Amplitude Energy Limited (AEL) Earnings Call Transcript & Summary

Thank you for standing by, and welcome to Cooper Energy Limited's FY '20 Results Presentation. [Operator Instructions] I would now like to hand the conference over to Mr. Don Murchland, Investor Relations. Please go ahead.

Thank you, Amanda, and good morning, everyone. Thank you for joining us on our presentation on our FY '20 results. With me today, I have David Maxwell, Managing Director; and Virginia Suttell, our CFO, who will be taking us through the results shortly. Plus, we also have members of the executive leadership team on the line for questions and answers after in the Q&A session. We'd encourage you to join into that if you have questions. [Operator Instructions] We'll be speaking with the pack -- to the pack which was lodged this morning with the ASX, which covered reserves, the financial results and, of course, the investor slides. Turning to the Slide 2, some compliance statements and important information, which I understand some of you may be familiar with. And I'll now hand over to David to take us through the results. Thank you, David.

Thank you very much, Don. And I'll add my welcome to everybody who's listening this morning and those that will listen over the next few days. In addition to the FY '20 results this morning, we're going to discuss also the activity in the last 2 months and the general business outlook. The 2020 financial year was a year of 2 contrasting halves. First half, the business performance was very good. In the second half, well, this has been masked by and impacted by the bushfires; the lower oil and spot LNG price; the COVID pandemic; and in particular, the ongoing delays at the Orbost Gas Plant. In a challenging environment, the company, we've stayed the course. We've maintained the strong fundamentals approach. And we're very well placed to supply growing gas production into Southeast Australia, a market where local supply is tight, and it's only going to get much tighter. The 3 -- and here, I'm talking to Slide 3. The 3 standout features of the 2020 financial results are the impact of COVID and the impact of the low oil price and the recent low spot gas price on the results. In the near term, and by this, I mean the next 9 to 12 months, gas price outlook. Secondly, the deferred Sole production, revenue and cash flow due to the delays at the Orbost Gas Processing Plant. And third, the progress and growth in gas assets, which have us ideally placed to produce more gas that's over and above Sole from 2023 onwards when gas supply based on oil forecasts is going to be very tight. The summary bar charts that you see at the foot of this slide will be addressed further in this presentation. Slide 4. There are, in our view, 5 key outcomes or messages in the FY '20 results. Firstly, the $76 million impairment, which is based on valuations determined in the current market environment for what is essentially a very long-term business. The impairment was primarily due to lower near-term gas prices, slightly higher developments and abandonment costs due in large part to a lower U.S. dollar-A dollar exchange rate and some U.S. dollar cost increases based on recent costings and the latest expectations of the regulator's requirements. Second, the Sole offshore project, which is managed by -- which was managed by Cooper Energy, was completed $20 million under the budget of $355 million and within schedule. And this was notwithstanding the offshore pipeline issues we had to manage together with Subsea 7. This clearly demonstrates and underpins our offshore development capabilities, a key asset of the company. Third, together with our Otway partners, Mitsui, we acquired the Minerva Gas Plant. And we immediately commenced the upgrade for what will be a very cost-effective processing hub for existing and future developments. Fourth, we added to our resources with the Annie and Dombey gas discoveries, and we expanded our Otway acreage position. These are all close to gas plants and the gas market opportunities. And fifth key -- and the fifth key outcome was the transition agreement that we announced with APA on the 20th of August, which establishes a clear pathway to completion of the Orbost Gas Plant, commencing -- commencement of the long-term gas sales agreements and rescheduling of the loan facility we have with the syndicate of 5 banks. Now turning to HSEC, Slide 5. Our safety performance continues to be much better than the offshore Australia industry average. And this is as measured by the total recordable injury frequency rate. This result was achieved in a very busy year, particularly the first 6 months. However, we did have one lost time injury. And always in our business, one is too many. I'll touch on the environment and community and sustainability aspects later in the presentation. At Slide 4 -- sorry, Slide 6 and staying with the HSEC theme, our response to the COVID pandemic. Firstly, I want to acknowledge these are extraordinary times and in particular for the people of Victoria, our own people, our contractors, the partners, the customers, the investors, government. We touch many parts of Victoria, and we acknowledge the current situation. And we wish you all the best. Just ask you to keep taking care. In response to COVID, we acted very quickly. And all but a couple of the staff and contract staff worked from home from mid-March until May. We maintained a small skeleton crew at the Athena Gas Plant. We implemented a range of initiatives, which ensured we could monitor the health and well-being of our staff and the contractors whilst adhering to all our standards and requirements, including our IT standards. All the production we operate, which is all of our gas production, is offshore and unmanned subsea installations. What this means is no platforms. We can operate our production wells remotely, and this proved very effective. It's probably worth noting here that we also successfully commissioned one of the Sole production wells during lockdown. And we did this remotely. Importantly, we employ local people at our assets. And this, together with the remote -- our remote operating capability, meant that the impact on our operations has really been negligible. Clearly, the COVID pandemic, together with low oil and spot LNG prices, has, however, significantly impacted the spot gas price. And we expect this to be a very -- however, we expect this to be a very short-term phenomenon. I'll now pass to Virginia to take us through the financials.

