Amplitude Energy Limited (AEL) Earnings Call Transcript & Summary

Good day, and welcome to the Cooper Energy FY '24 Half-Year Results Presentation. [Operator Instructions] And finally, I would like to advise all participants that this call is being recorded. Thank you. I'd now like to welcome Jane Norman, Managing Director and Chief Executive Officer, to begin the conference. Jane, over to you.

Great. Thank you very much, and good morning. Appreciate you joining the Cooper Energy Half-Year Results Webcast and Presentation. My name is Jane Norman, Managing Director and CEO of Cooper Energy, and I'm joined by Chief Financial Officer, Dan Young; and Chief Operating Officer, Chad Wilson. After the presentation, we'll be hosting the 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 is being recorded, and the playback will be available on our website later today. Please note the disclaimer information on Slide 2 of the presentation. Now turning to Slide 4. I'll take us through the highlights of the first half of FY '24. In the first half of FY '24, we delivered record results from both an operating and financial perspective. Our production was up 0.5% to an average of 60.8 terajoules equivalent per day. Excluding the planned 5-day maintenance shutdown in August in December 2023, average daily production was 61.7 terajoules equivalent per day, up 1% compared to the same period last year. Stepping back from the first half. Many of you will have seen the strong performance at Orbost in recent months. And I'm pleased to report that this month we set a 12-day production record at Orbost, with average -- the plant averaging 62.8 TJs a day and a 60-day record was also set with a client averaging 55.2 TJs a day. This is the outcome of the learnings we have made since becoming operator in May last year and demonstrates the progress we continue to make. Our revenue of $105.9 million was up 5% compared to the same period last year. Dan will discuss the financial results in more detail later in the presentation. Turning now to Slide 5 to look at the strong Southeast Australian gas market conditions. There is a clear shortfall of gas coming up within the next few years and new suppliers urgently needed to ensure gas is available for homes and industries in Southern Australian states. Australian manufacturing depends on gas for high temperature heat and feedstock for which there is no alternative. Higher gas pricing is already seeing businesses move offshore. And recently, iconic Australian brand, [ Sorban ] reportedly halved its workforce in Melbourne, shifting manufacturing to Indonesia and cutting 70 local jobs. With Gippsland Basin joint venture production declining, the new domestic gas supply is likely to be 3 to 4 years away due to approval time lines. Gas diverted from Queensland and LNG imports into Southern states will likely set the near-term pricing in the market. We have heard anecdotally that a number of the Queensland-based gas producers have received exemption from the $12 a gigajoule cap, further driving market prices towards mid-teens dollars per gigajoule. LNG imports into Southeastern states are likely to be a marginal source of supply at between $16 and $24 per gigajoule pricing, factoring in global LNG prices and regasification fees. On to Slide 6. Other than directly supplying energy to our homes and businesses, we also see an important role for gas in supporting the integration of variable renewables into the national electricity market or the NEM. Most of you will have heard me speak about the South Australian market being the window to the future. With more than 70% renewable energy in SA, gas-fired power generation contributed almost 25% of electricity supply over the last year, far higher than the 5% gap contributor to the whole NEM. It is reason to assume that demand for gas generation in the NEM will increase alongside the forecast increase in variable renewables. Another example of gas providing backup when it's needed occurred just 2 weeks ago when southern storms through Victoria resulted in the shutdown of the Loy Yang, Victoria's largest coal-fired gas generator. You can see that from this chart that the faster gas-fired generation rapidly went from effectively contributing no electricity supply to over 25% of electricity generation in the state. Slide 7 speaks to our health, safety and environment performance today. In the first half of FY '24, our work hours have doubled compared to the same period last year, as a result of taking over operatorship at OGPP and the ramp-up in the BMG decommissioning program. We had our first LTI since 2019, a finger injuries that require suturing. This is the only recordable injury we've had to date this year. Although the injury was relatively minor, the incident was fully investigated and the learnings have been implemented. We've had no Tier 1 or Tier 2 process safety events, no reportable environmental incidents. To maintain our carbon-neutral organization certification with respect to Scope 1, Scope 2 and relevant Scope 3 emissions, we continue to offset emissions via projects generated and purchased carbon credit. More information regarding Cooper Energy's carbon neutral certification is obtained in our 2023 sustainability report. Through the first half of FY '24, our focus has turned to value-accretive physical emission reduction opportunities. We have completed facility-specific workshops for both Athena and Orbost Gas Plants with a focus on energy efficiency and opportunities where we can reduce fuel gas consumption and flaring to increase sales to the market. Over 100 emission reduction opportunities have been identified, and the company has been working to prioritize and implement the highest value opportunities. On to Slide 8 with some operational highlights. I am encouraged to report that the average company production continues to improve quarter-on-quarter, in large part due to the positive outcomes from the August improvement project. As we announced in early January, we successfully reinstated the polisher unit with new media, which has enabled us to increase production rates. First half performance was negatively impacted by poor production at Orbost in the first quarter due to the number of trials we completed that did not result in positive production outcomes. However, we have learned from the outcomes of these trials and reviewed the way we complete the trials leading to improvements we achieved in Q2 and the current quarter. Athena Gas Plant performance has also improved. Reliability at Athena has improved compared to the same period last year and a project to lower the inlet pressure of the plant has increased average production by approximately 1 terajoule a day compared to the previous operating mode. Chad will speak to operational performance shortly. On to Slide 9 regarding our BMG decommissioning project. As we announced in December, the Helix Q7000 is on location and currently undertaking the 7-well decommissioning program at the Basker Manta Gummy field. The first part of the program relates to the bottom hole plugs. And so far, we have completed the lower reservoir plugs on Basker-3, Basker-7, Basker-4 and are progressing Basker-2. The lower plugs component of the wells decommissioning program represents approximately 2/3 of the entire program in terms of time and importantly, the reservoir is plugged and pressure isolated once the lower plugs are in place. Once the bottom hole component of each well is completed, the vessel will loop back to complete the top hole sections. Lessons from previous wells have been incorporated into the program to date, and we are seeing improved coordination across the service partners and evidenced that the efficiencies and learnings are being delivered. Despite some delays due to weather, we remain on track to complete the wells decommissioning program in early May. I'll now hand over to Chief Operating Officer, Chad Wilson to run through the update on operations and development.

