Cooper Energy Ltd

ASX:COE

Earnings Call Analysis

Earnings Call Transcript 2025-Q1

[Operator]

Thank you for standing by, and welcome to the Cooper Energy Limited Q1 FY '25 Quarterly Conference Call. [Operator Instructions] There will be a presentation followed by a question-and-answer session. [Operator Instructions]

I would now like to hand the conference over to Ms. Jane Norman, Managing Director and Chief Executive Officer. Please go ahead.

[Jane Norman, executive]

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 '25 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, 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 $65.8 million, or 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 claims has led to significantly higher spot ourselves 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 run times of 6 to 8 weeks between cleans this quarter compared to a typical absorber run time of 2 to 3 weeks during the same period last year, highlighting just how far the operations have come in the last 12 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 market with the East Coast supply projects ideally placed to leverage existing infrastructure and bring gas to market in the shortest possible time frame and with lower emissions compared to alternative gas sources.

Throughout this quarter, we have focused on our 4 business priorities for FY '25, and I will briefly touch on each of these now. Firstly, to production performance. August 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 August 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 was the plant really produced at or near nameplate capacity of 60 terajoules a day.

As part of the Orbost improvement project initiatives, we continue to trial form for the absorber packing material to assess the impact on absorbable performance and plant reliability. The duration of the mechanical silver cleans was also significantly reduced driven by process improvements and avoiding the need for consigned based entry.

In Orbost, the shortest ever of absorber clean was completed in less than 8 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 policy unit in June significantly reduced water compensation and contributed a record publisher run life with the polisher now having run for over 5 months. Our replacement of Polish and Media is expected to occur in the current quarter.

With the support of the Polish unit and other improvement initiatives, Absorber 2 achieved a record of 10 weeks run time between cleans during the quarter. While we continue to undertake initiatives to further improve Orbost performance, we have gained more confident that a new baseline performance has been set, and we will aim to more consistently achieve nameplate production levels at Orbost over the coming quarters.

In the Otway, production at the Athena Gas Plant averaged 10.3 terajoules per day. This was slightly lower than the prior quarter due to natural field decline. The plant continued its recent run of good reliability with 0 reliability loss in the month of July and September.

Our second FY '25 business priority is to progress the cost supply projects. We continue to move forward with the ECS 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 3 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 3 other operators. Cooper Energy is committed to at least 1 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 2 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 '24 provided us with the maximum flexibility regarding the ACS 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 commenced 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 ECSC and project funding, which may include prepayments. The CSP 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 3-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 $9.41 per terajoule, 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 August, 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 2.5x the volume of spot sales in the June quarter. In addition, the reduced number and duration of the absorber clean meant we avoided the need for any spot purchases over the quarter.

Additionally, in Orbost, 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 at our results, we are seeking to build on the $10.5 million in annualized cost savings achieved in FY '24. 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 and the commercial viability of elemental sulfur produced at Orbost.

There will, of course, be some elements of our cost base that remains stable Orbost the 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 silver 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 75 terajoules equivalent per day at the group level and over 62 terajoules per day at Orbost of the quarter. We've set multiple production records in Orbost with the breakthrough in absorber run time, cleaning times and throughput performance.

Revenue has materially stepped up on prior quarters driven by improved production, greater spot sales, increased spot volumes also allowed us to achieve higher average realized gas prices and improved margins. Preparations for the East Coast supply project continue and we look forward to realizing further details on the projects in coming months.

As we look to the remainder of FY '25, 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 '25. We have already made great strides towards this goal.

The business continues to review production rates against our full year guidance of 62 to 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 over the 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 guidance range in the first and the second half of the financial year, and we continue to access our production -- 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 remains compelling and there remains deep value in the business that we will look to capitalize on.

I'd now like to open the line for questions.

[Operator]

[Operator Instructions] Your first question comes from Sam Berridge with Perennial.

[Sam Berridge, analyst]

Jane, I was just wondering, with Orbost bumping up against that sort of the 68% -- sorry, 68 terajoule nameplate regularly now. Generally speaking, with these things are built with a bit of extra capacity available just to make sure they hit name play. Has there been any work done on debottlenecking Orbost now that the sulfur problem seems largely in hand and any sort of scope of what the plant could do?

[Jane Norman, executive]

Thanks, Sam. I'm going to throw to Chad for that.

[Chad Wilson, executive]

Yes. Great question. So we have started working on looking at debottlenecking certainly parts of the plant to get up over that 68 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 idle plant pressure to increase that flow through the pipeline. So yes, we have a project on right now that we'll start to eliminate some of the bottlenecks over the next few months.

[Sam Berridge, analyst]

And so what we see what the outcome of that in sort of a few months' time. Is that adding to the sort of the planned outcome or a little bit longer?

[Chad Wilson, executive]

We'll start to see gradual improvements, hopefully, over the next few months. Anything that would be substantial upticked, call it, from 68 to something like over 70 -- mid-70s, that will obviously include some kind of capital investment. So that will take longer. But the smaller incremental increases we'll be able to implement as we come across them.

