Amplitude Energy Limited (AEL) Earnings Call Transcript & Summary

Thank you for standing by, and welcome to the Cooper Energy Limited FY '21 Full Year Results Webcast. [Operator Instructions] I'd now like to hand the conference over to Mr. Derek Piper, Head of Investor Relations. Please go ahead.

Thank you, Ari, and good morning, everyone. Thank you for joining the Cooper Energy FY '21 full year results webcast. We released our results this morning and a presentation which went out a few moments ago. And this morning, we'll be talking through that presentation. With me is David Maxwell, our Managing Director; Virginia Suttell, our Chief Financial Officer; and other members of the executive leadership team. We'll walk through the slides and then open the lines for Q&A. So David, I'll hand over to you.

Thanks, Derek, and welcome to everybody on the call this morning and anybody that listens to this on the webcast later. A few introductory words,that the Cooper Energy FY '21 results are solid, albeit less than we have planned 14 months ago. And this is because of the delays and issues at the Orbost Gas Processing Plant, which is operated by APA. We are committed to doing all we can to make sure the Orbost processing rates are maximized, and there's a lot of value in this for our shareholders. In FY '21, the significant value in the gas portfolio approach we adopt was clearly evident. Before getting into the presentation, I'm going to explain why we took some actions that we did in the last financial year. APA was late with Orbost, and we had received the maximum liquidated damages available under the development agreement. But the gas plant was not yet at nameplate capacity, and that being 68 terajoules a day. It has been key that we support our customers and support the gas sales agreements. This was also important for the loan facility we had with our very supportive banks. We had to manage this time disconnect. Therefore, we negotiated the transition agreement to bridge to the long-term gas processing agreement. In these challenging circumstances, this was a key milestone for us. And it has meant the accounts may appear a little complex. Hopefully, that is explained this morning. I thank shareholders for your patience in what has been a challenging period. The fundamentals of the Cooper Energy business and the outlook are strong and getting stronger. Last year is not reflective of future value. We will explain the basis for this during this morning's call. The 3 key messages I think you should take from today's presentation are: Firstly, solid results during a challenging year. This is evidenced by record production, record sales volume and record revenue. It's evidenced by material cash margins generated on our gas business, even with the challenges and it's evidenced by we've retained the sound balance sheet. The second message is the strong second half momentum. This is evidenced by the significant increase for growth the second half results due to the commencement of the Sole Gas Sales Agreements mainly in January. We used our gas portfolio approach to maximize long-term value and mitigate risks. We're now earning good margins on our sales volumes -- sorry, on our Sole volumes despite the Orbost issues. And importantly, we met 100% of every customer nomination on every day and this momentum is continuing into FY '22. The third key message is that we're well positioned for continuing sustained growth. To support this or to illustrate this, our Southeast Australia gas strategy is long established and robust. This increase in cash generation from our existing assets, the Athena Gas Plant will soon be operational. And as I noted earlier, we have a sound balance sheet. Now turning to Slide 3, the value proposition. We're growing cash flow and earnings. And just to illustrate, a $50 million cash margin was generated from the gas business in FY '21, notwithstanding the challenges. Third-party gas purchases had a relatively small cost impact on our margins. Across all our Sole gas sales, the margin was more than 85% of what would have been achieved if we were operating normally. That is if the Sole GSA volumes had all come through the Orbost plant. Applying a notional margin of $3 a gigajoule to our 2P reserves infers approximately $900 million of margin to be generated from our existing reserves, and that's before any reserve additions and any production growth. We're increasing control and improving the