Cooper Energy Ltd

ASX:COE

Earnings Call Analysis

Earnings Call Transcript 2024-Q4

[Operator]

Thank you for standing by and welcome to the Cooper Energy Limited Q4 FY 2024 Quarterly Conference Call. [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]

Thank you. 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 Q4 June quarter results for FY '24, and I will start by making some comments on the quarter before opening the call for questions.

Cooper's total group production and revenue again increased quarter-on-quarter. We continue to see encouraging signs from the Orbost improvement project and following the completion of the BMG decommissioning program, the business has refocused on growth via the East Coast supply project.

Total quarterly production averaged 63.9 terajoules equivalent per day, up 1% on the last quarter, largely driven by a rebound in production from Athena following its planned maintenance shutdown in March. Total group production for the year of 62.1 terajoules equivalent per day was 4% higher than FY '23 and in line with our guidance. The annual increase in production was largely due to improved performance at Orbost.

During the June quarter, production from Sole was impacted by pipeline constraints that emerged from late May, which while frustrating, has now been resolved. Away from the pipeline issues, the Orbost improvement project continues to achieve sulfur processing improvements with the time between absorber cleans extending to 4 to 6 weeks over the June and early July.

Performance of the polisher unit has notably improved since insulation was installed around the unit in June. With these improvements and the resolution of the pipeline constraints, we are confident that we will see production increase over the September quarter.

In the Otway production at the Athena Gas Plant was 21% higher than the prior quarter. After the maintenance shutdown in the May quarter, Athena has demonstrated a stable operation with zero reliability loss across both the months of May and June. As we have been saying for some time now, the supply-demand balance in the Southeastern Australian market is very tight. We saw another reminder of this during the quarter, where reduced supply from the Longford Gas Plant coincided with high levels of gas power generation demand.

This contributed to notable increases in the Southeast Australian domestic gas price in June. Victorian spot gas prices peaked at $28 per gigajoule in June and averaged around $13.6 per gigajoule over the quarter. Meanwhile, gas levels at the Iona Underground Storage Facility fell approximately 40% between the 1st of May and the 1st of July. Levels have continued to decline in July even as Longford production has recovered.

On the 19th of June, AEMO issued an East Coast Gas System Risk or Threat Notice, highlighting that the supply of gas in the East Coast gas system may be inadequate to meet demand during the winter peak demand period through to 30th of September. This highlights yet again the need for new gas supply and the importance of Cooper Energy's East Coast supply project, which I will discuss shortly.

We sold 530 terajoules of gas into the spot market over the quarter realizing an average price of $13.54 per gigajoule. While this is a good pricing outcome for us, our focus remains on steadily increasing supply from Orbost and maximizing spot sales particularly during the current peak winter demand period.

Our overall realized gas price across both basins was $9.19 per gigajoule for the quarter, broadly flat on the March quarter, but 6.7% higher compared to the same quarter in FY '23. Sales revenue was $57.3 million, up 2% quarter-on-quarter and up 17% compared to the same quarter last year. Total sales revenue for FY '24 was $219.1 million and was 11% higher than FY '23. Throughout this quarter, we have maintained our focus on our 4 business priorities for FY '24.

Firstly, to Orbost performance. Orbost production was broadly flat for the quarter overall at 4.7 petajoules. As I mentioned earlier, daily plant production rates in late May through March of June were impacted by pipeline constraints caused by a buildup of liquids. These constraints overshadow of many of the sulfur processing improvements achieved through the Orbost improvement project. With pipeline constraints now resolved, we look forward to a more stable and increased production rates during the September quarter. Orbost improvement project initiatives undertaken during the June quarter included the installation of a mist eliminator in absorber one and a new 4-nozzle spray header in absorber two. Trials of absorber packing material were undertaken and are ongoing to assess impacts on absorber performance and overall plant reliability.

Insulation and trace heating were installed around the polishing unit in June. The installation has already notably reduced water condensation within the polisher unit, and we expect trace heating to have further benefits when it is activated during the September quarter.

