Beach Energy Limited

Thank you for standing by and welcome to the Beach Energy Limited FY24 full year results briefing. All participants are in a listen-only mode. There will be a presentation followed by a question and answer session. If you wish to ask a question, you will 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 Brett Woods, Managing Director and Chief Executive Officer. Please go ahead.

Hello and welcome to Beach Energy's FY24 Full Year Results webcast. My name is Brett Woods and I'm the Managing Director and Chief Executive Officer at Beach. Joining me today on the call is Anne-Marie, our Chief Financial Officer, and she will take us through the financials. For today's webcast, I'll provide an overview of the full year results, including progress over the past six months and an update on the outlook for FY25. Anne-Marie will go through the financial results and we will finish the webcast with some Q&A. But before I begin, I would like to take a moment to address the enterprise reserve revisions as highlighted through the announcement this morning. It goes without saying that I'm extremely disappointed to have to convey this news, particularly after flagging reserve revisions two months ago at our strategic review. The strategic review presentation occurred only four days after the enterprise field was bought online with strong production rates. Since then, we have accumulated sufficient pressure data to reassess our pre-production reserve estimates. In normal practice, well pressure performance would be monitored for a significantly longer period before assessing any updates to reserves. However, with the excellent quality of reservoir sands and high production rates observed at enterprise, We have observed a declining reservoir pressure trend over the past few weeks. We have rapidly moved to analyze this outcome and engage two independent experts to confirm our evaluation. So what has happened at Enterprise? Enterprise is single well development and when the exploration well was drilled, the well did not intersect the gas water contact. The location of the gas water contact was the primary risk with regards to the in-place gas volumes. The gas water contact was inferred from seismic interpretation in the mid-case 2P assessment. And as a consequence, it had a very wide range of uncertainty from a water contact just below where the gas was intersected in the well to a maximum extent supported by amplitudes and velocity modelling. This interpretation and range was supported through independent third-party reserve orders. Now that we have production, the well performance data to date indicates that the likely contact is on the shallower side of our original expectations and thus is not in line with our 2P mid-case scenario. It is, however, well within the range of our uncertainty. Despite the revision, it is important to note that this change will not impact our FY25 production guidance or impact our ability to deliver the enterprise gas sales agreements. Enterprise fuel remains a valuable asset within Bench's portfolio. Since arriving at beach, I've been working hard on further strengthening the team systems and process across our technical disciplines. I'd like to emphasize that I am proud of what we're currently delivering as a beach with our focus on lowering costs, rapidly making organizational structural changes and our strategic refresh and operational performance. This is underpinned by discipline and an accountable organization with an owner's mindset. Outside of the result at enterprise, our FY24 results are broadly in line with market expectations and as reflected through our strategic review update. On the next slide, you'll see our compliance statement, and I'll leave you to observe that at your time. We move forward. At the year end results in February, I set out my near-term priorities and key focus areas, which included Delivery production from Waitsia, Enterprise and Thales and West projects. Reducing the operating costs of the business. Instilling that owner's mindset and drive high performance and margin growth. And maintaining our strong financial position. While we've made good progress against these priorities, it is fair to say that the past six months have proved more challenging than I anticipated, due to both internal and external factors. Those challenges aside, the value proposition which attracted me to BEACH remains compelling. In fact, the intrinsic value of our portfolio is becoming more evident with continued acceleration of the energy transition and increasing recognition of the critical role that gas will play. This slide shows why we firmly believe BEACH is uniquely positioned to play an increasingly important role in the gas-supported energy transition. First, we have completed our strategic review implemented a new organisational structure and identified material cost savings with more to come. We are resetting our foundation as we position for sustainable growth and earn the right to grow. Second, Beech has exposure to key markets with strong fundamentals which will continue for decades to come as the energy transition plays out. Third, our financial position is strong and we are committed to disciplined CAPEX and OPEX deployment. Fourth, our outlook for increasing cash flow provides flexibility to balance sheet high dividends for shareholders in line with our capital management framework whilst retaining optionality. Fifth, we have several near-term value catalysts as we deliver current projects and progress organic growth opportunities. Lastly, our emissions reduction project at Moomba CCS will be a major contributor to our decarbonisation and sustainability objectives. Further material investment in sustainability or new energy opportunities by BEACH is not required to meet our 2030 targets. Turning to slide four, which summarised keel milestones from the year, I will touch on some of these in more detail a bit later, but for now it's worth calling out just a few. Completion of the strategic review and implementation of our new organisational structure was an important step for BEACH in resetting base business. The detailed review allowed us to establish the pathway for returning beach to being a low-cost operator while earning that right to grow. The weighty LNG and condensate cargos were good outcomes. Our strategy to mitigate committed LNG processing costs by using surplus gas from Xyrus and entering time swaps for third-party gas allowed us to lift two LNG cargos through last financial year. We continue to progress opportunities to deliver another Koga before start-up of the Waitsier gas plant. Speaking of which, progress of the plan is continuing. You'll recall that detailed review of schedule and cost undertaken by the joint venture during the year resulted in a capex increase and a delay to first gas. This was obviously very disappointing to me as well as to shareholders. We are targeting first gas from the Waitsier gas plant in early calendar year 2025. followed by a three- or four-month production ramp-up period. The beach-operated Perth Basin drilling campaign delivered gas discoveries at Ribback Deep, Tarantula Deep, and a development well at Bahara Springs Deep. Those results are encouraging for future drilling in the central fairway. In the western