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Edited Transcript of COE.AX earnings conference call or presentation 14-Feb-21 10:00pm GMT

·38 min read

Half Year 2021 Cooper Energy Ltd Earnings Call South Perth Feb 15, 2021 (Thomson StreetEvents) -- Edited Transcript of Cooper Energy Ltd earnings conference call or presentation Sunday, February 14, 2021 at 10:00:00pm GMT TEXT version of Transcript ================================================================================ Corporate Participants ================================================================================ * Andrew D. Thomas Cooper Energy Limited - General Manager of Exploration & Subsurface * David P. Maxwell Cooper Energy Limited - MD & Executive Director * Derek Piper * Eddy Glavas Cooper Energy Limited - General Manager of Commercial & Development * Michael Jacobsen Cooper Energy Limited - General Manager of Projects & Operations * Virginia Katherine Suttell Cooper Energy Limited - CFO ================================================================================ Conference Call Participants ================================================================================ * Adrian Prendergast Morgans Financial Limited, Research Division - Senior Analyst * Andrew Pedler * Gordon Alexander Ramsay RBC Capital Markets, Research Division - Analyst ================================================================================ Presentation -------------------------------------------------------------------------------- Operator [1] -------------------------------------------------------------------------------- Thank you for standing by, and welcome to the Cooper Energy Limited FY '21 half year results webcast. (Operator Instructions) I would now like to hand the conference over to Mr. Derek Piper, Head of Investor Relations. Please go ahead. -------------------------------------------------------------------------------- Derek Piper, [2] -------------------------------------------------------------------------------- Thank you very much, and good morning, everyone. Thanks for joining the Cooper Energy results call for the first half of FY '21. My name is Derek Piper, and I'm here this morning with David Maxwell, our Managing Director; and Virginia Suttell, our Chief Financial Officer. And also with us in the room are members of the leadership team. This morning, we released our half year results and also an accompanying presentation. We'll talk through that presentation this morning and then open the line for Q&A. So on that note, David, I'll hand over to you. -------------------------------------------------------------------------------- David P. Maxwell, Cooper Energy Limited - MD & Executive Director [3] -------------------------------------------------------------------------------- Thanks very much, Derek, and welcome to everybody on the call live and those that will listen to it later on the website. There's really 3 key messages today with our first half results for the financial year 2021. Firstly, the step change, which is a threefold increase in production revenue and net cash flow commenced in January when we started the bulk of our long-term gas sales agreements. Second, whilst the underlying business performed well in 2020, and here, I'm referring to Casino Henry in the Otway and the Cooper Basin oil, it was a challenging period with bushfires, COVID-19 restrictions and, of course, the delays at the Orbost Gas Processing Plant operated by APA. The Orbost plant delays deferred the significant step change in growth that I just mentioned. However, it's important to note that the sales and production were deferred, not lost. And then third, the fundamentals of the Southeast Australia gas market and the Cooper Energy assets are strong and getting stronger. Our next wave of growth projects has Cooper Energy ideally positioned for sustained growth. The gas plant delay and commissioning issues deferred the start of the long-term gas sales agreements. The transition agreement with APA, which was signed in August, provided the platform for change and the commencement of the gas sales agreements in December and January. The transition agreement falls away when we enter the long-term gas processing agreement. Under the transition agreement, we pay a toll only for Sole gas delivered into the gas sales agreements, and we'll share the revenue and costs for gas sold into the spot market. Importantly, Cooper Energy is effectively kept whole for the net cash flows arising from gas sales agreements. Key in the transition agreement was the capital works at the Orbost plant, which reconfigured the absorbers. Following the commissioning and tuning post these works, we've seen a step change in plant performance. I'll talk a little bit more about this in a minute. In the half year, there was an 82% increase in total production, and this is on a million barrels of oil equivalent basis, and a 24% increase in revenue when compared with the previous corresponding period. The first half results include the Sole production increase and were impacted by the transition agreement, which Virginia will take you through soon. We've maintained a strong balance sheet and very good and supportive relationships with each of our banks. Now a few words on the Orbost gas plant. There has been a material improvement in plant performance since the 1st of February. This is following the realignment of the absorbers, some other capital works that I mentioned and then the commissioning and tuning of the plant. The production was variable in January whilst APA tested and tuned the plant. Following the cleanout of each of the absorbers in the second half of January, we've seen pretty stable production, which has been at 45 terajoules a day on most days. The focus now is on further tuning the operations, increasing the long-term rates. There maybe some further capital works to support this. At this time, the analysis to find the root cause of the foaming continues with the technical experts. Key is we remain committed to achieving the 68 terajoules a day production level in accord with our project agreements and achieving this level as early as possible. On the next slide, we illustrate the link between Sole gas production and the sales volumes, which is key to understanding the step change in revenue and cash flow. In the transition agreement, and a summary of this is in the appendices, there are arrangements whereby if the gas processed on a day does