© 2024 Alpha Spread Limited. All Rights Reserved.
www.alphaspread.com is not operated by a broker, a dealer, or a registered investment adviser. Under no circumstances does any information posted on www.alphaspread.com represent a recommendation to buy or sell a security. The information on this site, and in its related newsletters, is not intended to be, nor does it constitute, investment advice or recommendations. The information on this site is in no way guaranteed for completeness, accuracy or in any other way. In no event shall Alpha Spread Limited be liable to any member, guest or third party for any damages of any kind arising out of the use of any content or other material published or available on www.alphaspread.com, or relating to the use of, or inability to use, www.alphaspread.com or any content, including, without limitation, any investment losses, lost profits, lost opportunity, special, incidental, indirect, consequential or punitive damages. Past performance is a poor indicator of future performance.
You don't have any saved screeners yet
Intrinsic Value is all-important and is the only logical way to evaluate the relative attractiveness of investments and businesses.
Thank you for standing by, and welcome to the Cooper Energy Limited Q1 FY '22 Quarterly Report Conference Call. [Operator Instructions]I would now like to hand the conference over to Derek Piper, Head of Investor Relations. Please go ahead.
Thank you, Sian. Good morning, everyone, and thanks for joining our call this morning. We released our quarterly report for the first quarter of FY '22 this morning. And David Maxwell, our Managing Director, will talk through some of the highlights from the quarter this morning. Also here, with the leadership team, so after David's gone through the highlights, we'll open the lines to Q&A. So David, over to you.
Yes. Excuse me. Thanks, Derek, and welcome to everybody this morning. We had a strong start to the new financial year with record performance and many milestones achieved. And we're getting ready for a very busy period ahead. The key message is this morning, there are 6 of them. Firstly, we achieved record quarterly production, record sales volume and record revenue, and most of this came from improved Orbost performance and higher Sole gas sales. Second, the Athena gas plant is being commissioned, and this will be an important enabler for future growth. Third, APA has commenced the Phase 2b works at Orbost with the new spray nozzles installed and the filtration system is on schedule for installation in the March quarter. Fourth, the quantity of third-party gas purchase declined by just on 1/3 from 33% to 22% of total sales due to higher Orbost processing and the new gas sale agreement that we put -- arrangements that we put in place. Sixth (sic) [ Fifth, ] the company is in a sound financial position, and we welcome Deutsche Bank to the lending syndicate. And sixth, the global energy crisis currently playing out, supports our long-held view that gas will be required for decades to come. What I'll do is I'll just go through each of those 6 messages and to add the support points behind them. So the first, record quarterly performance demonstrates continued incremental improvements. Our quarterly production was up 23% to 0.81 million barrels of oil equivalent, which was a record. Quarterly sales volume was up 6% to 1.03 million barrels of oil equivalent, which was a record. And the quarterly revenue was up 2% to $48 million, which, again, was a record. The average Orbost processing rates of 39 terajoules a day for the quarter compared with 33 terajoules in the prior quarter. The more frequent cleaning of the absorbers during winter improved stability. And then there was a slight extension of the cleaning cycles, and this helped improve the average rates. Gas sales were supported by winter peak demand with Sole sales at the maximum daily quantity of 59 terajoules a day all throughout the quarter. Uninterrupted processing of the Otway gas at the Iona plant resumed following the interruptions that we've had in the prior quarter. Consequently, the average processing rates of 13 terajoules a day compared with 9 terajoules in the prior quarter. And the average gas price remained relatively constant at roughly $7.20 a gigajoule. The second message, the Athena gas plant is being commissioned and we're on schedule to commence gas processing during this quarter. It's a huge credit to the team who have delivered the upgrade on schedule and on budget against the backdrop of the COVID-19 and all the challenges that, that posed. The plant is now operational, and we're just waiting on the pipeline cutover which will occur next month, November. This will redirect gas from Casino Henry and Netherby fields, through to the -- through the Athena plant for processing. Pipeline cutover will mean no production -- when we are undertaking the cutover, there will be no production for up to 4 weeks. And if all goes to plan, we then expect a smooth ramp-up to production over the ensuing 1 to 2 weeks with full production rates during December. We look forward to keeping you updated with the final stages of this important project. Thirdly, the Athena gas plant will be an important enabler for future growth. We hope you've had the opportunity to review the Otway Basin presentation that we released on Monday. The purpose of that presentation was twofold: First, to convey the fixed cost operating structure of Athena, which provides the significant economies of scale as gas throughput increases. And to illustrate, we estimate annual Athena operating costs to be approximately $20 million a year and current upstream field costs about $5 million a year. At initial processing rates, this equates to a total operating cost of approximately $2.30 -- sorry, $2.25 a gigajoule. However, at plant capacity of 150 terajoules a day, operating costs on a per unit basis reduced dramatically to $0.80 a gigajoule. And obviously, it's pretty much pro rata in between. We overlay the current domestic gas price outlook and you can see why we're excited by the future developments in the Otway Basin. Secondly, the reprocessing of the 3D seismic data over our Otway Basin acreage has been completed and initial observations confirm our enthusiasm for the basin. Seismic amplitude support, which is a direct indicator of gas presence, has been confirmed for key prospects. Seismic amplitude-supported prospects are lower risk. And past exploration results have proven this. Since 2002 in the Cooper Energy offshore Otway permits, there have been 8 exploration successes from 8 wells drilled with seismic amplitude support. And more recently, Beach Energy's discoveries at Artisan and Enterprise further add to that validation. We're now interpreting the reprocessed data and are targeting updated prospective resource estimates in the December quarter. Fourth, the Orbost Phase 2 works -- Phase 2b work, sorry, are underway with new nozzles installed in the filtration system on schedule for installation in the March quarter. The installation of the new spray nozzles was undertaken from late September to early October. Processing rates returned to 45 terajoules a day and remained at this level for most of a 2-week period. Furthermore, the absorbers were operating for over 3 weeks without a clean. More testing and tuning is required. And after that, the performance outcomes can be properly assessed. Both absorbers are currently being cleaned this week, hence, the lower rates that you might see if you go online and have a look. The major components of the Phase 2b works, the filtration system, is on schedule for the March quarter. The long lead items are arriving. And preparations for installation are underway. Fifth, the quantity of third-party gas purchase was reduced from 33% to 22% of total gas sales. Since commencement of our Sole gas sales agreements, the purchase of third-party gas from backup supply sources has been an ongoing requirement while Orbost processing rates remain below customer requirements. APA contributes to the cost of these backup arrangements. For the fourth quarter of FY '21, third-party gas purchases accounted for 33% of total sales. That's total sales of 5.7 petajoules. This quarter, the September quarter of FY '22, third-party gas purchases accounted for 22% of a higher total gas sales figure to 6.1 petajoules. The reduction was partly due to higher processing rates at Orbost and partly due to new gas supply arrangements with AGL, which were announced during the quarter. The arrangements with AGL involve a new gas sales agreement for all developed and uncontracted volumes from the Casino Henry and Netherby fields and the Otway Basin and amendments to the existing gas sales agreement. The net effect of these arrangements is a reduction in third-party gas requirements and, in turn, less associated risk of purchases, including pricing and gas availability. Sixth, the gas on the balance sheet, which remains very sound. Record revenue and an unwinding of the working capital build-up from last quarter saw a cash increase and net debt decrease during the quarter. We ended the quarter with cash reserves of $96 million, drawn debt of $211 million and, therefore, net debt of $115 million. This compares with the net debt last quarter of $127 million. Importantly, we have welcomed Deutsche Bank to the lending syndicate. Deutsche Bank took over the ABN AMRO exposure, which follows ABN AMRO's announcement or decision and then announcement back in 2020 for their planned exit from Australia. As you would expect, Deutsche undertook detailed due diligence before entering the syndicate. Their support is further validation of our gas strategy, our gas growth prospects and the risk profile. Seventh, the current global dynamic confirms our view that gas will be required for decades to come. Current events playing out in the global energy sector have highlighted the unintended but not unexpected consequences of rushing the transition to renewable energy sources. In Europe, the phasing out of fossil fuels over recent years and the consequent underinvestment in new supply are underpinning the spike in prices for coal, oil and gas, that the transition to increased renewables is needed and, importantly, must be done in an orderly manner and with continued investment in clean energy transition fuels such as gas. Gas, together with batteries, is the ideal backup supply source for renewables. What we're seeing in global energy markets highlights the value of the twin gas hub located -- of our strategy, which is twin gas hubs located close to the major domestic markets. And what we -- and that we are well positioned for long-term supply of gas into an ever-tightening domestic market. On that note, happy to open the lines and take questions.