Thank you, Jane. Starting on Slide 11. There is a clear trend of improved performance at Orbost. Since taking operatorship in May 2023, the team has developed a list of potential causes to the forming and fouling issues we see in the plant and identified and prioritized initiatives, which we've been methodically working through. In late December 2023, we installed new media in the polisher unit, which has enabled the polisher to effectively stay online since its reinstatement. This has enabled us to extend the time between absorber cleans, improving the stability and throughput of the plant. We have now also installed the new spray distributor nozzle and snowflake packing in one of the absorbers and we have seen reductions in the fouling in that absorber. As of today, this absorber has been online for almost 4 weeks since its last clean and continues to perform well. The success of that trial has led us to ordering the equipment for the second absorber and will enable us to progress with the next phase of in-situ washing, which is scheduled in the near term. In-situ washing has the potential to greatly reduce the time and cost of removing the sulfur fouling. What these plant improvements mean is that we have a greater volume of gas that can be sold into the spot market. In the first half of FY '24, we sold just over a petajoule of gas into the spot market, generating revenue of nearly $11.5 million. And this trend has continued in January and February with nearly $7.5 million in revenue from spot sales. At the same time, this means we have purchased significantly less gas. In fact, only 1.4 terajoules has been purchased this calendar year. We are continuing to work on the backstop option of the third absorber. Recent results led us to be -- lead us to be increasingly confident that we will not proceed to add a third absorber. However, we need to complete that evaluation work while we continue to see the recent sustained higher performance prevail. As previously outlined, we expect to be in a position to determine if the third absorber is required no later than the end of March. And now on to Slide 12. Our Otway Basin assets, the Casino Henry and Netherby fields and the Athena Gas Plant, which as of today is commencing a planned maintenance shutdown of around 10 days. Since resolving the long-standing compressor reliability issue in May 2023 through our dedicated engineering team, plant uptime has improved over 10% in first half FY '24 when compared to FY '23. Focusing on increasing production, the engineering operations team have implemented a project that reduces the inlet pressure of Athena, increasing production rates by approximately 1 terajoule per day compared to the previous operating mode. We continue to review the cycling programs for Casino Henry and Netherby wells to maximize performance. Now on to Slide 13 and a brief review of our non-operated Cooper Basin asset. PEL 92 production in first half FY '24 averaged just under 1,500 barrels per day, up 25% compared to first half FY '23. This was driven by the connection of 3 new wells, Rincon-4, Callawonga-23 and Bangalee South-1, which came online in June, July and December 2023, respectively. Now on to our Otway growth on Slide 14. Our technical work for the Otway growth project is complete, and we have the Transocean Equinox rig contracted for at least 1 well slot, with multiple optional slots currently under evaluation. The Athena Gas Plant has excess capacity to handle our current range of production expectations, and we're working through the approvals plan to progress the opportunity to produce into a tight domestic market. Funding options for OP3D are well advanced with key gas customers keen to secure offtake by funding the development work through prepayments. The company will make further announcements about these potential arrangements as they progress. I'll now hand over to Dan to provide the financial update starting on Slide 16.