not meet the customer nominations on that day, then APA contributes to the cost of sourcing gas from the back-up arrangements Cooper Energy has in place. The impact of this is that we receive a comparable gas margin as if all the gas had been produced ex-Orbost. The Sole gas that may not have been processed on a day can then be sold and processed later. As illustrated on this slide, the plant performance was variable whilst they were testing and tuning through January. And since 1 February, rates have stabilized. The dip for a day last week was due to a compressor trip in the plant. There will be dips in the future when they're cleaning an absorber, typically 2 to 3 days per absorber. It's important to note, we have not missed a nomination since any of the Sole gas sales agreements were started, and the sales volumes will vary with the season. Therefore, just to achieve the take-or-pay level total in our contracts, the nominations, and therefore, the sales volumes, increased between now and the end of the year. Slide 6 illustrates the step change in daily gas production from the average of the first half to financial year 2021 of 37 terajoules a day to 60 terajoules a day based on the February average to date. And to illustrate, we've included total gas production at 68 terajoules a day, which is the rate the Orbost agreements are based on. And here, I'm referring to the gas processing agreement. We include this to illustrate the growth now underway, and this growth comes just from the existing projects. And you'll see this reflected in the updated guidance and a further step increase when we release guidance for financial year 2022. The health, safety and environment performance was pleasing for the half year in what were difficult circumstances. We needed to manage within the COVID restrictions whilst operating our assets remotely and, for extended periods, working from home. We had no COVID cases reported and 1 lost time injury, and this was a contractor who strained a hamstring at the Athena Gas Plant. There were no reportable environmental incidents. An important move announced in October is our commitment to net zero carbon emissions -- carbon dioxide emissions. This is Scope 1, Scope 2 and controllable Scope 3, and from October, not some date or year in the future. We've participated with Greening Australia in the Coorong Biodiversity Project, and we are now net zero. We're progressing other projects, time to be in line with our gas production growth, and have a number of very cost-effective opportunities under review. It's interesting, the spin-off benefits and other value-adds this is starting to create to support our core gas business. I'll now hand over to Virginia, who will take you through the financial results for the first half. -------------------------------------------------------------------------------- Virginia Katherine Suttell, Cooper Energy Limited - CFO [4] -------------------------------------------------------------------------------- Thanks, David, and good morning, everyone. The first 6 months of FY '21 had been a series of decisions and outcomes that have resulted in what we see in the half year results today. Comparisons to the prior comparative period are somewhat difficult to make at the headline level due to the complexity of the arrangements in place across both periods. Throughout the next 5 slides, I will take you through some of the details. Firstly, the accounts are a representation of the increased sales from Sole production operating under the transition arrangements with APA, including the Orbost reconfiguration and recommissioning work from November and the commencement of our first full gas sale agreement in December 2020. An 82% increase production from our assets half-on-half is due to Sole and underpins the increase in revenue from $39.1 million in the first half of FY '20 to $48.6 million in the December 2020 half, a 24% increase. This increase in production is notwithstanding slightly lower volumes at Casino Henry Netherby and in the Cooper as well as the cessation of production from the Minerva Field in FY '20. Revenue was up predominantly from the Sole spot sales volume and also as a result of the pricing and the contract for our Otway gas. The transition agreement has assisted us to secure arrangements with customers as we continue to work toward the achievement of higher rates and associated cash flows. This has not been without impact to our key metrics. While sales revenue has shown growth with the new sharing arrangements with APA under the transition agreement, the average realized gas price reflects spot pricing achieved for gas unable to be sold into our gas sale agreements during this time. The share of operating costs and revenue are a net item of $10.7 million in cost of sales, broken down on the slide into its components of $7.6 million and $3.1 million. The contribution to the November works, which are funded -- or are to be funded from escrow funds, has been booked in the other expenses line in the profit and loss. These costs flow through to the EBITDAX, statutory loss after tax results as well as to the $10.7 million only operating cash flows. Whilst operating cash flows overall decreased, our cash flows purely from operations increased, notwithstanding the transition arrangements and lower spot pricing. Changes to the treatment of interest expense of $5.3 million and our PRRT position for the Otway assets have contributed to the decrease in operating cash flow. Capital expenditure incurred is down 73% from the prior comparative period, reflecting the status of our projects and assets in their life cycle. Turning to the next page. The company continues to meet and comply with the requirements of the senior debt facility, working constructively and with the continuing support of the lender group. As indicated on the slide, the first principal repayment of $4.5 million will be made next month. We are targeting adjustments to our banking arrangement by 30 June 2021 to realign the amortization to the value of reserves and gas sale agreements, which underpin our borrowings. Progress made at the Orbost Gas Processing Plant in the last half and through January and February to date is a positive input into these discussions. Future refinancing activity will be linked to development opportunities and decisions. Liquidity remains good with a net debt position of $114.1 million against cash of $115.3 million at 31 December 2020. On Slide 