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Thank you for standing by, and welcome to the Cooper Energy Limited Q2 FY '21 Quarterly Report Conference Call. [Operator Instructions] I would now like to hand the conference over to Mr. David Maxwell, Managing Director. Please go ahead.
Thank you very much, and good morning. Thank you to everybody that is joining us live this morning. And then those that I expect will join us later on the recorded version. This is the Cooper Energy Second Quarter Financial Year '21 Conference Call. I'm David Maxwell, the Managing Director, and I'm joined by the leadership team with Cooper Energy. Before we get underway, I just want to mention 2 new members of the Cooper Energy team. Firstly, Ashley Haren, who's joined as General Manager of People and Remuneration. Ashley has got extensive HR experience locally and abroad and across a range of industries, including oil and gas. And secondly, Derek Piper, who's joined as Head of Investor Relations. Replacing Don Murchland. Derek will be known to many of you. Also, today, in the place of Mike Jacobsen, who is on leave, we've got [ Dean Johnson ], our operations manager. So welcome to both Ashley and Derek to the team and also to [ Dean ]. This morning, I'm going to talk through the results and the progress from the quarter and also a bit of an update for January to date. I'm going to provide an update on the works at the Orbost Gas Processing plant, a few comments on the Southeast Australia gas market and then we'll open the lines for Q&A. So firstly, some key messages from the results and the performance in January today. First, the trajectory of our gas production rates is up and continues to improve. We're making good progress at the Orbost plant despite what I refer to as some commissioning challenges in January. Second, APA and Cooper Energy are working together on the immediate goal to determine the stable level of production at the Orbost plant. And there's clear encouragement in this respect. I note this morning, we're at 34 terajoules a day with absorber one down for its clean. And the rates are expected to steadily increase beyond the rates that we've seen in January. Third, in December and January, we started the long-term gas sales agreements, which underpinned the Sole project. We've met all the customers' nominations with supply from the Orbost plant and backup arrangements we have in place. And importantly, the margin, which is the gas price less operating costs/tariff, was at or above the margin we would have received had all the gas been processed through Orbost. And then also, it's important to reiterate that we remain focused, very focused on achieving the rate of 68 terajoules a day at Orbost. This has always been our objective, and we remain confident that we're going to get there. A quick summary of the results for the quarter. It was a solid quarter with several highlights demonstrating the continuing maturity and growth of our gas business. These highlights include record half year production, this was up 76% to 1.2 million barrels of oil equivalent, achieved on the back of increased Sole production. This trend is set to continue over the second half of FY '21. Production for the December quarter was down 28% compared to the previous quarter to 0.5 million barrels. This was due to the Orbost plant being off-line for 26 days for the absorber configuration works. Sales revenue was higher despite lower production in this quarter. Sales revenue was up 3% to $24.6 million due to higher oil and gas prices. The Sole gas sales agreements commenced. This was a great outcome following continued refinement of our arrangements with APA through the transition agreement, which we announced on the 20th of August and then an update on the 30th of October. We're now delivering into the contracts of close to 20 petajoules of gas in 2021. This is equivalent to 54 terajoules a day on an annual average. This will materially add to the second half revenue. The benefits of the transition agreement we negotiated with APA are evident. With the Sole gas sales agreements commenced, we're now earning a full margin on these gas sales even when the Orbost production is below our customer nominations. This is thanks to our transition agreement, which provides Cooper Energy with compensation from APA under such circumstances. As I noted at the start, we have serviced all customer nominations in January, and we expect this to continue. There's a strong financial position with ongoing support from our lenders. What we mean by this, we're in a strong financial position with $115 million in cash reserves at quarter end. Our lenders take comfort from the long-term gas sales agreements we have in place and have commenced, and that the Sole's reserves and reservoir performance have been proven. And then the Athena gas plant works have commenced. The project is now over 40% complete, and we're on track to deliver first gas from Casino Henry through the plant in the first quarter of FY '22. That's the September quarter of 2021. At Orbost, the works undertaken by APA allow the absorbers to now be operated either in parallel, individually or in series. This gives greater operational flexibility and allows production to continue when an absorber comes off-line for cleaning. I'll now make some specific comments on the Orbost gas plant. The production performance at Orbost is now showing encouraging signs, but it is still well short of what we want and our target. Those of you watching the daily production from Orbost, and I know there's many of you, will have seen variability in rates since production