Beach Energy Limited

I would now like to hand the conference over to Mr Brett Woods, Managing Director and Chief Executive Officer. Please go ahead.

Good morning everyone and welcome to Beach Energy's FY25 full year results presentation. Joining me today is Anne-Marie Barbaro, our Chief Financial Officer. Together we will take you through our results for the year and our latest outlook for FY26 before we open up the lines for Q&A. We thought it was appropriate to bring forward our results, given there was a lot of news out in the quarterly last Thursday, including reserves revision and a non-cash impairment, which we will discuss today. This year, Beach made significant progress against our strategic review objectives and its company vision of becoming Australia's leading domestic energy company, while delivering outstanding safety, environmental performance and strong financial results. It was Beach's operated assets which drove our solid results Those operations within our control and over which we apply our strict operating principles have transformed Beaches Foundation. We ended the year with a strengthened balance sheet and the financial flexibility to pursue both organic and opportunistic growth. Beaches operated assets and non-operated interests now supply 19% of the entire East Coast domestic gas market. This positions Beaches as one of the most significant suppliers of gas to the East Coast. Slide two sets out the compliance statements, which I'll lead you to read at your leisure. We begin with slide three, which conveys a compelling value proposition for BEACH. The hard work we've put in over the last 12 months has clearly transformed the organisation and strengthened our foundation for growth. We've materially lowered operating costs, expanded margins and finished with a year with a strong balance sheet. This puts us in great shape to deliver our existing pipeline of opportunities return cash flow to shareholders through the record fully frank dividend we announced today and position ourselves for growth. The strategy we announced last year is clear and simple. We are focused on our core East Coast and West Coast hubs as we work towards our vision of becoming Australia's leading domestic energy company. In FY25, we made great progress towards this vision by increasing our share of the East Coast gas market share from beaches operated assets and non-operated interests to 19%, as I mentioned. But more on the East Coast in a moment. An owner's mindset has become ingrained in the culture at beach. We have restructured the business, taken structural costs out, improved our margins and cash flows, and have driven our pre-growth, pre-cash flow break-even, all price, well below $30 a barrel. In the field, we delivered great outcomes from our operated assets, including completing the offshore oilway development program and reviving production in the Bass Basin. And we did this while achieving our best safety performance in 14 years. This is a credit to our teams. Our commercial focus on extracting maximum value for our molecules has seen a material proportion of the Cooper Joint Venture gas volumes recontracted while retaining volumes to capture value through seasonal spot demand. So in summary, all the elements of our strategy have been progressing this past year, which culminated in strong growth in earnings and free cash flow. This enabled the board to declare a record dividend of $0.06 per share, bringing total dividends declared this year to $0.09 per share. Slide four. shows our strategic pillars, four hubs, high margins and sustainable growth. These pillars established a clear framework to drive operational efficiencies, foster a culture of accountability and performance, and balance dividends with investment growth. As highlighted in today's presentation, in FY25, we made significant progress in executing key elements of our strategy. Strict focus on core hubs saw a material increase in the supply of gas from Beaches operated assets and non-operated assets. While progress made at Waitsea sets the foundation for a significant increase in West Coast gas market share once our LNG export period ends later this decade. An owner's mindset saw us deliver high margins with a 300 basis point increase in underlying EBITDA margin. And we are growing sustainably with Moomba CCS now online. Progress made this past financial year has positioned BEACH as an efficient, resilient and focused supplier of natural gas to Australia's domestic markets with a commitment to long-term value creation. Next slide shows outcomes against objectives at the start of the year. Implementation of the asset-based organisation structure and appointment of my full executive leadership team have clearly underpinned the reset of BEACH. This past year, we delivered the base horizon of BEACH's strategy, as outlined in the strategic review presentation from June last year. The base horizon involved forming a profitable and resilient foundation for growth through lower costs and higher margins, notably $130 million in cost reductions with a 20% reduction in sustaining capital, and an 18% unit operating cost reduction. Maintaining a strong balance sheet, notably reflected through our free cash flow breakeven, which is well below US$30 a barrel in FY25, and our low leverage. Refreshing exploration inventory and delivering sustainability objectives. The results set out on this slide clearly align with these objectives. We will talk to these achievements in more detail throughout today's presentation. The key targets for FY25 were imperative for delivering a low-cost, disciplined operating model. And I'm very proud of those achievements of our organisation, led by our exceptional executive team. Slide five tells a great story of Beech's position in the East Coast gas market. Starting with the macro outlook, where the story remains the same. Gas supply available to the domestic market is declining, while gas demand over the long term remains firm. This sees widening structural supply deficits from late this decade onwards, not to mention the seasonal supply deficits the East Coast currently experiences and are expected to increase over time. In response, Beech has been investing heavily over recent years to position ourselves as a leading supplier of gas to the East Coast market. This year, we've made great progress in achieving that goal. New gas supply from Enterprise and Thylacine West in the Otway Basin and a rejuvenated Yola Field in the Bass Basin saw our East Coast gas production increase by 23% in FY25. With high gas demand throughout the year, and in particular in recent winter months, beaches supplied 90% of the East Coast gas demand in 2025. On the contracting side, our disciplined gas marketing strategy saw us reposition our contract portfolio through this last financial year. The legacy Cooper-based and joint venture gas contract that we have been speaking of for some time ended on the 30th of June, allowing us to recontract a large volume of that gas in recent months. Approximately 40 terajoules a day of gas has been recontracted on a short-term basis, and you will see the benefits of this through our improved pricing and margins starting to flow through our quality reports during FY26. We are continuing to mature our sales and marketing capability and now have access to all the spot gas markets in the East Coast. This ensures we can deliver gas to where it is most needed when it is most needed. We have also begun exposing our molecules to the power market with one of the new contracts providing spark spread upside. This is a novel way to capture power pricing upside on days when demand for gas-fired power generation is high. On days when it's not, we retain our exposure to the gas spot market. Our June 2024 strategic review outlines that we would pursue adjacency in the power market, and this is just the start of implementation of that strategy. I look forward to sharing more with you over time. Our recontracting allowed us to rebalance our customer portfolio. We now have several new customers and have diversified our exposure across end users and industrial sector, retailers, and gas-fired power generators. Lastly, in line with our marketing strategy, we've retained approximately 30% of our East Coast gas supply for the spot market. This means we have a good balance between contracted volumes and spot exposure for when the market needs our gas. Our contracting strategy will enable us to make annual decisions on where these volumes can go. Turning now to slide six and our headline financial results, which again showed the outcomes of our hard work. Material growth across all key metrics were delivered. Total production increased 9% to 19.7 million barrels of all equivalent. In the Otway Basin, the 64% increase in production to 6.8 million barrels of all equivalent was driven by a connection of the Enterprise Fields in June 2024 and the Thales and West Development Wells in October 2024. In the Bass Basin, a low-cost production optimisation initiative delivered greatly improved well performance, leading to a 91% increase in production to 1.4 million barrels. Unfortunately, these good production outcomes were partially offset by severe flooding in the Cooper Basin late in the financial year. Sales volumes rose 16% to 24.7 million barrels of oil equivalent, supported by higher production and five weightsier LNG swap cargoes. The 13% increase in sales revenue to $2 billion benefit from those five LNG cargoes and a 13% increase in the average realised gas price to $10.70 for domestic volumes. The $352 million of revenue generated from the Waitsea LNG cargoes clearly shows the value to be created once the Waitsea gas plant is up and running. Underlining EBITDA increased 20% year-on-year to $1.1 billion while underlining NPAT increased 32% to 451 million. The underlying EBITDA margin improved by 300 basis points to 57%, reflecting structural cost savings achieved and improved commercial outcomes. These results culminated in a much higher cash flow generation with a four times increase in pre-growth free cash flow to 657 million. In recognition of these results, the Board has declared a record final dividend of $0.06 per share, bringing our full-year dividend to a record $0.09 per share. This represents a 31% pre-growth free cash flow payout ratio. I want to highlight that whilst the payout ratio is below the targeted 40% to 50% range, our policy has always been subject to Board discretion with a view of balancing returns to shareholders with investment in value-accredited growth. This year, we as a board took the decision to deliver a material step up in the dividend. However, to also preserve flexibility for FY26 capital activities and potential value accretive opportunities. As part of our strategic review outcomes we delivered in June last year, we highlighted the vision of this company to become Australia's leading domestic energy company. And to do this, we're always looking at opportunities for disciplined value accretive growth. We have active work programs across our portfolio in FY26 as we continue to progress our objectives of growing east and west coast market shares. Slide 7 sets out our reserves and resources position at 30 June 2025. Bahara Springs revision was clearly a disappointment. We had reported a reserves revision in FY24 due to results at Bahara Springs Deep 2. where well partial pressure communication was observed between Bajara Springs Deep 1. We had an upcoming well that had a range of potential outcomes, including compartmentalisations, which have been observed throughout the Waitsia Field. Therefore, Bajara Springs Deep 3 was required to address the initial reserve booking and to test connectivity across the fault floor, the variety of the commercial bookings, and to identify the preferred development pathway for that field. What we experienced was partial communication across a more significant fault block, which was unexpected. The potential for Bajara Springs Deep 3 to intersect an isolated compartment within the northern area of the Bajara Springs fields did not eventuate. The remaining reserves balance now correlates to a fully connected field volume across those three wells. While this is a disappointing outcome, learning from the campaign have focused our attention on structural traps further south and east of the Bajara Springs Kingia Fairway. A number of these present as material opportunities. We are refreshing our exploration portfolio and inventory and are planning further seismic acquisition across this area as we prepare for our next exploration campaign. I remain highly encouraged by the potential of the acreage. Flood down and reserve is also worth noting that the results from Bajara Springs 3 deep has no impact on weights year two, weights year stage two LNG sales or returns of any swap gas. We actually drilled three weight seer wells during the year and the results support our 2P bookings. In fact, the last three wells have been some of the best wells drilled in the field to this point. There are three wells remaining for full field development and we are confident in the booking that we have today. However, we'll be able to resolve further the range between 1P and 3P once the weight seer gas plant is online. Turning now to health, safety and environment on slide eight. Over the past year, we launched several targeted safety campaigns aimed at increasing awareness and strengthening compliance with critical safety procedures. Pleasingly, we delivered outstanding safety environmental performance, recording our best personal safety result in 14 years and no hydrocarbon spills of consequence. On the safety front, we recorded just one tier two process safety event, and one recordable injury. These are very pleasing results given the heightened focus beach has placed over recent years on improving our safety culture. It is also a credit to our staff in maintaining their dedication to safety as the organisation went through such a period of significant change. As we look to FY26, it is imperative we continue this level of performance, particularly as we've embarked on the Equinox rig campaign in offshore Victoria. Continual improvement is our mantra and is reflected in performance improving focuses over FY26. Slide 9 highlights several sustainability milestones that Beech have achieved over the past year. First and foremost, the key highlight was completion of the Moomba CCS project, which is an integral element to Beech's emissions reduction pathway. Moomba CCS is safely and reliably storing CO2 and has already abated more than 1 million tonnes equivalent to removing roughly 400,000 cars from Australian roads today. Successful commissioning and operation of member CCS have put Beech well on track to achieve its target of a 35% equity emissions intensity reduction by 2030. This is a significant achievement for both Beech and Australia's broader decarbonisation efforts. It was also very pleasing to see member CCS recognised at the 2025 APAC Energy Awards in Singapore. In FY25, we set a new methane intensity reduction target, reinforcing our commitment to safe and efficient operations, achieving a methane intensity of just 0.05%, an outstanding result and reflects our team's year-round focus on minimising fugitive emissions from our facilities. In addition, We published our inaugural Reconciliation Action Plan, formalising our commitment to build a more inclusive, respectful and equitable society. It's empowering to see the strong relationships we're building in local communities. On that note, I'll hand over to Anne-Marie to discuss our financial performance.

