Amplitude Energy Limited (AEL) Earnings Call Transcript & Summary

Thank you for standing by, and welcome to the Cooper Energy Limited FY '22 Half Year Results Webcast. [Operator Instructions] I would now like to hand the conference over to Mr. Eddy Glavas, General Manager, Commercial and Development. Please go ahead.

Good morning all, and thank you for joining the Cooper Energy FY '22 half year results webcast. My name is Eddy Glavas, and I'm the General Manager of Commercial and Development for Cooper Energy and currently managing Investor Relations. I'm joined by Managing Director, David Maxwell, and Acting Chief Financial Officer, David Di Blasio who will be taking you through the half year results presentation. Also with us in the room are members of the leadership team. After the presentation, we will be hosting a Q&A session, and we welcome your questions. The presentation and announcement were released to the ASX this morning and are available on the Cooper Energy website. Today's webcast recording will also be made available on our website later today. I will now hand over to David Maxwell to kick off the presentation.

Thanks very much, Eddy, and I'd add my welcome to everybody this morning and those that will listen later on the webcast. In particular, welcome David Di Blasio who Eddy said is the current Acting CFO. David is also our Finance Manager and David will discuss the financial results after I've said a few things. In early May, we will also welcome Daniel Young as our new CFO. We announced this to the ASX on the 24th of December. Slide 2, the highlights of the half year results. Simply put, record results on multiple fronts. A step change in production has been delivered and we expect this trend to continue. The fundamentals of the business are strong and this enables the continuing growth. And this is occurring at a time when gas prices have increased and our gas available for spot sales is increasing. Slide 3. The evidence of the record results when compared with the first half of FY '21 is clear, a 31% increase in production, a 96% increase in sales revenue. Strong balance sheet with clear ongoing support from our banks. The Athena Gas Plant commissioning was a key milestone in December and this enables the further Otway Basin growth and improves our returns. And then the improved performance at the Orbost Gas Processing Plant with stable rates at 50 terajoules a day in January and rates above this level have been achieved. The adjustment to the gas sales agreement, which applied from the 1st of January has mitigated some risks and increased the opportunity for spot gas sales. Now, turning to the Orbost Gas Processing Plant, which is operated by APA. At Orbost, APA and Cooper Energy are working together to further increase the processing rate for Sole Gas, further improve stability and determine the long-term arrangements, which are best for both parties. You can see the clear performance improvement from October to January. This comes from general operational improvements and plant management. The remaining Phase 2b project work aim to achieve further improvements includes a sulfur filtration component. APA has recently advised that there has been a delay with some of the software filtration equipment due to COVID and the timing of this part of the Phase 2b project is being reviewed. This timing review for the sulfur filtration equipment will take account of the now expected higher rates. And here, I'm talking about 50 terajoules a day plus any improvements. It is important to note that parties are committed to the Phase 2b works. Slide 5. Slide 5 illustrates the improvements in rates and stability that I mentioned and as shown here in more detail. I draw your attention in particular to the improvements since November. Note with the increase in rates and the gas sales agreement adjustments mentioned, the availability of gas to be sold at spot gas prices. Slide 6 summarizes the total gas portfolio and illustrates the growth and balance of long-term take-or-pay contracts and as yet uncontracted 2P reserves. We continue to work closely with our utility and industrial gas customers as we further grow our gas production and sales revenue. Health, safety and environment, Slide 7. When one considers the backdrop of COVID and the Athena Gas Plant upgrade project, which was a first for Cooper Energy, and this included the plant upgrade works and the gas pipeline cutover and the commissioning, the health, safety and environment performance in the first half of this financial year is particularly pleasing and I add industry-leading; 0 recordable incidents, 0 lost time incidents and a total recordable injury frequency rate, which is approximately half that of the offshore industry benchmark. These are results which speak for themselves. My thanks and appreciation to all staff and contractors involved. On to Slide 8. Our net zero carbon emissions position and that's net zero since 2020 is industry-leading and very well received by our existing banks and others wanting to support Cooper Energy with finance. In the last year or so, we've seen banks and financial institutions make commitments to the Paris goals and climate management with the aim of net zero emissions by 2050. In support of this, banks are taking actions, which guide their investment in and support for the oil and gas industry as well as other industries. The approach we have taken is very aligned with the bank's objectives. And as a general statement, our approach and commitments tick the boxes required for the bank internal approvals required. The strength and value of our net zero position cannot be underestimated. One reference point, which also highlights this is, 2 years ago, when we first committed to net zero as of 2020, ACCUs, Australian Carbon Credit Units, were trading around AUD 20 per ACCU, and now they're trading around AUD 50 per ACCU. We continue to grow our partnership with Greening Australia and Biodiverse Carbon, and other partnerships are under development. We are very much taking a portfolio approach to maintain net zero as our business grows, whilst at the same time, working to reduce our emissions where it's feasible technically and economically to do so. This is as well as the offsets. Slide 9. Closely linked to our net zero position where we work with the local communities are our more general community activities. We recognize and value the communities in which we operate and work. And consistent with this, we support them in a business and community sense where we can truly make a difference and it's good for our business. We think of this as part of our enduring legacy and good business. I'll now hand over to David to take you through the financial results.

