Central Petroleum Limited

Good morning and thanks for joining us today. I'm Leon Devaney, Central Petroleum CEO and Managing Director. I'm also joined by our CFO, Damian Galvin. Today we'll review our fiscal year 2026 annual results and provide an update on Central's current and planned activities. We'll start with our fiscal year 2026 annual results before moving on to our current drilling program at Palm Valley. We'll then look at the growth opportunities we're building across our broader portfolio, including our expansion in the Otway and Cooper basins and the exploration program planned over the next 12 months. Taken together, these activities represent an important period for Central as we seek to increase production from our existing assets while also pursuing new opportunities to grow and diversify the business. Please feel free to submit questions at any time using the online Q&A facility. and we'll address these, or as many as we can, at the end of the presentation. Finally, before we begin, please take a moment to read the legal disclaimer included with the presentation. With that, let's get started by handing it over to Damian.

Thanks, Leon. It feels like the 2026 financial year is some way behind us now, but I think it's worth recapping on the progress that we made last financial year and particularly the foundation that sets us for FY2027, and beyond. So strategically and commercially there were some pretty significant achievements. We were successful in securing those new multi-year gas sale agreements which were the catalyst for the feed for the two new Palm Valley wells which we're currently doing and they've got the potential to really boost our revenues significantly. Those gas sale agreements are a huge win for the Palm Valley joint venture given the current uncertainty there is in gas markets and the operational status of the Northern Gas Pipeline. Notably, those recent GSAs were only possible because the new gas production from the Palm Valley wells could be brought online very quickly, particularly before the end of this year. So from a growth perspective, we diversified our exploration portfolio. We exited from those high-cost, high-risk exploration permits in the Amadeus Basin and expanded our footprint into two of Australia's proven onshore basins. That's the Cooper Basin in South Australia and the Otway Basin in Victoria. Corporately we commenced our first shareholder return program through an on-market share buyback and we also had some cash settlement of share rights. So overall it was a pretty positive year financially with higher revenues and operating margins. The higher revenues were achieved despite lower sales volumes which reflected first half oil offtake constraints and pipeline restrictions along with the usual natural field supply. Despite those lower volumes, our revenue top line increased 3% to $44.7 million. That was supported by the higher portfolio pricing, driven by new supply contracts, including the new GSA with the Northern Territory Government, which started in January. As a result, average realised prices in FY26 increased 10% to $10.10 per gigajoule equivalent, and the average gas price increased by 3%. to $10.38 a gigajoule in the June quarter. These higher-priced contracts have flowed through to higher operating margins, which increased by 5%, to almost $5 per gigajoule equivalent in FY26, and that's an increase of 36% over two years. And while our overall gross operating profit was steady at $15 million, we did have a number of exploration related costs which pushed the bottom line to a $4.9 million statutory net loss of the year. The largest item of those was related to the exit from the two Amadi space and exploration permits. So we recognised a one-off non-cash impairment loss of $5.9 million as we wrote off the legacy costs associated with those permits. We also recognised $5.7 million of exploration and appraisal costs. Most of those costs for the preparation of long-lead items for those two new Palm Valley appraisal wells, the first of which is now subsequently drilled. And while normally development wells would be booked as a capital cost, these are classified as appraisal wells because we don't have any reserves booked. So our accounting policy requires us to expense those costs, similar to exploration wells. So as a result, those costs show up in our bottom line as we drill the wells. Our net corporate and admin costs for the year were also higher, partly due to the normal cost and salary increases and also non-recurring business development costs of about $900,000. That was driven by rebalancing of our exploration portfolio. We also made some adjustments to the way we allocate staff costs to joint ventures. That resulted in adjustments to previously reported expenses from 2024 and 2025. and it will result in a net reimbursement of $1.4 million. So we've updated our allocation methodology for future periods so that we won't have adjustments like that in the future. Off the back of those solid underlying results for FY26 and the cash reserves on hand, we're now set to fund a period of high impact activity. We've got our capital prioritised to increased investment in appraisal and exploration and it's underwritten by our improving free cash flows. I mentioned the new gas contracts earlier and it's worth revisiting those as they really are driving our improved financial and commercial outlook. Now most of you will already understand that we supply into a relatively isolated market in the Northern Territory. We've got the Northern Gas Pipeline to the East Coast markets being closed now for an extended period and Central's been supplying about 50% of the Northern Territory's gas demand with the balance being supplied firstly from diverted LNG and more recently from the Beetaloo gas supply, which has commenced in the last couple of months. There is obviously ongoing uncertainty around the supply-demand balance in the Northern Territory market. On one hand, you've got future volumes from Beetaloo producers are unknown. On the other, you've got the impact of the Federal Gas Reservation proposals remain outstanding. So in that context, the new multi-year gas contracts were very important to Central. We've effectively locked away, or locked in, offtake arrangements for 98% of our expected gas production for next year. It's calendar year 