Thanks, David, and welcome, everyone. On Slide 7, we have identified key results for FY '20. These are not the results that we had anticipated or had hoped to be presenting for this financial year. The single largest impact has been the delay in subsequent commissioning problems at the Orbost Gas Processing Plant, compounded by the effect COVID-19 has had on the uncontracted gas price and other macroeconomic assumptions. Impairment across the oil and gas assets and E&E assets of net $76 million was announced to market on the 25th of August and is the biggest individual item to impact net profit after tax. Pleasingly, our sales revenue has increased by 3% despite the downturn in oil prices and an associated debt in our oil revenue of $8.7 million. The contribution from gas sales increased from 69% to 81% year-on-year or from $53 million to $63 million. Gross profit decreased from $31.7 million to $23.6 million as a result of increased amortization per boe and a higher toll for Casino Henry gas as well as a reduced netback on oil sales. This flowed through the underlying loss after tax line. Further explanation to specific items can be found in Slide 30 in the pack. The movement in underlying EBITDA year-on-year has been impacted by higher costs within the business associated with growth and the Athena Gas Plant. I will look closer at cash flow from operations later in the pack, but it has increased year-on-year. Our net debt position has increased in line with the payment of Sole final contract value that the offshore project was completed. And debt has been utilized for interest payments until June 2020. The company ended the financial year with $131 million cash and cash equivalents on the balance sheet. Turning to Slide 8. This slide reconciles the statutory results to the underlying loss. Key items removed are the impairment previously mentioned, the liquidated damages received due to the Orbost Gas Plant delay, restoration provision movements and the tax effect of all of those. Delayed liquidated damages have been removed from the underlying result as in the half year as they are not directly associated with the production of hydrocarbons. The P&L impact of re-estimation of restoration provisions for the depleted Minerva and Patricia-Baleen fields has also been removed. The waterfall on Slide 9 steps through the key input to the shift in underlying profit from FY '19. The increased gas revenue was in part due to Sole sales in the fourth quarter but also the higher volumes and contracted gas price for Casino Henry. This has been partially offset by a decline in oil revenue caused by the number of barrels sold and the realized price. Contribution from the Minerva Gas Field to sales revenue ceased late in the third quarter of the financial year. Cost of sales changes are as outlined in the dot points from the slide and mentioned previously but also include costs associated with producing from the Sole field. Outside of operations, there has been some increase in costs associated with administration as Sole comes online, albeit later than planned, and future growth. The commissioning of Sole was the trigger for finance costs previously capitalized into the carrying value of the asset being expensed in the profit and loss. In addition, the care and maintenance associated with the Athena Gas Plant is taken through administration and other expenses until such time that it's processing gas again. And we've continued with our investment in corporate processes and systems across the last 12 months. Turning to Slide 10. The cash flow waterfall demonstrates that the company generated solid cash flows from operations of $40.3 million exclusive of the liquidated damages associated with the Orbost Gas Processing Plant. The company was able to transfer the credit from the exploration expenditure in VIC/P44 against PRRT assessable income from the Casino Henry field, which resulted in a net PRRT cash payment of $4.1 million in its financial year. Debt drawdowns were used as payment for finance costs during the year until Sole cash flows were generated. Exploration and development cash flows were in the main for the contractual closeout of the Sole field development, the drilling of the Annie-1 and Dombey-1 wells and some Cooper Basin drilling. On Slide 11, the key items on the balance sheet are the cash of $131 million, interest-bearing liabilities of $229 million and a net debt position at $98 million. The company at 30 June 2020 classified $26 million of outstanding debt as current. The acquisition of the additional 40% interest in the Athena gas plant has been booked on the balance sheet on completion of the acquisition as have the right-of-use assets for our commercial property leases in accordance with the commencement of the lease accounting standard on the 1st of July 2019. The company undertook a review of the restoration estimates associated with our offshore production wells on the back of revised costing for offshore activities and regulatory feedback during the second 6 months of the financial year. This has led to a revision of the provisions across all of our assets, inclusive of the impact of discount rates and changes to macroeconomic assumptions, such as exchange rates. Receipts of our gas revenue continues to be supported by the strength of our counterparties in our contracting strategy. I'll now hand back to David.

