Beach Energy Limited

Thank you for standing by and welcome to the Beach Energy Limited FY26 half-year results. All participants are in a listen-only mode. There will be a presentation followed by a question and answer session. If you would like to ask a question, you'll need to press the star key followed by the number one on your telephone keypad. I would now like to hand the conference over to Mr Brett Woods, Managing Director and Chief Executive Officer. Please go ahead.

Thank you. Good morning everyone and welcome to Beach Energy's FY26 half-year results presentation. Joining me today is Anne-Marie Barbaro, our Chief Financial Officer. Together we'll take you through our half-year results and outlook for the remainder of FY26, before I open up the lines for Q&A. This morning I'm pleased to report a solid set of underlying results in what has been a very active first half across our core basins, with great progress made on delivery of some key milestones. This half, BEACH has continued to demonstrate great progress across our base business. through our strong operating discipline and outstanding safety and environmental performance. We end the half year in a strengthened financial position and are well placed to pursue growth. Slide 2 sets out the compliance statements, which I'll leave to read at your leisure. Slide 3 will begin, which highlights the key milestones achieved in the first half. Starting over in the west, first gas was achieved from the Wake Deer gas plant in early December, with the plant now in production ramp up. Two gas compressors have now been commissioned and the plant has reached peak rates of 165T today so far. The third compressor is expected to commence commissioning in the coming weeks and once ramped up we will deliver the plant's main bank capacity of 250T a day. Also on the Wake Deer front we listed four cargoes in the half, generating $233 million in revenue. Onshore in the Cooper Basin, the team were hard at work to restore operations from the severe flooding experienced in late FY25. I'm pleased to report that 97% of flood impact production has been brought back online at the end of the December quarter. This is a great outcome which will support our second half performance. We also welcome the Venture 101 rig into the western flank to commence our 12-well oil appraisal and development program. It's fantastic to have the active rig back in the western flank. which we'll talk through more in coming slides. Offshore, phase one of the Equinol 3 campaign was delivered, the drilling of the Heapleys Exploration Prospect, as well as safe completion of three offshore well abandonments across Otway and Bass Basins. Member CCS ticked over 12 months in operation, having safely stored over 1.5 million tonnes of CO2 since start-up. It was pleasing to see Moomba CCS meet the clean energy regulated strict compliance standards and each receive over 30,000 ACCUs per FY25. This puts BEACH well on track to achieve its target of 35% equity emissions intensity reduction by 2030. During the half, we also completed the refinancing of our 2025 and 2026 facility maturities. and secured a new $300 million in Asian term loan, lifting total available liquidity to $925 million. This positions Beach Wells to pursue growth and continue our crucial role of supporting national energy security. On the marketing front, Beach flooded more than 15 petajoules of gas into spot in short-term projects, driving a 13% increase in our realized gas prices for the half-year compared to the prior corresponding period. Turning now to slide four and our headline financial results. Our financial results for the half were solid in a period of major pressure delivery and flood recovery. This is the outcome of our team's discipline across operations and focused execution against our strategic objectives. Production of 9.5 million barrels of all equivalent was largely impacted by the 2025 Cooper Basin flood event. It is also worth calling out the positive performance of a production uplift in the prior corresponding period, providing a meaningful contribution to total production through continued success from our descaling initiatives. A great example of our potent mindset in action. Sales volumes have increased 3% to 12.7 million barrels all according, supported by a delivery of four LNG cargoes during the period. Successful delivery of gas marketing customer base, resulting in that 13% uplift in our realised gas prices to $11.80, which is over a 30% increase in realised gas prices over the past two years. This resulted in delivery of $1 billion in total revenue for the half year. These factors, combined with ongoing structural cost reductions achieved across our operated to deliver solid first half earnings with underlying EBITDA of $558 million and pre-growth free cash flow generation of $225 million. With a focus on prudent capital management and noting our dividend policy is a full year policy, today the board has declared an interim dividend of $0.01 per share with a step up in capital activity expected in the second half of FY26. which demonstrates our strong safety performance achievements for the half year. Notably, we've recorded no T1 or T2 process safety events during this period. We've also achieved over 12 months recordable injury-free at all our operated sites, which is an outstanding result and it credits all our staff in maintaining their dedication to safety through a period of heightened activity, including the commencement of the Equinox campaign over the winter period in offshore Victoria, as well as the recent commencement of all appraisal and development of trawling in the western flank. To put this safety result into context, beach activity has significantly increased half on half, with a 43% increase in man hours and field work complexity. For such a ramp-up to be achieved with no recordable injuries is a fantastic accomplishment, achieved through focus, execution, leadership and operating disciplines. Our team is dedicated to maintaining this disciplined flow as we recommence the Equinox campaign in offshore Victoria and deliver the Western Plain drilling campaigns in the second half of FY26. Turning now to slide 6, I was pleased to report the Waste and Joint Venture achieved the first gas milestone of the Waste and Gas Plan during December. Having now completed what is the most significant project in Beaches history, The wastage I mentioned experienced some minor operational issues in the early stages of ramp-up. However, with two compressors currently in operation, the plant has achieved its peak production rate to date of 165 terajoules a day. As the remaining compressors are identical, we will continue to work with the operator to ensure minimal disruption as we commission them in the third quarter and ramp-up towards our main plate capacity. I also wanted to take a moment to highlight the excellent work delivered through our commercial team with the operator, which saw us deliver another four LNG cargoes during the period, resulting in a total of 11 cargoes today and $740 million in revenue ahead of the Waits Your First gas. These cargoes were facilitated through a combination of gas from Ziris, plant production, gas time swaps, and purchase and listing arrangements with the Northwest Shelf. West Australian Government remains supportive of the WAX and joint venture achieving its agreed export volumes and the facility now affords a compelling pathway for Perth Basin Gas to market to Menton Beach in a strong position. Now cutting to slide 7 and the East Coast Gas Market. As we know, East Coast Gas supply is in steep decline with demand remaining strong over the longer term. It is important to highlight that current demand outlooks provided don't yet contemplate the material increase in demand expected from emerging industries, including data centres and AI. Over the last five years, Beech has invested over $2 billion in capital to develop new supply to the East Coast market. And for the first half of FY26, we supplied more than 18% of East Coast gas demand, delivering 100% of our production to domestic customers. Our gas marketing strategy and re-contracting efforts have diversified retailers gas-fired power generators and deliver an up-list in real-life gas prices of 30%. In late December, the government released its Gas Market Review Report, turning around a recommendation to develop a reservation policy model. We expect further consultation to commence shortly and culminate in legislative process in the first half of FY27. BEACH is supportive of a prospective domestic gas reservation policy. To be successful, however, It must be paired with streamlined approvals and other incentives to drive exploration and development. Domestic-only producers need to be prioritised, incentivised and not constrained in delivering new projects. Nor should we be impacted by pricing or regulatory constraints, as it is the domestic-focused companies like Beach, who are delivering the much-needed gas to Australian manufacturers, supporting and power generation, which in turn bolsters Australian jobs. While there is a lot of focus on supply from the north, there is also significant infrastructure, transport capacity constraints, which make the gas less attractive and higher costs. Opening up new plays, faster approval times and a fit-for-purpose fiscal setting in the southern basin must be a key outcome for the review. Best gas for the market is always going to be that which is produced closest to where it's used. Pleasingly, all relevant government the need for further exploration and development. Governments must stay focused on supporting upstream investment by domestic focus companies such as BEACH to ensure a balanced long-term solution for Australia's energy security. On the East Coast, we continue to invest in our core onshore and offshore assets, targeting new East Coast gas supply. Our operating facilities have been operating at over 99% reliability this past and provide us with the ability to leverage our existing infrastructure to support future market requirements. We have been busy offshore having safely completed phase one of the ECONOLDS campaign with a successful flood and abandonment of three legacy wells and the drilling of Hercules exploration prospect. As we announced through a quarter one result, the Hercules well was a moderate to high risk target and failed to intercept hydrocarbons. We're now waiting for the return of Equinox rig at the end of third quarter, when we kick off phase two of the offshore campaign with a well intervention at Thylacine West, followed by the drill and completion of Lavalla 2 development well and undertake the completion of Artisan 1. This will be followed by the final abandonment in the Bass Basin to complete the campaign towards the end of FY26. Looking forward, we are targeting FID on the Artisan and Lavalla connections in the second half of FY26. Both discoveries currently sit within our contingent resources. Subject to final investment decision, gas production will be targeted for FY29. We're also progressing the assessment of nearshore drilling and exploration opportunities. This will likely be a multi-world campaign drill from the enterprise pad and in a success phase tied into existing infrastructure. Onshore on the Cooper Basin, we're working closely with operator Santos to complete our active drilling campaign with four rigs drilling in the basin, roughly equating to 100 wells per year. Beaches' ongoing investment in new supply will be a key contributor to the east coast market in the medium to long term. Now turning to the western flank on slide nine. In December, we commenced our 12-well appraisal and development program targeting undeveloped reserves in the McKinley and Birkhead reservoirs. with the aim to add new production following a drilling hiatus I imposed over two years ago to enable Beech to refresh and deliver new drilling inventory. We've had early success in the Kalawonga field with the results of our first three development wells, and as of last Friday, Kalawonga 26 was brought online just 33 days from re-release, which is a real credit to the focused planning efficiencies achieved by the same. We have facilitated these rapid online times by pre-laying flowlines, utilising a fasted rig, and driving end-to-end synergies throughout the process. This significant improvement will see the next two wells, Hallamwood 24 and 25, be brought online within the next week. A very full-easing 100% success rate from our first six wells, which we look forward to continuing through the remainder of our appraisal and development program, the program aims remains on budget and most importantly, safely executed and continues to support possible future work programs. For our fit-for-purpose onshore rig is operating with 20% less manpower than its comparable rig in FY24 and a 60% reduction in beach personnel, a remarkable outcome for our beach team in conjunction with our contract partners delivering on our strict operating principles. On completion of the development and appraisal campaign, we will commence the 10 World Fall Exploration Programme, planned for late FY26 and carrying into FY27. The campaign forms part of our focus to rebuild 2PM2C resources across the Western Plain and secondly to refresh with a view to build high-quality inventory for future exploration campaigns. Turning now to slide 10 for a look at our second half priorities, On the west coast, production ramp-up for the waste and gas plant is our key priority, as the Operating Commission's third and fourth sales cap compresses in Q3 FY26 to bring the plant up towards name-plate capacity. Offshore, we look forward to commencing Phase 2 of the Equinox campaign with the Thalassine Well Intervention, drilling and completion of the Ovala II development well, and the undertaking of the completion at Ardison. In the Cooper Basin, we look forward to successfully drilling the remaining well in the oil development and appraisal campaign and kicking off our 10 oil well exploration campaign in the Western Flames, along with continued exploration, appraisal and development drilling in our non-operated Cooper Basin joint venture. On the marketing front, we'll continue to expand commercial marketing with industrial sector and gas power generators. And on that note, I'll hand over to Anne-Marie to discuss our financial performance.

