Thank you for standing by, and welcome to the Beach Energy Limited FY 2023 Half Year Results Call. 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 Mr. Morné Engelbrecht, Chief Executive Officer. Please go ahead. Thank you, Darcy. Morning and welcome to the FY 2023 H alf Year Results Presentation for Beach Energy. My name is Morné Engelbrecht, and I'm the Chief Executive Officer here at Beach. Joining me on the call today is our Chief Financial Officer, Anne-Marie Barbaro. We're also joined by the Beach executive team. For today's presentation, I will first provide an introduction on the recent activities at Beach as we progress towards our step change in production and free cash flow. Then it will be over to Anne-Marie, who will give an update on the financials, including the new dividend policy that we announced this morning. Then I'll provide some insight into the forward outlook for our portfolio as well. Following that, we will open the lines for Q&A. Slide two is our compliance statements, which I will leave to you to read in your own time. Onto slide three. We have been working hard in the first half of FY 2023 to progress and de-risk our major growth projects. I want to highlight the following key messages from today's update. First of all, Beach is growing its gas and LNG business. There's been good progress during the first half in FY 2023 on this front. Over on the East Coast, we are planning for the connection of our Otway Thylacine wells in the coming months, which will allow the Otway Gas Plant to produce at its nameplate capacity of 205 TJs per day. This milestone will be the first catalyst for the uptick in our production and cash flows that we have been forecasting over recent years. The Enterprise Nearshore well is being connected to the plant, and we now expect to be ready for first gas mid-FY 2024. On the West Coast, the Waitsia development drilling campaign is now complete. Plant construction progressing and agreement reached with Webuild to take over the construction of the project from the administrator. Webuild and the JV are targeting first gas by the end of this calendar year. Beach is growing strong free cash flow. Once we complete the Waitsia gas plant, we will have eight gas plants supplying local and international markets. Strong and diversified cash flow will position us for enhanced, disciplined capital management, delivering increasing returns to shareholders while continuing to fund future growth. Our strong balance sheet allows us to invest in future growth beyond our major project pipeline. With AUD 609 million in available liquidity and increasing free cash flow, we are able to fund new gas projects and other growth opportunities that are necessary beyond FY 2024. Today, we are planning drilling in each of our operating basins. This includes our much-anticipated Perth Basin exploration campaign, which has already delivered one success from two material operated wells. While the Beach operated campaign begins in Q4 this financial year. Finally, as we all know, the energy transition is underway globally, with Beach supporting this through our investment in gas, CCS and other abatement and new energy initiatives. We know that demand for natural gas is not going to disappear soon. We also know that our industry must decarbonize. Beach is doing this today primarily through our investment in Moomba CCS, but this is just the beginning. We have a 35% emissions intensity reduction target for our portfolio. We are investigating new energy opportunities that will support our business as those new markets emerge. I hope you will see today that Beach's plans are progressing and as our free cash flows and production increases materialize, Beach is looking forward to the future while rewarding our shareholders for their loyalty. Moving to slide four, there's nothing more important to me than the safety of our people. Beach's agency performance in the first half began with a few minor safety incidents. However, I'm very pleased with how the team has responded. Pleasantly, two of our sites have just recorded major milestones. Otway Gas Plant achieving eight years and Beharra Springs achieving four years recordable injury-free. We've also just clocked up three years without a lost time injury in the Western Flank. Well done to those teams. We've also seen a strong period in our environmental performance to date. I also want to give a shout-out to the Dombey survey team, who received the South Australian Premier's Award for Energy and Mining in the environmental category. This was for their approach to using new technologies to eliminate the need for land clearing during the Dombey seismic survey and the SA Otway. Congratulations to the seismic team. Going to slide five and our first half financial results. Beach performance was largely driven by lower production and sales volumes, while sales revenue were up 3% at AUD 813 million. EBITDA was down slightly at AUD 491 million, while underlying NPAT was down 10%. In line with our newly announced dividend policy, you will notice today that we have implemented the policy and confirmed the AUD 0.02 per share interim dividend, a doubling of the AUD 0.01 per share dividend Beach has paid for many years. With more than AUD 500 million in franking credits available, there's still more to come. Turning to slide six, less than two weeks ago, we provided our FY 2023 second quarter update. Since that time, there have been two important milestones achieved on our key growth projects. First of all, the Beach Environment Plan was approved by NOPSEMA for our offshore Otway well connection activities. This EP allows for the remaining subsea work to be completed with the Duff subsea vessel now on location. Once the Thylacine wells are commissioned and connected to the Otway Gas Plant, it will allow for an additional 100 TJ a day to be available for the east coast gas market. The second major development of the last two weeks was the news that Webuild will take over construction of the Waitsia stage two project. This is part of their broad acquisition of Clough. Beach provided an update to the market at the time, including a modestly increasing CapEx guidance range. When you consider the possible alternatives from the voluntary administration process, this is the best outcome all involved in the project could have hoped for. This news and the Thylacine EP approval move both projects closer to completion, which will allow for Beach to deliver the step change in production and free cash flows from FY 2024. Turning to slide seven, which provides a further summary of the milestones achieved across the business so far in FY 2023. Perhaps most notably, back in July, Beach completed its largest ever drilling campaign, the largest ever in the Otway Basin's history, with gas now flowing from the Geographe wells. As mentioned, we are now progressing the Thylacine well connections as well. In New Zealand, negotiations are progressing for a rig for our forthcoming Kupe Development Well, which we aim to drill at the end of 2023 calendar year. We also announced a new emissions intensity reduction target of 35% by 2030 as we progress the Moomba CCS project with operator Santos. I've already touched on the Webuild transaction with develop and drilling complete and our SBA in place with customer BP. Our third basin exploration campaign has also already delivered one discovery within the Tui operated Gennatrix well, and we have some exciting prospects ahead in the Beach operated phase of the campaign, which kicks off in early April this year. It has been a productive period for the first part of FY 2023, and that is despite some of the headwinds that Beach and our industry has faced. We look forward to continuing this momentum as we move towards the end of FY 2023. Moving to slide eight. Today, Beach has unveiled a new dividend policy, which Emery will speak to in more detail shortly. Over many years, Beach has demonstrated financial discipline through our philosophy of diversifying revenue streams, prudently managing the balance sheet and ensuring sufficient liquidity for growth and dividend payments. This philosophy is reflected in our capital management framework, which put simply, has three objectives: maintain balance sheet strength by targeting to keep net gearing below 15%, reward shareholders through our new dividend policy, which will recognize increasing cash flows and utilize our substantial balance of ranking credits, currently more than AUD 500 million, and continue to invest in growth both from within our existing portfolio and other opportunities. We trust this framework and the dividend policy provides more transparency as to how Beach will manage capital and how we will fund growth and higher returns to shareholders going forward. On slide 9, looking to the second half focus areas for Beach. In the Cooper Basin, we are focused on clearing the backlog of Western Flank oil connections. We are then also focusing on development drilling for the remainder of the year. This should see us delivering an uptick in Western Flank oil production with oil prices on the up as the second half progresses. Connecting the Thylacine wells into the Otway Gas Plant is also key. As I said, the Duff vessel is now on location and we remain on track for first gas mid-year. Meanwhile, we look to make an investment decision on the next phase of Otway Basin drilling as well. We look forward to sharing details once the investment has been sanctioned. At Waitsia stage two, we are working towards keeping the project on schedule towards first gas by the end of this year. Our Beach operated exploration campaign at the Perth Basin is expected to commence in early Q4 of this