Central Petroleum Limited (CTP) Earnings Call Transcript

Good morning, and thanks for joining us today. I'm Leon Devaney, Central Petroleum's CEO and Managing Director. I'm also joined by our CFO, Damien Galvan. 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 2016 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. [Operator Instructions] 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 FY 2027 and beyond. So look, strategically and commercially, there were some pretty significant achievements. We were successful in securing those new multiyear gas sale agreements, which were the catalyst for the FID for the 2 new Par Valley wells, which we're currently drilling, 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, higher risk exploration permits in the Omalley's Basin and expanded our footprint into 2 of the Australia's proven onshore basins. So it'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 decline. Despite those lower volumes, our revenue top line increased 3% to $44.7 million. That was supported by higher portfolio pricing driven by new supply contracts, including the new GSA with the Northern Territory government, which started in January. So as a result, average realized prices in FY '26 increased 10% to $10.10 per gigajoule equivalent and the average gas price increased by 3% to $10.38 per 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 FY '26. And that's an increase of 36% over 2 years. And while our gross -- 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 for the year. And the largest item of those was related to the exit from the 2 Amati space and exploration permits. So we recognized a one-off noncash impairment loss of $5.9 million as we wrote off the legacy costs associated with those permits. We also recognized $5.7 million of exploration and appraisal costs. Most of that is cost for the preparation and long lead items for those 2 new Palm Valley appraisal wells, the first of which we've now subsequently drilled. And while normally development wells would be booked as a capital cost, these are classified as appraisal wells since 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 nonrecurring business development cost of about $900,000. That was driven by rebalancing of our exploration portfolio. We also made some adjustments to the way we allocate staff cost 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 updated our allocation methodology for future periods, so that we don't have adjustments like that in the future. Off the back of those solid underlying results for FY '26 and the cash reserves on hand, we're now set to fund a period of high impact activity. We've got our capital prioritized to increased investment in appraisal and exploration, and it's underwritten by our improving free cash flows. I mentioned the new gas contracts earlier 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 market has been closed now for an extended period. And Central has been supplying about 50% of the Northern Territories gas demand, with the balance being supplied firstly from diverted LNG and more recently, from the Beluga supply, which has commenced in the last couple of months. But there is obviously ongoing uncertainty around the supply-demand balance in the Northern Territory market. On 1 hand, we've got future volumes from Beluga 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 multiyear 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 and 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 3 years contracted. As that provides a high level of confidence of cash flows for at least the next 3 years, regardless of market conditions. And we also expect to participate in several new exploration wells across the 3 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 Amati space, and 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 offtake but also improved margins. And that's already been demonstrated in the underlying FY '26 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 overlift liability. We've been repaying that back at 2 terajoules a day since 2020, and it was fully repaid in May this year. And 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. So we're targeting the plant capacity of about 14 terajoules a day. And at that rate, that would boost Central's production revenues by about 40%. On the slide in the chart, we've illustrated what this might look like on a quarterly run rate basis compared to the previous quarters. And you can see that we're looking forward to a very significant uplift. So that expected additional cash flow when you combine it with our starting cash reserves and our additional bank facilities, gives us some -- the 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 got the first of the 2 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 call 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, et cetera. So with that, back to you, Leo.