12, as is customary, we remove one-off or unusual items unrelated to the underlying operating performance from the statutory results to provide a meaningful comparison of results between periods. Items totaling $5.7 million after tax have been removed for the half year and comprise the expected noncash adjustments for movements in discount rates associated with restoration provisions for our depleted assets as well as the contribution provided for a new account for the reconfiguration and recommissioning in November at Orbost, to be paid, as mentioned, from escrow funds. These funds are represented in the balance sheet as part of current other financial assets. Adjustments from underlying net profit after tax to underlying EBITDAX includes the usual items of tax, finance costs, exploration and evaluation expense and depreciation and amortization, as outlined on the slide. The movement of underlying EBITDAX from $16.3 million to $9.7 million when comparing the first half of FY '20 to this half can be attributed to the disproportionate increase in production costs associated with Sole, the decline in netback for the oil business due to lower volumes and prices as well as movements in other expenses, such as gas marketing costs and foreign currency translation loss. These are outlined on the next slide. Here, we compare the underlying results for the 2 periods. Most significantly, you can see the step change in revenue of $15 million, predominantly from the sales of Sole revenue into spot contracts. This is offset by the cost of sales increase, which includes increased production cost for Sole, as you would expect, including those associated with the transition agreement as well as amortization of the asset in line with production. In addition, the decline in oil prices and the strengthening of the Australian dollar against the U.S. in the first half of FY '21 had been the main -- been the cause of the reduced oil revenue of $5.5 million from the prior comparative period. Net finance costs increase of $5.8 million are associated with the cessation of the capitalization of interest into the carrying value of the Sole asset in the second half of FY '20 with a full 6 months of interest expense being taken to the profit and loss in this half as well as reduced interest income. Net other expenditure movements include some increased gas marketing costs, a flat G&A profile and movements in foreign currency translations. Now turning to cash flow performance on Slide 14. Notwithstanding lower revenue from spot sales offsetting production costs for Sole, the business generated an increase in cash flows from operations from $24.6 million in the first half of FY '20 to $31.3 million in this half. The commencement of the gas sale agreements from December will be reflected in the cash flows of the second half due to timing. The other items resulting in the overall operating cash flow result of $6.7 million; a cash G&A cost of $6 million, slightly lower than in the first half of FY '20; restoration spend of $6 million, which is associated with the continued planning work for restoration activity for future obligations; PRRT payments of $7.4 million, serviced from cash flows for our Casino Henry Netherby asset; and interest expense, as previously mentioned. When comparing the operating cash flow result in the first half of FY '20 of $31.4 million, which you saw on Slide 10, to the $6.7 million this half, included within the $31.4 million was $9 million of liquidated damages. Cash capital expenditure has reduced from the prior comparative period in line with guidance and the completion of the Sole offshore project. Predominant capital spend has been for the Athena gas plant upgrade, which is in property, plants and equipment. The cash balance at 31 December 2020 is $115.3 million. I'll now hand back to David to take you through the rest of the pack. -------------------------------------------------------------------------------- David P. Maxwell, Cooper Energy Limited - MD & Executive Director [5] -------------------------------------------------------------------------------- Thanks, Virginia. With the gas sales agreements underpinned by Sole starting in December, we've updated our guidance for production and capital expenditure, and we've commenced guidance on sales volumes. On production, we are guiding to a total of 2.7 million to 2.9 million barrels of oil equivalent for the 2021 financial year. This is Cooper Basin oil; Otway gas, which is Casino Henry Netherby; and Gippsland gas, which is Sole. On sales volumes, we are guiding to 2.9 million to 3.1 million barrels of oil equivalent. You will note that the sales volumes and, therefore, the revenue and cash flow are higher than the production volumes. This is due to the arrangements included in the transition agreement, the backup arrangements we have in place and gas sales portfolio optimization opportunities. On capital expenditure, we're guiding to $45 million to $50 million for the full year, which is a reduction from our previous capital expenditure guidance for the year of $50 million to $58 million. The reductions for the year are across the board. Now a few comments on the gas market in Southeast Australia and the Cooper Energy position. This slide summarizes our current gas sales agreement portfolio. In addition, we can optimize our net cash flows within a day with other contracts and arrangements we have in place. Note that 61% of our 2P reserves, that's our proved and probable reserves, are under take-or-pay contracts, and we have uncontracted gas mainly from 2024 onwards. This is important in the context of the gas market outlook. We continue to see tight gas supply in Southeast Australia. This shortfall grows to be in excess of 100 petajoules in 3 to 4 years' time. On the AEMO forecast, this shortfall is equivalent to 4 to 5 Sole projects by 2024, that's 4 to 5 Sole projects online by 2024, which means that these projects need to have been at FID now or very soon to change this supply shortfall situation come 2024. The shortfall will be supplied by cole seam gas from Queensland, which has a pipeline cost disadvantage relative to gas from Southeast Australia. And in the medium term, not the short term, possibly there's also imported LNG as an option. The next slide shows movements in the Victoria spot gas price and movements in the LNG netback price at Wallumbilla, Wallumbilla being a transfer point or a hub in Queensland. A transport cost of circa $2 