financial year with the spudding of Trigg 1. We'll go into some further detail on that campaign a bit later. In New Zealand, we look forward to signing up the rig for the Kupe development well, which we are planning to drill before the end of the year as well. Turning to slide 10 and our FY 2023 guidance update. Today, we've lowered our production guidance from FY 2023 to 19-20.5 MMboe. Narrowed CapEx guidance of AUD 900 million-AUD 1 billion and increased our operating cost guidance of AUD 13.75-AUD 14.75 per BOE. The lower production guidance reflects unplanned challenges that occurred in the first half when then impact production in the second half of the year as well. We remain confident that the material step change in production and cash flow will arrive in FY 2024. We will no longer be referencing the FY 2024 production target as the production target remains subject to timing of major project delivery, which has in recent times been impacted by the Clough administration process and regulatory approval uncertainty. FY 2024 production guidance will be provided with full year results in August 2023, as is normally the case, in which time we will have greater certainty and clarity on both Waitsia start up and the Otway well connections. Capital expenditure guidance reflects high estimates for Waitsia stage 2, offset to a degree by efficiencies achieved in other programs. The outlook for operating costs reflects industry-wide cost inflation, as well as higher Cooper Basin JV costs as advised by the operator due to increased workover activities and unplanned maintenance. On slide 11, I want to give you a clear picture of what we expect to deliver on the east coast gas market as we complete the Thylacine well connections. Beach is uniquely positioned as a domestic-focused producer on the East Coast, we will increase our market share to 16% in FY 2024, up from 12% currently. This is underpinned by production from Thylacine wells, which will enable Otway Gas Plant to meet its nameplate capacity of 205 TJ per day. We also have the Enterprise well to connect with FY 2024 and further opportunities both nearshore and offshore, including the existing Artisan and La Bella discoveries that can be developed. Our message here is the Alpha Gas Plant will become a core driver of Beach's production and cash flow step change. We have a plan to maintain high production levels for many years into the future. Slide 12. Moving to the West Coast. Beach is already contributing to the WA domestic market through our Beharra Springs and Xyris gas plants, which together delivered a 22% production increase in the half. We are committed to WA domestic gas market, evidenced by our investment in exploration, which we hope will provide more supply certainty to the market in future years. At our Q2 results, we reported the news of our reserve revision. That does not change our commitment towards LNG nor domestic gas. Like you, we are, of course, eager to see the first LNG cargo delivered to our customer, BP. Our JKM Brent pricing structure will deliver the type of revenues that you would expect from the current market conditions. As we stated previously, for confidentiality reasons, we can't disclose details. What we have done here is provide illustrative pricing ranges based on Brent and JKM prices over the past year. Hopefully, what this chart demonstrates is that there is a premium pricing ahead for LNG cargoes, with this revenue stream to continue through to the end of 2028. On the Perth Basin, my message is that no one else has the reserves, the assets, the prospectivity, and the capability to deliver like the Beach and Mitsui JV. Beach intends to capitalize on our dominant acreage positions in the Perth Basin for the full benefit of our shareholders and our gas customers, both domestically and overseas. Turning to slide 14 and the Beach's progress on emissions reduction. First, a quick mention of the proposed changes to the Safeguard Mechanism. While there is still more detail required before Beach can fully understand any direct impacts to our business, its focus on emissions intensity reduction is broadly consistent with Beach's ambitions to drive down intensity by 35% by 2030. We are already actively pursuing the policy objectives through emissions reduction activities across our portfolio. Beach has commenced the select phase on Otway Basin CCS proposal. This would be Beach's first operated CCS facility. Meanwhile, in the Cooper Basin, we are near completion on a pre-feasibility study on ammonia production. While at Kupe, we are participants in a study on wind power generation using our offshore facility to gather data. As you know, we are investing in one of the nation's biggest emissions reduction projects in Moomba CCS. Operator Santos tells us the new facility is about 40% complete with the first CO2 injection currently anticipated in 2024. It was pleasing to see the federal government's CSAP review highlighting the important contribution that CCS could make to limiting climate change. Let's hope this is a sign of more things to come as the CCS skeptics start seeing the growing evidence base for this important technology. I'll hand over to our Chief Financial Officer, Anne-Marie Barbaro, who will provide an update on our financial performance for the half. Anne-Marie? Thank you, Morné. Good morning, everyone. Thank you again for joining us today. This morning, I'll take you through the financial results for the first half of FY 2023 and provide an overview of the new dividend policy, which we're pleased to announce today. Beginning with slide 15 and our key financial metrics. Our first half FY 2023 results were influenced by a reduction in production and sales volumes as we continued to deliver our key growth projects. During the half, Beach recorded higher sales revenue of AUD 813 million, up 3% on the first half of FY 2022, with higher realized prices offsetting lower sales volumes. Underlying EBITDA and NPAT were down with an increase in cost of sales, in part, the result of the current higher cost environment. Gas sales accounted for 41% of our sales revenue mix, with liquids accounting for 59%. We also ended the half in a net cash position. Moving to slide 16, which shows a comparison of the first half FY 2023 underlying NPAT to the corresponding prior period. The 10% reduction in underlying NPAT was driven by a few factors, including lower production and sales volumes, which includes a one-off non-cash impact on sales volumes and revenue in the 1st quarter of FY 2023, driven by a change in contractual terms on Cooper Basin liquids, which resulted in a revised revenue recognition point. This is not expected to have a material impact on full year FY 2023 earnings. Higher cash costs are primarily driven by an increase in third-party purchases, both through increased volumes and higher prices, as well as a 14% increase in field operating costs, which were mainly the result of the heightened inflationary pressures, as well as higher Cooper Basin JV costs as advised by the operator due to additional work overactivity and unplanned maintenance. Higher financing costs were driven by a non-cash increase in the unwind of discount on restoration provisions as a result of increased long-term bond rates. These impacts are partly offset by stronger gas and liquids commodity prices and higher third-party sales realized in the first half of FY 2023. Slide 17 outlines our cash flow movements for the period, with cash reserves of AUD 189 million at the end of the half. Operating cash flows were AUD 404 million for the first half of FY 2023, and included within operating cash flows were income tax payments of AUD 97 million, compared with AUD 29 million in the prior corresponding period. We also saw elevated levels of capital expenditure continue in the first half of FY 2023 as we progressed our major growth projects. Of the AUD 527 million cash spend, AUD 217 million of this expenditure was to fund our major growth projects. Pre-growth free cash flow for the first half was AUD 84 million. This figure forms the basis for our dividend payment this period, in line with our new dividend policy. On slide 18, you'll see our balance sheet remains in great shape. We entered the half in a net cash position with AUD 609 million in available liquidity. This strong position enables Beach to maintain balance sheet flexibility, invest in growth projects, and deliver higher returns to our shareholders. As we move towards a period of strengthened free cash flow in FY 2024, once major growth projects in the Otway and Perth Basins come on stream, we have the capacity to deliver growth and pay higher dividends while retaining optionality when it comes to other growth opportunities. Turning to slide 19 and following on from Morné's comments earlier about our capital management framework, which aims to balance our growth objectives against improved shareholder returns. A core component of the capital management framework is our new dividend policy. After considering various capital management initiatives, Beach decided that a free cash flow-based dividend payout ratio would be the best way to provide increased returns to our shareholders. The policy has been designed to provide transparency, utilize our franking credits, which are in excess of AUD 500 million, and reward our shareholders for their ongoing commitment to our strategy as we yield the benefits of our major investment period. The dividend payout ratio targets a range of 40%-50% of pre-growth free cash flow. This is defined as operating cash flow, less investing cash flow, excluding acquisitions, divestments, and major growth capital expenditure, less lease liability payments. The board