Thanks very much, Virginia. And turning now to operations and Slide 13. Our total production increased 19% to 1.56 million barrels of oil equivalent, which was a record for the company, and -- but there's a lot more in store. Importantly and consistent with our focus on growing a valuable gas business, the gas production increased some 24%. And this more than made up for the natural decline in Cooper Basin ore production that Virginia mentioned. For the total sales -- the total sales revenue increased to $78.1 million. And gas revenue was up 22% to account for 81% of our sales revenue. Gas price and therefore gas revenue is typically not as volatile as oil price, which is important as our gas production continues to grow. These numbers include the first contributions from Sole gas production. Some 2 petajoules were sold at spot prices, which was during the commissioning phase. The prices under the long-term contracts are materially higher than the spot gas prices realized over the last few months, which is consistent with reports that the current spot price is well below long-term gas contract prices. As illustrated in the table on the right-hand side, notwithstanding the low spot gas prices for the 2 petajoules from Sole, which accounted for about 1/4 of our production, the average gas price received for the year was $8.99, a 14% increase from the previous year. Now Slide 14, where we deal with reserves and contingent resources. Here, I'm referring to proven and probable reserves or what's known as 2P reserves and the best estimate contingent resources or 2C. It was a small decrease of about 5 petajoules in gas reserves in our Otway Basin and Gippsland Basin gas assets. This was due to field production and some minor revisions to gas plant fuel assumptions. We also debooked a minor volume of reserves at Minerva due to the cessation of production at that field. In the Cooper Basin, the 2P oil reserves decreased by about 0.3 million barrels primarily due to production. The 2C contingent resource increased 52 petajoules or 33%. This was mainly attributable to the gas discovery at Annie in the offshore Otway Basin. There were also minor 2C increases for the Dombey gas discovery in the onshore Otway and extensions to end of field life for the Casino Henry fields due to the Athena gas plant upgrade. Now the Sole project, Slide 15. As mentioned at the start, the Sole offshore project was completed and commissioned within budget and within schedule. This was an important major milestone for the company. Unfortunately, the onshore gas processing plant at Orbost was late. And then bushfires and commissioning issues, in particular foaming in the absorbers, compounded this delay. The gas plant can process 40 to 45 terajoules a day, notwithstanding the foaming issue. And I'm going to discuss the pathway to the completion rate of 68 terajoules a day on the next slide. To increase the processing capacity to the 68 terajoules a day and hopefully more, there are 2 work streams. And these 2 work streams are being conducted in parallel: the analysis of the root cause of the foaming; and secondly, plant modifications to increase the rate, notwithstanding the root-cause analysis. Slide 16. On the 20th of August, Cooper Energy and APA, who are the owners and operators of the Orbost Gas Plant, we announced the transition agreement, whereby we will pool our capabilities and work together to achieve practical completion, which is 68 terajoules a day of stable production as early as possible. The transition agreement is a clear pathway to practical completion. Under the transition agreement, we are sharing revenue and costs with APA, and the gas is being sold to the spot market until we start our long-term gas sales agreement. The future activities, and these are future near-term activities, as it relates to the Orbost Gas Plant, this week, there's a 6-day shutdown to remove sulfur buildup and install components to enable further testing and analysis to improve the plant rate and reliability. The plant then returns later this week to production, and tests will be run in single-absorber mode. The results from these tests are then the key input into what is being called Phase 2. Phase 2 will involve an approximate 3-week shutdown, probably around November, to make modifications to further improve the plant processing rate and reliability. As I mentioned earlier, in parallel with these activities, the root-cause analysis work will continue. These are distinct steps being taken to get the 68 terajoules a day and hopefully more. We plan the Cooper Energy term gas sales agreements will also commence later this year. Now the results of the FY '20 exploration and development activities with a total cost of some $77 million. And here, I'm talking to Slide 17. I discussed the reserves and resources on an earlier slide. The feature results of the FY '20 program were: the new discoveries in the Otway Basin, and here, I'm referring to Annie and Dombey; the Sole project, which we've already discussed; the acquisition of what is now called the Athena Gas Plant together with Mitsui; and the final investment decision for the planned upgrade expected to be online in the September quarter next year; and the Cooper Basin oil program in PEL 92, which is operated by Beach, where 16 developments and exploration wells were drilled, 3 appraisal wells were cased and suspended, and these results could have been better. Slide 18, the Annie gas discovery. This discovery extends the offshore Otway exploration rate, where 11 out of 12 wells drilled on an amplitude have been successful. The optimum development of Annie is now being evaluated in a project referred to as OP3D, which includes the undeveloped gas in the Henry field. A feature of our main offshore Otway exploration permits, which we share together with Mitsui, is that we have multiple relatively low-risk, that's low risk for exploration, targets, which are being assessed for drilling in the proposed FY '23 drilling program. This will include the Elanora prospect, which was deferred from FY '20 for rig safety reasons. Slide 19. As our gas business grows and oil and gas business is operated by Cooper Energy, our activities in support of our sustainability objectives are also growing. In the last year, we had 0 reportable environmental incidents. We committed to the Task Force Climate-related Financial Disclosures (sic) [ Task Force on Climate-related Financial Disclosures ]. And this was included in our inaugural sustainability report, and we expect to have more to say on this in the coming months. And we increased our activities and involvement with the regional communities around the Otway and Gippsland assets. This included a number of community initiatives focused on health, education and marine. It included the provision of cash and in-kind support to help manage the impact of the bushfires and support the mitigation of the COVID pandemic in these remote regional communities. Now Slide 20. We move on to gas and a few words on the gas market and our approach. Slide 21. For more than 5 years, we've been building our business around very cost-competitive assets. These are resources and gas funds to supply the increasing opportunities foreseen in Southeast Australia. This slide summarizes the model, and I don't plan on going into it in detail other than to say it's a portfolio approach with well-located production development and exploration at the low end of the cost curve. And we continue to grow both the upstream and the market components of this model, and the reasons why will become very clear on the next couple of slides. The next slide. Couple what is happening -- sorry, I'm just a little bit out of order here. Gas prices, Slide 22. We are seeing gas prices in Southeast Australia being increasingly influenced by the export LNG prices. Put another way, the price in Southeast Australia is more and more following the trend of international LNG prices. In particular, spot LNG prices are influencing the spot domestic gas price, a market which is very thin. And there, I'm referring to the domestic gas price market. Hence, the spot price for gas in Southeast Australia has been much lower in 2020 than previous years, just like the spot LNG price. Industry analysts and commentators are expecting the global LNG market to move from surplus to deficit or surplus supply to tight supply over the next 1 or 2 years. Consistent with this, the current low spot LNG prices are not expected to last for too long and will move back to much higher and more normal levels in the next year or so. Now the next slide. You couple what I've just said with what was happening with global LNG supply and prices with the continued decline in Southeast Australia gas supply whilst demand is relatively flat, one can see that come 2022 to 2023, domestic gas prices will increase. In our view, the stable long-term gas price is in the range $8 to $11. And it's this sort of price level needed to support new gas developments. I draw your attention to the quote from a recent ACCC report, which highlights the pipeline capacity to transport gas from Southeast Queensland to Southeast Australia is congested. Hence, notwithstanding what happens with LNG prices, the availability of Queensland gas will be constrained for a good few years at least. Absent new developments, the decline in Southeast Australia supply is much more rapid and the gas price in all likelihood much higher. Hence, why we say focusing on more supply from Southeast Australia is the best supply option for Southeast Australia. Such an approach also minimizes the price volatility and provides the best long-term sustainable gas price outlook. Now turning to outlook on Slide 25. The transition agreement with APA provides a clear and aligned path forward to full production from Sole. With this comes a material step-up in gas production, revenue and cash flow. We continue to grow and develop our gas market book. These are all take-or-pay contracts. And we're now working through what is the optimum gas contracting for our uncontracted Otway Basin gas, this being Casino Henry and the gas produced from the proposed OP3D project. The Athena Gas Plant upgrade is a priority for FY '21 and, when online, will be another valuable asset consistent with our business model. In terms of production, in FY '20, we've produced oil and gas at a rate equivalent to 4,300 barrels of oil equivalent per day. At 40 to 45 terajoules a day from Sole, together with our existing Otway and Cooper Basin assets, we would expect to be doing 9,000 to 10,000 barrels of oil equivalent per day. At 68 terajoules a day from Sole, this would take this to 13,000 to 14,000 barrels of oil equivalent per day in total Cooper Energy share. Slide 26. In FY '21, our activities in the $50 million to $58 million exploration and development program, which is down from $77 million last year, are based around, and in no particular order, the following: increasing oil production rates in the Cooper Basin; progressing the OP3D project offshore Victoria to FID around the September quarter in 2021; maturing exploration targets in the Otway and Gippsland Basins and preparing for the FY '23 drilling program; planning the BMG abandonment activities and completing the Athena Gas Plant upgrade; and of course, increasing the gas sales out of Sole to the 68 terajoules a day together with APA. To summarize, we'll wrap up before we then take questions. The FY '20 year performance was marked by the COVID pandemic, low oil and spot gas prices and the delays at Orbost. Second, in the last year, the company has affirmed its capabilities to successfully explore, develop and produce gas opportunities offshore Southeast Australia. Third, there is a clear pathway with the Orbost Gas Plant, and this will lead to material production increases and the commencement of term gas sales contracts. Fourth, the growing Cooper Energy portfolio is ideally positioned to provide increased gas production and sales for the Southeast Australia gas market opportunities. And fifth, there will be a substantial uplift in production, revenue and cash flow in FY '21 on the back of Sole. On that note, we're happy to hand back and take any questions.

