Beach Energy Limited

Thank you for standing by and welcome to the Beach Energy Limited FY23 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'll need to press the star key followed by the number one on your telephone keypad. I would now like to hand the conference over to Mr. Mornay Engelbrecht, Chief Executive Officer. Please go ahead.

Thank you, Darcy. Morning and welcome to the FY23 half-year results presentation for Beach Energy. My name is Morne 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, 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. And 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. On to slide three, we have been working hard in the first half of FY23 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 FY23 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 main plate 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. Furthermore, the enterprise nearshore well has been connected to the plant, and we now expect to be ready for first gas mid FY24. On the west coast, the weight share 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. Webult and Najavi are targeting first gas by the end of this calendar year. Second, Beaches is growing strong free cash flow. Once we complete the Whiteshare 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. Third, our strong balance sheet allows us to invest in future growth beyond our major project pipeline. With $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 FY24. 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 Mitsui Operated Wells, while the Beach Operated Campaign begins in Q4 this financial year. Finally, as we all know, the energy transition is on the way globally. We've been 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 decarbonise. We're just 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 Beaches' plans are progressing, and as our free cash flows and production increases materialize, Beaches is looking forward to the future while rewarding our shareholders for their loyalty. Moving to slide four, and there's nothing more important to me than the safety of our people. Beaches' HSE performance in the first half began with a few minor safety incidents, however, I'm very pleased with how the team has responded. Pleasingly, two of our sites have just recorded major milestones. Upper Gas Plant achieving eight years and Bahara 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 Dongby 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 Dombe Seismic Survey and the SA Artway. Congratulations to the seismic team. Energy Site 5 and our first half financial results. Beach performance was largely driven by low production and sales volumes. while sales revenue were up 3% at $813 million. EBITDA was down slightly at $491 million, while underlying impact was down 10%. In line with our nearly announced dividend policy, you will notice today that we have implemented the policy and confirmed a $0.02 per share interim dividend, a doubling of the $0.01 per share dividend we just paid for many years, and with more than half a billion dollars in frankie credits available, There's still more to come. Turning to Site 6, and less than two weeks ago we provided our FY23 second quarter update. Since that time, there have been two important milestones achieved on our key growth projects. First of all, the beach environmental plan was approved by NOFSEMA for our offshore upway well connection activities. This EP allows for the remaining subsea work to be completed with the DOF subsea vessel now on location. Once the thylacine wells are commissioned and connected to the off-way gas plant, it will allow for an additional 100 terajoules a day to be available for the East Coast gas market. The second major development of the last two weeks was the news that we both will take over construction of the Waitseer Stage 2 project. This is part of a broader acquisition of CLUT. We 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 for all involved in the project could have hoped for. This news and the filings in EP approval move both projects closer to completion, which will allow for beach to deliver the state change in production and free cash flows from FY24. which provides a further summary of the milestones achieved across the business so far in FY23, Perhaps most notably, back in July, we completed its largest ever drilling campaign, the largest ever in the Otway Basin's history, with gas now flowing from the geographic wells. And as mentioned, we are now progressing the thylacine well connections as well. In New Zealand, negotiations are progressing for a rig for our forthcoming Coupe 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 progressed the Moomba CCS project with operator Santos. And I've already touched on the WeBuild transaction with development drilling complete and our SBA in place with customer BP. Our Perth Basin Exploration Campaign has also already delivered one discovery within the TUI operated genotrix 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 FY23, and that is despite some of the headwinds that Beech and our industry has faced. We look forward to continuing this momentum as we move towards the end of FY23. Moving to slide eight, today Beech has unveiled a new dividend policy, which Anne-Marie will speak to in more detail shortly. Over many years, Beech has demonstrated financial discipline through our philosophy of diversifying revenue streams, brilliantly 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 half a billion dollars, 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 nine, and 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, and 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 pathway gas plant is also key. As I said, the Duff vessel is now in 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 Waitier stage two, we are working towards keeping the project on schedule towards first gas by the end of this year. A beach operated exploration campaign at the third basin is expected to commence in early Q4 of this financial year with the starting of trip one. 