Cooper Energy Ltd

ASX:COE

Earnings Call Transcript 2020-Q4

[David P. Maxwell, MD & Executive Director]

Thank you, Ashley, and welcome, everybody, to the call. Good afternoon. Thanks for taking the time to join the Cooper Energy Fourth Quarter Conference call. With me on the call today, I've got Virginia Suttell, our CFO; Eddy Glavas, who's the General Manager of Commercial and Development; Don Murchland, who many of you will know, who looks after Investor Relations; Iain MacDougall, who -- General Manager of HSEC and Technical Services; Amelia Jalleh, who's the Company Secretary and legal counsel; and then in Perth, Mike Jacobsen, who's the General Manager of Projects and Operations; and myself.In the past, we've not typically held an investor call as a part of our quarterlies, but we thought it was appropriate this quarter, particularly regarding an update on the Sole Gas Project and the Orbost Gas Processing Plant. Our final quarter for FY '20 shows the first impact of Sole on our business, with our highest annual and quarterly revenue and production since the company commenced. However, it's a result that is well short of what we had hoped for late in 2019 as the Orbost Gas Processing Plant operated by APA has yet to reach nameplate capacity. As a result, production from Sole was roughly 1/3 of what it should be. We've made a number of progress announcements on the gas plant's commissioning and status and included an update in the report today. We expect investors will have further questions and welcome the opportunity to address them as best we can in the Q&A session that will follow after this brief introduction. However, before I go to that, I'll just give you a quick snapshot of some of the key points. And then as I say, we can get into the Q&A. First, safety. 0 lost time injuries in the quarter, and we finished the year with the single lost time injury incurred on the Ocean Monarch rig in September of last year. A statistical quirk arising from having less hours worked in the last quarter means the frequency rate of our recordable cases and lost time injuries rose despite 0 incidents in the June quarter. As an aside, our year-end rate of 3.53 total recordable case frequency compares to the offshore Australia industry average of 5.27. Hence, our performance was much better than the industry average, but we aspire to 0 injuries. On production, this was up 118% on the prior quarter and 19% on the prior year. Our gas output for the quarter was 3.5 petajoules, which was up 147% from the prior quarter's 1.4 petajoules with the first full quarter contribution from Sole, albeit not at the full rates. I'll return to the results and the status of Sole before we go to the Q&A. On the financials, revenue was up 61% on the prior quarter and 3% for the year. Gas accounted for $21.5 million or nearly 90% of the quarter's $24 million sales. We concluded the quarter with cash of $131 million and net debt of $98 million. Our cash balance reduced by $12 million after cash capital expenditure of $35 million in the quarter. A feature of our capital expenditure was commercial close of some of the outstanding contracts for the Sole Gas Project. This was a favorable outcome as can be seen in the $9 million credit in our incurred Gippsland Basin CapEx for the period and the reduction to the spend on the offshore Sole Gas Project. Capital expenditure on the project now stands at $335 million, which compares to the budget of $355 million. So on this -- on these numbers, the project is within budget and within schedule for the offshore operated component of the Sole project, which has been operated and run by Cooper Energy. On the projects themselves, we took the Athena project, which is Athena being the new name for the Minerva Gas Plant through to FID last week and the Otway's Phase III Development or OP3D, as we call it, is continuing through the Concept Select stage with an FID target for June quarter of next year. That's next calendar year. Our market analysis and feedback from other participants is resourcing -- is reinforcing our expectation of a tight gas supply emerging in southeast Australia from '21, '22 onwards. Our work on OP3D, Manta, and on our exploration targets for the coming drilling program in 2022 is all directed to leveraging our assets for portfolio value add, much as we did really for Sole to capture the opportunity around the gas plants and acreage and then build further from it. On Sole, as we've advised in our announcements, commissioning of the Orbost Gas Processing Plant has been delayed by the occurrence of unexplained foaming in the absorber section of the plant at the higher end of its production range. Work done by APA has seen improvements such that steady production of 40 to 45 terajoules a day was maintained after its return from shutdown in June to mid-July. This is a good improvement on the 20-ish terajoules a day range before the first shutdown but still well short of the 68 terajoules a day rate required in our gas processing contract. As many of you will have noticed, production this week is lower. This is by design. This is for technical analysis of elements of the gas liquid stream going into the Orbost Gas Processing Plant. It's our expectation that the plant will get to the 68 terajoules a day capacity one way or the other. And this is being pursued at the moment on 3 fronts: firstly, ongoing plant optimization works; secondly, plans for the plant reconfiguration; and of course, the technical analysis to try to identify the root cause of the foaming. In the meantime, we're selling gas at spot prices less transport. That's spot gas prices less transport into New South Wales and Victoria. We've maintained dialogue with our customers and our financiers. Our start dates for our firm gas contracts have been deferred, and we remain well within our financing covenants. Both customers and banks have been supportive of the project. And once we have dates for firm supply, we will work through whatever consequential changes that may be associated with the change in start dates that are required for the gas sales agreements and the debt facility. With regards to FY '21, the report includes guidance on FY '21 production and CapEx. As you might expect, we're anticipating a large increase in production and sales, thanks to Sole. But just how large that increase is will be dependent on the rate and timing of improvement at Orbost. We thank our shareholders for their support of the company as we move to the Sole finish line. I can assure you, all in Cooper Energy are doing all they can to make the Sole finish line as early as possible. I'll now turn over to Q&A. Myself and my colleagues are available to answer any questions you may have.

