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Thank you for standing by, and welcome to the Cooper Energy Q3 FY '21 Quarterly Report Conference Call. [Operator Instructions] I would now like to hand the conference over to Mr. Derek Piper, Head of Investor Relations. Please go ahead.
Thanks, Jan, and good morning, everyone. Thanks for joining the Cooper Energy quarterly results conference call. I'm here with David Maxwell, our Managing Director; Virginia Suttell, our Chief Financial Officer; and other members of the executive leadership team. David and Virginia will talk through the results, and then we'll open the lines for Q&A. So David, I'll hand over to you.
Thanks, Derek, and welcome to everybody. What I'm going to do, we don't actually have a presentation. It's just comments. And really, when you think about the third quarter results, it comes up in 8 points. And I'll make the 8 points with support behind each of those points, and then we can open up to Q&A, as Derek said. So firstly, this quarter, we reset the baseline performance from which we'll continue to grow. To illustrate that, in support of that, the gas plant at Sole or the Orbost Gas Plant, which is operated by APA, is being reconfigured. It's being tuned and partly debottlenecked. The plant processed 3.2 petajoules in the quarter, which was up 97% from the prior quarter. And that's acknowledging the plant was offline for 3 weeks last quarter for reconfiguration works. Planned works will further debottleneck the plant for higher rates and greater stability. We're now delivering into all of our Sole gas sales agreements, and the transition agreement with APA underwrites the margins for our Sole production on a day when the gas plant might not be producing at the full rate nominated by customers. The second point is resetting the baseline performance and market expectations was an important step for us. Production from the Orbost Gas Plant is now in the 40- to 45-terajoule a day range, albeit with absorber cleans still required. The plant is 2/3 of the way to the nameplate processing capacity of 68 terajoules a day. And I note that the plant came back online over the weekend. And today, the plan is to produce 45 terajoules a day. 2/3 of the nameplate capacity equates to a valuable asset for Cooper Energy. So at 45 terajoules a day, we're 2/3 of the way to that 68. We're receiving materially higher revenue now that the gas sales agreements are up and running. We've met every nomination on every day since the gas sales agreements commenced. And we're generating full and healthy margins, underpinned by the transition agreement with APA. The third point is improved performance this quarter delivered record results: record production, up 46% to 0.77 million barrels of oil equivalent; record sales volumes, up 55% to 0.82 million barrels of oil equivalent; record quarterly revenue, up 46% to $36 million. We've also achieved record full year results with a quarter still to come. On this basis and as noted in the quarterly, we have maintained full year FY '21 production guidance of 2.7 million to 2.9 million barrels of production and 2.9 million to 3.1 million barrels of sales volume. The fourth point: Our baseline performance is partly underwritten by the transition agreement, which we've extended to the 1st of May next year. Clearly, we would have preferred not to extend, but the reality is that we needed the time. The benefits of the transition agreement are evident in our quarterly, and you can see that in the numbers I've just quoted. Sole generated a 200% increase in revenue, thanks to the higher processed volumes at Orbost and the higher pricing that comes with those Sole gas sales agreements. The transition agreement effectively underwrites our margins when back-up gas supply is needed to service our customer requirements. And it's worth noting that while the plant has been down over the past week for cleaning, and this is cleaning ahead of the winter and the higher rates expected through winter, we've continued to service our customer commitments and received compensation from APA, thus keeping our margins broadly whole. The fifth point: We're seeing better performance from the gas plant following reconfiguration of the plant. Average daily production in March was 42 terajoules a day. This is 63% higher than the average rate last quarter, and that's after excluding downtime days for cleaning. The plant has been able to maintain rates at 45 terajoules a day for increasing periods. And we're now working to get the rates higher, recognizing that the target in our agreements with APA is 68 terajoules a day. The stock exchange announcement we put out on the 6th of April details the works to be undertaken to further increase the rates and extend the cleaning cycles and increase the stability. The quarterly report issued this morning includes a summary of the proposed future capital works to increase the Orbost rate, as to increase the 45, together with better plant performance as the plant continues to be tuned by the APA operators. These debottlenecking works were part of the reconfiguration activities originally agreed as a part of the transition agreement signed and announced with APA back in August of last year, and this is the reason why Cooper Energy is sharing after costs. There's also a lot of work still going on to identify the root cause of the foaming and the fouling. The sixth point: We continue to work with APA with the common objective of increasing production and improving plant performance with the clear target being 68 terajoules a day. My hope is that the rate will have materially increased by the end of the calendar year 2021. Under our existing agreements and, in particular, the gas development agreement, APA has a contractual commitment to provide processing capacity of 68 terajoules a day. The seventh point: We're making good progress across our other projects and, in particular, the Otway Basin. To illustrate this, the Athena Gas Plant project is tracking to plan and is now 65% complete. We will start commissioning the plant in the next quarter, and the plan is to switch processing from Iona to Athena, that's the processing for our Casino Henry gas, from Iona to Athena in October after the winter period. We continue to progress OP3D and expect to have more to say on this later in the year. [indiscernible] assessment of various exploration prospects and seismic interpretation to position ourselves to add reserves and add resource consistent with market opportunities. Just going to hand over to Virginia, who has a few summary comments on the financials. And then we'll open it up for Q&A.
