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 half-year results presentation. Joining me today is Anne-Marie Barbaro, our Chief Financial Officer. Together, we will take you through our half-year results and provide an update on the outlook for the remainder of FY25 before we open up the Q&A. Before I begin, I'd like to acknowledge the hard work and dedication of the entire BEACH team. You'll recall that we announced our strategic review towards the end of last financial year, and since then we've been extremely busy with the organisational reset and implementing a range of strategic initiatives while keeping focused on safe delivery of operations and major projects. Today is pleasing to announce a set of results which reflects initial outcomes from that strategic review. I believe the results demonstrate good, solid progress and early signs of what is ahead for beach. Production growth, cost reductions and increases in earnings, cash flow and dividends are key themes for today. Importantly, we have achieved these results with outstanding safety and environmental performance. Slide two sets out our compliance statements, which I'll leave for you to read at your leisure. Slide three lists the key milestones for the first half. The organisational elements of the strategic review have been completed. The business has been restructured and we achieved our target 30% headcount reduction. In fact, we've exceeded that target and currently have 32% less headcount than at our peak last year. The appointment of my executive leadership team is also complete and I'm glad that many of you got to meet them during the Wayseer site visit in December. It is great to see the vigour in which the ExCo are chasing down opportunities in implementing our strategic initiatives. In the field, this half saw completion of two major projects and progress on waste here. Successful connection to the thylacine west wells and completed the offshore hot wave program and commissioning and ramp up of Moomba CCS completed the slammer commission's reduction project. I'll talk to our major projects in more detail shortly. Another great outcome was success we had in the Bass Basin with our wellboard descaling initiatives. We first trialled this at YOLA 6, which greatly improved gas flow, and subsequently followed it up with two other producing YOLA wells. This is a low-cost initiative at roughly $60,000 per well, which has delivered a material uplift in production. This past week, we've averaged over 25 terajoules a day of sales gas production, which compares to around 9 terajoules a day last financial year. This additional gas is going into the spot market to help ease current East Coast supply constraints. This is a great example of our operating philosophy for non-core assets. Our selective capital investment in this instance has delivered material value uplift. Turning to slide four and our headline financial results. This half we recorded an uplift across all key metrics, which, as I mentioned, is a solid outcome following on from our strategic review. Production was up 15% from the prior corresponding period. In the Otway Basin, we saw more than doubling of production from higher take-or-pay arrangements and increased well-deliverability following connection of Enterprise and Thylacine West. The Bass Basin also provided a meaningful contribution to growth thanks to the descaling initiatives. On the earning front, in addition to stronger production, the great work done by our commercial team and the Waitsea Joint Venture partner Mitsui in securing gas swaps for early energy cargos contributed to revenue growth. Two beach LNG cargoes were listed in the first half and delivered $139 million of revenue and supported 5% increase in total sales revenue to approximately $1 billion. Reductions in costs, including a 20% reduction in unit field operating costs, also underpinned our results. These factors combined to drive a 20% increase in the underlying EBITDA to $587 million and a 37% increase in underlying impact to $237 million. With high production, revenue and earnings, our cash flow and liquidity position strengthened. Liquidity increased to $631 million, net gearing reduced to 10%, and pre-growth free cash flow increased tenfold to $431 million. In recognition of first half performance, the Board has declared a $0.03 per share fully franked interim dividend. Whilst our free cash flow for the first half of FY25 has been strong, We've taken a balanced approach on the interim dividend to recognise the seasonality of gas demand on the East Coast, as well as the upcoming offshore abandonment activities that will be kicking off in the second half of FY25 as part of the Equinox campaign. Turning to slide five, which shows our continued solid outcomes across safety and environmental performance. We again recorded no tier one or tier two process safety events and no environmental spills of more than one barrel. Unfortunately, over Christmas, We had one recordable injury, which ended our record 12-month run of being recordable injury-free. An employee's hand was pinched in a pulley during maintenance activity. He has fully recovered and is as expected, and we're implementing measures to prevent such incidents in the future. We are fully committed to a safety and well-being culture, pursuing continual improvement in Beach's business. On slide six, We show the key highlights from our offshore Otway Basin development program and movement CCS project, both of which were completed during the half. In the Otway Basin, the six-well development program concluded with the connection of Thylacine West 1 and 2. The Thylacine West wells have performed in line with expectations since coming online. BEACH has invested in the Otway Basin to restore well deliverability for the Otway gas plant and bring much-needed new gas to the East Coast market. It is great to see the plant operating at high rates and knowing that we have additional gas available for the market when our customer needs it. On the emissions front, I was in the Cooper Basin last week with our joint venture partner, Santos, along with the Premier of South Australia, Peter Malinowskis, and the Minister for Energy and Mining, Tom Kitsantonis, to tour our member CCS facility. The committing process and ramp-up of CO2 injection well exceeded our expectations, which is an absolute credit to the project teams. At capacity injection rates, the emissions reduction delivered by Murmur CCS is equivalent to taking roughly 700,000 petrol cars off the roads each year. So we're making a real contribution to Australia's emissions reduction journey. The success of Murmur CCS strikes a telling blow to the Naysayers who are choosing anti-gas ideology over science. Turning now to Waits here on slide seven. The key milestones of mechanical completion being construction of the plant, was achieved during the first half, and the completion of the phase two development drilling scope is now done. We are now in full final commissioning phase and continue to target first sales gas from the plant in the first quarter FY25. In December, we announced some quality issues at the valve station for the Zyrus to wait to see a flow line. Most of the valve rectification works have now been completed. However, there are still some components which we're expecting delivery this month. mid this month. While this delayed the introduction of Xyros fuel gas into the plant to support commissioning activities, we've maintained our first sales gas target. In conjunction with the operator Mitsui, we have established plans to introduce temporary power and hot water supply to progress critical commissioning such as the Amin Tower. This would previously only been undertaken once Xyros fuel gas was introduced to the plant, de-risking the schedule. Beach now has in excess of 20 senior professionals seconded into the commissioning team to support Mitsui. Mitsui is operators controlling the commissioning schedule and activities, with club personnel taking direction from Mitsui now. We acknowledge the frustration and length of the delivery time for this project. Beach is now operating and doing what it can to support this process. Despite the challenges, a real positive has been our ability to do a gas fire time swaps to fill early LNG cargoes. In addition to the two cargos in FY24, Beech lifted another two cargos this half and has delivered $293 million in revenue at a healthy average price of over $18 Aussie per MMBTU. These gas swaps have been a great initiative with key advantages being bringing forward revenue and cash flow, which would otherwise have been dependent on Waitsia plant startup, benefiting from strong commodity pricing and the pricing inherent in Beech's LNG contracts, Utilisation of committed processing costs at the north-west shelf, which are repayable regardless whether volumes are supplied or not. And the strengthening of our financial position thanks to significant cash contribution from these cargoes. With four cargoes listed today and a fifth in January, the material contribution weight simplified once running at full rates is now evident. Holding all-outs constant and ignoring factors such as de-bottlenecking upside We would expect eight to 10 Beach LNG cargoes per year. Now turning to slide eight for a quick look at our second half focus. Commissioning the Waitsia gas plant is clearly a priority. And though we're not operating Waitsia Joint Venture, Beach will continue to deliver support to Mitsui in bringing the plant online. In the Perth Basin, we have also some exciting drilling coming up. The Ariana gas exploration hole will be drilled from the L1 permit meaning any discovered volumes could be directed to the Wadesea Export Licence. Bahara Springs Deep Free Development Well aims to convert undeveloped 2p reserves and will help inform future development plans for that field. Two other important work programs will commence this half. First, we've been planning the next phase of the offshore Victoria activity for some time and will soon commence that program. I will take you through that campaign in more detail shortly. But in the fourth quarter, we aim to plug and abandon two wells and drill one exploration well in the offshore railway. In the western flank, we have a 10-well oil development and appraisal campaign ready to go, with rig negotiations entering their final stages. I'll provide detail on both of these programs after we hear from Anne-Marie on our financial plans.