[Operator]

[Operator Instructions] Your first question comes from James Bullen with CGS.

[James P. Bullen, Senior Energy Analyst]

Just a question on firstly around liquidated damages. How much has been paid by APA? And will there be an increase to the cap on liquidated damages?

[David P. Maxwell, MD & Executive Director]

I'm going to pass that to my colleagues in Adelaide to answer.

[Virginia Katherine Suttell, Chief Financial Officer]

James, it's Virginia. So your question was how much is being paid by APA in respect to the liquidated damages under the development agreement. At 30th of June, we have invoiced for the $20 million worth of liquidated damages under the development agreement. And I think the second part was around the cap. At the moment, that cap is sitting at $20 million. So we have reached the cap with 1 or 2 matters still to be sorted out.

[David P. Maxwell, MD & Executive Director]

It's worth noting that on the days when we're selling gas, there are no -- up to the -- and the revenue up to the value of a daily LD, there's no LD payable.

[James P. Bullen, Senior Energy Analyst]

Right. And second question is around abandonment spend. You've provided us with CapEx guidance for FY '21. Does that include spend on abandonment? Or is that going to be incremental? Or can that be deferred further?

[David P. Maxwell, MD & Executive Director]

No, it includes -- the numbers there include the planning for abandonment activities. It doesn't include any of the major offshore abandonment campaign. We're talking about that in FY '22. So the numbers -- there are some numbers in FY '21, but that's more for the planning of the abandonment campaign. And here, I'm referring to the BMG, the assets to be abandoned in BMG.

[James P. Bullen, Senior Energy Analyst]

Okay. Brilliant. And final question, impairment testing and any potential for reserve downgrades due to, obviously, the oil price fall, but then also delays around Sole.

[David P. Maxwell, MD & Executive Director]

I'll comment on the reserves, and I'll leave Virginia to comment on impairment. Reserves, we're in the process of finalizing the year-end reserve numbers at the moment. And it's going to be pretty line ball. What we are adding in terms of -- and here talking about proven and probable. What we're adding in proven and probable pretty much equates to production. And that's looking at -- really looking at the remaining reserves in the offshore Otway; Sole, where there's no change; and the Cooper Basin. So the aggregate of that through the year, some slight adjustments up, offset by production over the last financial year. On impairments, I will pass that one over to Virginia.

[Virginia Katherine Suttell, Chief Financial Officer]

Sure. Thanks, David. So we review for triggers of impairment every 6 months. And as part of that review, we look at the macroeconomic and assets persist assumptions to determine whether triggers exist. And we then we then test for impairment where triggers have been identified. So the current macroeconomic and operating environment has meant that triggers have been identified for a number of our assets in the oil, gas and exploration category. And these are currently being tested. So modeling is underway and will be finalized along with the reserve process and then put through the audit and Board as appropriate. So our assets, I guess, from a modeling perspective, are most sensitive to the prevailing gas price and the cost estimates associated with the development and restoration and then obviously, the WACC and discount rates that are used in modeling. So at the moment, the process is ongoing to establish whether there's an impairment.