Thank you Brett. Good morning all and thank you again for joining us today. Our headline financial metrics are set out on slide 12. Our first half results reflect solid performance as we made significant progress on flood recovery, delivered first gas at Waitsia and completed the first phase of the Equinox campaign in offshore Victoria during the period. Results for the half were underpinned by four Waitsia LNG cargoes, continued progress on structural cost reductions through our operated assets and delivery on our gas marketing strategy, which resulted in an increase in realised gas prices during the period. Earnings were impacted by lower production in the flood-impacted Cooper Basin and a softer bread price. Our average realised oil price was 12% lower compared to the prior corresponding period at Australian $110 per barrel, whilst average realised gas prices rose 13% to $11.80. Underlying EBITDA of $558 million and underlying MPAT of $219 million were down 5% and 8% respectively. Statutory earnings were impacted by the expensing of the unsuccessful Pennsylvania exploration well drilled during the half year, as well as costs associated with unutilised Northwest Shelf processing capacity. Slide 13 steps out movements in underlying MPAT. which, as mentioned, was 8% below the prior corresponding period. Sales revenue was largely in line at $982 million, with lower production and softer rent prices offset by two additional weight-fit LNG cargoes and strengthened gas prices. Higher cost of sales, including third-party purchases, tolling and inventory movements, facilitated the four weight-fit LNG cargoes listed during the half. Field operating costs were 8% lower than the prior corresponding periods, reflecting ongoing cost discipline across our operated assets. Notably, our operated assets delivered a unit operating cost of $10 per barrel of oil equivalent for the half year, reflecting that the operations within our control and over which we apply our strict operating principles continues to strengthen beaches-based business. Higher other income reflects a revaluation of the common-site overlooks liability recognised at the time we listed our one-off cargo at Waitsia in the first half of FY24. With a higher proportion now expected to be returning volume in the future, this reduces the cash settlement component, in addition to the foreign exchange gains made in the half. Slide 14 shows movements in cash during the year, which resulted in closing cash reserves of $235 million. Operating cash flow of $442 million includes around $1 billion in receipts from customers for the half and also includes $107 million in restoration payments, reflecting the delivery of three offshore abandonment wells during the period. Total payments for capital expenditure for the half was $377 million, reflecting Waitsier Stage 2 completion, drilling of the Hercules Well in offshore Victoria, ongoing drilling throughout the period at the Cooper Face and Drake Venture, and the commencement of our Western Flank Oil Development and Appraisal Campaign. Slide 15 reiterates Beech's strong financial position. We ended the half year with $925 million of available liquidity and have maintained our low leverage position, reflected through 12% net gearing reported at the end of the period. As Brett spoke to you earlier, we have announced an interim dividend of $0.01 per share, reflecting capital management discipline and to acknowledge the heightened capital activity and spend across optional Victoria and the Cooper Basin in the second half. As our dividend policy is an annual policy we will revisit this at the full year. On that note I'll hand back to Brett.