will retain discretion to ensure the broader capital management framework is preserved, in particular, target gearing levels during heightened periods of investment. The new dividend policy has been implemented and will take effect as of FY 2023, which results in an AUD 0.02 per share interim dividend announced today. We expect the dividend to grow in FY 2024 as our free cash flow step change is delivered. With that, I'll now hand back to Morné. Great. Thank you, Anne-Marie. I will now talk a bit more about the future outlook, including our plans for future growth across Beach's portfolio. On slide 21, Beach's exposure to five key markets. These markets all have strong fundamentals. We know that the east coast gas market will continue to face supply challenges, with AEMO predicting potential shortages in the near, medium, and long term. As I said in the past, we need policy settings that are geared towards getting more Australian gas out of the ground, not burdening gas producers and especially domestic gas producers like Beach, with more regulatory burden. On the East Coast, it would be remiss of me to not mention the potential damage to future investment which may be caused by the government's mandatory code of conduct and the reasonable price provision. There's much uncertainty to be cleared here. For example, any price regulation must take into account complex industry nuances such as exploration risk, significant capital required, and multi-decade investment horizons. As I said publicly before, removing investment uncertainty is imperative, as new gas supply is the only answer for low prices. In the West, we know the domestic market is tightening, just as Beach seeks to continue to grow its domestic gas share. In New Zealand, we see how anti-gas policy settings have created supply constraints at times when energy needs are high with continued reliance on coal. Once again, Beach will do its part to meet the needs of this tight market. Our long-time involvement in global oil markets extend to LNG markets as we complete the Waitsia project, where Beach has unhedged exposure to Brent and liquids pricing. Beach aims to continue to increase our share of these markets. As the world transitions to clean energy, our products will become more important than ever to global energy security. Turning now to slide 22, I want to give you a glimpse of our future, both plans and potential opportunities across Beach's portfolio. Starting in the Perth Basin and working clockwise, we begin with the Perth Basin exploration campaign in Q4, further series of Waitsia development wells to be drilled, and a Skipper 3D seismic is planned for FY 2025 to inform the future exploration and appraisal program. In the Western Flank, we will be drilling continually and targeting the Birkhead formation for appraisal and exploration potential, still to be pursued in the Namur. The Cooper Basin JV will stay busy with the drill bit with four to five rigs operating, targeting up to 100 wells per year. In New Zealand, the focus on the Kupe development well, which aims to bring the plant back to capacity. In the Bass Basin, our Prime seismic interpretation gives us more informed data on Trefoil, White Ibis, and Bass, all of which could be pursued as a further phase of Bass Strait drilling in FY 2025 and beyond. In the Offshore Otway, we have discoveries of Iris and La Bella to appraise for further exploration of Hercules, Anatolia, Thistle, Updip, and Themis provide potential further opportunities. Following the Enterprise, the Calico 3D seismic survey is planned for the nearshore Otway Basin, where we can use the existing Enterprise well plan to target nearshore opportunities. As you can see, there is significant opportunity across the portfolio to develop our existing assets, to explore for new reserves, and to fill our gas plants. Beach has the balance sheet position to make this happen. Looking deeper into these assets and starting with the Perth Basin on slide 23, I want to go into our achievements in the half, which have already been discussed, but our forward-looking focus is to progress construction of the 250 TJ a day Waitsia gas plant, continue the Perth Basin gas exploration program with the first Beach-operated wells, and to complete the select phase for Beharra Springs Permeate Recovery Project. On slide 24, we've laid out the current schedule for the campaign, which shows Trigg 1 to commence in early Q4. From there, the rig will move to Trigg Northwest and then Beharra Springs deep development well. From there, we have three further exploration wells at Tarantula Deep, Redback Deep, and Peacock, all targeting the Kingia formation. Beyond that, a number of follow-up wells are planned, which will in part be dependent on the outcomes of the earlier wells. For the Beach-operated acreage, we have 19 prospects and leads identified, and nine of these have 3D seismic data. We have contracted the Ventia 106 rig to FY 2024, which will initially drill up to the six wells of the Beach-operated campaign. We think this could be just the beginning though, and subject to JV and other approvals, we will target extending the rig contract to drill the follow-up opportunities mentioned. I look forward to updating you on the campaign throughout the year and we wish the team success. On slide 25, we drill down a bit further on and look at Trigg 1, which we see as being an on-trend with West Erregulla and South Erregulla discoveries. If Trigg 1 is successful, there's an opportunity for a sidetrack well to test the broader Trigg structure. Success at Trigg will also de-risk the southeast part of the basin. There's also significant follow-up potential at Trigg South, Quarter Slow, and the lakeside prospects. On slide 26, the Otway Basin is at the core of east coast gas growth, which increased production by 32% compared to the first half of FY 2022. Our priorities looking forward include the connection of Thylacine wells to the Otway Gas Plant, connecting activities for the Enterprise discovery, maturing offshore exploration to release prospects, planning for nearshore and onshore 3D seismic acquisition, and refine our CCS study for a potential 200,000 ton per annum facility. On slide 27, in the Bass Basin, we're progressing planning for Yolla West drilling in the first half of 2024. Also update Trefoil, White Ibis, and Bass resource estimates from the Prime 3D seismic survey, this will inform our development strategy for these opportunities. On slide 28, over the ditch, the Kupe Plant remains a highly reliable facility and an important part of the Beach's portfolio. During FY 2023, while we are finalizing negotiations on the rig contract, we're targeting the mobilization of the rig for Kupe South 9, which we aim to start by the end of 2023, subject to JV and regulatory approvals. Back onto dry land, slide 29 looks at the Western Flank, which has been highlighted by a high level of drilling success. We have 10 oil wells to be connected before the end of FY 2023 and continued drilling, which aims to increase production rates in the second half. As reported at the quarterly, the production performance in the Cooper Basin has been a result of operational impacts, not reservoir performance. Finally, to slide 30 on the Cooper Basin JV, where the focus is on the five rig campaign targeting mostly gas development. The JV has performed well in the recent quarter with Moomba production maintaining plateau, although a higher operating cost environment has been experienced by the operator, which is a material part of our increase in production cost guidance today. We are excited about the progress on the Moomba CCS project, which is reported to be 40% complete, as well as on time and on budget. Before I move to Q&A, I'd like to once again remind you of the key takeaways from today. First, we are growing our gas and LNG business. Our two key growth projects are progressing well with some important developments in the recent period. Second, Beach is growing its free cash flow, and starting today, we are rewarding our shareholders through our new dividend policy. Third, our strong balance sheet allows us to invest in future growth projects. The drill bit will be very busy at Beach in the coming years as we further develop our onshore and offshore plans. Finally, we will grow sustainably through the energy transition, and thus while our existing products are going to be needed for many years to come. With that, I would like to throw the lines open for Q&A. Thank you. If you wish to ask a question, please press star one on your telephone and wait for your name to be announced. If you wish to cancel your request, please press star two. If you're on a speakerphone, please pick up the handset to ask your question. Your first question comes from James Byrne from Citi. Please go ahead. Pardon me, James. Your line is now live. Your next question comes from Tom Allen from UBS. Please go ahead. Good morning, Morné, Anne-Marie, and the team. Just regarding the new distribution policy announced today. With the payout ratio defined on a pre-growth basis, can you share some detail on how the board intends to balance priorities between paying out stronger dividends versus investing in new growth that's additional to the exploration plans that you've outlined in today's presentation? Yeah, Tom, I'll let Anne-Marie cover off on some of the detail. At a high level, the board will manage that through looking at our growth program and our capital forecast and budget for the year ahead. It will balance that and obviously adjust for, you know, significant material projects, infrastructure projects, material drilling, material projects, and adjust the free cash flow on that basis