flank, a 16-well oil and gas exploration and appraisal campaign was completed with mixed results. All discoveries were made at Bangalee South and Kalawonga North, and successful appraisal drilling was undertaken at the Martell Hill. I remain confident that there is further exploration potential to pursue in line with our disciplined approach to capital deployment. In the Otway Basin, the enterprise development was completed with a nearshore gas field connected to the Otway gas plant. With Enterprise Online, the East Coast market received an injection of new gas supply at a time when it was desperately needed. We saw our first uptick in production following the connection to the enterprise field in which supported a 31% increase in our Otway Basin production for the fourth quarter. We also progressed the connection of the Thighlights End West 1 and 2 wells, the two wells in the offshore Otway Basin campaign. We're targeting first gas from these wells in the first half of FY25, which will provide further well deliverability for the Otway gas plant and another new source of gas supply for the East Coast market. On the commercial front, key Otway Basin agreements were struck during the year. We concluded negotiations for the Otway Basin price review, and a new agreement was signed for the sale of the enterprise gas. Lastly, the Moomba CCS project reached a mechanical completion shortly after the year end, and first CO2 injection in the first half of FY25 is targeted. Moomba CCS plays an important role in our climate transition action plan, which we released in April. The CTAP outlines our target of reducing scope one and two equity emissions intensity by 35% by 2030 and our ambition to achieve net zero emissions by 2050. Thanks to our significant investment in Moomba CCS, beach can rightfully be considered industry leading in terms of decarbonisation. Turning now to slide five for a quick overview of headline results. It was a solid set of results for FY24 and we maintained a strong financial position while we progressed our major projects. Production of 18.2 million barrels of oil equivalent was 7% below the year prior due to lower customer nominations in the Otway Basin, delays in project delivery, and weather events in the Cooper Basin. Despite lower production, revenue was up 9% to $1.8 billion, driven in part by the weightier cargoes and higher realized oil and gas prices. Our realized gas price of the year was up 8% to $9.50 per gigajoule thanks to new contracts, repricing of the Otway Basin GSA, and higher spot prices over the winter. Underlying EBITDA of $950 million was broadly in line with the prior year, and underlying NPAT of $341 million was 11% lower than the prior year. Free growth, free cash flow was $163 million and allowed the board to declare a final dividend of $0.02 per share resulting in a full-year dividend of $0.04 per share. We ended the financial year in a strong financial position with $437 million of available liquidity and gearing of 15%. Slide 6 sets out our reserves position with the enterprise revision announced today and the revision slated in June with the strategic review. A detailed subsurface review was undertaken, which assessed recent drilling results, reservoir performances, and various data interpretations. Reserved revisions flagged in June were due to outcomes of the Coupe South 9 development well and Coupe reservoir depletion from existing wells, outcomes from Bahara Springs 2 deep development well and revised reservoir mapping, bath of an anticipated decline from Thylacine North wells, and some minor reservoir performance just across the Cooper Basin joint venture. Turning to slide seven, which details our health, safety, and environmental outcomes. Our personal safety performance in FY24 was a story of two halves. In the first half, safety was not where it needed to be, so we promptly initiated Stand Together for Safety campaign. The campaign included company-wide stand-downs, toolbox talks, executive leadership site inspections, and a special purpose contractor forum and implementation of new life-saving rules. Surprisingly, we did not experience a single recordable injury in the second half of the year. We have now achieved over eight months of recordable injury free. This is our best run of safety outcomes since 2018. And this is during a period of significant change within the organization. Plant process safety performance was strong throughout the year. With no Tier 1 or 2 incidents, we also had no environmental spills of more than one barrel. We're determined to continue our strong momentum through FY25 and beyond. Slide 8 sets out progress on the sustainability front. There were enough highlights through the year, including release of BEACH's first Climate Transition Action Plan, good progress at MUBA CCS, which reached mechanical completion shortly after year-end, progress towards our inaugural Reconciliation Action Plan, which we expect to release in FY25, a readiness assessment for the upcoming implementation of the Australian Sustainability Reporting Standards, which we expect in FY26. You'll find a lot more detail in this year's Sustainability Report, which is now incorporated in our annual report, which was released today. Turning to slide nine, and a quick recap of the strategic review. Six months ago it was clear that change within the organisation was required. I initiated a detailed strategic review which looked at our organisational model, asset portfolio, operating and capital cost structures and growth opportunities. The review sought to establish the pathway for returning Beech to being a low-cost operator while earning the right to grow. I'll come from the reviewer announced on the 18th of June. And if you haven't done so yet already, I would encourage you to have a review of that presentation. Our vision is to become Australia's leading domestic energy company. To achieve this, we are guided by a very fresh three pillar strategy. The core hubs recognises beaches established in diverse portfolio of strategically valuable infrastructure servicing the east and west coast markets. We will focus on these core hubs to optimise our assets as we grow our market share. High margins fills an owner's mindset into our day-to-day operations and our capital allocation decisions. Low-cost operations and pursuing the high failure for our molecules underpins this pillar. Sustainable growth captures our desire to lengthen the duration of our portfolio and deliver sustainable value creations for our shareholders. Our emissions reductions target and CTAP underpin this pillar. Our first priority is delivering profitable and a resilient-based business. In doing so, we believe that enables us to earn the right to grow through inorganic and organic opportunities. Today, we have identified roughly $135 million of costs and sustaining capex to come out of the business at FY25. We're targeting to increase this over $150 million by the end of FY26 and to lock in the structural savings. It is worth noting that savings to date have largely come out of our operated assets. We're still in the early stages of pursuing cost savings with joint venture partners for our non-operated parts of our business. On that note, I'll hand over to Anne-Marie for a look at our financial performance.