commenced in early December 2020. This has been due to ongoing testing and commissioning of the reconfigured absorbers and has included tuning of new flow control valves and electrical instrumentation; the testing of absorber operations in each of the 3 modes I mentioned, parallel, series and independent; addressing some commissioning and start-up issues encountered during the reconfiguration process; and the cleaning of each absorber, which is currently underway. APA is continuing absorber testing and commissioning with expected production at sustainable rates of 45 terajoules a day imminent. We remain absolutely focused on achieving stable production from the plant and increasing production to the 68 terajoules a day for practical completion. In parallel, we continue to focus on determining the root cause of foaming in new absorbers and the sulfur buildup. This has proven to be a complex issue. The technical experts are progressing the analysis and systematically rolling out causes of the foaming. We are confident that in time, the root cause will be identified. Now a few comments on the Southeast Australia gas market. In the December quarter, the average spot gas price in Victoria increased by approximately $1 a gigajoule over the previous quarter. This was an increase to $5.48 a gigajoule for the December quarter. The spot gas price in Victoria yesterday was $5.60 a gigajoule, and in Sydney, $6.79 a gigajoule. In the same time period, the average monthly LNG netback price, this is the LNG netback price at Wallumbilla, ranged from $4.71 a gigajoule in October to $7.61 a gigajoule in December and then much higher in January. And to these numbers, then needs to be added the cost of transport to get the gas to Sydney, Melbourne, Adelaide. Interestingly, and not surprisingly, we saw the direction of gas flow reverse over this period. During the June and September quarters, Queensland coals and gas flowed South to the Southeast Australia market. In the December quarter, the gas flow was from Southeast Australia to Queensland. With total gas supply in Southeast Australia in decline, the fundamentals of gas from Southeast Australia for Southeast Australia gas customers are strong. I should also note that on the 20th of October, we announced Cooper Energy will be carbon-neutral in 2020. That's financial year 2020 and also financial year -- sorry, calendar year 2020 and financial year 2021. And a commitment to this on an ongoing basis. This covers our Scope 1 and Scope 2 and controllable Scope 3 emissions. This is a first for an Australian gas producer, and it includes tangible other benefits for the local communities in which we operate. So a few comments on the outlook. We have a number of reasons to look forward to the second half of FY '21. We're now selling into the long-term gas sales agreements at prices above the spot gas prices. And we're being compensated by APA for the backup gas purchases, which may be required during this Orbost commissioning phase. We have confidence in the increasing rate of production at Orbost and establishing a stable rate very soon. The prices we receive for our gas sales agreements have increased as we sell -- as we sell almost all the gas now under long-term gas sales agreements. Lastly, we continue to progress our other gas growth projects such as the Athena gas plant and the Otway Phase 3 Development project. We'll have more to say on our results, outlook and guidance at our half year results in February. So on that note, I'll ask the lines to be open, and we'll take questions. Thank you.
[Operator Instructions] Your first question comes from James Bullen with CGS.
I guess I was just looking for more color on why you are confident that you can get up to the 68 terajoules a day. I guess it's difficult for us to see based on the AEMO data that's coming through. Is that because you have some form of agreement that you will be adding absorption capacity here?
I'll make a few comments, and then I'm going to ask [ Dean Johnson ] to add his view to that as well. Firstly, what we're seeing is progressive improvement in the plant performance with time. And this is the operators and APA get to understand the plant and [ changing ] of the plant, performance is increasing. And this is partly little debottleneck projects, and it's partly just skill learning capability, getting to know the plant and what it can and can't do. Second is the root cause analysis. We're not going to let that bone go until we find the answer. And once we find the answer, then it's going to be a lot easier to what is the cause. It's going to be a lot easier to address that. There are a range of options that we have in front of us to increase capacity. You mentioned one there, the third absorber, which is on the surface a logical option. There's a range of other things as well, and some of them are being trialed at the moment. And all of this just so it's really, I would say, the work streams are 2 in parallel. One is looking at debottlenecking and what we can do to increase the capacity, not knowing the cause; and the second work stream is understanding the cause. The progress on both and then looking separately at other plants with the same technology and what they've encountered gives us confidence that we'll get to that 68. The question that people then ask is when. And I guess that's a little bit harder to answer, but the steady progress, and I have to say, significant improvement in the last few weeks gives us confidence that, that's sooner rather than later. But [ Dean ], you're a lot closer to the actual plant than I am. Any comments that you'd add to that?
