Cooper Energy Ltd

ASX:COE

Earnings Call Transcript 2021-Q1

[Operator]

Thank you for standing by, and welcome to the Cooper Energy Limited September quarter update conference call. [Operator Instructions]I would now like to hand the conference over to Mr. David Maxwell. Please go ahead.

[David P. Maxwell, MD & Executive Director]

Thank you very much, and welcome, everybody, to the call this morning. The Cooper Energy September quarterly report is a little later than usual for Cooper Energy and the reason for this is that we wanted to include the latest on the Sole Gas Project. I'll provide a quick summary overview, and it will be pretty quick. And then we can proceed straight to questions.I'm joined this morning by the leadership team, which includes Virginia Suttell, our CFO; Mike Jacobsen, who heads up Projects and Operations; Eddy Glavas, who heads up Commercial and Development; Iain MacDougall, HSEC and Technical Services; Andrew Thomas, Exploration and Subsurface. And of course, with us, we've also got our Investor Relations lead, Don Murchland.A quick summary of the September quarter and the events since. Production was up 10% compared with the previous quarter to 0.61 million barrels of oil equivalent. This reflects the contribution of Sole production in the commissioning phase. The revenue for the quarter was maintained at some $24 million, the same as the previous quarter. Again, this was due to the contribution from Sole as the oil revenue fell by about 15% and the growth in sales resulted in revenue, essentially unchanged, and that's the gas sales revenue essentially unchanged. It was a lower gas price, which reflects lower spot gas prices during the quarter for the Sole commissioning gas.We took the final investment decision for the Athena Gas Plant upgrade, and the project is 17% complete and the work on site has now started. The Athena Gas Plant upgrade is on track for processing Casino Henry gas through the Athena plant in the September quarter of next year, 2021.On the 12th of October, we announced our CO2 emissions commitment, which means that Cooper Energy is the first carbon neutral gas producer in Australia. This is as a consequence of our partnership with Biodiverse Carbon, which is part of Greening Australia.We're offsetting all our scope 1 and all our scope 2 emissions and the controllable scope 3 emissions. Important to us is that we're not just buying credits, but we're investing in a high-value native revegetation project in a region of international -- which is internationally recognized for its environmental significance.Importantly, after extended delays to the Orbost Gas Processing Plant upgrade, which is managed by APA, in August of this quarter we announced the signing of the transition agreement. The transition agreement provides a framework for Cooper Energy and APA to work together to enable firm gas sales to commence and practical completion of the Orbost Gas Processing Plant as soon as possible.The transition agreement was effective from the 1st of July. And then late yesterday, within the framework of the transition agreement which we signed in August, we and APA committed to additional works at Orbost designed to increase the sustainable processing capacity at the gas plant. These works to start in mid-November will take some 3 weeks and we've agreed the basis for Cooper Energy to start the firm gas supply agreements from the 1st of December and the 1st of January. The rates at 1st January being equivalent to the annual contract quantity of 19.75 petajoules a year, which is some 54 terajoules a day annual contract quantity average.It is planned that term gas supply agreements total then steps up to the full 22 petajoules a year, which is some 60 terajoules a day annual contract quantity from January 2021, at which time the full volume of all of the existing term gas supply agreements are initiated. So on this basis, we're starting nearly 90% of the total volume of the term gas supply agreements by 1st January, 2021, just some 2 months away.This is a key milestone for the company, what many people have worked hard to achieve and it realizes the step change in production and revenue attributable to the Sole Gas Project, albeit later than we had hoped and later than we had originally planned. We wish to acknowledge the support and patience of our gas customers, whose commitment to the term contracts enabled the Sole Project to proceed.It's been disappointing that supply could not start as scheduled, but we're now delighted to -- delighted that we've got the commencement very much within sight. Importantly, all the terms of the gas supply agreement other than the start dates are unchanged from when they were negotiated some time ago.And finally, a plug. We have the Cooper Energy Annual General Meeting on Thursday the 12th of November. This will be a virtual AGM and provides the opportunity for all shareholders to attend online, ask questions and listen to our plans for the next year or 2.That completes the brief summary of the quarterly and announcement since, and I'll now hand back to the moderator to facilitate questions.

[Operator]

[Operator Instructions] Our first question is from James Redfern of Bank of America.