to $2.50 is to be added to the transport cost from Wallumbilla to Southeast Australia. LNG prices in the last 3 months and the fundamentals continue to support our view that the long-term gas price range, and that's the price for term contracts such as those that we negotiate and those that we work with, that price is in the range, in our view, $8 to $10. Hence, my comments at the start that the market fundamentals remain strong and the outlook supports stronger prices. Now some words on the progress of our growth projects beyond Sole. This is a combination of gas and plant developments and the main medium-term exploration opportunities. And on this slide, we illustrate where the projects are at and the project management process that we use. Firstly, the Athena Gas Plant project. This project is about upgrading and converting the existing plant to process Casino Henry gas, new developments such as OP3D and new gas discoveries. The Athena Gas Plant project is on track to be ready to process Casino Henry gas late in the September quarter. That's the September quarter of 2021. On this basis, we, together with our partner, Mitsui, will be processing our own gas in our own gas plant, and this lowers the operating costs and provides productivity and stability benefits. The first new development we plan to process through Athena is OP3D. This project adds some 120 petajoules, and that's on a 100% basis, and preparations are underway for this project to enter front-end engineering and design very soon, with a view to making a final investment decision in the first half of financial year 2022. That's the second half of this calendar year. Coincident with this, we're preparing to start the customer negotiations for the take-or-pay contracts, which will then underpin the financing. On the current schedule, first production will be in mid-2023, which is well placed with respect to the gas market outlook I mentioned earlier. In the Gippsland, the next project we have is Manta. The next step is drilling the Manta-3 appraisal well, which will include the Manta Deep exploration play of some 500 petajoules. This is a material exploration prospect in the context of the gas market. On this slide, we show diagrammatically the growth based on the existing near-term projects only. As we firm up the projects to the right, we will add the numbers for further growth quantum. So to wrap up. Our current gas production of some 60 terajoules a day is a step change, underpinned by the long-term gas sales agreements we commenced in December and January with the investment-grade customers. Second, this will increase throughout this year, this year being 2021 calendar year, as the offtake volumes increase and with further improvements in the Orbost plant performance. Third, coming after this is OP3D, which increases the gas to be processed through the Athena Gas Plant. And fourth, the market fundamentals -- the gas market fundamentals and the Cooper Energy position are strong and getting stronger. This underpins the basis of the next wave of growth in production, revenue, cash flow and value. On that note, happy to take questions. And I have the leadership team here with me as well as if needed. ================================================================================ Questions and Answers -------------------------------------------------------------------------------- Operator [1] -------------------------------------------------------------------------------- (Operator Instructions) Your first question comes from Adrian Prendergast from Morgans Financial. -------------------------------------------------------------------------------- Adrian Prendergast, Morgans Financial Limited, Research Division - Senior Analyst [2] -------------------------------------------------------------------------------- Congratulations on the progress at Orbost. Just a quick question on when you say possible further capital works planned, just what you're sort of planning here incrementally to grow that production number now that you've got that stable performance in February. -------------------------------------------------------------------------------- David P. Maxwell, Cooper Energy Limited - MD & Executive Director [3] -------------------------------------------------------------------------------- Yes. Thanks, Adrian. The -- I think the -- as reflected in the Q&A, there's 2 streams of work. One is the root cause analysis, which is ongoing, and we will get to the answer there. We just don't know when that will be. And the other is the debottleneck work, notwithstanding what to -- what might be the cause of the foaming and the failing. And with the debottleneck work, there is the opportunity for some smallish capital projects to enhance the existing production level. That's under review at the moment, and we and APA are working closely on that. We'd expect to have more to say about that in the next couple of months, I think. We've got Mike Jacobsen on the line as well. And Mike, I wonder if you'd like to add anything. And Mike heads up our projects and operations team. Mike, I wonder if you'd like to add anything to that. -------------------------------------------------------------------------------- Michael Jacobsen, Cooper Energy Limited - General Manager of Projects & Operations [4] -------------------------------------------------------------------------------- Yes. Thanks, David. And Adrian, thanks for the question. Yes. At this point, as David said, the planning for any further capital works is ongoing. I guess the 2 areas of focus at the moment for APA, and this is work in progress, I stress it's work in progress, is working on trying to deal with the issues that we've got and trying to get quite a lot of the sulfur or try to get the sulfur out of the system, which is causing us -- which has been causing some of the issues. So it's focused around that, really dealing with the symptoms at this point. There's been quite a lot of testing work that APA has been doing. And those tests have been positive, and the expectation is yes, as David said, in the next few months, we'll be able to come out with some more information on what that looks like and certainly the costings. -------------------------------------------------------------------------------- Adrian Prendergast, Morgans Financial Limited, Research Division - Senior Analyst [5] -------------------------------------------------------------------------------- Great. And maybe