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

David, congrats on the results. I've got a few questions. I guess starting with abandonment and provisioning. Obviously, now in the FY '20 result, you've got about $394 million provisioned on the balance sheet. That's up from about $120 million in FY '17. Just wondering, one, when you have to start spending on those abandonment requirements; and two, whether you now feel comfortable that you've got the right amount of abandonment provisioning on the balance sheet.

Thanks, James. The -- just one of the reasons for the increase is the increased activities. So it's associated also with the likes of Sole and assets that we've acquired. So as your activity levels grow offshore and particularly in production activities, then you have to abandon those at the end of life. We do feel comfortable with the numbers that we've got. And the bulk of the activity for abandonment is long-dated, and it's linked to our Casino Henry and Sole activities. But as to when it starts, we're looking at '22 at the moment for -- and this is all subject to rig availability and obviously regulatory approvals, but we're looking at around '22, doing some abandonment work with the BMG assets. So it is spread out over a period of time.

Okay. And then just around the EBITDAX margin, obviously, come down from 45% to 38%. You mentioned there are a few of the initiatives that you're going with. Do you think you can get yourselves back up to that 45% plus? Or is sort of below 40% the new norm for the business?

I'll say a couple of things, then I'll pass it across to Virginia and say some things as well. I think there's a lot more loaded into the cost line in the last 12 months. And obviously, the delay with the Sole production start-up, and we were selling the Sole gas at spot prices which are quite significantly below the long-term gas sales contracts that we have for Sole. So we don't forecast EBITDAX because in that case, it's very heavily dependent on gas prices. It's something that we'll certainly look to do once we've got Sole up and running and all the long-term gas contracts in place. It will become quite -- it will be quite transparent at that point. The other thing that I would comment on that, though, is that the oil price has had a material impact on that. We had previously much higher oil margins than what we have in the last 12 months on the back of the oil price.

Yes. I guess I was driving towards cost initiatives.