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 Kerbe Development Well, which we are planning to drill before the end of the year as well. Turning to slide 10 in our FY23 guidance update. Today we've lowered our production guidance from FY23 to 19 to 20 and a half million barrels of oil equivalent. Narrowed capital expenditure guidance of $900 to $1 billion and increased our operating cost guidance of $13.75 to $14.75 per BOE. The low 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 materials step change in production and cash flow will arise in FY24. But we will no longer be referencing the FY24 production target as the production target remains subject to the timing of major project delivery, which has in recent times been impacted by the CAF administration process and regulatory approval uncertainty. FY24 production guidance will be provided for full year results in August 2023, as it's normally the case in which time we will have greater certainty and clarity on both weight shear startup and the outlay well connections. Capital expenditure guidance reflects high estimates for waste year stage two, offset to a degree by efficiencies achieved in other programs. The outlook for operating costs reflects industry-wide cost inflation, as well as high super-basin JV costs as advised by the operator, with the increased work over 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 focus producer on the East Coast, and we will increase our market share to 16% in FY24, up from 12% currently. This is underpinned by production from thylacine wells, which will enable our gas plant to meet its main plate capacity of 205 terajoules per day. We also have the enterprise well to connect with FY24 and further opportunities both nearshore and offshore, including the existing artisan and labella discoveries that can be developed. Our message here is the auto gas plant will become a core driver of Beaches' production and cash flow step change, and we have a plan to maintain high production levels for many years into the future. FY12 and moving to the west coast, Beaches is already contributing to the WA domestic market to our Bajara Springs and Zyrus 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 needs of our reserve provision, but that does not change our commitment towards LNG or domestic gas. Like you, we are of course eager to see the first LNG cargo delivered to our customer VP. Our JKM Brent pricing structure will deliver the type of revenues that you would expect from the current market conditions. We appreciate that many of you would like further detail on the pricing structure for our LNG contract, but 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 demonstrated is that there's 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 Beech and Mitsui JV. Beech intends to capitalize on the dominant accurate 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. They are already actively pursuing the policy objectives through emissions reduction activities across our portfolio. Beaches commenced the select phase on off-way basement CCS proposal. This would be Beaches' first operated CCS facility. Meanwhile, in the Cooper Basin, we are near completion on a pre-feasibility study on ammonia production. While at Cooper, 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 Wimber CCS. Operator Santos tells us the new facility is about 40% complete, the first CO2 injection currently anticipated in 2024. Finally, it was pleasing to see the federal government's CHAP 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. Now we'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, Mornay. Good morning, everyone, and thank you again for joining us today. This morning, I'll take you through the financial results for the first half of FY23. 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 FY23 results were influenced by a reduction in production and sales volumes as we continue to deliver our key growth projects. During the half, Beach recorded higher sales revenue of $813 million, up 3% on the first half of FY22. 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 the comparison of the first half FY23 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 first quarter of FY23, driven by a change in contractual terms on cooper base and liquids. which resulted in a revised revenue recognition point. This is not expected to have a material impact on full-year FY23 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 creeper basin JV costs. as advised by the operator due to additional work over activity and unplanned maintenance. And higher financing costs were driven by a non-cash increase in the unwanted discount on restoration provision as a result of increased long-term bond rates. These impacts are partly upset by stronger gas and liquids commodity prices and higher third-party sales realized in the first half of FY23. Slide 17 outlines our cash flow movements for the period with cash reserves of $189 million at the end of the half. Operating cash flows were $404 million for the first half of FY23 and included within operating cash flows were income tax payments of $97 million compared with $29 million in the prior corresponding period. We also saw elevated levels of capital expenditure continue in the first half of FY23 as we progressed our major growth projects. Of the $527 million cash spend, $217 million of this expenditure was to fund our major growth projects. Free growth, free cash flow for the first half was $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 $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 FY24, 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 Mornay'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, utilise our franking credits, which are in excess of half a billion dollars, 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 to 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 FY23 which results in a $0.02 per share interim dividend announced today. We expect the dividend to grow in FY24 as our free cash flow step change is delivered. With that, I'll now hand back to Mornay.