Thank you, Brett. Good morning, and thank you again for joining us today. Our headline financial metrics are set out on slide 11. Beach reported a solid set of results for FY24 and maintained a strong financial position while delivery of major projects continued. Our results in FY24 were influenced by a 7% decline in production, driven by lower Otway Basin customer nominations, weather events in the Cooper Basin, and natural fuel decline. Despite lower production, sales volumes were up 3% to 21.3 million barrels of oil equivalent, and revenue was up 9% to 1.8 billion, supported by two early weight tier LNG cargoes and a one-off condensate cargo lifted during the financial year, coupled with higher realised oil and gas prices. The earlier weights year cargo saw our product mix shift more towards liquids, which accounted for 61% of sales revenue, with gas accounting for 39%. For reference in FY23, the split was 58% liquids and 42% gas. Underlying EBITDA of $950 million was broadly in line with the prior year, An underlying NPAT of $341 million was 11% below the prior year, mainly due to higher depreciation. Not shown on this slide is our net asset position. Net assets reduced by $565 million to $3.3 billion, with non-cash impairment charges for producing and exploration assets, being a material contributor to this reduction. The impairment charge of approximately $1.1 billion before tax related to the following. Producing assets in the Cooper Basin, largely driven by increasing Cooper Basin joint venture operating and capital costs. Producing assets in the Taranaki Basin, following results from the Coupe South 9 development well. Producing and development assets in the Bass Basin on the decision not to develop trefoil. And exploration assets across the Western Flank, SA Otway and Bonaparte Basins. It's important to note that the impairment charges are non-cash and do not impact our underlying earnings, which I'll now touch on. Slide 12 steps out our underlying NPA, which as mentioned was 11% below the previous year. We've touched on a number of the elements here, so I'll just briefly mention a number of the key drivers. Revenue was higher due to the two weights year LNG cargoes and a one-off condensate cargo lifted during the financial year. in addition to higher realized oil and gas prices across the portfolio. These were partly offset by lower production. Cash costs were higher due to higher third-party purchases, tariffs and tolls, and inventory movements, largely associated with the weightsier cargoes, and higher operating costs, which were mainly attributable to our interest in the non-operated Cooper Basin joint venture. Lastly, we reported higher depreciation in FY24, with higher Cooper Basin JV costs in the first half of FY24 and a change to methodology for our Cooper Basin assets from 1 January, accelerating depreciation during the second half of FY24. Slide 13 shows movements in cash during the financial year, which resulted in closing cash reserves of $172 million. Operating cash flow of $774 million was 17% below the prior year. Impacts from lower production and unavoidable weights year LNG processing costs were partly offset by cash receipts from the weights year LNG and condensate cargoes. Debt drawdowns of $370 million were made as we continued to progress through a capital intensive period. Capital expenditure cash flows of $1.1 billion included growth capital expenditure of $499 million for major projects and sustaining capital expenditure of $609 million. As announced as part of the strategic review, through structural cost savings and operating efficiencies, Beach is targeting a reduction in sustaining capex to less than $450 million. For FY25, our guidance for sustaining capex is $420 to $480 million. Free growth free cash flow was $163 million, and the Board declared a final dividend of $0.02 per share, resulting in full-year dividends of $0.05 per share. On slide 14, you'll see that our balance sheet remains strong. We ended the year with net debt of $583 million, net gearing of 15%, and $437 million of available liquidity. A maturing $250 million debt facility was refinanced during the year by our new three-year $350 million tranche. There was strong lender support across domestic and international banks, and competitive market terms were secured. A strong financial position allows us to maintain flexibility as we balance investment and growth with increasing dividends to shareholders. As we move towards strengthening free cash flow from our major growth projects in the Otway and Perth basins, we have the capacity to pay high dividends to shareholders while continuing to invest in sustainable growth. Supporting these objectives are our strict operating principles, capital management framework and discipline investment framework, which were articulated as part of the strategic review. I'll finish on slide 15 with a quick recap of our operating principles and capital management framework. Our operating principles are underpinned by key financial targets, including a free cash flow breakeven of less than $30 a barrel, field operating costs of less than $11 per barrel of oil equivalent, and sustaining capex of less than $450 million per annum. Throughout the business, there is strict focus on compliance with these targets. The capital management framework outlines our gearing and shareholder return targets. On gearing, we're comfortable with increasing gearing for the right growth opportunity, noting that any investment must demonstrate a path to timely pay down of debt. On shareholder returns, our dividend framework of 40 to 50% of pre-growth free cash flow for frank dividends will see us delivering higher returns to shareholders once our major growth projects are complete. Ultimately, our objective is to deliver higher returns for shareholders through disciplined operations and capital allocation. On that note, I'll hand back to Brett.