performance of the 2 gas hubs. And here, I'm referring to the hubs at Athena and Orbost. At the same time, we are seeing increasing gas supply shortfalls in Southeast Australia and gas prices are increasing. We have a range of cost competitive growth options in the existing portfolio to increase and extend the growth. There is clear support from our banks and customers. We report regularly to the banks and they get their own technical advice. Interestingly, the equity markets seem to carry a view different to the debt providers. Now to Slide 4. Improving Orbost's performance has meant increasing sold production which delivered a record for total production. It was up 69%. The Sole gas reservoir and offshore facilities are performing in line with expectations. The commencement of the Sole Gas Sales Agreements drove record sales volume and revenue results, which were up 94% and 69%, respectively. Safety outcomes were pleasing, particularly given the challenging COVID backdrop. We offset all our CO2 emissions so we were net 0 in FY '20 and FY '21, and we delivered on a number of projects and opportunities, and we did this very cost effectively. These projects are all required to support a growing business and cash flow. In this, I want to highlight the gas portfolio approach and the ability to optimize for value and risk across the different sources of supply. This affords us a lot of opportunities and flexibility. Now comparing the second half to the first half to illustrate what I'm saying about growth. The second half momentum is clearly evident from these figures with the key indicators, all up for the second half compared with the first half, and this is continuing in FY '22. Comparing half-on-half, production was up 19%; sales volumes up 49% and underlying EBITDAX up 109%. You will note and read the guidance we're providing for FY '22, and I'm going to cover this on a later slide. Just a few quick words on the Phase 2b works at Orbost. I highly recommend people to listen to last Friday's webcast, where Mike Jacobson and Dean Johnson took us through the reasons for our confidence around Phase 2b and improving Orbost performance. On Friday, we reported the $20 million cost estimate for Phase 2b. That's on a 100% basis. This is shared equally with APA and the Cooper Energy share is expected to be largely funded from the existing escrow account. This means a minimal impact on our cash reserves. I know investors would like to hear affirm expected Sole production figure post Phase 2b works. For a number of reasons, we're not in a position to advise this at this time. However, I do point you to our production guidance, which incorporates our prudent low and high case scenarios for Orbost in FY '22. Now a few words on the Athena Gas Plant, which is operated by Cooper Energy. The commissioning of the Athena Gas Plant is imminent. Once back online, this plant will mean we can deliver stronger margins and increased daily volumes from the Otway Basin gas reserves. The Athena plant provides significant processing capacity for OP3D and other future discoveries. The team's have done a great job in delivering this project to date. As I mentioned, we're now down to the critical final stages before we introduce gas into the plant and connect the plant to our existing Casino, Henry and Netherby wells. On health, safety and the environment, we had no COVID cases and this included all the staff and contractors working at the Athena Gas Plant. We had 2 minor safety incidents, which meant that the recordable injury frequency rate increased. These incidents were contractors; one was a hamstring strain and the other a cut on the nose. With both incidents, the party returned to work the next day, and there were no days off, no days lost. We had no reportable environmental incidents at our operated sites. Some words on our low-cost industry-leading approach to emissions management. Cooper Energy is Australia's first carbon-neutral domestic gas producer and the net 0 status was independently audited. We're many years, and here, up to 30 years is what I'm talking about, ahead of most of our peers, albeit we have a relatively small emissions profile. This standing is receiving great feedback from our investors and lenders. We have a range of low-cost initiatives to maintain our leading position, and we look forward to sharing updates as we progress these. I'm now going to hand over to Virginia to take us through the financial results.