ANNE-MARIE BUSBY- Thanks, Brett. Good morning, everyone, and thank you again for joining us today. Our headline financial metrics are set out on slide 12. Results this year were underpinned by higher production, five weightsier LNG cargoes and great progress with structural cost reductions throughout the business. These delivered a material step up in underlying earnings and cash flow. Sales revenue was up 13% to 2 billion, driven by an uplift in our offshore Victorian sales volume, coupled with a 13% increase in realised gas pricing. in addition to five LNG cargoes at Waitsea which were delivered during the financial year. Growth in sales revenue was partly mitigated by a lower oil price realised during the financial year. Our average realised oil price was 13% lower this year at 124 Aussie per barrel. Underlying EBITDA and MPAT were up 20% and 32% respectively with a 300 basis point underlying EBITDA margin expansion. Statutory earnings were impacted by the non-cash impairment announced in our quarterly report last week. We recorded a $474 million post-tax impairment of our Cooper Basin and Perth Basin carrying values. The impairment in the Cooper Basin was largely driven by a lower near-term commodity price outlook, as we saw realised through FY25, in addition to prioritisation of development drilling in the Cooper Basin joint venture in the near term following recovery of the floods. This prioritisation has no overall impact on our capital expenditure guidance or outlook. In the Perth Basin, again, the impairment recognised was largely driven by lower near-term commodity prices, with other smaller impacts, including the reserve revision in Bahara Springs and cost inflation associated with future weights year development activities. Our strong operating results delivered a greater than four times increase in pre-growth free cash flow to $657 million for the financial year. Slide 13 steps out the movements in underlying NPAT, which, as mentioned, was 32% above the prior year. This slide shows the great job done across the business in driving costs out of our operations with a $32 million reduction in field operating costs, which equates to an 18% reduction in unit operating costs to $12.80 per barrel of oil equivalent, well below our FY25 target of $14 per barrel of oil equivalent. We're well on track to deliver our $11 barrel of oil equivalent target once Waits Year is up and running. It's also worth calling out that Beaches Operated Assets delivered a unit operating cost of $10.68 per barrel of oil equivalent this year. The operations within our control and over which we apply our strict operating principles have transformed Beaches Foundation. Turning to slide 14, which shows movements in cash during the financial year, which resulted in closing cash reserves of $172 million. Operating cash flow of $1.1 billion was a significant step up and was driven by higher production, largely across offshore Victoria, the delivery of five weight tier LNG cargoes and the cost reductions achieved. Sustaining capital expenditure of $465 million was 22% below last year, which again reflects our efforts in driving cost out of our business. Just to note, sustaining capex incurred during FY25 was $402 million, well below our target of $450 million, with the remainder reflecting movements in working capital. With a strong free cash flow generated this year, we paid down $215 million of debt, enabling us to maintain our low leverage position, which I'll turn to now. Slide 15 reflects our strong position. We ended the year with $652 million of available liquidity and have maintained our low leverage position reflected through 10% net gearing at the end of the financial year. Our capital management framework aims for net gearing to remain below 15% through our cycle. This target leaves ample capacity to increase debt levels to enable Beach to capture opportunistic growth. As Brett spoke to earlier, Beach delivered a record final dividend of $0.06 per share, bringing full-year dividends declared to $0.09 per share. This dividend reflects a balance between delivering strong shareholders' returns whilst maintaining capital for our organic capital program and to capture opportunistic growth. On that note, I'll hand back to Brett.