Thanks, Brett. Good morning, all, and thank you again for joining us today. Our headline financial metrics are set out on slide 10. As Brett mentioned, our results for the first half of FY25 reflect good progress towards our strategic review initiatives. Production and sales volumes were up 15% and 12%, respectively, which underpin growth in earnings and cash flow. Underlying EBITDA was up 20% to $587 million, underlying NPAT up 37% to $237 million, and operating cash flow up 88% to $659 million. While we recorded two weightsier LNG swap cargos, our revenue mix rotated from liquids to gas thanks to a more than doubling of production from the Otway Basin and a 67% increase from the Bass Basin. For the half, liquids accounted for 55% of sales revenue and gas accounted for 45%. For reference, in the prior corresponding period, the split was 67% liquids and 33% gas. Also of note is the 18% increase in our average realised gas price to $10.50 per gigajoule. This partly reflects the tightening market, which we've long anticipated, as well as our strategy to expose more of our gas to spot and shorter-term pricing. Repricing of the Otway and Cooper Basin GSAs and the new Enterprise GSA also contributed to stronger realised prices. Slide 11 steps out our underlying NPAT, which, as mentioned, was 37% above the prior corresponding period. Strong revenues for the half were largely driven by an uplift in production in our Victorian offshore gas assets, which Brett outlined earlier, and LNG revenues. Lower cash costs contributed to earnings growth, with a reduction in field operating costs driven by cost-out initiatives, which are progressing well, and lower third-party LNG purchases recorded. partially offsetting these reductions with higher northwest shelf LNG tolling charges, as well as a result of additional LNG cargo this half. Slide 12 shows movement in cash during the financial year, which resulted in closing cash reserves of $251 million. Operating cash flow of $659 million was 88% above the prior corresponding period, thanks to higher production, weightier LNG swap cargos and cost-out initiatives. Lower income tax payment and lower financing costs as a result of lower dawn debt also contributed to higher operating cash flow. Cash capital expenditure of $413 million was materially below the $603 million recorded in the prior corresponding period. Cash outflows from growth activities reduced from $298 million to $191 million through completion of some of our major projects while cash outflows from sustaining expenditure reduced from $305 million to $222 million. Sustaining capital expenditure is on track to hit our FY25 target of less than $450 million. This will be achieved through a number of activities, including our cost out programs and work program optimizations. On slide 13, you'll see a much improved financial position. Higher free cash flow generation during the half saw us pay down $115 million of debt and end the period with net debt of $389 million, net gearing of 10% and available liquidity of $631 million. In recognition of the half-year results and strong cash flow generation, the Board declared a $0.03 per share fully franked interim dividend. This is a 50% increase from the prior dividend and marks the first step in Beecher's journey towards paying higher sustainable dividends. It should be noted that if you apply our capital management framework and dividend policy to the first half's pre-growth free cash flow of $431 million, you'll arrive at a dividend that is higher than $0.03 that we've declared. Our policy is applied over a full year free cash flow, and we're taking a prudent approach to the interim dividend, noting that in the second half of FY25, we'll be conducting abandonment in offshore Victoria and commencing our western flank development drilling. Our aim is to deliver sustainable long-term dividend growth. I'll close by reiterating that Beech is in a strong financial position as reflected through our strong results for the first half of FY25. This allows us to maintain flexibility as we balance investment in growth while sustainably increasing our dividends to shareholders. On that note, I'll hand back to Brett.