[James Redfern, Vice President]

My question is really around changes to agreement and commencing the firm gas sales agreements with Sole. So I guess, this is working on the assumption that the modifications in November resolved the issues at the Orbost Gas Plant and at the plant producing the 54 terajoules a day. And I guess in the event that it doesn't, will Cooper Energy then have to buy gas in the spot market to meet obligations? And so I guess, worst-case scenario, your production in December and January is, say, 30 or 40 terajoules a day, Cooper Energy has to buy the balance in the spot market. Is that how we should think about it?

[David P. Maxwell, MD & Executive Director]

The way I would -- it's partly right, not completely. The APA and ourselves worked very closely over the last couple of months on what might be -- what will be the sustainable rates. There have been a lot of testing done in the plant in different modes of operation over the last couple of months and that gives APA and ourselves a strong baseline before the Phase 2 work, so before the works in November.And off the back of that, we have together developed profiles, which we're both very confident about. And then separately, we, Cooper Energy, have -- will be putting in place backup supply arrangements in the event that there is an interruption, if a part of the plant was unable to provide on a day. We don't expect that to be called very often. And in the event that we do call the backup supply arrangements, we won't be paying a processing tariff to APA.And then I think important in this is we've always said that we are running a portfolio of gas contracts. We've got over in the Otway, Casino Henry, and we've got a good portion of that gas uncontracted for next year. Expect to see an announcement on some contracts for that gas. But we've got the ability with that gas to play the portfolio game and fill a gap, if you like, if there were to be an interruption from the Sole plant.But it's not quite as simple as -- well, on a day if it can't come from Sole, it comes from the spot market. And we are putting some -- we are putting a range of backup arrangements in place. And the -- in essence, the economics -- or the economics or the -- we kept whole -- to all intents and purposes, we kept whole as to whether the gas is coming from Orbost or from somewhere else into the Sole gas contract.

[James Redfern, Vice President]

Okay. Okay. All right. That makes sense. And then maybe just if you could please just confirm what the recent average realized price has been for the Sole gas in the spot market? Are you still sort of closer to $3, $3.50?

[David P. Maxwell, MD & Executive Director]

No, I mean, we've -- well, recently, I haven't had a look, this morning. But it's been -- it has had a 5 in front of it, and we got into the 6s, got into the low 6s this week and the week before. So it's been nudging up quite progressively. I don't know if Eddy Glavas has got today's prices or the prices in the last couple of days.

[James Redfern, Vice President]

Yes, I thought that -- I thought your realized price is -- net of transportation costs of $1.50 or thereabouts.

[David P. Maxwell, MD & Executive Director]

No -- yes, that's right. Well, that's the gas price. And then there is a small reduction for transportation, but it's certainly not $1.50. It's a lot smaller number than that. We are selling into the spot market at the moment, yes.

[Operator]

Next question is from Peter Liu of Credit Suisse.

[Peter Liu, Research Analyst]

David, my first question is a follow-on James' question. So in your response, you mentioned you established some sort of strong baseline scenario in terms of Orbost sustainable rate structure, right? Is that, the 55 TJs per day, implied by the 19.75 petajoules a year starting in 2021?

[David P. Maxwell, MD & Executive Director]

No, it's got the ability to go higher than that. The rate that -- the 54, 55 is simply the 19.75 petajoules a year divided by 365. And then on a day, the rate -- there's the ability for the rate to be higher or lower than that. And then we've got maximum. So then, typically, the maximum is 10% above the annual average.So if you were to take that -- so the take-or-pay level at 19.75, I think, is just on 52 joules a day. The annual average, I think, is around 54, 55. And then the maximum is around 60.

[Peter Liu, Research Analyst]

Right. My next question is, in the quarterly report, you also mentioned the possibility of reaching 58 TJs per day full nameplate capacity by doing this parallel processing reconfiguration. But you also mentioned that, that would require ongoing maintenance for Sole. So can you provide some guidance in terms of what production impact of the ongoing maintenance might be?