[David P. Maxwell, MD & Executive Director]

And when we talk about gas prices, the gas prices that we use, where the gas price is -- where the gas is under contract, we use the contract prices. And where the gas is not contracted, it's left up to a review between ourselves and the auditors as to what is an appropriate price to use.

[James P. Bullen, Senior Energy Analyst]

Right. But I guess with everyone expecting the gas market to tighten again, particularly in southeast Australia, you'd imagine that impairments are unlikely.

[David P. Maxwell, MD & Executive Director]

I don't -- I mean, I'll say something and then Virginia might want to add. I think auditors and banks don't look too far ahead. I'm not going to say that impairments are likely or unlikely. But as Virginia said, there's some triggers that have been identified, so now we have to go and do the further analysis. But auditors do look more closely at the immediate gas price. So where there's uncontracted gas in the next year or 2, they'll be looking at current prices.

[Virginia Katherine Suttell, Chief Financial Officer]

I think, just to add to that, you're modeling on the basis of the contracts that you have in place at the moment as opposed to modeling on the basis of what you think you're going to be contracting in the future contract at term and firm pricing. So the nuance there is that the -- you're looking at what spot prices are expected through the audit lens.

[Operator]

Our next question comes from Adrian Prendergast with Morgans Financial.

[Adrian Prendergast, Senior Analyst]

A question for each. Just on your financiers and your customers where you say that they are obviously remaining cooperative and supportive. Just on the banks, just -- obviously, the short-term nature of the issue isn't going to change the life -- all of life size view and value of a project. Is that fair to say? And what kind of talks are going on? Obviously, your net debt is far smaller outstanding than your facility. And just give us a view for what may happen there or what you can say. And then secondly, just on your customers, obviously, very weak current spot prices are also helping them. And -- but I do recall when you were doing the offtake to sell that a lot of language around being a partnership with customers and supporting and sustainable pricing. Just does that garner now support that you're going through some commissioning issues? And just whatever color you can give us on that, too.

[David P. Maxwell, MD & Executive Director]

Yes. I'll answer the one on the customers secondly, but I'll leave it to Virginia. We'll do -- take it in the order in which you've asked them, Adrian, to speak about the banks.

[Virginia Katherine Suttell, Chief Financial Officer]

So the bank, as we sort of indicated in the quarterly, we're in discussions with the banks, as you'd expect, we would be having -- have them finance the Sole Gas Project and provide our facility. So we have, as we've always said, a sort of constructive relationship with the banks. The things that the lenders -- I mean, I think your question went to the what things do they look at and what are we considering. So the things that they look at around the Sole Gas Project is the value that's in the GSAs, which David can talk about on the relationships with the customers and maintaining that value. And they look at the reservoir and that the gas -- the hydrocarbons are there and that we can produce them and then they look at the pathway to market. So at the moment, we're sort of looking -- focusing on the pathway to market and the Orbost Gas Plant. So they're the areas they look at. The hydrocarbons are still there. They will be produced. It's a matter of time and a matter of root cause analysis and then the sort of the optimization that David mentioned. So the lenders very much have that in their viewfinder at the moment, and it's for us to be keeping them up to date to those things that they look at when they consider the debt facility with Cooper.