Thanks, David. So many of the key statistics and metrics David has already mentioned so far. So I think I'll probably just make some high-level points here around our financial position and how it's strengthening. So first of all, our revenue is growing. We can see that if you look at the key performance metrics, 46% increase quarter-on-quarter and 57% for the 9 months to March as compared to the 9 months to March in 2020. Sole revenue, as David mentioned, is increasing 200% quarter-on-quarter, and that was enabled by the commencement of the Sole GSA, which has provided that step-up and resetting the baseline financial performance. Our margins are healthy and are relatively firm. Our Otway Basin earnings profile will improve post switchover to a Athena Gas Plant, which is -- the project is around about, I'm going to say, 70% complete...
55%.
55%, yes. There you go, round up. We -- cash reserves are circa $110 million at the moment, and we continue to have the strong support from our lenders. To that end, we're currently working with the syndicate of 5 banks on resetting the debt facility terms and conditions and with the Orbost Gas Plant's baseline performance, and that work is expected to be sort of done by 30 June. Now I hand back to David, if you want to close out.
No. That's good. Thank you. So let's maybe open the lines to Q&A. And we've got a few of the leadership team here as well, depending on the questions to be asked.
[Operator Instructions] Your first question comes from James Bullen from CG.
Just on guidance. You're holding it there solid at 2.7 million to 2.9 million. That's quite a wide range, given you've only got the June quarter to go. Could you provide a bit of color as to why you're retaining such a wide range?
I wouldn't call 0.2 [ million ] barrels oil equivalent with 1 quarter to go a wide range.
20-odd percent.
But I don't -- well, maybe my math and yours are a little bit different. But I think it's much closer to 10%. But the...
700,000 to 900,000 BOE for the final quarter.
Yes. Yes. The thing that we decided was that you don't want to be changing guidance. We're well within that range, and we thought just tweaking it a little bit was not going to make too much difference. So that was the logic. We did ask ourselves a question whether we should tighten the range, and we thought not. And that's the simple answer, sorry. I don't know, Virginia, if you wanted to add anything around that.
I think that's right. I think we've just seen the plant come back today from its winter clean effectively. And we -- also, the proportion of contribution that Sole makes to that range is reasonably significant in the business. So we made the decision to keep the range where it was at the moment.
Yes. And the upper end of the range reflects what we think customers will do through the winter, recognizing nominations are going to significantly increase. And who's to say whether that eventuates or not in definitive terms. If you look at history, you'd expect it absolutely will. So we've covered the range in that sense because we are coming into the high-demand period.
Okay. Great. And just, I guess, when do you think that you can be free cash flow positive?
Well, I guess when you say free cash flow positive, you're talking about the operating cash flow. Or are you taking account of repayments of debt and facilities? Well...
Yes. I guess I'm just starting to think about when you can -- yes, beyond payment of the debt facilities, when you can start to show a bit of a cash balance increasing.
Well, this month, I mean, we are operating cash flow positive right now. And then as reflected in the quarterly, there's a PRRT payment, and we've started to repay the facility down. You'll see our revenue increase, and you'll see the cash -- the operating cash being generated out of the business increase. So let me just pass across to Virginia, and she can add and other...
Yes. I think, James, one of the things to take into consideration in sort of commenting on that is the discussions that we're currently having with lenders and what a future repayment profile looks like under the facility. So probably giving you any definitive time line whilst those conversations are going on wouldn't be something that I'd be looking to do.
Yes. I think one thing just -- so building on that question, I think you'll see more in the June numbers as well, I expect. But Virginia made the comment about the healthy returns on the gas business. And I think you're going to see that emerging over time quite clearly, particularly in the detailed accounts that will come out in June -- sorry, come out in August, but for year-end June.
Your next question comes from Gordon Ramsay from RBC Capital Markets.