Thank you, Anne-Marie. Now, looking more at the outlook for the remainder of FY25 and beyond. Slide 16 sets out our production and capital expenditure guidance for FY25. We have narrowed what was wide production guidance range of 17.5 to 21.5 million barrels of oil equivalent to 18.5 to 20.5 million barrels of oil equivalent. With first gas from Waitasea now expected in the fourth quarter, we will no longer be able to achieve the top end of the original guidance range. However, solid nomination in the Otway Basin, strong reservoir performance in the Western Plank, and a marked improvement in the Bass Basin in the first has given us confidence to also lift the bottom end. Key assumptions by basin are noted on the slide. It is worth pointing out that despite a high Otway Basin take or pay volume set for calendar 25, we have chosen to remain prudent with our guidance and assume 150 terajoules a day on average throughout the year. Other assumptions remain relatively constant. with the exception of a much improved outlook for the Bass Basin. The capital expenditure we're tracking to our original guidance and thus made no change to the $700 to $800 million. The second half of the year we will see some additional spend on the Western flank drilling campaign and the Otway Basin exploration well. It is important to know that abandonment activity is not included within this capital expenditure guidance and I will touch on our abandonment campaign shortly. Progress against our FY25 targets is set out in slide 17. As Anne-Marie mentioned, we have made great strides in driving costs out of the business, which is reflected in field operating costs and sustaining capital expenditure. For the first half, we've achieved a 20% reduction from the prior corresponding period in field operating costs on a per BOE basis. This puts us well on track to achieve our FY25 target. Our sustaining capital expenditure reduced materially and is also on track to achieve our FY25 target. For our free cash flow breakeven oil price, the additional cash flow from the high-margin White Sea LNG swap cargoes has reduced that figure to close to zero for the first half. We are well on track to achieve our full-year FY25 target. Turning now to an important work program, which will commence in this half, the Harsh Environment Semi-Submersible Transocean Equinox Rig will soon be mobilising to offshore Victoria allowing us to commence our next phase of offshore Victoria activity. The Equinox rig campaign will kick off activity for the offshore gas Victoria project, which I've been planning for some time. The Equinox rig has been contracted as a part of consortium with three other operators for a total of 380 days, plus options to extend if required. Beech's share of the rig campaign is roughly 240 days, which will allow us to undertake a comprehensive program of drilling, abandonment and intervention activities. The Equinox rig campaign is expected to include a range of activities. We will drill the Hercules Exploration Well and complete it in a success case. The Hercules prospect is a large-scale opportunity which aligns with our inorganic growth strategy. We plan to drill and complete the La Bella II Development Well. This follows our unsuccessful efforts to farm down the Mavis Exploration Well, and a decision not to progress that opportunity to 100% equity. Lavella was previously considered borderline from an economics perspective. However, with the regional and alternative development pathways assessed, the project is modelled to have the potential to meet our required investment hurdles. The previously discovered artisan field will be completed, with the potential for well intervention at Thylacine to optimise production performance. And lastly, we'll be abandoning five suspended wells, two in the Otway Basin and three in the Bass Basin. These activities will position us to undertake a program of subsea developments and connection of wells to the Otway Gas Plant with a view of achieving first gas in calendar year 2028. We expect to start the first phase of activity in the fourth quarter of FY25. This will include the two Otway Basin well abandonments and the Hercules Exploration Wells. For FY25, capital spend of $40 to $45 million for the Hercules drill is included in our guidance. For the two abandonments, $40 to $45 million of restoration expenditure is expected to be incurred and, as mentioned previously, is excluded from FY25 guidance. After this activity, we'll have a break while other operators utilise a rig. We therefore expect to recommence work program from mid-FY26 where we plan to draw the Labella 2 well, do completions at Artisan and Labella, and conduct abandonment of three wells in the Bass Basin. Further details on this part of the program and related expenditure will be provided later this year. It should be noted that all activity is subject to various regulatory approvals, including environmental approvals. Slide 19 provides a bit more detail on the Hercules glass exploration well. This is a large prospect with an assessed mean size of well over 100 BCF, which, if successful, could extend production at the Otway gas plant for many years. The prospect is just south of the Artisan Discovery, and we are targeting the same Morris Sea Reservoir within a three-way fault-bounded structure. It has seismic amplitude support, which has proven to be a key part of past exploration tests in the Otway Basin. If the Equinox remobilisation and the drilling of Hercules progress is planned, we'll look forward to sharing the outcomes with you before the end of this financial year. A quick wrap up before we begin the Q&A. I trust you agree that today's results demonstrate good progress against our strategic review initiatives. It is certainly pleasing to report the completion of the two major projects. Structural costs out being taken out of business, growth in production and earnings, and a higher dividend reflecting stronger cash flow generation and financial position. There is still, however, much work to be done. A key priority is clearly the Waitseer gas plant and navigating the final commissioning stage with the operator Mitsui. As our early LNG swap cargoes have demonstrated, once the plant is online and fully delivering, Waitseer will provide a change in earnings and cash flow. With activity ramping up in our operated acreage across the offshore highway basin and western flank, we will be continuing our diligent focus on safety and environment as we deliver these important programs. We look forward to providing updates as these activities progress. With our progress from the first half, and in particular commissioning of member CCS, BEACH continues to play an increasingly important role in Australia's gas supported energy transition. Our existing infrastructure and acreage positions and established presence in the East and West Coast markets underpin our value proposition. We will now open up the lines for some 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 Tom Allen with UBS. Please go ahead.