[David P. Maxwell, MD & Executive Director]

Yes. And just if I could just add a couple of things to that. When Virginia talks about the gas contracts and the gas customers, there have been no changes to the terms that we've negotiated with the customers in terms of pricing offtake volumes. What has happened is that the start date for the contracts has been moved out, and everything if you can think of it, just a bit like a template that's there, and it's all just moved out a few months, as Virginia said. So from a bank's point of view, from a financier's point of view, their security is still there. Their security sits in the gas contracts and the reserves on the ground, primarily. In terms of the relationship with the customers, I have to say it is very, very positive. And I don't say those words lightly. And what I mean by it is that that's been very constructive. We haven't adjusted any of the terms. The customers themselves realize that these are term -- long-term arrangements and the outlook for the gas market, '22, '23, '24, is for a significant uptick in gas prices. And off the back of that, that's what these contracts are there for from their point of view. They write long-term contracts to give themselves stability. And fortuitously or fortunately, for them and for us, maybe, they can buy at the moment. If they have to buy extra gas, they can buy it on the spot market for a little bit less than what they're buying at -- they would have been paying under our term contract. So in some respects, there's a bit of a win-win. They preserve the lower price for the longer term, and they can get in a slightly lower price now in the short term off the spot market. And I mean, as we work closely with our financiers, the banks, we work closely with the customers, and the small marketing team is in contact with them every day. The spot gas sales that we are -- the gas we're selling at spot prices at the moment is being sold to 2 of our customers as well.

[Operator]

Your next question comes from Gordon Ramsay with RBC.

[Gordon Alexander Ramsay, Analyst]

David, just a couple of quick questions. Just the investigation that's going on right now with respect to potentially shutting the plant for 3 weeks and doing the modifications. What key criteria would you be working with to make that decision?

[David P. Maxwell, MD & Executive Director]

I'll say a couple of things, and then I'll pass across to Mike Jacobsen, who's also here in Perth. There's 2 approaches -- I'll not say 2 approaches. But there's 2 things -- the things that we're looking at fall into 2 buckets: One is what you might call the root cause analysis. And once you know the root cause, then you can address the cause. The other is adjustments to the system, which -- whether it's the plant configuration or other parts of it, which will increase the production rate. But in doing that, you might still not know directly the cause. Now both courses of action are being pursued. And I'll pass across to Mike to give a little bit more color around it and the timing and the sort of decision-making criteria that are being applied.

[Michael Jacobsen, General Manager of Projects & Operations]

Yes. Thanks, David. Gordon, thanks for the question. I think as David mentioned, it's about the first part of the work is dealing with the symptoms and the second part is dealing with the recourse. So in terms of the criteria to determine whether this first half reconfiguration of the plant will occur, it's really our understanding of the root cause and then how do we deal with the root cause. If we can deal with that quickly and easily, then the need to do dealing with the symptoms is probably less likely. But if it's going to take longer to be able to deal with the root cause, we're certainly very keen to push ahead with the reconfiguration because it will go a long way to get us close to the required 68 terajoules a day, albeit possibly with intermediate shutdowns every period of time, and that might be 3 months to have a cleanup. But -- so certainly, I think the criteria is about finding the root cause and then finding how we deal with that root cause.

[Gordon Alexander Ramsay, Analyst]

This might come back to you, David. So who pays for this, if you shut down the plant? Is it a design issue with Downer? Or is it a construction implementation delivery issue with APA? Or is it outside of the contract?

[David P. Maxwell, MD & Executive Director]

It depends on -- in many respects, what is the cause needs to be identified first. And if it is a plant design issue, then that would sit with the people involved in upgrading the plant. And if it is something else, then we have to go to where that is. The one thing I will say is that we and APA have been working very closely together on finding the solution or identifying the path forward. We've got a couple of our people -- I was going to say, embedded in their team not quite embedded because we're working remotely but talking all the time and for some things that we have suggested, some things that we're doing in support of APA to identify it. So I'm not answering your question in its A or B because we don't know whether it is A or B that pays for this at this stage. But certainly, APA and ourselves are working closely on the solution and coming out of that will be also who pays for it.

[Gordon Alexander Ramsay, Analyst]

Okay. Just last one from me. Just on the completion test for moving across to -- for APA to get some tolling and I guess for financial completion. Is that -- was that 90 days at 68 terajoules a day? And is that in the process of being renegotiated? Can you maybe comment on where that whole process is with the lenders and with APA at the moment?