Thank you, Chad, and hello, everybody. Today, we are again reporting a set of record numbers, notwithstanding a half that was impacted by a couple of key headwinds. Revenue was up almost 5%, in part reflecting slightly higher production rates and notwithstanding realized spot prices, which were around 42% lower compared to the first half of fiscal 2023. Unit production expenses were $2.42 a gigajoule, which is flat compared to first half 2023, but it should be noted that this number includes the costs associated with the performance improvement project and the higher cadence of absorber cleans and polisher media changeout. So we anticipate unit costs will fall through the second half of this financial year and into FY '25. Underlying EBITDAX was up slightly on first half 2023, benefiting from that higher revenue. And again, as we look to the second half of FY '24, with the continuation of the improved production seen in January and February and related reducing production expenses, together with assumed higher uncontracted gas prices, we expect underlying EBITDAX to trend up through the second half. While reported cash flow has contracted, if we exclude the spend on the BMG Well's decommissioning program as well as nonrecurring items, including some of the one-off costs triggered by the cost-out program, our underlying cash generation for first half FY '24 was over $70 million. We ended the half with net debt of around $115 million with the BMG Well's decommissioning underway. And while we will draw more from the committed $400 million facility over the next few months as we complete the well's decommissioning program, we remain very comfortably funded for this work. Moving to Slide 17. We have set out the cash bridge for the first half. While reported operating cash flow reflects the impact of the BMG spend over the first half, the underlying number, as mentioned, was just over $70 million, also excluding some nonrecurring items related to redundancies and other expenses arising from the cost-out program and some other one-off ESG regulatory costs. Our cash balance was also impacted by the deferred consideration of $40 million paid to APA at the end of July for the acquisition of Orbost and the $60 million drawdown closer to the end of the financial year as we ramped up the BMG program. Slide 18 is in the same format as you have seen previously, and reinforces the strong liquidity position of the group today. In addition to the cash at year-end, we have an additional $195 million fully committed and available to draw from the [ Sandy Bank ] facility. And as a reminder, this facility has a term out to September 2027, and a large balloon repayment at that time of $180 million. We recently completed the annual redetermination with the bank group, which was very positive for the company, increasing the assessed underlying borrowing base significantly from the banking case agreed at the beginning of the facility in July 2022. This is positive for both the near-term picture but moreover, as we think about the funding options for the next phase of growth. We committed to providing more detail on the cost-out program as part of today's discussion of first half results, including on the progress achieved to date. Slide 19 illustrates how we think about the program overall. The section in red shading reflects the people side of the program, including more direct accountability for outcomes and a more fit-for-purpose structure with the right people, the right capabilities and in the right locations for the business today. The green shaded section speaks to how we work, including working more efficiently as well as a more disciplined approach to planning activities and in a smarter way. Collectively, we are seeking outcomes that result in higher uptime and result in production, lower aggregate and significantly lower unit costs and stronger project execution. I'll talk about G&A in a minute. But on Slide 20, we are providing a greater degree of focus on our production expenses where the biggest prize sits for the business. The pie chart on the left calls out the components of total Orbost production expenses in red, with everything else in different shades of green. The overall sum of the pie aggregates to the group's production expenses, which we have guided to a range of $60 million to $68 million for FY '24. The transformation program is group-wide in its focus. And in the table on the right-hand side of the slide, you can see some further detail. The first 3 red shaded lines are targeting Orbost costs. This includes reducing the costs we incur in managing industrial waste at the plant such as bleed water, spent process fluids and sulfur. While more work is required, we see the potential for more than $2 million of savings here. Chad has already given quite a bit of focus on the next 2 examples in the table. The section in gray in the rest of the table speak to initiatives that are more than just Orbost. Operations excellence goes back to what I mentioned on the previous slide, being smarter in how we go about activities, not just repeating the same steps or the same approaches taken last time and stopping activity that doesn't contribute to the key outcomes. On Slide 21, we're pleased to see reported G&A is down by 20% compared to the second half of fiscal 2023. This is after redundancies and other sundry items arising from the cost-out program as well as some other nonrecurring costs included in the line item that aggregate to $2 million. Excluding these one-off items, the reported number for the half would have been a little under $6.5 billion or a circa 40% reduction. With more savings to come, we are well placed to maintain a 20% saving if not achieving something better for reported G&A in FY '24 versus the prior year. Slide 22 summarizes the different elements of the transformation program. We currently have 93 initiatives tracked group-wide, 19 of those are realized actions completed. We are working hard to have the vast majority of those completed by the end of the financial year. For those outstanding at year-end, this is typically to do with timing of completion or the passage of time rather than actions that need to be executed. For example, changes to software licensing or office lease commitments. In aggregate, we hope to achieve savings of in excess of $10 million across both production expenses and G&A. And if you think about the group cost base across those 2 categories, that implies around 15% reduction in costs overall. While we have seen some savings already booked, the majority of those savings will accumulate in FY '25. And as the strap line notes, this analysis has not assumed a root cause fix of the sulfur fouling at Orbost, which would imply a significant further reduction in production costs. And with that, I will now hand back to Jane.