just... -------------------------------------------------------------------------------- David P. Maxwell, Cooper Energy Limited - MD & Executive Director [6] -------------------------------------------------------------------------------- Maybe -- sorry, Adrian. Maybe just to add one other thing to that is that what we have seen is that following the cleanout in January and stable rates since the start of February, is that one of the absorbers is performing a lot better than the other. And the one that's performing a lot better has had a few little tweaks to it, to its inside, relatively simple straightforward tweaks. And I'd expect in the next few weeks that those same tweaks will be applied to the other absorber, which will increase the rates. Now that's not really a minor capital project, that's not capital works, but that's the sort of thing that is being looked at to increase the rates. -------------------------------------------------------------------------------- Adrian Prendergast, Morgans Financial Limited, Research Division - Senior Analyst [7] -------------------------------------------------------------------------------- Great. Makes sense. Encouraging as well. And just -- maybe just a broader, more general question just on gas market. And obviously, very different pressures short and long term with the LNG market as well. Just interested in your view and maybe from your marketing team just on the current customer appetite for some of the longer-term volumes. -------------------------------------------------------------------------------- David P. Maxwell, Cooper Energy Limited - MD & Executive Director [8] -------------------------------------------------------------------------------- Yes. The -- what we have seen in the last 3 months, and perhaps no coincidence with what's happened with LNG prices, is a significant step-up in inbound inquiries from, in particular, some of the larger buyers. And we are looking to engage with them in the next month or 2 with a view to sorting things out by the middle of the year. Maybe I'm going to ask Eddy Glavas, who heads up the commercial and marketing side of things. So if you wanted to add anything to that. -------------------------------------------------------------------------------- Eddy Glavas, Cooper Energy Limited - General Manager of Commercial & Development [9] -------------------------------------------------------------------------------- Yes, no, I think, generally, with the larger customers, in particular the retailers, they're looking to fill their book in '23 and '24 in particular. So that bodes well for our growth plans that David mentioned earlier into that window. And yes, we are seeing a step change. LNG will drive maybe some of the increases that we've already seen at Wallumbilla and also the capacity, how it moves from the North and the South and how the Southern fields perform and supply into that market as well. -------------------------------------------------------------------------------- David P. Maxwell, Cooper Energy Limited - MD & Executive Director [10] -------------------------------------------------------------------------------- I think the other thing that's sort of telling on this is that -- what we've seen around the LNG input terminals and the increased activity in that respect, both from LNG import facility developers, but also from some of the customers or the buyers, I think that's a reflection of what people in the market that are very close to the market are starting to feel. So I think you sometimes got to look at the actions rather than the words to see what people really think about an outlook. And that, for me, is quite telling. -------------------------------------------------------------------------------- Operator [11] -------------------------------------------------------------------------------- Our next question comes from Gordon Ramsay from RBC CM. -------------------------------------------------------------------------------- Gordon Alexander Ramsay, RBC Capital Markets, Research Division - Analyst [12] -------------------------------------------------------------------------------- Just quickly on the gas price. Your average gas price, $6.35, you're seeing a high percentage of that with -- to the spot sales. Can you give us a feel for the outlook for the gas price going forward? Obviously, you're going to move them into the contractual volumes. -------------------------------------------------------------------------------- David P. Maxwell, Cooper Energy Limited - MD & Executive Director [13] -------------------------------------------------------------------------------- It's a difficult question to answer easily, right, Gordon? I hesitate mainly because it's wrapped up, obviously, as you'd expect, in the long term. It's material over and above that. But first 6 months was dominated by spot sales. And you can see where spot sales were occurring, somewhere in the $4 to $6 range, being supplemented, obviously, by our gas sales agreements out of the Otway. There's a material step-up you should expect in the second half. I'm sorry, I'm not going to give you a guidance on price, but it's a very material increase in the second half. -------------------------------------------------------------------------------- Gordon Alexander Ramsay, RBC Capital Markets, Research Division - Analyst [14] -------------------------------------------------------------------------------- I guess what I was thinking is maybe just percentage of overall volume, spot versus contractual going forward. -------------------------------------------------------------------------------- David P. Maxwell, Cooper Energy Limited - MD & Executive Director [15] -------------------------------------------------------------------------------- Oh, okay. Fine. Well, yes, yes. Pretty much all of it will be under gas sales agreements in the second half out of Sole. And there is -- we've held back some of our volume in the Otway, about 8 terajoules a day. Our share in the Otway, we've held back for the spot market. So if you thought about it on that basis, pretty much all of Sole will be under gas -- under the long-term gas sales agreements, and about half of our Otway production, which is around 8 out of the 15, 16 terajoules a day, would be in the spot. The rest is under term contracts. -------------------------------------------------------------------------------- Operator [16] -------------------------------------------------------------------------------- (Operator