Thanks, David, and good morning. Headline financial metrics for FY '21 are outlined on Slide 11. It is clear that these results are impacted by the ongoing commissioning of the Orbost Gas Processing Plant and the delayed commencement of long-term management for the processing of Sole gas. Positively, we had a 60% increase in production year-on-year, attributable to a full year of producing gas console. Similarly, the company reports a 94% increase in sales volumes off the back of the commencement of the Sole GSA. Sales revenue has increased by 69% and compared to the previous financial year, with the largest step-up in the second half of FY '21, underpinned by the Sole contract. This was a result of strong customer relationships and the transition agreement with APA allowing the service those long-term GSA. This result is inclusive of slightly lower volumes at Casino, Henry, Netherby as expected; lower realized spot gas prices achieved on full volumes in the first half; and greater fluctuations in pricing due to sales in the Otway supporting supply mitigation. The focus of the company has been securing a pathway to market and maintaining the long-term value associated with the processing and sale of our hydrocarbon. The Sole reservoir is performing in line with expectations, and the East Coast gas supply demand situation is unfolding as predicted. The transition agreement was needed to get through this period. But the bottom line and underlying results are not on the whole were anticipated had nameplate capacity at all of being reached. In key metrics, sales revenue is showing growth of any sharing arrangements with APA. The average realized gas price reflects the first 6 months of the financial year, where gas was sold into the stock market but has improved in the second half. The breakdown of the costs associated with the transition agreement, excluding the toll, but including the purchase of gas can be found on Slide 30 in the appendix. And the contribution to Phase 2 works has been captured outside of production costs and stripped from the underlying result. Operating cash flows overall have decreased, but our cash flows generated by our assets before taxes and finance costs have increased. I will give some further detail on cash movements on a later slide. Capital expenditure incurred has decreased, reflecting the status of our projects with the major spend in the period associated with the upgrade of the Athena Gas Plant. Statutory and underlying results are looked across the next few slides. Cash and debt are reflective of the commencement of servicing of debt from cash flow as well as the commencement of amortization of the facility. Turning to Slide 12 to discuss the bank facility further. During the financial year, the amortization period for the senior debt facility commenced. The debt draw down ceased as capital expenditure associated with the offshore execution of the Sole project wrapped up. As mentioned, interest is being serviced from cash flow and with fees to be capitalized into the carrying value of the Sole asset in line with the start of production. Amendments to some of the terms and conditions were agreed with lenders during the last quarter of the financial year. These amendments secured a resculpt of the repayment profile on the basis of current Orbost performance, the expiration of the transition agreement in May and the timing of the Phase 2b work. The facility tenant was not extended at this time. A refinance is anticipated to align with other activities in the business, for example, the Otway Phase 3 development. Moving to Slide 13, where a breakdown and reconciliation of statutory to underlying loss and EBITDAX is provided. Until long-term processing arrangements commence, the underlying result reflects operating costs that are impacted by bridging arrangements with APA and associated processing volumes. The underlying results have not been adjusted for the impact of the transition agreement as these costs are associated with production and form part of the cost of sales. Operating costs have been one of the biggest contributors to the result. In particular, the commencement of tariffs for processing Sole gas sold into the Sole GSA and amortization of the assets, recognizing, of course, the margin is lower for Sole than for Otway gas. The Orbost tolling arrangements are front-end loaded in the initial years of field depletion. This effectively pays for the planned upfront capital investment in the plant. The processing toll during this period for gas produced through Orbost and Sole -- into Sole GSA is consistent with the gas processing agreement negotiated in 2017 as part of the APA transaction. Slide 14 compares the movement in underlying NPAT across periods. As was the case in the first half, the most significant movement of the step change in gas revenue was $55.9 million and the associated cost of sales, which is inclusive of amortization of the cost of development of the Sole field as well as transitional arrangements. Other movements of note are the finance costs, which captures the full year of expensing of interest, an increase in new venture spend as well as costs associated with system and process upgrades and certain provisions. Lower E&A expense in FY '21 corresponds with lower exploration activity. The G&A profile for the company has been pleasingly contained through actions undertaken in the business to effectively manage costs through this period. Turning to Slide 15 On this slide, I will now step you through drivers for the cash flow result and some of the individual line items. Cash flows generated by our assets before taxes and finance costs in the operations waterfall item increased year-on-year. They are, however, lower than planned, and this is in the main volume driven with some price impact through first half spot sales and oil prices. There is some timing impact in these cash flows with variable payment and collection terms having a working capital impact due to the commencement of these activities during the period. Other items resulting in the overall operating cash flow result of $8 million, a cash G&A, restoration spend associated with planning activities; interest payments for the full 12 months and quarterly [priority] payments for the Otway. It is worth noting that our higher operating cash flow result of $48.1 million in the prior financial year included $20 million of liquidated damages associated with delays at Orbost. Cash capital expenditures reduced with the spend represented in the main by the Athena gas plant. In addition, $11.4 million of principal repayments were made, both in cash and cash equivalents was $91.3 million at balance date and does not include funds held escrow for Phase 2 work, including the remaining funds identified figures for Phase 2b nor does the movement include the use of $11.2 million of escrow funds for Phase 2a. I'll now hand back to David to take you through the remainder of the pack.