Thanks, Dan. And here on Slide 24, we continue to focus on the same FY '24 priorities that we laid out in August 2023. As we have discussed here today, we are firmly focused on Orbost performance and the BMG decommissioning in the immediate term. Whilst we are making good progress with production improvements, we are continuing to work through our identified initiatives methodically, delivering the BMG decommissioning program safely and efficiently as possible is the top priority for the executive team and me in the coming months. As we work towards its completion and continuing to deliver identified cost opportunities, we will unlock the latent potential of the business and our Otway growth project this financial year. We will provide an update on the company's strategy and growth opportunities at a Capital Markets Day following completion of the BMG Well's decommissioning program. The strategy and market opportunity for Cooper Energy remain compelling. And there remains a deep value within the business that we will unlock as we look to capture our future growth opportunities. Thank you for your time today, and I would now like to open the lines to any questions.

[Operator Instructions] And your first question comes from the line of Nik Burns from Jarden Australia.

Jane, Dan and Chad, make sure I got the names right today. And congratulations on the results. Jane, can we just start maybe with -- because that the BMG decommissioning program is so important to Cooper. Can you just provide us a bit more detail on the -- and a walk-through for the remaining steps in the program. You mentioned that setting the lower plugs represented 2/3 of the entire program. Does it also represent the riskier part of the program, I assume? But -- and also when you expect to complete that lower plug, having all of those being set, will that be done by, say, the end of next month?