Great. Thank you, Anne-Marie. I will now talk a bit more about the future outlook, including our plans for future growth across Beecher's portfolio. On slide 21, Beecher's exposure to five key markets, and these markets all have strong fundamentals. We know that the East Coast gas market will continue to face supply challenges, with IEMO 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 burden gas producers, and especially domestic gas producers like Beech 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 a reasonably priced 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've said publicly before, removing investment uncertainty is imperative as new gas supply is the only answer for low prices. 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. A long-time involvement in global oil markets extends to LNG markets as we complete the Whiteshare project where BEACH has unearthed exposure to Brent and liquids pricing. This aims to continue to increase our share of these markets, and as the world transitions to clean energy, our products will become more important than ever to global energy security. Turning now to slide 22, and I want to give you a glimpse of our future, both planned and potential opportunities across features portfolio. Starting in the Perth Basin and working clockwise, and we begin with the Perth Basin Exploration Campaign in Q4, further series of whitehead development wells to be drilled and a SCIPA 3D seismic is planned for FY25 to inform the future exploration and appraisal program. In the Western Flak, we will be drilling continually and targeting the Birkhead Formation for appraisal and exploration potential still to be pursued in the Lemur. 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 Coupé 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 straight drilling in FY25 and beyond. In the offshore outway, we have discoveries of Ides and Labella to appraise, while further exploration of Hercules, Anateas, Thistle, Updip and Themis provide a potential further opportunities. Following the enterprise, the Calico 3D seismic survey is planned for the near-shore Artway Basin, where we can use the existing enterprise welfare to target near-shore opportunities. So 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. And BEACH has the balance sheet position to make this happen. Looking deeper into these assets, and starting with the birth base on slide 23, I want to go into our achievements and a half, which have already been discussed. But our forward-looking focus is to progress construction of the 250-terrajoule-a-day wet-air gas plant, continue the birth base and gas exploration program with the first beach-operated wells, and to complete the select phase for Bajara Springs' thermoelectric recovery project. On slide 24, we've laid out the current schedule for the campaign. which shows Trick 1 to commence in early Q4. From there, the rig will move to Trick NW and then Bahara Springs Deep Development Well. From there we have three further exploration wells at Tarantula Deep, Redback Deep and Peacock, all targeting the King Ear 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've contracted the Ventia 106 rig to FY24, which will initially drill up to the six wells of the beach operator campaign. We think this could be just the beginning though and subject to JV and other approvals who will target extending the rig contract to draw the follow-up opportunities mentioned. I look forward to updating you on the campaign throughout the year and we wish the team success. On Site 25, we draw down a bit further on and look at Trick 1, which we see as being an on-trend with West Aravila and South Aravila discoveries. If Trick 1 is successful, there's an opportunity for a sidetrack wall to test a broader trick structure. A test of trick will also de-risk the southeast part of the basin. There's also significant follow-up potential at Trick South, Quarterslow, 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 FY22. Our priorities looking forward include the connection of thylacine wells to the Otway gas plant, connecting activities for the enterprise discovery, maturing offshore exploration drilling prospects, planning for nearshore and onshore 3D seismic acquisition, and refine our CCS study for a potential 200,000 tonne per annum facility. On slide 27, and in the Bass Basin, we were progressing planning for Yolo West drilling in the first half of 2024. Also update trefoil, white arbors, and bass resource estimates from the PRIME 3D seismic survey, and this will inform our development strategy for these opportunities. On slide 28, and over the ditch, the Kupe plant remains a highly reliable facility and an important part of the beach's portfolio. During FY23, while we are finalising negotiations on the rig contract, we're targeting the mobilisation of the rig for Kupe South 9, which we aimed to spot by the end of 2023, subject to JV and regulatory approvals. Back onto dry land, and 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 FY23, 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 Fire 3 campaign targeting mostly gas development. The JV has performed well in the recent quarter with Moomba production maintaining plateau, although a high 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 Moon by 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, Beech 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 Beech in the coming years as we further develop our onshore and offshore plans. Finally, it will grow sustainably through the energy transition and this 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 1 on your telephone and wait for your name to be announced. If you wish to cancel your request, please press star 2. If you're on a speakerphone, please pick up the handset to ask your question. Your first question comes from 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, Mornay, 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 intend 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?