[Operator Instructions] Your first question comes from Gordon Ramsay from RBC Capital Markets.
And pleasing to see that production is increasing at Sole. Just a very quick question on guidance. There's no commentary on guidance in the quarterly. I just want to ensure that, that's still maintained at the previous levels for FY '22, please?
Yes, it is within the range. Definitely, we reviewed it and felt that the appropriate guidance was what we had put out earlier. I think the one comment I would make is that to where we land within that guidance range is going to be very dependent on what happens in the second half, particularly at Sole and the success and production levels following the filtration components of the Phase 2b works.
Okay. Just one other quick one for me. Just on -- when you talk about Athena potentially, the capacity of that plant and the lowering of operating costs when you -- when -- have you got any feeling for what the time frame would be to reach that kind of goal to fill the plant to capacity? Because it's a nice figure, but you're never going to get to fill that plant to capacity, it's going to take 10 years. Then it doesn't become quite as meaningful. So I just want to get a feel for what your outlook would be in terms of holding up the plant?
Yes. I think about it in 3 parts: Firstly, our own next round of activity. And as we've said, we're working through at the moment with Mitsui just exactly what makes up what we call Otway Phase 3 Development, or OP3D. That would go a long way to increasing the throughput in the plant. Then this exploration as a part of that campaign, and we have scenarios where -- and so the first phase of OP3D would be looking at production as early as '24, possibly '25, but we'd be aiming for '24. And then within 1 year or 2 of that, you could quite easily see yourself well into the mid-100s for the exploration success. And there's a few prospects out there that -- and we're thinking about it in phases, so around offshore campaign. So there's 2 buckets, the existing OP3D exploration is the next source of bucket. And then the third is the opportunity to process others gas. It's a low-cost facility. Waarre C gas tends to be similar specification. So it's in a position to process third-party gas as well. Sorry, I would add that I think, your 10-year forecast is -- that's long. We'd be well inside 10 years for the 150 terajoules. A more realistic period, I think, would be building over a 5-, 6-, 7-year period.
Your next question comes from Nik Burns from Jarden Australia.
Congratulations, David and team, on a strong quarter. Yes. First of all, just on the Otway Basin, I might just follow up on Gordon's question. Can I just get some clarification. You mentioned production timing, David, of '24 or '25. Can I just confirm, is that FY '24 and FY '25? Or is it calendar year?
Calendar '24. And so yes, calendar '24, calendar '25. Yes. I mean our target, and it's a case of whether you can achieve it or not based on availability of all the bits and pieces that have to be brought together to be online, which I have to say is a super stretch target, would be online for the winter of '24. I think more likely, it would be the back end of '24, early '25.
Okay. And would -- you talk about exploration, would exploration be part of the first phase, if you like, when you're drilling Henry-3 and Henry-2? Would you -- is your plan to include exploration drilling then? Or would the plan be to come back and drill further wells?
