closing share price on 18 August 2025. Each Placement Share is accompanied by one Attaching Option exercisable at $0.02 and expiring one year from the date of issue. Additionally, for every two Attaching Options exercised, the Option holder will receive one Bonus Option exercisable at $0.03 and expiring three years from the date of issue. Proceeds from the Placement will be applied towards the Company’s share of drilling costs for the Amistad-2 production well and for general corporate purposes. On 21 August 2025, the Company provided an operational update on Block 9 PSC, onshore Cuba. Rig mobilisation had commenced for the drilling of the Amistad-2 production well, with a projected spud date in mid-September and results expected by mid-October. Permitting and civil works have been completed for the Amistad-3 production well. Meanwhile, Alameda-2 continued to produce oil from the Unit 1B formation, with over 30,000 barrels currently in inventory. Additionally, permitting is well advanced for the drilling of further shallow production wells scheduled for 2026. On 26 August 2025, the Company advised that the National Offshore Petroleum Titles Administrator (NOPTA) had approved a variation of the minimum work requirements for Permit Year 4 of petroleum exploration permits WA-544-P and NT/P87 (Permits) granted to the Company in 2020 (Melbana 100%). The Permits are in the Joseph Bonaparte Gulf offshore northern Australia. 23 Melbana Energy Limited Annual Report 2025
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