Thank you for standing by and welcome to the Amplitude Energy Limited Q4 FY25 quarterly report conference call. All participants are in a listen-only mode. There will be a presentation followed by a question and answer session. If you wish to ask a question, you will need to press the star key followed by the number one on your telephone keypad. I would now like to hand the conference over to Ms. Jane Norman, Managing Director and Chief Executive Officer. Please go ahead.
Good morning. This is Jane Norman. I'm joined this morning by our Acting Chief Financial Officer, Eddy Glavas, and our Chief Operating Officer, Chad Wilson. This morning we released our FY25 June quarter report. I will start with a short summary of my take on the quarter before opening the call for questions. Our business has had an exceptional end to FY25 with record productions, spot gas sales, and revenue for the June quarter. For the first time in the plant's history, production from the soil fields into August averaged the nameplate capacity of 68 TJ per day in the month of June. Together with our existing Otway and Cooper Basin productions, the group production produced the equivalent of over 77 TJ per day in June, well above the target we set ourselves 12 months ago, which was for group production to exit FY25 above 70 TJ per day.
For FY25 as a whole, the group produced at 73 TJ equivalent per day, the top end of our guidance range, which was increased twice over FY25. Group production for FY25 was in aggregate 17% higher than FY24. I'm very pleased with the operational performance at August and the collective focus within our engineering and operational teams on improved reliability, efficiency, and continuous improvement. With a new base net line now set, we are confident that production near the nameplate capacity can be maintained and potentially improved. Another highlight for the quarter was our spot sales and trading performance, with a new record of 2 PJ of gas sold into spot markets, or 21 TJ per day on average over the quarter. Roughly a third of the average production from August is now going into the spot market, or a little over one quarter of our average group production.
June was an interesting case study in power markets, highlighting the important role that gas plays in delivering energy security to all Australians. A recent outage at the Yvonne Brown Coal Power Station in Victoria has seen a significant increase in demand for gas power generation in the electricity system to ensure the lights stay on. This, combined with the usual variability of renewable power generation and the seasonal impacts of winter, saw spot gas prices rise and become more volatile throughout the month. Our commercial teams were able to take advantage of the trends emerging in spot markets and the disparity between the markets to maximize sale prices we achieved for our spot gas. Improved gas production drove revenue up to a new quarterly record of $70.7 million, up 12% on the prior quarter.
For the full FY25 year, sales revenue came in at $267.7 million, up 22% on FY24. We continue to build cash and reduce our net debt levels ahead of the East Coast Supply Project, with net debt down to $242.8 million by the end of the quarter. Net debt is now over $35 million below its peak in the first quarter of FY25, despite the investments we have made in long-lead items for the East Coast Supply Project over the last financial year. On a cash basis, we spent around $5 million in the quarter to progress the East Coast Supply Project and a further $19 million on restoration costs, the vast majority of which was for our 10% share of the Minerva decommissioning project, where the program to abandon the wells is now complete.
Our cash generation was also impacted by movements within working capital, which we expect will unwind this quarter. Progress on ECSP continues at pace ahead of our first well at the Eleanor and Isabella fields later this calendar year. We continue to closely manage the project budget and timeline, with long-lead item orders and approvals on track to hit key milestones. We recently commenced front-end engineering design work on the gas processing plant and subsea development phase of the project. Together with our JV partner, OG Energy, we intend to proceed to a final investment decision on the development phase in the first half of calendar year 2026. Throughout the quarter, we remain focused on our four business priorities for FY25, and I will briefly touch on each of these now. Firstly, to production performance.
August production averaged a record of 67.1 TJ per day for the quarter, or 6.1 PJ in total, up 17% from the prior quarter and capping off its great turnaround from prior years. Over the full FY25 financial year, August produced at an average of 62 TJ per day, or 22 PJ in total, a 25% increase on FY24. Modifications to the internal configuration of the absorbers undertaken during the March shutdown, combined with the use of stainless steel packing in the absorber beds, significantly reduced foaming and fouling in the absorber units. The number of absorber unit cleans undertaken during the quarter was reduced to only two, including a trial of a new chemical clean-in-place system. Both absorber units have smashed previous records for runtimes between cleans, with the first absorber unit last cleaned nine weeks ago and the second unit cleaned over 16 weeks ago.