Thank you Anne-Marie. Now a look at what's coming up in the second half of FY26. Slide 17 sets out the FY26 guidance update. For production we maintain a guidance of between and 22.5 million barrels of oil equivalent. Our first-hour production performance has on track to deliver on line with our guidance. As mentioned throughout the quarterly, 97% of flood-impacted production has been restored across the Cooper Basin, with remaining impacted wells to come on line over the next quarter. Our off-way acreage continued performing strongly, with the off-way gas plant producing a close to 205T of main-flank capacity for extended periods during winter. The second half expectations back to a traditional nomination level. For capital expenditure, we maintain our guidance between $675 to $775 million, with no significant changes to the capital program discussed and guided at the four-year results. Key activities in the second half include phase two of the F103 campaign, continuing the Western Plain Fall Approval and Development Campaign, which will be followed by the 10 World Exploration Campaign and the commencement of NUMA central optimisation in the fifth base in joint venture, which is forecast to deliver significant operating and capital cost efficiency once completed. Regarding sustaining capital expenditure, we maintain our guidance of below our $450 million operating principle, which is a material reduction from recent years. I will now close out the presentation before we turn to Q&A. Our FY26 half-year results demonstrate continued progress and solid performance against our strategic objectives. We have strengthened our balance sheet and enabled us to invest in growth across our core hubs. We've delivered strong safety, operational and cost discipline across our operating assets. We've made significant progress on growth across our core hubs, including the successful commissioning of the WSIFS plant, which has now allowed progress through grant funds, successful completion of Phase 1 of the ECONOS campaign, ongoing drilling in the Cooper Basin Joint Venture and commencement of our all appraisal drilling in the western flank. And we've now delivered an uplift in gas pricing through effective commercial strategies during the period. We're carrying this momentum into the second half to execute and deliver on what will be an active period across our core east and west coast hubs. And on that note, I'll open up the line for Q&A.

Thank you. If you would like to ask a question, please press Star 1 on your telephone and wait for your name to be announced. If you would like to cancel your request, please press Star 2. If you are on a speakerphone, please pick up the handset to ask your question. Your first question today comes from Tom Allen from UBS. Please go ahead.

Good morning Brett, Anne-Marie and the broader team. So the interim dividend reflects a much lower payout of your pre-growth free cash flow than policy. implying that the board is prioritising building capacity to fund growth over dividends. So can you please clarify further how investors should interpret your current dividend policy? I think Emery just called out higher capex over the second half with some drilling spend. So are you saying that investors should not expect a strong payout of second half cash flows in the final dividend that would meet your policy over the full year?

I'll let Emery go with that one if you like.

Thanks Tom. So very similar to last year, obviously our dividend policy is over a full year basis and whilst we sort of have a good understanding of what activities we've got in the second half, we're being quite prudent for the first half of the payout to ensure that we can true this up at the full year. There has been currently no change to the dividend policy. We are still maintaining that policy. Obviously that does get revisited on a regular basis. But at this time, the payout sort of reflects more of a sort of balanced approach of prudent capital management for the second half activities levels.

Okay, thank you Anne-Marie. Beaches previously mentioned that management and the board are scouring the market for domestic growth opportunities in new long cycle projects that can help add some length to Beaches' remaining reserve life. Can you please clarify how investors should interpret the geographic breadth and the asset classes the beach are looking for and is the preference for greenfield developments or projects already generating cash flow?