[Operator]

The next question comes from Gordon Ramsay with RBC Capital Markets.

[Gordon Ramsay, analyst]

Great result, Jane. It's nice to see that Orbost produced at higher sustained rates. It's a terrific achievement so well done. Just wanted to ask a question about the kind of risk going forward with the Otway program coming up and the comments that you've made that you do will only commit to one firm well if you can't bring in a partner. I 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?

[Jane Norman, executive]

Yes, sure. Thanks, Gordon. So what we've said is that our preferred program remains a 3-well program on a 50% basis with a joint venture partner. And we have said we're not going to do the 3-well program on our own on a 100% basis. We're aware that Mitsui continue to run their sales process to the Otway Basin, and we understand that their engaged in discussions with potential buyers. But ultimately, it is their process. So we're limited in what we can say about that.

And we have 1 slot booked for a firm well and we have a number of options lots 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 full risk position, we will advise the market on which world we're drilling in the number of wells, but we're not going to commit to the full 3-well program on a 100% basis. So we just wanted to clarify that.

We remain convinced that the 3-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.

[Gordon Ramsay, analyst]

Okay. And just on this, you've mentioned 3 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 to bring a gas customer in as a partner on the wells? Is that -- would you have to deal directly with Mitsui? I mean how would that work?

[Jane Norman, executive]

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 -- from the development phase of the project. So the best way to think of the project is in 2 parts where there's a drilling phase and then on successful discovery of gas in Juliet and Isabella along with the Annie discovery, the beer development phase to connect those wells into the existing offshore pipeline. And it's that second phase that would be funded by the prepayment and the drilling phase will be funded by free cash flow and the existing senior debt facility.

[Operator]

[Operator Instructions] Your next question comes from James Bullen with Canaccord.

[James Bullen, analyst]

Congratulations on the results. I just wanted to inquire around how you're going in terms of progress with your banking syndicate on pushing out that 2-year maturity?

[Jane Norman, executive]

Yes. Thanks, James. I'll Chad will answer that.

[Chad Wilson, executive]

James, we -- those conversations are going well. That process is underway. We are working in that process alongside over in parallel with the prepayment as well. And 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.

[James Bullen, analyst]

That's great. And previously, you've talked about having the data room opened as Mitsui with their sales process. Could you provide us with a sense of the interest levels and how many people have been hitting into that data work?

[Jane Norman, executive]

Yes, we've talked about supporting Mitsui 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 2 years now, and we continue to see the same names looking in the data room. So I'll leave it at that.

[Operator]

Your next question comes from Adrian Prendergast with Morgans Financial.

[Adrian Prendergast, analyst]

Congratulations on the good work you guys are doing and today's results. 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 presales or how you'd shape the gas book? Is that evolving or just a bit of an update on that upside?

[Jane Norman, executive]

Yes, sure. Thanks, Adrian. The way the customers are thinking about gas is there's 3 sources that Southern Basin supply from the Otway and gets from basins. There's gas redirected from Queensland and then there's LNG imports. And so those 3 sources of gas are impacting their price expectations. And certainly, as we talk to people about foundation GSA, 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 are supported by the foundation gas price, and then probably hold some smaller volumes back for shorter-term sales of spot sales. But I think it's fair to say that there's a big focus right now from all of our customers on LNG imports spend and the alternative. And so certainly, that's influencing price expectations.

[Operator]

Our next question comes from Mark Wiseman with Macquarie.

[Mark Wiseman, analyst]

Congratulations on the result. Amazing results down there at Orbost. Just a question following on from Mark's question on the gas sales agreements and price expectations. It does seem like there's a lot of customers sitting on their hands on incentive contract. I'm just wondering, have your price expectations or the confidence of securing those foundation GSAs. Has that changed at all over the last 6 to 12 months?

[Jane Norman, executive]

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 prepayments in order to secure the gas. And that shows their level of interest in, one, securing up; and two, supporting this project. But no, we're not seeing a change in behavior over the last 6 months.

[Mark Wiseman, analyst]

And would you expect those foundation contracts to be flip surprised with the CPI escalator? Is that the structure you'd be looking for?

[Jane Norman, executive]

There are a number of options on the table, but certainly, one of them is fixed price with CPI indexation. I think it's going to 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 prices, CPI indexation.

[Mark Wiseman, analyst]

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 31 December? And if so, by how much?

[Jane Norman, executive]

Go ahead, Dan.

[Daniel Patrick Young, executive]

Thanks, Jane. So this was -- we had said that we expected debt to peak in the third quarter of the calendar year. We talked about at the half year. And again, 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 arise 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 sets yes, this is the peak. We have now at the path to the peak position.

[Operator]

There are no further questions at this time. I'll now hand back to Ms. Norman for closing remarks.

[Jane Norman, executive]

Great. Thank you, and thanks for joining the call today. We are obviously very pleased with the improvement in performance at Orbost 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.

So thanks very much for joining today, and we will catch you at the half year.

[Operator]

That does conclude our conference for today. Thank you for participating. You may now disconnect.