[David P. Maxwell, MD & Executive Director]

Not at this stage, but it's likely that it would only be a couple of days and once the Phase 2 works are complete, once the November works are complete. So we've got a baseline now. And the November works are designed to do a few things, run the plant in parallel modes. And we know that we can run both absorbers at 34 terajoules a day. Two times 34, 68, that's the maximum nameplate.And then in the event that there is -- and sorry, and then there's a part of the work -- there's also activity to reduce sulfur buildup and reduce foaming, outside of operating just in parallel mode. And we'll get an idea once the plant is up and running from early December as to what the long-term sustainable will actually be post the Phase 2 works.The commitments that we have made and what we're talking to customers about is what we know we can do now before the Phase 2 works. What I mean by that is knowing what the Phase -- knowing -- by configuring the plants in parallel, what we know we're going to be getting out of it. Then there's a number of other activities in the Phase 2 works which are designed to further improve it.Now what are the impact of those further improvements, we don't know at this point. We don't know the baseline, the new backline. But we know what the baseline definitely is going to be, and it will be higher -- be above that.

[Peter Liu, Research Analyst]

Okay. And my last question. Just going back to your carbon emission initiative, you mentioned this initiative, but what about the cost? Like how should we think about the process having this emission offset going forward?

[David P. Maxwell, MD & Executive Director]

Yes. I'll say a couple of things and then ask Iain MacDougall to add some comments. We reviewed a wide range of projects and we reviewed them against a range of different criteria and cost was one of them. We're not disclosing what the cost is, but what we can say is that the cost is a lot less than it would cost us to buy the credits on the market. Ian, would you like to add anymore around that in the way we thought about it?

[Iain MacDougall, General Manager of HSEC & Technical Services]

I think that summarizes it, David. It is -- they are what I call Australian carbon credit units, which are units that we can use for compliance purposes. It's a low-cost initiative, but it's something that actually delivers a significant outcome for us in this space.

[Operator]

Our next question is from Adrian Prendergast of Morgan Financial.

[Adrian Prendergast, Senior Analyst]

You have a very good progress there. Thank you for the update today. Just, I guess, a further question looking to next year. If the Phase 2 works are successful as designed and you're producing at least 54 terajoules per day, does your focus then shift to still trying to squeeze out incremental fixes to counter the foaming? Or is it easier and better value returning to move on to more typical debottlenecking work first?

[David P. Maxwell, MD & Executive Director]

The 2 projects will happen in parallel. Yes, there's -- the root cause analysis work still has to -- there's a lot of analysis and testing going on. Until that's complete, we're not doing it justice. And it's important that we do complete that together with APA or led by APA.And then the debottleneck work is in parallel. Where it makes economic sense to increase the capacity of the plant -- I mean, we're confident we'll get to 68. There's a question of exactly when. We think it will be reasonably soon after the Phase 2 works. And then debottleneck gives us the opportunity to further increase capacity above the 68. So the 2 will happen in parallel.I don't know if Mike Jacobsen has got anything he wants to add to that.

[Michael Jacobsen, General Manager of Projects & Operations]

Yes. Yes, I think it is a question of really economies of what is -- where's our best bang for our buck. Certainly, the root cause analysis is ongoing. We feel that we're getting closer to that. It's a very -- it takes a lot of time to get the samples and get them tested and to analyze. So we feel that we're getting closer on that and it will be a question really of what is the most economic next part of the modifications, is it to deal with the root cause or, as you say, to focus on reducing the foaming. So that's where we're at. We need to finish the root cause. We need to see how the plant comes back after Phase 2 and see what sort of rates -- if we can get close to 68 at that point, then that's great. So it's really a case of getting those results and then making an assessment from that point.

[David P. Maxwell, MD & Executive Director]

I think just one comment, though, I'd add that picks up from an earlier question. The commitments and the undertakings we're making to our customers is what we know we can deliver off the plant as it is in parallel mode based on all the work that's been done today. And we are expecting that rate to be higher. But until we -- until it is confirmed as higher, we can't lock it in.

[Adrian Prendergast, Senior Analyst]

Certainly, a very good start for work. We're setting a very high proportion of nameplate, already at minimum commitment. So we're very, very happy.

[David P. Maxwell, MD & Executive Director]

No, I think -- and I think it highlights one of the things that we've been talking about for quite some time now, which is a portfolio approach to our gas business and working with the customers on the portfolio approach.

[Operator]

Our next question is from James Bullen of Canaccord Genuity.

[James P. Bullen, Senior Energy Analyst]

I just have a question around the banking syndicate. I'm assuming they've been kept fully informed all the way through this. Do you expect post this announcement that there will be any changes to the facility at all?