Yes, cheers. Thanks Tom. I'll go to that. I think we don't really have a preference on whether it's greenfield or existing cash flow generating assets. I think that helps us manage our own cash flow. If, you know, my guidance would be if it was a greenfield-type opportunity, we would look to be able to manage that within our 25% gearing objectives. And if it had production elements to it, we'd probably think about maybe spending that to upwards of, say, 35% gearing, as long as the cash flow helps support de-gearing in a relatively quick basis. I think if you reflect on the lattice transaction, it was a very similar model to that market model. We have built a very strong balance sheet and we have capacity within the balance sheet, so we are very confident that we can utilise our balance sheet to deliver growth opportunities. In terms of preference, as indicated before and previously, certainly our main focus is across the east coast of Australia. We're not looking anywhere offshore. So whether it be opportunities that are emerging in Queensland, opportunities that are emerging in the southern markets, we're looking at opportunities such as that. But critically, it goes to your point, reserve growth, portfolio longevity are the objectives I'm looking at solving for. And, you know, we're going to be very prudent with our capital. very prudent with the opportunities we're looking at and continue to chase opportunities or look at opportunities that we see as TSRF-ready for shareholders.

Thanks, Brett. That's clear.

Thank you. Your next question comes from Adam Martin from E&P. Please go ahead.

Yeah, morning, Brett, Anne-Marie and team. Just a question on weights here. It looks January came in a bit lower than probably what people would have thought a few months back. You sort of touched on that. But how confident are you on the Feb-March uplift that you've got there in the PAC Slide 6? That looks encouraging. Just, yeah, just confidence there. Maybe you can talk through that, please.

Yeah, so what's inside the PAC Slide 6 is the operator's forecast that goes to the AMO website on a weekly basis. So what you can see from bringing the plant online to where we are today, we've got the two compressors online. We had that peak rate of 165 and we've had some minor operational issues and I can be more specific about them. It's mostly been cleanliness so we've had to do a lot of strainer swap outs and clean the front end of the plant and that's typical when you're commissioning to get the you know, dirt and debris at the front end through the plant. So, as the system cleans up, we'll see that production going to sustain. Over the next short period, our third and fourth compressions will be commissioned. So, you know, we're looking forward to seeing the outcomes of that over the next period, and that will drive us to full rate. So, we still guide to three to four months' worth Our ramp up schedule and the forecast that you see there is the operator's forecast is slightly more aggressive than that to achieve the first gas. In terms of my sense of it, every day gets better and better through the ongoing cleanliness work that we're doing through the plant. We've had a few minor vibration issues that have been rectified as well. So we continue to be seeing better and better performance every day through the operator.

Okay, good to see. And then the second question, just on the old way, I suppose the asset continues to sort of underperform versus the sort of upstream capacity, partly due to the contracts you've got. Where you're at in terms of, you know, are there opportunities there, whether it's, you know, partnering with companies in the basin or further exposure? You just talk us through that because... That's a real opportunity if you can get it right.

Yeah, we've got production capacity hit room at the plant at the moment and when the market calls for the gas, we can deliver up to the 205 capacity a day. So we're obviously constrained through nominations through the plant on a daily basis, particularly when the weather is mild or the sun is shining. In terms of our opportunities, what I'm particularly excited about is our Mearshore campaign that will extend from our enterprise well pay. That looks like a great opportunity to make sure that we've got additional well capacity later this decade as the existing well capacity starts to decline. And then also we have the finalising of the Otway offshore Equinox campaign. which will have a completion at Artisan and an intervention at SiloSingwest will add some more production, as well as the drilling of the LaBella II well, which gives us good optionality for connecting those again later this decade. In terms of opportunities outside and abroad, It's fantastic to see ConocoPhyllis have a great discovery with their Essinton opportunity and obviously our plan is well placed in support of that. Similarly, our friends next door at Amplitude look like they've got a very exciting drilling campaign coming up so we look forward to hopefully seeing some discoveries there and give the whole region a bit of optionality about where things can be developed and opportunities to move forward. So there's plenty of opportunities organically as well as inorganically in the region that we'll continue to observe and potentially pursue.

Okay, thank you. That's great.

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

Good morning, team. Just to follow up on weights here, the accounting treatment for all of the cargoes is getting quite complicated. So I'm hoping you can step through, I guess, first of all, when the volumes that have been over-lifted swaps or purchased will be returned, and then how revenue costs and cash flow will be recognised for those cargoes, please. I'll let Anne-Marie start with this one.

Thanks, Anne-Marie. I'll try to summarise it for you. So I think previously we've talked just sort of that rough So for the cargoes today, roughly 30% of those have been delivered through Xyrus gas production, with 70% of those cargoes being delivered through swaps and purchases. So effectively, at the moment, the profile is sort of based relatively evenly over the period to FY29 in terms of return of those volleys. I guess what I would notice, we have tried to, through the quarterly reports, articulate how much is purchased volumes. For those that we have paid a third party purchase, when we return those, we'll actually get sales revenue for that as a domestic gas price in the future. That's quite a simple high level overview of how that is being returned. When we go and produce that gas for return, either for the purchases or the swaps, obviously from a P&L perspective, you'll need to recognise the cost to produce those molecules for that. And obviously for a portion, there'll be no revenue. And then for a portion that we've articulated through the quarterlies, there will be a revenue component on that return.

Great. Okay. Thanks, Anne-Marie. I guess the post-basin has seen various reserve downgrades over the past few years, and the geology has been proven to be quite complex. Could you just share how production and pressure depletion has compared against original expectations, now that we're producing a bit more, and do you have enough data gathered yet to infer reserve estimates, or would we need to wait for the full-year process to come out in August?

