Thank you for standing by, and welcome to the Cooper Energy Limited Q1 FY twenty-five quarterly 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, Managing Director and Chief Executive Officer of Cooper Energy, and I'm joined this morning by our Chief Financial Officer, Dan Young, and our Chief Operating Officer, Chad Wilson. This morning, we released our September FY twenty-five quarterly report, and I will start by highlighting some of my reflections on the quarter before opening the call for questions. We are very pleased to see the hard work of the team at Orbost showing through in the production numbers this quarter. The production uplift at Orbost was due to a lot in large part, the initiatives implemented over the last 12 months, which, when combined with better reliability and the resolution of the pipeline restrictions, has started to be reflected in much higher production rates.
Total quarterly production averaged 74.5 terajoules equivalent per day, a new company record, up 17% on the last quarter on a daily average basis, and driven by the improved production at Orbost. Sales revenue for the quarter was AUD 65.8 million, also a company record, and up 15% quarter on quarter or 30% compared to the same quarter last year. Over recent months, it seems like every week brought another set of new Orbost production records. Higher production rates, together with fewer and faster absorber cleans, has led to significantly higher spot gas sales and eliminated the need for spot purchases over the quarter. This allowed us to maximize our realized gas prices, reduce our costs, and grow our margins.
At Orbost, we achieved absorber runtimes of six to eight weeks between cleans this quarter, compared to a typical absorber runtime of two to three weeks during the same period last year, highlighting just how far the operations have come in the last twelve months. We continue to undertake Orbost Improvement Project initiatives as we seek to learn from the lessons of the past and embed the recent successes into our daily operations. With the Orbost operations now having proven it can hit and sustain nameplate production for several weeks at a time, it is great to see the team's mindset shifting to target nameplate capacity on a consistent basis. Beyond our operational successes, we continue to progress the East Coast Supply Project with the order of long lead items and ongoing discussions with potential customers.
Our major customers, regulators, and policymakers have highlighted the need for new, local and affordable gas supply into the southern Australian markets, with the East Coast Supply Project ideally placed to leverage existing infrastructure and bring gas to market in the shortest possible timeframe and with lower emissions compared to alternative gas sources. Throughout this quarter, we have focused on our four business priorities for FY 25, and I will briefly touch on each of these now. Firstly, production performance. Orbost production averaged 62.3 terajoules a day for the quarter, 22% higher on an average daily basis than the prior quarter or 5.7 petajoules in total. Multiple production records were achieved over the quarter, including the highest-ever monthly average of 66.2 terajoules a day in September.
As of a few days ago, the average 90-day rate was 63.8 terajoules a day, a new record for the plant. As I mentioned earlier, one of the overhangs of the pipeline constraint from the June quarter was cleared by mid-July, and the numerous sulfur processing improvements that have been implemented at Orbost over the past year have begun to show through. Orbost production rates of above 66 terajoules a day were achieved on over half the days during the quarter, while the plant regularly produced at or near nameplate capacity of 68 terajoules a day. As part of the Orbost Improvement Project initiatives, we continue to trial forms of absorber packing material to assess the impacts on absorber performance and plant reliability. The duration of the mechanical absorber cleans was also significantly reduced, driven by process improvements and avoiding the need for confined space entry.
In Orbust, the shortest-ever absorber clean was completed in less than eight hours, compared to the previous average duration of around 31 hours, and with peak gas rates restored in less than 24 hours, compared to the previous average of around 48 hours. Combined with the improved plant production when operating at a single absorber mode, faster cleans have allowed Orbost to operate at higher daily rates, even during absorber cleans. Heat tracing and insulation installed around the polisher unit in June significantly reduced water condensation and contributed a record polisher run life, with the polisher now having run for over five months. A replacement of polisher media is expected to occur in the current quarter. With the support of the polisher unit and other improvement initiatives, Absorber Two achieved a record of 10 weeks runtime between cleans during the quarter.
While we continue to undertake initiatives to further improve Orbost's performance, we are growing more confident that a new baseline performance has been set, and we will aim to more consistently achieve nameplate production levels at Orbost over coming quarters. In the Otway, production at the Athena gas plant averaged 10.3 terajoules a day. This was slightly lower than the prior quarter due to natural field decline. The plant continued its recent run of good reliability, with zero reliability loss in the months of July and September. Our second FY twenty-five business priority is to progress the East Coast Supply Project. We continue to move forward with the ECSP, a project which maximizes the use of existing offshore and onshore Otway Basin invested infrastructure, to bring much-needed new gas supply to the southeast of Australia.