Instructions) Your next question comes from [Ralph Sulewski] from [Sulewski Nominees Pty Ltd.] -------------------------------------------------------------------------------- Unidentified Analyst, [17] -------------------------------------------------------------------------------- I've been a Cooper Energy shareholder in the super funds since the Morocco (sic) [Tunisia] days. So I hold a fairly significant -- or actually, it's well overweight in the super fund. And my question is really around -- and you sort of read my mind a little bit. It's sort of really around Slide 5. So I was going to ask whether you would consider doing such a thing. But since you've already started doing it, can I expect Cooper Energy to perhaps continue with such advice on an ongoing basis during this second half to maybe, I don't know, reduce the uncertainty that the market has in, say, Cooper delivering on those gas sale agreements? But I'd like to see you change that just a little bit to give me sort of like 4 numbers, the total volume in, say, terajoules that has been sold, the total volumes sold under a gas sale agreement, the total volume sourced from the Sole gas project and the total volume contributed by the Sole gas plant operator as backup supply. Would that be something that Cooper could do on a fortnightly basis going forward, perhaps? -------------------------------------------------------------------------------- David P. Maxwell, Cooper Energy Limited - MD & Executive Director [18] -------------------------------------------------------------------------------- First, thanks for the question, [Ralph]. I think when you talked about Morocco, I'm going to have a guess, I mean, not as long as I've ever remembered, but you might -- are you thinking about Tunisia? -------------------------------------------------------------------------------- Unidentified Analyst, [19] -------------------------------------------------------------------------------- Yes, Tunisia, sorry. Yes. Close enough. -------------------------------------------------------------------------------- David P. Maxwell, Cooper Energy Limited - MD & Executive Director [20] -------------------------------------------------------------------------------- Well, firstly, thanks very much for the support and patience through the time. -------------------------------------------------------------------------------- Unidentified Analyst, [21] -------------------------------------------------------------------------------- Well, it's for gas vision. Yes. -------------------------------------------------------------------------------- David P. Maxwell, Cooper Energy Limited - MD & Executive Director [22] -------------------------------------------------------------------------------- Yes. A lot of expansions then, hasn't it? Look, what we have done -- and I'll answer your question in 2 parts, what we've done is guided on sales volumes and as well as production volumes. And the reason for doing that was to get around the misunderstanding, I would say, by many as to what sales revenue was going to be generated out of Sole. We have thought about other guidance, and at this stage, feel that, that's the best of best and most appropriate. What we will do, though, and it's a requirement upon us, is to update the market for any material changes. And we will be giving consideration to that. And for example, if there is a step change in production at Sole, a step change in revenue at Sole, we have an obligation to keep the market informed. Having started, what you see on graph 5 there, there will be questions about it and how are we going against that. And on a -- whether it's in investor packs or whether it's on an update to the market because there's been some material change, positive or whatever, we'll be keeping the market informed. As to putting out an every -- an announcement every couple of weeks, I don't think we can commit to that simply because once you start something, it's very hard to then stop it. This is an interim mechanism, very much. Once we enter the gas processing agreement, every molecule that we produce out of Sole will be going into the market or into other parts of the portfolio such as storage or pipeline storage. So we would, at that point, not have the need for this because the transition agreement, which is where APA is contributing to any shortfalls on nominations, would fall away. So that's when we get to the gas processing agreements and the 68 terajoules a day. It's a long answer to a very good question, but I hope I've given you a bit of an understanding as to what we're thinking and how we're heading. I'm also going to just invite Eddy Glavas, who heads up our gas market and commercial BD side to make some comments. -------------------------------------------------------------------------------- Eddy Glavas, Cooper Energy Limited - General Manager of Commercial & Development [23] -------------------------------------------------------------------------------- Yes. Thank you, [Ralph]. Just clarifying on your fourth point that you said -- that you mentioned about the total sourced by the gas plant operator. APA advises what processing capacity they have in a day. That's Cooper Energy that sources or the gas from the other sources -- from other options. So it's not the plant operator. It's Cooper Energy that goes out and uses alternatives to find the gas. -------------------------------------------------------------------------------- David P. Maxwell, Cooper Energy Limited - MD & Executive Director [24] -------------------------------------------------------------------------------- Yes. We source it, and then APA has to contribute to essentially keep us whole. -------------------------------------------------------------------------------- Eddy Glavas, Cooper Energy Limited - General Manager of Commercial & Development [25] -------------------------------------------------------------------------------- Right. -------------------------------------------------------------------------------- Unidentified Analyst, [26] -------------------------------------------------------------------------------- Right. Okay. Good. I do have a slight follow-up on the same graph, conceptually, with the banking facilities. I suspect that, that was originally all sort of on the basis of 68 terajoules a day. So there's still a significant gap between 54 and 68. Is that what's -- what you referred to as the