Yeah, unfortunately it's still too early to comment on depletion across the field. What we're seeing is great capacity across wells. We've only got a few wells operating at the moment because we only need a few wells. So the delivery of those wells has been very strong. So as we bring on the other compressors, we'll bring on additional wells. And then as we trend towards full-year results, we'll start to see the pressure response across those wells to understand where we are. We feel pretty confident where we are at the moment. We're not seeing any red flags through that production. So it's all looking good at this point in time.

Great. Good to hear. Thanks, Brett.

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

Thank you for the result of the presentation today. My question relates to strategy, Brent, and it's more in line with the treatment of the Hercules exploration well in that you've expensed it and treated it as an abnormal item. And to quote the company, the projects scale any frequent nature of exploration activities in the rationale. That kind of implies to me that you're not looking at, the drill bit in terms of adding reserves, resources and reserves to grow the company, and you're leaning to M&A, the upsize of the debt facility by $300 million, can you explain if that's been solely done for your war chest for M&A and to grow the company and to buy actual projects and production assets instead of using the drill bit?

I think offshore Victoria, there's quite a few resources that are available and we are infrequently drilling exploration wells in that region. There's plenty of discovered resource and I expect there'll be more discovered resource coming up from the upcoming drilling to give us that optionality. So, you know, new discoveries, new additional discoveries for us past the Artisanal and Butler opportunities really only come to life for us mid-next decade. So we don't see that we need to invest significantly moving forward across exploration in the offshore, particularly given there's been great opportunities being discovered nearby. So I think we've got a good optionality to align with other joint ventures there to deliver long-stated value across the Otway. And we're obviously reflecting on the outcomes at Hercules to understand what our organic portfolio looks like as well. What I'm particularly excited with is our nearshore assets. They have relatively low risk in terms of their amplitude response. It can be connected through the enterprise wealth plan. So in terms of rates of return, they're very strong projects which will add additional volumes, additional organic volumes to our portfolio, so they make a lot of sense for me. I just want to be cautious about investing in offshore expensive exploration given any overhang around the East Coast gas market pressures, so we're making sure that whatever we chase can deliver sufficient margin to make sure that we get strong outcomes for all shareholders. And in terms of our facilities, you know, we had some maturities. We needed to just make sure that we recycle that. I wanted to have the capital available for our ongoing work. We have our opportunities across the Western Plain. We have opportunities, obviously, in offshore Victoria. and we're looking at how we can deploy that capital best in a disciplined manner. Obviously, I've been honest the whole time I've been in this organisation. I do see it's important for the beach to grow. We're certainly working very hard on our organic portfolio and how we grow within that, but ultimately, I think you can all be sure that some component of the M&A is required for us to give that longevity in the portfolio. But we'll only do that in a very disciplined approach. And I think the fact that I've been maintaining that so far is a demonstration of that. We've only just got Wageshare Online, and that was always a key metric for me to make sure that we delivered that to give us that line of sight of long-term cash flows in support of our strategy. So hopefully I've answered your question there Gordon.

No thanks for the answer. Just one more for me. Activities picking up at the western flank. You've got your 12 well appraisal development program followed by 10 exploration wells. What's your target in that program? Do you expect to actually grow production or are you just hopeful to limit the decline, pretty aggressive decline rate that we've seen from that area more recently?

I think the appraisal and development will do both. stop the decline and having 100% outcome of our wells drills there so far is good. We've seen some positivity in those results and I hope to see some growth as well. So we've still got six to go and I'm looking forward to getting those connected quickly and seeing the response of those wells. If you looked at slide nine, there's a colour, I think it's yellow, which represents some of the exploration targets we're chasing. what you would observe from that there are a little bit of step outs from some of the core areas that we've chased in the past again some really good technical work has gone on to unlock what we think is some pretty exciting opportunities there and that's supportive of scale so that's really about growing reserves and growing our future development portfolio of optionality so um with this this phase has really much been liquid focus we've also done a great piece of work about looking at our gas portfolio and how we can lean into the area around Middleton in future campaigns. So I'm really pleased where we've got to technically in understanding the Western Flank from the period a few years ago where our success rate fell circa that 10%. Now we're looking at an opportunity to unlock some volume. And, you know, my objective here in the Western Flank is to build at an asset base that is self-sustaining, that we can continue to keep maturing inventory as we drill and continue to get that good tickled yield because the Western flank does deliver a high yielding piece of business if we operate it effectively and that's really our objective is to get that balance right. And it's just a place of what the team has done in terms of doing it with less resources Getting a faster rig, our operational execution has been fantastic. I'm so proud of what the team is delivering out in the Western Plain.

Thank you, Brett.

Thank you. Your next question comes from Saul Lawrence-Kavodick from MST Marquis. Please go ahead.

Thank you, Brett and Anne-Marie. First question is just on weights here, assuming this is, you know, ramping up on target, are there any plans or need to do infill well drilling or another well campaign or some compression over the next 18 months? And is that likely, if it is true, is that likely to put any pressure on the $450 billion sustaining capex for FY27 and FY28?

So we always plan to drill another three development wells in the future. So they're planning to come in around the 27-28 timeline. So they effectively should deliver the 2P resources that are currently booked in the campaign. So we haven't had to look through infill drilling at this point in time. We are looking at an exploration campaign. Bill and the team have done a really good job on highlighting some other opportunities at scale within our existing portfolio that we may look to do again later this decade, probably on the back of that Development Well campaign. But in addition, you're correct, inlet compression has always been a part of the plan across the Perth Basin waste-seer assets. We would look to bring inlet compression online late this decade. The commencement of the inlet compression project is probably in the order of 12 to 18 months away, which will be ordering a large turbine in support of lowering the suction pressure through the field. the compartments across the field are effectively a depletion drive mostly and that enables us to recover additional resources. So, you know, inlet compression was always a plan and that is certainly – we're not moving away from that. It's not – we're not starting that at the moment. That's still some time away from commencement.