With the support of the polisher unit and other improvement initiatives, a record absorber run time of 6 weeks between cleans was achieved over June and into early July compared to the previous typical absorber run time of 2 to 3 weeks. Further Orbost initiatives are being progressed to improve the reliability of the plant and maximize production rates.

We expect further institute cleaning trials of the absorbers to take place during the September quarter with the aim of further reducing the time required for cleaning. A decision on the installation of the third absorber remains under evaluation as we progress the remaining improvement initiatives.

Now to the second FY business priority for FY '24, BMG wells decommissioning. As previously announced to the market, we completed the BMG wells decommissioning in May. The work involved more than 360,000 worker hours with no lost time injuries and no significant environmental incidents. The success of the project highlights our commitment to health, safety and environment, and the team's strong engineering capability. The total cost of the BMG wells decommissioning is expected to come in at slightly less than $270 million. Inclusive of the BMG wells spend in FY '24, total capital and abandonment expenditure is on track to be within the guidance range of $240 million to $280 million.

Thirdly, to our cost-out initiative. As discussed at our recent investor briefing, we remain on track to unlock around $10 million of annualized cost savings from the middle of this year. We also remain on track to meet our guidance for FY '24 production expenses of $57 million to $63 million, which we previously revised downwards and narrowed in April from the original guidance of $60 million to $68 million. We are consciously working to ensure these cost savings are sustained structural changes rather than temporary savings and further updates will be provided on this at the full year results in August.

There will be some elements of our cost base that will remain stable, but we expect to see further reductions in some production costs across the business, including from the sulfur plant at Orbost, in aggregate, delivering the potential to unlock further margin expansion.

Going forward, we see the cost-out program forming the basis of an ongoing continuous improvement program that will continue to reduce costs and improve value across the business.

Fourth and finally, we continue to progress planning of the East Coast supply project. This project is designed to bring additional gas supply into the Southeast Australian market from the Otway Basin, utilizing existing offshore and onshore invested infrastructure. Utilizing existing infrastructure minimizes the project's cost, time frame and environmental footprint. Collectively, this means gas from this project will be one of the earliest lowest cost and lowest emission sources of new gas into a market that is structurally short.

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 would be drilled in conjunction with the adjacent Elanora fields.

As we have previously announced, we have 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 and within the consortium agreement with options to drill additional subsea development and/or exploration appraisal wells. Subject to the progress on its current work program, the Equinox rig is expected to arrive in the Otway region in the second half of calendar year 2025 and commencement work on our committed well in late calendar year '25 or early '26. This timing remains subject to a number of variables.

These close supply project development connects into Cooper Energy's existing gas processing infrastructure at Athena, which has approximately 150 terajoules a day of total capacity with first gas targeted for 2028. We expect to fund the project from a range of sources, including organic cash generation and our existing bank debt facilities. We have recently commenced a process to extend the maturity of our bank facilities by 2 years to 2029 and maximize the funding available to us under those facilities.

Additionally, we continue to progress discussions with several potential gas customers regarding offtake and funding arrangements to the project which could include prepayments. We also continue to engage with our joint venture partner, and we'll update the market when the program has been agreed.

So to summarize Q4, we capped off a transformational year for Cooper Energy. We produced over 63 terajoules equivalent per day in the second half of FY '24 and over 51 terajoules per day at Orbost over the same period.

We are seeing positive results from the Orbost improvement project and with the benefits of the trials we have been undertaking and the lessons learned from past issues, we look forward to improved performance in the September quarter. Revenue continues to improve quarter-on-quarter, driven by improved production and spot pricing. Higher and more stable production rates at Orbost will allow us to continue to increase our weighted average realized prices through increased spot volumes.

We have completed the BMG wells decommissioning project, a significant milestone for the company with the team delivering a technically challenging project without incidents. We also remain on track for our cost guidance for the year, delivering more than $10 million in annualized savings through the transformation project. FY '24 was a strong year for Cooper Energy and with our strategy set, we are now focused on delivering in FY '25.