Thanks, Nick. Thanks for the question. So with the BMG program, we're onto the fourth well now in terms of the lower abandonment plugs and hoping that's finished later this week. That leaves 3 remaining wells and the lower abandonment plugs on those. And then the Helix Q7000 and the support vessels will come back and do the upper abandonment plugs on those wells. That's a simpler piece of work. The real complexity and most of the risk sits in these lower abandonment plugs. So that work has gone well. As we've already announced, we've had a slow start to the program with the integration of equipment in the first well. But since then, we actually are delivering the savings and efficiencies that we forecast when we reset the program, and seeing pleasing results in terms of performance improvement on the same activity from well to well. So we anticipate the whole program will be finished in the well's decommissioning in early May and the lower abandonment plugs. Once we're through Basker-2, there will be 3 remaining wells. And so that should take us into the back half of March, early April.

Got it. Maybe a question for Chad. Just on the Orbost improvement program, Chad. First of all, well done on the gains you've made today, it's been really impressive. Just do you have any feel for how far you are through the laundry list of potential improvements that you can make to the plant? Just trying to get a sense for how much further increases are possible here. Are you confident that you can see a scenario here where without a third absorber, you can return the plant to close to its nameplate capacity of 68 terajoules a day?

Yes. Thank you, Nick. So earlier in the year, we announced that we'd hit the nameplate capacity for multiple hours with a 1-day record production of 67 -- over 67 terajoules per day. So we continue to progress through all of the items that we had identified early on. And we've actually added items as we go and find things that can be improved even more. So when we did that record production date, we had also announced that we produced up to 70 terajoules per day of instantaneous rates. Obviously, the sustainable plant production rate is up to a maximum of 68 terajoules per day, and that's really where we've been focused. So in terms of the third absorber, as I had mentioned, we're getting more and more confident with the current production levels that we won't need a third absorber, but that decision will be made at the back half of March.

[Operator Instructions] And your next question from the line of Stuart Howe from Bell Potter Securities.

Dan, similar questions around BMG abandonment. Just when you have everything done by May, how much of that guided $240 million to $280 million spend is left to go? I know that there's other remaining infrastructure that needs to be removed?

Thanks, Stuart. So the guidance range of $240 million to $280 million is for well's decommissioning program, which is the work we're currently undertaking. That range reflects additional general contingency being added in and an ability to deliver the savings and efficiencies that we had forecast into the program. So we are tracking well against that range and certainly within that range still. But we are allowing contingencies depending on whether and what we find in the world. Some wells are more complicated than others and require additional work and additional tests to be run in order to satisfy not [ seeing ] that the wells have been plugged in the reservoir fields. So that range does apply just to this well's decommissioning program. There is some subsequent activity, which is picking up equipment such as umbilicals and flow lines. That needs to be completed by the end of 2026. And that will be part of a separate program, hopefully using a vessel of opportunity that's in the region to do decommissioning work for Exxon, for example. And we're still to tender that work, but the quantum of spend for it is significantly lower compared to the well's decommissioning, which is the riskier, more complex and definitely more costly part of the program.

Great. That's what I was sort of after. And then moving to Orbost. I guess, from my understanding, you've got one bid that's doing in situ cleaning at the moment, and you're looking to roll that out on to the second. If you look at production rates average in December, versus the calendar year-to-date, you're sort of up around 67 TJs a day. If you put in that in-situ cleaning in the second absorber, is that sort of the quantum that you hope to achieve again to spur this production into the -- into the sort of mid-60s?

Stuart, so we actually don't have in-situ cleaning running in either absorber right now. What we've done is some trials on in-situ washing. In the first absorber, we have installed the spray distributor and the new packing material, which enables us to do in-situ cleaning easier. So there was a top tray in the absorber under the old equipment setup and that top tray was really preventing the water or the fluids from washing through into the packing. When we did the original trials, we showed that we could get the top section and the top tray really clean with the in-situ washing, but it wasn't effective through the bed. And that's where some of these equipment changes have enabled us to get better in-situ washing, which is planned for the upcoming months here. Where we are at currently with the current setup is that we're running at over 64 terajoules per day in the two-absorber mode, and we're over about 35 terajoules a day when we go to a single-absorber mode. So to absorbers is over 64, 65 and one single absorber is 35.