Thank you, David, and Good morning, everyone. Turning to Slide 11, which shows the headline financial metrics for the first half. This slide presents the clearest evidence to date of the importance of the transition agreement with APA, which enabled Cooper Energy to commence Sole Gas sales agreements in December 2020 and January 2021. David presented the increases in production and sales volumes earlier, which have generated an almost doubling of sales revenue to $95.4 million, which is a half year record. Gas revenue increased by over 100%, mainly as a result of commencement of the Sole Gas sales agreements as compared to the first half of FY '21, where gas sales from Sole were realized at then suppressed spot gas prices. The 17% increase in realized gas price is reflective of this offset by the roll-off of a higher-priced Casino Henry gas sales agreement in FY '21. Oil and condensate revenue increased by 34%, due to strong oil prices in the first half of FY '22, more than offsetting the impact of lower volumes. Underlying EBITDAX for the half increased by 163% to $25.5 million when compared to the first half of FY '21. I note that the full year underlying EBITDAX for FY '21 was $30 million. Pre-net loss after tax and underlying net loss after tax have shown similar significant improvements. Operating cash flows for the half of $28 million represents a 318% increase over the first half of FY '21 and represents roughly a $20 million increase when compared to the FY '21 full year figure of $8.1 million. I also refer you to Slide 27, which summarizes movements in headline financial metrics against both halves of FY '21 and highlights the continued growth over the 18-month period. While these increases are pleasing, further improvements are expected as a result of significantly reduced reliance on third-party gas purchases, noting the $19.6 million incurred in the first half of FY '22 for 2.7 petajoules of purchased gas. This reduced reliances due to 2 factors. First, the reshaped gas sales agreement with AGL and second, the improving performance of the Orbost Gas Processing Plant. In fact, overall, the company is fairly well balanced as far as gas supply is concerned for the second half of FY '22, if not in a slightly long position, which can be expected to increase with improved Orbost Plant performance. Capital expenditure is 32% lower than the first half of FY '21, noting that for FY '22, expenditure is more heavily weighted to the second half of the year. Hence, our guidance for capital expenditure remains unchanged as does our guidance for all other metrics, which can be found on Slide 26. On the basis of continued performance of the Orbost Gas Plant at rates achieved in January, full year performance is trending towards the higher end of guidance for production volumes, sales volumes and underlying EBITDAX. Moving to Slide 12. And at the end of FY '21, the company announced debt facility adjustments, which included realignment of principal repayments through to expiry of the transition agreement on 1 May 2022. During the half, $14 million in scheduled facility repayments were made along with $4.7 million in interest payments. At the end of September 2021, we welcome Deutsche Bank as a new member of the lending syndicate. Cooper Energy continues to enjoy ongoing support from our lenders. On Slide 13, the table on the left outlines the underlying adjustments to the statutory loss for the first half. The first item reflects the impact of higher discount rates on restoration provisions due to increases in government bond rates and the second item reflects Cooper Energy's share of Phase 2a and Phase 2b costs incurred in the first half and which are expensed. The table on the right shows adjustments to underlying loss in order to derive underlying EBITDAX. Amortization represents the largest change half-on-half and is in line with increased production volumes. Slide 14 illustrates the movements in the underlying result from the first half of the prior financial year. The step change in gas revenue due to commencement of the Sole Gas sales agreements drove a $45 million increase. Oil revenue increased as a result of higher prices despite lower volumes as mentioned earlier. As indicated on this slide, the increase in cost of sales when compared to the first half of FY '21 was production volume driven for both production expenses and amortization. As discussed earlier, the increase in third-party gas purchases is directly linked to commencement of the Sole Gas sales agreements and the backup supply arrangements the company put in place to ensure that 100% of customer nominations over calendar 2021 were met. Achieving this was not without challenges, but credit goes to our commercial team for very rapidly developing capability and a portfolio of arrangements to balance customer demand against the various supply sources every single day. Now, turning to Slide 15. The modest increase in cash over the first half of the year was driven by the much improved operating cash flows of $28 million offset by investing cash flows of circa $13 million and scheduled facility repayments of $14 million. Cash flows generated by assets before taxes and finance costs as illustrated by the operations waterfall item of $44 million compares to the full year figure from FY '21 of $49 million. The company has had a very strong start to the second half of FY '22 with 113 terajoules of surplus Sole Gas, which was sold in the spot market in January as per the operations update recently released to the market. While the improvements presented today are pleasing, there is more growth to come. I'll now hand back to David.