We will continue to focus on production performance across our portfolio. By the end of FY '25, we are targeting average production below 60 terajoules per day from Orbost, resulting in group production of more than 70 terajoules per day equivalent. Our priority will be on maximizing cash generation and paying down debt ahead of investing in our major growth projects. 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 also position us as an operator of choice when looking at bringing in third-party volumes through our facilities. And of course, we will continue to progress the East Coast supply project with the aim of locking in our preferred 3-well drilling program in preparation for the arrival of the rig.

The growth strategy and investment proposition for Cooper Energy remain compelling and there remains deep value within the business that we will capitalize on. We look forward to this journey with you as our shareholders and I'd now like to open the line to questions.

[Operator]

[Operator Instructions] Your first question comes from Nik Burns with Jarden Australia.

[Nik Burns, analyst]

Jane, Dan and Chad, maybe just starting off with a question on Orbost. Jane, in May, at your investor briefing, you outlined a near-term average production target of 58 terajoules a day and 62 terajoules a day by the end of FY '25. Since then, you've obviously had some new challenges in the form of liquids buildup and water condensation, et cetera. A note from the AEMO daily data, you haven't achieved a daily rate of 64 terajoules a day since late May. Just wondering how confident you are right now that you can achieve your 58 terajoules a day target in the near term and what needs to go right from here to achieve this?

[Jane Norman, executive]

Yes. Thanks, Nik. Yes, we haven't got back to that level of around 64, 65 yet because of the resolving the liquids issues with the buildup in the pipeline, but we are on track to do that. And I'll just hand over to Chad to talk about that in a bit more detail.

[Chad Wilson, executive]

Yes. Thanks, Nik. So the plant actually has been running fairly well. The pipeline liquids issues were what was restricting rates. That pipeline has now returned to normal operating pressure. And after that was returned to normal operating pressure, we took the opportunity to change some of our filter elements and things like that. So you should start to see over the next 2 weeks or so of that returning to that higher production level.

[Nik Burns, analyst]

Got it. Okay. And just a liquids in the pipeline that build up there. I mean, has that happened before? What caused it? Can you avoid it from happening again?

[Chad Wilson, executive]

Yes. So as the temperatures decreased, we started to inject more glycol into the pipeline. And once we start to inject the glycol, higher rates of glycol levels, we started to get the liquids back into the plant. We've seen a drop off in the normal liquids into the plant through the last month before that problem happened. So we just increased glycol injection. And since then, we're seeing the normal liquids rate into the plant.

[Nik Burns, analyst]

Got it. Just one more for me. Just on the decision around the third sulfur absorber. It feels like this decision continues to push to the right. I think at one point, you were looking at making a decision in the March quarter. Can you just talk through why that's been deferred? And when do you think you will actually be at a point where you can decide to categorically whether to go ahead with that or not?

[Chad Wilson, executive]

Yes. So contractually, we've been able to maintain all the time lines and deferring the major capital spend. So that's basically where we're at. We haven't needed to make the decision. We're continuing to monitor our improvement plans and our delivery times for the major equipment have been maintained through contractual setups.

[Jane Norman, executive]

Yes. Nik, it gives us a chance to do more in situ cleaning trials, which we're planning to do in the current quarter and to assess the impact of that on the average rate of the plant and then that will inform whether the third absorber will be of benefit or not. But as Chad said, we've been able to maintain the time line for that through contractual arrangements. So it won't impact when it would be installed if we did go ahead with it.

[Operator]

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

[Gordon Ramsay, analyst]

Thank you very much. No solid result. Just a quick question on what used to be the OCP program, which is now called East Coast Supply Project. You talked about potentially drilling 3 or 4 wells with a sidetrack, but then you're saying this is only 1 firm committed well. What's the key issue here? Is it entirely joint venture related in terms of Mitsui's participation? In other words, if they don't participate, are you only going to drill 1 well? Or are there other options where you could potentially drill more than 1 firm well even without Mitsui?

