Cooper Energy Ltd

ASX:COE

Earnings Call Transcript 2022-Q4

[Operator]

Thank you for standing by, and welcome to the Cooper Energy Limited Q4 FY '22 Quarterly Report Conference Call. [Operator Instructions] I would now like to hand the conference over to Mr. David Maxwell, Managing Director. Please go ahead.

[David Maxwell, executive]

Thanks very much, and good morning to everybody listening in to the conference call this morning. This is David Maxwell, the Managing Director and CEO of Cooper Energy. I'm joined on the call this morning by some members of our leadership team as well.

I'm going to make a few introductory comments following the release of our June 2022 quarterly report this morning and then hand over to questions and answers. And I think that's really where the value is.

As I said, we released our fourth quarter results this morning for the 2021-2022 financial year. This is another set of strong results evidenced by record annual production, record sales volumes and gas prices in the June quarter, which were a record by quite a margin, together combining to deliver a significant increase in annual revenue to over $200 million, that's $200 million. There were a number of highlights in the fourth quarter. Firstly, the Orbost Gas Plant acquisition and the associated announcements. In June, the company announced the acquisition of the Orbost Gas Processing Plant. This is transformative for the company and delivers the next step in our Gippsland and Otway twin gas hubs supply position, underpinned by attractive Southeast Australia market dynamics and increasing gas prices.

Together, and at the same time as the acquisition announcement, Cooper Energy raised $244 million in equity and secured a $400 million underwritten debt facility. This strengthens the company's funding and liquidity position and supports an immediate cash flow uplift. Cooper Energy is now ideally positioned for the next growth phase and step change. And this is occurring at a time and in a market where new domestic gas supply is desperately needed by the community.

A few comments on revenue. Quarterly revenue was up 30%, and the average realized gas price was 33% higher than the previous quarter. This was an average realized gas price of $10.49 per gigajoule. The production and sales volume were marginally lower at 2% and 1%, respectively. The increases -- the increased revenue is a clear demonstration that Cooper Energy's gas portfolio is well positioned to supply surplus gas into a tight market and benefit from the current high spot gas prices.

A close look at the numbers will indicate a very different second half of the financial year compared to the first half. The improvement in Orbost Gas Processing Plant performance and the lower Sole term contracts maximum daily quantity resulted in a net surplus gas supply position for Cooper Energy from 1 January 2022. From that date to the end of June, we sold 1.1 petajoules of gas surplus at spot prices at an average price of $19.06 a gigajoule. It's also worth noting that in the second half of the financial year, we purchased 0.5 petajoules or 500 terajoules from third parties. This is 82% lower than the 2.8 petajoules of third-party gas purchased in the first half.

Now a few comments on the Orbost Gas Plant and the Phase 2B works. In April, the Phase 2B works were completed at the Orbost Gas Processing Plant, albeit a little later than expected due to the heavy rains, which curtailed access to the plant. The Phase 2B works included the installation and commissioning of a polishing unit, APA's cost and the installation of the Sulphur Removal Package, with tie-in and commissioning to be completed at a later time. This means completing tie-in and commissioning at an optimal time, balanced having regard to the market and customer permitted allowances, and thereby, designed to minimize the impact of any downtime for the commissioning of Phase 2B and the Solids Recovery Unit.

After experiencing some further improvement in the processing rates, and these are rates as high as 68 terajoules a day post the commissioning of the polishing unit, the polishing unit performance degraded and was taken back off-line in early June. At the moment, the plant is stable at between 55 and 57 terajoules a day on 2 absorbers. And at the same time, a root cause analysis of the polishing unit performance is underway and tend to be completed, we understand by APA.

A few comments on the offshore Otway and their gas hub. In May, Cooper Energy announced the growth plans for the offshore Otway. This includes the development of Annie as the first step to underpin the potential to deliver around 580 Bcf, that's approximately 580 petajoules of new cost-competitive gas. Let me just reemphasize the volume there, 580 petajoules or 580,000 terajoules. The Otway growth will be off the back of successfully upgrading and commissioning the Athena gas plant, which has secured processing infrastructure with available capacity and direct access to the Southeast Australia gas customers.