There's a number of things happening on that front. We're driving the cost side, I think, both at Casino Henry and at Sole at the moment. But maybe I'm just going to pass across to Virginia who's got -- I'm sure she can add some comments to that as well.

From a cost initiative perspective, we're reviewing our sort of administrative costs, et cetera, on an ongoing basis and delaying where possible activities. And also this year, we've spent quite a bit of money, as I indicated, on stepping up in our processes and systems. And those processes and systems will allow for us to manage the operations with Sole coming online, the changes with the Athena Gas Plant and then future growth as well. So they're meant to be able to be stepped up and scaled. The Athena Gas Plant, when that upgrade is complete, we will change the operating profile -- cost profile for the gas coming through the Otway there. So there's probably a couple of things. To David's point, the netback position in -- across our assets for Casino Henry was stronger this year. The Sole netback was lower than we had hoped on the back of those spot sales, and then the downturn in the oil price impacted the net PAT. But from cost initiatives, it's something that we're looking at. We're reviewing our cost estimate at the moment, going out to market, trying to establish sort of pricing in a post-COVID environment as well.

Okay. And just finally, talk about the Phase 2 works. Has there been much discussion at all within yourselves and APA about the potential to add a third absorber?

There's a range of options being looked at. And when one talks about adding a third absorber, it doesn't need to be an absorber of the size of the current 2 absorbers. I'm going to mention some numbers here, and I'm going to ask Mike to say a few words. And if the numbers I mentioned are not absolutely precise, Mike will correct me, I'm sure. But the gas comes into the plant at about 1,000 ppm H2S. And what we're seeing is ex -- when we get increased foaming and you start to get sulfur buildup and the gas starts to go off spec, it's not -- it's going off spec -- the spec is around 5 ppm. I think 4 or 5, I'm not absolutely sure. Michael, correct me. And we're seeing ex the absorbers, getting up to 15, 20, 25 ppm. So a small polishing unit, for example, is all that would be needed to take it from that 20 to 25 back down again. So it's that sort of thing -- that's some of the stuff that's being looked at, at the moment for Phase 2. This Phase 2 is not just aligning absorbers. There's some other work going on in Phase 2 as well, all directed at increasing the rate in the plant regardless of the root-cause analysis. But maybe Mike who's -- we and APA are talking all the time together on this now. We've got a joint team between ourselves and APA working very collaboratively on the Phase 2 project. But Mike, maybe if I can pass across to you, you're the lead on this from our side.

Yes. Thanks, David. James, thanks for the question. Yes, you did get the numbers right, David. It's 4 ppm is the gas spec down from 1,000, which is what the gas comes in at. So certainly, James, that is one of the options that we're looking at, just to be able to do that final bit of absorbing on the gas after it passes through the 2 absorbers once they move to [ parallelment ]. So it is one of the options that is being explored, some more testing see how things are performing. And if that's one of the necessary changes, then that's certainly one of the things that can be done in a relatively shortish period of time to go to that final polishing as it was described.

Your next question comes from Adrian Prendergast from Morgans Financial.

David, Virginia and team, very helpful update as always. Just a couple of questions from me on the Otway just around the gas contracting strategy. Just obviously, a lot of the market expected to -- the gas market to sort of tighten from 2023 and beyond. But how much of the current weakness is impacting that contracting strategy? And does it pose any scheduling risk? And then my second question is just on Elanora. Obviously, it looks like very big structured -- will one well be enough to appraise it? And what sort of development would be there contrasting it to Annie, which is obviously very different?

Yes. Thanks. And on the Otway gas contracting strategy, it's about creating the optimum. We've got a project which is economic at the moment, OP3D. And it's a case of saying, well, what's the best business case for us? And time has value here as well. And what we are seeing is customers very interested in contracting for that to '22, '23, '24, '25 period. I'm not so keen to contract for now and next year at the sort of prices that we think are fair. So it is a case of getting the blend right. And maybe it's a little bit higher now and a little bit less than what they might expect in '23, '24, '25. That's one way of looking at it. That's a piece of work that's going on at the moment. And I don't think that what's happening with the gas pricing is a risk for the schedule at all. The main issue for the schedule is getting the best costs. And we're just going out at the moment. We're re-tendering a lot of the costs on the back of we've seen some signs that things are coming down a little bit further. So we're taking the opportunity to re-tender a number of the costs. And it is then bringing it all together in the business case. I think the idea of slipping at 6 to 12 months is not an attractive economic proposition because we want to be there for the gas market '23, '24, '25. A question on Elanora and development. At this stage, we're only proposing one well. But what I might do is pass across to Andrew Thomas, who heads up our exploration and subsurface team to talk about -- I think the question was one well and what -- is that enough to appraise Elanora. And the development concepts between he and Eddy, they can have a chat about that. Andrew?

Yes. Yes, you're right, Elanora is quite a large structure. So if -- it depends what we find in the well obviously, but there is a lot into that. There could be future appraisal. And Elanora -- a success at Elanora actually opens up pathways to a couple of other prospects very close to it. So it's only 5 or 6 kilometers away from the time point on the existing pipeline. So there is an opportunity to connect the well. But depending on the outcome, it may make more sense to do further appraisal on the -- in the upside case where you could have over a couple of hundred Bcf, you'd certainly want to optimize a future development by future appraisal.

[Operator Instructions] Your next question comes from Gordon Ramsay from RBC Capital.