before then calculating the dividend, which is set out at the 40%-50% of that free cash flow number. Maybe, Anne-Marie, you can cover some of the detail there. Yeah, sure. Thanks, Morné. Essentially, we've set up a range of 40%-50% of pre-growth free cash flow to enable sort of a steady state operational cash flow to sort of support both returns to shareholders, as well as continuing to fund major growth, noting that we do have strong liquidity. I guess the board has sort of included within that sort of a target gearing ratio that we'd like to stay below as well. It's just managing, you know, 50% of that operational cash flow, 40%-50%, to enable those dividend returns. Obviously, in periods where we are looking at potential major growth, the board may need to exercise their discretion to maintain our target gearing as we move forward. Essentially that growth capital that we're talking about is really major construction of facilities and major drilling campaigns. That's what we're sort of talking about when we talk about the major growth and then obviously M&A and divestiture as well. Yeah, sure. Just a little bit of extra color on that major growth regarding M&A. I recall last year you mentioned that Beach would consider new growth opportunities that could leverage your existing infrastructure. Is that still a key requirement for your growth pursuits, that are more at scale? Recognizing that tighter supply outlook on the East and now the West Coasts, with both regions now facing increasing government intervention risk, which areas present the strongest return profile and why? Look, I think in terms of the major capital that we're looking to employ going forward, obviously that still relates to the Whale Clear project, finalizing that and connecting the Thylacine wells. Beyond that, we are looking to further invest in our offshore acreage as we've outlined today in terms of the Artisan offshore and looking at how we link that in with the Bass development as well from an infrastructure point of view. Again, the main aim is there to have as much gas going through those plants into the east coast gas market, which as AEMO has reported, is gonna be short gas in the short, medium, and long term. in obviously bringing more gas to bear into the market, but also through our gas plants currently. In terms of major capital spent around our infrastructure, that's probably where that's going to come from. And then in terms of highest returns, I think when you look at our portfolio, and especially specific to your question, Tom, around the east coast gas market, we see that coming from Artisan offshore and Arthur near shore as well. I think when you look at our portfolio there, we've got quite a number of prospects. We've obviously got, you know, Artisan and La Bella, which we still need to connect up. But there's a lot of potential and running room left there for us to explore. If we look at how we develop that, then we can develop that in conjunction with the Bass Strait as well. You know, you start looking at some significant capital savings from that perspective as well. From a return perspective, that's probably high on the list of potential, you know, capital activities that we wanna look at. Then the continual drilling in the Western Flank and obviously Cooper Basin as well, that will feed into that market. Sure. That's clear. Just if I can sneak one more. You've mentioned a couple of times that the drill bit will be busy. What proportion, if any, of your planned growth in exploration and appraisal spend on the East Coast is subject to changes being made to this exposure draft legislation regarding the reasonable price provision? Look, the reasonable price provision is obviously impacts the east coast gas market. In terms of looking at our plans, if you look at the Bass Basin and the Artisan offshore activity, that will obviously form part of that, if that's the final mandatory code of conduct and the final sort of settling of the words there. You know, in terms of the way we look at it, you know, the east coast gas market is gonna be short gas. That's based on current forecast. That's without projects being delayed, potentially, due to regulatory, you know, policy being developed as well. That's very fluid at the moment. I think from our point of view, we do see an opportunity there to bring more gas to market in that setting. Okay. Thanks, Morné. Thanks, Anne-Marie. Thanks, Phil. Thank you. Thank you. Your next question comes from Mark Samter from MST. Please go ahead. Morning, guys. Just wondering if I could ask on the around the dividend policy framework, you guide to your view of the spending CapEx being AUD 310 million for the half, so annualize AUD 620 million a year. Can you just give us a feel? I look at my numbers, I look at consensus numbers a couple of years out, everyone's going at AUD 350 million-AUD 400 million CapEx for the whole business, we obviously have production tailing off with that. Can you just give a sense for what you're defining as that sustaining CapEx? Is that the CapEx that just is a lot of that just fixed asset CapEx that doesn't really dwindle with production? Just the profile of that number as we go forward, or is there a risk-? Yeah. we're underestimating go forward to sustaining CapEx? Yeah. Look, from a sustaining CapEx point of view, we do count in the Cooper Basin drilling. We've got, in the CB JV, as I said, we've got five rigs running there, Mark, that we see as sustaining CapEx that links to production. The more rigs we've got running there and targeting the 100 wells per year, that will support our production staying flat. Similarly on the western flank, we've got the one rig running. Then on the offshore side of things, that's mainly fixed operating costs in terms of maintenance costs that we're referring to there. That will be similar on the west coast as well, once we get that plant up and running. I think the... In terms of what we see as sustaining CapEx, it may be the variance or the difference there is that you've got five rigs running in the Cooper Basin JV, which we see as sustaining CapEx. Okay. Awesome. Thank you. I might just make one other quick question, if I can. I know we're dealing with a pretty large range on that illustrative guidance for the energy SPA. Just when you talk about, based off average Brent prices over the last three, six, and 12 months, can you just make clear traditionally energy contracts are obviously on a JCC or Brent, on a lag. I guess, A, can you tell us if your contract has that traditional three month-ish lag? B, if the indicative prices you used in that assume that same lag as well? Look, I think, in terms of what we set out there is trying to just show an average over those periods. It's traditionally, and as we said previously, Mark, the contract we have with BP is linked to JKM and a slope to Brent. We haven't said what that sort of combination is in terms of percentage, but we've tried to apply an average of that across the average of the prices that we've reflected in the slide there. It's just to give an indication of potential ranges. It's not a reflection of what you would expect, but it's trying to give more clarity around, if you look at the market over the last three, six, 12 months, that's sort of the pricing we would have looked at if we had energy going into that contract. Yeah. Okay, cool. Thanks, Morné. All right. Thanks, Mark. Thank you. Your next question comes from James Byrne from Citi. Please go ahead. Hi. Thanks. look, first question on gearing target being less than 15%. I look at the business, a lot of the riskier parts of the CapEx cycle are behind you. decent portion of your revenue, CPI link. your dividend policy obviously flexes with commodity prices. Is 15% really the most efficient number as opposed to, you know, a range such as 15%-25%? again, like, if I think about the history of Beach, Morné, you were CFO when you acquired Lattice and, you know, your predecessor as a CEO used to tout about, you know, how the debt funding of that acquisition and the gearing going to 25%, had created a significant amount of value for shareholders. Today's presentation slides, you've got M&A on there as an option for growth. I'm just wondering whether this 15% is a soft ceiling or not. Yeah. Look, I think, James, from a board perspective, in terms of setting that ceiling, obviously, you know, setting out the policy today, we wanted to set that ceiling there so that people can sort of know where we're going in terms of potential gearing, noting that obviously that excludes in terms of dividend policy, initially the major capital that we've spoken about. I think it's an appropriate target in terms of gearing from where we sit right now, with all the uncertainty that we're dealing with in terms of still having to complete the two major projects. Looking at what we invest in further in terms of further development as a buyer client in terms of Bass and Otway Offshore as well. I think it's appropriate for where we are at this point in time. you know, obviously the board can review that and adjust that as we go along and some of the projects are delivered and we've got more confidence in cash flows and CapEx going forward. I think for today it's an appropriate guide to the market. Referring back to in terms of what you've outlined in terms of the Lattice acquisition and the, you know, in terms of the debt funding of that particular acquisition, that was obviously done at those levels because we were comfortable with the cash flows that we were seeing coming out of the business. If we look forward in terms of potential M&A for us as well, and as we've said previously, we'll only look at the M&A from a value perspective. And