Just a quick one, David, on gas pricing. We've seen it come down from the December quarter, and I know you've explained that some of that is bringing some of the Otway gas in. Just trying to understand kind of directionally what will happen going forward as customer nominations increase and the relationship with APA on the transition agreement on gas pricing because we've seen, obviously, a new contract repriced between Origin and Beach at what looks like fairly attractive pricing.
Yes. Glad you asked the question, Gordon. Thank you. The -- what I might do in explaining -- I mean, in the quarterly, you'll see the numbers compared to the March quarter FY '20 as well. If we go back to -- and I'll deal with that first and then deal with the quarter-on-quarter in terms of December versus March. If we go back to March, it was essentially -- it was all Casino Henry, and it was a contract with the utility at a good price. That was the bulk of the revenue -- the gas price revenue at that point. In December, we didn't have too many of -- we only had 2 of the gas sales agreements started, and all the rest of the gas was being sold into the spot market. And then coming through into March, I think all but -- I think I'm right in saying all but some -- just under 90% of the gas in Sole went into gas sales agreements. And there was a little bit of gas sold into the spot market. What we also had was, in the Otway, a contract come off in December, a contract that was at a previously higher price. And we chose not to extend that contract but rather put it into the spot market and keep some flexibility until Sole volumes were up and the Athena plant was online, at which point we would contract long term. So the main reason for that dip is the increased sales that have gone into the spot market for Casino Henry in the January-to-March period. In terms of pricing out of Sole, the average pricing out of Sole is above what you see there is -- that number is dragged down by the spot price relative to our Sole term contracts. It's a bit of a convoluted answer. But hopefully, it's addressed the question.
No. That's good, David. And just going forward then, we could expect to see more higher price -- Sole pricing coming through. Is that a fair statement?
Yes. Yes. I think you will, particularly in the June quarter because the proportion of sales out of Sole relative to Casino Henry will be higher. And then when the Athena plant comes online in the October-November period, we'll be looking to contract the remaining -- the uncontracted gas in Athena on term contracts. And I think you got a pretty good sense of where those gas prices are. But it's probably worth saying here, one of the reasons why we've held off contracting those Casino Henry volumes is -- well, there's 2 reasons, really. One is, as people know, processing that gas through Iona is interruptible supply. So that takes a little bit of a discount to what you might call normal term contract prices. And we chose not to do that because we'd rather sit back and wait for the better prices that we think will get out of firm supply. And the second reason was the -- we just wanted to make sure we have, across the portfolio, as much supply available as possible whilst Sole was going through its extended commissioning phase. So in some respects, if the prices go through the roof, spot prices were to go through the roof, we've got a bit of a natural hedge with the uncontracted volumes in Casino Henry.
[Operator Instructions] Your next question comes from [ Ralph Zularowski ] from [ Zularowski ] Nominees Proprietary Limited.
Yes. I've got a couple of areas I want to try and drill into, and the first one is still on Sole. Now I'm an individual investor, so I'm beginning to think that the way the market looks at Sole is that discounting that project is somewhat of a partially stranded gas asset in the sense that Sole gas being sour has to be first processed by the Orbost Gas Plant. And there's no other option available. So that partially stranded aspect I'm getting at is the difference between the nameplate for the project and what looks to be the current operating capacity for the short term of 45 terajoules. And while that 23 terajoules is deferred into future years, it does significantly alter the project's economics, even though it is a material asset. So aside from the extension of the transition agreement, how is the banking syndicate responding to this sort of gap in capacity? And what are your contingency plans for dealing with a scenario where the Orbost Gas Plant doesn't get to 68 terajoules and Cooper faces a gas supply shortage in its GSAs?
Yes. Let me answer the stranded gas asset comment, and Virginia will provide comments on what we're doing with the banks. But firstly, thanks for the question, [ Ralph ]. And the thing that I think is important is to think about the banks and their position here and where is their security. Their security sits in the 2P reserves and the gas sales agreements. And the 2P reserves, the upstream, the field has performed at or better than expected. And the gas sales agreements are strong, robust and nothing -- and we've met every nomination on every day. I'm going to leave Virginia to just talk a little bit about how we're managing that in the context of the banks. But your comment about the stranded gas asset is if you take the thinking that you've shared there, every asset is stranded because what actually links an asset to a market is the pipeline. And gas fields, the upstream, has a linkage into a system, and the processing plant and all gas fields are linked by a pipeline to a processing plant. Our -- what you will find in some of the bigger projects, the Cooper Basin, for example, or what we've got in Casino Henry or over in -- just in the bigger project in Sole, but maybe the Gippsland Basin joint venture, they've got multiple fields. So they can call off multiple fields. And what we've got here is 2 wells. So we have -- to all intents and purposes, it's the same field, 2 wells. So you think of each well as a source into that gas plant. And we, to date, have been producing, out of all of our production, out of one well at a time. So we've always had one well on standby. And we -- that's part of our insurance, if you like. So I think the stranded asset concept is, it's the same as any other asset that exists in the upstream sector. In terms of the banks and the conversations that we've been having with the banks, I'll ask Virginia to say a little bit about that.