Good morning, Brett, Anne-Marie and the broader team. Given the first half free cash flow and the balance sheet are in good shape, can you please update on how Beach will preference the need to allocate capital to growth to support your reserve base and your medium-term production profile versus returning cash to shareholders over the next 12 months from here?

So obviously, when we get to our full year results, we'll be looking very closely at our expenditure and making sure that we fit to our dividend and capital management policy. We've got capital to be spent through the Otway Basin campaign, which I'm really looking forward to seeing the outcomes of that. So I think we've got a very balanced view about how we and maybe positive, partly conservative view about how we're going to manage our cash flows over the year. I'm really pleased in the position of the balance sheet. And I think we've got a great optionality to do both, which is invest in maintaining our strong production position, as well as giving progressive dividends and sustained dividends to shareholders.

And is the focus, Brett, still, as you commented before, that any allocation or meaningful allocation to growth wouldn't be until the end of fourth quarter, fiscal 25, when the Waitsey gas plant is up and running? Or if the opportunity came about, could we see a move earlier?

It's a really good question. You know, I'm really pleased with the business here in terms of its operating discipline and what we've been able to do to our business. You know, I think we talked previously about earning the right to grow and, you know, it's it's not for me to judge, but I feel more confident that I've got an organisation and leadership team that can facilitate growth. And as opportunities arise, we'll certainly look at hard at those things that make the most sense.

Okay, thanks. And then finally, it feels like the Hercules exploration world is an important one for Beach. Can you please clarify that if Hercules returns a sub-commercial outcome, What happens to artisan gas and how will you think about future drilling plans and investment in growth in the Otway?

Yeah, so in the event Hercules doesn't work, we would still look to bring artisan online. There's some other operators executing program in the region, even our board of us, which has got some good synergies with our plants. and potential to grow the value through our infrastructure. So we're looking at how we work with and alongside those parties to maximise value. So continue to work that program. Thanks Brett. Cheers.

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

Yeah, morning, Brett Emery. Just back on the dividend, it looks like something like 16%, 18% you've paid of sort of pre-growth free cash flow. Just to confirm, in the second half, assuming weight is up and running as expected, would you do the second half at somewhere between that 40% to 50% on a full-year basis? So we're going to see a big top-up, or just trying to understand that, please?

Yeah, I think the dividend, or the capital management policy, has always kind of been written about a full-year dividend. So, you know, I think we'll have a very hard look at what the impacts are from the rest of this year, you know, which I don't think Weixi would preclude a change to the dividend at full years. So I don't think we're hanging on that. We've delivered significant value through swaps. But I think both getting past some of the abandonment capital and having the exploration world drilled just gives me the confidence to, you know, deliver what I want to be as a sustained dividend. So, you know, our ambition is to get that, to deliver that 40% to 50% of pre-growth FCF as dividend. That hasn't changed. We've just got to get there and manage the balance sheet in a prudent fashion.

Yeah. Okay. That makes sense. And then just in terms of these swap cargoes, clearly you need to return some of that gas, so that will come out of weights for your production. I mean, we're assuming some cargoes 26, some cargoes 27, but just give us a sense of how quickly you need to return those cargoes, please.

Yeah, so we've given a little bit of colour in the pack about, of the swap LNG cargoes so far, 35% of that gas has come from our own production, so we don't need to swap that back. So of the swap cargoes, effectively 65% come as time swaps. And if you think about our existing LNG licence, effectively the best way to describe it is fairly even distribution of cargoes each year. So we've got this expectation or one of the plants that normal operating capacity, we should be getting between 8 and 10 LNG cargoes a year. So if you take effectively what the gas we've delivered, you can see relatively modest impact over those years progressively on a fairly even basis.

Okay. And just final question, a material portion of the Cooper Basin is going to get recontracted. Where you're at in those negotiations, I think it's around July, sort of Repricing, is that going to origin somewhere else? Is that going to be short-term, long-term deal? Just a bit more coal there, please.

Yeah, I'm really pleased to say that we've been able to achieve great progress on some short-term transactions, and you see that through our average realised gas prices. That's heading in the right direction. We have done a couple of minor gas sales moving forward, really well-priced, but I'm just being very cautious of going too hard too early. Origin is certainly interested. I think other parties, we've got a lot of parties that are interested in that gas. And I'm just trying to play that as carefully as I can to maximise value for the organisation and make sure that we deliver gas at the right time to achieve that. So, yeah, real positivity in terms of our marketing efforts at the moment. OK, no, thank you.

Yes. Your next question comes from Dale Conders with Darren Joey. Please go ahead.

Morning guys, Brett I was hoping you could expand on your comments for development concepts for Labella and for Artisan. Are these for backfill into the Otway plant and if so how long is that plateau production for or are you looking to develop through other plants?

Artisan Labella can go through our plant and I think that's our preference at the moment. If we have a big outcome at Hercules or if we have an expected outcome at Hercules, we'd probably want to get that volume on first and we may seek to put artisan maybe across any other plant that has available ullage in the region, really depending on where other operators go with their drilling. I think for me... I've long talked about the challenges I have economically with Labella. We've seen improvement in our cost base, improvement in the gas market, and also we see some pretty low-risk exploration drilling outboard of us that I think will also significantly amplify the value there. So I'm not going to commit today to what the development concept is, but we've got quite a bit of optionality that's emerging through the offshore way. As we get, you know, certainly at the back end of the Hercules well, we'll be able to give a much clearer view of what our program is and the succession of backfilling those prospects.

Part of the, I guess, frustrational concerns of the market has been the roll-off of production for beach and part of that is the Otway project. If these fields are developed, how long can you sustain the Otway gas plant at full capacity for?