sort of changes in the financing facilities, is to sort of address that gap as to when it may happen, that it closes or the repayments because of the fact that we aren't selling as much as we originally thought? -------------------------------------------------------------------------------- David P. Maxwell, Cooper Energy Limited - MD & Executive Director [27] -------------------------------------------------------------------------------- Yes. I'll make some comments and then invite Virginia to add. The finance facility that we have with the syndicate of 5 banks was based on the gas sales agreements that we had, which, in total, at 24 petajoules a year. And if you work that out, I think that doesn't take up the full capacity of the plant every day. So the nameplate capacity, design capacity of the plant, 68. I think 20 -- back to the maths, but I think it's in the low 60s. I think it's... -------------------------------------------------------------------------------- Unidentified Analyst, [28] -------------------------------------------------------------------------------- Yes. I've done those maths. Yes. -------------------------------------------------------------------------------- David P. Maxwell, Cooper Energy Limited - MD & Executive Director [29] -------------------------------------------------------------------------------- Yes, yes. And so that -- and the gas contracts together -- those gas contracts, together with the 2P reserves, are the security that the banks have. And the important thing here is that the gas contracts haven't changed and the 2P reserves have not changed. What has changed is the profile in the initial period for those contracts. And when we talk about adjustments to the existing finance facility and then refinancing, the adjustments are more about making the finance agreement that we have with the 5 banks a bit more bespoke to the situation as it now is because, as we all know, these gas sales agreements have started circa 12 months later than previously expected. What's important is that the banks are working with us around this in a very supportive, constructive way. And maybe Virginia, who's, together with our advisers, leading this, can add to that. -------------------------------------------------------------------------------- Virginia Katherine Suttell, Cooper Energy Limited - CFO [30] -------------------------------------------------------------------------------- Yes. Sure. Thanks, David. So probably the one thing to just add there is that the bank facility that is modeled for an RBL has quite a number of imports into it. One of -- the least one of which is the production profile. And it's not just Sole that we're looking at in the business, but our other producing assets as borrowing base assets. So to David's point, the security and the value in the bank facility is the reserves and the gas contracts, which remain on foot irrespective of the production profile that we've seen currently. So yes, you're right. The initial modeling had higher rates. However, with sort of the reserves still being there and security still being in place when we talk about sort of -- any sort of adjustments that we make in the near term and then refinancing around future opportunities such as OP3D and Manta, you would look to sort of realign the profile in that facility model to match where our -- the value sits within our reserves and the life of the fields, et cetera. So the reason why we're doing sort of those adjustments or looking to do those adjustments is, as David indicated, the delays to completion and then the delays to the cash flows that have occurred, which have pushed out sort of, I guess, the reserve tail and also the length of those gas contracts. -------------------------------------------------------------------------------- Unidentified Analyst, [31] -------------------------------------------------------------------------------- Okay. Okay. That's good. So like still roughly 50% of the producing half life is where the banks want to get repaid within? Is that roughly correct, still? -------------------------------------------------------------------------------- Virginia Katherine Suttell, Cooper Energy Limited - CFO [32] -------------------------------------------------------------------------------- I think probably it varies from facility to facility, but I think that's probably a little bit conservative for us. But yes, that's -- it just depends on your business as to what they look like. -------------------------------------------------------------------------------- Unidentified Analyst, [33] -------------------------------------------------------------------------------- Yes. Okay. That's fine. That's fine. -------------------------------------------------------------------------------- David P. Maxwell, Cooper Energy Limited - MD & Executive Director [34] -------------------------------------------------------------------------------- Thanks, [Ralph]. And the comments that you made on the graph on Slide 5. And as I've said in my comments when I was going through the presentation, we roll that graph forward for a few months. You'll see the actual sales increasing simply to meet the take-or-pay levels that we have with the customers. -------------------------------------------------------------------------------- Operator [35] -------------------------------------------------------------------------------- (Operator Instructions) Your next question comes from Andrew Pedler from Matau Advisory, Eight Investment Partners. -------------------------------------------------------------------------------- Andrew Pedler, [36] -------------------------------------------------------------------------------- A couple of questions. One, you commented that the performance in absorber #1, should we call it, has outperformed absorber #2 due to some tweaking sort of have been applied to #1. Roughly, what sort of percentage differences are between them at the moment? -------------------------------------------------------------------------------- David P. Maxwell, Cooper Energy Limited - MD & Executive Director [37] -------------------------------------------------------------------------------- I actually didn't name the absorbers. I said one of them is performing better than the other. And the truth be known, it's actually around the other way. Pre the works that were undertaken in the back end of last year, absorber 1 was performing better than absorber 2. With