Thanks very much, Virginia. And I also note that today is the last time you will hear Virginia's voice delivering the Cooper Energy results as Virginia has decided to take a break and pursue other opportunities. As I noted earlier, the strong momentum is continuing, and this is reflected in the FY '22 guidance. Now that we have started the GSAs and the long-term Sole production, we're also providing EBITDAX guidance. We are guiding to a production increase of 14% to 37% or 3 million to 3.6 million barrels of oil equivalent, a sales volume increase of 24% to 43% or 3.7 million to 4.3 million barrels of oil equivalent, and underlying EBITDAX up 100% to 133% to $60 million to $70 million. On the next slide, on capital, we're guiding for a relatively capital-light year. However, our valuable growth projects are progressing. Total capital guidance is $25 million to $30 million allocated across the 3 basins with the allocation of approximately 50-50 between exploration and development. Note, this includes OP3D expenditure as we progress through the select phase and front-end engineering and design. The costs for abandonment planning are not included in capital expenditure. The abandonment planning costs in FY '22 are expected to be some $9 million, and this covers planning for both BMG and Minerva abandonment. On the next slide, we illustrate the categories of growth options within the existing portfolio. Our approach is all about setting the robust long-term base levels of firm production, cash generation and earnings and then building on this foundation and growing further long-term cash generation and earnings and managing this with sustainability uppermost in our minds. And when we talk about sustainability, we talk about sustainability in all respects as well as material 2P reserves, we have a broad portfolio of near-term high-margin growth opportunities. Importantly, we have the flexibility to time these growth opportunities based on the gas market outlook and funding capacity with an eye to what maximizes shareholder value. On OP3D, once the Athena plant is online, our attention turns quickly to increasing the gas process through the plant, and the first opportunity is OP3D. This is a very high-margin project, and we're now working with our joint venture partner, Mitsui, preparing to enter feed. We're targeting an OP3D final investment decision in this financial year. On Slide 21, beyond OP3D, we have multiple opportunities in our existing Gippsland and Otway Basins portfolio, as you can see from this slide. The size of the bubbles highlights that we have some significant prospects to pursue. Just look at and compare the size of the bubbles with the size of Sole. Note, these are the net Cooper Energy numbers. And by this, I mean, this includes only the Cooper Energy 50% share of the Otway opportunities. The key Otway prospects are seismic amplitude supported and just like the nearby producing fields. The recent gas discoveries by Beach Energy, and here I refer to Artisan and Enterprise are further examples which serve to validate the expected success rate for amplitude-supported prospects in the offshore Otway Basin. 13 of the past 14 such Otway wells or prospects have been successful. You can quickly see the value the Athena gas plant represents as it provides the opportunity for rapid monetization of any new offshore Otway Basin discovery, on top of OP3D. Now turning to Slide 22. Here, we illustrate the proximity of our permits and prospects to existing infrastructure. This highlights the value of our twin gas hub strategy and shows what we have very deliberately built over the last few years. We're now positioned to deliver increasing gas volumes into what is a tight gas market that is getting tighter. And that's a very good segue into discussing the gas market. Gas production in Southern Australia is in decline. This is something we foresaw some time ago. Almost every day, you can read about this in the press. Here, we have used forecast from EnergyQuest and AEMO, which very much align with our own analysis. Increasingly, Southern Australia is dependent on Queensland -- sorry, is dependent on gas from Queensland, which includes a significant pipeline transport cost for Queensland gas to be delivered to the populous Southern states. The lowest delivered cost gas for South Australia is gas from Southern Australia. The importance of the right policies and maintaining the right settings to support the continued development of new gas supply is clear, and Cooper Energy is ideally placed. Now to Slide 25. Here, we illustrate the increasing reliance of Southern Australia on Queensland Gas. For Southern Australia, this inevitably means the increasing influence of LNG markets and LNG pricing on domestic gas pricing, whether it's gas from Queensland or imported LNG. As illustrated on this slide, the volume of gas being transported from Queensland to Southern Australia is increasing and particularly in the winter months. We also note the plans to increase the gas pipeline capacity to support the further increase in gas volumes being transported from Queensland to Southern Australia. Specifically now on gas prices, as illustrated on Slide 26, there's an emerging close link between the gas price, in this case, the Victoria spot gas price, and LNG pricing. This is a forecast from EnergyQuest, which is very similar to our own analysis. Our view is that the new long term, and by that, I mean, multiyear gas sales contracts will include Citygate gas prices in the range $8 to $11 a gigajoule. This is what we expect to be the case. At these price levels, our significant inventory of gas supply opportunities is very valuable. To wrap up. There's a lot to absorb from what has been a year of challenge for Cooper Energy. In short, FY '21 was a year of 2 halves. In the first half, we were getting things sorted out after the delays APA had experienced at Orbost. The second half is a different story. In the second half, 1 can see the strong cash generation and growth and we're working hard to continue this and get it to where it needs to be. And this is -- and by this, I refer to 68 terajoules a day at Orbost and hopefully more, plus growing the gas processed through Athena. The momentum and growth trajectory from the second half is continuing in FY '22, and we'll continue beyond them. This is reflected in our guidance. which now includes EBITDAX guidance. The FY '22 work program is focused on increasing the Sole production with the Phase 2 works at Orbost, in particular. Add to this, bringing the Athena Gas Plant online, which enables increased performance metrics from our offshore Otway Basin assets and then ongoing growth. You can see the pattern. We set the cash flow and earnings base. We grow the cash flow and earnings base and then we repeat this cycle in a sustainable way. The approach we're taking to the business is very disciplined and built around the set growth sustained. On that note, we finished the presentation and happy to open up for questions.