[Jane Norman, executive]

Thanks, Gordon. The sidetrack you mentioned would be part of the 1 well program. So it will be well into Elanora with the sidetrack into Isabella and that would be treated as 1 slot on the rig consortium rather than 2 wells. In terms of whether we drill 1 well or 3 wells, we are very focused on moving this forward as a 3-well program to deliver 90 terajoules a day. And we are working with Mitsui on that in order to progress the project. So that's the optimum project and then to complete the wells on success. So we can come back in the second phase and simply tie them in to achieve first production.

So it's really a program that's focused on 3 things. One is identifying and unlocking the greatest resource numbers so we know we can keep the plant full for years. Secondly, making sure it's the most capital-efficient program in terms of completing the wells to preserve any exploration wells for production. And then thirdly, it's about developing resources that sit within production licenses because that's the fastest time line to market and that supports the 2028 first production date. Rather than trying to convert wells that sit within exploration permits that have a 2-year time line with [ enough time ] to convert them to payout. So that's the project in summary and very focused on moving that forward with the joint venture partner.

[Operator]

Your next question comes from Declan Bonnick with Euroz Hartleys.

[Declan Bonnick, analyst]

Thanks, Jane and the team for the update. I was just wondering on the CapEx number for that subsea tree on the East Coast Supply Project, is that 100% of the cost of the subsea tree or is that split 50% on the joint venture?

[Daniel Patrick Young, executive]

That's the 100% cost number that we are talking about there in terms of the cash flow impact. But yes, as Jane has talked about, the strategy and our approach overall is a 3-well program with a partner.

[Operator]

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

[James Bullen, analyst]

Thanks, Jane, for the update. Just quickly around the in-situ cleaning trials that you're going to be conducting in the September quarter. Is there any risk to production from those trials?

[Chad Wilson, executive]

Thanks. So we've already conducted some trials. This is about how do we do it faster and cheaper. So the trials were, from a technical standpoint, we're incredibly successful. It gave us improved performance. It actually ended up responding just as if we did the mechanical clean and even a little bit better because we were able to get into, I would say, the nooks and crannies of the vessel that you usually don't get with the mechanical clean. So the focus is the go-forward trials is how do we make this routine repeatable process that happens faster and cheaper than the mechanical cleans.

[James Bullen, analyst]

Understood. And just around the liquids buildup in the pipeline, did this occur in previous winters, but because Orbost didn't have the capacity, it didn't really matter?

[Chad Wilson, executive]

That's a great question. Not quite sure. We haven't been running at these higher rates historically. So that could have been it. We might not have just noticed it in the past. But yes, the increase in the glycol injection seemed to have alleviated the problem.

[James Bullen, analyst]

Okay. And just to confirm, so it wasn't hydrates building up at all that's why you had to ramp up the glycol.

[Chad Wilson, executive]

We're not totally positive, but it could have been maybe some slushy fluids, so start of hydrates possibly.

[Operator]

Your next question comes from Nik Burns with Jarden Australia.

[Nik Burns, analyst]

This is just one for Dan. Just on net debt, June 30, I think, it was $250 million. Can you just clarify how much residual cash flow spend was still remaining on the BMG decommissioning project that will come through in FY '25?

[Daniel Patrick Young, executive]

Thanks, Nik. We talked previously at the half year that we anticipated financial indebtedness will probably peak in July, and that's still the case. So there is still a little more cash spend around BMG that will go out at the door this month. We'll have a definitive view in the next 10 days, 2 weeks on the final, final number. As we say in the report today, we expect the wells Phase 1 cost to be a little bit under $270 million, we're very confident that we're going to come inside that number. That does leave us, as you'll be aware, with over $100 million of funding flexibility under the senior debt facility.

So we still have a very strong financial position as we look at some of these long lead items and the like. So there's a little bit more that will come out in July. And I think by the time we report our results in August, we can give you a final, final number on BMG wells, but very confident that it will be inside $270 million.