Thank you, David. If we move now to Slide 17, and a few comments on the gas market. Last week, on the 16th of February, the ACCC released their 12th interim report into gas supply arrangements. These reports are based on information provided by gas producers and customers. This is effectively a form of legal discovery process and hence, can be deemed for facts or reality. On the Southeast Australia gas market and supply, there is a clear trend for tight and getting tighter gas supply and declining southern gas production. This shortfall will be met by gas from Queensland, mainly coal seam gas and we expect imported LNG. The shortfall is expected to grow to circa 100 petajoules a year. That's greater than 270 terajoules a day and that growth is expected to occur over the next 5 years, that shortage growth. Slide 18. The high volumes of Queensland gas and the likely imported LNG will further increase the influence of LNG prices on the domestic gas price in Eastern Australia and in particular, Southeastern Australia. EnergyQuest, who review and publish a quarterly report on oil and gas are forecasting Otway and Gippsland gas prices in the range of $9.50 to $11 per gigajoule over the next 8 years. This aligns with our experience and our expectations. Slide 19. The ACCC report also includes information and data supporting the growing closer link and interaction between the domestic gas market and the LNG market. This slide illustrates the Queensland LNG producers' role in supplying the domestic market and that the LNG producers are now purchasing more third-party gas for export than gas they are putting into the domestic market themselves. Next slide. Against this background of tight gas supply, increasing influence of LNG on domestic markets and increasing domestic prices, Cooper Energy is well positioned. Slide 21. Our Twin hub strategy for further production growth and new projects is concentrated around 2 ideally located hubs; the Otway Hub and the Gippsland Hub. We continue to grow these hubs and their value. In this regard, the commissioning of the Athena Gas Plant was a key milestone achieved on the 10th of December with first gas sales ex the upgraded Athena Plant on the 17th of December. Orbost continues to improve, as mentioned previously, and we were able to optimize across these 2 hubs to maximize the supply flexibility to meet contractual undertakings, production growth and grow the gas margins. The Otway Gas Hub. At the Otway Hub, we now are processing our gas together with Mitsui, our joint venture partner at the Athena Gas Plant, which is now upgraded, as I mentioned, and operated by Cooper Energy. This has a range of add value benefits as noted on this slide. On the 9th of February, we released the results of months of exploration analysis, which included the integration and reprocessing of 3D seismic exploration data. The results of this work validated the low-risk prospectivity assessment of our offshore Otway permits and high-graded some existing and new prospects. The aggregated mean un-risked prospective resource potential of just 5 amplitude-supported prospects is 585 billion cubic feet, Bcf, which is approximately 585 petajoules. And the Cooper Energy share of that is 325 Bcf or just over 325 petajoules. Expect to hear more in our plants for the Otway soon, including the OP3D project. At the Gippsland Hub, we have the existing and growing Sole production being processed at Orbost. To come after this, we have the Manta contingent resource and nearby exploration opportunities. I expect we will update the market on our plans for this hub and further growing production very soon. So, to wrap up and in summary, a step change in gas production and revenue with further growth underway. This is evidenced by current equity gas production approximately 60 terajoules a day Cooper Energy equity share, which is approaching 2x that of what it was in the previous corresponding period, stable and growing cash flow underpinned by our gas sales agreements with the quality customers, a robust base business built around 2 hubs with a secure and controllable path to market, gas supply is tight, getting tighter and prices have increased and we have projects around the 2 hubs to deliver sustained growth at very competitive costs. At that point, we're happy to open the lines for any questions.