David, I just want to focus on the Sole project. Just trying to get a feel for how you move out of this transition agreement as you boost production. Is it possible you can enter and take complete individual contracts and move forward with them and start getting full contractual gas pricing? Is it going to feel it is incremental? Or does it all happen at once?

No. Our thinking is there's every chance it will be incremental. In fact, we're in a position now that we started to look at when we should be starting some of the contracts. It's not a big bank in that we're not constrained contractually with customers or with APA in the way we've set up the transition agreement, but it's all altogether at the same time, we can build it up. And once we're comfortable that those levels long term sustainable in a 40, 45, which we know is capable now, I would see there's every likelihood. But in the fourth quarter this year, we'll be commencing some of those gas contracts.

Could you please put that in perspective with what APA was saying in terms of an EBITDA of $10 million for FY '21 from the project and how that relates to your numbers potentially?

Well, my understanding and speaking with APA, they phrased that -- as their assumptions as conservative planning assumptions. Our conversations around the transition agreement have been as soon as we are able to start long-term sustainable contracts, that's what we'll be seeking to do. And that's conversations that APA and ourselves have had. And in that world, then a portion of the tariff, not the full tariff but a portion of the tariff would commence to APA. I don't know the ins and outs of their numbers. We don't share our individual accounting numbers. But my understanding is that the numbers that -- what they put out there was what was phrased as a conservative planning assumption.

Okay. And just lastly from me. Just on volumes expected after the 6-day shutdown that I assume just started now, you're talking about removing the sell-through buildup and insulation work to improve the plant rate and availability. Could we get back up to that 40, 45 terajoule a day period between now and the big shutdown in the December quarter? Or is it going to be much less?

I think it's going to be -- it's going to jump up and down a bit because there is going to be a bit of testing. They're doing quite a bit of testing work to get the absolute input parameters for the Phase 2 activity in the December quarter. So I think it will jump up and down a bit, but I would expect to see it up at that -- once we've got the analysis -- got the testing results, then I would expect to see it up around that 40, 45 terajoules a day until we start Phase 2. But the priority is to get the testing done, get the input for Phase 2, and then we'll produce as much gas as we can in the interim until we start Phase 2. And then, Mike, would you want to add anything to that?

Yes, that's right. That's right, David. Certainly, when we get back from the shut around this 6-day shutdown, when they're doing this first part of the testing, yes, we should see lower rates. But the expectation is soon after that, what we know the plant can do, we know the plant can currently do up to 45 terajoules a day. So the expectation is that will complete. Prior to the Phase 2 shutdown in November, the expectation is that we'll be back at that 40 to 45 terajoules a day range.

I wouldn't be surprised it's a little bit above 45, Gordon, because some of the work that's being done in this shutdown is a little bit of work which is directed at debottlenecking as well. So -- but we'll wait and see when we get there.

Your next question comes from Mark Wiseman from Macquarie.

Thanks for the upgrade. Just a couple of follow-up questions on Sole. Firstly, are you able to just clarify what costs are associated with the Phase 2 work and who would be paying for those costs?

Yes. At the moment, the costs for the Phase 2 works are envisaged to be about $15 million on a 100% basis, and that includes contingency and allowances. And our share of that on the basis of $15 million would be $7.5 million. And I think I can say we have a -- it's disclosed that we have an escrow agreement -- an escrow arrangement with APA of $20 million. And those capital works would be -- the funding for those capital works would be sourced out of that escrow arrangement.

Okay. Great. And can I also just clarify, are you expecting any change in the gas price from your industrial and utility customers through this discussion process that you've been going through?

No, no. We have -- the customers have -- we've been very sensitive of the customers' position. And they've been incredibly supportive, and they want to see new supply. They want to see Cooper grow. They want to see more gas come into the market, which is so -- and around that, we're aligned. But no, we've not had a request for price changes. And I put a lot of that down to where the price is set is below where the price is likely to -- everyone expects the price to become 22, 23, 24. So it's a good contract for us and good contracts for the customers over an extended period. We haven't seen any resets and don't expect any reset in those gas prices. Eddy Glavas, who heads up our commercial marketing and development activities, is involved in that. Eddy, do you want to add anything to that?

Yes. I think Cooper Energy and Sole, we give the customers some diversity in supply, and that's also important for them as well. Back to the industrials, as you mentioned earlier, O-I was a foundation contract, and Visy was a recent customer with Sole. So we've been working to move the start dates but none of the other terms. So -- and as David said that overall, on balance, they are good contracts, both for our customers and for Cooper. And it's also -- this is new supply, so that's also quite important.

I think the other thing I would add is that we've also got supply -- we're supplying some of these customers out of the Otway as well. So this is the portfolio approach, for example, AGL and O-I, of being supported out of the Otway as well.

Okay. That's great. And just a final question for me just on the debt facility. You're obviously holding a sizable cash balance in cash and time deposits. But I just wondered if you could clarify, is there likely to be any sort of extension or revision of the maturity payments for that debt facility as we move through 2021?

That's a very timely question, Mark. There's been conversations with the bank syndicate in the last -- on the back of the transition agreement that we signed with APA. And all 5 banks have supported us in changing some schedule dates in the bank facility. At this point, there hasn't been any conversations around changing the tenor of the facility overall. But I would envisage that once Sole comes online at the full rate that there'll be a conversation around what's the right structure for the loan facility. And it was always contemplated that there would be a refinancing once Sole is in full production. Virginia has been managing all the conversations with the banks and our advisers that she can talk more intimately about that. Virginia?