Our intention is to develop three fields as part of the project, including the existing Annie discovery, the highly prospective Juliet Field, which sits under the existing CHN pipeline, and the large Isabella prospect, which will be drilled in conjunction with the adjacent Elanora Field. As we have previously announced, we've secured the Transocean Equinox rig as part of a consortium agreement with three other operators. Cooper Energy is committed to at least one firm well within the consortium agreement, with the option to drill additional subsea development and/or exploration appraisal wells. During the quarter, we made long lead orders for two further subsea trees, completion equipment, and tubulars in anticipation of the East Coast Supply Project development phase. These orders, in addition to the first subsea tree order in Q4 FY 2024, provided us with the maximum flexibility regarding the ECSP program.
Subject to the progress on its current work program, the Equinox rig is expected to arrive in the Otway region in the middle of calendar year 2025 and commence work on our committed well in late calendar year 2025. This timing remains subject to a number of variables. The company continues to engage with several gas customers regarding foundation gas contracts for the ECSP and project funding, which may include prepayments. The ECSP is expected to be funded from a range of sources, including organic cash generation, customer prepayments, and the existing secured bank debt facility. We also continued to engage with our joint venture partner, and we'll update the market when the program has been agreed. To manage project risk and funding, Cooper Energy does not intend to pursue a three-well East Coast Supply Project program without a partner.
Our third priority is to increase realized gas prices through increased exposure to spot peaking product opportunities. Our overall realized gas sales price across both basins was AUD 9.41 per gigajoule, up for the quarter by 2% on the June quarter and 13% higher than the September quarter of 2023. These increases were driven by a greater volume of spot gas from Orbost, thanks to the production improvements I mentioned earlier. We sold 1.4 petajoules of gas from Orbost into the spot market over the quarter, more than two and a half times the volume of spot sales in the June quarter. In addition, the reduced number and duration of absorber cleans meant we avoided the need for any spot purchases over the quarter.
Additionally, in August, we began supplying as available gas to the Bairnsdale Power Station under our agreement with Alinta Energy. While the volumes of gas supplied to date are small, we supplied 29 terajoules of gas over the quarter. The Bairnsdale agreement represents the first step in providing customers with solutions as the shape of gas demand evolves and power generation is increasingly called upon to firm up renewable generation in the energy transition. The Bairnsdale agreement allows us to increase our margins by accessing prices at a premium to spot while minimizing transport costs, and we continue to explore similar agreements. Fourth, and finally, we continue to drive further cost and emissions reductions through continuous improvement and efficiency. As discussed in our results, we are seeking to build on the AUD 10.5 million in annualized cost savings achieved in FY 2024.
Our intent is to leverage last year's transformation program to drive a mindset of continuous improvement, to keep identifying opportunities to do things better, reduce costs, and improve productivity. We will also be giving more attention to improving energy efficiency and reducing waste and emissions at our plants. This will not only maximize our sales gas volumes, but position us as an operator of choice when looking at bringing in third-party volumes through our facilities. Our identified opportunities include the ongoing Orbost sulfur trial, which will seek to convert a costly waste disposal stream into a source of potential revenue, as well as contributing to the local economy. We recently signed an MOU with Devco Australia, a major manufacturer of sulfur-based products for the agricultural and industrial markets across Australia. This was to investigate the commercial viability of elemental sulfur produced at Orbost.
There will, of course, be some elements of our cost base that remain stable or possibly increased due to inflation or higher production rates. However, we expect to see further reductions in some production costs, including savings from fewer and faster absorber cleans at Orbost. This has the potential to unlock further margin expansion. So to summarize, Q1 was a great start to the new financial year for Cooper Energy. We produced almost seventy-five terajoules equivalent per day at the group level and over sixty-two terajoules per day at Orbost over the quarter. We set multiple production records at Orbost, with the breakthrough in absorber runtime, cleaning time, and throughput performance... Revenue has materially stepped up on prior quarters, driven by improved production, greater spot sales, increased both spot volumes also allowed us to achieve higher average realized gas prices and improved margins.
Preparation for the East Coast Supply Project continues, and we look forward to realizing further details on the project in coming months. As we look to the remainder of FY 2025, we will continue to focus on production performance across our portfolio. In the capital markets day in early June, I mentioned that we are targeting an average group exit rate of more than 70 terajoules equivalent per day by the end of FY 2025. We have already made great strides towards this goal. The business continues to review production rates against our full year guidance of 62-69 terajoules equivalent per day. Our year on year-to-date average rate means we are tracking slightly above the top end of this guidance.