[Operator Instructions] Our first question is from Saul Kavonic of Credit Suisse.

David, I just have 2, if you don't mind. Just the first one on the decommissioning of BMG. I just want to get an understanding, if you could remind me of what was the indication you gave of the cost of BMG? And was that based upon full removal of all facilities or was that based on getting an exemption from not CMR and allowing for some facilities to lay in situ?

The timing for -- well, first of all, a few comments. Firstly, we provision for BMG banner, as you would expect, and that gets reviewed at the half year and the full year. And the planning base that we're working to is the decommissioning end of calendar '23. And we're in conversations with NOPSEMA around that at the moment. And then as to the kit to be removed, yes, we are working on the basis of being consistent with the NOPSEMA guidelines at this point. Now the size of the work program, obviously, is ultimately dependent on the results of those conversations with NOPSEMA but we're taking a fairly conservative prudent approach in our planning base at this time. Does that answer your question, Saul?

Just perhaps a follow-on is the proposed changes that on the decommissioning front, which is being flagged and the requirement for financial assurance and so on. How do you see this if it used to go through in its current proposed form by NOPSEMA and the government, how do you see this impacting Cooper for next year?

I don't see any material change because we're planning for that abandonment now. I think what -- and the changes, I think, are going to occur more in the medium- and longer-term for other assets. And what we're hearing and in discussions with NOPSEMA is that people need to be planning -- NOPSEMA is looking to operators to plan well in advance of the activity. And in our case, for example, think through Casino, Henry or Sole. So it's as you're approaching the end of field life, then you've got the plans in place and NOPSEMA is comfortable that those plans are fair and reasonable, both on a cost and time sense. And they're looking to have field facilities abandons within a period, within a predetermined period of the end of production. And that's consistent with the way that we are planning. In the case of BMG, I'd point out that we've been working on BMG abandonment now for the last couple of years. We've got a small team working on it. I don't think it's any secret. It's in the public domain. We're working together with Helix Energy to secure a special-purpose vessel for BMG abandonment and the timing and cost of that is what we're working through with Helix at the moment.

My second question is just on OP3D. Are you able to give a kind of even ballpark number for the CapEx of OP3D? And just confirm why the delay in the FID timing. You previously indicated you're expecting kind of negotiations on funding to happen within the next couple of months. That's now that time frame is being taken away. Is there something wrong with those discussions? Or what else has been driving the delay?

Yes. Firstly, on the cost, they will be looked at -- they haven't changed much, but they'll be looked at as a part of feed and so I'm a bit reluctant to put any new numbers out there at the moment. In terms of the timing, it's really linked to 3 things. One, the Athena gas plant and that coming online because as we said in the presentation, what comes in behind that is OP3D. Two, we are in discussions with Mitsui about just what the size of that program is because it's not just OP3D, we'd take the opportunity in all likelihood to add in exploration opportunities at the same time. And then the other thing, and I think it's absolutely out there. The delays at Orbost have meant that we needed to shore up the certainty on Sole because the refinancing of the bank facility is a key aspect of funding for OP3D. We restructured the -- resculpted the finance facility. And the next phase as Virginia reflected is a refinancing, and we're looking to do that in the next year or 2, and we would tie that in and around FID for OP3D. So -- and I won't bucket, but the delays the issues that Sole have impacted the timing for us in the offshore Otway. The other thing is that I don't think one can ignore the impact of COVID it has added -- whilst we've stayed pretty much within budget on the Athena project that has added a couple of months to the Athena project. And yes that causes one to -- not to take stock, but it causes one to do things in a more deliberate fashion.