[David P. Maxwell, MD & Executive Director]

Well, we have a -- what we call practical completion with APA, which is 68 terajoules a day stable rate. And that -- at that point, we flip into what we call a gas processing agreement, and we would be paying APA the processing fees that we've negotiated. Separately with the banks, when we move from what you might call the project facility into a more corporate facility, that's where the 90-day test comes into it, and you would only start the 90-day test after practical completion. So neither of those tests have been initiated at this stage.

[Gordon Alexander Ramsay, Analyst]

I guess the question is, sorry, are you in the process of negotiating changes to those or literally the plant works other than the H2S issue?

[David P. Maxwell, MD & Executive Director]

With APA? We're in conversations with APA. But -- and that's around a whole range of things, but we haven't specifically addressed the testing period and the characteristics of the test and those computations at the moment.

[Operator]

Your next question comes from Mark Wiseman with Macquarie.

[Mark Andrew Wiseman, Research Analyst]

I also had a question on the lending facility. I think everyone on the call is hoping that the production rates can overcome this issue and get to 68 terajoules per day. But in the event that this issue takes longer to work through, I'm just wondering is there a certain point in time where the lenders reduce the available credit from that $250 million to something lower if this issue takes longer than expected.

[David P. Maxwell, MD & Executive Director]

I'll say a couple of things and then pass across to Virginia. As Virginia reflected earlier, the lenders look at the gas contracts and the reserves on the ground. And if the production profile is resculpted in some way, and it could -- there's all sorts of things, could be slightly down for a longer period, it could -- with debottleneck, it can go up. It's going to be -- well, what's the appropriate recovery of payback to them of the monies and the profile against which we do that. And that's the approach that from the discussions that I'm aware of is being taken, and that's certainly the approach that we're taking. And maybe Virginia can update a little bit more on the schedule for that.

[Virginia Katherine Suttell, Chief Financial Officer]

Yes. I think what's important, I sort of absolutely agree with what David said there, which is the pathway forward. And I think having a view to a technical pathway forward will then inform what the facility will look like into the future. So as to time frames, we've obviously got discussions going on with both APA and our lenders to establish the technical pathway and then the appropriate financial model that reflects that technical pathway through to 68 terajoules a day. So those -- the determination of that is very much subject to being able to provide functionally the information to be discussed and to inform lenders on a view. So that is ongoing work at the moment.

[Mark Andrew Wiseman, Research Analyst]

Okay. And just on the gas sales agreements, do they contain a sunset clause or similar type of clause where beyond that particular date, the customer can cancel the contract?

[David P. Maxwell, MD & Executive Director]

They don't include a sunset clause as such. They have a start date, and we've been in continual communication with the customers around that start date. Hence, they have been very supportive of -- and we have sought and received very quickly the extensions of that start date, but there's no sunset clause as such.

[Mark Andrew Wiseman, Research Analyst]

Okay. Okay. And just the last one for me. Just on the Otway Basin, you announced the switch over to the Minerva, Athena plant, but I'm just having a bit of trouble squaring away the CapEx. In your guidance today, it seems like on a gross basis, the Otway CapEx would be sort of around the $70 million mark, which is a little bit higher than the announcement the other day. Could you just maybe explain the CapEx program at Otway and how that is squared?

[David P. Maxwell, MD & Executive Director]

No, there's quite a lot of other things in that CapEx guidance that we provided today. It's -- don't take all of that CapEx guidance as the Athena Gas Plant. The Athena Gas Plant is around $16 million. And then there's some what you might call working capital type works associated with some of the control technology, which is another $9 million, $10 million. And then there's work in there also for the development program, OP3D, which is moving through the concept -- sorry, moving through the select phase at the moment. That's got about $4 million. And then there's some drips and drabs, which take it up. So I think we guided to $30 million to $35 million, didn't we? Yes, $30 million to $35 million. Yes. So it's mixed up. About half of it is the Athena Gas Plant. The Athena Gas Plant look forward capital was as we indicated last week, $37 million for the project. It's on 100% basis, we're 50% of that.

[Operator]

Your next question comes from Scott Ashton with SHA Energy Consulting.