[Nik Burns, analyst]

Got it. And maybe just one on the East Coast Supply Project. Just looking at through the scope of works and the plan for 3 wells. Just thinking through, we haven't had a cost update for quite some time in terms of what that total cost could look like. But just thinking about the scope of what might be considered, can you talk to the potential for CO2 in the exploration targets? Just noting, I think, Athena has limited CO2 handling capacity. I mean would there be an anticipation that we should see the investment in CO2 handling as part of what you outlined as your forward work program for those 3 wells?

[Jane Norman, executive]

Yes. Thanks, Nik. Yes, if the development were Annie alone, it would require [ aiming ] at the Athena Gas Plant because the Annie field is just above the pipeline spec CO2 levels. We anticipate that Juliet and Isabella will be lower CO2. If we look at the Casino field, CO2 levels, it's very, very low. So we anticipate being able to blend the way that Annie field CO2. And therefore, we wouldn't need [ aiming ] at the plant. And we wouldn't be stripping inventing CO2 at the plant as well. So that's the current focus. But there is an option to install [ aiming ] as part of the plant relifing if we find that there's higher levels of CO2 in those other fields, but we just don't anticipate that.

[Nik Burns, analyst]

Got it. So the previous cost estimate we had for the project or OP3D, as it was called back then, did that include [ aiming ] back then? Or is that excluding [ aiming's ] installations?

[Daniel Patrick Young, executive]

Well, we've never given a definitive kind of cost estimate for the 3-well program that we're looking at here. So we've talked around different approximate ranges, but there's no company guidance number for OP3D in terms of the 3-well program we're looking at here. So yes, I think that's what we can say at this point.

[Jane Norman, executive]

Yes. The best way to think about it, Nik, is really in 2 phases, that there's a drilling phase during possibly late calendar year '25 into '26 which will be 3 wells. One of those wells will include the sidetrack into Isabella. And then there will be an execute phase.

So the wells will be completed with trees on success in order to preserve them for production. And there'll be a second phase, which goes into '27 and start of '28, which is tying it all in with umbilicals and flow lines. And so the CapEx is effectively spread over those calendar years, which supports the project being funded from organic cash flow. And means there's no material upfront commitment to the whole program until we've had success from the exploration wells.

[Operator]

Your next question comes from Henry Meyer with Goldman Sachs.

[Henry Meyer, analyst]

Are you able to share an indicative time line for the Gippsland Basin farm-out process, please?

[Jane Norman, executive]

Henry, yes, look, that's kicking off now. And the plan there is to find a partner who will come in and support us on the exploration of gas in those BMG licensed books. And we know that there's -- we know significant gas is there from the time when the oil was produced and there is already a 2C booking there. So that process is underway.

[Henry Meyer, analyst]

Great. Is there sort of like a time line where you think it might be completed? Or is it just open an expression of interest for now?

[Jane Norman, executive]

Yes, just open at the moment.

[Operator]

Your next question comes from Kieran Barratt with Petra Capital.

[Kieran Barratt, analyst]

Thanks, Jane. Well done on a good result. I noticed the proportion of contracted sales is up quite materially despite increased volumes. Was that just driven by market conditions? And can you just talk to the short-term outlook for that? Should we expect a bit of a reversion back to the main?

[Daniel Patrick Young, executive]

Yes. Thanks, Kieran. So I think we're in the midst of the winter peak period, customers are nominating their maximum quantities and as a result, yes, contracted sales as a proportion of total sales has been higher. Particularly through this period where the pipeline issues we've spoken to, meaning the volumes, ultimate volumes out of Orbost have been impacted, and haven't sold as much into the spot market than would have been the case in the absence of those pipeline constraints.

[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 to everyone for joining us today. We're really pleased with the steady performance in Q4. The FY '24 full year results will be on Tuesday, the 27th of August and at that point, we'll be giving guidance for FY '25 for production, production expenses and capital expenditures. We look forward to seeing many of you in the roadshow that will follow those results. But thanks again for joining today.

[Operator]

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