Thanks, Emery. We'll have a quick look at the outlook for FY25 and beyond. Slide 17 is a quick reminder that Beech sells its products into key energy markets, which all have very strong fundamentals. This diverse market exposure is a key element of our value proposition. The outlook for our key market is unchanged. Structural supply deficits are persistent and growing. In particular, market dynamics in the East Coast and West Coast support the focus on our core hubs, as described through our strategic review. In addition, forecast supply deficits for global liquids provide strong support for oil pricing, which in turn provides the opportunity for more oil link price exposure and hence enhancement of our margins. But 18 is the indicative timeline for completion of the Waitsys Stage 2 project. As I mentioned earlier, the review we undertook during the year was brought about due to the continuous emergence of quality and execution issues during pre-commissioning at the plant. It meant most of the onsite workforce was redirected to remedial works rather than progressing pre-commissioning activities. This is what led to the schedule delay and in turn CAPEX increase. Following the review, BEACH was able to support the operator Mitsui via secondes to help drive the contractor, Clough. This has given us better insight into real-time progress and allowed us to exert greater influence over the project execution and respond quicker to emerging issues. Today, the proportion of workforce focus on remedial works has significantly reduced and the majority of the construction is now complete. They are focused on commissioning activities. The workforce is operating on a 12-hour shift, 24 hours a day, and no further quality issues have emerged, and a good sign, approximately 80% of the plant is now cordoned off solely for commissioning activities. Although on-site productivity is improving, it is still not where it needs to be. Introduction of fuel gas into the plant by the end of July was expected, but is now likely to be in September. This means a large proportion of the buffer we built into our updated schedule has been eroded, and this has introduced some risk of further schedule slippage. I've included in the pack a schedule of the key forward activities and milestones to enable greater clarity and communications between now and first export gas. At this point in time, I remain confident in achieving first gas from the plant in early calendar year 2025. This timing would mean our capital expenditure guidance of $600 to $650 million still holds. Now turning to our guidance for FY25 on slide 19. Production and capital expenditure guidance is unchanged from the strategic review in June. We have decided not to narrow production guidance despite a good start to FY25. Production outcomes in FY25 will be largely dependent on the timing of ramp-up to the waste year gas plants. Furthermore, despite recent Otway Basin production being well above take-or-pay levels, there remains the risk that customer nominations could reduce such that annual take-or-pay levels do eventuate. We have therefore maintained guidance at 17.5 to 21.5 million barrels of all equivalent. Capital expenditure guidance of 700 to 800 million FY will be another important year for BEACH, with Waitseer Stage 2, Salatin West, due for completion. Planned activities and priorities this year include a clear focus on getting our operations and execution right, continuing the strong momentum from FY24 in relation to health, safety and environmental performance, working with a joint venture partner and operator, Mitsui, to commission the Waitseer gas plant, Installing the Thylacine West flow line and bringing the final two development wells from the offshore Otway Basin campaign online. Refreshing the inventory of gas exploration prospects in the Perth Basin and all exploration prospects across the western flank. The potential FY26 campaigns. Refreshing the inventory of our potential FY26 campaign. Ongoing oil and gas exploration appraisal and development drilling in the Cooper Basin joint venture, including further assessment of the granite wash play. Working with joint venture partner and operator Santos to commission member CCS. Planning for the next phase of offshore Victoria drilling. Commencing initial assessment of the potential for gas storage and gas peaking power utilisation by utilising our existing assets. Flight 20 sets out the field operating costs and free cash flow break-even targets, which again are unchanged from the strategic review. We've provided depreciation guidance of $400 to $450 million, which is largely driven by production outcomes. A one-off expense item of up to $59 million relates to the committed LNG processing costs. As I mentioned, we're pursuing arrangements to sell another cargo before start-up of the Wadesia gas plant, which will utilise some of this commitment. Slide 21. In closing, a quick reminder that we've already made good progress against our strategic review objectives. In the past six months, we have completed the detailed strategic review, implemented the new organisational structure and taken costs out of the business. While we still have more to do, our strict operating principles which are underpinned by the cost and cash flow break-even targets, have established the pathway for returning Beech to being a low-cost operator. With the strategic review complete and outcomes being implemented, Beech's oil positions play an important role in Australia's gas-supported energy transition. Our existing infrastructure and acreage positions and established presence in East and West Coast markets underpin that value proposition. We begin FY25 with much strength and foundation to deliver our near-term priorities and position ourselves. Strategic review allowed us to establish the pathway for returning beach to being a low-cost operator while earning that right to grow. I'll now open up the lines for Q&A.

Thank you. If you wish to ask a question, please press the star 1 on your telephone and wait for your name to be announced. If you wish to cancel your request, please press star then two. If you're using a speakerphone, please pick up the handset to ask your question. The first question today comes from Tom Allen from UBS. Please go ahead.

Good morning, Brett, Anne-Marie and the broader team. Can I ask you to please share more colour on how you're going to balance the need to address Beaches' reserve replacement risk with shareholders' expectations of materially stronger capital returns? Another reserve downgrade today to Enterprise, again, emphasises that Beach has to deploy a good portion of that step change in cash flow that investors have been patiently waiting for into new growth to top up reserves. So does the reserve right down to Enterprise, does it change your appetite to pursue organic growth in the Otway through Artisan or even Hercules and Mavis, which I know to light on your information today?

Yeah, so we haven't taken FID on that Mavis and Hercules campaign. I think, as kind of highlighted previously, Tom, my anxiety about the Otway Basin is more based on the scale of the opportunities. You know, I think Otway works when you have opportunities that have significant scale. Hence, we moved away from things like Labella and Truffaut, which have risk and aren't of the scale that can deliver value in return. So our focus really for things like in the old way is to make sure that we have line of sight that scale is sufficient to cover a range of uncertainties. You know, the gas can be observed through the seismic image, but the single well developments always have that risk of downside outcome. And certainly, I can be frank, you know, the outcome at Enterprise is certainly significant. given me right to look much, much harder at what we're going to do with our capital moving forward across the broader offshore railway basin.