Thanks, Damian. Turning now to our Palm Valley drilling program. As shown on the slide, we are halfway through a 2-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. The 3-bridge plugs were then set to slate 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 clear 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 within 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 a steady-state production. By way of comparison, the PV 12 well, completed in July 2022, initially encountered water when drilled. But after setting isolation plug, well cleaned up and has now been producing reliability for over 4 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, in 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 3 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. Well 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 clear view of its production potential. The rig has now moved to PV-15, which we expect to spud over the next few days. Importantly, we do not believe that PV14 results change the risk profile for PV-15. PV-15 is located approximately 3 kilometers away and targets the Southern Flank of field rather than the Northern Flank, which was targeted by PV 14. It is also closer to the crest of the structure, and further up dip 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 but still achieve our target of restoring Palm 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 2 proven Australian petroleum provinces. The onshore Otway Basin in Victoria and the Cooper Basin in South Australia. We hold a 20% interest in PEP 169 in the Otway and a 49% interest in PEL 677 and 24 associated retention 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 3 exploration wells planned across these 2 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's important evolution in our portfolio. We retain the cash-generating strength in 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. I'll now look at each of these new basin positions in more detail. One near-term growth opportunity is the Enterprise North prospect, where 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 Worry Sea formation, a well-established and highly productive reservoir in this part of the Otway Basin. Nearby discoveries have demonstrated permeability above 1,000 millidarcies 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, Otway 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. Copper is 1 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 underexplored 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 7 considered close to drill ready, subject to completion of this target selection review. The JV is now finalizing plans to drill 2 exploration wells in 2027, subject to joint venture approval. The initial program is expected to focus on the Birkhead oil and Patchawarra gas targets, both our proven Cooper Basin plays and provide additional diversification in basins and commodities. The 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 the discovery. The 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 tie in 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 9 TJs per day in aggregate from PV 14 and PV-15 to achieve that. During 2027 and subject to joint venture approval, we are planning to drill the Enterprise North exploration well in the Otway Basin and 2 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 Mt 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-in 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 multiyear contracts provide improved revenue visibility. Central enters 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 are happy to answer any questions that have been submitted online Thanks.

Thanks, Leon. We do have some questions coming through. So we might get started on those. So first of all, this is the 1 we probably get fairly regularly, when will be [ we be ] paid?

That's a good question. A lot of people are interested in that, obviously. We're currently going through a significant phase over the next 12 months of intensive activity, obviously, with Palm Valley wells and the exploration wells in the Cooper and Otway. The expectation is, once we're through that capital spending phase around mid-next year, we should then be in a really good position to assess where we're at and be able to things like debt reduction and shareholder returns. So really, for the next 12 months, I think we're going to be focused on delivering what we have on our plate. But it is our intent and 1 of the things that the company is specifically focused on is maximizing cash flow, conserving cost during this period so that when we come out of this capital, spending phase. We're in a very good position to return cash flows and cash reserves back to shareholders either through debt reduction or dividend.

Okay. Now obviously, in with the share price has sort of been a bit depressed a little ones. There's a couple of questions on that vein, I might try and combine those together. So here's 1 here that says, over the last 5 years, ASX Oil and Gas index has moved up 31%. During that same period, Central shareholders have seen their investments down by 60%. How does that sort of relate to the incentives that receive and there was a second 1 on a similar vein.

Yes. It's obviously something we follow. It's been a very difficult period for the sector and our peer group, in particular. I would highlight that over the past 5 years, we have really been focused on improving the business, improving the fundamentals of the business and setting it up for future success. We've done a lot of things that are under the surface, the hard work. Some of those were reducing the liabilities and paying those off. We've put in place some very significant important new gas contracts that will be coming more and more visible as we -- clear they've started to become visible and Damian did talk to those. We've certainly high-graded our exploration portfolio. We're looking to consolidate and save cost there, but also give us a better chance for lower cost [ on the high end] And as I said before, we're very focused and have been for some time on maximizing those cash flows of this capital base over the next 12 months. Best positioned to be able to start looking at those return to shareholders. Ultimately, we need to deliver what's on our plate. And that is the Palm Valley drilling program. We're in the middle of that. It is a challenging program. We need to finish up the second half with Palm Valley 15 and get a good result there, which we're looking forward to. But we also have the planned exploration in the Cooper and Otway which we're looking to deliver. And again, those are going to be important opportunities and catalysts for share price growth with the company. Beyond that, I think we're going to start seeing the visibility of that hard work we've done over the past 5 years come to light. And I think as the market sees financial strength of the business and the ability of this business to produce operating free cash flow, I think at that point, there'll be further recognition of the potential for the company to certainly start returning value to shareholders or returning capital to shareholders through dividends. And again, debt reduction and acceleration of the debt reduction is something that is on our plate as well. That's probably the best sort of summary I can give on the status of the debt.