I suppose one thing that does give us some confidence is each absorber individually has shown capability above 34 terajoules a day. So having both of them online and the ability to actually make sure they stay in a clean and stable state does give us some degree of confidence that, that is possible. So in terms of a hydraulic and pure process engineering problem and with the items that David mentioned in terms of finding the root cause and alternative options going forward, there is a foreseeable pathway to get there.
Great. You say clean, but you're having to now shut them down every 6 weeks for clean out. I'm just trying to reconcile that in my head.
But you -- when you say you're trying to reconcile in your head...
Say, you can do 34 terajoules a day in a clean and stable fashion, but then you're having to shut them down very regularly to remove sulfur.
Yes. Yes. Yes. And what we expect -- what we have seen and what we expect is the frequency of those cleans would be extended over time. So as you're better operating the plant and understanding it, that period gets pushed out.
Okay. And just, I guess, BMG, it doesn't get much of a mention nowadays in the quarterlies. Progress on those -- on that development?
Are you referring to BMG there?
Yes. Basker, Manta, yes.
Basker, Manta, Manta. Yes. Don't -- this is very much a quarterly report about the activities in the last quarter. And as I said, we're going to have a bit more to say around our future plans in the half year. Maybe a few comments here. There is work underway at the moment planning for the next round of development, which is a combination of development drilling to support the OP3D project, which has increased production out of Henry and the development of the Annie field through the Athena gas plant. And then separately, just how many exploration wells we should be drilling in the Otway and 1 or 2 wells in the Gippsland. Manta, which I think is what you're referring to there, there's the existing Manta field in Manta Deep, where the timing for the program, which would include that body of work, the earliest we were thinking would be late '22, but more likely '23. So a consolidated program possibly starting as early as late '22, but more likely early '23 across development appraisal and exploration wells. And that the Manta well, which would be a part of that, [ we plan to ] include as a part of that program is the key next step for Manta. In parallel with that, the development options for Manta are under review.
Your next question comes from Mark Wiseman with Macquarie.
I've got a few questions. Firstly, I just wanted to ask regarding the third-party gas purchases. The difference between your gas production and sales, I think, was about 0.3 petajoules. And in one of the footnotes, you said you've purchased 56 TJs. I'm just wondering, was that 56 TJs a day for a period of time? Or was it 56 TJs...
No. No. That's 56 TJs in total over the quarter. And we started, just a little bit of background on that, Mark, we started the gas sales agreements with Visy on the 1st of December. That's Visy glass and Visy paper. And then we started the gas sales agreements with AGL, Alinta and EnergyAustralia on the 1st of January. So you don't see any purchases to support the utility gas sales agreements in this quarterly, obviously. So that was 56 terajoules a day. And that was in part, as the Orbost gas plant was off-line, was a part of the reconfiguration and came back on, I think it was the 8th of December, 8th and 9th of December. So we did need to purchase some backup gas in that period. There was a little bit of purchase since the 8th of December when the Orbost plant was interrupted on the odd day. And then separately, we have built up a little bit of an inventory of gas, which we store on the Eastern Gas Pipeline.
Okay. Interesting. So the line pack must be 200 terajoules or something, over 200 TJs. Would that be the right way to read it, the difference between the 0.3 and the 56 TJs?
I'm not sure I understand your question.
Mark, we'll take that off-line.
Yes.
Okay. Okay. All right.
Off-line [indiscernible] that.
Okay. And the average gas price obviously increased significantly this quarter, and I presume that says the contracts have kicked in, which is great. I'm just wondering, is that sort of an indicative price that we should consider? Or will that continue to rise as you enjoy a full quarter of contract sales?
A full quarter of contract sales in January, we'll see -- I mean, I'm not going to predict prices on a day, spot prices on a day, but the gas sales -- the average gas sales agreement price increases. And what I mean by that is the average term gas sales price increases. And the reason for that is because we're selling more under our term gas sales agreements than we are in the spot market. So -- and we're getting the full benefit of those gas sales agreement prices. As to where that lands as the average price for the March quarter will depend on how much surplus gas we have on a day that we might then put into the spot market and what spot prices might be. But if you just took the prices under our gas sales agreements and average them, what you've seen to December, this is a pointer. I wouldn't give it -- I could -- I wouldn't be any more definitive at this point than that. Does that answer the question, Mark?