Thanks, Anne-Marie. Now let's have a look at what's coming up in FY26. FY17 sets out the FY26 guidance. much of which we have already guided to, so I'll try and keep my comments brief. For production, we are guiding between 19.7 and 22 million barrels of all equivalent, which reflects an increase in production from FY25. Variation in that range is primarily driven by timing of weight startup and the ramp-up profile and the impact of the Cooper Basin flooding and customer nominations in the Otway Basin. In the Cooper Basin, the floods will defer roughly 1.5 million barrels of production across the western flank and the Cooper Basin joint venture. Floodwaters are starting to recede, but it is a slow process and restoration of wells will need to be done incrementally during the first half of FY26. In the Elway Basin, an expected reduction in production of up to 20% is expected this year, which consists of many factors, including field decline, some planned maintenance and commercial elements of our gas sales agreement with Origin, which do require us to set our take-or-pay levels with a degree of conservatism. I should emphasise that Otway Anchorage is performing strongly and the Otway gas plant is producing close to its 205-terajoule-day nameplate capacity for an extended period this winter. With the Otway Fields Production nominations FY25 performing well above budget, I've had to reset that expectation back to normal production levels. For capital and abandonment expenditure, the big driver is the Equinox rig campaign. The scope and cost associated with the campaign is in line with our prior communications. Also included in the capital program is the Western Flank oil appraisal and development campaign. We're also planning to start this in the second half of the financial year when the flood waters subside and access to leases reopen. Regarding standing capital expenditure, I note that the guidance is below our $450 million operating principle, which is a material reduction from recent years. Turning to the next slide, our planned activity for FY26, as this slide shows, we're actively investing in the base business to develop our existing reserves and go after new discoveries. In the west, delivery of the wastewater gas plant will be a major milestone for BEACH. The way to joint venture is close to bringing the plan online with first gas expected during this quarter. Commissioning of the amine system has been de-risked with the completion of the hot flushing and degreasing work scopes. Key activities from here to begin production include finishing commissioning of the sales gas compressor, the MEG systems and closing out the final commissioning amine system and the wells and gathering systems. On the east coast, the Equinox rig campaign is now underway. after a weather-related delay. The rig is currently on location at Geograph 1 and is undertaking abandonment of that well. We're now well into this abandonment and it is all tracked into plan so far. We will then abandon the Thylacine 1 well before embarking on the exciting Hercules Exploration well. The Hercules prospect is larger scale opportunity, albeit with a moderate risk, which lines to our growth strategy. Other activities in the campaign includes drilling and completing of the Labella II development well, completing the previously discovered artisan field, potential well intervention at thylacine to optimise production performance, and abandonment of two wells in the Bass Basin. A successful Equinox campaign will provide us with optionality to consider a potential subsidy development and connection of wells to the Otway gas plant. We expect to make a final decision at the end of the Equinox rig campaign. In the western flank, the delayed Tenwell oil appraisal and development campaign is set to commence in the second half of FY26. We'll be targeting undeveloped reserves in the McKinley and Burkhead reservoirs with the aim of arresting some of the decline seen over recent years. In line with our operating principles, efficiencies and cost savings will be an integral component of this campaign. And initiatives will include dual laterals to reduce the number of wellheads and associated infrastructure, drilling from common drill pads and reducing casing and cementing requirements. I look forward to reporting on drilling outcomes in due course. I'll now close out the presentation before we turn to Q&A. FY25 results demonstrated solid progress against our strategic review initiatives, while the growth in earnings and cash flow show the strength and foundation we have created to deliver growth. As we look to FY26, our strong balance sheet low-cost operations and domestic focus make Beech uniquely positioned to pursue organic and opportunity growth to deliver on our vision to become Australia's leading domestic energy company. I'm excited for the year ahead. And on that note, I'll open the line for Q&A.

Thank you. If you wish to ask a question, please press star 1 on your telephone and wait for your name to be announced. If you wish to cancel your request, please press star 2. If you're on a speakerphone, please pick up the handset to ask your question. Your first question comes from Adam Martin from E&P. Please go ahead.

Yeah, morning, Brett and Marie. Yeah, morning, Brett and Marie. Sorry, can you hear us okay?

We're just having a feedback. We can now.