Well, it really depends on the scale of things like Huxleys and the other activity in the region. This campaign will be the consolidation rig campaign that Assault, Amplitude and ConocoPhillips are executing wells, give us quite a bit of optionality for sustaining the Altway gas plant for many years. And I guess the question you're really asking is what proportionality of of beaches gas would that represent? And at the moment, I think when we see the back end of the Hercules well, we'll have a much better view on what that looks like.

Okay. And then just in terms of abandonment spend, you sort of called out some works, 25 and 26. Are there other abandonment work to be done in the outlay of the bass over coming years?

No, not in the short term. This really represents our statutory and prudent, while we've got a rig in place, activity to make sure that we manage the wells we have. We're seeing through that sustained production at Bass that the Bass, the Yola field, has quite a bit more life in it yet. So there's no pending near-term abandonments associated with the program outside of the five that we've outlined in the presentation today and previously. Okay. Thank you. Cheers.

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

Good morning, all. Thanks for the update. Just a wait here as we move towards production. Could you step through the current development and production plan? How long do you think you could sustain a Plateau 250 TJ day rate and what level of production you might look to supply to the domestic market after 2028?

Yeah, we don't really give all that detail. Obviously, we've got our reserve statement out there and our target is to get the plant to full capacity and deliver through the LNG export window at our full rates. And then we've got additional program coming in with Arenaria and we've got the potential to do an interconnect project from Bajara Springs to add additional volumes through the Waitsea plant and potentially into export as well given the change to the export license conditions that ourselves and our joint venture partner are working through. So there's a lot of optionality there for us and certainly through this decade and through next decade Waitsea will be delivering strong production through that facility and and, you know, as we get all our wells online. And just to be clear, we've completed Phase 2 development drilling programs, so all the wells that we need to get the plant up and fully supplied are in hand. And, you know, probably to cut to the chase, what's the next question? You know, all our pressure and clean-up tests are all performing extremely well, so we understand the pressure regime, we understand the compartmentalisation regime, Beach previously took an adjustment on reserves. I don't see any risk there from the work that we've done so far. So, you know, I feel fairly confident that what we have is going to deliver what we've promised to market.

Great. Thanks, Brett. So just to confirm, based on current 2p reserves and ignoring any potential exploration success, do you think, based on what you know, you can keep the plant full till 2028? Yeah, yeah, absolutely. Great, okay, thank you. If I can squeeze another one, just on the cargo swaps being returned, are there any other costs or adjustments to think about there, or is it purely just volume?

I'll ping that across to Anne-Marie.

Thanks, Henry. So just in relation to the swaps, the majority of them are fewer time swaps, so from a cash flow perspective, I guess in the future we'll be producing that gas and returning it, so the cost of producing that gas is what you'll need to think about, what that costs now and Basically, we won't be getting the revenues for that. There's a small discrete swap fee. One of our contracts does have a payment now for the gas. And then when we return that gas, there'll be a payment in the future. But that's sort of a smaller component of the total swaps that we've made to date. So if you're modelling cash flows, it's really just thinking about in the future, like Brett talked about, sort of if you assume a roughly even distribution of returning that volume, it's just the cost of production.

Got it, okay. Yeah, we've worked closely with the parties, the counterparties to make sure that we don't have some kind of peaky return volumes. We're trying to do that on a smoothed out basis across the forthcoming years. Great, thanks Brett.

Your next question comes from James Byrne with City. Please go ahead.

Morning team. I wanted to prosecute the case a bit more on Tom Allen's excellent question just around capital allocation and portfolio. And just forgive me here for a little bit of preamble, but I think it's important just to set the scene. Gearing, if you actually adjust it for LNG swaps, which are now effectively debt in a way, you know, gearing's actually 16%. 2P reserves life, if we adjust for weights, you're ramping up. is about seven years, and heaven forbid it doesn't perform, then 1p reserves life is three and a half years. But without organic growth left, I think those sort of adjustments that I've done suggest that the reinvestment treadmill in beach is actually quite steep. Now, our estimate, if you push gearing all the way to 25%, you'd have about half a billion Aussie headroom today, and I'm not sure that that necessarily moves the needle enough in the absence of script. to do an acquisition that's going to solve the longevity of the business. My question here is, you know, the payout ratio suggests you're going to pay out half your cash flows. And I'm just not sure that that's prudent necessarily, given how steep this reinvestment treadmill is going to become. Now, indeed, the board hasn't been confident enough today to pay at the payout ratio. It sounds like for FY25, that's the case too. Now, Marie, you mentioned that was because of abandonment and drilling activities in the second half, but I'd contend that they're actually a normal part of your day-to-day business. So why should we as a market expect the boards going to be confident to pay those higher dividends in lieu of using that capital for the urgency in the portfolio to do some M&A? Did you want to start with that one, Emery?

I guess, yeah. I'd just say, you know, similar to sort of the things that Brett and I have both mentioned through the presentation today, the payout of the dividend is based on four-year cash flows. So we wouldn't be looking to pay on just the first half alone because we do have more sitting in that basically free cash flow ex-growth. We've got more expenditure coming in the second half. So we've taken that into account And it's not, I guess what we would say there is we are being sort of carefully measured in the way that we are allocating dividends. When we get to August and our full year results, that will be revisited. And obviously we have a policy out there that we are looking to deliver within as we continue through the cycle. And from a gearing perspective, we are at 10% through some outstanding work from our commercial team. And that's not, You know, it is all value accretive. It's not value neutral is what I'd say on that one. James, it's not just, you know, a swap and the cash now versus the cash later. All of these swaps are NPV positive because of the way the LNG contract is struck. We're bringing value forward into a period where we are yielding really strong pricing. And I guess I'll hand back to Brett in terms of balancing M&A and dividends. going forward?