Yes. Yes. I mean it's as helpful as, I think, you can be within the constraints of what you can say. So that great. And just in terms of the transition agreement with APA seems like it's been quite reasonable for both parties in terms of sharing the burden. I'm just wondering if the plant just doesn't get to 68 terajoules a day and 40 to 45 is sort of the long-term production rate, I'm just wondering, I mean, who -- is there some sort of compensation beyond this transition period that could be sought from APA? Or is there any framework that we can sort of think about that?
Well, firstly, the transition agreement has the opportunity to extend through to May 22. That runs to May of this year, and then we've got the option to extend at 12 month. So in that sense, that's a 17-month period from the start of the year. The agreement is quite clear. The agreement that we have with APA is quite clear, that practical completion is achieved when we get to 68 terajoules a day. There is -- we have capped out liquidated damages. So anything that we were to do would have to be a separate negotiation between ourselves and APA. APA is committed to providing us with 68 terajoules a day processing capacity under the agreements for our Sole gas through the Orbost gas plant. And when they get there, we're committed to paying them the tariff for the gas processed for our Sole gas processed. So outside of that, there is no what if we don't get the agreement that you referred to. That's something that we and APA would have to sit down and work out. But I mean I -- your comment at the start, I think, is right. It is the transition agreement and the amendments to it are good agreements, in my view, for both APA and Cooper Energy. And the parties have come together and that the plant hasn't started in the time frame that we all expected. We had to negotiate something separate to accommodate the period. Most important in this for us was keeping the customers whole and satisfied. APA totally understood that and supported us in starting the gas sales agreements in the way they have. So I think you can take from that the spirit of the arrangements between APA and ourselves just to work together to get this thing to 68 terajoules a day.
[Operator Instructions] Your next question comes from James Redfern with Bank of America.
Thank you, but all my questions has been answered, is really around the Orbost gas processing plant and just when we're going to get to 45 and 68 TJs a day. But you've already answered that.
Your next question comes from Saul Kavonic with Crédit Suisse.
I apologize also. You've answered most of my questions. But I just -- I think this was asked before, but I missed it. I just wanted to confirm the 45 TJ a day stable production that's been targeted, is that pre or post the shutdown for cleaning?
That is post the shutdown for cleaning and the clean -- the shut -- the first -- sorry, let me start again. That is post the cleanup of the 2 absorbers. Absorber 2 has already been cleaned up and is back in operation. And absorber one is being cleaned up at the moment, and we expect that to be back online in the next couple of days. So when we use the word imminent, post the commencement, post the restart of absorber 1, we're expecting to see 45 terajoules a day, subject to the nominations that we get from customers, obviously. And we have seen customer nominations a little bit lower through January. And indications are that, that will increase in February, but subject to customer nominations and expect to be looking at 45 in February.
All right. So just to clarify. So in the report, you talk about an average of 3 days of cleaning for every 6 weeks. So I'm just thinking, if we look on it, therefore, on an average 6-week period, is it 45 TJs a day over that 6 weeks? Or do we need to take off the 3 days of cleaning off that, so it's actually going to be closer to 42 TJs a day, on average, once you factor in the periodic cleaning requirement?
No. Our expectation is that it's -- that 45 is the average. I mean, we're seeing at the moment with the [ open absorber ] 30 -- typically 34, and that's what it's running at, at the moment. So on a day rates higher than 45, depending on nominations, but averaged, when I take -- when [ we use so it's ] sustainable, that's effectively averaged.
Your next question comes from Jon Bishop with Euroz Hartleys.
David, just around the ramp-up commissioning and practical completion. Are you able to comment as to where things stand with the banking syndicate? Obviously, 68 terajoules a day would have formed a practical completion test historically. You're talking about getting the plant to 45 sustainably for now and, obviously, taking it higher later. Are you able to give some context as to where the banks are going to be comfortable? And at what point you're able to talk around any changes to amortization profiles, et cetera?
Yes. I'll make a couple of comments and then pass over to Virginia. What the banks -- and as I said in my introductory comments, what the banks really look at is the security in the reserves and the cash flows. So clearly, a profile that might average 45 and then increase over time to 68 is different to a profile -- and 68 is the maximum, is different to a profile that has got a maximum one a day of 68 now. But the reserves and the GSAs where their security sits and the ability to then process the gas to get the confidence in the cash flow stream is the important piece. The banks have been very supportive. They are kept up-to-date on a regular basis. What do I mean by regular? It's almost some fortnightly communications. And the refinancing, restructuring of the existing facility is the subject of current discussions with the banks. At that point, I'm going to pass across to Virginia, who can -- who's leading this together with our advisers.