We refer to the next phase of Otway development as OP3D, or Otway Phase 3 Development, which will be based around the development of the Annie gas field, as I mentioned, together with a proposed low-risk short-cycle time exploration drilling campaign. This approach optimizes capital management and maximizes the financial return. The further development of Annie and as the undeveloped reserves resource in Annie will be considered for inclusion in a future phase.

Front End Engineering and Design, or FEED, is planned for the first quarter of this financial year, with the final investment decision, or FID, targeted for the third quarter as the March quarter 2023. First gas is targeted by winter 2025, and the project itself is subject to joint venture approval.

A few comments now on BMG decommissioning. Cooper Energy approved to the BMG abandonment project or the decommissioning project to proceed during the quarter. We have contracted the Helix Q7000 intervention vessel to perform the works and the works planned to plug the BMG wells by no later than the 31st of December 2023. In a separate campaign, we plan to remove the remaining infrastructure by no later than 31st of December 2026.

A couple of comments now on the Cooper Basin. In the Cooper Basin, together with Beach, 2 exploration wells in the area formerly known as PEL92 were drilled in the quarter. The first well, Bangalee, intersected approximately 4 meters of net pay in the target in the more reservoir, with minor pay in the Birkhead reservoir. The well was cased and suspended as a future oil producer, and we expect that to be online in this financial year FY '23. The second well, Hummocky-1 was plugged and abandoned after failing to encounter significant hydrocarbons in the primary target Namur reservoir.

It's been a busy fourth quarter against a backdrop of unprecedented spot gas prices, both globally and in the domestic market, which is where we operate and sell. Cooper Energy has demonstrated we have a resilient gas supply portfolio. We are able to manage periods of variable production and supply surplus gas at spot prices when the opportunities present themselves. The downside exposure to purchasing third-party gas has been largely mitigated. As a result, we upgraded our guidance for production, sales volume and underlying EBITDAX twice in the fourth quarter. EBITDAX for the 2020 financial year will be reported soon.

It's worth noting relative to guidance final year-end production of 3.3 million barrels of oil equivalent against the final guidance range of 3.3 MMboe to 3.4 MMboe. And as I mentioned, that was after twice tightening the range towards the upper end. Sales volume, 3.8 million barrels of oil equivalent against the guidance range of 3.8 MMboe to 3.9 MMboe. And again, towards the upper end of what was the previous range. Capital expenditure, $19.3 million against a guidance range of $19 million to $21 million, so at the low end of guidance for capital, which is where you'd like to be.

So on that note, happy to open the lines and take any questions to myself or others on the leadership team. Thank you.

[Operator]

[Operator Instructions] Your first question comes from Dale Koenders with Barrenjoey.

[Dale Koenders, analyst]

Wondering if you can just provide sort of like your updated thoughts on the outlook for Orbost processing capacity. How do we get through this, I guess, polishing unit issue? Is there any other CapEx that you're thinking needs to be spent to grow production rates from currently 55 to 57 TJs a day? How are you thinking about the frequency of absorber cleans? And where does that all get us to in a success case for average daily flow rate?

[David Maxwell, executive]

Yes. Thanks, Dale. I'll give a few comments, and then I'll ask Mike as well to add and to supplement anything that I say. What we found with Orbost is the plant operates best when it's stable. And getting it into the sweet spot or the stable state and then gradually inching up the rates. And we've seen that over the last couple of months. I mean, I mentioned we're currently at around 57 terajoules a day. Current cycle is 2 absorbers, 57 terajoules a day, 1 absorber per week down for 2.5 to 3 days for clean. And while that's happening, the plant running at circa 36 terajoules a day.

The next step is the return of the polishing unit, and we expect that to give us a small increase in incremental production, taking that 57 up towards 60, you'd like to think. And once that's determined, as I mentioned in the introductory comments is to commission the solid recovery package that's been installed, and we'd expect that to be, at the moment, probably in the March, April timing next year. And that will -- the purpose of that is to effectively remove the cleaning cycles. So you then be -- if you're running at that point, you're running at 60, then you're averaging 60 in cleaning once a year.