Just breaking up a bit.

Sorry, yeah, just on the dividend, can you talk us through the dividend there? Some in the market worried about sort of, you know, much lower dividend on M&A or, you know, net debt rising in the next 12 months. Can you talk us through that, please?

Yeah, so with regard to the dividend, the board took the decision to set the payout list level slightly below our 40% to 50% number that we guided. This is fundamentally to make sure that we're well positioned for the coming year in terms of our... and always to leave a little bit of cash available for anything that may be opportunistic. I can assure you at the moment, I don't have anything in that opportunistic category. But as I highlighted through last year's strategic review, my focus has been earning the right to grow. And I think much of our execution over the last year has really been setting the basis of our of our organisation, getting our balance sheet right, getting our operations effective and really reducing that cost that the organisation had built up over a number of years. Hopefully you'll see that the results reflect a real strong movement and positive movement in cost reduction and performance across our assets. And, you know, then we, you know, I think I've often used the language earning the right to grow. I've always reflected that any right to grow really needs to have the wax year project in production. And, you know, I think we're a long way down that track to reflect on the fact that we're ready for growth. I think the challenge I have, and I've often spoke through with many of you on this call, is... features in organic portfolio is limited in scale. So we will be looking to improve our portfolio and try and add some length into our portfolio over time. But I'll only do this in a very considered and value credit way for all shareholders.

And just on cost, quite a bit of a mention in FY25. You know, any further cost to our potential, 26, 27, just conscious of that lower production in the Cooper Basin on a unit perspective, but any further momentum there on cost, please?

Yeah, so through what we were seeing through the flooding in the Cooper Basin, we did take some opportunities and Glenn, our head of the assets, is taking the opportunity to further decrease costs across those assets. We've recently simplified our operations in New Zealand very much to address that. Adam, the key thing as we have some late life assets across our portfolio, we'll continue to drive our margins to defend against those assets decreasing in their contributions on an annual basis. That's really an absolute focus. We're well on track to deliver against our $11 a barrel target for this financial year in terms of our cost base. And I think it's very much in my DNA and now I think in the organisation's DNA to continue to chase costs and opportunities as we move forward.

Okay, thank you.

Thank you. Your next question comes from Dale Kernders from Baron Joey. Please go ahead.

Morning, Brett and team. Maybe just firstly, on your $11 per Bowie cost target, there's a footnote in the expenses where you've reallocated $23 million of field costs into tariffs and tolls. So is that 11 still 11 or is it now 10?

It's still 11, Dale. I guess when we set that target, it was really looking at our peers and our what targets and what achievements there are in the market. So we set that $11 a barrel at a level that is outperforming our peers. So we're still, obviously, we're trying very hard to outperform that. And as you would have seen with our operated assets, as I mentioned earlier, we were down at $10.68 this year. So we are obviously trying to do better than that, but the $11 was really a benchmark set to be able to compare us to our domestic peers.

Okay, and then just given the strong focus on financial strength for growth, I'd just be interested in some comments around where you think your balance sheet capacity is given gearing's effectively your target and the willingness to use equity where it's value accretive.

Yeah, so I think maybe if I take you back in terms of when Beach did the lattice transaction, we have a target gearing level kind of through the cycle, but for opportunities that may arise, be willing to stretch the balance sheet and similar levels that were executed through the latter's acquisition and using our debt capacity to support acquisition for that regard. So, you know, I think we have a very strong balance sheet, 10% going at the moment, you know, we'll rise through the year through our Equinox campaign, but it doesn't exceed our 15% target level, and we'll be at a D gear very quickly after that. And similarly, that gives us great opportunity to use that strength of balance sheet if the right types of opportunities come up to grow.

Yeah, and I guess to support that, Dale, obviously we've talked about this 15% gearing as our target, and it's really going to depend on the types of assets we look to acquire as to how far we're comfortable to stretch that gearing. If they're assets that have production in them, obviously we're comfortable to stretch them further like we did with Lattice. Obviously if there's a lot of capital to invest, we'll balance that out. So really our priority is to use debt for acquisition and we'll be stretching that sort of as needed depending on the assets that we acquire if and when we do so.

Okay. Thank you.

Thank you. Your next question comes from Tom Allen from UBS. Please go ahead.

Good morning, Brett, Anne-Marie and the broader team. Can we read into the board's willingness to pay a six cent per share final dividend despite Waitsia not being commissioned as a clear sign of the board's comfort that Waitsia will be commissioned within weeks rather than months? And can you share any colour on the commissioning the joint venture has completed over the last month or so on the sales compressor trains?

Yeah, so, yeah, cheers. Thanks for the question, Tom. I think the critical element which I've raised with the market through the previous quarters has been a question about the cleanliness of the amine circuit. That was kind of a critical path item for me, and we were able to, in supporting the operator, accelerate power and hot water into the commissioning to get that system worked. I'm very, very pleased to say that we've now completed the hot water flushing across the amine to demonstrate its cleanliness. We've now done the degreasing, and that's taken the amine circuit off the critical path, so that's really critical. So what's left now are, you know, your normal traditional elements to go, which is getting the sales compressors going. And we'll be moving through that over the next few weeks. And I certainly, you know, always have to be cautious when... I don't operate an asset, but we are very much on track to deliver weights here online in this quarter. And obviously the board is very supportive of the way we've been performing and the way we've been driving this forward through our commissioning team that we're using to support the operator. And that reflects our ability to pay dividend and confidence within that position.

OK, thanks, Brett. If I could sneak another, please. So the reserve statement sees a net reduction of 13 million buoys of 2p. So the average remaining reserve life now just over seven years, depending on your production assumptions. You provided a little bit of colour on this call, just around the types of opportunities that you'd be willing to stretch the balance sheet a little bit. But the question is, can you please outline more detail on the framework under which you're going to assess new opportunistic growth? So perhaps a guide on hurdle rates that Beech will target, indicative funding plan, perhaps some colour on the geographic and product-based diversification that you might seek to build in this future portfolio.