Strong absorber performance and the additional redundancy provided by the H2S scavenger injection have enabled us to defer replacement of the media in the polisher unit, which we will now look to do in the months after winter. With sulfur processing no longer creating a regular constraint on the plant production, we are assessing the potential to increase the plant's instantaneous nameplate capacity above 68 TJ a day through debolting of the plant and inlet pipelines. Internal technical work on this is largely complete, and we are now working through the required regulatory steps. In the Otway, we continue to see good reliability performance from the production at the Athena Gas Plant, which averaged 8.7 tTJ per day for our 50% share, representing 0.8 PJ, or a 5% increase over the prior quarter.
Pleasingly, both plants operated at near 100% reliability over the June quarter and demonstrated reliability loss well below 1% for the whole of FY25. Bear in mind that we set ourselves a target for reliability loss of below 2% by the end of FY26, so it's great to see both plants beating those targets already. Our second FY25 business priority was to progress the East Coast Supply Project. The project maximizes the use of existing offshore and onshore Otway Basin invested infrastructure to bring much-needed new gas supply to the Southeast Australian market in 2028. As we previously announced, the TransOcean Equinox drilling rig arrived in the offshore Otway Basin in April and is expected to commence drilling of our first well in its campaign for Amplitude Energy, being the Eleanor Expiration Well, with a side track to Isabella in late calendar year 2025.
Drilling of the second and third wells in the program, targeting the Juliet Prospect, followed by the Annie Discovery, is expected to take place in the second half of calendar year 2026. This timing remains subject to a number of variables. Detailed planning and engineering for the East Coast Supply Project continued, with multiple contracts awarded during the quarter to progress with the drilling of the three-well program. Site survey work was undertaken at the drilling locations for confirmation of mooring line deployment for rig activities. Key long-lead items, including the subsea trees, are on track to be delivered ahead of our drilling windows. We also received the key approvals required to proceed with the drilling phase of the project.
We understand that OG Energy, our incoming JV partner in the Otway Basin, has made considerable progress with transaction approvals for their Otway sales transaction with Mitsui and now expects to complete the remaining approvals in the current quarter. Planning for the plant modifications and subsea development phase of the East Coast Supply Project is also progressing, with FEED having commenced on this phase of the project and tenders for the subsea tie-in scope to be issued over the coming months. Amplitude Energy and OG Energy intend to proceed to final investment decision to undertake the development phase of the project in the first half of calendar year 2026. In the June quarter, we commenced a marketing campaign with potential gas customers regarding the foundation contracts for the East Coast Supply Project, which include marketing gas on behalf of OG Energy.
Project CapEx is expected to be funded from the existing cash on hand, underlying organic cash generation over 2025- 2028, and the company's existing bank debt facilities. Our third priority is to increase the realized gas price through increased exposure to spot and peaking product opportunities. We realized an average price for spot gas of $11.60 per GJ during the quarter, translating to $10.11 per gigajoule for our average realized gas price overall. This is 10% above our average realized gas price for the same quarter last year. Our average realized gas price for the whole of FY25 was $9.91 a gigajoule, an increase of 12% over FY24. We generated additional margin by optimizing the profile of spot sales during higher gas demand periods. This has been achieved by using pipeline storage to shape spot sales to the highest price markets where possible.
The ability to optimize spot sales has been made possible by August's improved consistent and stable performance. Fourth and finally, we drove further cost and emission reductions through continuous improvements and efficiencies. Our continuous improvement program demonstrates what can be achieved with a collective mindset of thinking differently. We keep identifying opportunities to do things better, reduce costs, and improve output. Building on the success of the FY24 transformation program, this year's program focused on delivering further value and cash flow improvements through cost and emissions reductions, improved productivity, and margin expansion. Over 70 separate initiatives across the business were identified over FY25 and were either completed or remain in delivery as of the 30th of June. In aggregate, the continuous improvement program resulted in improved cash flow of around $20 million in FY25, with the completion of remaining initiatives expected to realize significant benefits into FY26 and beyond.
Like last year, the program outperformed our expectations with buy-in across the organization. Over half of the realized value in FY25 came from new operational improvements at August, primarily associated with the absorber cleaning and polisher treatment improvements. These have driven near-term value through increased sales volume, reduced contracted costs, and reduced consumable costs. The continuous improvement focus will remain in FY26, with a number of mature initiatives nearing value realization, including finding a beneficial use for the sulfur produced from the August gas processing plant. As we have discussed before, we have been working with a local farming cooperative, the Gippsland Agriculture Group. We conducted a trial in 2024 to determine the viability and effectiveness of the plant sulfur when applied to crop soil. Our sulfur was found to exhibit properties identical to other commercially available sulfur products.