[David P. Maxwell, MD & Executive Director]

I'll say a couple of things and then pass across to Virginia, who together with our advisers have been working very closely with the banks. Firstly, your assumption that we've been working closely with the banks is dead right. They have been receiving independent technical reports as well as all the information from ourselves, so they are absolutely full bottle on what's going on.And obviously, the Orbost plant being a bit later than planned, that has meant that some of the dates in our financing facility had to be revisited, and I'll leave it to Virginia to talk about that. It's always been our intention that once Soles online that we would refinance, restructure the finance facility, and that hasn't changed. And the start of production, initiating the gas sales agreements is a key milestone.And then they're pretty soon after that, ourselves and the banks will be in conversations around reworking, restructuring the finance facility. Because essentially, it's a project facility and we would -- and with the opportunity to move it into a bit more of a corporate type facility, which is what we and the banks had always had as our intention.In terms of keeping the banks informed and where the banks are at, at the moment, Virginia, would you like to add that?

[Virginia Katherine Suttell, Chief Financial Officer]

So I guess to your question, James, Cooper has met all the information requirements that are from the banks. They've been kept fully informed all along. And so we had an agreement to provide information on an ongoing basis. And there's some time lines with respect to Orbost Gas Plant performance, and we've done that.To your question does this announcement mean that we should be restructuring the facility. I don't think this announcement per se lends itself to that. I think the Phase 2 work is an indicator who -- once that completes and the outcomes of that are fully known, that certainly lends itself to having a look at the facility terms, particularly as there's a significant portion of value in the full reserves and the gas sale agreement that sits outside the current contract of this, really.

[James P. Bullen, Senior Energy Analyst]

Right. And you're electing not to add any additional absorption capacity. I'm just wondering whether that was considered and why it was excluded from the shutdown.

[David P. Maxwell, MD & Executive Director]

Well, I'm not sure that's a correct statement, James. We -- well, certainly, we're not adding any absorption capacity in this shutdown, but we haven't eliminated that as an option and there's a range of alternatives within that. There's quite a bit of work to be done to work out what is the optimum. Mike, would you like to...

[Michael Jacobsen, General Manager of Projects & Operations]

Yes, that's right, David. James, it is a question of is another absorber the right approach. We don't know that. We need to see how the plant comes back after Phase 2. And putting in a second absorber -- sorry, a third absorber -- it is a big piece of equipment and we don't -- there's a longish lead time. So -- and so to make that investment not really knowing that it's going to work or have the desired effect. We really want to see the results from the root cause analysis and how the plant comes back in December after Phase 2.

[David P. Maxwell, MD & Executive Director]

And so let me think about that. There's also a different -- some variations, if you like, on the theme. I mean we've referred in the past to the possibility of a smaller unit of -- effectively a polishing unit or a smaller unit just to clean up because you've got a much lower H2S level, and that's certainly an option as well. And realizing that the plant is operated and managed by APA and they are working closely with ourselves and our people on that. I wouldn't assume it's eliminated at all.

[James P. Bullen, Senior Energy Analyst]

Great. And then just stepping back a bit, I guess. A lot of change in the gas industry in Australia. Can you conduct M&A activities when you don't have Orbost running up near nameplate?

[David P. Maxwell, MD & Executive Director]

We don't have any M&A activities. And if you're talking about ourselves, we've not announced anything. But as a general statement or the way that we approach our business -- and we've got growth opportunities around -- we've got growth opportunities in the portfolio in the Gippsland. And our business is driven very much by a fair strategy, which is a bit of a stuck record, I think, that has 3 criteria around the existing -- around the Australia gas business, which is low end of the cost curve, in production -- or able to be in production within 5 years and we can add value to the assets and/or the assets can add value to us.One can put a sort of a fourth criteria or a fourth play in there, which is, you do what you know is going to add value for your shareholders. And I think there's no doubt that we've -- the Sole Project is some 4 months late and we're very mindful of that. And we pace our capital investments. We paced our activities having regard to the strategy and maximizing value. We've made no commitments on M&A in the last year or so at all. In fact, this has been very much on Sole.

[Operator]

[Operator Instructions] Our next question is from Jon Bishop of Euroz.

[Jon Bishop, Executive Director & Head of Research]

Just getting back to the pending gas sales agreements to kick off from the start of next year. I mean, in effect, as I understand these agreements, there's sort of a [ 91-10 ] nomination on their election. Would the work around -- you're effectively working at sort of 90% or at the low end of that band. So has there been any amendments to those offtake agreements to reflect, I guess, the change in the operating parameters, I guess, in the short to medium term? The customers seem to have been highly flexible today. Just if you're able to provide any insight around that?