[Scott Ashton;SHA Energy Consulting]

Look, just on the back of Mark's question, I'm just trying to understand that the CapEx earmark for Minerva, you're not on the hook for any of the upgrade at Orbost. So your ability to spend money on Minerva won't be impacted with what's happening at Sole. And then just back on Sole, it's got nothing to do with sort of the mercury beds that are already in the plant. I mean I suppose the sort of start-up and commissioning issues are always a bit of a pain in the proverbial. So I suppose from a technical perspective, is the technology that's used to treat the H2S, I mean that's pretty simple off-the-shelf kit, is that something that we'll get a line of sight on soon once you're able to determine what's causing this actual foaming? So just back on the Minerva and then back on to Sole, but I just want to make sure that the cap -- you're not being sort of hamstrung on being able to upgrade Minerva. And I suppose just on the Minerva or to dance around here, that's a low pressure -- that was a low-pressure gas modification to Minerva, is that right? Because of the higher pressure gas from Casino.

[David P. Maxwell, MD & Executive Director]

Let me -- yes, that's right. Well, that's what we're doing. We're dropping the inlet pressure. That's one of the -- well, we're not dropping the inlet pressure. The Minerva Gas Plant has a lower inlet pressure than the Iona Gas Plant. In terms of Sole impacting the Athena gas projects, no, completely different, 2 completely disconnected, unrelated. And when we FID the Athena gas project, there was nothing that was going on in Sole that was going to -- that constrained us from what we're wanting to do with Athena. So from a financing point of view and a technical point of view, there's no linkages there at all. The Athena, the works at Athena, if I understand your question properly, are mainly around a short connection of the pipeline, the Casino Henry pipeline into the plant; the controls, moving the controls from the Iona Gas Plant across to the Minerva Gas Plant. And then there's a bit of a -- I'm not going to call it a full refurbishment, but a bit of a sort of an intermediate refurbishment, if you like, of Minerva Gas Plant or what we're now calling the Athena Gas Plant in there at the same time. So compressors, storage vessels, et cetera, all being surveyed, reviewed and life extensions being achieved. So it's a bundle of small projects that make up the Athena gas processing project. In terms of the -- your question on -- the short answer is no, it has nothing to do with mercury, the mercury recovery beds in the Orbost gas plant. And the more technical parts of that, I'll pass across to Mike.

[Michael Jacobsen, General Manager of Projects & Operations]

Yes. Thanks, David, and thanks, Scott, for the question. I mean mercury, the issues that we're having at the gas plant is around foaming. The health of the bacteria that is doing the breakdown is very, very strong. Mercury has a negative impact on the health of the -- of that colony of bacteria. So we're not seeing evidence of any type of contamination that is detrimental to the health of the bacteria. So mercury comes into that category.

[Scott Ashton;SHA Energy Consulting]

Okay. That's great. And I suppose just a more sort of thematic question here, given your business model has been sort of predicated on supplying a sort of portfolio approach to gas, would it be a fair comment to say that your customers, lenders, your offtakers are pretty comfortable, notwithstanding the problems at Sole, that you're able to supply gas out of other parts of the portfolio? Is that a -- would that be a fair comment on the company?

[David P. Maxwell, MD & Executive Director]

Yes. I mean I think in some respects, it's a question to -- that the customers themselves have to answer. They certainly take comfort that we can back up supply from other sources. And we are supplying AGL and O-I out of the offshore Otway at the moment. So that portfolio approach builds the relationship, deepens the relationship and mitigates issues if and when they may occur. So that helps, absolutely. I think it was one of the other questions earlier in terms of our approach to marketing gas. We don't view our approach to marketing gas as, hey, we've got gas to sell. What's the best price we can get today and not worry about tomorrow? Our approach is very much -- we view these as long-term relationships. And in order to get those to be successful for both sides, one has to listen to both sides and work together. And I have to say, we've been really pleased with the support that we've received from the customers in that context. And I think part of it is because we have not gone out -- when the opportunities presented itself in the past, we haven't gone out and tried to bleed the last cent out of the market.

[Operator]

Your next question comes from James Redfern with Bank of America Securities.

[James Redfern, Vice President]

Just had a couple of questions, please. So the liquidated damages is capped to $20 million, and that was all paid in the June half, and there's no more to be received. Is that right?