27, with a greater proportion of those new higher-priced contracts. And we've got over 80% of expected gas production for the next three years contracted. That provides a higher level of confidence for cash flows for at least the next three years, regardless of market conditions. and we also expect to participate in several new exploration wells across the three basins over the next 12 months and Leon will go into those in more depth shortly. Now I mentioned our expectations of improving cash flows previously and that's really coming from our producing fields in the Amadis Basin. We're expecting them to generate increasing cash flows from this year and there's a number of key drivers for that. Firstly, we've got the new gas supply contracts and they provide not only certainty of off-take but also improved margins and that's already been demonstrated in the underlying FY26 results. Remember 98% of next year's expected production is already contracted and that's with an increased proportion of higher priced contracts. Secondly, we've got the gas over-lift liability, we've been repaying that back at two terajoules a day since 2020, and it was fully repaid in May this year. So that will release an expected $7 million per year in additional margin and cash flow. And finally, we've got the increased volume from the New Palm Valley Wells. We're targeting the plant capacity of about 14 terajoules a day. At that rate, that would boost Central's production revenues by about 40%. On the slide in the chart, it was illustrated what this might look like on a quarterly run rate basis compared to the previous quarters. You can see that we're looking forward to a very significant uplift. That expected additional cash flow when you combine it with our starting cash reserves and our additional bank facilities gives us some financial strength that we need to cover the expected capital demands from the current and the planned drilling programs over the next 12 months. We've got the first of the two Palm Valley wells. It's taken a bit longer than anticipated. We're currently forecasting the total cost of the drilling program to exceed budget by about 5%. We have the opportunity to claw back some of that overrun on the second well, but in any case we've got sufficient resources to cover the expected total cost. And so once the capital intensive drilling programs are complete, which we would expect by this time next year, we anticipate a very healthy free cash flow that can then be considered for allocation towards, among other things, debt reduction, shareholder returns, etc. So with that, back to you, Leo.

Thanks, Damien. Turning now to our Palm Valley drilling program. As shown on the slide, we are halfway through a two-well program that could restore Palm Valley production to the plant capacity of around 14 terajoules per day. Achieving this target would increase Central's total gas production by around 40%. The first well, Palm Valley 14, has been successfully drilled to a measured depth of 2,942 meters, but encountered a water bearing fracture or fractures close to this depth. Three bridge plugs were then set to isolate these fractures, with the last being set at 2,729 meters. A subsequent short duration test measured gas flow of approximately 3.2 terajoules per day, and indicated initial gas production of around 3 to 4 terajoules per day once tied into the existing network. This indicative result is below expectation and the initial rates achieved from recent Palm Valley wells. However, a short duration rig test is not necessarily a reliable indicator of long-term production performance. At this time, Palm Valley 14's ultimate performance remains uncertain, but we will get a clearer picture once the well is commissioned and producing through the surface facilities. It is worth noting here that the Palm Valley gas production depends almost entirely on intersecting natural fractures, which vary considerably in number, width, and length across the field. Some of the larger fractures, which extend to great depths, may act as a conduit for formation water, which can constrain or prevent gas production at any stage of the well's life. None of these factors can be fully assessed from a short-duration rig-based flow test, which is why we need to wait for results from the steady-state production. By way of comparison, the PV-12 well, completed in July 2022, initially encountered water when drilled, but after setting isolation plugs, the well cleaned up and has now been producing reliably for over four years. Despite the risks and uncertainties, drilling at Palm Valley remains an attractive investment. Existing spare plant capacity means the marginal cost of additional production is low, Importantly for Central, bringing new Palm Valley gas into the Northern Territory market via PV-14 and PV-15 before year-end allowed us to secure a long-term gas sale agreement with the Northern Territory government and that will underpin our forward cash flows through 2034. To put Palm Valley 14 into context, An initial flow rate of 4 terajoules per day, assuming a typical Palm Valley decline rate, would provide a payback on the current forecast well cost in around three years and recover almost half of that cost by the end of next year. With some Palm Valley wells producing for more than 10 years, this well can still deliver attractive economics even at these lower initial production rates. The wall has now been completed and tie-in activities are underway, with commissioning expected before the end of October. Once PV-14 is online, we will have a much clearer view of its production potential. The rig is now moved to PV-15, which we expect to spread over the next few days. Importantly, we do not believe that PV-14 results change the risk profile for PV-15. PV-15 is located approximately three kilometers away and targets the southern flank of the field rather than the northern flank, which was targeted by PV-14. It is also closer to the crest of the structure and further upped it from possible water sources. PV-15 will be only the second well after the successful PV-12 well to directly access the southern flank. We remain confident that a good result from PV-15 would still achieve our target of restoring Pond Valley sales capacity to its plant capacity of approximately 14 terajoules per day. Turning now to our broader growth portfolio, over