And just one last question, if I may. Just on OP3D and Mitsui's alignment. And I know the standard response is always, well, it's a question for Mitsui, but I guess they're not listed here, and we don't get a lot of readthrough into what their thoughts and feelings are on the project. And I know it's not until the back end of sort of 2025 that, that rig comes in start that program. But just wondering if you can give us any sort of color on how you think the joint venture alignment is on that project. I guess the subsequent question to that is you're positioned for growth by then and hopefully, your balance sheet will be repaired somewhat. If not the [ alt ] ways, where do you see growth?

All right. Thanks, Stuart. So with Mitsui, we continue to work with them on progressing the projects. As I think everyone is aware, they've been running sales project and Cooper Energy has been supporting that in terms of the data room on the growth project itself because they don't have that data. And they continue to look at opportunities to exit the asset, but they are more engaged in progressing the asset and they recognize the strategic importance of the infrastructure and the market opportunity and certainly where the gas price has move to. We are doing everything we need to, to progress growth and to keep the growth option alive while we're trying to resolve the JV issue. We have been part of the rig [ cut ] to bring the Transocean rig to the area as you say, in late 2025, early 2026 for our drilling, and we have a firm [ FLOT ] and a number of optional [ FLOTs ] that we can call in that program. So we see that as a very attractive option.

And I guess just on growth, if not the [ alt ] ways.

Sorry. On the growth projects, we're in the midst of a farm into the PEP 169 acreage around the Athena Gas Plant in the onshore Otway Basin. So that presents another opportunity to bring gas back into the plant. We are also looking at opportunities in the Gippsland Basin in 2 areas. One is exploring in the acreage that the BMG well decommissioning sits in. There's significant gas resources there. We announced 1.3 Tcf of prospective resource. And we are looking at bringing a partner in to help us explore that, and that will ultimately tie back the Orbost plant at the end of the [ Sofield ] life. We are also working on what would be involved in repairing and restarting the Patricia Baleen and potentially the Longtom assets working with Seven Group. But those assets are already connected into the Orbost Gas Plant and used to produce into the plant. But the umbilical, which control the wells failed. So we're looking at repairs for that infrastructure in order to get it restarted. So that potentially represents another growth opportunity, which should be faster cycle than a greenfield development or a new resource tied back to the plant because all of the infrastructure is in place. So we're just going through a process of assessing the state of that infrastructure and what repairs would be required to restart it. But they are the 2 focus areas for us. We're very comfortable with that focus in both the Otway and the Gippsland Basin. There's significant prospectivity in both basins. The plants are close to markets. These are low reservoir CO2 assets that are well connected into the existing markets and customers. So we are comfortable with really trying to unlock the latent value in that and see enough running room in our backyard.

Your next question comes from the line of James Bullen from CGS.

Just I guess I've got a first question around the leverage. Jane, how do you think about leveraging the appropriate level for this business? And also, I was just curious as to the size of the borrowing base now post the redetermination?

Great. Thanks, James. I'm going to hand to Dan to answer these questions.

Yes. So what we will look to do with the next phase of growth, of course, is to fund a significant portion of that with debt. Of course, we do have fairly long-life GSA contracts with fixed price and fixed escalation. And we're seeing those contracts getting repriced or reviewed or reset into the mid-teens. And so we're really excited about that. And of course, that's with investment-grade offtakers. And so we think that profile does suit high levels of leverage -- than other potential upstream opportunities across the sector. I think in terms of the redetermination, where that's left us has been a significant increase in that borrowing base and significantly above the $400 million committed funding, which is a nice place to be as we think about the possibility or the potential to access the accordion in the next phase of growth.

And just around production expenses of $2.42 in the first half. I think you had mentioned that they were going to fall in the second half. Is that just driven by assumptions around higher levels of production, both at Orbost and Athena? Or is there something else that could be driving that?