Our next question is from Nik Burns of Jarden Australia.

Just wanted to start, first of all, on gross and net debt. Thanks, first of all, for providing EBITDAX guidance for FY '22. Just looking at your net debt position at the end of '21, it looks like it's increased by $29 million through the year, which was probably a relatively light year from a CapEx perspective, and it looks like FY '22 going to be in a similar vein. And as you touched on with Saul, you've got OP3D that's going to come sometime later, which you will see a big step up in CapEx. With the improving production and underlying EBITDAX up by more than 100% versus FY '21 levels. Do you expect net debt position to improve by the end of FY '22? So that's the first part. And just a quick 1 on gross debt as well. Just your current debt liability and your balance sheet has $60 million there. Just wondering if that's an indicator of the principal component that needs to be repaid in FY '22?

Yes. I'm going to ask -- the second question first, so quickly answer it, and then Virginia on the net debt question. The gross debt, I think you're referring there to what we're flagging as repayments in this financial year?

It's just on your debt, you're showing a current liability of $60 million against your debt.

Yes. yes, there is a larger payment at the end of FY '22, and that coincides with timing and when we think we'd be refinancing the facility as well, but that's not built into the numbers. Obviously, that's the facility as it is today and the resculpted payments. In terms of net debt, Virginia?

Yes. So net debt, you're right, Nik, there has been that change. I mean we are in a position where we are not generating the cash flow in the business that we would have liked to have been generated. We're not seeing the volumes coming through or loss that we would have liked. So Absolutely, cash flow is not there. So we are repaying the debt. We did resculpt both the terms and conditions of the facility to structure that so that it was more in line during this period with what we're seeing in performance. But we do need to service the debt and the cash has been impacted that with cash not being generated in the businesses we would like, we are progressing the critical Athena gas plant project. So there has been use of cash reserves to ensure that we can continue to progress the growth opportunities within the business whilst we resolve the issue with Orbost.

Does that answer the question, Nick?

Yes, it does. That was great. Look, maybe just 1 more for me. I'm just interested in your comments, Dave, around the value gap between debt and equity markets. Can you explain that maybe a little bit more? And why you think that is? And what actions do you think that you'll be taking over the next 6 to 12 months that will allow that gap to be closed?

Look, I don't have the wisdom of Solomon as to exactly why it is the case. I think that -- and this is a personal view, but the banks who, as I said, have their own technical advisers, see everything. The contracts, the arrangements with APA, our budgets and cost schedules and they do their own models. And I think they probably take a more bottom-up view, look at the fundamentals and are able to see the value that sits there. I don't want to be critical of the equity markets, but I think equity markets are very short-term responsive and don't look through to see what's there, and react to things very much in the moment as opposed to what might happen over the next 6, 12, 18 months. I think one thing that the banks certainly see is the strength of the revenue stream and the underpinning of the revenue stream that comes with the gas sales agreement. I don't think that -- and they also see the value in the flexibility we have in the gas portfolio. I don't see the -- I don't think the equity markets are picking that up at all. Look, I'd invite Virginia to make any comments. She's the one that's managed the conversations with the banks and obviously has the exposure to the equity markets as well. Any reflections that you've got from that?

Yes, I think that, as David indicated, lenders have pretty intense line of sight to what's going on within the business, as you can imagine. The underpinning of their interest in Cooper Energy is twofold. One, it's about the current state and the value that exists in our assets at the moment. So they look at the reservoir, how it's performing, they look at the pathway to market and the contracts and processing, of course, is the third limit of that. So that they look at all of those things and their interest is around how do we service their investment in Cooper Energy. And then secondly, they're interested in, well, how can - banks are in the business of lending money. Our banks are oil and gas bankers, so they are still interested very much so in the ESG space, but also still interested in banking oil and gas. So they are looking at the future growth opportunities and understanding that as well. And looking at how they can assist in the achievement of that.