Another corporate type question. So will management or the Board look to buy shares on market and support the company rather than just filling their pockets, while shareholders suffer poor returns for the 20 years to date.

Yes. I think both the Board and management have a program in place to ensure that we have significant exposure into the equity of the business, and we do that through our long and short-term incentive plans. Those are recalibrated every year. So there is certainly that exposure in incentive. That adjusts with the share price and to put that into some perspective, the current ones we have best at share prices between $0.12 and $0.16. So significantly higher than the current share price, and that provides, obviously, not only the incentive, but certainly the alignment between management and shareholder expectations. So I think that is there. Management and the Board have in the past, bought on market. So it's not a new thing. But I would highlight that for a majority of the time, we typically are not able to buy or sell shares in Central because we have inside information. We're working on material activities that could impact the share price and therefore, were locked down under ASX restrictions from transacting. But again, it's something that certainly could be possible and has been done in the past.

Okay. All right. So turning to the current drilling program at Palm Valley. This question might have come in before you got to it in your presentation, but I'll read out anyway. So please update on the 2 wells, 14 and 15, and issues with the water and the amount of wells that you're looking forward in '26 to '28 you're expecting to do.

Yes. So I obviously covered that. Hopefully, in enough detail during the presentation, Palm Valley 14 did hit water at the end of the lateral. We have spent a bit of time plugging that back and isolating that water, and we hope that is the case. Obviously, we don't know both the performance and the, I guess, the effectiveness of those plugs until we bring that well online on a steady state, and we expect to have that situation and having those wells producing into the facility over the next couple of weeks. So we'll know a lot more at that point than we do at this point. But that's been a difficult well. I think we've given it the best shot to be the best producer we can, but the jury is still out on that, and we look forward to seeing where that goes, and we're optimistic we can get ultimately a good result from the flow rates from 14. The rig has now moved to 15. We think that has the opportunity to be a very strong well. It is targeting the same side of the flank that PV 12 has, which was very successful, and it is further up dipping on the crest away from water relative to PV 14. So there's some things that we think are encouraging that we believe could give it a much better outcome. But again, is a field that's got a lot of uncertainty, very difficult to predict. The outcomes. The wells can be very productive, very lucrative, very economic, so it's worth the investment, worth the risk. But again, we're just starting in on that well and all things going to plan. Hopefully, we'll come out with very strong result, and we do hit our target of 14 TJs per day out of the Palm Valley facility. Besides that, we've got the exploration wells that we're looking at with our joint venture partner, AZ, they are the operator, and we obviously feed in and work with them on that program. We're having -- we're working towards having the enterprise North well and 2 wells in the Cooper completed around midyear, if not sooner, and we're certainly focused on ensuring that we get the best outcome from that and also keep a lid on costs. Costs have obviously been an issue across the board for everyone operating in this economy, in particular particularly drilling, particularly in the NT, for exploration companies that are performing these sort of tasks. But I think that's tracking well, and we're very hopeful for a solid positive outcome from those exploration activities.

Okay. So there's a question here, to Leon, just are on if Palm Valley 15 and 14 combined don't provide 9 terajoules a day, will you need to drill another well to fulfill the Palm Valley contract?

No. We've got -- we've structured that contract to be very flexible, both in terms of the volume that we can commit to that GSA. So we're able to put the wells online, we're able to get a good track record of production over time from those wells before we commit to longer-term production on a firm basis. And again, that is in tranches. So as we see more information, we have an opportunity to readjust those so that they fit the production profile. But further to that, we also have the ability to make up any shortfalls or gaps in the commitments we have under the GSA with the Northern Territory government. We can make that up from production that we do have out of Marine, if necessary.

Okay. So another question is around those well the Palm Valley wells. How much of Central's capital will be spent on the Palm Valley wells?