[Operator Instructions] The first question comes from Nik Burns from Jarden Australia.

David, just a question in relation to the delay in Phase 2b works. Can you talk a little bit more about what's the cause of the delay there and what the new timing might be? I think we're just a few days away from when the proposed start date of Phase 2b works was meant to commence. Just were you surprised to learn about this supply issue and delay, so close to the expected start date?

Thanks, Nik. I'll also make a couple of comments at the start and then pass across to Mike Jacobsen who can provide a little bit more on it. We were advised just on a week ago. So yes, I think it's fair to say there was a bit of a surprise. And as I mentioned in my words there, it is just one part of the Phase 2b project that has been deferred. And it is due to COVID and there's some parts which are being manufactured overseas. And it's the delay about receiving those at site, which has caused the delay. A lot of the kit is already there. I'm going to hand over to Mike to put a little bit more around the answer. And then if there's further from that, you can ask Mike a follow-on question.

Yes. Thanks, David. Morning, Nik. Thanks for the question. Yes, so there was some piece of equipment coming out of Singapore and the shipment was delayed. As you know, the supply chains around the world have been seriously interrupted with COVID, and there was a shipment that was basically bumped, which has put the schedule back. So, we're working alongside with APA, really assessing when that equipment is going to arrive, the impact on the overall schedule. But certainly, with the improved plant performance, it does give us an opportunity to run the plant at those higher rates. We had a short period of time above 50 terajoules a day. So, we see this as an opportunity to try to run the plant at higher rates while we're waiting for that equipment. So, it's probably too soon to say the exact impact in terms of weeks, but we're working with APA to understand that better.

So, you're still confident you might get this underway before the end of FY '22?

Certainly, yes. We are confident we'll have it complete before the end of FY '22.

I think there's another component to it, which is -- and Mike touched on it there, which is you might remember when we committed the Phase 2b works, I think at the time, the rate for the plant was in the low-40s, which is quite different to the 50s. And so there is a question for us about what's the optimum time, as Mike alluded to, to now interrupt production as well. So, we'll certainly be in a position to complete the project, absolutely. If there's a question about what is the right time and that's going to be driven by what maximizes value and cash flow.

I guess just looking at your unchanged guidance and still pointing towards the upper end of production and EBITDAX, just thinking that, I guess it was an expectation that you could get an uplift in output post Phase 2b. And so if this is delayed, I guess, all things being equal, that could impact production if it was going to happen this financial year because we won't see much of an uplift at the back end. But I guess, just trying to wondering if we should be inferring from your unchanged guidance here, whether this could be a signal that you slip into FY '23 for this work, so you maintain output at still up a higher rate than you were originally anticipating, but you don't have the downtime associated with the Phase 2b works?

As David Di Blasio commented, our base case is that things continue as they are at present. We're trending towards the upper end of guidance on sales volume production and EBITDAX. So, when that guidance was put together and last advise, we didn't expect ourselves to be in January producing at 50 terajoules a day. We had lower numbers at that stage. You might remember that November, the plant was running stably at around 45. So, we've been very prudent with our guidance indications. And our expectation would be if Phase 2b is deferred towards the end of this financial year, that we would still be at the top end of guidance.