if it doesn't stack up from a gearing perspective as with Lattice in terms of throwing out significant cash flows to de-gear us on a quick, you know, on a quickly from that point of view, then we won't do it, right? I think going to higher gearing levels would require whatever you look at from an M&A perspective to throw out significant cash flow so you can de-gear, you know, at a rapid rate. Yeah. Okay. That's very clear. Just on slide 22, which is the map with FY 2024 and 2025 potential activity. All of the offshore work, aside from one of those seismic surveys, is either expected or not firm. You've talked about policy settings needing to be more certain to be able to invest CapEx. Does that also pertain to your exploration expenditure? Yeah, look, I think it's across the board. In terms of policy settings, we do want further clarity in terms of how that plays out, especially on the east coast side of things. I think from a WA perspective, we are very comfortable with our exploration activity there and going ahead, like I said, with the 19 prospects we have from a Beach perspective and what we're going after in the initial round, we're very comfortable in terms of the capital we are playing there. Very comfortable with, you know, what that could mean from a domestic gas point of view and meeting our obligations there as well. And we're very excited about the growth potential in the Perth Basin from our, from our point of view. We've obviously got significant outreach there, significant reserves and us together with Mitsui, very keen to go after the exploration activity there. Similarly in, obviously exploration in Western Flank and otherwise in CB JV as well, keen to go after that. I think the offshore component has still got some time to go in terms of how we plan that and how we sort of put it together. Therefore, you know, you see the darker blue ones there expected, that's in the planning phase. The not firm is obviously on the cards, but that's further than the foreseeable future in terms of how we bring that to market. Definitely having clarity on the policy setting will help our decisions and how we view those prospects going forward. Okay. The question about gearing and exploration really just kind of leads me into a question about distributions, which is. There's obviously a lot of this uncertainty on East Coast gas markets, which might affect, you know, how much capital you're able to deploy in development projects or exploration. Maybe you don't find anything at scale in Perth Basin, and there's no guarantee you'll ever find anything to buy M&A-wise. In that sort of hypothetical scenario a few years out, your balance sheet's gonna be flush with surplus cash. I'm wondering whether you'd consider unlocking more of that franking credit balance via, like, temporarily higher distributions than what you've guided to today. Yeah. Look, James, that's a total theoretical sort of question. I'm hoping that we don't get there, that we've got great success out of the Perth Basin. Lots of development there and great success on offshore and Bass Basin as well. We can redeploy capital on those fronts as well because that is high returning, shareholders should want us to invest more on high returning assets. In that case, I would assume in your scenario the board will reconsider and relook at the dividend policy at that point in time. Again, for now, today, the dividend policy is in line with how we're thinking about the business, including the safeguard in terms of the 15% net gearing. Fine. Thank you, Morné. All right. Thanks, James. Thank you. Your next question comes from James Redfern from Bank of America. Please go ahead. Thanks very much. Just a few quick questions, please. I just wanna follow on to Mark's question around the sustaining CapEx, just in regards to calculating the free cash flows, pre-growth CapEx. Should we assume that the sustaining and exploration CapEx is relatively flat going forward, above your AUD 240 million per annum? I've got two more. Thanks. James. I don't think we regard it to AUD 240 million going forward. I think if you look at our current CapEx outlay and you will see that sort of looking at that sort of mark, plus then if you look at sustaining CapEx, as I said to Mark as well, you need to include the Cooper Basin JV drilling in the five, which we've currently got operating there as part of that sort of sustaining CapEx as well. Okay, good. Thanks. Just in relation to Waitsia, that's the sort of, you know, the big unknown with regards to the FY 2024 production guidance. Just wondering if you could please provide or confirm what percentage of the Waitsia project is currently complete, please? Look, if, on that front, James, we're just waiting for Webuild to take the reins on from the administrator, before we come into market and confirm what level of percentage complete that is. I think it's just prudent to wait until they're behind the wheel, before we come out to market, with the completion. Good. Thanks. Well, one last quick one. Just in regards to the price caps of AUD 12 per GJ for 2023 uncontracted gas. I mean, whilst no one really likes government intervention and price caps, is it fair to say that Beach is largely unimpacted by this, given the realized price of AUD 8.40 in the last half and the amount of contracted gas to Origin Energy, that your sort of, you know, internal models and cash flows are unaffected by these price caps? Is that fair? Yeah, I think that's fair, James. I think, you know, we're not materially impacted by those price caps. As you've outlined, most of our gas is sort of contracted and at fixed prices as well. Yeah. Yeah, exactly. Okay, cool. All right. Thanks, Morné. Thanks, James. Yes. Thank you. Your next question comes from Dale Koenders from Barrenjoey. Please go ahead. Morning, all. I'm just wondering if you could provide some color on the 10 drilled but uncompleted wells in the Cooper Western Flank. What sort of exit rate of production are you targeting for FY 2023? On a go forward basis, with the 30 wells per annum, what do you think this will then do in terms of reserve replacement and production? Yeah, maybe I'll throw to Sam for that question. I think in terms of connecting the 10 wells, the team is obviously working on that at the moment. We have the workover rig running 24/7, more recently in terms of, you know, progressing that as fast as we can after the weather events and some of the supply chain issues as well that was caused by that. The plan is to get them all connected by the end of this financial year. We haven't guided to what that means from a production uplift point of view because it's just structurally complex in terms of flowing the wells. We wanna actually flow some wells, get the production, and then that will give us the indication of what we can expect from a production point of view going forward. That's part of the reason why we've got quite a wide range in terms of the guidance we give for FY 2023. It could be a low side outcome, it could be an expected outcome, or it could be a high side outcome from the flow of those wells. Don't wanna go to that just yet. The ongoing drilling? That's the answer. Sorry, say again. The ongoing drilling, do you think that 30 wells per annum, is that something that can then replace all production in terms of reserve position and continue to grow oil production from the Western Flank? I think that's obviously something which we'll work through. As Morné's highlighted, quite rightly, the production going forward will be informed by the production that we get out of these wells which we're waiting on connecting up. That's an important component of the answer to your question. The second component to it will be in FY 2024, we're looking at doing quite a lot more exploration and appraisal. It will also depend upon the success of that. As we work through that information, obviously we'll get a better understanding of what that might look like. Perth Basin, you've called out sort of 19 targets. Can you give a steer in terms of, you know, whether it's a risked or unrisked potential of these targets combined and probability success rates you're considering? Yeah, no, we haven't guided to that. we purposely just wanted to show that there's a lot of. Hence the question. We wanted to show that there's a lot of prospects there. We do feel, you know, there's a lot of prospectivity there in terms of. That's why we're spending the capital to go after it. You can see that there's quite a long list of wells that we're gonna be going after and drilling, and obviously some of them are reliant on the success of the earlier ones. But we're very excited about the acreage in the Perth Basin and adding to our reserves in the future. We didn't want to guide to anything there until, again, we've drilled and got the results, and then we can report on the results. Okay. I might ask one final question. Hope to get a more of a summative answer. Seven or eight development wells with Waitsia that's flagged for FY 2024 and 2025. I'm a bit surprised that you're drilling so soon again in this field. Is that to sustain production or would that potentially grow versus current production capacity? No, I think that's, now looking at Sam here, but that was always the plan to drill it in that sequence. It's not earlier or later, in terms of the sequencing. The first, six wells we drilled was needed to get us to production and maintain production, obviously there's a timing aspect to it in terms of when you bring the new capital or new wells on board, in terms of when you spend the capital. Nothing is earlier or later on that front. Okay. Thank you. Thanks, Dale. Thank you. Your next question comes from