Sure. Thanks, David. Ralph, I think probably the first thing with respect to the lenders is that the offshore component of the project is being executed, for -- which is what the facility was loaned to us in the first place. So that's the first point. The point that David made around the reserves and that they're still there and that it's an extended period of time, it's also really relevant, as is the customer agreements that they're in place activated on the terms and conditions that were in place at the time that we undertook the loan. What the lenders, in my view, look at, because this is my view, I'm not speaking on behalf of the lenders here, is around debt serviceability and recovery of their investment. So their economics are significantly sensitized and [ concerned ] based on a set of conservative assumptions. So when you look at our reserve-based lending facility, lenders bank 2P developed, 1P undeveloped reserve profile. They have an oil deck, which is substantially lower than what the forward curve would be suggesting it is. So they do run a conservative bank case. So as to what they're thinking as just sort of the extended time line and obviously the change in economics for the project, they're -- the things that they're thinking about is the serviceability primarily, so making sure that we're servicing the debt through repayments and also through the interest coverage. So that's what they'd be thinking about.
The other thing that I would add is that the maximum on a day under our gas sales agreements is just over 60 terajoules a day. That's not the 68. So we -- the banks haven't banked 68 terajoules a day. The banks have banked the GSAs and the maximum under those GSAs, which is a smidgen over 60 on a day. And the conversations with the banks, as Virginia said in the summary comments, have been very constructive about adjusting the facility to better reflect the profile that we now have before us. And this is -- I think it's important that people don't lose sight of this. 45 is not our -- 45 might be the base today and the foundation, but it's not where we plan to stop. I mean, we've still got our eye very much on that 68 or absolutely as close to the 68 as we can possibly get, hence the Phase 2b works, hence the improved -- the ongoing work and tuning the plant and the ongoing work in understanding the root cause.
All right. I just want to just -- if I could, just drill a little bit further on that. So Virginia, just a -- so 45 terajoules a day, if that was -- economically speaking, that project stands up at 45 terajoules a day. That's kind of sort of where I want to get to. We don't need 68. 45 would, in and of itself, be a significant project that can repay itself and take care of the serviceability and everything else. Is that correct?
We need to adjust the finance facility to reflect the 45 terajoules a day. And the short answer to that is yes. The economics are different at different points in the cycle. And go back to -- when we were looking at this project, it was a $605 million project. Our share of that was $355 million, which we delivered for just over $330 million. And the APA share of it was $250 million, which they've delivered for a number north of $250 million. When you look at the economics, you look at the economics point forward. So is supply out of Sole today into the Orbost Gas Plant economic on a point-forward basis, taking account of the costs that we have expended in the upstream as Cooper Energy from our point of view? Absolutely, yes. We haven't impaired the asset. If it wasn't economic, we would have -- or if we were under water in terms of our historical cost, we would have had to have impaired our cost to date for Sole. The economics for APA is a separate question, and that's a question for APA. But we did -- we do note that they impaired their asset at 30 December -- 31 December.
So Ralph, I will just say that the economics that David's talking about is different for us as it is for the banks, as [ we just ] made the point with APA. So the question of what terajoules a day is economic for the lenders, I'd have to say that I would expect so on adjusted terms and conditions, but I don't run their model.
Yes. That's fine. You've answered the question, and it's a good answer. And David, I was -- I did have a follow-up on the whole Sole thing with APA, and you've sort of begun that. With them impairing, I guess, to a carrying value of 0, based on, as they say, the reassessment of the plant's future cash flows, is there a scenario where Cooper considers acquiring the Orbost Gas Plant? And if so, how would you ensure egress options for the sales quality gas from the plant we now own?