Okay, thanks Brett. Can you please outline the pricing upside that Beech might be able to extract across the gas portfolio in fiscal 26? I recall there's some legacy Cooper Basin joint venture gas rolling off, but I was hoping you could just confirm the whole suite of assets and volumes that either reprice or they face spot exposure from fiscal 26.

Yeah, so we actually have in excess of 50 terajoules a day that come off long-term contract out of the Cooper Basin by the end of FY25. We also have volume coming out of Enterprise that finishes contracts during the end of 2026. So we have additional volume coming from there that should be able to be pushed to spot. So those of you who followed a cooler winter in Victoria over the last few months have noticed the fantastic pricing we've been able to achieve through the winter months associated with that volume and through peak summer as well, we get that price. So the East Coast has become a a very seasonally dominated environment, and my ambition is to drive more and more of that volume. This year, on average, we've been doing about 32 terajoules of gas into spot markets across the east and west coast, where of that 32, effectively 30 of it goes into the east coast spot market. And we've been able to achieve... higher prices than our $9.50 average across our portfolio. So we see significant value upside. And then with regards to scale, it's about getting that at the right time. So hence, we're looking at things like storage so we can utilize some of those lower pricing months, getting some volume into storage or holding it back, and then chasing that through the peak periods. Thanks, Brett.

I appreciate it. Thanks, Tom.

The next question comes from James Byrne from Citi. Please go ahead.

Thanks. Good morning. So enterprise, look, when you work with NSAI on that reserves audit, you're obviously going to have a forecast for production, notwithstanding the uncertainty around nominations, how would you describe what that production is going to look like beyond FY25 where you've maintained guidance for that financial year?

Yeah, so we should see no impact to production through our guidance from Enterprise this year. Enterprise can hold up. It's really the tale of Enterprise is shrunk more than the field has got fantastic deliverability. So it's not really a FY25 or dare I say for the majority FY26 of a production downgrade. The production will come off a bit harder following, at the end of FY26 and through 27 onwards.

Got it, that's helpful. Okay, I want to come back to Tom Allen's question earlier. Now, the 31.5 million barrels reserves downgrade by perhaps liberally round up is two years of reserves life. It's also the breadth of the underperformance of assets that I think is a bit concerning. Now, you rightly talk about earning that right to invest and you haven't been shy around the potential for deals. I'm just wondering what the scale of that deal flow has to look like in the future to be able to dilute the underperformance of the portfolio that's unfolding today. And if I perhaps press you on Tom's question around what that means for the 40% to 50% payout ratio, because I would have thought that the scale now of deals that needs to be done does actually require equity participation. And that would be in contrast to a potentially 50% payout ratio.

I think the reality is, James, over the foreseeable future, I'm going to be really focused not on acquisitions, but really about getting the based business operating as lean and as efficient as we can. We still have a very good balance sheet. So, you know, after we can get the cost base in the right place and we get the organisational right, we've got some decisions that we can make. And I still really strongly believe, given our scale of our franking credits, that delivering value to shareholders is important. And I'm going to look through a very critical eye about any form of acquisitions only to be short of accretive. So I guess probably since I spoke to the market through the strategic review, I'm probably going to play a more conservative line on acquisitions at the moment, really focus on getting the business fit and right and continue to deliver that cost out as I've promised. You know, so, you know, our balance sheet is still a strong, very strong, in fact, to be able to fit things into the future. But I want to see weights here come online, the free cash flow out of weights here. I want to see the final $2 seen wells come online and see how they perform, given they look like excellent wells, to make sure that I've got a strong, robust narrative that I can give to the market and clearly make sure that we can get past this period of reserve write-downs.

Excellent. Thanks so much. I appreciate that.

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

Yeah, morning, Brett and Marie. Just back on the reserves, I mean, I would have thought 2P reserves sort of meant to be more like P50 outcomes, but obviously the reserves just keep falling. Are you making any operational changes here or just any thoughts here? Because obviously it's important for future valuation and cash flows of the company?

Yeah, so through the organisational change, I've done the dominant part of the executive team of being changed out, including bringing Bill Ovend in and as the head of subsurface. So those new sets of eyes have been really helpful for me. And given my technical background, I've put a very discerning look over the portfolio, in particular the reserves, and we're working on making sure that we strengthen all our processes and systems and procedures within the organisation in support of that. You know, whether it be through NSI or any of the other independent experts, we all effectively highlight, or the organisation effectively highlighted the same risk at Enterprise, which is when you have gas on rock and you're not sure where the water is, but you had gas pressures well below the original aquifer gradient, there was a level of uncertainty associated where that water was. And only production kind of effectively can resolve that, or the other thing is you could do is drill more wells. And it kind of goes to the heart of the challenge I see with small developments in the offshore If you don't have enough scale, you can never afford to drill enough wells to properly de-risk it. So you enter a development with a kind of a very broad range of uncertainty. And I would agree. I think we seem to be having a run of some downside outcomes across a couple of parts of our portfolio. So I'm making sure that I'm doing a detailed look back on how we've got to where we are and what we need to do to further add strength to our systems and processes through bringing people like Bill Overton into the business as well as Glen White who starts in the next few weeks.

Okay, that makes sense. Just a second question. It looks like about just under half the FY25 capex is going into the Cooper Basin, JV with I mean, are you expecting that asset to improve in the next one to two years in terms of production and any sort of update around cost structure there with Santos you can talk about?