And then at that point, it's the time to then talk, well what's the long-term stable rate with the kit as it's currently installed and then look at the opportunity for incremental capital investment to get it up above that rate. And that's where we think about things like the possibility of a third absorber, and there are other options. That's the way that we're approaching it. The way that we like to think about it as bringing real discipline to the process and finding that the stable rates and then keeping the plant in that stable rate window. This is a plant that doesn't like wild fluctuations, and past experience illustrates that. Then Mike from an operations and technical point of view, what would you -- do you want to add to that?

[Michael Jacobsen, executive]

Yes. I think, David, just I think, as you mentioned, it's finding the sweet spot between the frequency of the cleans, Dale, and the rate. So what we're seeing now is, yes, the frequency is a little lower, or it's a little -- is more cleans than more often. But the rate between cleans is higher than it was previously. And as David mentioned, around that sort of 57 terajoules a day when both absorbers are on and then when we are cleaning around that sort of 36 mark gives an average of close to 50 terajoules a day.

When the polishers brought on, certainly, that will improve the plant stability. It will potentially stretch out the time between the cleans and also give us a slight bump potentially with the actual rate, which then all goes towards a higher average rate. So I think once that's back on, and we expect that to back online probably in around the August time frame, depending on the results of the root cause analysis that David mentioned and APA is currently doing, so we would expect a bump-up in the average production rate once that's brought back online.

[Dale Koenders, analyst]

Okay. And just a second question then just on the abandonment costs, $165 million. Can I confirm that's just for the first stage of wells program and if you had an estimate then for what the second stage of removing structural costs would be?

[David Maxwell, executive]

I can confirm that is for the first phase and includes significant contingencies and allowances. And we've provisioned for the second phase. And I'm going to pass over to Dan Young, our CFO, to make any comments around that. I don't think we've disclosed definitive numbers for the second phase, but we certainly have provisioned for it but pass over to Dan.

[Daniel Patrick Young, executive]

Yes, that number isn't a fair number at this stage in terms of releasing that publicly, but it's fully provisioned at this stage.

[Dale Koenders, analyst]

Can you give us any [indiscernible] in terms of...

[David Maxwell, executive]

To give you a little bit of a [indiscernible], my understanding, it is -- it's in the order of -- and Dan will correct me if I've got this wrong, but it's in the order of $20 million.

[Daniel Patrick Young, executive]

That's right.

[Operator]

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

[Gordon Ramsay, analyst]

David, just a quick question on the hazard license and the expected timing on that. I know you've previously indicated it could take up to 6 months. Can you just give a feel for where that stands right now?

[David Maxwell, executive]

Yes. It might take -- well, it might take a little bit longer than 6 months. 6 months would be what we would hope for. The work on that, the detailed work on that is just starting. And I think in the past, others have been through the process of -- in the order of 6, 9 months. I know Beach, my understanding is Beach at the major hazard facility assigned to them within 4. But at that stage, what Beach acquired is my understanding was Lattice, and Lattice had the major hazard facility license already.

So it was -- in buying the subsidiary, the Beach was acquiring the major hazard facility license and it was a slightly different process. They had same process but a slightly different arm of the same process that they had to go through. So I would -- I mean, 6 months would be a very good result. I think it could be more like 9. That is something that's going to become clearer to us as we get -- as the team that we've established for that gets more into the detailed conversations with WorkSafe Victoria and gets into the APA systems and processes and what's involved in moving them across to Cooper and the time involved in that.

And Mike, did you want to weigh anything to that?

[Michael Jacobsen, executive]

Yes, I think that's right. I mean, I think the process involves the regulator, and they have a very set process. So we're sort of in their hands to a large extent. And also really how much of the systems are we able to rely on that are currently at the gas plant. So we're working through that now with APA, how many of the operations and maintenance systems that they have on the ground there and we're able to roll over to Cooper Energy or do we need to start from fresh. So we're just getting into that now. And once we've got that plan together, we'll have a bit more clarity around the timing, but notwithstanding the fact that WorkSafe Victoria has a very set process, which we will follow, of course.

[David Maxwell, executive]

I will take the opportunity to add, though. We have, as we reflected in our announcement on the 20th of June, I think also in the quarterly, we've made offers to the operational staff and the technical staff involved with running Orbost, and we have had a very good response to those offers. So we expect almost all or all of the team to be coming across to Cooper. The bulk of them have already accepted to come across and work with Cooper.