And just one more. Just thinking through the upcoming expiry of the Orbost transition agreement with APA. I guess, if the Phase 2b works was happening in the time frame you previously said you'd potentially have some update on the output from that or the -- how that works and what the potential implications for that would be. Now you won't have that information at your disposal leading into that expiry. Where are you at with that in your discussions with APA? How are you thinking through this? And from an investor perspective, how should they be thinking about Cooper Energy in relation to this upcoming expiry and what might happen next?

On how should people be thinking about Cooper Energy and what might happen next, we're driven very much by the scenario that's going to maximize value for shareholders, which comes in the case of Orbost from the scenario that's going to get the rates up as soon -- as high as possible, as soon as possible and stable. As it relates to where we're at with the ongoing conversations, I'm not in a position to say any more than my comments during the presentation and that we're working really closely together with APA on increasing the rates and getting that better stability. And the parties having conversations about the long-term arrangements, which are best for both parties. And when I say best for both parties and what's the objective in that for Cooper Energy it's what I mentioned about the rates being as high as possible for as long as possible and stable. Sorry, I can't say any more at this point than that.

[Operator Instructions] We have a follow-up question from Nik Burns from Jarden Australia.

I take the opportunity Dave, while there is no one else on the call just to -- on Q&A call, just to ask a couple more, if that's okay?

Sure.

Just on your East Coast gas market, obviously, you pointed out the upcoming supply shortfall 100 petajoules here. Just interested in your thoughts around you had a chart in there showing forecast pricing, I think, for Victoria around AUD9.50 gigajoule over the next few years and potentially going higher from that. I think that's an EnergyQuest forecast. I was wondering whether that gels with your own view and whether in relation to recent discussions with customers around pricing, are you seeing customers looking to move back to contracts? I think some of them have moved away from contracts and relying on the spot. But in the last 6 or so months, that hasn't worked out so well for them. And are you seeing that coming through in any conversations you're having with customers at the moment?

We are engaged with customers at the moment in what is a pretty volatile situation. And I guess that volatility has only increased in the last week with the news about some of the large coal generators. What we have seen since probably October-November, there's an increased willingness on the part of particularly the utility customers to enter into term contracts. And the term contracts that we're discussing primarily around OP3D and additional volumes out of the Otway and for the prices that people are discussing are in the range that you see in that EnergyQuest forecast for term contracts. Here, I'm talking about 5, 6, 7 years with indexation as well. What we've seen in the last 3, 4 months is increasing interest in term contracts at the expense of buying on the shorter-term market or even the spot market. I guess that's a reflection of what's happening with international prices and the impact that international prices are having on domestic prices. So, the short answer to your question is yes, we are seeing prices in that range and there for term contracts. I know I should say take-or-pay contracts at high -- relatively high percentage take-or-pay components.

And in terms of how that fits into your thinking around OP3D and thank you for that recent presentation you put out around your updated views on prospective resources in the Otway Basin. But as you look forward and you're considering your plans in the Otway, are you more optimistic around your plans there? And in terms of how should we think about the number of potential exploration wells that you might want to drill? I think you outlined a number that have quite a high chance of success and reasonable volumes in the success case and given the [ outage ] at the Athena Plant, all sort of points to some quite good potential there for the company. But just wondering what your updated thoughts are there too?

And that's the work that's actually underway right now. I mean there's the base project, which is OP3D, which is primarily built around Annie and then separately, there's the undeveloped Henry resource. And we are now giving -- well, I think there's 2 lines of thinking and they're in parallel. One is OP3D and what should -- what exploration well should we add to an OP3D program. And that's probably a little bit longer in duration than the alternative. And the alternative is -- well, let's think about an exploration well or 2 if there's a rig available in the short term. And what I mean by the short term is in the next 12 months. So, we're doing that work at the moment. We've got 2 possible paths to go down. If a rig of opportunity comes up, then in all likelihood, we and our joint venture partner, Mitsui, will actively talk about securing that rig of opportunity to drill 1 or 2 exploration wells in the short term and then OP3D come in as a development project a couple of years later. If there is no rig of opportunity that works, then we would take an extra couple of a couple of exploration wells, whether it's 1, 2 or 3 years to be worked out onto the OP3D development program. Maybe I'll take the opportunity also just to ask Andrew Thomas to make a couple of comments around the work that we put out a few weeks back on the offshore prospectivity because I mean, for us, this is exciting stuff, particularly where the market is at the moment. So maybe Andrew, make a few comments about that.