Yeah, so I'll leave Kevin to really talk through the cost. I've had some great engagements with Santos, both at working level as well as directly with Kevin on cost. He's got a really strong agenda. We haven't included any of that cost reduction in our portfolio, but I'm pretty excited about what Kevin intends to do across the broader Cooper Basin, or I guess Brett Daly will be doing it for him. But they are working really hard and we're trying to support them as best we can. We've been able to deliver a significant cost out of our portfolio. And I think, you know, with all these inflationary pressures we've seen across the market, you know, we all have to respond. So, you know, I'm confident Kevin can deliver it and Sandos can deliver it and they've They've given us significant material now that we're analysing in terms of their pathway to increase production and lower costs. We're effectively just taking a view of flat production across the Cooper and no cost out within our numbers. So anything that we can achieve out of Santos, the operator, across their CBJV is upside to our numbers.

Okay, that's good to hear. That's all for me. Thank you.

The next question comes from Dale Coenders from Baron Joey. Please go ahead.

Good morning, Brett. I was just wondering, in terms of your free cash flow break-evens for 25, how are you thinking about 26? It was previously meant to be sort of momentum to lower free cash flow break-evens. But now that you've got potentially enterprise declining production in that year, sort of do you still think there's momentum with cost out and wait for your startup to go lower?

Yeah, so looking crystal balling through to 26, we still expect it to go lower, just including on our current production post-enterprise outcome. So with weights here and everything, we should be able to drive that lower. I still want to focus on efficiency through the business, but we're line of sighting to seeing a number lower than 30 through FY26 and beyond.

Okay, and then maybe just a second question just on non-core assets. Is there any updates there, Bass Basin and New Zealand, both flags non-core for a while now?

Yeah, so interesting. Well, I think we talked a bit about doing some work at Bass. So recently we've run an asset job through Bass and it's been producing around 20 terajoules a day. So that was a nice operational benefit that we saw through Bass. I think the key thing for me is I'm not spending any real money on it. That was just a small bit of OPEX that we deployed to get a blockage around a well. Interestingly for Bass, I think maybe I mentioned last time, Dale, that I was worried that some of these issues were mechanical, but it feels like it's just an issue across scale on some of those wells. So we may be doing a little bit more asset across some of those wells to make sure we can grow because all of the BAS volume we get, we can deploy into spot markets. So that is also helpful. Across Coupé, Coupé delivers a strong free cash flow. I don't want to spend any money there because of the political situation. And the reality is, I think the running for other opportunities across New Zealand is quite small. I guess it's... I'm really... You know, this is kind of a call-out to anyone who's maybe listening. If you're interested in buying anything at Coupé, In New Zealand, I'm more than happy to have a discussion about Coupé. I think since I've highlighted that Coupé is non-core, there really hasn't been a pile of people running, knocking the door down to have a chat. So what I'll do is I'll run the asset for value. It delivers really strong free cash flow. I think it's really just lacking that clear political support and really lacking that kind of running room at the moment to deliver long-term sustainable growth.

Okay, thank you.

The next question comes from Nick Burns from Jarden, Australia. Please go ahead.

Hi, Brett and Anne-Marie. Yeah, my first question is just on weights here. Brett, you mentioned that some of the buffer has been eroded and there was a risk of further slippage from here are there any activities you're focused on in particular that could see first gas pushed further to the right or is it a more just general view on overall productivity levels that have you concerned there well two things i think last time we spoke i highlighted that i wanted to see gas into the plant by the end of july um and now gas into the plant's not coming till september so that kind of circa six weeks is a kind of a i think a

A bit of a six week risk to to a to a kind of a January one date. You know, if like if you were to think of our guidance as on the optimistic side as as being a January one, that's been a bit of a risk element now. What I say Mitsui and working on things running in parallel, so we're we're trying to rather rather than execute everything in series, do things in parallel. So there's still great opportunities for very early. January date, but I think the reality is we're probably facing in the order of about six weeks delay from from our, you know, the most optimistic view of our guidance being a January one. So, you know, that's. I think outside of that, effectively, the plants will build 80% of it in custody of the commissioning team. You know, bringing gas into the plant will help close in on those key things. We started commissioning of flow lines. We started commissioning of compressors. These things are demonstrating that materially the project is just about there. I'm not sure if you had a chance to look at it yet, Nick, but we've put a little bit of a slide in to demonstrate what I think are some of the key milestones between now and first gas. I think the benefit for me is having in the market is now that I can come back and talk to it. I would say keeping your eye on the timing of first gas entering plants is an important milestone for the asset to deliver. And that helps us steer for the subsequent pieces. But, you know, there's, you know, really we've got buffer in our CAPEX to be able to survive the full scope even longer than our garden. So I don't have any risk really against CAPEX. And I think what we're talking about now, getting close to the end of weight zero, is we're talking weeks, not months. That's kind of where we are in terms of having a clean line of sight to first gas.

That's clear, thanks for that Brett. And then maybe just a follow up on your next phase of Otway drilling. I appreciate you taking another look at the program given the recent reserve downgrades that have occurred there. But the next phase could be reasonably significant and potentially could commence in around 12 months time. I'm just wondering what you can tell us about the next phase. How many rig slots has Beech committed to? When do you think it's going to start? Any sense of scale of investment? And when do you think you'll be in a position to provide us with more information about this program? Thanks.

Yeah, so still working through all those issues at the moment. You know, we have a campaign of five statutory abandonments that we have to do as part of that campaign. And then we have a... a couple of exploration wells that we'll be looking at. And we've talked about Mavis and Hercules potentially, or most probably, taking those slots. You know, why I pivoted to those was really about chasing the volume. They're well beyond things in terms of scale than Labella and gives us a lot of running room. And, you know, I worry about things that are small in the Otway, just, you know... Enterprise is a classic example. There's a huge value in enterprise still remaining. The upside has been significantly pared back with the reserve outcome, obviously. So we want to make sure that we've got things at the right scale. So probably later this year, not committing to any date, but I'll come back to the market and give an update on the Otway program. I might expect to give that update before year end. Sorry, calendar year end, I should say.