However, we are mindful we have a full Orbost plant shutdown in the March shoulder period, and while I'm pleased with the progress to date on tackling plant reliability issues outside of the plant sulfur phase, the plant has historically shown production volatility. We would ordinarily expect to tighten our production guide and guidance range in the second half of the financial year, and we continue to assess our production rates against guidance in the interim. At our full year results in August, we spoke about our debt levels peaking in the September quarter due to the final deferred acquisition payment to APA in July and the final BMG well decommissioning payments. With these payments now having been made, and with the increased production and spot sales, we look forward to maximizing cash generation and paying down our debt.
The growth strategy and investment proposition for Cooper Energy remain compelling, and there remains deep value in the business that we will look to capitalize on. I'd like now 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 speakerphone, please pick up the handset to ask your question. Your first question comes from Sam Burridge with Perennial. Please go ahead.
Good day, Jane. I was just wondering, with Orbost, you know, bumping up against that sort of the 68%, or sorry, 68 terajoule nameplate regularly now, generally speaking, when these things are built, you know, they're built with a bit of extra capacity available just to make sure they hit nameplate. Has there been any work done on de-bottlenecking Orbost now that the sulfur problem seems largely in hand and any sort of scope of what the plant could do?
Thanks, Sam. I'm gonna throw to Chad for that.
Yeah. Hi, Sam. Yeah, no, great, great question. So we have started working on looking at de-bottlenecking in certain parts of the plant to get up over that sixty-eight terajoules a day average. The first bottleneck, obviously, is the pipeline, and we're just working through what are the elements that we can do to lower inlet plant pressure to increase that flow through the pipeline. So yeah, we have a project on right now that will start to eliminate some of those bottlenecks over the next few months.
Good stuff. And so, what we'd see, what the outcome of that in sort of a few months' time, is that as in the sort of planned outcome or a little bit longer?
We'll start to see gradual improvements, hopefully, over the next few months. Anything that would be substantial uptick, call it from sixty-eight to something like over seventy, mid-seventies, that'll obviously include some kind of capital investment, so that'll take longer. But the smaller incremental increases, we'll be able to implement as we come across them.
All right. Thanks very much, guys. That's it for me.
Your next question comes from Gordon Ramsay with RBC Capital Markets. Please go ahead.
Thank you very much. Great result, Jane. It's nice to see that Orbost, you know, produce at higher sustained rates. It's a terrific achievement, so well done. Just wanted to ask a question about the kind of risks going forward with the Otway program coming up and the comments that you've made that you will only commit to one firm well if you can't bring in a partner. I'd just like a little bit more detail on kind of where that stands, because clearly that's really up to Mitsui at the end of the day, in terms of whether they sell their asset or come into the party. Can you just give us a little bit of an update, further update in terms of where that sits at the moment?
Yeah, sure. Thanks, Gordon. So, what we've said is that our preferred program remains a three-well program on a 50% basis with a joint venture partner. We have said we're not going to do the three-well program on our own on a 100% basis. We're aware that Mitsui continue to run their sales process for the Otway Basin, and we understand that they're engaged in discussions with potential buyers, but ultimately it is their process, so we're limited in what we can say about that. We have one slot booked for a firm well, and we have a number of option slots that can be called over the next 18 months. So we have flexibility in terms of the program and the number of wells we drill.
So if we end up in a sole risk position, we will advise the market on which wells we're drilling and the number of wells, but we're not gonna commit to the full three-well program on a 100% basis. So we're just wanting to clarify that. We remain convinced that the three well program is the best outcome for the market, given how short the market is, and it would be a missed opportunity to be doing a smaller program on a 100% basis. So we are actively working with Mitsui to try and find a new partner to come into this.
Okay. And just on this, you've mentioned three sources of funding: obviously, cash that you generate, customer prepayments, and then potentially the existing debt facilities. Just on the customer prepayments, is it possible, you know, to bring a gas customer in as a partner on the wells? Is that-- would they have to deal directly with Mitsui? I mean, how would, how would that work?
We're very open to that, if someone did want to come into the asset as our partner. But I think, as you would know, there are very big restrictions on what utilities can invest in these days, and typically they want to be off-takers from a gas supply contract. In terms of the prepayment itself, that would be access to fund the development phase of the project. So the best way to think of the project is in two parts, where there's a drilling phase, and then on successful discovery of gas in Juliet and Isabella, along with the Annie discovery, there'd be a development phase to connect those wells into the existing offshore pipeline.
It's that second phase that would be funded by the prepayment, and the drilling phase will be funded by free cashflow and the existing senior debt facility.
Got it. Thank you very much. That's excellent.
Thank you.
Once again, if you wish to ask a question, please press star one on your telephone and wait for your name to be announced. The next question comes from James Bullen with Canaccord. Please go ahead.