Yeah, so last year's investor strategic review, we outlined our investment criteria for our hurdle rates. So we haven't shifted from that, which are typical and strong, so north of 12% rates of return, et cetera, across our gas portfolio and in excess of that for any liquids opportunities. In terms of opportunities we're looking for, I really believe that there is wonderful opportunities domestically here within Australia, and we're very much focused on that vision of becoming Australia's leading domestic energy provider. So we'll be looking around opportunities connected to the east coast of Australia and the west coast of Australia as a fundamental. I'm not looking offshore. That is outside of our area of interest. And, you know, we'll continue to do that, particularly... around areas where we have existing infrastructure, like the Otway Basin or the Perth Basin, for instance. So, you know, for me, there's opportunities that will emerge over the next years with drilling campaigns that are occurring in the Otway Basin and around that area, and other opportunities that may occur moving forward. So very keen to make sure that we will only deliver against opportunities that deliver hurdle rates. As Amarine alluded to, I've always kind of had a bit of a rule of thumb for the team that we wouldn't stretch gearing past 25% for a development asset, you know, but we would push it further for a production asset as long as that production asset can de-gear quickly to maintain that. So I've been, you know, it's unusual for me to move slow on things, but I've been very cautious not to kind of damage our balance sheet with, small Pac-Man type acquisitions, looking for things that can support the lengthening of our portfolio and get beach growing sustainability for the future.

Thanks, Brett. And just following up your comment on the wide range of attractive domestic growth opportunities that you see. A number of those larger domestic opportunities are held by others in the sector currently under a take private proposal. So do you see any constraint in Beech's ability to access exposure to some of those assets? Or you think there's a broader suite out there that fit the profile?

Well, you know, I hope to demonstrate to you that I think there is a broader suite over the next few years. At this point in time, I haven't had any discussions with any people involved with that transaction you're alluding to. And, you know, my focus really is to put Beach in the best possible position to maximise value for shareholders and utilise our balance sheet. And I think we offer a very unique value proposition being an Australian company, being very focused on domestic supply, and now being quite an influential player across the East Coast, given the fact that we... we deliver 19% of the East Coast gas market. So I think that helps support our objective. And, you know, we all know how much gas is required to continue to supply the future of the demand past 2050 even for the East Coast. So, you know, I think there's a great opportunity for us to lean into that. And we'll continue, whether it be through gazettals or through other opportunities to look through opportunities that will add value to our portfolio and deliver top-level TSR outcomes for our shareholders. Thank you, Brett.

Thank you. Your next question comes from Saul Kavanich from MST. Please go ahead.

Thank you. If I could start just coming back to the dividend and the payout policy because I think it was at the December half it was a lower payout than the policy citing things like ABEX uncertainty and now it's a lower payout citing potentials for growth. Given there's always going to be potential for growth and there's always going to be ABEX uncertainty, how much confidence, how committed are you, I guess, to the 40% to 50% payout policy And it comes from a lens of, do we need to be worried that if we model 40 plus percent payouts, that we risk having downgrades to consensus expectations and upcoming results?

Yeah, it's a really good question, Sol. You know, for me, I'm trying to balance that opportunistic growth potential and, you know, what our FY26 expectations The board certainly hasn't walked away from 40% to 50%, but I've always maintained that discretion to make an adjustment if required. And one of the challenges that I face for this FY is we had the delay with the Equinox rig coming in, and then we had the floods pushing a lot of capital into this year. So I was looking to make sure that I protected the balance sheet and had an opportunity, if required, to utilise that extra cash if there was an unforeseen circumstance across our currently planned execution. And similarly, it just helps me give that balance to demonstrating that I have the financial strength to undertake an acquisition if required. You know, what we'll do is each year we'll look at the dividend policy or the capital framework and understand whether that still is critical for us moving forward At this point in time, the board is committed to that level. But, you know, we'll make sure that through our future plans that we get that balance. So, you know, I wouldn't... You know, obviously, it's a significant step up from where we were, and I'm pleased to be able to deliver it. But I'm just trying to make sure I balance our commitments this year with that market expectation.

Thanks, Mark. A question on the growth. Are there any new acreage releases at either a federal or state level that are likely to come up that you have a particular interest in, like which areas?

Yeah, so this acreage release is currently in South Australia that we're working, the team are working on. I've always had a small soft spot for CSG to get help for that length in their portfolio so we're looking through the acreage leases in Queensland around as well at the moment but at this point in time I really don't have anything more to add than that I'm sorry Saul.

Understood and just a quick last one just touching back on that re-contracting at the Cooper Basin contract the 40 TJs If I look, you know, on what we've got modeling here, the legacy pricing was well below $10. And when you would have contracted this, the forward curve was about $13. So that could be a potentially pretty big uplift, which if we carry forward is like over $0.10 or even $0.15 a share worth. How should we think about the potential pricing delta upside that we might see here? Or do we have to wait for the September results to get an idea of the quantum net?

Well, I'll try and lean into that a little bit. So you're correct. Before this contract rolled off, we were achieving for the volumes we recontracted south of $10 a gigajoule across the East Coast market. And what I tried to infer through the presentation is we've recently recontracted 40 terajoules effectively at the prevailing domestic gas prices. and that would be kind of in line circa with what you were implying. So I think most people will have a view on that, certainly not mid-teen levels, but not far below mid-teen levels in terms of pricing, and we expect that to be flowing through our results at the next quarter, but hopefully that gives you a bit of a steer, a real positive outcome for us in terms of rebasing our contract book.

Perfect. That's all from me. Thanks, Brett.

Thank you. Your next question comes from Henry Meyer from Goldman Sachs. Please go ahead.

Good morning, all. We've had another reserve downgrade in the Perth and Otway basins, which were flagged as being better understood in the last update. Are you confident that this will now be the last downgrade, at least for Otway? And for Waits here, we're calling out the 1p to 3p that would be better understood once production starts? Could you just step through what the key uncertainties you'll be keeping an eye out for there, please?