[Gordon Ramsay, analyst]

Just last question for me. Just the recent announcement in terms of the state of the Victorian, Southeastern Australian gas market and concerns that Iona is getting drawn down. Is there any opportunity for you to possibly sell additional gas into that situation? Or is that pretty much being done already?

[David Maxwell, executive]

We are looking to sell incremental terajoules -- effectively, we're selling at the spot price to select term customers. So we are looking and we are doing that at the moment. We are not putting our own gas in storage. Storage tends to be used more by the customers, the AGLs and the EnergyAustralias origins of this world. We tend to put that gas into the -- directly into the market and get the spot price. So every terajoule we can, and I can assure you that guys -- and our operations team are focused on putting as many terajoules as they can in the winter into the market. And separate to that, we've had requests -- we have a request from the regulator to do what we can, to put as much gas into the market as well.

Might just make one comment to add to your previous question, Gordon, and draw the distinction between the time when the major hazard facilities licenses transferred from APA to Cooper Energy and our ownership of the plant. We take ownership of the plants just for the avoidance of any doubt. We take ownership of the plant at completion. So when we complete with APA in the very near future, we think ownership and get the economic benefit of that. And we will continue at that point to look to put as much gas into the market as possible at a time when the market needs gas.

Separately, APA is operating the plant on our behalf, and we're working collaboratively with APA through what we call the transition period, which is a period between when we complete and when the major hazard facility license has transferred across to Cooper Energy.

[Operator]

Your next question comes from Nik Burns with Jarden Australia.

[Nik Burns, analyst]

I've got a follow-up question for Mike. Just on the recent performance of Orbost and the sweet spot for the plant there. I guess we can figure on the AMO production data, as you pointed out, like every week or so, you're taking one absorber off-line and trying to find the best optimal performance for the plant. It looks like you're continuing to ratchet up the peak rate. And I think you've said, David, you're up 57 terajoules a day, but you still have this 1 week between absorber cleans. It's a plan to say how high you can get between absorber cleans or you're trying to extend the period between absorber cleans like if you could look back at the start of this calendar year, I think you're going 4-or-so weeks between absorber cleans running at around 50 terajoules a day, but now you're at 57%. But having to incur these higher rate of claims, and that's dragging down the average rate. Can you just maybe just expand a little bit more on what you're trying to achieve here? Is it a higher peak rate or to extend the period between claims here?

[David Maxwell, executive]

I'll ask Mike to take that direct.

[Michael Jacobsen, executive]

Yes. Thanks, Nik. Look, I think it's both, Nik. I think really what is the driving thing for us is the average rate. So if we can get a higher instantaneous rate with a reasonable frequency of cleans, that will give us a higher average. So I think the average that we're seeing at the moment based on what you just said there, the 57 terajoules and then the 36 terajoules when we are cleaning, is giving us that average surplus sort of 48.5 terajoules a day. And that is -- I mean, firstly, it's probably, I guess, on a long-term basis, it's probably one of the highest averages that we've seen on a longer-term basis out with the polisher. But it's reliable. I think that's the important point. It's stable. It's reliable. We know that we'll get it month-after-month.

So that's really the mix that we're trying to balance, our APA is trying to balance is to get that reliability, get that stability, but also get that average up as high as we can. Once that polisher comes back, the expectation is we'll have another tool in the toolkit to be able to improve the instantaneous rate, but also the stability and then the time between the cleans.

[Nik Burns, analyst]

Got it. And look, I just have a follow-up question on BMG as well. First of all, are you able to narrow the window at all, David, around the timing of that program? You've contracted the rig now. I think you've said you need to undertake that work by the end of the calendar year.

[David Maxwell, executive]

Yes. We expect the work to be undertaken in the October, November, December period of next year, maybe starting a little bit earlier than that -- and possibly September. And in terms of money out in the order of 1/3 goes out in the period up to December and about 2/3 goes out over the 3, 4 months after. So January through to April '24. The work -- we want to do the work in the back end of the spring coming into summer. We've selected this vessel, the Q7000, which is a vessel we identified a couple of years ago and selected it then. And for -- because of its ability to work through variable weather conditions and keep the time to as short as possible.