Thanks, James. Yes. So as you've seen, the production expenses in aggregate for the first half were around $28 [ billion ]. And so on an annualized basis, that's positioning us very well. In the second half of the year, both the numerator and the denominator, we're excited to see what we can achieve on both elements. And so first half of the year, including in the first quarter, but for much of the first half of the year, the cadence around those absorber cleans was very focused on that fortnightly cycle, and as Chad has mentioned, absorber 1 has now been operating for around 4 weeks and is still in operation. And so we expect to see, for example, a lesser cadence or an extended period of time between absorber cleans and that does result in lower costs. We're really pleased to see how the new media has been performing in the polisher unit. So we'd expect fewer polisher media change-outs based on what we see right now. And so that's just a couple of examples around the numerator. And then the denominator as we've talked about, we've set a record of 55 terajoules over a 60-day period compared to the reported production rate for the first half, which is 10% below that number. So we're really excited to see what happens with the numerator and the denominator. And we'll keep a very close eye on production expense guidance to review that once we have greater confidence and conviction in terms of where things are going over the next couple of months. We are mindful, of course, that the plant has shown variability and uncertainty. And so we do want to factor in and reflect on that as well in the mix. But yes, it's -- we're really pleased with what we've seen over the last 2, 3 months.

Your next question comes from the line of Sam Berridge from Perennial.

Just I think there was a comment made by Chad that the -- that one of the absorbers has been online for 4 weeks, and that one had a different packing in it. I was just curious if -- is that different that's, I think it's called snowflake packing, still to be installed in the second absorber? Or is that already there?

Yes. Thanks, Sam. So yes, the snowflake packing is still to be installed on the second absorber. Through our trials, we wanted to do a stepwise process where we tested it with the different setup for the spray distributor versus the old plate distributor and different elements. The good news about the increased length between our absorber cleans is that we're getting more production. Ironically, the thing that affects is it takes longer for us to do our trials because it takes us a while to be able to set it up, to get in there to do the trials. So yes, we do not have snowflake packing in the second absorber or the spray distributor.

Yes. Okay. And with the spray distributor, I think you mentioned the first trial. I didn't quite give you the answers that you want to say, which is you guys were just looking at some reorientation within the beds or the trays at the top. Have you got sort of a broad steer on when that next trial of the in-situ cleaning will be carried out as in a month or quarter's time?

It's months' time.

Okay. Got you. And sorry, just one last question for me. On the -- just from the previous question from James regarding the debt redetermination. I'm curious with the -- is there going to be a bit of a difference between the prices used by the banks and the assumptions by the sub-analysts on the sell side?

Yes, I'd say there's definitely a difference between the assumptions that the banking group tends to deploy for its banking case modeling purposes. The redetermination certainly benefited from the annual price resets that are built into the GSAs. And as the inflation rate that we observed in 2022 and 2023, the Energy Australia contract that we announced the contracting for, also had an impact for volumes in 2026. So there was a variety of factors. But Sam, yes, they certainly take a -- for their base case banking case model, they tend to take a fairly cautious view, something that's driven off the low end of an industry consultant view like EnergyQuest but often making further adjustments to that as well. So yes, there's -- I would say there's a difference there. But overall, that annual redetermination, as I mentioned, was a positive outcome for the business and resulted in a significant increase in that underlying borrowing base assessment.