After engagement with the Victorian EPA and potential off-takers in the East Gippsland region, we have committed to a six-month pilot sales agreement under which our sulfur is being distributed to farmers as a fertilizer additive. Late last month, our first load of elemental sulfur was delivered as a product to DEVCO Australia, who manufacture a range of sulfur-based products for the agriculture and industrial markets across Australia. In this pilot phase, the sulfur from August will be distributed to local Gippsland farmers, contributing to a new era of sustainable agricultural practices in the region, while at the same time reducing our waste costs and transport emissions. Our strong focus on organizational emissions remains, and the improvements at August mean we are ahead of our target for a 40% flaring reduction by FY2030.
We will have more to say on the continuous improvement program and expenses overall in the August results. To summarize, as we look back on FY25, we can genuinely say that we delivered well ahead of our four business priorities. We produced 77.1 TJ equivalent per day at a group level and 67.1 TJ per day at August over the quarter. We continue to set production records and other operational records at August, with our focus now turning to debolting production and optimizing production costs. Record spot sales volumes into the tight East Coast gas markets drove improved average sales prices and margins. Revenue has materially stepped up, and net debt continues to decline, now over $35 million below its peak in the September quarter of FY25, despite the investments we have made in long-lead items for the East Coast Supply Project over the last financial year.
The East Coast Supply Project remains on track, and we look forward with excitement to the drilling in the first well later this year. Our business has exited FY25 with excellent momentum, and of course, our attention now turns to continuing growth into FY26. The East Coast domestic gas market remains in dire need of new supply sources, and we are proud to play our part in bringing additional gas supply to market as quickly as possible. Our growth project is one of the most significant new domestic gas supply projects in Australia's Southeast, large enough to deliver enough gas to meet the demands of over 60,000 homes. As you may have heard me say in the past, gas produced and consumed in the local Southeastern market is significantly lower cost and multiple times lower emission than supply imported from elsewhere.
Energy has never been more important to our way of life and to Australia's economic prosperity, and it is encouraging to see more favorable public recognition of the important role gas plays in our country's energy future. However, much more needs to be done, and we are hopeful that the gas market review that opened two weeks ago will focus on streamlining market regulation and approval processes to support new domestic gas supply over the long term. On a final note, we are very pleased that Ian Davies will soon be joining the board as Chairman-elect, with John Conde AO having confirmed that he will retire from the board following our annual general meeting this year. Ian will be well known to many of you, and we're excited to have someone of his caliber and experience accept a key role on our board.
We will be looking to finalize our board and executive team renewal process with the appointment of a permanent CFO and the addition of non-executive directors in coming months. Now I'd like to open the line for questions.
Thank you. If you wish to ask a question, please press star one on your telephone and wait for your name to be announced. If you wish to cancel your request, please press star two. If you're on a speaker phone, please pick up the handset to ask your question. Your first question comes from Gordon Ramsay from RBC Capital Markets. Please go ahead.
Hi, Jane. Seeing great results, the strong operational performance, really nice to see that. First question relates to the realized gas price. It fell 1% relative to the previous quarter. We thought it might be higher, especially with really strong spot volumes, record level from the company, and the estimated BWGM average $11.50 over the quarter. With the new short-term contract, is that priced at spot? I'm just trying to figure out reasons why it dropped 1%.
The new short-term contract is consistent with other pricing we've seen this year, in particular with the range that ACCC publishes to the market. It was really the warm weather at the start of the quarter that pushed spot prices down, and we've seen that very strong pricing come through in the month of June with the Yvonne outage pushing up gas-fired power generation demand. We also saw stronger gas prices at the start of this year as retail customers were recharging their positions in Iona as well before the winter. I think on balance, we had probably had a stronger Q3 third quarter in terms of spot pricing and then slightly weaker start to winter with the warm weather, but it certainly ended up with strong pricing at the end of the quarter in June.
Thank you. Next question just on Minerva. The decommissioning well work was completed, but the subsea facility work was not. Can you comment on the future timing and estimated cost to complete the Minerva decommissioning?