adjustments, absorber 2 has been performing better than or absorber 1. I'm going to ask Mike to make some comments. I can answer it but not as well as Mike can from a technical perspective. So I'm going to ask Mike to make some comments on that. Mike? -------------------------------------------------------------------------------- Michael Jacobsen, Cooper Energy Limited - General Manager of Projects & Operations [38] -------------------------------------------------------------------------------- Okay. Thanks, David. So for the last 2 weeks, when the plant has been very steady around that 45 terajoules a day, they have been -- when the gas flow rate in 2 is split at about 50-50. They have been trying to match the gas flow. And that's what we've seen for the last few weeks. What they have -- there is a slight difference in the design of a material that acts as the contact between the gas and the solution. There is a different design now in absorber 2, and that is being -- seemed to be giving better performance and less tendency to foam. So currently, they have -- they are tweaking the gas rate between the 2 absorbers. But for the most part of this, it has been 50-50. There is a plan -- and this is one of the points that David mentioned earlier. There is a plan to change that packing material. It's a very simple plastic type of material that goes into the absorbers, a very simple change there looking to make -- or to make the change in absorber 1, which is the first on the gas side, make those changes into absorber 1 to match absorber 2. So they've been seeing better performance over the last few weeks, and they'll make that change to absorber 1. But currently, for the most part, it is 50-50, but they have to make tweaks from time to time. But it's not a significant change between the absorbers. -------------------------------------------------------------------------------- Andrew Pedler, [39] -------------------------------------------------------------------------------- Right. Okay. Next question. I think we've asked these questions years ago, but could you remind me what -- how does Manta gas, what's known of it, compare with Sole gas? -------------------------------------------------------------------------------- David P. Maxwell, Cooper Energy Limited - MD & Executive Director [40] -------------------------------------------------------------------------------- In terms of... -------------------------------------------------------------------------------- Andrew Pedler, [41] -------------------------------------------------------------------------------- In terms of quality, specifications of quality. -------------------------------------------------------------------------------- David P. Maxwell, Cooper Energy Limited - MD & Executive Director [42] -------------------------------------------------------------------------------- Yes, yes, yes. Fine. Manta has no H2S that needs removal. So we don't need to go through the H2S removal component of Orbost. And Manta has quite a lot more liquids, I think in the order of 3 million barrels of condensate in Manta, whereas Sole is relatively lean. Manta is more akin to the fields that were originally put through the Patricia-Baleen plant. Andrew Thomas is with us, who heads up exploration and subsurface. I'll ask him if he wants to add anything to that. -------------------------------------------------------------------------------- Andrew D. Thomas, Cooper Energy Limited - General Manager of Exploration & Subsurface [43] -------------------------------------------------------------------------------- Yes. Thanks, David. And I think you've got it right, David. And it's what they would call sweet gas in the Gippsland Basin. So CO2 is relatively low, as David mentioned. There's no H2S. There's no special processing required to get that gas into a facility that can handle the liquids. So I think the takeaway for that is that it's quite easy to process the Manta gas spec than it is to the Sole gas. -------------------------------------------------------------------------------- Operator [44] -------------------------------------------------------------------------------- Thank you. There are no further questions at this time. I'll now hand back to Mr. Maxwell for closing remarks. -------------------------------------------------------------------------------- David P. Maxwell, Cooper Energy Limited - MD & Executive Director [45] -------------------------------------------------------------------------------- Well, thanks to everybody that's participated and listened to the call. I just wanted to emphasize 3 things. Firstly, the step change that we've been waiting for, for the last 12 months, we're now in the midst of it, and you can see that in the numbers. I ask people to really have a look at the sales volumes numbers because those are the numbers that flow through to the accounts in particular. Second, we acknowledge that the last 12 months has had its challenges for a range of reasons, some beyond our control and some related to the gas plant. The important thing is that the underlying strength of the business hasn't changed notwithstanding those changes. The market is -- the strategy is very clear with respect to the market. The market is strong and getting stronger, and the assets in terms of reserves and customers are unchanged. So one could view 2020 as a deferred year in some respects. And thirdly, the outlook. To be honest, it surprised us in the last few months just how quickly things have moved. And I guess the message in that is that it's the underlying strength of the fundamentals that we've got. So the shortfall in supply and where that supply might come from, whether it's coal seam gas or imported LNG or new developments in Southeast Australia, all point to much stronger prices than what we've seen through the bulk of 2020 in the spot market. So on that note, thank you very much. And please, if you have any questions following the call or following a further read of the results for the half year, don't hesitate to get in contact with Derek. His contact details are on the presentation. And he'll get back to you with answers as quickly as possible. Thank you. -------------------------------------------------------------------------------- Operator [46] -------------------------------------------------------------------------------- Thank you. That does conclude our conference for today. Thank you for participating. You may now disconnect.