Saul Kavonic from Credit Suisse. Please go ahead. Hi, folks. It's just one quick question from me, and it's coming back to the illustrative LNG contract pricing chart you put out there with the very wide ranges, depending on the, you know, the, the contract terms, which you're saying basically are evolving over the term of that SPA. Now, if I run, like, just very quick high level, if I assume, say, a 12% FOB slope. That range accounts for, you know, your LNG spot linkage ranging from anywhere from about 10% to 40% of the volumes over that period. Would I be, you know, ballpark correct in assuming that the spot LNG exposure in this contract changes over time and you perhaps managed to get greater spot exposure at the early part of this contract when we're expecting LNG spot prices to potentially be higher? Yeah, thanks for the question, Saul. I can't really answer that question 'cause it's commercial in confidence. In terms of the ranges there, I think, you know, when you look at the contract over the term of the contract, the range in terms of JKM versus, you know, Brent linkage sort of remains the same over that period. That's probably as much as I can say, I suppose, from that perspective. Perhaps then, I guess the follow-up would be if the spot LNG versus Brent linkage isn't changing, and I mean that. What you've given there applies to, you know, fixed historic JKM and Brent links. What is actually changing that can account for that large range? Sorry, Derek. That's okay. Derek here. Just jumping in. I guess one of the messages on that slide is that there are changing parameters at SPA over time, and it's a complex SPA, and it's very difficult to talk to. When you look at, we know what the prices were at the past 12 months commodity-wise and FX. When you apply those to the SPA parameters over time, over the five years, you get those ranges. Realize it doesn't answer any question precisely, but hopefully it gives you a bit of an indication and helps convey the fact that there's some complexity to them. Yeah. I think the other thing to note, Saul, is that I think you mentioned FOB, this contract is a day rate contract. Oh, sorry, FOB. Sorry. Yeah. BP takes the shipping risk attached to the contract. Understood. I guess it's like, so it's not really helping in terms of indication here. I mean, we wanna model this. Yeah. The difference between AUD 20 and AUD 30 is huge. Yeah. And we- Yeah. You're saying you can't give us an indication of what we should look for, whether it's gonna be closer to AUD 20 or AUD 30, you know, over the... Yeah. you know, for the 2022 period. Yep. Okay. Yep. That's what we say, Saul. Sorry about that. All right. We can't give any more detail than that. We try to be helpful with the slides, but it's that's as much as we can provide, unfortunately. All right. Thanks, guys. That's all right. Thanks, Saul. Thank you. Your next question comes from Mark Wiseman from Macquarie Group. Please go ahead. Good day. Thanks for listening to the question. Just on Waitsia. Obviously, you've spent a lot of CapEx there and taking the first move in the basin with a couple of other very high-profile players with big resource. Are there discussions taking place around sharing of gas processing infrastructure and perhaps Beach and Mitsui taking on a processing role for other gas? Are those discussions taking place or do you expect them to take place? Look, don't wanna comment on any discussions. I think if you look at the basin, and I said this last year at a conference, but if you look at the basin and you look at the plants there, we obviously own and operate together with Mitsui, three gas plants in the area. I think from our perspective, you know, you don't, definitely don't need more plants in the area. I think it would make sense to have those discussions. You know, I can't say whether those discussions are happening or not, I think it would make sense. How much additional capacity are you planning to install on the existing site in the event that you have more discoveries here? I think again, we said this previously, but from a Waitsia plant point of view, we can probably add about 150 TJ a day there in terms of the current footprint of the plant. Obviously, this is subject to all kinds of approvals from environmental and regulatory point of view. There's also expansion ability at the Beharra Springs plant that we can look at. I think from a Xyris point of view, that's probably doing as much as it can do at the moment. That's probably between those, the Beharra Springs plant and the Waitsia plant that we're probably looking at expansion. Okay, great. Just on Enterprise, I think there was a discussion previously around you were contracting or you were marketing that gas for an interruptible contract. Is that gonna be effectively spot gas when it comes on stream, or are you still planning to contract that up? We're still planning to contract that up, so negotiations are ongoing with Enterprise. Some of that will depend on when the gas actually hits the market, whether it's, you know, within 2023 or 2024. The negotiations are ongoing. Okay, great. Just finally from me, the Otway CCS project. Could you maybe just help us to understand what the business model is gonna be here? Are you intending to take third-party CO2 into that CCS asset? If you've got any context on how those discussions are occurring post the safeguard reforms, is that something that is exciting you at the moment in terms of the prospects of taking third-party CO2? Look, we in terms of looking at the project, initially, we look at taking out the CO2 from the obviously the operations at Otway, so from our own production, and those of our joint venture as well, joint venture participants as well. I think on that basis, you know, from a timing perspective, we do see it making a good return for us without third-party involvement. I think the third-party side of things will come later once we've sort of exhausted the development opportunities and keeping the plant full with our own acreage and production. I think that's not something we need in terms of sanctioning the project. We see that from our own production, that project will pay dividends. Okay. That's clear. Thanks, Morné. Thanks, Mark. Thank you. Your next question comes from Adam Martin from E&P Financial. Please go ahead. Good morning. Just confidence around sort of hitting the Otway uplift target middle of the year. You've sort of flagged regular risks, but obviously sort of walked away from that FY 2024 production uplift you're gonna provide in August. Just give us your confidence levels there on hitting that target first. Look, I think from a FY 2023 point of view, looking at the target there and the 19 to 20.5, we have more confidence in terms of getting the gas in by middle of this year from the Otway, and connecting up the Thylacine wells after the EP has been approved by offtaker. Definitely more confidence there. We did mobilize the vessel over the weekend, so it's now sitting across the wells and we'll start doing the work that's necessary to connect up the Thylacine wells. That is dependent on obviously the weather and how we go there with that program. Then there's some brownfields work to do at the site as well. That affects the upper end of that sort of guidance. If we can get that in early, then obviously we'll end up at the high end of the guidance, all things being equal on other fronts. In terms of confidence levels, you know, we're feeling very confident in terms of reaching our target there. Good. Good. Just another question just on costs. I think you mentioned or Emery mentioned just the Cooper JV just around production costs. Are there any other assets so that you're seeing that, or should we assume most of those costs are the Santos JV that are coming through in terms of higher numbers? Look, the material component of that is the CB JV. I think the other component of that is obviously the production the guidance that we provided today as well. In terms of, you know, production being lower, that impacts that range as well. From a gross operating cost point of view, CB JV is the major contributor. Just final question of AUD 400 million-AUD 450 million, you've talked about for Waitsia for net CapEx. How long does that take you out of just thinking about the extra drilling you talked about in 2024, 2025? Is that in that number? Is that additional? Just wondering how far out that CapEx guidance goes for. Yeah. Look, Adam, that guidance is just for the Waitsia gas plant. That's just to complete the Waitsia gas plant, get first gas out of the door. With the other CapEx guidance, we'll obviously include that as we go through the guidance. The drilling we're going after in terms of exploration drilling and Perth Basin, that's included in our FY 2023 guidance range. When we get to FY 2024, we'll obviously add all the other wells there from a WA perspective as well. Okay. Okay, that's great. Thank you. Great. Thanks, Adam. Thank you. Your next question comes from Daniel Butcher from CLSA. Please go ahead. Hi, everyone. First one's just on the Waitsia CapEx again. It was reported in the news that Webuild contract is reimbursable. I'm just sort of curious, given they had a short time to do DD on the project, which is well publicized by the administrator, how confident are you that the new quote is accurate, given they can pass on any increases down the track to you and Mitsui? Hello. Thanks, Daniel. In terms of the DD that's performed by WeBuild obviously spent quite a bit of time before Clough went into administration looking to buy the Clough business. Clough went into administration, then obviously did some more DDs. They probably got, you know, I would