Sure. The capping of the three wells is now complete, and Woodside are now making arrangements for a workboat to come back and complete the infrastructure removal. That work is going to be targeted to better weather windows over summer, and they're currently running the process to secure a vessel for that.
Okay. Lastly, just on Patricia Baleen, you're looking at potentially commercializing it. What would that involve, and is there any feel for what production levels that might generate, and is that dependent on expanding the Orbost plant nominal production capacity?
Thank you, Gordon. I'll hand to Eddy on that.
Yeah, we're just looking at the restart of the Patricia Baleen project now and potential future studies for gas storage. For the restart, we're planning to take that project to a select phase, which will involve all of the studies and engineering required, in terms of the outage that can be made available at the plant and the rates that will be flowing. As soon as we get through that select phase, we'll have an idea of rates and outage and things like that, which we'll be able to share at that time.
Okay, thank you.
Thank you. Once again, if you wish to ask a question, please press star one. The next question comes from Nik Burns from Jarden, Australia. Please go ahead.
Yes. Hi, Jane and team again. Congratulations on the record quarter. It feels like the time's getting closer when we don't talk about sulfur issues at Orbost anymore. Just in terms of debolting activities there, I just wanted to confirm, I think you said your analysis would be complete there and you're progressing regulatory approvals. Can you just confirm that? Can you talk about what level of debolting you've been trialing, the timeframe you think will be needed to obtain the necessary approvals, and any investment required to achieve consistently high rates? Thanks.
Yep. Thank you. Yes, we've completed the technical work, and it's now going through the regulatory approvals. I'll hand it to Chad to follow up on the rest.
Yeah. For regulatory approval timelines, that's a great question. Working through the application on that now. They're not very complex applications, but the approval times, we'll work through those as they go. In terms of what level we're talking about, we're incrementing up in a couple of TJs a day steps over time just to see that we can do that in a reliable and safe manner, without impacting the production throughput of the plant.
Got it. Thank you. Just on the East Coast Supply Project, you mentioned in the quarterly you've awarded multiple contracts. Can you just maybe give us an update in terms of how the cost of those contracts compare with your assumptions that underpin your phase one cost estimate range of $240 to $270 million you provided back in March? Thanks.
I think we're over 98% of the contracts have been awarded now. They're all falling within the contract range that we had in that announcement.
Easy. You talked about ticking off gas marketing for the East Coast Supply Project during the quarter. Recently, Jane, I think you had a release talking about you might be in a position to contract an additional 20 PTs of gas from Seoul, depending on what happens there with gas reserves. Can you just give us a bit of an update in terms of engagement with gas buyers? How is the market progressing? You've obviously did a small-scale contract recently, but as we look ahead, you want to lock in some longer-term contracts. I've got this evolving situation with either gas imports or further gas from Queensland. How does that engagement look like? Thanks.
I'll take that one. Nik, yeah. The first part of your question, yes, we have commenced a marketing campaign jointly with OG Energy, and we have dialogue with a number of customers there that has commenced, and that is a mixture of retail and industrial customers as well. We're confident, in terms of the pricing range, that is going to be at market. When it comes online in 2028 or 2029, depending on when we choose to commence those contracts, with the rates that we're getting now from Seoul and OGPP and also the confidence in the reserves, certainly, we're getting increasingly confident with the reserves coverage there. At the right time, we may announce some more contracts for Seoul towards the back end as the contract stacks now really sort of opening up into that better pricing range.
We'll wait and see, in terms of how we go with this next round of East Coast Supply Project as a priority and then follow up with some more Seoul contracts. Certainly, the sentiment from the customers, the demand is there. There is a clear shortfall, particularly from 2028 onwards. It's just about getting the right conversations with the customers in terms of the dynamics that are happening in the market and, as you mentioned as well, with LNG imports. Now, industrials, they look for 24/7 loads, so they won't get their heads around LNG imports. Certainly, it's what we can offer, and suits the industrial customer a lot more, and it's much closer to where they need to go.
That's great. Thanks, Eddy. Appreciate it.
Thank you. Your next question comes from Henry Meyer from Goldman Sachs. Please go ahead.
Morning, all. Just expanding on the potential reserves uplift, could you elaborate on what data you're seeing there that's giving you confidence, and whether we should simply assume that 20 PJ sales uplift opportunity is indicative of the upside or potentially more?