Yeah, maybe I'll start with Waitsea first. The good thing about Waitsea now that we've got the majority of the development wells in is we understand the in-place numbers really well. That is... And we've had independent assurance and audit across that The challenge is, you know, there is not a huge production history in the Wakefield, obviously. We have our history across the Irish, so we understand part of it, but Perth Basin seems to be constantly throwing up some challenges. One of the things across the Wakefield that seems different to Bahara Springs is we do have compartmentalisation across the broad Wakefield. So, you know, for me, it's how well does the wells sweep their compartments And ultimately, how many wells do we need to deliver 100% of the planned reserves? So we think we're in a really good place. We think we understand that well. And ultimately, production will realise that. We have three more wells planned to infill some areas where we believe that we would need to add some more wells. But we have ample wells to get to our full rates, and we have ample wells to get to some headroom through there. I feel confident for our delivery over the next few years that we have the well stock in place. So ultimately, and one of the good things about being onshore versus offshore, if we need to down space, there is always that opportunity because the cost base is smaller than the offshore. In the Otway, one of the challenges we have is that a lot of the wells behave very differently So I'm trying to take a much more cautious view in terms of the way we reflect our reserves there, because what we can see is across the different fields and reservoir components, we see different contributions of drive from water, and that requires different outcomes. So in the upcoming thylacine intervention campaign, we'll be shutting off some water to make sure that we can get access to additional volumes through there. But that's normal reservoir management. I'm obviously very disappointed with the Bahara Springs outcome. After Bahara Springs 1, it was observed as a risk because the field was behaving differently than what Waitsea was seeing in terms of partial communication between Bahara Springs 1 and Bahara Springs 2. So what we did is we drove forward to understand the booking at Bahara Springs 3 with the additional well. Pleasingly, we found gas there, but the disappointing part was it was in pressure communication. So what that means is the whole field is acting as one tank rather than three discrete fault blocks with all their own individual pressure cell. And ultimately, the drainage from Baharat Springs 1 has lowered the total field reserve. So what we've done is we've got simulation and we've got mass balance now that looks at Bahara Springs as one unified field. So I don't see any more risk at that particular field. And across our production in Otway, we've got a lot of wells in those now and understand those much better. I think one of the key things to reflect on, and I'm sure this is probably a concern, certainly has been for me over the last 12 months, is how confident can I be in the reserves given our recent history? We've now at a point where we're in excess of 80% of our 2P is in the developed category. So that significantly de-risked our kind of 2P undeveloped to 2P developed factor. And I think that was part of the challenges that we had a large volume of 2P undeveloped. But as we've gone and executed more program, we've now, you know, in the order of high 70% of our 2P undeveloped undeveloped is now to be developed. So we understand those volumes much better now and obviously I'm standing behind the numbers that we have put out in the market.

Okay, thanks Brett. And just to expand a bit on the Perth Basin, we've had part of the impairments last week associated with higher sustaining weight-sue costs. We talk a bit there about maybe needing more wells depending on how they perform to keep the plants Could you maybe just step through what scope is currently in plan to drill out REDBAC and TRIG and what scope and costs would be required to connect those up to the weights of your plant, whether we need extra compression or other infrastructure to get it there?

I'll let Emery start with that one and then I'll finish that one.

That's good. Thanks, Henry. So I guess, first of all, the cost increases that we've highlighted here relate to future development activities. The inlet compression project is obviously one that's within our future scope. Obviously, with cost inflation that we're experiencing at the moment, those cost estimates have gone up and we're obviously in the final stages of refining that project ahead of making a decision on that. We aren't planning to drill additional wells yet over and above what we've done for Waitsia. We do have, I think, three wells left to drill out as part of the current Waitsia portfolio. Those costs also, obviously, with cost escalation are looking to be a bit higher than the previous expectations on those as well. So it's really in relation to some of those future development activities that were already in the plan and the cost escalation that we're seeing on those. And I'll hand back to Brett in relation to the other fairways in the Perth.

Yeah, so don't get me wrong. I don't believe that we need to drill any more wells and wades here at the moment. I just meant That is a simple mitigation if we need to. We've got three more wells planned within the Waitsie Field, but they're always the subject of previous discussions. In terms of Redback Deep, that's a really interesting opportunity. Now, Bill is particularly excited about that area that's going to chase more volume. So we'll be looking through the seismic and the next phase of exploration to try and unlock more volumes through there. And as soon as that information is at hand, we'll be able to give you an update in terms of its development potential and its tieback through the field. We previously highlighted that we may do an interconnected program. That seems unlikely, so we'll strip that capital out of the forward-looking CAPEX. We'll just be focusing on inlet compression over the next period to make sure that we maximise our return on the well stock that we have in place.

Great. Okay. Thank you both. And just another, if I can, there's always a lot of uncertainty on decommissioning scope and cost, particularly as we move into actually starting work and may not understand exactly what's required. We've seen some cost increases for other projects over the last year or so. Just what's the confidence level on the decommissioning scope for the Yachtway and Bass campaign, and how could the cost in 27 and 28 compare to 26?

Yeah, so to start with the confidence, so we're just on our first well in that campaign and we fortunately saw cement all the way around the casing to the top level, you know, exceeded what we needed to have. So we can quickly and very simply get after and abandon that well. So that's performing much better than expectation, which is a really good sign, probably a credit to the previous operator actually at drilling that well well. and moving forward we'll look at each of those wells as they come up we've built quite a bit of contingency into our model given how offshore campaigns can turn we did lose in the order of 15 days at the start of this campaign with weather it's you know picking up the rig at this time of year is always a bit of a challenge but it looks like we're going to make up quite a bit of that time through the first abandonment we'll continue to look at this very closely. I'm pretty confident the Thylacine Geograph wells, which were drilled in similar times, hopefully shouldn't be too challenging for us. I think our more challenging wells come through the back end at the Bass Basin, which have a higher cost profile. But we've got all the material, we understand the engineering of those wells, and we'll be looking to punch through those as fast as we can. You know, some of the excellent work that companies like Amplitude did to get out of their program quickly and efficiently, we'll be looking at trying to emulate that type of performance and not stay on those locations too long.

And then just in relation to FY27 and FY28, in FY27-28, once we've finished this offshore campaign, we don't have any large-scale offshore abandonment activities planned until late this decade, early next decade, whenever Bass completes its field life. So it will really just be the small scale onshore abandonment that we do every year that you'll see in 27, 28. Obviously, there's always risk depending on, I guess, all the consortium partners in this campaign as to whether some of the FY26 campaign will spill out into 27, but we'll keep the market informed as we know that information.

Thanks, Wes. A very quick follow-up, if I can. The accounts note there's about a $250 million cost saving for completing scope in a campaign. Is any of that attributed to this campaign, or is that that future BAS or Taranaki scope?

Is that in there where we talk to the cost exposure that we have if we need to do full subsea abandonment, or is that...?

I think that's noted as cost savings assumed to complete scope within a campaign.

Yeah, so that's for future campaigns, Henry. So at this point in time, obviously, we know we've got a cost-sharing model under the consortium. So for future campaigns, we've obviously assumed that we'll be able to get synergies through bringing wealth together to do abandonments or doing them at the same time as other operators. And if we aren't able to achieve that, that additional cost will be realised through our estimates at that time.

The good thing about getting this... campaign done at the moment is these are really the only non-platform wells that we have to abandon. So moving forward, when we get to the end of BAS, which is probably looking like early next decade, now late this decade, probably more early next decade, the solution for abandonment is much simpler than the standalone kind of suspended exploration wells. Great, thank you.

Thank you. Your next question comes from Nick Burns from Jarden, Australia. Please go ahead.