[David P. Maxwell, MD & Executive Director]

Yes. Yes. The basis of the conversations at this point, Jon -- and we expect the sort of -- what we're really doing is we've -- there's a -- the conversation has been held with the customers on the expectation that this is where we're going to get to. Once we get there -- and we got there and signed agreements yesterday -- then we flange up exactly what we've been talking to the customers. So that's where things are at, nothing -- and you'll see that flange -- well, we'll see that flanged up, I'm expecting, in the next few days.The gas sales agreements themselves have been effectively unchanged. There's one agreement which -- where the volume might come down by a couple of petajoules for the first year and then increase to the -- then increase from the start of '22. So if you think about it like that, then 19.75, round that to 20 petajoules, and then another 2 petajoules coming on 12 months' time with one customer, all other terms and conditions, so take-or-pay levels, MDQs, maximums and minimums on a day, are unchanged. Does that answer your question?

[Jon Bishop, Executive Director & Head of Research]

Yes. Okay. Just to take it a little bit further then. I mean, you've never fully contracted your Sole reserves. Does the existing spare capacity on the, let's call it, the modified production profile for life-of-the-field provide you some additional flexibility to meet that, let's call it, 110% nomination scenario?

[David P. Maxwell, MD & Executive Director]

Yes, it does. Yes. Yes, it does. When we talk about the capacity of 68 terajoules a day, that's our -- that's what we can go -- that's the sum of them. That's what we would refer to as the sum of the maximums. The actual sum of the maximums for all of our contracts at the moment -- I think I'm right, and Eddy is going to correct me if I'm wrong -- I think it's about 64, 65 terajoules a day.So we've got 3 or 4 terajoules a day to take it to the [ main figure ] of 68.

[Jon Bishop, Executive Director & Head of Research]

Okay. And then just...

[David P. Maxwell, MD & Executive Director]

Eddy -- just sorry. Sorry, Jon. Eddy, you're across the precise numbers. You would just know that? Correct me.

[Eddy Glavas, General Manager of Commercial & Development]

That's right, it's 65. So yes, we do still have that flexibility. All the reserves are still there. So once we're up and running in higher rates, we'll work out how we'll use that flexibility or recontract -- or contract some of it to a new customer.

[Jon Bishop, Executive Director & Head of Research]

All right. And then to really just -- sorry?

[David P. Maxwell, MD & Executive Director]

Sorry. Go on.

[Jon Bishop, Executive Director & Head of Research]

Okay. Just to really round out then. I presume under the agreements either prescriptively or otherwise there is some acknowledgment of plant availability I would have thought. Obviously, that's changing a little bit with the required regular maintenance to manage cleanout. And David, obviously, answered the question on that, talking about a couple of days. Notionally, on what you're seeing, would there be any look to modify that availability in principle under those agreements, maybe 97% goes to 95%? Or is there any latitude there do you think?

[David P. Maxwell, MD & Executive Director]

Not within the gas sales agreements. We're not planning to tinker with those. But we're talking about across a year 94% uptime in the plant. And that's what -- that's effectively what's allowed in the planning base that one uses, because within the arrangements around the gas plant and within our gas contracts with the customers we have a certain number of planned maintenance days and a certain number of unplanned maintenance days each year.

[Operator]

Our next question is from Gordon Ramsay of RBC.

[Gordon Alexander Ramsay, Analyst]

David, just on kind of expenditure going forward. I just want to confirm some of the numbers. You've gone from $15 million to $19 million for Sole. I'm assuming that difference is just the extra 6 days that you just had from the 21st of October. Is that right?

[David P. Maxwell, MD & Executive Director]

It's actually -- it's a bunch of things, Gordon. The number that was provided previously was an indication. So it's the final number based on fee. It includes everything pretty much of a -- you might call it a capital nature since 1st July. So it's not all in that 3-week program that's planned from the middle of November. So it includes a bunch of things, the refining of some numbers, a little bit of accommodation for the COVID and with some historical -- with some historical -- wouldn't say historical; I mean, money that has been spent since July.I'll ask Mike Jacobsen if he's got anything he wants to add to that.