A bit more color on the pricing. When we talk to our major gas customers, they are actively in discussions with all of the 4 LNG import projects. They need a physical solution for their gas supply and their options are gas [ devoted ] from Queensland and the pricing for that is in very rough terms, $12 at Wallumbilla and somewhere between $2 and $4 of transport cost at Victoria depending on your sub transport position. And then LNG imports, obviously, will be at international prices, partly the regas fee and the distribution costs. So we are seeing a significant shift in the buyer's attitude around gas supply, there's a sense of urgency setting in, but also the price has definitely moved upwards. And EnergyQuest have come out saying LNG imports would be circa $16 to $24 a gigajoule, and that's simply just converting U.S. dollar LNG prices with the current FX. But we really see a material shift and where buyers are thinking about the price of gas from even 12 months ago. And that's just reflecting the scarcity in the market. The rapid decline in the Gippsland Basin production and long fixed capacity. And certainly, that's why we're seeing this very strong support for the Otway growth project. Our project there, a 3-well development bringing 90 terajoules back to the plant is potentially the biggest new supply project into the Southeastern market. And so there's a lot of support from customers to see that happen. And if they don't get gas from us and they're very reliant on LNG imports or gas from Queensland.

Yes, yes. So that's what I was getting at. I mean, and specifically, the GSA with Energy Australia, I mean, that's -- I'm guessing, I think we'll see it somewhere in the mid-teens. I'm assuming that that's going to be a base case assumed for debt or for everybody really, isn't it?

Yes. So there were specifics to that particular price review. And every contract we signed with an individual buyer has term specific to that contract in terms of any caps on the price review and the duration of that price review. But certainly, the trend is we're seeing gaps being repriced to the alternative, which is Gas directed from Queensland or potential LNG imports.

Your next question comes from the line of Declan Bonnick from Euroz Hartleys.

Congrats on the improvements to date. That's really great to see. I've just got a question on BMG and the contingency cost there. So given you stated there's been a bit of weight on weather. Are you able to provide a quantum on how much of that contingency has been used to date?

Thanks, Declan. Yes, we have had a couple of occasions where we've been waiting on weather. And it's really because the weather has been too good and we need more wind to flare off the vessel and what flare the contents of the rig. So it's almost the opposite of what the Helix experienced in New Zealand. When we reforecast the program and announced that on the 22nd of January, we reloaded the estimate with contingency for both waiting on weather and nonproductive time. And that's included in the bottom end of that range at $240 million. The top end of the range, $280 million includes further general contingency and also an expectation that the savings and efficiencies wouldn't be successfully delivered right up at the top end of that range. So the progress so far really reflects -- the waiting on weather component of the contingencies. And there are some savings and improvements. Some wells are more complicated than other than others, as we've talked about before, but we're continuing to track within the revised guidance range.

That's excellent. And just the other one on OP3D timing. Is there an update there? In terms of that [ first term ] rig slot?

The rig is due to come to the Otway in late 2025. We understand that the Crux program has been slightly extended, and that's going to create a small delay to the rig arriving in the Otway. So it's likely to push the Cooper Energy firm well into late '25, possibly early '26. And then our optional slots will come after that. We do have some flexibility on calling those options over the next 1.5 years. So we will continue to sort of work to progress the project with Mitsui and get ourselves in a position to proceed. There are some long lead items we wanted to commit to over the coming 6 to 12 months, which will lock in the program and ensure we're ready to proceed with that exploration and appraisal activity and development wells.

And that concludes our Q&A session for today. I'd like to hand back over to Jane for closing remarks.

Great. Thank you very much, and thanks to everyone for joining us this morning. We're really pleased to see the steady progress of both BMG and the improvements at Orbost. And we're seeing steady progress in terms of removing the sulphur problems and pretty confident in how we're going to continue to deliver that process over coming weeks and months. We're really pleased with the cost-out progress we've made and an annualized saving of potentially $10 million to be locked in by the end of this financial year on a repeatable basis going into FY '25. Once we have resolved BMG and improved Orbost, we'll be really in a much stronger position for growth. As we've discussed, there's a significant growth project there of 90 terajoules per day, potentially the largest supply project into what's an increasingly short market with pricing moving to LNG import parity or redirection from Queensland. So we're very pleased with the strong support we've seen from our gas customers for that project and the reliability and operational excellence we're driving into the business, gives us more confidence in our abilities to deliver that sort of growth project, but also to meet our annual production targets and cost reduction targets. So thanks again for joining us today, and we look forward to seeing you on the road.

This concludes today's conference call. Thank you all for joining us. You may now disconnect.