Yes, I'll let Anne-Marie cover off on some of the detail, but 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 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% to 50% of that free cash flow number. But maybe Anne-Marie can cover some of the details.

Yeah, sure. Thanks, Mornay. So essentially we've set up a range of 40% to 50% of pre-growth free cash flow to enable sort of the 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 and 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 so it's just managing sort of the you know 50% of that operational cash flow 40 to 50% to enable those dividend returns and 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. But essentially that pre-growth, 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 colour on that major growth regarding M&A. I remember, 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? And then recognising 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 waste care project, finalising 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 off-air offshore and looking at how we Link that in with the best development as well from an infrastructure point of view. So the again, the main aim is there to have as much gas going through those plants into the East Coast gas market, which as emo is reported, is going to be short gas in the short, medium and long term. So we do see value and obviously bringing more gas to be into the market, but also. through our gas plants currently. So 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, especially specific to your question, Tom, around the East Coast gas market, we see that coming from offshore and offshore and nearshore as well. I think when you look at our portfolio there, we've got quite a number of prospects. We've obviously got Artisan and Lobela, which we still need to connect up. But there's a lot of potential and running room left there for us to explore. And if we look at how we develop that, then we can develop that in conjunction with the Bass trade as well. You start looking at some significant capital savings from that perspective as well. So from a return perspective, that's probably high on the list of potential, you know, capital activities that we want to look at, and 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 obviously impacts the East Coast gas market. So in terms of looking at our plans, if you look at the Bass Basin and the Otway Offshore activity, that will obviously form part of that. That's the final... mandatory code of conduct and the final sort of settling of the words there. But, you know, in terms of the way we look at it, you know, the East Coast gas market is going to be short gas. And that's based on current forecast. That's without projects being delayed potentially due to regulatory, you know, policy being developed as well. And that's very fluid at the moment. So, I think from our point of view, we do see an opportunity there to bring more gas to market in that setting.

Okay. Thanks, Morne. Thanks, Anne-Marie. Thanks, Tom.

Thank you.

Thank you. Your next question comes from Mark Zanta from MST. Please go ahead.

Yeah, morning, guys. I'm just wondering if I could ask on the dividend policy. framework, but you go to your view of, I guess, just having CapEx being $310 million for the half. So annualized $620 million a year. Can you just give us a feel? Because I mean, I look at my numbers and I look at consensus numbers a couple of years out and everyone's down at $350, $400 million CapEx for the whole business. But we obviously have production tailing off with that. Can you just give a sense for what you are defining? Is 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 we're underestimating to go forward to sustaining capex?

From a sustaining capex point of view, we do count in the Cooper Basin drilling. So we've got in the CVJV, as I said, we've got five weeks running their mark. That we see as sustaining capital that's linked to production. So the more rigs we've got running there and targeting the 100 wells per year, that will support our production staying flat. And similarly on the western flank, we've got the one rig running. And then on the offshore side of things, that's mainly fixed operating costs in terms of maintenance costs that we're referring to there. and that will be similar on the West Coast as well once we get that plant up and running. So I think in terms of what we see as sustaining CapEx, maybe the variance or the difference there is that you've got five weeks running in the Cooper Basin JV, which we see as sustaining CapEx.

Awesome. Thank you. I might just make one other quick question. I know we're dealing with a pretty large range on that illustrative guidance for the LNG SPA, but Just when you talk about based off average rent prices over the last three, six, and 12 months, can you just make clear traditionally LNG contracts are obviously on a JCC or rent, but on a lag? I guess, A, can you tell us if your contract has that traditional three-month-ish lag, and B, if the indicative price is used in that, assume that same lag as well?