We looked at -- I know this is not your question, Nik, but I think it's worthwhile just explaining a little bit of the background. We looked at a whole range of vessels and the whole range of different configurations, and the Q7000 came out so far in front in terms of its ability to do the work, keep the vessel operating during variable weather periods. And that's the vessel we've gone with and expect the work program itself to be sort of in the order of 2 to 3 months.

[Nik Burns, analyst]

Got it. That was my next question about the duration. So that's clear. And the subsequent phase, I think you mentioned around the approximate cost for that. But has the -- have you -- do you have an agreement with AMO -- or sorry, [ AMO, not CMO ], in relation to what infrastructure needs to be removed? Is that being locked in?

[David Maxwell, executive]

Yes. The equipment that needs to be removed has effectively been locked in. And we've got the extra time to do that work, which allows us to identify a vessel of opportunity or a vessel which is in the region at some point. So we planned for it. We don't need a vessel like the Q7000 to do that work. We can do it with a lot smaller vessel and sort of vessels that are in the region a lot more frequently. And when there's 1 there with a bit of spare time, we look to contract that and use it.

And in terms of the time involved in that, Mike...

[Michael Jacobsen, executive]

Yes. I think it's -- this is a minor piece of work. It's probably less than a month to work offshore and the commitment or the obligation is by the end of 2026 that work needs to be done. And as David mentioned, when there's a vessel at around that time frame that is in the area of working for another operator, we would take that opportunity to do that work, which is the most cost-efficient way to do it.

[David Maxwell, executive]

I'd point out that -- and I'm sure you've drawn the ends together, but that's also around the time that we'll be thinking ourselves of the next campaign in that part of the world with OP3D. And I expect vessels to support that and others who are in the same campaign or same room club with us to be in the region for 18-, 24-plus months. So we're expecting the availability of vessels around that time frame, and we'll fill in a bit of spare time for them.

[Nik Burns, analyst]

Got it. I guess, that's on that point -- sorry, go ahead.

[Michael Jacobsen, executive]

Sorry, Nik, I was just going to add to David's point. I think certainly, this is an order of magnitude less than the wells in terms of complexity and in terms of cost. It's an order of magnitude less than what we have in this first campaign with the wells.

[Nik Burns, analyst]

Indeed. Just on the, I guess, the potential in the BMG fields, David. You talked about potentially targeting Manta Deep, et cetera. Has there been any progress on progressing a combination certificate for that if you're going to tie that back to Orbost at some point?

[David Maxwell, executive]

There has been progress internally, and there hasn't been any progress with the different arms of government yet. We are putting all our bits and pieces together, and I expect in the next 6 months as a part of planning the next campaign, we'll be in talking to the different departments in Canberra around the combination certificate, the credits available to BMG and the ability to use them together with Sole. That's the conversations that we'll be having, I expect, in the next 6 months with Canberra. And we're getting all our bits and pieces together for that.

[Operator]

Your next question comes from James Bullen with CGS.

[James Bullen, analyst]

Just curious around third-party purchases. You've mentioned in place that you've put in arrangements around storage, et cetera. What could we expect that 0.2 petajoules to shrink to on a go-forward basis?

[David Maxwell, executive]

We've got ourselves in a -- thanks, James. We've got ourselves in a place now where we expect that to -- on the proviso that the plant can operate stably to the sort of rates that Mike is talking about averaging 48-plus terajoules a day. We've got ourselves in a place where we don't think we'll be needing any third-party gas to back up our commitments to our customers. We haven't in the last 2 months had to draw around that. We are using 3 methods, sort of 3 sort of pathways, if you like. One is we park gas on the EGP for a period. So in the period when we were overproduced, we'll put some gas into storage on the Eastern gas pipeline, and then draw it down when the absorber is -- when 1 absorber is down for a clean. Secondly is we have with some customers arrangements where we can time swap. So we'll oversupply on a day and undersupply on the next day to manage the -- to maintaining their nominations over 2-, 3-day period.

And then thirdly, we have arrangements with some other gas suppliers where we can, if needed, acquire some gas from them. So we've got those 3 in place. And almost that's the order in which we draw off them. And I'm expecting it to be very close to 0 draw on the spot gas market or through third-party gas buying it off the spot market.

[James Bullen, analyst]

Great. That's good news. And just in terms of Annie and thinking about when you could be out in the market looking for contracts and what you're hearing in terms of long-term gas contracts?