Yeah, and as I've mentioned numerous times, we've got a great opportunity in cash flows. You're inferring if we get a downside outcome across our whole portfolio. that we would need to act. And I think that's, you know, if that was a possibility at that point in time, we would have to act. But we've got all the hallmarks through what we're seeing at the moment through our production activity and certainly through what we've now completed development drilling across Waitsia, understanding that what's in the ground there, certainly much better than what we did several years ago. So, you know, there's a level of confidence in terms of the organisation that we can deliver long-term sustainable value from those assets and continue to seek to grow them. Notwithstanding that, I think we've previously talked about later this decade that we do have production decline across the portfolio. I'm certainly not hiding from that, Tom. And we are definitely, sorry, James, we are definitely looking at how we continue to strengthen our portfolio through a range of opportunities. So we've got a very strong balance sheet. We can utilise that balance sheet if we need to. But we're looking at making sure that we get the right mix between giving good, sustainable returns and growing the business. So I do think we have a balance sheet that can support that.

Yeah, okay. I guess philosophically though, I wasn't talking to a downside case, right? I think seven years reserves life on a 2P basis is still reasonably short and surely you've got a good cash flow hump. But philosophically, I was testing whether paying half the cash flows is really consistent with solving for the longevity of the business. I think my second question then, when I talk to institutional investors, a big sticking point that I have personally and many institutional investors have is, what are we buying? If we're buying today, given that decline that we can see a couple of years out, my question really is, do you think that we should trust... management team and the board today by being invested today not necessarily knowing what the asset mix is going to look like in the future or can you sympathize with the view of people like myself that it's probably better to wait till we know what we're buying uh potentially after a deal oh yeah i can't i'm not in any place to give you personal financial advice james but um

you know, what I see at the moment is a very strong leadership team that has access to a fantastic balance sheet that has enabled it to grow its business organically and also grow its business inorganically. So, you know, we've got, as you said, a great cash flow generated business which we need to continue to manage and to nurture and to make sure that we get the right opportunities to come in to keep those cash flows coming. So, I guess the investment thesis for yourself, being your financial advisor of the day, would be that I hope that you do trust what I can deliver. And if you need to wait, well, then you pay at a higher price, I guess, is typically what happens. But I'm looking to try and grow the business. I'm looking to deliver value from our assets. And I think we're on track to do that. Excellent. Thanks. Really appreciate it. Cheers.

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

Good morning, everybody. I'm going to ask a positive question. Nice to see you reduce your field operating costs by 20%. Can you kind of highlight where that's come from, and is it mainly in the Otway Basin?

It's actually across the whole business. When we did our... Our headcount reduction, we haven't kind of focused on a particular asset. We've taken that across both corporate speech as well as across our field locations. We've been working with our contractors, getting better deals and trying to deliver higher values. We've been looking at positioning our contractor base out of just solely being tier one to picking some of those local suppliers to deliver a low cost and high value outcome. So, you know, Gordon, when you try and deliver these types of changes, you have to look under every stone. And, you know, we've really been focused on that. And that's been great. Clearly, we've had some help with lift and production. But in terms of the raw cost through the business, we're seeing great intent. And, you know, that's against the backdrop of higher electricity costs in New Zealand and some of the inflationary pressures. So, You know, I never want to stop our focus on reducing costs, but I'm very pleased with the direction we've gone. And, you know, we set a target for 30% headcount. We've reached 32. That also speaks to a bit of the culture in the leadership team that they just want to keep on looking how to grow and how to mature and how to become more efficient across the space.

Thanks, Brad. Just on the Waitsea project, you made a comment earlier, I think it was slide seven, that Clough personnel are now taking direction from Mitsui. I mean, that kind of scared me. I would have thought that would have been the case all the way along because Mitsui is the operator. And then I guess, you know, you put 20 professionals in there. Tell me I'm wrong, but are you kind of giving instructions to Mitsui who gives instructions to Clough type of thing? Is this still... not perhaps most ideal joint venture structure in terms of giving you high level of confidence in the ability to deliver the commissioning of the project, or have you seen a big improvement there?

I think the challenges we had, you know, the contractors that were signed originally had Mitsui taking over commissioning control. And, you know, one of the things that Beach has inherited in its business is a high level of capability, particularly in commissioning. We're always bringing things online. So we have the expertise to help. So I've tried to deploy that and help. So when I say Mitsubishi, so effectively, now we're going to commissioning, it's going in from project control to operational control in different parts of the plant. And the ops team is the Mitsui team. So you have that kind of period between full project and ops where you've got commissioning. And we've certainly got a lot of help in that space. We've got very senior people in the structure, you know, giving great advice, giving great direction. I'd love to have more people in there. You know, at the moment I don't have an organisation that is capable of probably giving too many more people just because of our other opportunities around the business. But, you know, I thought a great move, you know, I was very disappointed not to have fuel gas into the plant. We're still waiting on a few valves and some pipe work to be delivered. But we worked with Mitsui to figure out, you know, how do we break that from being a critical path? And as you would have seen when you visit, you know, that big AMN train, we need to get that commissioned. That was a real important piece. So we brought in equipment to get that commissioned so that we break out the fuel gas in as that critical element of the um of critical path so you know working together on those things has been quite um quite good and having more influence in the joint venture has been fantastic and you know i've got to give credit to glenn and his team um who are you know speaking to mitsui every day working with them um engaging with our staff making sure that we get this um this project up okay last question from me and someone who's worked with maps for a big part of their career

I'm comparing the map that you have for the Perth Basin in the December quarter report to the new one that you've put out today, and I'm looking at Redback Deep, and it looks like it's got a lot smaller. I'm a little bit worried. Is this just a schematic, or is it an actual change in potential size of Redback Deep?