Yes. Thank you, David. I think you must wall have noted over a week ago that we updated our Otway prospective resources and that was on the back of reprocessing the seismic data, emerging seismic surveys in the offshore and then really looking at our prospects. I think the key takeaway there is we are more encouraged than we were previously about the prospectivity of the areas. There's some very low-risk prospects, very similar to Annie. And then I think everybody would have noted that there is a [ the port of ] Elanora, Isabella trend, if you like, uptick with the Casino gas fields, which has very strong seismic attitudes and very, very encouraging for the presence of gas. So, I think in ourselves and our joint venture partner, Mitsui, are very keen to secure a rig if possible in the near term to test the potential in that area, which could be up around the 300 Bcf mark.

Your next question comes from Stuart Howe from Bell Potter Securities.

Just firstly, or first question around debt adjustments and realignment. You've sort of mentioned that principal repayments were realigned for lower processing rates and also that you expect further adjustments by the end of FY '22. Can you perhaps talk a little bit more about that, I guess, in the context of how performance at Sole can play into that -- those discussions?

The adjustment to the facility was re-sculpting the facility to more reflect the rates that we're doing at the moment versus what was originally planned. You might remember the original contract that we have with APA, and we still have with APA at 68 terajoules a day, but we're not producing at that nameplate level. We're producing at somewhere between 50 and 55 when we're not down for a clean. So, the profile was re-sculpted and we are in conversations with our bank consortia at the moment about refinancing the existing facility. It was always available to us. It was always our plan. And those conversations are going very well. My comments on net zero and the way that banks view these things was directed partly at that. And I would expect in the next month or 2, we'll be announcing a refinance facility, which will reflect where we are in terms of the Sole project, where we are now in terms of the offshore Otway, where we also operate a plant and the facility have the ability to support us for the next round of development. And here, I'm thinking in particular of OP3D. So, those conversations are underway at the moment and I would expect to be announcing something -- would expect to be announcing something in the next couple of months.

So, you can sort of come to an agreement with that regardless of how all the timing plays out for the APA upgrade at the plant?

Yes. And the way that it's being discussed is a facility which can flex up as you meet certain performance indicators, which is, I think, a reflection of the flexibility being shown by ourselves and the banks. So, as the capacity in the Otway and the capacity in Sole increases, then the ability of the facility to increase also and then obviously support subsequent development, yes. So, we're not trying to be -- we're looking to -- it's not a project facility any longer. It is now a facility to support the sustained growth of Cooper Energy.

And I guess following from that second question, just around -- you mentioned Gippsland Basin potential, I guess, views of how that will progress in exploration shortly. Could you perhaps add a little bit more to that, David?

I'd like to think that -- I mean, the first thing for us is getting the rates at Sole up and getting the rates through Orbost up. I'd like to think that as a part of -- and our planning certainly is built around those. But as a part of the next development program in the Otway and I talked about exploration wells being added to that program, we also add at least 1 and possibly 2 exploration wells in the Gippsland. One would obviously be Manta and Manta Deep. And there's some other things which Andrew and his team are working on at the moment, which are analogies to those prospects. And that's going to be a function of our ability to fund and where we are at with Sole and Orbost.

And just a quick third one as well on the -- I know you probably can't say much, but on that transition agreement with APA. It does end on the 1st of May. Assuming nothing changes between now and then in terms of an agreement or discussion with APA, effectively, that means you're just taking the gas as it's processed and any -- I presume any shortfalls in meeting your contracts you just get met with Orbost -- sorry, Otway gas and purchases and there's no further compensation from APA. Is that how it works?

At the moment, that is at the moment as the agreements are structured, that's correct. That agreement finishes at the end of April, so from the 1st of May. But I come back to the words that I used in my presentation and I mentioned earlier, both APA and ourselves are working closely together to increase the rates, get better stability and determine the long-term arrangements, which are best for both parties. And I think I spelt quite -- out quite clearly what our objective is in that about stability and long-term rates. So, I can't --.

With that long -- and with that long gas position that you expect to have, does that mean that purchases will be relatively low you'd expect?