[Michael Jacobsen, General Manager of Projects & Operations]

Yes. I think it's -- as the design matures -- Gordon, what we've got here is this is the detailed design now after all the analysis has been complete. It also includes contingency as well. So there is a fair amount of margin built into that $19 million. So yes, there's a high level of confidence that they'll be able to deliver Phase 2 within that $19 million.

[Gordon Alexander Ramsay, Analyst]

Okay. Just on those numbers then because I'm a little bit confused. Before you might have been talking about a parallel configuration for the absorbers. Now you're saying that it could be sequential. And you haven't ruled out the unit at the end that you've talked about, David, to capture some of the sulfur. So that is still all open-ended, but you feel that with the numbers you've got, you've adequately covered for whatever the final solution is?

[David P. Maxwell, MD & Executive Director]

Yes. Sorry, if I've caused any confusion, Gordon. It is sequential at the moment. The works in November move that to parallel, but give us the flexibility to run Athena in parallel or sequential. But the expectation is that we will be running in parallel.

[Gordon Alexander Ramsay, Analyst]

Okay. And just lastly, on CapEx, David. $6 million for the quarter. Obviously, it's going to pick up significantly going forward. You're going to spend some money on Athena. I just want to confirm CapEx guidance again.

[David P. Maxwell, MD & Executive Director]

We are well within guidance. Let's see. The guidance remains unchanged from the start of the year. This year is light CapEx and next year we expect it to be even lighter. And then it would be FY'23. But we would expect to see CapEx kick back up again, and that's on the back of the development in the Otway, particularly around OP3D and exploration coming in both the Otway and to Gippsland. So we're well within guidance this year, and we'll be updating -- I expect we'll be updating guidance around -- probably around the -- at the AGM. But capital-wise, we are very consistent.

[Operator]

We have a follow-up question from Peter Liu of Credit Suisse.

[Peter Liu, Research Analyst]

I just have a follow-up question on the cost. In the quarterly, there's a mention of $4.5 million recognized expense for APA's share of revenue and another $6.6 million for Cooper's share of cost. Is this just for the accounting expense that occurred during the September quarter or is something which you expect to be more going forward? And how should we actually treat that on the P&L? Should we treat that as part of the underlying EBITDA numbers or should we treat it as a one-off?

[David P. Maxwell, MD & Executive Director]

Yes. I'll make a couple of comments and then I'm going to ask Virginia to talk about the P&L impacts. The arrangements that we have with -- under the transition agreement, which is for the period of 1st July until gas sales agreements commence, is that we share the costs, the operating costs, the offshore operating costs, which are our operating costs, the higher operating costs, which are effectively APA operating costs, and the revenue 50-50. And then separately, the Phase 2 works is funded separately, but again it's 50-50.In terms of how we're handling it in an accounting sense, we're expensing those costs. But Virginia, would you like to say a little bit more about that?

[Virginia Katherine Suttell, Chief Financial Officer]

So David, I'm afraid you're right. They are the costs and the share of revenues that are associated with the transition agreement that we announced in August that was effective 1st July for the quarter. And it is expected -- and we're just closing out some of the accounting treatment associated with the Phase 2 work. But these will all be gone to the P&L as some form of expense. So -- and that includes the Phase 2 cost. The closeout on that is just dealing with the lease accounting [indiscernible] we have had regularly. But we are expecting that all of those costs will be expensed through the P&L.As to whether the -- sort of it's underlying or in sort of base business, that decision hasn't been yet [indiscernible].

[Operator]

Mr. Maxwell, there are no further questions at this time. Would you like to make some closing comments?

[David P. Maxwell, MD & Executive Director]

Well, thank you very much, everybody, for joining. And we appreciate it was at a relatively short notice, but I think you can now understand why we held off on our quarterly.Starting the gas sales agreement is a big milestone for Cooper and it's even -- as I've said in my introductory piece, will be at later than we've planned and later than we hoped. But the fundamentals of the business, the fundamentals of the market are unchanged, and effectively the revenue streams and the cash flow streams and the production is deferred from where we had expected 12 months ago, it's not lost.And we're on the cusp of a very significant increase in both production and cash flow and the shareholders see the benefit of that. I expect the first real sign of that will be in the March quarter early next year. But we'll be keeping the market fully informed, as you would expect.On that note, thank you very much. And if you've got any further questions, please don't hesitate to contact myself or in particular Don Murchland. Many thanks.

[Operator]

Thank you. That concludes today's call. Thank you for joining us. You may now disconnect your lines.