Hi, Brett and Anne-Marie. Thanks for taking my question today. Maybe just keeping a focus on Otway first. Assuming the three whales, Hercules, Artisan and Labella are successful, can you just walk through the scope timing and production uplift you're expecting from those wells and including I guess cost as well for the connection of those wells back to the Otway gas plant and then just maybe if you can also just Brett you talked before about your increasing confidence in the reserve base as reserves move from undeveloped to developed obviously you've got Artisan and Labella there that you've inherited that you're looking to develop what's your view of the of the contingent resource that's been booked there and how confident are you around those reserves? Thanks.

Yeah, just so starting with reserves, artisans discovery, obviously single well field has a relatively wide range of reserve outcomes, but we've run the ruler post our recent campaigns and post things like enterprise to make sure that we're confident with the estimates and that it's been independently audited. So I feel comfortable with that. Labella too, we'll drill another well there. So we'll have another point in that field to understand what the scale truly is. I think we're well balanced in the middle in terms of where we sit. So I'm comfortable with the 2P number across Labella. Sorry, 2C across Labella, I should say. So that looks like it's something that we can move into reserves following that drilling. These fields are in the order of, you know, I'll give you kind of just a rough around that 50 BCF level. You know, for me, I want to chase opportunities that are larger in scale. I think one of the challenges with the offshore upway is this recycling capital that can go on. You know, it's not... it's expensive to drill and expensive to develop in the offshore way. Hence, opportunities like Hercules are the types of scale of opportunities that I personally believe is required to unlock value. You know, I know there's a few other operators. Certainly I could point you to ConocoPhillips that are chasing some bigger things outboard of us. With ConocoPhillips having success, we can see incredible synergies about bringing our molecules together and lowering the cost of our operations to connect things like artisan and labella through our Otway gas facility. So those opportunities are important. The labella and artisan, if we elect at the end of this campaign to drill them or to, sorry, connect them, I have a kind of a cost exposure in the order of $300 to $500 million each share, depending on how we connect them and what synergies there are. We haven't guided to that because we're still early in engineering, but I probably disclosed too much. But I just wanted to give you a sense of the scale of the capital for those connections.

That's really helpful. Thanks for that, Brett. And then I guess while we're on costs, Anne-Marie, you did mention the plan for inlet compression at Waites here. Do we have any sort of sense or rough range in terms of, I guess, costs for that as well?

I'll try and grab that one. So not yet. We've currently put a cost challenge across that asset with the operator and Glenn, who's done many of these projects in the past, has a very sharp pencil in terms of the way we think this can be driven. But I think we'll be in a good shape to describe that later this year through investor roadshow slash investor day type opportunities.

Yeah, that's a good point. So I guess at this stage, we've used sort of indicative operator estimates, but there's still quite a long way to go in Beech's view as to what those costs could look like. So once we get closer to a final decision, we'll be able to share that information.

Got it. Okay. Maybe just one more from me. Your five swap cargoes you completed in FY25 certainly contributed a lot of revenue to the business. Just the fact that weights here, it feels like it's unlikely to be fully ramped up until mid FY26, so we've probably got five or six months to go. Is there any scope for BEACH to look at additional swap cargoes in the next six months? Thanks.

Yeah, so we've delivered one swap cargo so far this FY. We're on track to deliver a second one and we'll be working with Mitsui to see how we can support additional moving forward. One of the critical things about the swap cargoes, it's very beneficial to the West Australian gas market. This is about customers who are currently taking gas where the gas price is currently subdued and they're looking to make sure that they've got protection late this decade, early next decade for their gas supply. So it's a very supportive engagement that we've had with the customers about utilising some of their gas today and giving them back that gas into the future. And I'm pleased to be able to support the Western Australian domestic market with that return volume. And we'll be looking, working with the regulator in Western Australia, the Northwest Shelf, as well as Mitsui, the operator, on delivering more value, creative optionality for our volumes.

That's great. Thanks, Brett.

Thank you. Your next question comes from Gordon Ramsey from RBC. Please go ahead.

Oh, thank you very much. I just want to ask about guidance on CapEx and expenditure over FY26. I think, Henry, you said CapEx guidance is $675 to $775 million. How much of that is drilling CapEx? And can you also comment on the FY26 guidance for restoration expense as well?

Thanks, Gordon. So I guess there's drilling capital within the sort of guidance that we've provided. There's drilling capex across both growth and sustaining. From a growth perspective, it's really the drilling across Hercules and Labella, which we've guided to previously, which is that 250 to 300 million of drilling in there in the growth side. And then you've got your regular sort of four rigs drilling in the Cooper Basin joint venture all year. with about 50 mil for drilling in the western flank as well. So there's a bit of drilling in FY26 which is exciting for us. In terms of abandonment expenditure, the guidance that we've put forward this year is 200 to 250 million. That's pretty much in line with the guidance that we put out in the Q3 quarterly results in terms of the Equinox campaign. There's only a small modest amount of onshore abandonment activity planned for FY26 as well. The abandonment guidance that we put forward covers the two wells in Otway and the three wells in the Bass Basin that we're abandoning. Obviously, the Bass being the heavier capital ones, as Brett mentioned earlier, and at 100% equity interest for those ones.

Thank you for that. I think Brett mentioned earlier there's quite a bit of contingency in the model for the drilling costs. Can you tell us what percentage that is, roughly, of the program?

It's roughly around 20%.

Okay. Well, that's good. Just another quick question relating to reserves. I'm sorry to harp on this because I know other analysts have raised it before. Just look at your annual report. Obviously, the big change in scope of 2P reserves has been power springs at deep. You've also lowered reserves, it looks like, in the outweigh. And I guess what I'm trying to get my head around is whether we're going to see more risk of that next year. And the reason I'm asking you that is that in FY24 you did highlight that pressures were declining faster than anticipated in the outweigh, and I just worried that that's going to lead to a further reserves downgrade. You can correct me on this if I'm wrong, but I think for this year the outweigh reduction was 2.6 million barrels of oil equivalent. And you're talking about a 20% reduction in production. So I'm worried that we're just going to see more next year. Can you just comment on that, please?