suspect about four or five months of DD behind them in terms of looking at the various projects. The other thing that we did do is obviously look at alternatives in terms of if we didn't go with WeBuild, what else is out there? Who else can do the work? Obviously that formed part of our decision to sign with WeBuild as well in terms of that process. In terms of what we saw from other providers, you know, in terms of what we're guiding to, it was there or there about, so materially the same sort of numbers. Right. Similar numbers. Okay, thanks. Just curious if you can give us a bit more detail about what you think about the average nominations you expect from Origin for throughput at Otway Gas Plants versus the actual capacity of 205. Perhaps this is the second part to that question. Could you give us a bit of a feel for when it would start to go off plateau in terms of out of the 205, both before and after enterprise, once it's hooked up? Yeah. Look, in terms of the nominations for Origin, obviously Origin has got a very complex book that they're balancing on their side in terms of the various assets and gas that they can pull on. You would have seen over the last, you know, six or so months that's been variable. It has been down when some of the LNG plants have gone into maintenance where they then nominate lower on the Otway side of things. In terms of the nominations, traditionally in winter, we do see full nominations and then in summer traditionally, that's dropped off. Going forward, you know, that's I suppose, the expectation in terms of winter and summer. When these wells are connected, we expect nominations to be high or, you know, nominating the full plant, at least in winter. What happens beyond that is then, you know, there's take-or-pay levels, and then there's the maximum level that we obviously inform Origin that the wells can produce, and the nominations will be within that range going forward. I suppose it's not a, I suppose an answer in terms of, you know, maximum 2 TJ and 5 TJ a day. It's an answer in terms of it's complex in terms of the nominations from Origin. They're balancing their side of the gas equation as well. Okay, thanks. Just to follow up on the second part of the question. Yeah. In terms of the plateau, obviously, it will depend again on nominations and then when we're actually connecting the Thylacine wells, whether that's through the high nomination period, potentially in the winter period versus summer when that might drop off, perhaps the plateau. Definitely if Enterprise comes in at the time that Thylacine is still producing at high nominations, we do expect that to, you know, plateau for a number of months beyond that. Oh, okay. So it's a matter of months, not years. Okay. Very good. Well… Final one. Might not be. Yep. Let's just clarify that, Daniel. In terms of That's why we're looking at the other wells we're connecting up in terms of Artisan and La Bella, and when that comes in, is to keep the plant at plateau for longer in terms of what that looks like. Just I suppose I was just trying to clarify, but it depends on nominations, so and when the wells are connected. If we connect the wells earlier and Origin nominate at high levels, you know, that plateau is gonna be dependent on when we can get Enterprise connected, and when the timing on that is. Right. Okay. Thanks. Maybe final one, if I can ask it. You know, sort of if you look at Cooper Basin reserves downgrade at Western Flank, the other year, it's about nearly 50% on remaining reserves post-production at the point in time, and then Waitsia, it's obviously about 15% of the Waitsia gas, excluding the Beharra Springs stuff was downgraded just a couple of weeks ago. I know Beach has usually carried a bit more of 2P for Cooper Basin JV than Santos has pro rata, if my memory serves me correctly. Just, how can we be confident that there's no downgrade coming for Otway reserves before all is said and done? So, uh- Is there any risks you see to misestimation or any misunderstanding of the reservoir that could be points to its variabilities that would either be upside or downside to the currently booked reserves? Yeah. Look, Daniel, don't wanna cover old ground, but obviously there was reasons for Western Flank downgrade reserves. As we've outlined with Waitsia, that was obviously informed by the drill bit in terms of what we found. As we outlined there, it's very dependent on the seismic you have, whether you've got 2D or 3D seismic. There's obviously a lot of faulting in the basin. You know, the other reason for that was the High Cliff wasn't as well developed as we expected in a couple of areas, especially the southwest of the basin. You know, in terms of looking forward, in terms of Otway, we did last year do a full audit on our reserves. Obviously the reserves we have for Otway is informed by the drilling results we have at the moment. We've drilled the two Geographe wells and we've drilled the four Thylacine wells. That has informed our view on the reserves that we have currently in play. I think from a from a reserve point of view, we're feeling comfortable in terms of what we have out there at the moment. Maybe I'll get Sam to comment more detail on that as well. Just one clarification. You mentioned on the Cooper Basin Joint Venture, FY 2022 to be 100% clear here, we believe our reserves are almost identical to Santos's. There is no difference. I wanna be very clear on that. That's from FY 2022, and we see no reason why that will not change going forward. There's a very good alignment there. In regards to other changes, I think we wanna clarify that with Waitsia, there was always a very wide range from 1P to 3P. Anytime you have that, then it is reasonable when you get your data to expect the numbers will move around. In that respect, I think these things are all very reasonable and significant new information. As Morné has highlighted, we've already reviewed the wells from offshore Otway, so we have some, we believe, stability there, and then also a stability in the Cooper Basin, and we've clarified our position in Waitsia in the Perth Basin. I think we're actually in pretty good shape. As always, whenever we get new information, we'll analyze that and come out to the market as soon as we can. Great. Thanks very much, guys, for the answers. Thanks, Daniel. Thank you. Your next question comes from Gordon Ramsay from RBC. Please go ahead. Oh, thank you very much, and congratulations, Morné, on your new capital management program. Very pleased to see that. Thanks, Gordon. Good morning. Just a very quick question on the FY 2024 guidance. You've withdrawn that, and your previous aspirational target was 28 MMboe, but you did highlight risks to that. The commentary today just specifically mentioned the Clough administration process and regulatory approval uncertainty. I just wanna get some more granularity from you on that, because clearly, from the Clough administration process viewpoint, your recent guidance has implied around a six month delay on timing, and you've given a cost indication. Does this come down to other projects and specifically potential for Enterprise to push out beyond your previous guidance? Thanks, Gordon. In terms of what we've set out in terms of the reasoning there, like you've outlined, the Clough administration process has added time to the project, there's no doubt about that, and that's what we've provided our guidance there and obviously the capital cost as well. I mean, if you think about the Waitsia plant, you know, net Beach share, you're looking at about, you know, up to 600,000 barrels a month. It doesn't take a lot to start moving the dial in terms of the potential there from a production impact on the FY 2024 production target. That is the main part of it. The other part, as you've outlined as well, is from an Enterprise point of view. We've indicated there in the FY 2024, we've still got a few hurdles to go there in terms of, you know, specifically the weather has impacted us there. In terms of starting the pipeline construction, there's been some supply chain issues there as well, and we still need some regulatory approvals to go on that one as well before we can actually produce the gas. But in terms of what we've outlined, really the Clough administration process is the main process on that. That's impacted that. Thanks, Morné. Just with Enterprise, I think you previously mentioned there were some permitting issues, maybe that's your regulatory comment. Can you just provide more detail on that? Is that onshore? Yeah. We just need approvals from the Victorian government around actually starting construction on the Enterprise well site. Once we have that, we can actually start the works and actually start bringing stuff in to start connecting up from that point of view. We're just waiting on that. Once we have clarity on that, we can then start construction on the well site as well. Okay. Just one other from me, Morné. At the beginning when you started the presentation, you talked about the strength in the balance sheet and you're targeting future growth. You mentioned new gas projects and other opportunities. What's meant by new gas projects? Look, that's just what we outlined here today, Gordon, in terms of talking about the Otway Offshore in particular in terms of connecting those wells, looking at how we progress our acreage, you know, more broadly in terms of the opportunity that's there from an offshore point of view and nearshore as well. Then looking at Trefo il, White Ibis and Bass and how we sort of link that up into our offshore developments there as well. That's what's meant by that. Excellent. Thank you very much. Thank you. Thank you. Your next question