Yes. Thanks, David. I think you've pretty much summarized it quite well that we're talking security around the [indiscernible]. I think the other sort of really important thing to consider that banks are looking at is stability. So your question around 45, are they going to be satisfied, I think stability lends itself to actually sort of being able to put that profile forward that see the future pathway, particularly that the reserves are still there, and it's a matter of time. So stability over -- that we'll see post this absorber one coming back online is critical to the [ position ].
I think one of the other things to sort of comment on here is whilst the Sole project is the cornerstone of the finance facility, we do also have Casino Henry, the Athena Gas project. And the banks are also looking at what's coming in behind that, OP3D and Manta. And so it is, I have to say, the banks, like the customers, have seen the longer-term picture here. And much like the position we have with APA. It's people sitting down and working out what's best for both parties over the longer term because the fundamentals of the longer term haven't changed.
Okay. So roughly speaking, though, in terms of -- I mean there was a -- is a test period of 90 days, and then it was sort of roughly 45, they would be comfortable. Are you sitting with the syndicate in March post this current works and testing and saying, well, okay, we've delivered 45, it looks pretty stable? Is that the sort of the current indicative time frame to bed things down with them?
So I think, Jon, as David indicated, we're in fortnightly conversations with lenders via the technical bank in any ad hoc calls that I take. And certainly, they're watching and they're looking at what's going on at the gas plant at the moment. We also have information undertaking that exist under the facility that require an independent expert to provide technical reports through the lenders on a regular basis. But all of that happens on a regular basis. And yes, it will be happening within this quarter.
The March time frame is a reasonable forecast at this point.
Okay. And then just finally to round out on Manta. I think the question was sort of asked. The work on the combination certificate, are you able to comment as to where that currently rests?
That rests in conversations between ourselves and the various arms of government. That's being worked through on a constructive basis. And in some respects, the delays that we've had at Sole haven't helped. What I mean by haven't helped, hasn't endangered the combination certificate is just you want to get that sorted out before you're sitting down and having the conversations. We would like to have been having the conversations the second half of last year. But getting Sole sorted out and stable has been the priority. And there are conversations going on at the moment with the different departments.
Is it -- figure my ignorance because I'm not a chemical engineer, but is it conceivable that you could have the Sole upstream running at a moderated rate versus what was initially targeted as nameplate and backfilling latent capacity with Manta? Or do you need to treat these as 2 different product streams and reconfigure the plant accordingly? Because I guess you've got theoretical capacity beyond 68 currently.
Yes. First, there's 2 parts to answer. Firstly, is what is the right development concept for Manta and where Manta is best processed. And then the second part is Manta going into the Orbost gas plant, doesn't go -- would not go through the hydrogen sulfide removal unit. So in some respects, it's the kit downstream of the hydrogen sulfide removal unit that Manta accesses. So it's an add-on. It's not a -- from an economic -- maximizing economic value point of view weighted, topping up, topping up sales with Manta doesn't make a lot of sense. Manta is a stand-alone separate development, which we had chased as early as possible. Does that answer your question?
I think so. I'll probably explore that with you off-line.
There are no further questions at this time. I'll now hand back to Mr. Maxwell for closing remarks.
So thank you very much, and thanks for the questions that were raised. We're open to have conversations over the next week or so. So please don't hesitate to get in contact with Derek and arrange if people want follow-up conversations. Just highlighting a couple of things from the quarterly. It's taken a little bit longer than we would have liked, but the positive signs for the Sole project are there. 45 terajoules a day is imminent, as I mentioned. Starting the gas sales agreement -- agreements has been an important milestone for the company and getting the project up to 68 terajoules a day is our next Sole target. And then in parallel with that, we've got the Athena plant, Casino Henry, which we haven't talked about on this call, producing slightly better than expected. And then the development activities to come in behind, both the Otway and the Gippsland, in an environment where the southeast of Australia is calling out for more gas and prices, I would use the word robust. So against that background, thanks for listening, and look forward to an update with us providing you with an update around our half year results in February. Thank you.
That does conclude our conference for today. Thank you for participating. You may now disconnect.