Thanks, Henry. We'll provide more detail in our August results when we release the reserves report. At this stage, it's looking positive in terms of risks doing their assurance work on this. At this stage, it's looking like probably another year equivalent of production will be added to the reserve. It's really just pointing to the reserves being at the higher end of the range that was announced to the market. At the moment, our 2P is around that 2032 level, so potentially pushing it back a year. If we see another year of strong production data for the plant and consistent wellhead pressures, then potentially there's an opportunity to do a crease again in another year's time. As Eddy said, that gap is currently not contracted later in the decade, so it gives us a bit more flexibility to contract the volume towards the end of the decade.
Great. Thanks, Jane. The west is clearly an attractive opportunity to open a scene to third-party tolling as well, subject to your exploration success. Could you share whether any progress has been made there for potential tolling?
Yeah, I'll take that one. Look, we work together in a consortium with drilling with all the parties in that region. You know, the Athena Gas Plant has significant outage, even at the ECSP base case at 90. There's still another potentially 60 TJs a day going through there. We continue to have conversations with all parties that can access that plant to commercialize their gas, without accounting for what it would be for a greenfield construction of a new plant through there. It's incumbent on all of the parties that work in that region to make sure that we're getting their gas evacuated to market in the best way. Certainly, there's many conversations around that happening and certainly open for business to see what can be done most efficiently in the area.
Excellent. Okay. Thank you. Last one, if I can, back on Patricia Baleen and potential storage opportunities. Could you comment perhaps on how you see the relative competitiveness of that as a storage field compared to other options in Victoria, Greenfield or Brownfield?
Yeah, I think it's early days at this stage. You know, it's not necessarily the size of the reservoirs, it's the rate that you can inject and withdraw at. We're looking at various options about linking a product to potential power generation as well. Initially, the first thing that we need to do is to ensure that that production system and the operability of those wells is something that we'd like to get into the market as a priority and then keep studying the storage opportunities. As I said before, once we get through this select phase, we'll have more to say on that. Any Brownfield infrastructure that's already there in place, we've got a good gas plant there with plenty of compression, is always going to be competitive in the scheme of things.
I think that on that side of Victoria as well, through the Latrobe Valley, you've got a lot more capacity to get gas to and from that plant. It's a lot more tighter over in the Etoile Campbell area.
Excellent. Thank you.
Thank you. Once again, if you wish to ask a question, please press star one on your telephone. The next question comes from Uwan Minogue from Barrenjoey . Please go ahead. Hi to you, Uwan. You may have yourself on mute.
Apologies. That's my bad. Morning, guys, and congrats to work again on the result. Just a quick one from me. If we look further down the track, is there any opportunity for further debottling at Orbost beyond the several TJs a day targeted at this stage? If so, what would that look like and what's your current thinking there? Thank you.
Thank you. We're doing that work at the moment to look at how much we can debolt at the plant for sulfur production. In addition to that work, we're doing the work around Patricia Baleen and restart. We've also talked before about doing the work with Seven Group to restart the Longtom field, which produces into that same Patricia Baleen system. They're two separate pieces of work that are clearly connected as they're going through the same plant.
The Patricia Baleen and restart of potentially storage projects and the restart of Longtom would be a larger expansion of the plant, which requires some capital investment. Whereas the work we're doing right now on debolting at sulfur production through the Orbost plant, that's not really requiring CapEx. It's simply around the ability for the plant to operate at that higher throughput and then managing the regulatory changes, which is what we're working on right now.
Right. Thank you.
Thank you. Your next question comes from Declan Bonnick from Euroz Hartleys. Please go ahead.
Yeah. Morning, Jane and team. Congrats on the great operational result again. I was just wondering, Gordon touched on it with the Minerva abandonment spend. He asked for a figure on remaining spend, and you didn't give that, Jane. I guess that's because the rig's still to be contracted. Maybe you could give a split on spend that's been done and what's remaining there. Like on my numbers, it appears maybe half-half. Is that about right?
No, I would say the majority of the spend is the wells decommissioning. That's the most complicated and expensive part of the work. That's now finished. The remaining work around lifting infrastructure, removal of infrastructure, will be considerably lower CapEx.
Okay. If that's the case, it seems like the updated guidance there might have quite a bit of contingency. That sounds good if the redraw is correct there.
We hope so. Yeah.
Excellent. Good to hear. Thanks.
Thank you. There are no further questions at this time. That does conclude our conference for today. Thank you for participating. You may now disconnect.