Yes. I just -- I think I'd just add a couple of comments to that, Nick. And the bank security in our existing business is in the 2P reserves and the GSAs. And then it's how that's monetized over a period of time, which is really the resculpting or the shaping of the facility and the repayments. The fact that the banks work together with us on the resculpting, I think, is an important marker. The other thing -- and exactly as Virginia just said, is they're not in this for one arrangement around the existing Sole project and the existing customers. They're in this to build a book and over the longer term. And they look through and they look at the fundamentals of the business and the opportunities that are coming up. And obviously, they -- I'm not going to speak for the banks, but the refinancing on the back of OP3D, where you've got a proven gas -- at that stage, you've got a proven gas plant, known reserves and you're contracting with investment-grade customers and upsizing the business with a stronger base, a cash flow is a good proposition for them. So -- and there's growth to come behind that. So I have to say, I think the banks take a more fundamental approach than the equity markets.

It's from Mark Wiseman of Macquarie.

You mentioned in the call, the Minerva abandonment. You've discussed quite a bit in the past, the costs associated with the BMG abandonment and the provision. But just wondering, could you talk through what's the timing and scope of work to be done at Minerva?

Yes. There's a few -- I think it's 3, 2 wells, 2 wells to be abandoned. We've got 10% of that. BHP is the operator, and they're going through the planning phase for that at the moment. I'd expect it to be within the next 3 years. And the cost for us, we haven't got final cost. We've done our own work based off the experience that we've develop from BMG. But it's not big numbers by any stretch. And it is something that we're looking to have abandoned within the next -- as I say, within the next 3 years. And it's really focused mainly around the 2 wells. The shore crossing in the pipeline is up for discussion. The reason for adding -- just sorry, just the reason for adding Minerva in at some stage, we'll be saying we're going through the process of abandoning Minerva, and we just make sure the market is aware that that's something that we're planning for.

And our next question is from James Bullen of CGS. The next question is from Jon Bishop of Euroz Hartleys.

Just a couple from me. There was some discussion a little while ago about taking the Manta gas through the Sole infrastructure, piggybacking through that infrastructure, but it was sort of predicated on getting a combination certificate. Just wondering where all that sits with the regulators and the government at the moment? And then just a second question on Sole. So just around root cause analysis and where you feel that's at based on your discussion on Friday morning.

Yes, thanks, Jon. Firstly, on Manta. The Manta development is not dependent on the combination certificate. The combination certificate is an additional benefit arising from the Manta development. The way we think about Manta is, as Manta's stand-alone economic, what's the best development scenario, having -- once we've approved that, we then look at the combination between Manta and Sole. So it's not -- it's upside effectively for Sole. It occurs after we have approved the Manta development. So what's the status of that? There are conversations going on with the different departments and what we're finding is it more than 1 in Canberra pretty much as we speak. And as we advance the Manta development, and I'm expecting those conversations to progress in parallel. And we're not being told that what we -- the approach that we're taking and the way that we're interpreting the legislation and the recommendations that came from the review of years ago is incorrect. We're just having to work through multi-department views within Canberra, and I here refer to tax and finance and resources and is bringing those all together. And obviously, Prime Minister and Cabinet has a role in that as well. It wouldn't go past people that we said that the best gas for South or Southern Australia is gas from Southern Australia and here's a very good example of exactly that. So I think we'll get there. It's a question of when, and we're bringing those sort of the Manta development and the combination certificate have been brought along in parallel. In terms of the root cause analysis. Mike reflected on Friday that -- mentioned on Friday that the surfactant chemists and a lot of work has reviewed a lot of analysis, a lot of tests that have been done, and that's got us to a certain point, and it's pointing in some things are more likely and other things are less likely. And he's -- in order to firm up on those views, he's proposing, and the parties, ourselves and APA are discussing the next round of tests and analysis. I'm not in a position to say any more about that here today than that. But Mike is on the line, and I'd invite him to add anything else he wanted to that. Mike?

Yes. Thanks, David. Thanks for the question, Jon. there is not a lot more to add to your comments there, David. I think you are correct. There is some further testing that the surfactant chemist has asked for. looking for what is the root cause of the firming and/or the failing. And that work is expected to take the best in the next 3 months or so to get that testing done. And looking for what the causes might be within the solution. So different types of testing to what we've commissioned all to this point. So it's probably in that sort of time frame to get more information from that testing, Jon.