[David Maxwell, executive]

You're talking about contracts there?

[James Bullen, analyst]

Yes.

[David Maxwell, executive]

We are out in the market now. We are active now with customers and we're receiving a lot of interest. No surprise. But I would expect on the basis of conversations that are underway, it won't be that far away that we'll be announcing the gas supply arrangements to support OP3D.

[James Bullen, analyst]

Any color around where long-term pricing is?

[David Maxwell, executive]

Yes, I don't want to put the customers in the difficult spot. Certainly, the customers are showing appetite for prices higher than what we've seen in the past. You look at our average price for the June quarter of $10.49, I think that's a mix of term contracts and spot. I think that gives you a reasonably good steer.

[James Bullen, analyst]

Yes.

[David Maxwell, executive]

And sorry, I would also say that independent reports prepared by EnergyQuest and others are talking about take-or-pay contracts, term contracts or medium-term contracts. It's contracts for 4, 5, 6, 7 years in that sort of range as well.

[James Bullen, analyst]

Okay. And just final question. Now that you are taking control of the Orbost Gas Plant, it's obviously [ SIBHP ] do have some smallish discoveries that might make more sense going through that gas plant and really extend the life out beyond just Sole? Are those things that you're looking at or have there been any level of interaction about whether those might fit better within the Cooper portfolio?

[David Maxwell, executive]

Yes. I mean, I think you're probably referring to SA Woodside.

[James Bullen, analyst]

Sorry, yes.

[David Maxwell, executive]

Yes, yes. The short answer is yes. I'll say a couple of things, and then I'm going to ask Andrew Thomas, to talk a little bit more about it. We've obviously had to call our jets a little bit and the Gippsland in the last 18 months, 2 years. The important thing is to get the Orbost operating stably and pushing as much Sole gas into the market as possible. While that's been going on, I mean Andrew and his team haven't been idle, and I'll leave him to talk about some of the exploration opportunities that we have there.

But separately, we are also looking on what you might call Gippsland regional basis. And Andrew can talk about seismic acquisition and processing of that. And looking at [ William ] -- how we might optimize across the Gippsland. And that's what resources are best processed through an expanded Orbost Gas Plant, and we're very keen to put as much gas to Orbost as possible, whether it's our gas or third-party gas provided it on sensible commercial terms. And at the same time, there may be large discoveries that could be closer and better to go through the Woodside facilities, in which case there has been conversations in the past around that. But look, Andrew, do you want to talk a little bit to the work that's been going on getting ourselves ready for the next wave of growth in the Gippsland?

[Andrew Thomas, executive]

Yes. Thanks, David. I think it's fair to say over the period of the last 12 to 24 months, we've been continuing subservice studies sort of in the background, not really been the highlight of news, but we have accumulated a very good portfolio of exploration opportunities around our Manta hub area. So they're all within a fairly close range in 5 to 10-kilometer tieback to a Manta development. We're embarking on remapping the new CGG seismic in the region. And our expectation is that, that will provide us with an uplift of even more exploration potential. And that's actually been communicated to us by others that this new seismic is giving people a bit more hope on possibilities for the future that may not have been readily identifiable with the previous 3D data in the basin.

So I think as we push forward, we're going to continue to look at what we've got and evaluate new possibilities to build up a fairly significant prospective resource portfolio on that northern plant of the basin.

[David Maxwell, executive]

I'd add also to what Andrew said, James, that we have received a number of inbound inquiries from parties wanting to work with us on the Gippsland. That's obviously something we're in a position now to have a talk further about.

[Operator]

Your next question comes from Mark Wiseman with Macquarie.

[Mark Wiseman, analyst]

Thanks for the update today. I just had a question on the spot gas prices over the rest of the winter season. AMO clearly signaled yesterday that they're pretty concerned about the storage drawdown, and obviously, the cold weather is causing pretty strong demand. It seems like they need to do something. Just wondering, as we try and forecast your spot gas revenues over the next quarter, do you think there's a possibility that, that administered price cap gets lowered? Or any other sort of restrictions get put in place that would mean that your realizations could be lower?