Look, I think in terms of what we said out there is, is trying to just show an average over those periods. And it's traditionally, and as we said previously, Mark, the contract we have with BP is linked to JPM and a slope to Brent. We haven't set 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 from the slide there. And 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.

Okay. Thanks, Mark. All right. Thanks, Mark.

Thank you. Your next question comes from James Byrne from Citi. Please go ahead.

Hi, thanks. So look, first question on gearing target being less than 15%. I look at business, a lot of the riskier parts of the CapEx cycle are behind you, a decent portion of your revenue, CPI links, 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% to 25%? And, again, like if I think about the history of Beach, Mornay, 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 up 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. And then looking at what we invest in further in terms of further development as a bioclient in terms of Bass and Otway. offshore as well. So 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. But I think for today, it's an appropriate guide to the market. And referring back to in terms of what you've outlined in terms of the lattice acquisition and the 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 will only look at M&A from a value perspective. And if it doesn't stack up from a a gearing perspective as with ladders in terms of throwing out significant cash flows to de-gear us on a quick, you know, quickly from that point of view, then we won't do it, right? So I think going to high 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, Guy, that's very clear. Just on slide 22, which is the map with FIs 24 and 25, potential activity, all of the offshore work aside from one of those seismic surveys is either expected or not firm. Now, 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. So 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 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 point of view. We've obviously got significant outreach there, significant reserves, and us together with Mitsui are very keen to go after the exploration activity there. Similarly, in obviously exploration and in Western Flank and otherwise, and CBJV 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. And therefore, you know, you see the darker blue ones they expected. That's in the planning phase. The NOC firm is obviously on the cards, but that's further than the foreseeable future in terms of how we bring that to market. But definitely having clarity on the policy setting will help our decisions and how we view those prospects going forward.

Yeah, okay. So the question about gearing and exploration really just kind of leads me into a question about distributions, which is, you know, 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. That sort of hypothetical scenario a few years out, your balance sheet's going to be flush with surplus cash. I'm wondering whether you'd consider unlocking more of that franking credit balance via temporarily higher distributions than what you've got it 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 the Otway Offshore and Bass Basin as well. And we can redeploy capital on those fronts as well because that is high-returning, so shareholders should want us to invest more in high-returning assets. But in that case, I would assume in your scenario, the board will reconsider and re-look at the dividend policy at that point in time. But 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.

Thank you, Mono. 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 want to follow on from Mark's question around the sustaining capex, just in regards to calculating the free cash flow pre-growth capex. So should we assume that the sustaining and exploration capex is going to be flat going forward, roughly $240 million per annum? I've got two more. Thanks.

James, I don't think we got it to $240 million going forward. I think if you look at our current CapEx outlay, you will see that we're sort of looking at that sort of mark plus 10. 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 weeks we've currently got operating there as part of that sort of sustaining CapEx as well.

Yeah, okay. Okay, good. Thanks. Now, in relation to weights here, that's the big unknown with regards to the FY24 production guidance. Just wondering if you could please provide or confirm what percentage of the weights your project is currently complete, please?

On that front, James, we're just waiting for Webull to take the reins 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 a completion. Okay, good.

Thanks. Okay, well, one last quick one. In regards to the price caps of $12 Aussie per gigajoule for 2023, uncontracted gas, I mean, whilst no one really likes government intervention in price caps, is it fair to say that the beach is largely only taxed by this given the realised price of $8.40 in the last half and amount of contracted gas to Origin Energy, that your sort of internal models and cash flows are affected by these price gaps? Is that fair?

Yeah, I think that's fair, James. So I think we're not materially impacted by those price gaps. As you've outlined, most of our gas is sort of contracted and at fixed prices as well.

Yes, exactly.

Okay, cool. All right. Thanks, Moiré.

Thanks, James. Yes.

Thank you. Your next question comes from JL Coenders from Baron Joey. Please go ahead.