[Virginia Katherine Suttell, Chief Financial Officer]

There's been anyway…

[David P. Maxwell, MD & Executive Director]

It wasn't all paid in the June half. We hit the cap in the June half, but a lot of it was paid in the first half of this financial year. I think we had $9.8 million I think it was from memory, was paid in the first 6 months.

[Virginia Katherine Suttell, Chief Financial Officer]

Remind me of June.

[David P. Maxwell, MD & Executive Director]

Sorry, Virginia is going to correct me on that. What was the number there, Virginia?

[Virginia Katherine Suttell, Chief Financial Officer]

That's okay. No. I was just going to say so the $20 million has been invoiced at 30 June. So there's a 30-day payment down here. So there's 1 month of liquidated damages to be received from a cash perspective in this financial year.

[James Redfern, Vice President]

Okay. And then just in terms of the processing fee at the Orbost Gas Plant, just confirming there's no tolling fees paid until the plant is being commissioned is that right?

[David P. Maxwell, MD & Executive Director]

We are not paying a processing fee to APA at the moment for processing the gas. So what we're getting is that we're selling the gas at the spot price minus a nominal transportation charge.

[James Redfern, Vice President]

Okay. And just a few more, if that's okay. In terms of the drop in production at Casino Henry, you're talking about maintenance there. Any more color on the timing of the maintenance in terms of which quarters we should expect that downtime?

[David P. Maxwell, MD & Executive Director]

Mike, do you want to address that one?

[Michael Jacobsen, General Manager of Projects & Operations]

Yes. It's certainly the fourth quarter of the financial year, so that April through to June timing.

[David P. Maxwell, MD & Executive Director]

And that's linked in also with the connection into the Athena Gas Plant. We're trying to bring together -- we're looking to bring together, rather than 2 shutdown windows, 1 shutdown window where we -- so that activities are occurring at the same time and, thus, the minimum impact on production.

[Michael Jacobsen, General Manager of Projects & Operations]

That's right.

[James Redfern, Vice President]

So no issues with weaker gas demand or natural fuel decline being the drivers there?

[David P. Maxwell, MD & Executive Director]

No. No.

[James Redfern, Vice President]

Okay. And then one last one, if I can, please. Just in terms of the contracting gas for Casino Henry, I think you're trying to contract 5 petajoules for 2021 and beyond. Is there any update on how those discussions are going with customers?

[David P. Maxwell, MD & Executive Director]

So I'm going to pass across here to Eddy Glavas, who heads up the gas marketing, commercial and development side of it. But those conversations have -- are only starting to get underway now. But Eddy, do you want to add to that?

[Eddy Glavas, General Manager of Commercial & Development]

Yes. I think one of the common threads with our customers really, as David alluded to earlier, where the market sits at the moment has influenced their thinking. But the common thread across them all is that they want to see Cooper succeed and they want to see the project get up. They want -- they see these projects as valuable, given that they are long term and all those things help the conversations. We've been very transparent with them in terms of what's going on, which they're appreciative of. So moving the date further down our long-term GSAs, there are not many alternatives for suppliers in the longer term. It's a lot more uncertain from where else they can get their gas from, so that influences their thinking as well. So there's constant dialogue and looking at firming up the date as soon as we've got a good, firm line of sight.

[David P. Maxwell, MD & Executive Director]

And Eddy, the contracting -- the timing for the contracting of the uncontracted gas in the offshore Otway, which is part of James' question?

[Eddy Glavas, General Manager of Commercial & Development]

Yes, that's right. We'll do that in the remainder of this year and where that's part of the portfolio approach and as David said, some common customers across both of them. But yes, we'll do that across the remainder of the year, factoring in what we're talking about across at Sole.

[Operator]

Your next question comes from James Hood with Regal.

[James Hood;Regal Funds Management]

Yes, can you hear me?

[David P. Maxwell, MD & Executive Director]

Yes.

[James Hood;Regal Funds Management]

Just a few questions from me. Is there any update on the timing of the PRRT combination determination with Sole and BMG?