Yes. That's something that we're working through at the moment. What we do want to do is to include exploration in that first wave. Those big economies in terms of the number of wells from the campaign, rigs don't turn up there too often, and you want to make the most of them when you can. So certainly, our aspiration is to have 2 or 3 exploration wells in the Otway as a part of the OP3D campaign. The question then becomes in what order do you drill them. And secondly, the exploration wells, the Waarre C wells, do you drill them as keepers? Or do you drill them as pure exploration wells? The work on that's going on at the moment. If you drill them as keepers, then the lead time to get them in production is significantly, significantly reduced. You're getting it down to -- from discovery, you're getting it down to 1 to 2 years. Hence, my answer to the question from earlier from Gordon that, I think you can see quite rapid buildup if your drilling campaign is structured around -- I'm going to say around success. We never design things around success. But given the hit rate and given the high probability of success, it's a relatively low-risk approach to be drilling the exploration wells as keepers.
Got it. And just in terms of the 3D seismic, your free process. It sounds like you're pretty excited by the results. Just wondering what status, where you are up to in your discussions with your JV partner, Mitsui? Have you been through that with them? Are they fully on board? Just trying to get a sense of alignment between yourselves and them? Obviously, it's key to have your 50-50 JV partner on board here for at least a quarter of your plans going forward?
I think I may say 1 or 2 things and I'll pass across to Andrew Thomas. I think Mitsui is probably a bit more excited about the exploration than they are about the production, which is probably the one thing I would say. And they're very keen, particularly on a couple of the prospects to see us test those prospects. But Andrew, why don't you...?
Well, with regards to alignment, I think I can say that we're all aligned on drilling Elanora. And Mitsui, can you do it sooner rather than later. But -- so Elanora is one that everybody agrees will be drilled as part of the upcoming campaign. There are other possibilities that we've had in the books for a while. There are a few prospects that are effectively the same as the Annie discovery. And we're considering where they go into a campaign and how they go into a campaign, as David just mentioned regarding keeper wells and timing. And then to the south of the Elanora area, based on the new seismic, which is actually a significant upgrade on the previous data, we had there some really interesting prospectivity that we're working through now. And we're yet to have that conversation with our partner about those other things, but they would, in all likelihood, form the basis of a wave after the next plant.
Yes, we will be -- our plan is obviously sharing in the technical committee meetings with Mitsui. And we're planning an Investor Day late November, early December. And the Investor Day will be using the opportunity then also to share more detail on the prospectivity in the offshore and the things that are of particular interest and why we're excited. And that -- at that point, we will have obviously had the conversations with Mitsui as well.
That's great. Just one final one on the finance side. Just so you had repaid $7 million debt in the last quarter. Is there any principal repayment scheduled for this quarter?
Same. We've got $7 million quarter for the next -- for the first 3 quarters of this year. And then there's a slightly bigger payment in the fourth quarter, which I think is [ $39 million. ]
Your next question comes from James Bullen from CG.
Just a quick question around Black Watch. Are you planning on drilling on your side of the permit there? Or have things progressed with discussions with Beach?
We don't think we need to drill on our side of the permit, James. In our view, the gas is there. Have things progressed with Beach? No, they haven't. But it's not a conversation that has to be had today. It's a conversation that I think will be had over the next year or so.
Okay. And just around what should we be thinking about in terms of abandonment spend for this financial year? Obviously, you are approaching FID around BMG abandonment. But what do you think the spend is going to be like this year?
The focus this year is on the planning for the BMG abandonment. I'm going to ask David to give you a bit of a steer on that. But it is the plan in getting ready for FID. So there's no final project commitments at this point, but the planning expenditure in the order. David?
James, it's in the order of $8 million to $9 million.
[Operator Instructions] Your next question comes from Jon Bishop from Euroz Hartleys.
David and team, very good quarterly. Just a perennial favorite of mine. Have you had any further progress with the combination certificate discussions with the Federal Energy Minister?