Got it. Thanks, Brett. The next question comes from Gordon Ramsey from RBC Capital Markets. Please go ahead.

Thanks very much, and good results against our numbers. Just very quickly on the outlook, Brett, I guess one of the things is the reserve downgrade. I just want to feel comfortable that we're not going to see another impairment going forward on that. Is that covered in the current impairment that has come through in terms of specifically enterprise?

Yeah, yeah. So we've got plenty of headroom in enterprise, I think is the short way to say it. So there's no impairment coming for enterprise.

Okay, and then the other question relates around weights. I mean, just listening to some of your commentary about a clear line of sight for first gas, buffering the capex, and you're talking weeks, not months. Why hasn't the capex guidance been narrowed then from 600 to 650 down to a tighter range?

I just didn't think it was prudent to do it at that time. We've still got to go through commissioning. So it's just... I believe it's a reasonable range given where we are at the moment.

Okay, thanks. Actually, it's good that you haven't changed it, to be honest, in terms of the timing and the cost. So thanks for that.

Yes, thanks. The next question comes from Sarah from Morgan Stanley. Please go ahead.

Good morning. This might be a question for Anne-Marie. I was just wondering if the $1 billion of non-cash impairments that you've previously announced this year include the additional $12.5 million bullies of reserve downgrades that was disclosed this morning?

Hi Sarah, thank you. As Brett just previously mentioned, Enterprise, we don't need to recognise any impairment charges or write downs in relation to Enterprise or the Greater Otway Basin. We have a lot of headroom in that asset. It's a highly accretive asset. So we haven't added any impairment charges in relation to that and don't expect to.

Okay, thanks. And just one more question for you, Anne-Marie. So with the gearing, you've highlighted 25% is the upper limit through the cycle that Beach is comfortable with. How long would you anticipate being in that area for?

So I guess from a standard operations perspective where we are now, we sort of think that staying at around the 15% is prudent. It would depend on the size of the opportunity as to whether we were comfortable to go to 25 or above that and how long we'd stay there for. But, you know, as Brett talked about, it all comes down to the opportunity ahead of us and the scale of that opportunity. But obviously, we would want our acquisitions to be able to sort of de-gear quite quickly as well if we were going to go to 25 or above.

Okay, great. Thanks.

The next question comes from Henry Mayer from Goldman Sachs. Please go ahead.

Morning, all. Just back on reserves. I just wanted to confirm whether the additional 11 million BOE downgrade since June was allotted to Enterprise, or has there been another downgrade to LSE North? Sorry, Brad.

No, just Enterprise.

Okay, great. And so no change to the confidence in thylacine west volumes?

No, no. I had a good look at those the other day with the team as well to reaffirm that. Thylacine west within the broader thylacine structure as well is much better understood. There's obviously ranges of uncertainties within any development, but they look pretty solid wells to me, to be fair.

Got it. Thanks, Brett. And in the Cooper Basin, I appreciate Santos might provide an update as well, but perhaps just for now, it seems the JV is targeting flat production with some significant cost-out targets. You've also got a slight reserve downgrade there too. Could you share the key field development priorities over the near term? What might be driving that reserve downgrade and how the granite wash could fit into the plan?

Yeah, well, I'll leave Kevin to talk to... Beaches expecting flat production. I'm not sure what. So that's how we've modelled through our portfolio. And with, you know, ground washes, obviously, we've got some wells coming in this coming year, which look really interesting. They seem to be good high deliverability wells. I think the areas that the joint venture are really focusing on are those far field locations that are relatively high operating costs and not contain significant volumes. So I think there's an opportunity to kind of simplify some of those operations. And I know that's really at the heart of where Santos have been focused on looking through their CBJB operations.

Great. Thanks, Brad. Maybe if I can squeeze in just a final one on the Cooper Basin. Just any updates on the scope remaining to commission Moomba CCS? and how you might be planning to maximize the value of the credits against Waitsea or Otway, for example?

Yeah, well, effectively, member CCS, well, the plant is effectively built. They're running dry CO2 into the turbines to commission the turbines at the moment. So, yeah, the timeline to first injection is getting very close. You know, again, that's, stand off the operator, I'll let them um wave the flag on that one you know i'd be keen to get up there shortly and have a good look at it myself because it's been such an exciting project um with regards to um the credits yeah you know we have a period of having um credits in excess of our requirements um and we're looking through how to best maximize value out of out of those in the short term We do have safeguard mechanism obligations across different parts of our portfolio, so we're looking at how we can play the most value through member CCS. Thanks, Brett.

The next question is from Saul Kavonic from MST. Please go ahead.