[David Maxwell, executive]

I don't think the 40 cap will be reduced. One needs to understand how that 40 cap has worked out. I mean, it's the sum of prices over a period. And then if that averages a certain level, then the cap of 40, which is a reasonably high price is imposed. I mean they have yesterday, because the average wasn't what it was. It was -- you saw the day before, Eddy will correct me if I'm wrong, but I think the Sydney price was up in the mid-50s. So I don't think you'll see the cap lowered. But what I do think you'll see this increasing asks of gas producers to put as much gas as possible into the market. So that cap is a function of tight supply.

And I think what you will see and as likely is asks of, for example, the Gladstone producers to put as much gas as they possibly can into the market and then the constraint becomes pipeline capacity. So that's -- we don't -- we're not expecting to see an enforced lowering of the cap.

I'm going to ask Eddy Glavas if he wants to add anything to that and what we're seeing in the gas market.

[Eddy Glavas, executive]

Yes. Thanks, David. And I think, just quickly, there's 2 good barometers in terms of how long this could go for. And obviously, one's Longford. They've been going at some quite high rates recently through the winter. And the other one is Iona, and that's been publicized. It's getting drawn down as it did last winter. So how -- once that number, their storage number starts to come up, that's gas being injected back and we expect usually to see that towards the end of winter. So I think they are the 2 key parameters to see how long that [ 40 cap ] is going to last. But yes, David, you're right, the Sydney price was 55% as it is today.

[David Maxwell, executive]

Will you have a -- we received -- Mark, we received -- we received the notice from the regulator AMO last week, which has been -- I see you got into the press in the last couple of days. But the gas industry was being asked to put as much gas as they could into the system last week.

[Mark Wiseman, analyst]

Right. Can I just ask 1 more question just on the Otway. You talked about the 580 petajoules of potential there. I just wanted to clarify, presumably, these 2 to 3 exploration prospects will be drilled in the same campaign as the Annie well. Beach in there quarterly this morning is just saying that because of REIT unavailability, they're actually deferring [ Yola West ], which was interesting. I assume that we're talking about different categories of rigs here. Could you maybe just clarify when that drilling will take place? Does that explain...

[David Maxwell, executive]

Yes. I can't speak for Beach and their drilling. What I can say and what we know is that there's a rig club, which has been established, and Beach is a member of that. And we are looking to put in place that curve, as I understand, is looking to put in place a campaign, which will go for at least a year and probably longer than that with firm wells, and we would bid a certain number of wells into that club within a series of options.

So if the rig is in the region for 12-, 24-plus months, then the parties will work out, which swaps they're going to take in that firm campaign. So we see the opportunity for working and there's a rig club in place, which includes 3, 4 parties, and we see the opportunity for a bit of flexibility about the timing of those wells. Obviously, for us, it will be anchored around Annie, I mean, 2 or 3 exploration wells and where they were in that 24 months is something that we and the other members of the rig club would work out. Does that answer your question, Mark?

[Mark Wiseman, analyst]

Yes, I think so. So it's definitely not this coming summer period. It would be '23, '24 summer...

[David Maxwell, executive]

No, no, no. We're talking, Andrew -- Andrew Thomas, we're talking '24. And Andrew, correct me, if I've got '24 onwards, mid '24 onwards, and Andrew, correct me if I've got anything wrong there.

[Andrew Thomas, executive]

You're right, David. I mean, my understanding is the rig clubs talking about bringing -- rigging in the back end of next year and then as you say, 12 to 24 months after that, that there will be conversations about the order of March of the drilling and where people fit in.

[Operator]

[Operator Instructions] Your next question comes from Saul Kavonic with Credit Suisse.

[Saul Kavonic, analyst]

Sorry, hello, can you all hear me?

[David Maxwell, executive]

Yes, I can hear you. I can hear you, Saul, so I think that...

[Saul Kavonic, analyst]

I just had a quick question really about OP3D and JV dynamic there. What's the indication you're getting from your JV partner, Mitsui, in terms of their preparedness to go along with you in the OP3D campaign because you've obviously seen Mitsui withdraw from kind of these gas campaigns, for example, with Trefoil and Beach.