It's just a schematic, to be honest. Gordon, I haven't looked at that map in that much detail. You know, given we come from a similar background, I probably should have. But no, no, ribactive hasn't got any smaller.

Okay, thanks for that.

Yeah, cheers.

Your next question comes from Nick Burns with Jarden Australia. Please go ahead.

Yes, hi Brett and Anne-Marie. Just back on weights here, look Brett I'm sure you know that the whole process has been a source of intense frustration for yourself and shareholders more generally. You talked about the delay in the introduction of fuel gas but you've been able to mitigate some of that timeline by bringing in other equipment to start some of the AMEN commissioning. Just as we sit here today, How confident are you that the timeline to completion of First Gas presented here is realistic and can be met with no change in capex? Thanks.

Yeah, so we engaged several external parties to do reviews, you know, to very much get some more confirmation of that question. You know, and there was, you know, a tone of that review, which is what's been set out as achievable and, you know, I hate to use this language, but somewhat conservative. And so we've got to balance that comment from the external reviews of the conservative timeline that was mentioned versus the actual delivery of activity in the field and the challenges we've had with things like valves, particularly about getting xyrus gas in. So I feel like we're fairly balanced in terms of our risk understanding. I go and look at the plant. The plant's built, and we've just got to replace these valves and get these valves from the suppliers in a timely fashion and get the process online. I hate to give a comparison, but you look at what Sandals delivered with commissioning the Mover CCS project, full rates within about six weeks. That's kind of world-class activity, and we need operators to lift to be able to deliver that type of outcome. And I'm trying to get in there and support them to do that.

Got it. Thanks for that. You've called out opportunities for further gas swaps ahead of our Waitsia startup. Jessica, can you talk about, you know, are we talking maybe one or two more cargoes? And you do mention Mitsui involvement there as well. My recollection is they haven't been involved with swap cargoes to date. So are they looking now to partner up with you? So further swap cargoes, maybe 50-50 with them? Or how should we think about that?

I think Mitsui looks at them on a case-by-case basis, so we will continue to work with Mitsui on that. We have opportunities for additional swaps in the market, and we're looking very closely. I don't want to give you a promise, Nick, because you'll put it in your model, but I'm hoping to get another one at least out before... before the half year. And if I don't, I apologise in advance, but we've certainly got the opportunity to do that.

Got it. Thank you. One more from me. Just on the Otway upcoming campaign, you called out you're not going to drill Mavis. My understanding is that was a commitment well. I'm just wondering, have you been able to get out of that commitment and what does that mean? And then just following on from that, I think you're pretty bullish around the near shore exploration campaign obviously would use an onshore rig rather than offshore but is there anything you can say about plans to progress near shore drilling in the next year or so? Thanks.

Yeah, so we'll bring some more plans to that later this year. Sorry, I'll start with the near shore. From the enterprise well slot there's opportunities to do additional wells and we have really high quality opportunities near shore that we can connect through. So We started the engagement with joint ventures and regulators to move that forward and I hope to give you an update of that in the not too distant future, probably either at the full years or maybe at our next strategic update. I'll give you some colour at that point. They look really exciting to me. not too dissimilar in size to how we view enterprise today, which are still very highly value-accretive and relatively low cost. So I love those near-shore activities because we can, like you said, use an onshore rig. We can deliver it at a much lower cost point, and we don't have that challenge of mobilising large offshore vessels around. So things like that make a lot of sense to me, Nick. And I can't remember what the other part of your question was, unfortunately. Mavis, we're working with the regulator on that. I can't really comment too much on that at the moment, yeah.

Okay, thanks. Thanks, everyone. Cheers.

Your next question comes from Saul Kavanagh with MST Marquee. Please go ahead.

Thank you, Brett and Anne-Marie. Putting weights aside, perhaps on balance it looks like the business is outperforming across the other assets versus, you know, your expectations six to nine months ago. Keen to get your take on, you know, is that the case? And particularly if we look at the outlook for FY26 and FY27, weight to your side, are you becoming more optimistic on what our production looks like over those years versus expectations at the time of the strategic review earlier last year?

Yeah, it's a really good question. So at the point of the strategic review, I had some concerns of some of the options and we made changes to some of our reserves through that period. So I had some concerns through there. And what we've seen is much better performance against what the expectation was. So I feel pretty confident in where we are in the Otway in terms of production and reserves. Certainly, We've seen, even just across the Western Flank, we've been able to defend production and we've got a really solid campaign of wells coming up across the Western Flank in this development and appraisal period. And then Bill and his team will get the final look at what their exploration campaign looks like, which will follow on after the development program in the Western Flank. And that's looking pretty good. So I'm feeling pretty confident about where we are for development Certainly 25, 26 and 27, no doubt we've got enough information to hand to be able to fill that way. So, you know, I'm not promising any reserve upgrades at this point in time or anything, but I feel very confident about what our modelling suggests.

Great, thank you. Perhaps a question related to some of the early ones, but being more specific. There's a number of companies are scouring new Queensland gas opportunities, inorganic ones, to meet the domestic shortfall forecast and LNG outage next decade. Do you see a role for BEACH to play in Queensland onshore CSG and tight gas?

I think I've always had a view that CSG would be a good part of our portfolio. I think it's got that longevity, it's got that consistent cash flows, and as long as you've got the right acreage position, you can take strong advantage of it. Now, obviously, we're not there at the moment, but one of my direct reports, Glenn Watt, is kind of an expert in this field. He's run assets across Queensland for one of the major operators there, and he's got probably more experience than anyone else. We've got some individuals in the organisation that understand that pretty well. So if the right opportunity come up, I would certainly have a look at it.