Yes. Yes. And as David mentioned, I mean, at the moment, it's very few days that we are purchasing gas. And as reflected on the slide in the presentation, we're actually putting gas into the spot market on quite a few days since the end of January. Not today, we're not because the plant is down, the absorbers are down for a clean. But when it comes back, the intention as it comes back to 50 and possibly a little bit higher, we'll be putting gas into the spot market. So, our need to draw on the backup arrangements that we have in place is expected to decline quite significantly from December. Well, it has declined quite significantly from December of '21.

Your next question comes from James Bullen from Canaccord.

Great to see that result out this morning and seeing guidance being retained and indeed pushing us towards the upper end. Just you mentioned the refinancing. I'm just wondering if you're anticipating any changes for that lending certificate as a result of the refinancing?

I think it would be inappropriate to make any comment around that, James. We're certainly engaged with our existing banks. And as to whether there are other banks added, there's certainly been interest from others, quite significant interest. But as to whether that results and other banks being added, we will have to wait to a short while. The fact that others are approaching us and wanting to be involved in the financing is really encouraging from our side. And as I mentioned when I talked through the net zero, I think the position that we've taken on that. I mean banks still make their business out of lending money. And provided you met the criteria, they're very, very interested. And I have to say the net zero position that we took just on 2 years ago, a little bit less than 2 years ago now, has certainly given us some competitive advantage in terms of the number of banks that are interested in working with us. But as to what that leads to in terms of the structure of a final consortium, we'll have to wait and see. The one thing I would say, though, is that we're very minded to support those that have supported us. And probably I shouldn't say any more than that.

And obviously, gas prices, they get political very quickly. I mean they haven't moved anywhere near the LNG netback pricing. Do you get a sense that they're becoming a bit of a political football again? And is there any risk do you think around the government using its security mechanism on the East Coast?

I think I wouldn't underestimate the sense of responsibility that gas producers in Eastern Australia have to the domestic market and wanting to make sure that supply continues into the market at reasonable prices. You're right, prices haven't approached LNG netback. But LNG netback is it will be close to double what the prices are at the moment. I haven't had a look at the spot prices today, but I should imagine they're around somewhere between AUD9 and AUD10.50. And it would be double that if it was LNG netback or more than double that if it was LNG netback. So domestic, the producers and here include the Queensland LNG producers, I can't speak for them, but I do know that the sense of responsibility to the domestic market is strong. You're right, gas has been -- attracted a lot of attention in terms from a political standpoint. What we have seen though is the volume wound down on the noise about gas price. And I suspect that's because in other markets, gas prices are also high. And if you just look at the U.S. and look to Europe, you'll see that gas prices there are high, which is a reflection of the value of gas in a world of increasing renewables. And I think going back to gas prices where they were 2 years ago most people, if not all, I think that that's a foregone wish account, it won't happen. And in all likelihood, what we're seeing at the moment from time to time, they might dip a little bit. But in that band, that Energy Quest, I think, is reasonable. And then spot prices from time to time will go above that. I mean we sold gas last year, only a small volume because that's what we had available but at $15. So, that was a short-term spot opportunity, which we took. But I think there'll be straight, there'll be points like that, but I don't think we'll be going back to where we were. And to the political aspects, I think that becomes noise when people see prices, which people are receiving in other places, much less than what they're getting today, which has become less the case in the last 18 months off the back of the role of gas with renewables and the role of gas globally.

[Operator Instructions] Ladies and gentlemen, as there are no further questions at this time, I will now hand the conference back to Mr. David Maxwell for closing remarks.

Thanks very much. And look, thank you, everybody, for joining. And I'd just really summarize with a couple of points. One, it was a record 6 months. As David pointed out, the 6 months that we are now in the second half of FY '22, we expect to be another record and it is off the back of increasing production at Sole, albeit Phase 2b has slipped a short period and strong support from customers, very strong support from banks, what sets us up well for the next round of growth built around the 2 hubs, over which we're having increasing influence. So, on that note, thank you very much.

Thank you very much. Ladies and gentlemen, that does conclude our conference for today. Thank you for participating. You may now disconnect your lines.