comes from Nik Burns from Jarden Australia. Please go ahead. Thanks, Morné, and everyone. Given time, I'll just limit my questions to one. Just on Cooper Basin Joint Venture, just looking at your recent run on the success rate, 95% on 68 wells. This is a huge turnaround on 12 months ago. I think you participated in 32 wells in the first half of 2022 at an 88% success rate. What's changed here in terms of your in terms of both the quantity and the quality of the drilling targets you're going after here? How should we read this in terms of the outlook for production? I mean, obviously there's been a few quarters in recent times where we've seen quarter-on-quarter decline in gas production, should we infer from this that higher production is ahead? Thanks. Morning, Nik. Just to answer your question, I think, you know, we definitely got a higher proportion of development wells that we've agreed with Santos in terms of that sort of 100 well sort of program that we're going after. I think credit to the teams as well for working together in terms of looking at the prospectivity in the basin, looking at where the next well should be drilled. There's quite a good collaboration between the technical teams around what we should be going after in the basin. I think that's paying dividends for us and Santos as well. Then the other question you had there is around production. We do see production stabilizing and slightly increasing from where we've seen over the previous quarters. Again, you know, we reported on some of the unplanned maintenance that happened last year and then impacted by weather as well in the basin. I think, you know, there's definitely more focus in terms of getting those wells back online and then also focusing on how we support production going forward in terms of looking at better quality development wells, bringing that online as well. I think all around good focus from the operator on production and getting production back up. That's great. Thanks, Morné. Cheers. Thanks, Nik. Thank you. Your next question comes from Henry Meyer from Goldman Sachs. Please go ahead. Hi. Morning, y'all. I'm conscious of time. Just a couple of quick ones from me. Obviously more to play out on the East Coast regulatory environments. If flagging Artisan and La Bella is expected, is it fair to assume that you'd be happy to develop those fields at AUD 12 a GJ perhaps inflating forward? Look, I think, you know, in terms of developing those fields, would be great to get more clarity around the Code of Conduct and reasonably priced gas provisions and how that would look like and how that would work, and how we need to think about that going forward in terms of whether it covers operating costs plus return, plus exploration risk, plus abandonment costs, you know, within those costs as well, to make an assessment on whether that's reasonable for our projects going forward. I think there's some clarity needed before we, you know, get things going on that front. In terms of, you know, AUD 12 gas at the moment, when we look at those opportunities and you put those numbers to work on the project, if they make a return at AUD 12, then I would assume that, you know, you would go ahead with those projects. In terms of doing the economic analysis on that, it's very difficult to do that with unclear regulatory guidance in terms of how the reasonably priced gas provisions will work going forward. Got it. Thanks, Morné. Maybe just a quick follow-up. Are you able to share any details on the process for sanctioning fields? I mean, do you test against a P50 and a low case outcome? If you could share any IRR hurdle rates or otherwise that they're required to sanction. Yeah, Henry, I think, we don't share the hurdle rates, obviously it needs to be above our, you know, our cost of capital, and make us a return above our cost of capital. In terms of looking at the projects, they go through a quite a significant and detailed hurdle gate process as per usual. We do assess them against a number of metrics, including returns and return on capital. They need to obviously compete against capital from other projects around our portfolio as well before they're sanctioned. They go through a rigorous process, and you... as you would expect, we do stress test the projects in terms of low case outcomes, P50, and then obviously look at whether they, if they're better than expected, what does it mean from follow-on work and expansion of our activities as well. It does cover the full gamut of how you would look at a project and before you sanction it. Okay, great. Thanks, Morné. Thanks, Henry. Thank you. Your next question comes from Sarah Kerr from Morgan Stanley. Please go ahead. Thank you so much. I just have two questions, if I may. I was wondering if I could get some further details on east coast gas contracting. In your FY 2022 results presentation, you had 77% of FY 2024 east coast gas volumes up for repricing or were uncontracted. I was wondering if we could get an update on the% of FY 2024 east coast gas volumes that have been contracted so far. Yeah, look, thanks, Sarah. In terms of looking at our position currently in FY 2024 or looking ahead for 2024, we are, you know, one of those key contracts that's gonna come up is around our Otway Gas Plant. We are currently in negotiation around that and obviously that's with Origin. As we've previously outlined, that contract sets out very clear how you sort of reprice that contract from a, you know, looking backwards over the last three years at comparable contracts in a comparable market. We are currently negotiating that contract. That will be the main contract that comes up in FY 2024 in terms of what we need to, I suppose, contract from a pricing point of view. Thank you. just to quickly follow up, any update on historical Lattice contract repricing? No, that's the main one, that I've just mentioned in terms of Otway. The next one would be a year later, which is relating to the Cooper Basin JV volumes. Yep. Okay, great. Thank you. My second question might be for Sam. With your Trigg prospect being located down dip of Strike's South Erregulla discovery, I was just wondering, what your new 3D seismic survey was telling you about any potential spill risks with Strike's block? Yeah. Thanks for the question, Sarah. It's actually not down dip at all. We think it may be up dip and likely separate from the South Erregulla discovery. Yeah, we have very clear 3D seismic which covers the vast majority of it, and then goes, you know, there's some 2D seismic into the Strike area, so we're pretty clear on that to a not linked directly. Oh, fantastic. Thank you so much. Thanks, Sarah. Thank you. Your next question comes from Scott Ashton from SHA Energy. Please go ahead. Good morning, Morné and Sam. Just on the back of the last question. In the event of success for Trigg, how do you expect that to be developed? Is it daisy chained into Waitsia or Beharra? How would you see a success case being developed? Yeah, thanks for the question. Good one at that. I think our position on this has been it's very much dependent upon the scale of the volume. That's why we haven't really been talking about that. We could get some very large upside volume, in which case, that would give us pause for thought. Otherwise, as you say, putting it back into Waitsia is certainly something we would always consider as well. Not yet defined. Yeah. I suppose, you know, given you've got a JV, well, not a JV participant, but you're a participant in the Perth Basin that shows South Erregulla going into your block. Is unitization potentially on the cards here at some point if you find out that the structure's actually joined? I think we'd have to, defer that comment until further wells have proven up, whether that's the case or not. Certainly from the data we've got at the moment, that's not justifiable. Yeah. Okay. Just the very last one. I mean, I'm cognizant of the time. It's a great table on all the prospects and leads there. I think I asked this question last time. Obviously, you're not chasing sort of 30 BCF type targets, so pretty safe to assume that, you know, those targets there are sort of anywhere between sort of 100-300 BCF to justify optimizing developments in the basin rather than having all these sort of scattergun approach to plants that are sort of, you know, of the Beharra Springs type scale. Are you looking to sort of, you know, chase meaningful volumes? Yeah, look, I think, Scott, again, we're not giving any guidance on potential here. I think from your question it's definitely obvious that we'll go for the bigger prospects and targets first, before we go for the smaller ones. You know, definitely wanna see what that means for us in the basin and how we think about development and whether there's expansion of plants that could be driven by this or whether it's backfill to plants going forward. Definitely from our perspective, we're excited about the whole basin, so that's why we're going after these wells, quite quickly and spending the capital. And we're quite excited what that means for us going forward in terms of, you know, obviously supplying domestic gas market and looking at how we progress the basin. really looking forward to the results. Thanks for that. It's great. Great feedback. Great. Thanks, Scott. Thank you. There are no further questions at this time. I'll now hand back to Mr. Engelbrecht for closing remarks. Great. Thank you everybody for joining us. As per usual, if you've got any questions, please call us afterwards. We'll be doing roadshow in Sydney and Melbourne, so see you soon. Cheers. Thank you. That does conclude our conference for today. Thank you for participating. You may now disconnect.