Yes. First point, I don't think they impaired to 0. I think they -- I'm going to go from memory here, I think they impaired to $239 million. So -- and -- but what they did impair -- and so they reduced to -- by $240-odd million, from memory, to bring it down to $239 million. So yes, it's not 0 on the -- certainly not 0 on the APA balance sheet. And they're earning -- as at today, they're earning a good tariff from Cooper Energy. In terms of where to from here, look, we will review all options with respect to what's the -- what the best way to deal with things in the future. At the moment, us and APA are working very closely on all the technical and operating aspects of the project. And they're meeting -- they, together with the backup arrangements that we've put in place, are meeting the nominations of all of our gas sales agreements. And it's embedded in the agreements that we have with APA that we recognize -- we, being APA and Cooper Energy, recognize the importance of those gas sales agreements. So -- and I think we've been on the public record with that. So I don't think I can say any more than that. If there are questions around the gas plant, I think they really have to be directed to APA.
Okay. Okay. That's fine. I just had one other area. It used to be -- and we have to go back to like March 10, 2020, and you just put out slide presentations. And the one I'm referring to, from March 10, 2020 in Slide 21, is you had a slide that was titled Profile of Contracted and Uncontracted Gas Reserves by Project. And that very clearly showed the future expected sales volumes from -- that has been contracted in that basin for Otway and what's been contracted for Sole and what's uncontracted, et cetera. Now you stopped doing that. I was wondering whether you'd maybe consider including that in future presentations and maybe also including a subsequent slide that specifically breaks out the total amount of take-or-pay in each of the projects. Is that something you can do?
We've -- well, we can do it. It's a question of whether we think it's the right thing to do. What we have done is we've presented the gas reserves and the gas portfolio in our recent investor packs in a different form. And the reason we've done that is because we're wanting to steer the market to understand the way we manage our business. And the way we manage our business is across the source of supply in 2 key hubs, the Otway and the Gippsland, into a suite of gas contracts in Southeast Australia and then optimizing across that hub. And that's exactly what you see us doing at the moment. And we've set out the portion that's under term contracts, the portion that's uncontracted. And then separately, in a graph, and we've included the graph in this year's -- quarter's report, we set out a high level of our contracts in Sole, which is at the 90% level. So someone can work it out if they want. We've done it slightly differently, and it's really reflecting the maturation of the business. And as you see us adding OP3D, Manta and then the other opportunities through successful exploration, et cetera, you'll see us talking about it more on a total portfolio perspective. Here's the gas sales agreements. Here's the uncontracted gas, and here's the supply sources. So we -- that's the way that we think about it.
All right. Okay. There's no thought to perhaps at least just spitting out what the spot pricing has been in the basin.
Yes. We have to be really careful now with our gas sales agreements. But we -- I mean, the terms and conditions of those agreements are confidential. So what we do is we average everything up. And if we were to put out the spot price, people can work -- a good analyst can work backwards on the spot price. But -- and then say, "Okay, what's the average of the gas sales agreements?" That can be done reasonably easily on a day, if someone wants to get in and do the analysis. We have to be very sensitive to customers here.
Yes. Agreed. I mean -- but it is kind of sort of published, right? I mean, $7.82, roughly speaking, I think, was what I was -- figured it out. But -- okay. But that's nothing I can -- that's not something you'll be likely to do.
Let us give it some thought. Let us give it some thought. Yes. Yes. Appreciate it.
[Operator Instructions] There are no further questions at this time. I'll now hand back to Mr. Maxwell for closing remarks.
Yes. Thank you very much. Look, I'll just make a few quick comments to close out. Firstly, the last 9, 12 months have been challenging. And what we announced a couple of weeks ago was some details around the transition agreements and the status of the business. And what we've seen in the quarterly report which we issued this morning is the evidence behind that. But the worm has turned or the worm is turning in terms of actual performance, and you see that in the results, production revenue, et cetera. The second thing is that this is happening at a time -- we've always said that there will be a tight gas supply in Southeast Australia. There's been evidence in the last few months that, that is absolutely firming, and our views are correct. And so we think that we've got ourselves well positioned, albeit we've still got some way to go with Sole. I don't want any shareholder or anyone thinking of being a shareholder to think that we rest where we are. What we've done is set a base of production, around about 60 terajoules a day, so 45 out of Sole and 15 out of Casino Henry, south Cooper Basin. And from this, we've got growth in all of our assets, Cooper, the Gippsland and the Otway. So my hope and my expectation is that you'll see this gradual improvement, a, on the back of increased demand, particularly coming into winter; and then b, on the back of improved performance, particularly in the Sole, so the Orbost Gas Plant; and then c, as the next round of projects starts to come through. So on that note, thanks very much for your time. And if you do have questions outside of the call, please don't hesitate to contact Derek Piper. His details are on the quarterly report. Thank you.
That does conclude our conference for today. Thank you for participating. You may now disconnect.