Yes. No, this is just as what you said, David, I think probably just the key point with where we're at with our lenders at the moment is that the syndicates agreed to review and reset dates once appropriate information has been made available, and the time frame for providing that information is Q4 of this calendar year. The information we need to provide is a sort of a technical plan and anticipated production profile and the associated cash flows with that. And that sort of will inform the discussion for a going-forward basis.

I think it's a point worth stressing here, and I guess the answer to the questions that you've just asked, Mark, and highlighted is that notwithstanding the delays that we've experienced at Sole, which are around Orbost, the customers and the banks have been incredibly supportive and very, very constructive. We've kept them fully informed all the way through, and they're in a similar position to ourselves. They'd like it to have started earlier than it is. But they're very supportive because of the value of the long term -- the fundamentals and the value of the contracts and the project over the longer term.

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

Congrats on the results. A few questions if I may. Firstly, just as part of the asset review and the impairment testing you did, you mentioned you've done an update on OP3D development costs and BMG costs. Are you able to give us some of the details around that? Perhaps some unit cost ballpark numbers we can think about for Henry and Annie and OP3D development costs in general?

At this stage, I don't think we are able to give a steer on that. We are seeing the numbers come down for OP3D, and that's on the back of a few things, U.S. dollar numbers coming down and then obviously this exchange rate, which has worked the other way, to take some of that away. So we're not quoting any new numbers on OP3D. But what I can say is we've got a range of cases in front of us, which are economic. And we're looking about strengthening those business cases, strengthening the business case ahead of the optimum, which will take to FID. On BMG, we've -- our exposure there is 90% of the abandonment costs. And the other 10% is paid by partner -- or pro forma partner, Pertamina. We're not giving out absolute costs for BMG, but maybe Iain MacDougall can comment on just what is behind some of the changes that we have seen for the BMG abandonment work because there has been a lot of work done on that.

Thank you, David. So when we look at the various costs, I mean there are a few factors impacting this. Changes in the exchange rate assumptions have been mentioned, though we note that very recently, we see the U.S. dollar -- the AUD improving against the U.S. dollar, which takes some of that, which gives us some of that back. We've seen rig rates move something like 10% over previous assumptions, moved upwards in U.S. dollar terms. Having said that, there isn't really much in the way of benchmarking post-COVID on that. So we're seeing -- we are starting to see some small changes in the other direction. We also, on the abandonment side of things, in general, we're seeing some higher technical standards required by the regulator compared to even 5 years ago with some technical challenges there. So that's -- those are the factors that are driving the changes in those costs.

All right. But that has gone up, yes?

They have gone up a little bit, yes. Yes, yes.

Sorry, just Don here. I want -- while we're on that, I want to just clarify, we spoke about the timing of that in response to James earlier on. And I think you might have said FY '22. I think we're thinking -- you said -- I think you said 2022. I think we think it's going to fall in the '23 financial year.

Sorry. Yes. Sorry, you're right, yes.

Yes. So that's my question. Are you expecting the total sum of BMG abandonment to fall all within FY '23? Or will it be spread over more than 1 year?

Be spread. One of the things we're looking at, at the moment is what is the optimum way to schedule this as well, to do it all at once or to do it in -- to do part of it now and then do part of it later on when there's low-cost opportunities available? Now we don't include that low-cost opportunity thinking in our planning for impairment purposes. But it's about optimizing and making things safe as early as possible and then optimizing the costs.

Great. My next question is on just Casino. With the delay in OP3D, how do you think we should think about the client rate there ahead of the OP3D development wells finally coming in?

Yes. What we've seen is Casino Henry has held up very well. Production has held in that sort of 32 to 35, 36 terajoules a day pretty constantly. When we move across to Athena, we're producing against a lower plant inlet pressure, so we can get more volume as well. So there's some -- obviously some natural field decline, but we're seeing the field not declining as fast as we thought. And then move across to Athena, we can produce at higher rates under the same -- otherwise under the same -- for the same conditions just because of the lower plant inlet pressure. So we have included in our guidance our outlook for the Cooper Basin and Casino Henry. But it is in that sort of drifting down towards 30 terajoules a day on a 100% basis.

Got it. Great. That's nice. That's great. Our next question is also just on Sole, a couple of things there. One is on the APA agreement. Are you able to give us an indication of OpEx for the Orbost plant so that we can -- now that we need to kind of model this split cost-sharing between you and APA?

It's -- we haven't got that information out there. This between $2.5 million and $3 million a month operating costs all up, that's ourselves and APA, closer to $2.5 million than to $3 million. And that's shared 50-50. And that includes the offshore operating costs as well. So it's offshore operating costs and the plant operating costs, that's all up. That's everything included.

Great. That's great disclosure. And my final question, that is also, just this agreement with APA, how long does the agreement last to? And what happens at expiry of the agreement in terms of each party's legal rights if we still don't have nameplate reached by then?