And is the cost of these things included within your $450 million sustaining annual capex guidance or would that be something in addition to that?

The wells are included within our sustaining guidance. We're just waiting to get the cost of the inlet compression, and I'll be able to update you with that in the future.

Understood. Thanks. And just coming back to Western Flank, When do you think you will be in a position to actually provide colour to market on what that sustaining rate might be? Because I think this is an asset which the market has risked quite severely and there could be some upside here once the market has some confidence on what a sustained rate and capital spend for it might be.

Yeah, that's a good question. I think what we'll have by the full year is effectively the rates and delivery of the development and appraisal campaign. But on the exploration campaign, we'll probably be somewhere about a quarter of the way through the exploration campaign. So the rig that we've got drilling the development campaign leaves us for several months and then it's coming back to do the exploration campaign. And I think on the back of the exploration campaign, you know, looking at some of those larger scale opportunities that we're chasing along there as well as some of those opportunities just along the board from fields such as Snatcha and Martlet and Growler. We will see what this new part of exploration campaigns can do and ultimately each of those discoveries have a lot of follow-up and that will give us a real good sense of where we are. So I don't expect to see a reserves write-up of any significance at full years but following the exploration campaign I think we'll get a a really good sense on what a standard sustaining business looks like in the Western Blank. Western Blank delivers great returns for us in terms of the money spent, you know, really, really high double digit rates of return across those opportunities. So for me it's about operational skill and execution and, you know, the time that we've given the subsurface team to kind of rebuild their inventory has been very important. And now we're going to test it, so testing it will come through this exploration campaign. We've acquired new seismic, we've done a lot of reprocessing, we've done a lot of very good technical work in support of the upcoming campaign and I think probably over this calendar year we'll be in a really good position to have a better understanding of what long-term longevity looks like across the oil part of the business. And then in the following year we'll probably be drilling some exploration wells around the gas infrastructure. and see what longevity looks like for our own gas infrastructure through that area.

Great. Thank you very much, Brett. That's all from me.

Cheers.

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

Just look back on Waitsia. Is there any update on Waitsia being allowed to export LNG beyond the current date of end CY28? And when will we know whether this is locked in?

Yeah, so the Premier of WA has given us this support, so we're still in negotiations with across the Northwest Shelf to secure processing at the right cost and we'll work on that over the upcoming period. So very confident in terms of the government support for us to continue to do that as being a good domestic player in Western Australia. We've got a lot of engagement with them on that. I think it's the final commercial part to the arrangement in terms of supply throughput and what the tolls look like is probably the final part of the equations before we can clearly tick that one off.

Got it. Just stepping back on Perth Basin, in terms of reserves, at end of FY25 your developed undeveloped reserve split on 2P is around 60% of the reserves there is classified as developed. So that's 40%. I'd imagine most of that is within weights here. You mentioned before about three more development wells and inlet compression. Will that investment get all the undeveloped toothier reserves at Waitsia into the developed category?

Yes, that's certainly the intent. The inlet compression is a large piece of that and then the three additional wells into parts that haven't been drilled at the moment should get that. Some of those wells will look at the responses of the current production wells to see if there's parts of compartmentalisation or not, whether those wells are needed, but at the moment it's in the base case assessment for the reserves.

Got it. Do we have any sense about the scale of that compression investment?

Yeah, well it's in the circa $100 million level. I'm pretty sure that's what I told you last time. That's the number that we're working towards.

Great, thank you. Maybe just one more quick one if I can. Just on Otway Basin, I was a little surprised that JV has yet to sanction the drilling of La Bella and the completion of Artisan, given you get the rig very shortly. Assuming that you do move ahead and drill and complete those wells, can you give us an indication about how much the connection cost for those wells will be? You talked about bringing them online in FY29. And then just beyond that, further offshore exploration drilling, it sounds like you're less enamoured with that now, Brett, and focusing more on nearshore, but I'm conscious you did have a commitment well offshore. I'm just wondering what's happened to that commitment well as well. Thank you.

Yeah, I'm sorry if I was confusing before. The joint venture is fully committed to drilling the Artisan Lavella wells. That's all lined up. So we'll be drilling Lavella 2 and completing. We'll be completing Artisan, which was already drilled, so that is already in track. What hasn't been sanctioned at this point in time is the final connections. So we're working with the operators adjacent to get the lowest priced connection solution that we can. With Hercules not being added to the program, I previously guided some numbers for the connections without the Hercules piece, we're probably talking more about the $300 to $400 level to get the connections done for Artisan Labella. We haven't made that final investment decision on whether we will connect but that should come towards the end of this half year. Got it. My challenge has always been in the offshore is unlocking scale. It's not cheap operating offshore in the away even with all the synergies we've delivered so far. So one of the great things about our position in the nearshore is we can deliver those with an onshore rig with effectively all available onshore kind of technology. So I look at a lot of those opportunities. They're very encouraging. We can manage with our balance sheet very easily. There's not any balance sheet stress that we need to put ourselves in under to unlock those. And I look at opportunities that are being discovered in the region as probably offering a better solution or a simpler solution for bringing additional gas over the facility. In terms of the exploration well, we had a different prospect, so we've effectively deferred that and looking for other things to do with that option in the RIG. We'll effectively deliver all our RIG days through our current program, so we don't believe there's an obligation to drill that subsequent well.

That's great. Thanks so much, Brett. Cheers.

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

Good morning, guys. A couple of quick ones. Just wait till your spot car goes. Is that a thing of the past now that you've got an inventory position to unwind and you're getting close to nameplate capacity?

Yeah, so I believe so, Dale. You know, we... We effectively have got ourselves to a point where we just get the next two compressors online and the project will be hopefully getting big rat tests in the not-too-distant future and then we'll be effectively fully commissioned and properly under the arrangements that we have across the joint venture. Our requirement to do further swaps or anything is massively diminished and so we'll unwind small localist position that we have at the end of the half and deliver our cargoes moving forward. The quicker I can get those two compressors online, the happier I'll be.