We haven't had any progress with the Minister himself, but there has been quite a lot of progress done internally and together with our tax advisers on developing the case to then put to the energy minister and us developing our strategy around the timing of that and what goes with it. And I mean, it wouldn't be a surprise that the thinking on that goes very much to linking Manta, Manta Deep. And you will have seen that we reported in the quarterly about the prospectivity in and around Gummy, which is [ bound ] to get people a little bit excited as well. So we would see ourselves sitting in a conversation with government and with the government advisers over the next 3, 6 months, putting the pieces in place and linking the combination certificate there to the next round of activity in the Gippsland.
Okay. And just around that, to cast the mine forward, in the event that you do ultimately develop the Manta gas reserves or something around Gummy there or any number of some third-party volumes, which I think are drilled discovered, but currently marginal, what plant capacity is there at Orbost beyond the buy-side reactors to increase throughput? Are you able to run sort of a dual upstream feed and increase output from the plant? Or is that the bottleneck there, regardless?
Yes. There is the opportunity to process other gas through the plant. We don't have to -- we don't -- it's not just Sole, but it does require some expenditure. And it depends, obviously, on the volume and the components of the other stream that's going through. We had done the conceptual work for Manta. Obviously, Manta Deep would require investment in the plant. And Mike Jacobsen's online. And Mike, maybe you could give a little bit more detail about what would be involved at Orbost? I wonder if Mike's still on mute?
Pardon me. This is the operator. Mike has disconnected.
That wasn't planned. Sorry about that. Look, I'll explain. The smaller volumes can be processed with relatively little capital increments in the plant. Larger volumes and something, obviously, of the size of -- even of Manta, which has got significant early volumes being in the first 3 or 4 years, there would be additional capital required in the plant. And the preliminary planning work for that had been done a year or so back by APA. So it's a function, Jon, really, of the source of the gas, the volume of the gas and the components of the gas.
Okay. Maybe another way I could ask it, therefore, if you're prepared to comment, is given the current configuration, what would be the additional bandwidth of the plant? Is it another 15 terajoules a day? Are you able to give a sort of an order of magnitude?
Yes. No. Well, previously, Patricia Baleen, I think, was producing at 90 terajoules -- yes, in the order of 90 terajoules a day. So Patricia Baleen quality gas, which is similar to the long-term quality gas, can handle -- very little capital can handle up to 90. Manta goes well above that. By the time you put Manta together with Sole, goes well above that. So you've got quite a bit more capital. Separately, Manta has in the order of 3 million barrels of liquids. And it's the liquids handling that is probably where the money is going to go. And one of the issues to be worked through is just how you then move the condensate, in this case, to the refinery. So that's where the work is. It's in the liquids handling and then mobilizing the liquids to its point of sale.
Okay. So one final question. Have you had any approaches from third parties in regards to utilizing your infrastructure, therefore?
Well, that's a Dorothy Dixer. Isn't it? Yes, we had.
It's not, because you didn't ask me to ask you that.
It's not a Dorothy Dix. But know that, yes, we have. And those conversations are protected by a confidentiality agreement.
Yes. Okay. I expected as much, but I thought I at least ask.
Yes. I mean I can't say, no.
There are no further questions at this time. I'll now hand back to Mr. Maxwell for closing remarks.
Well, thanks very much, everybody, for joining this morning. And as you can see, it was a solid performance. And look, it's worthwhile just making a few comments about where we've come from over the last 18 months, as we've said, and we'll be talking more about it at the Annual General Meeting coming up. Have been challenging. We feel like we're coming out of that challenging period, and we are engaged with APA about long-term certainty for Sole through Orbost. And this is all occurring at a time when the Eastern Australia gas market is tight, getting tighter, and gas prices are reflecting that. And the level of interest that we're seeing from gas customers and wanting to contract additional gas in both the Gippsland and the Otway is significant. But we'll have more of that -- more to say about that in the Investor Day, which is coming up in a couple of months. So on that note, thank you very much.
That does conclude our conference for today. Thank you for participating. You may now disconnect.