Yes. It's a good question. The -- as the title of the agreement suggests, it's a transition agreement. Maybe a little bit of a discussion on what's behind the logic of it because that is really important. The agreement that we were operating under previously was the so-called development agreement. And the development agreement was the agreement that governed us and APA through the construction phase and the commissioning phase. Once the plant got to 68 terajoules a day, we move into the gas processing agreement. As we've -- as is publicly known, the liquidated damage is capped out. And so we were -- not in no man's land, but we were in an agreement which really wasn't designed to address the circumstances that we were jointly facing. And it's really important that we and APA work together to get to practical completion or to get to the 68 terajoules a day as early as possible. So the transition agreement is an agreement that takes us -- effectively bridging us from the gas processing agreement -- sorry, the development agreement to the gas processing agreement. Once we are in the gas processing agreement, that hasn't -- that doesn't change, and the transition agreement falls away. So it -- and that was important for us, important for our customers and important for the financiers and important for APA obviously as well. So in terms of -- and then once we're in the -- once we are in the gas processing agreement, then the terms and conditions of the gas processing agreement apply.

Great. So I guess my follow-up question to that is that if you don't reach nameplate, what commercial arrangement then governs the relationship? Do you stay in the transition agreement forever? Or is there a natural [ expansion ]?

No, I don't think we -- no, I doubt that. I doubt that. Look, I mean if we got to -- let's assume we get to a number like, I don't know, 65 or 60 or something like that -- we will get to 68. It's a question of when. And as Mike's indicated, there's work that can be done, and the technology is working. But if we got to -- we got very close to 68, so we got to 65, we would sit down and work it out, and we will be in the gas processing agreement at 65.

Great. Just one last question if I can squeeze it in. Are there any discussions with Seven Group regarding extracting synergies with their Longtom development, which they're also looking to take through Orbost?

There have been conversations in the past. There haven't been any recent conversations. We consider the Seven Group if they -- if we bring -- we're looking to -- talking about the FY '23 drilling program is a good plan. And we've got a number of targets there, which we think are very interesting. We'd certainly welcome the Seven Group as a partner in the rig program. And there have been conversations with Seven around processing -- restarting Longtom, but that hasn't -- those conversations haven't been held for some time, for some months now.

Your next question comes from James Redfern from BofA.

I just had a quick question on Casino Henry. Just wondering if you could please confirm the contracted gas volumes for FY '21. And then I got another follow-up from that, please.

For FY '21 for Casino Henry, we are fully contracted to December of this year. And then I can't remember exactly the number. We've got some gas. Eddy Glavas is on the line. He can give us the -- how much is contracted and how much is uncontracted for -- from January onwards.

Yes. January onwards, there's a GSA with O-I. I think it's for 1.5, 2 terajoules for the year, and the rest of it remains uncontracted. What we're doing at the moment as we transition to the Athena Gas Plant, we're moving through from Iona to Athena, from firming up the product there. So we're balancing all of that with the customers that remain and their short-term and long-term needs.

Okay, okay. All right. And then comments before about that. Did you say that the LNG market is going to move into deficit in the next 1 or 2 years? Is that what we said?

Yes. We've done a lot of work in the last 12 months to understand the market dynamics of Southeast Australia. And what we see is the LNG market -- spot LNG price increasingly influencing the spot gas price. And then so we went, had a look very closely at the global LNG market. And every way we look at it and all the commentators and talking to a wide range of players in the market suggests that supply's a bit to be in surplus at the minute. But come '23 onwards, that moves the other way quite quickly. And if projects are put on hold and pushed out, then that is exacerbated. So the information we have and all the intelligence that we receive in speaking to people is that '23 onwards, the LNG market turns from being a surplus to very tight.

Okay, okay, okay. And then just on the Seven transition agreement probably, is it correct that post the various shutdowns at -- by, say, December, for example, if the Orbost plant can process 45 TJs a day, then the firm sales contracts will begin based on supplying 45 TJs as day at, say, $7 obviously a gigajoule. And then if the process increase to 65, then obviously, it would set up to 65 TJs a day at $7 as opposed to selling gas at spot at $3 to $3.50 at the moment. Is that how we must think about it?

When we start the long-term gas sales agreements, we'll be starting the pricing consistent with those agreements. And just an answer to the question earlier, I think it's highly likely that, that will be on a gradated basis. I'd like to think it's all going to be at the same time. And if it is, that's great, but that would be sooner rather than later. But I think in all likelihood, it's going to -- once we know long-term sustainable rates post the Phase 2 works, then we'll be starting contracts up to that.

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

Well, thank you very much to everybody for the questions this morning. Our approach in investor calls is to be as transparent as we possibly can be whilst recognizing there's a number of things that are commercial. But I think from the presentation and then the questions and answers today, you get the sense that the last 12 months, we have had our challenges. And they have been around the delays in particular associated with Orbost and the Sole gas project. But notwithstanding that, the company is ideally positioned, strong balance sheet, prospects in terms of projects, development, exploration and the 2 gas plants, the Orbost plant together with APA and the Athena plant together with Mitsui. We're ideally positioned to supply increasing gas profile, cash flow, revenue over the next 2, 3 years. And we expect to see FY '21 results with significantly larger production, revenue and cash flow than what we had in FY '20. So on that note, thank you very much for your time. Thank you very much for your interest in the company.

Thank you. That does conclude our conference for today. Thank you for participating. You may now disconnect.