And then on page six of the slide deck where you're showing the weight to your gas ramp up, there's a gap between your nameplate and production. Does that mean we don't quite get to nameplate capacity? Is that an availability assumption or can you explain that to me please?

Yeah, so that's just running a line of guidance. So we've been effectively saying 90% of nameplate capacity is our number. So it's just being, again, conservative. And you will also see there's a shutdown in March. So we're currently working on that. That's probably going to be moved to align with the Northwest shutdown in the April period. So there's a few million pieces. The operators forecast ramp-up profile gets changed every week. It's not a static view. It's just the kind of... I know that you all look at the AMO reports. You message me about it a lot. So, you know, I thought I'd share that to see where we are versus what the operator had as their ramp-up profile. But, no, obviously my objective is to try and deliver better than that. And certainly we'll get... I expect that the shutdown in March will shift into April coincident with the Northwest Shell shutdown.

Okay. Just for clarity, is that 90% availability the operator's long-term assumption as well?

No, no. This is just for the first FY. You know, our gap plans. power gas plants are apparently across the highway and New Zealand are running at 99. So expectation would be we trend towards that high 90s level in the not too distant future. It's just being a bit conservative in the first year of production.

Okay, perfect. Thanks Greg.

Thank you. Your next question comes from Sarah Kerr from Argonaut. Please go ahead.

Good morning from Perth but I have a question about the Otway Basin. Our friends at 3D Energy had quite unexpected cost overruns with Equinox on their Two Well campaign. Is that of particular concern for you now that you've got the rig?

Not particularly. I think they had reservoir and pressure issues which we're not expecting to have at our drilling. We've used the Equinox rig for the Eccles Wells and the Three Abandonments and we had fantastic performance across that rig and even though we had to face material weather issues, we've been able to deliver those pieces of work effectively on budget. So I've actually been really pleased with the performance of the Equinox rig and pleased with our technical work to understand what we're drilling into and what that looks like. I expect us to continue to deliver as per our promise.

That's good to hear. Just one quick question. Just staying in Victoria, are you talking to any data centres? I think you mentioned that in one of the slides for direct gas sales or is it mostly the utilities that you're talking to?

Well, the heavy part of what we've done, we've moved from effectively having nearly two customers across the East Coast. So we've really diversified our gas buyers and we're starting to see quite a lot of interest from people who are trying to get support for things like data centres. I'm not sure if there's been a lot of government support for that at this present time but I can see a strong growing demand coming in that area. We're certainly supporting a lot of power producers in terms of their gas requirements and that seems to be a growing demand centre for us, which has been great. You know, very much aligned with our objective is to be able to play and to open up a lot of our gas into being uncontracted and that's given us a great opportunity to deliver improvements in our real life gas prices and another that I'm super proud of is we've delivered in the last two years a 30% increase in our real life gas prices and it's fundamentally been through the East Coast of Australia. And that's on the back of our gas strategy where we're not taking long-term commitments. We're kind of supporting the producers as and when they need it and we've been able to continue to chase value for our molecules. And I think that's super important as a domestic-only producer across the East Coast of Australia.

Great. Thank you so much.

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

Good morning. Congratulations on the results. So first question is in relation to the gas market review which you've called out some of the points on it and obviously a little bit to go before legislation. Can you talk about how that interacts with your growth aspiration and investment? Are there things that you want to see out of this review before you make decisions or the opportunities before you kind of enable you to make no regret type calls?

That's a really good question. I'll be transparent with you. I have some concerns about what the outcome could be for the first gas market review. So I'm engaging heavily in support of the domestic producers to get the right outcome for us. We would like to see that domestic producers are protected through particularly the winters in the southern markets, that we don't get some of the high margin periods in our sector taken away through allergy producers playing the arbitrage between the North Asian and southern markets at higher gas prices. That would be disappointing if that effectively opened up the opportunity for allergy producers to deliver higher value through the winters and the southern markets. We've been sitting there offering gas to the market representing nearly 18% in the last half of the domestic supply which has been critical. So we would expect to see strong support from the government for the domestic only producers. What I would also like to see is that we get our legislative change through so that we can make the approvals process and all the overhead that we have in trying to get opportunities up moving forward. So for me, the uncertainty about what the East Coast gas market could look like is very much at the heart of our strategy, delivering low cost and high margin businesses. So in terms of the opportunities I'm trying to chase, I'm trying to deliver those molecules that have fully in development and production costs in that $8 to $9 a gigajoule maximum level. If there is downward pressure on pricing that's come through an oversupply from Northern Gas, I want to make sure that Veach is in a good position to continue to deliver value for shareholders and TSR accretion by maintaining margin. And that's why I like the onshore part of the Otway, because it gives us that ability to manage costs, deliver low costs, but have molecules coming in at the right place. It's always going to be cheaper to have molecules developed close to where the demand centres are. So the Otway onshore certainly offers that and, you know, our offshore portfolio, because much of it's already been developed outside of the flowlines, we can deliver that at fairly good rates of return or strong rates of return, I should say. And moving forward in terms of our future development, we're looking at things probably slightly more leaning to onshore than offshore. that we can guarantee ourselves that we can maintain margin, i.e. deliver that all in costs at a competitive rate that we can, irrespective of what happens at East Coast Gas Review, we can deliver rates of return.

Great. Thank you so much. Okay. My second question relates to the abandonment expenditure and activities there. That kind of feels like that's going according to plan so far this year. I hope that that remains the case. Can you maybe comment on any learnings you've had from the process and implications that has for the future non-current provisions? And then maybe if there's any big-ticket items we should be bearing in mind over, say, FY27, FY28, please.