Thank you, and congratulations on the results, guys. I just wanted to inquire around how you're going in terms of progress with your banking syndicate on pushing out that two-year maturity.
Yep. Thanks, James. I'll throw to Dan for that.
Yeah. Hi, James. Those conversations are going well. That process is underway. We are working that process alongside or in parallel with the prepayment as well, and you know, both those work streams are progressing well, and we'll have further updates, I would expect, around the time of our AGM, and in the lead up to Christmas.
That's great. Thank you. And, previously you've talked about, having the data room open to assist Mitsui with their sales process. Could you provide us with a sense of the interest levels and how many people have been heading into that data room?
Yes, we've talked about supporting Mitsui's process. Because they didn't participate in the front-end engineering design, we've provided access to that sort of information around the growth project. Look, I think it's fair to say there's been significant interest in this asset. There's been a number of parties who have been looking at this for over two years now, and we continue to see the same, the same names looking in the data room, so I'll leave it at that.
Okay. Thank you very much.
Your next question comes from Adrian Prendergast with Morgans Financial. Please go ahead.
Thanks, Jane, and congratulations on the good work you guys are doing. And today's result. Just a question on just gas markets, generally, and the behavior of customers and how you're seeing that change. Obviously, everyone can see the next few years and some of the southern markets especially look pretty tough. And so does that drive your strategy around pre-sales or how you'd shape the gas book? Is that evolving or just a bit of an update on that upside?
Yeah, sure. Thanks, Adrian. The way that customers are thinking about gas is there's three sources. There's southern basin supply from the Otway and Gippsland Basins, there's gas redirected from Queensland, and then there's LNG imports, and so those three sources of gas are impacting their price expectations, and certainly, as we talk to people about Foundation GSAs, they are thinking about this gas priced against alternatives in the market, so our strategy would be to contract probably around 70% of the gas in order to know that the project economics is supported by the foundation gas price, and then probably hold some smaller volumes back for shorter-term sales or spot sales.
I think it's fair to say that there's a big focus right now from all of our customers on LNG imports being the alternative, and so certainly that's influencing price expectations.
Fantastic. Thanks, Jane.
Our next question comes from Mark Wiseman with Macquarie. Please go ahead.
Oh, g'day, Jane and team. Congratulations on the result. Amazing results down there at Orbost. Just a question following on from Morgan's question on the gas sales agreements and price expectations. It does seem like there's a lot of customers sitting on their hands, not necessarily incentivized to contract. I'm just wondering, you know, have your price expectations or, you know, the confidence of securing those foundation GSAs, has that changed at all over the last six to twelve months?
Thanks, Mark. No, we're not seeing that in the discussions we're having with customers around foundation contracts. We're talking to a number of customers, including some larger customers, who are prepared to fund the project through prepayments in order to secure the gas, and that shows their level of interest in one, securing gas, and two, supporting this project, but no, we're not seeing a change in behavior over the last six months.
Would you expect those foundation contracts to be fixed price with a CPI escalator? Is that the structure you'd be looking for?
There are a number of options on the table, but certainly one of them is fixed price with CPI indexation. I think it's gonna be interesting to see how LNG imports at either an oil slope or JKM start influencing price expectations, and pricing for contracts. But right now, the focus is on fixed price with CPI indexation.
Okay, great. And perhaps just finally, can I just ask on the balance sheet, the net debt position there, of $279 million at the end of September, is that the peak net debt level? Would you expect that to be coming down by thirty-one December? And if so, by how much?
Yeah, sure.
Thanks, Jane. So yeah, yeah, this was the... We had said that we expected debt to peak in the third quarter of the calendar year. We talked about that at the half year and again, at the capital markets day and the full year results. The business will continue to delever on an underlying basis. I think over the course of this financial year, you should see that net debt number come down, but of course, the timing on the East Coast Supply Project, when rig arrives, and activity around that will also be a partial offset to that. So what I would say is that you should expect some deleveraging over the course of the financial year, and certainly, yeah, this is the peak.
We're now past the peak debt position.
Fantastic. Thank you.
There are no further questions at this time. I'll now hand back to Ms. Norman for closing remarks.
Great. Thank you, and thanks for joining the call today. We are obviously very pleased with the improvement in performance at August, and very focused on sustaining that improvement and continuing to even improve off the levels we have achieved, and Chad touched on some of those focus areas. We're continuing to move forward on the East Coast Supply Project, and we see this as a very attractive and economic project in today's market and in a very short market that gas is definitely needed. And really pleased with the overall performance in terms of cost out and focus on transformation that we're continuing to drive through the business. Thanks very much for joining today, and we will catch you at the half year.
That does conclude our conference for today. Thank you for participating. You may now disconnect.