[David Maxwell, executive]

Yes. Look, I can't speak for Mitsui. All I can speak for is Cooper Energy and our interactions with Mitsui. I would say that Mitsui, ever since we got involved in this joint venture has been a very constructive joint venture participant. But in the time frame that we've been in the joint venture, Mitsui's own business has changed materially. Obviously, now they are involved in larger gas projects in Australia, and they're the operator. And that tends to -- it's very natural for that sort of activity to get more retention.

Mitsui's advice to us is that they are supportive of growing our business in the Otway. What we haven't agreed and aligned on with Mitsui at this point is the timing and how we will go about that. We separately have been spending our own mines to, well, if our timing is different, how do we manage that and it would perhaps been no surprise that we've had a lot of inbound inquiries from people willing to work with us in the Otway. The economics on a return basis are so compelling. It might not be as material as TCFs and other places, but the economics are very compelling and particularly in a market which is what we're seeing at the moment, attracting a lot of interest.

So I guess if I was going to put that into 2 sentences, it would be, we work very closely with Mitsui and continue to do so. But at the same time, we're thinking about how to maintain schedule and move things forward. And I would say that Mitsui was there together with us in acquiring the Athena Gas Plant and redirecting Casino, Henry and Netherby through the plan with a view to that being, but the hub around which we grow our Otway business. So I haven't answered your question whether yes or no, but I've hopefully given you a sense of how we're thinking about it.

[Saul Kavonic, analyst]

Appreciate it. That's great disclosure. I guess, my second question is, in the event that Mitsui weren't to participate and you weren't having a partner there, how then should we think about the funding availability and the timing for Annie in the subsequent OP3D campaign?

[David Maxwell, executive]

I don't think that's something that you have to be exercising a lot of thought about at the moment. Simply put, the economics are so compelling a take-or-pay contract together with a bit of -- together with the debt facility can cover it. I don't know, Dan -- Dan Young, our new CFO, would you like to make any comments on that? You've been engaged with the banks as a part of the restructuring of the facility.

[Daniel Patrick Young, executive]

Yes, I think that's right, David. I think the investment proposition is very, very compelling. And, you know, the company has a very strong financial flexibility, and there are a number of options, as David has also laid out. So we don't see that as a -- in that event, we think there are a number of other avenues that mean that timetable can be maintained.

[Saul Kavonic, analyst]

Sorry, just to clarify, I'm looking at your funding for growth chart that you put out as the part of the raise in the Orbost acquisition. On that chart, you've got your share of Annie CapEx, which would leave you with a cash pile of between $100 million and $150 million by the end of FY '25. But if we double that share of Annie CapEx, then that would take your kind of net surplus capital linked to negative territory, like if I just look simply on that chart. So what would that be [ missing there ] in terms of one of your...

[David Maxwell, executive]

I'll put you on the right track, Saul. That's a relative chart and you have to look at the start point. If we own 100% of Casino, Henry and Netherby, obviously, the revenue side would be quite a bit larger as well. Separately, the depth available would be larger as well. And the numbers that -- that chart would look quite different if we owned 100% of Casino, Henry and Netherby.

And separately, if you have a close look at that, you'll see some of the assumptions, and that are very, very conservative. For example, a spot gas price of $10. And if you're owning and the rates that we're assuming for Sole are quite a bit down from where we are and what Mike spoke about, and yes, the numbers were quite different if you were to put 100% into that.

[Saul Kavonic, analyst]

All right. Understood. So the rig gets bigger when the green gets bigger too, and you get that offsetting.

[Operator]

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

[David Maxwell, executive]

Look, I'll just add a couple of things. Thank you very much for everybody who's joined the call that the second half of the year has been a complete contrast to the first half of the year for Cooper Energy. And I hope people are now starting to see just how we've got ourselves positioned. I'll point people to the step up in average gas price, notwithstanding the bulk of our sales still went into our take-or-pay contracts, which underpin the development of Sole. Every extra terajoules we produce is a terajoules that can be sold into the spot market at spot prices -- sorry, can be sold to customers at spot prices. And our focus now is very much on maintaining stability at Orbost, gradually getting production up and then bringing and then advancing into the next growth phase around both the Otway and the Gippsland.

So thank you, and we will be issuing, I expect in the next month or so, our final numbers for the year and where we landed on EBITDAX, which is the 1 number, but we have guided to date to the top end of that range. And everything that we're seeing is that's going to be affirmed plus. So on that note, thank you very much.