Yeah, so we set out to abandon five wells offshore. Normally on an annual basis, we kind of participate in about circa $20 to $30 million worth of standard abandonment, particularly across our onshore portfolios, and that seems to be a fairly regular and static number. So the offshore abandonments being effectively very episodic. We don't have any more offshore abandonments until next decade after we complete the next two wells. So I'm very pleased that we've been able to deliver the three wells so far as per our guided numbers in our accounts, and it really defends our position in terms of the cost at which we need to execute these offshore abandonments, so very pleasing. You know, I would have loved to have done some of them outside of the winter, and if there was a magic learning that I could have had, it would have been that the rig arrived about six months earlier than it did, so I could have got all that done without losing some winter days. Outside of that, I think the quality of the rig and the crew was exceptional. I've got to give hats off to Transocean. Also, I think the other part that's worked very well has been the consortium. We've been working very well with groups like Amplitude, Energy, Woodside and ConocoPhillips about sharing helicopters, sharing boats, sharing all the infrastructure. helps us deliver a fairly strong outcome in terms of cost. But, you know, for me, offshore execution is expensive and, you know, moving forward, we need to work in this consortium model and get the support to get these approvals quickly so we don't burn capital on, you know, five years' worth of approval delays, things like that, just a rogue value from all parties.

Great, thank you. Can I ask specifically for the future offshore activities that you highlighted, maybe next decade in the 30s, which projects are those? Are you able to help us with that?

Oh, no, sorry. What I was talking to is a BATS abandonment. So the YOLA field is probably online to commence decommissioning early next decade. So that would require a re-coming back around that lock timeline. We'll coincide that with the abandonments for the other major operators in the region to make sure we get the synergies through that. But a great outcome for us was the work we've done on increasing production out of the YOLA field through our interventions there with acid washing. and that's given us an uplift in production and turned that asset into something that's going to strongly be delivering for us until the end of this decade.

Yeah. Yeah. Great. Okay. I guess there's not much risk that you'll get a direction to decommission that early while it's still going, so that's good.

You know, BC's had no directions, so I'm really pleased with that.

Yeah, yeah. Excellent. Thank you so much.

Thank you. Your next question comes from Baden Moore from CITIC CLSA. Please go ahead.

Good morning Brett. Just in mind with your Western flank reinvestment, do you have an idea or a target in terms of your overall mix of oil and gas leverage going forward? Is there a medium term target you could talk to and how quickly you would like to get there? And just a follow on question from one of the capital management questions you answered Is it right you're still doing a broader capital management view of your business which includes the dividend policy?

I'll start with the end one first. Yeah, absolutely. I think working closely with the board on the dividend policy, we're looking at opportunities to grow the business and as a consequence, there may be some great opportunities ahead of us. So we're just looking at being very prudent with that and At this point in time, there was no requirement for us to make a change, so we thought it would be wise to offer a dividend to shareholders at this point in time. But we'll certainly be looking at, as we do all the science, moving into the four-year results to give a more fulsome update on where we are with our capital management. Sorry, what was the other part of the question?

Just in terms of your mix around oil versus gas leverage, just with the East Coast market moving around a little bit, I guess, and you're reinvesting pretty heavily into the Western flank, do you have an idea in terms of weighting into oil production in your portfolio and how quickly you'd like to get there? And a small follow-on as well, we've got a review on the safeguard mechanism coming up as well. have any hopes out of the expansion or what you might be looking for?

Yeah, I think for us, across the Western Flank, we like to see that liquid yield. That liquid yield helps lower our overall costs across the basin and that protects margins. So the more liquids we can get in the Western Flank, the better. I would be happy with liquids in other basins as well but our predominant focus really is is gas on the East Coast and gas on the West Coast. That is... So we haven't really got an internal solver equation for what proportion of our portfolio is liquid. You know, we recently entered an AMI with Omega and TriStar for an opportunity in Queensland called the Turin Basin, and hopefully there's a decision on that over the next few weeks But opportunities like that that have liquids associated with them can help you lower your cost of your combined product and as a consequence can deliver you potentially a lower cost gas delivered. So a bit like Henry, you know, why is Henry Hub so cheap? All the associated liquids in the United States help deliver a lower cost of gas. Australia doesn't have that benefit from many basins but opportunities such as the Western and potentially opportunities in Western Australia do have liquids. So we look at those and look at those quite carefully to see which ones can add value. But, you know, to answer your question properly, our real focus is gas, gas on the East Coast, and gas through our plant in Western Australia across the West Coast.

And any expectations out of the Safeguard review?

Gosh, well... I would like the safeguard review to be considerate of where we are as a country in terms of our manufacturing. You know, I would hope that the government would be a bit, given where we are in inflation and given where we are as an economy, that we can kind of effectively leave the safeguard mechanism where it is. But I know that's not where the government's trending. So fortunately we've done more than we need to with our member CCOs project to give us plenty of headroom. So at the moment our priority is investment in traditional oil and gas to deliver gas to the market because gas is one of the best things to decarbonise. So getting recognition for that I think would be important. That would be a great outcome for the safeguards review.

Thank you. Thank you. Your next question comes from Declan Bonick from Euros Heartleaf. Please go ahead.

Good morning, Brett and Anne-Marie. So you mentioned no current cut to the dividend policies planned. If you don't execute M&A in the next six months, do you see that second half dividend lifting to hit that 40-50% power ratio?

We'll address that at the full years. Certainly, I'm not going to do a deal for deals date, so we're going to be very prudent with our capital management. And if opportunities don't eventuate, well, then the board will obviously look at opportunities to return value to shareholders. I think that's something that I've always said, that that is part of our agenda. It's, you know, we'll only do things that are truly TSR accrued. If not, we'll look at returning capital. That's, you know, that would be certainly top of mind for myself and for the board.

Excellent. Thanks. Look forward to the second half.

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