[David P. Maxwell, MD & Executive Director]

Virginia, would you like to pick that one up?

[Virginia Katherine Suttell, Chief Financial Officer]

I think I'd like to say, yes, absolutely, there's an update. I think it still remains uncertain from the government's perspective. They've indicated sort of some delays to sort of tranche 2 in the wake of everything that's going on in the economy at the moment. However, on our side, we're highly motivated to continue to lobby with the government to see tranche 2 legislated, to see decisions being made around our particular issue. So whilst on one hand, the government is saying that it's not on their radar, we are still actively seeking for it to be on their radar and to be on their radar now. And we are dedicating quite sort of a significant amount of resourcing towards driving sort of that position this year.

[David P. Maxwell, MD & Executive Director]

And what we have done is picked up the conversations in the last couple of weeks. And off the back of Cooper growing as a gas supplier into eastern Australia, I have to say there's a bit more -- I'm not going to say positive because it's always been positive, but there's a bit more urgency about, oh, yes, oh, hang on, yes, we should get to that. Whereas 6, 9 months ago, it was, well, we're going to do it, but we're going to do it, as Virginia is reflecting, in phase 2. I think one can look at it and say, well, here's an opportunity to help the development of more gas into eastern Australia at a time when eastern Australia needs more gas, the economy needs more jobs and the economy needs more projects.

[Virginia Katherine Suttell, Chief Financial Officer]

So we're actively -- just to sort of clarify a little bit what we're doing, is what we are trying to do is line up the government's position around energy policy and supply and the need to get supply into the market with the administrative sort of side of PRRT reform. So it's about bringing those 2 areas together in an expedient way.

[James Hood;Regal Funds Management]

Okay. And then in relation to VIC/P75, it says here on Page 7 of the quarterly that the license is granted up to 6 years and the first 3 years requires seismic reprocessing and G&G work. Does the last 3 years of the license include additional work commitments, e.g., are you going to need to drill a well on VIC/P75 as well?

[David P. Maxwell, MD & Executive Director]

I'm going to work off memory here. Andrew Thomas, who heads up our exploration and subsurface is not on the call. But I'm pretty sure there's a well in what we call the secondary term, which -- and whether we proceed into the secondary term is determined by what we see from the reprocessing in the primary term.

[Operator]

[Operator Instructions] Your next question is from Mark Wiseman with Macquarie.

[Mark Andrew Wiseman, Research Analyst]

Just a question on the Black Watch field that's now been brought on to production onshore. I just wondered whether there's still any sort of claim that you can make there and how you can recover any value as that field sort of goes through the production phase now?

[David P. Maxwell, MD & Executive Director]

Yes. Thanks, Mark. There -- I think it's fair to say that Beach and ourselves have a different view around Black Watch. And the fact that the field has commenced production according to the Beach reports doesn't change anything in that at all. Whether we did it before production or well into the field life, it doesn't change the rights that we feel we've got.

[Mark Andrew Wiseman, Research Analyst]

Okay. Is there any intention to drill a well on your side of the license?

[David P. Maxwell, MD & Executive Director]

We don't have any plans at the moment. We don't have any plans to drill a well on our side at the moment, no. But all of the maps that we've seen, including others' maps, clearly illustrate the Black Watch field extending into the acreage that Mitsui and I have -- Mitsui and Cooper Energy have and in the order of half of the field size in our permit.

[Operator]

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

[David P. Maxwell, MD & Executive Director]

Well, thank you, everybody, for participating. I realize it's getting on in the eastern states, which is where the bulk of you are. And what we will do is keep the market informed as we are required and as we have in the past on the progress of the company, and in particular, the progress of the Sole project. And we do appreciate all the questions we got. As I said at the start, we don't normally do calls around our quarterly. We felt this time it was important that we provide the opportunity for questions and everybody to hear the answers. But maybe after this, it's a conversation we'll be having internally, maybe it's something we should do after each quarterly. But that's a conversation that we'll have. So thank you, everybody, for joining. And if you've got any questions in the meantime, please don't hesitate to contact Don Murchland. Many thanks.