Great. And just last one, I think, following on from the previous question, just on, you know, Mavis isn't mentioned anymore. We've got Hercules in the next few months. It seems, you know, I'm just looking at slide 17, nothing for the FY26 activity is suggesting more exploration. Is Hercules basically it for the next 18 months in terms of big offshore exploration prospects you're targeting, or is there scope to put additional things in the FY26 program?

Yeah, so Hercules is the only one we're discussing at the moment, but there is scope to do two other things, and we're just working on those at the moment. And hopefully we can give the market an update when closer to that time.

Great. Thank you. That's all from me.

Yes, thanks.

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

Good morning and congratulations on the amounts achieved so far. Just a few questions on the swaps, the gas swaps. You've kind of given us some colour of where the gases come from there, 35% from your own production. Is that a good way to think about the sourcing of the swaps this half? 3565 or is it a bit more case by case?

No I think that's fairly representative of how you should think about it moving forward.

Okay great and then I guess I'm just looking at the accounts and we're just trying to because there was a comment on one of the other questions about gearing including swaps being significantly higher just wondering if Ms Barbaro has any further feedback on whether that number was right or not. I don't think it is but Where in the accounts is the financing component of the swap obligations please?

No, there is no financing obligations as such that would be incorporated into a gearing calculation. So I can't speak for James' calculation but our gearing as outlined in our PAC is 10%. From a swap obligation perspective, I guess the only place that you would probably see through the financials is within the inventory on balance sheet. So there's sort of that, you know, borrow and loan that you account for as effectively just at the cost to produce that gas in the future. So like I spoke to earlier in Henry's question, when you're thinking about modelling how these swaps get returned. From a cash flow perspective, you should be thinking about what it costs to produce that gas, and that's the cost effectively to return that gas in the future. With one of the contracts, we do have them paying us for that gas in the future as well, which also is a good little cash flow for us in that return period as well.

Yeah, great. Yeah, that's consistent with how I understood it. So that works for me. All right. And then you've called out in the second half a little bit of P&As. activity which is I guess going into your thinking on dividend which makes a lot of sense. Can I just get some colour on how you're managing those costs, how that market for restoration and rehab is going and is it worthwhile for example bringing forward activity if there's equipment available, labour available or is it better to just fulfil your statutory obligations and keep pushing out as much as you can?

I think for us it's about looking at wells that we fear that might have some issues. So we're just taking advantage of a rig being in the region to fulfill an obligation to make sure that the barriers are properly in place. So we obviously investigate all our wells all the time to check that they have strong and intact barriers. A couple of those wells are starting to have some challenges. So we wanted to get them done and hence moving them through. Now, the best solution for abandonment is to do it at one time so that you can mobilize once you have all the equipment and have the right people there. And that's obviously best done at the end of the project. So, you know, it's probably not normal to do this in this timeline, but outside of wanting to make sure that we had integrity across those walls and across those barriers. So, you know, we felt like that was an absolute requirement and the regulator agreed with us that there is a requirement to do that. So we've moved that forward. But otherwise, I would suggest that doing things once and at the end is a much more prudent use of capital and a much safer way to do it because you'll have all the right people and equipment in the right place. And moving forward with additional abandonments for others, there'll be more equipment and things and I think the competitiveness of the market will progressively increase as well.

Okay, thank you very much. That's super helpful and good luck with the rest of it. Thank you so much. Cheers, thanks.

Your next question comes from Mark Wiseman with Macquarie. Please go ahead.

Oh, good day. Thanks for the update, Brett and Marie. Just a few hopefully quick questions. On Waitsea, you mentioned eight to 10 LNG cargoes per year. Can I just check, is that net of the time swap settlements over the next few years and the 10 would sort of be without? Or is there some variability year on year on production as well?

I think you've seen through me, Mark. Yeah, that's fairly accurate, mate.

Okay, okay. And just on the weights here, the delay to introducing that fuel gas, I appreciate what you were saying around the amine testing, but could you just talk through what was the root cause of the issues with introducing fuel gas? Was it a spec issue or a pipe valve issue?

No, it's unfortunately just valve issues. So part of the challenge is being a slow construction phase. is some of the valves would sit in location for a long time without being served and some of them were in locations that couldn't be properly pressure tested. So when they were finally able to be fully pressure tested, some of them were passing beyond what the specifications would allow. So they had to be rectified and then replacements needed to be put in place. If you can execute a project in a much more timely fashion, these are normal project activities that you should get done. But over the longevity of this execution period, some of these issues have popped up. So the majority of those valves are all fixed and in place. We've still got a few that were lighting supply chain-related issues to get in place, and we'll get that done in the future. But, you know, I've been very conscious about getting the project up, you know, obviously, you know, We all have shareholders alike. And so the clear way to kind of accelerate some of that time is to break. As you know, Mark, bringing the gas into the plant was the key tool to be able to commission the rest of the plant. So rather than having everything stalled, waiting for a valve or two, we brought some equipment in so that we can continue the commissioning phase around the bringing those iris gasses first gas in and so that remains the focus of us of course but it enables us to get on with work and not have to wait for a supply chain issue.

Okay fantastic and just finally for me on the sustaining capex, within that seven to eight hundred million guide the sustaining was $420 to $480, you've spent $195 in the first half, is there anything between the second half and the first half that we should think about? Or it looks like you've driven out quite a bit of cost there.

Yeah, so probably the difference, you know, what we normally include in sustaining is western flank development drilling. And so we're bringing a rig in so that, you know, while we're still guiding for the targeters, or our forecasters, I should say, is because we have that rig coming in to do those... 10 development wells, proseline development wells across the western flank. So obviously you wouldn't have seen that in the first half activity, but that's the second half activity that there has been a capex spent on.

Fantastic. Thanks very much.

Cheers. Thanks, Mike.

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