Yeah, so, yeah, $2.6 million was... We had lots of swings and roundabouts across the assets. We had some ups at Thylacine, a little bit of down at Thylacine West. We've seen a little bit further down at Enterprise. That effectively was equivalent to around $2.6 million down across those assets. And then we had approximately about a $2.7 million up across Bass. So... Offshore, we're kind of net neutral, really, in total reserves outcomes. You know, I just want to... Just on the 20%, I probably overstated in the quarterly. So we don't have a 20% production decline rate across our offshore assets. You know, natural field decline is much less than that. How you need to see through that number is Normal behaviour for our main contract offtake there, we achieved much higher production out of the Otway than we had done in previous years. So we just kind of rebased that to normal lifting behaviour, which will give an apparent reduction in production across the Otway, hence guiding to that 20%. So we have a plant shutdown. We have, you know, just assuming... more typical origin lifting behaviour, and then just the standard natural field decline across the asset. Each year we set our ACQ and we effectively have to set it at the kind of exit rate for the field to make sure that we can deliver 100% of that volume without any penalties. So, you know, I hate to use the word conservatism, particularly with regards to guidance. But I'm just very cautious that, you know, over the last five years, that lifting behavior is quite variable. And if we don't manage that, then I don't want to fail on the downside. It's the long and short of it, Gordon.

Okay, thanks, Brett. And just last question from me, just on Hercules. I think today you described it as moderate risk, and previously the companies called it moderate to high risk, why would it be high risk as opposed to moderate? Two seconds on how you're looking at that prospect.

Yeah, so it's probably just me in my loose use of language. It's a one in four chance, I think, is the answer, Gordon. You know, so I think some of the Otway campaigns that we've drilled in the past, you would put at more of that north of 50% chance of success in terms of amplitude support. Now this feature has amplitude support, but it's just not as strong as what we've seen in some of the other wells we've drilled and there's really good reason for that. The seismic quality there is different and there's some other factors, but in terms of some of the incredibly bright amplitude support that you can see across some of these assets, it's not quite fully there for for Hercules. So we think that we've got a really robust trap and it's material and it's scale and size and it's worth taking that risk to get that scale through the business. Now delivering scale through the offshore way gives you a plant full for a much longer period of time. It means you don't have to go and recycle capital. You can deliver that really strong rate of return and get that low operating cost story. So I'm really focused on that part of it. And then if we have success in Labella and we make a decision. We can integrate those developments. We can deliver significant volumes from 28, 29 onwards, getting that plant capacity up.

To summarize, you're saying you like the prospect. It doesn't quite light up, but everything else is pretty good.

That's right. That's exactly right. Good large-scale prospect. But it just doesn't have that intrinsic super bright amplitude that you see in others. It is amplitude supported. It's just not as bright as what we see in some of the offset fields. And it's possibly because of the scale and the quality of the seismic at that particular location.

Got it. Thank you.

Thank you. Your next question comes from Rob Coe from Morgan Stanley.

Please. Good morning. Yeah, thanks for the... Just two questions from me. The first one's a quick one with you, just looking at your debt disclosures. You've got 300-ish of maturities coming up. Can you just maybe give us a sense of what your refinancing is looking like there?

Yeah, thanks, Rob. Good morning. So we're in actually the final stages of that refinancing at the moment. We're expecting to close that in the next couple of weeks. We were oversubscribed again for that facility, which is really good for us. And we're also looking at extending the FY26 maturity as well. So we're well progressed with our refinancing at the moment.

Alrighty, sounds good. And then if I can ask a more longer range question on growth, some of the second and third horizon growth priorities from the strategy update included gas peakers, storage and CCS. And so just wondering if you've had any evolution of thinking on that. And then I guess New Zealand is now open for exploration. And just if you have any thoughts there.

Yeah, I'll start with the electricity strategy. So we came out in our strategic review highlighting this as an opportunity. So far, Fiona and the team have done a fantastic job setting up that opportunity. for us moving forward. I'm looking forward to taking the board through that in the next few months, in fact. But what we've been able to do is already at this point, I guess starting Ian, we see the strategy effectively having kind of three key steps. The first step is kind of exposing our molecules through other people's infrastructure. And that is a way to take gas that we could be normally putting to the spot market, but to expose it to the spark spread. And Fiona's been able to deliver a fantastic contract that gives us access to that spot market. But on those days where the electricity price is high through gas peaking, we take an uplift of value for that, supplying that into that market. So it's a, you know, effectively very low capex or no capex increment of our existing spot market arrangements. So I'm very excited and we'll be looking at doing more of those into the future. And then you have those kind of light CapEx solutions where we can participate with others, we can share their infrastructure and look at supplying or putting term through peaking to support that phase. And then finally, like the ultimate potential is the build and operate type model, which we're also looking at as well and deploying. Within South Australia, the government has been very progressive. They've started a new program called FIRM, and that's looking to build a gas capacity mechanism within South Australia. So we're looking at working through both the South Australian, Victorian and other markets to see how we can help support putting our molecules further to work. And, you know, in my perspective, the organisation with the molecules should be able to deliver the maximum value through the peaking. And you've seen the requirement for peaking to significantly increase year on year. And we see that looking forward further increasing. So that for me, really exciting opportunities to deploy our molecules and add uplifted value to that. In terms of New Zealand, yeah, I understand that the exploration potential is open. We look at New Zealand, and I think I'm still very concerned that the pendulum of political certainty can swing either way. So it's just a hard place for me to sit there and deploy shareholder capital. You know, Beach was intending to drill wells there in the past, and that got shut down through previous government changes. We need to be careful. And at the moment, I'm not looking at anything that is of the right risk profile for us to pursue. And fundamentally, my focus for growing the organisation is really a domestic play in Australia. We're looking at positioning better in the east coast of Australia as well as the west coast in Australia.

Okay, great. Thanks, Mr Wood. That's very clear. May I also just touch on storage, both gas and CO2? Yes, of course.

Yeah, so fortunately, the Cooper Basin for us has got an incredible storage opportunity. We have water blocks in areas outside of that as well that has potential for storage. We've pivoted away from Victorian offshore storage at the moment because until we can see a significant supply of CO2, We're not going to build it and wait for it to come. I think we need to see the market signals of CO2 aggregation in the Victoria market before we would sit there and deploy that. Across the Cooper Basin, I'm sure you've probably heard Santos say this a number of times, the ability for the Cooper Basin to store significant volumes of CO2 is absolutely there. The operator, Santos, has done a fantastic job in managing the reservoir and bringing that project online. And we see, as further CO2 becomes available, a great opportunity to expand CO2 storage across the Cooper base. And so there's really no risk about the storage potential across the broader Cooper. With all those fields, some of them already fully depleted, we have great opportunity to add new fields and keep growing our storage capacity across that asset.

Okay, great. Thank you so much.

Thank you. There are no further questions at this time. That does conclude our conference for today. Thank you for participating. You may now disconnect.