Morning, all. I'm just wondering if you could provide some colour on the 10 drilled but uncompleted wells in the Cooper Western flank. What sort of exit rate of production are you targeting for FY23? And 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 it 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 had the work over week running 24-7 more recently in terms of 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. So, 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. So, we want to actually flow some wells, hit the production, and then that will give us the indication of what we can expect from a production point of view going forward. And that's part of the reason why we've got quite a wide range in terms of the guidance we give for FY23. Because there could be a low side outcome, there could be an expected outcome, or it could be a high side outcome from the FOFO as well. So don't want to go into that just yet. And that's the answer. Sorry, say again.

And 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 Plains?

I think that's obviously something which we'll work through, as Mornay'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. So that's important. of the answer to your question. The second component to it will be in FY24, we're looking at doing quite a lot more exploration and appraisal. So it will also depend upon the success of that. So as we work through that information, obviously we'll get a better understanding of what that might look like.

Okay. 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? probability success rates you're considering?

Yeah, we haven't guided to that. So we purposely just wanted to show that there's a lot of, yeah, so 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, and that's why we're spending the capital to go after it. And you can see that there's quite a long list of wells that we're going to 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. So we didn't want to go out 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 more of a definitive answer. Seven or eight development wells at weights here that's flagged for FY24 and 25. 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?

I think that's not looking at Sam here, but that was always the plan to drill it in that sequence. So it starts earlier or later in terms of the sequencing. The first six wells we drilled was needed to get us to production and maintain production and 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. So nothing is earlier or later on that front.

Okay. Thank you. Thanks, Dale.

Thank you. Your next question comes from Saul Cabanich from Credit Suisse. Please go ahead.

Hi, folks. It's just one quick question for 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 contract terms, which you're saying basically are evolving over the term of that SPA. Now, if I run just very quick high level, if I assume, say, a 12% FOB slope, then 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 manage 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 and so on. I can't really answer that question because it's commercial incompetence. But 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 J-CAM versus, you know, brand linkage sort of remains the same over that period. So that's probably as much as I can say, I suppose, from that perspective.

Perhaps the follow-up would be if the spot versus spot energy versus Brentlinkage isn't changing, and what you've given there applies to fixed historic JPM and Brentlinks, what is actually changing that can account for that large range?

Sorry, Derek?

Derek, yes. So I guess one of the messages on that slide is that there are changing parameters for SPA over time, and it's a complex SPA, and it's very difficult to talk to. So when you look at... We know what the prices were over the past 12 months commodity-wise in Essex. When you apply those to the SPA parameters over time, over the five years, you get those ranges. So realise 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 it.

Yeah. I think the other thing to note, Saul, is that I think you mentioned FLB. This contract is a DACE contract. So in terms of, you know, we... Oh, sorry, FLB. Sorry. Yeah. So BP takes the shipping risk attached to the contract.

Understood. But I guess it's like, so it's not really helping in terms of indication here. I mean, we're trying to, we want to model this. The difference between $20 and $30 is huge. And you can't give us an indication of what we should look for, whether it's going to be close to the $20 or the $30, you know, over the 2022 period. Yep. Okay. Yep.

That's what we say. Sorry about that. But we can't give you any more detail than that. So we try to be helpful with the site, but it's... That's as much as we can provide, unfortunately.

All right. Thanks, folks. That's all right. Thanks, all.

Thank you. Your next question comes from Mark Wiseman from Macquarie Group. Please go ahead.

Oh, good day. Thanks for listening to the question. Just on weights here, obviously you've spent a lot of CapEx there and taken the first move in the base and 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 Beech and Mitsui taking on a processing role for other gas? Are those discussions taking place or do you expect them to take place?

Look, I don't want to comment on any discussions, but 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 three gas plants in the area. I think from our perspective, you definitely don't need more plants in the area. So I think it would make sense to have those discussions. But I can't say whether those discussions are happening or not, but I think it would make sense.