the past year we have taken deliberate steps to diversify Central beyond our existing Amadeus Basin operations and established positions in two proven Australian petroleum provinces. The onshore Otway Basin in Victoria and the Cooper Basin in South Australia. We hold a 20% interest in PEP169 in the Otway and a 49% interest in PEL677 leases in the Cooper. The attraction of these areas is straightforward. Both basins have a long history of successful petroleum production, extensive technical data, and established infrastructure. This provides us with potentially lower cost exploration opportunities, and in the event of success, shorter and more direct routes to market. We currently have three exploration wells planned across these two basins in 2027. subject to joint approval, obviously. These wells will give central exposure to both gas and oil opportunities, while also providing access to the larger and higher-value southern and east coast markets. It is an important evolution in our portfolio. We retain the cash-generating strength and near-field upside of our northern territory assets, while adding exploration opportunities in established basins where success could materially increase our reserves, diversify our revenue, and create the next phase of growth. We'll now look at each of these new basin positions in more detail. One near-term growth opportunity is the Enterprise North Prospect where a well is planned for 2027, subject to joint venture approval. Enterprise North is located approximately 2.5 kilometers up-dip from and along the interpreted spill path of the producing Enterprise gas field. It is also supported by seismic amplitude anomalies, which provide additional technical support ahead of drilling. The primary target is the Warry C formation, a well-established and highly productive reservoir in this part of the Otway Basin. Nearby discoveries have demonstrated permeability above 1,000 millidarces, with Enterprise One flowing at more than 50 terajoules per day during testing. Just as importantly, the prospect is close to existing pipelines and the Iona, Awai, and Athena gas processing facilities. That infrastructure provides potential routes to the Victorian gas market without a significant capital expenditure, usually required to create entirely new development corridors. Enterprise North is targeting up to 79 billion cubic feet of gas in place, of which approximately 16 billion cubic feet would be attributable to Central's 20% interest. These volumes are prospective and unrisked, and drilling is required to determine whether a recoverable accumulation exists. Nevertheless, success at Enterprise North could roughly double Central's annual equity gas production and provide a material new source of gas close to an important domestic market. Another near-term growth opportunity is the Cooper Basin. Vancouver is one of Australia's most established petroleum provinces with a long history of oil and gas discoveries and an extensive network of pipelines, processing facilities, and oil export infrastructure. Our acreage was relatively under explored during its suspension between 2016 and 2025, but it benefits from extensive existing seismic coverage. Earlier this year, a significant amount of this seismic data was reprocessed and reinterpreted to support re-ranking of these various reservoir targets. The JV has previously identified 17 prospects and leads across the acreage with at least seven considered close to drill ready, subject to completion of this target selection review. The JV is now finalizing plans to drill two exploration wells in 2027, subject to joint venture approval. The initial program is expected to focus on the Birkhead Oil and Catawara gas targets. Both are proven Cooper Basin plays and provide additional diversification in basins and commodities. Existing infrastructure in proximity to our Cooper assets is a significant advantage. In the event of success, oil can potentially be transported using established trucking and export arrangements, while gas may have access to existing pipeline networks. This can reduce the capital and time required to commercialize a discovery. Cooper position therefore complements our assets in the Amadeus Basin. It introduces exposure to potential oil reserves and global liquids markets. while retaining gas upside in the basin with well-established routes to market. It is a disciplined entry into a proven region with multiple follow-up opportunities if the initial wells are successful. Bringing all these activities together, we have a busy program ahead of us. As I covered on Palm Valley, PV-14 time is underway and commissioning expected in the next couple of weeks. PV-15 will follow as a second well in the campaign, and we hope to have it online by the end of the year. Together, the wells are targeting total Palm Valley sales capacity to approximately 14 terajoules per day on a 100% joint venture basis, although actual production will depend on individual well performance and natural field decline. We are currently producing about 5.5 terajoules per day at Palm Valley, So we need initial production of around nine TJs per day in aggregate from PV-14 and PV-15 to achieve that. During 2027 and subject to joint venture approval, we're planning to drill the Enterprise North exploration well in the Otway Basin and two exploration wells in the Cooper Basin. As I mentioned, these provide material, gas, and oil upside with established routes to key markets. Beyond that, the growth program includes the potential drilling of a sub-salt well at Mount Kitty in early 2028, again subject to joint venture approval. This prospect provides potential exposure to helium, hydrogen, and natural gas in the Amadeus Basin. We are continuing to seek farm and partners for Mount Kitty in order to mitigate our cost and risk exposure. Importantly, all of these growth activities are supported by a strong financial base. The repayment of the gas overlift position has released more than $7 million of annual cash flow, while new multi-year contracts provide improved revenue visibility. Central ensures these programs more financially resilient with a diversified exploration portfolio and a potential series of near-term drilling catalysts. That wraps up the formal presentation. So at this point, we're happy to answer any questions that have been submitted online.