Hi. Thanks, Brett. Thanks, Anne-Marie. My question just comes, I guess, more to the general outlook. I think the market was hoping for the Band-Aid to be fully ripped off at the Strategy Day two months ago. You've highlighted, obviously, the reserves downgrade at Otway here and that buffer headroom at Waits here are moving. But I guess outside those two items, do you still consider the outlook that you've put out at the Strategy Day to be on the more conservative side side of things and could you perhaps just touch on have you had a look through what the consensus outlook is because when i look at for example va consensus they still got 26 or so million barrels of production fy26 where i think you indicated only two months ago it'd probably top out closer to 25 so just how you're thinking about where market expectations are versus the conservatism of your outlook yeah um so i think in terms of fy25

I think we've done a lot of work with the market to make sure that we get consensus as close to where we are responsible. So I think I'm very comfortable where the market sits, FY25. I think my comments about where production will top out, I think, well, are still valid. So I don't have any particular concerns about that piece. And, you know, so that's obviously less than that number you mentioned before. I'm not sure what analysts suggested that. But I think the issue you're kind of alluding to is the Band-Aid fully ripped off. Obviously, this has been a very disappointing outcome for enterprise for me. What I've tried to do is move as fast as I can. As soon as I saw something that didn't feel in line with what was out in the market's lens. So we've effectively had to still a double step on getting that one fully resolved and pulled through. So I'm very comfortable where we are as a business now, making sure that I think the market is fully informed across all our assets. I really don't see much downside to our business at all. Our current production for this calendar year is looking excellent, given the winter we're seeing in Victoria. So we're seeing really strong production and our assets standing up and you'll see that through the AMO data. Excellent production we're getting out of our Victorian assets. So we haven't seen any downside across any of our portfolio and it's always good when you have a look at your daily production profile and every asset and everything is green and has been green all year.

um you know i think i think there is a healthy level of conservatism associated with our numbers that are currently in the market and just to follow on to that uh obviously you know you've come in um and bill's come in uh any reserve changes going forward i know i'm asking the same question again but are you really confident now and is bill really confident now in the 2p numbers you have out there and uh you know so if there's uh there's a downgrade i mean Do the market now hold you and Bill responsible for anything from here? Whereas up to this date, we can say, well, this is the hand of cards you've been dealt coming in.

Yeah, and I've felt personally very focused on understanding every molecule that we have in our portfolio. So I have gone and hence put a lot of focus in understanding where we were. I didn't want to go to the market with an overstatement of reserve reductions, absolutely. So I feel very comfortable that we're, you know, that I can stand behind everything moving forward in terms of our 2P numbers across our portfolio. You know, I think the ultimate test across the full portfolio is probably when we bring weights here online, but the weights and numbers for me, We've taken reductions previously. They look very solid. We're getting good well outcomes. So weights are on line is probably the biggest test for us in our kind of currently not in production major reserve piece. But the numbers look solid for me and I'll be obviously standing behind what we've taken through audit and the numbers moving forward. So yes, Sol, you can blame me for anything moving forward.

Great, thanks. I think that's all we want to hear. That's all from me.

The next question comes from Matt Chalmers from B of A Securities. Please go ahead.

G'day, Brett. G'day, Anne-Marie. Thanks for your time. So just sticking on the wait here, just a quick question from me in terms of the pending export license expiry in 2028. Just want to get some thoughts in terms of how you considering dealing with that given, you know, given the six-week slip now, it's in terms of first gas, you know, how are you thinking about calling back some of those cash flows that deadline approaches?

Yeah, so we've been, the joint venture through Midsui have been working with the regulators in Western Australia and the time we're getting out of them, it's a They're supportive of us getting our commitment of 7.5 million tons of volume away. So we're just having those conversations and we're working through that. And I think that's probably one element that we want to make sure that we can come to a good agreement with. The other one is obviously being opportunistic with the swap cargoes, delivering the condensate cargo and the two LNG cargoes so far. We're still working with Mitsui on delivering additional swaps. anything we can do to accelerate cargoes into the current window is really good for value for the joint venture. So we're working on those elements as well. So I can't, you know, the Premier of Western Australia needs to make a decision about the former part of that comment that I just made. So, you know, we'll continue to work through the joint venture to make sure that the Western Australian government get the information they have so that we can deliver as promised through the White Sea project.

Thank you. That's it. Thank you. The next question is a follow-up from Sarah Kerr from Morgan Stanley. Please go ahead.

Thanks so much for giving me that question. So I was just wondering with Enterprise, if the pressure gradients that you did get from the exploration wells indicated a higher gas water contact or if the beach team was putting more weight on the seismic interpretation?

Yeah, so there's nothing from the exploration wells that indicated where the water was at all at Enterprise. So, you know, we had pressure samples through the through the main reservoir. And what it did highlight is that we had gas on rock deeper than the known or the regional aquifer gradient. So there was some evidence that we were in a different pressure environment. And then what the team tried to do is correlate the amplitude shutoffs and velocity to the structure. So they had effectively arranged. The low case was effectively a couple of metres below where the gas was intersected by the well to the high side, which was the maximum extent of closure to the spill point with amplitudes. So that gave it a broad range. And yeah, so we're within that range, but much closer to the water being just below the not just below, below the gas on rock point of the well.

Okay, and I was just wondering if the team will be taking a more conservative view, weighted more towards a P90 outcome for future development. Obviously, you have reserves based on ranges that have previously been a bit, probably too optimistic at the P50 level.

Yeah, so just, so the, obviously, This field was FID'd on the basis of P90 reserves. Hence, though that we've got a reserve downgrade, there is no impairment or no value at risk here. We still have plenty of headroom associated with the enterprise field. What we've done is we've trimmed, obviously, the longevity of enterprise, not the near-term value of enterprise. We'll always take the view of being an FID project on a conservative volume. And I think for me, understanding scale, scale is a critical factor in anything offshore, that you've got a big enough opportunity that has value given the risk.

Thanks so much.

Yes.

Thank you. At this time, we're showing no further questions. That does conclude our conference for today. Thank you for participating. You may now disconnect.