And how much additional capacity do you plan 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 weightier plant point of view, we can probably add about 100, 150 TJs a day there in terms of the current footprint of the plant. Obviously, this is subject to all kinds of approvals from an environmental and regulatory point of view. ability at the Bajorra Springs plant that we can look at. So I think from Azara's point of view, that's probably doing as much as it can do at the moment. So that's probably between those Bajorra Springs plant and the Waitier plant that we're probably looking at expansion.

Okay, great. And 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 going to 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.

But negotiations are ongoing.

Okay great and just finally from me, the Otway CCS project, could you maybe just help us to understand what the business model is going to be here? Are you intending to take third party CO2 into that CCS asset and 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?

In terms of looking at the project, initially we look at taking out the CO2 from 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, 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. So I think that's not something we need in terms of sanctioning the project. So we see that from our own production that that project will pay dividends.

Okay, that's clear. Thanks, Monet. 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 and obviously sort of walked away from that FY24 production uplift you're going to provide in August. But just give us your confidence levels there on hitting that target plus.

Yeah, look, I think from an FY23 point of view, looking at the target there and the 19 to 20 and a half, we have more confidence in terms of getting the gas in by middle of this year from the and connecting up the thylacine wells after the EP has been approved . So 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 that with harnessing wells. That is dependent on obviously the weather and how we go there with that program, and then there's the brownfields work to do at the site as well. So that reflects the upper end of that sort of guidance, so 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. So in terms of confidence levels, you know, we're feeling very confident in terms of reaching our target there.

Good, good. And just another question just on costs. I think you mentioned, or Anne-Marie mentioned, just the Cupid JV, just around production costs. Are there any other assets that you're seeing that, or should we assume most of those costs are the Sanos JV that are coming through in terms of higher numbers?

Yeah, the material component of that is the CBJV. I think the other component of that is obviously the production, the guidance that we provided today as well. So in terms of production being lower, that impacts that range as well. But from a gross operating cost point of view, CBJV is the major contributor.

And just final question of 400 to 450 you've talked about for weights here for net capex. How long does that take you out? I'm just thinking about the extra drilling you talked about in 24, 25. Is that in that number as an additional? Just wondering how far out that capex guidance goes for.

Yeah, look, Adam, that guidance is just for the weights here gas plant. So that's just to complete the weights here gas plant, get the first gas out of the door and... With the other CapEx guidance, we'll obviously include that as we go through the guidance. So the drilling we're going after in terms of exploration drilling and birth basin, that's included in our FY23 guidance range. And then when we get to FY24, 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 weight tier capex again. It was reported in the news that the WeBuild contract is reimbursable. I'm just sort of curious, given they only had a short time to do DD on the project, which is well publicised 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?

Thanks, Daniel. So in terms of the DD that's performed by Webull, Webull obviously spent quite a bit of time before Clough went into administration looking to buy the Clough business. And then Clough went into administration and then they obviously did some more DD. So 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? And obviously, that formed part of our decision to sign with WeBuild as well in terms of that process. But in terms of what we saw from other providers, you know, in terms of what we're guiding to, it was there or thereabouts, so materially the same sort of numbers.

Right, similar numbers, okay. Thanks.

I'm just curious if I 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. And perhaps this is the second part of that question. Could you give us a bit of a feel for when it would start to go off plateau in terms of the 205, both before and after enterprise, once it's hooked up?

Yeah, look, in terms of the denominations of 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. And you would have seen over the last, you know, six or so months that that's been variable. So that has been down when some of the LNG plants have gone into maintenance, where they then nominate lower on the off-way side of things. So in terms of the nominations, traditionally in winter we do see full nominations and then in summer traditionally that's dropped off. So going forward, you know, that's I suppose the expectation in terms of winter and summer. And when these files 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. So I suppose it's not a, I suppose an answer in terms of, you know, maximum 205 terajoules a day. It's an answer in terms of it's complex in terms of the nominations from origin, and 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 actually connect in the thylacine wells, whether that's through the high nomination period potentially in the winter period versus summer when that might drop off, but then perhaps the plateau. But 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.

Okay, so a matter of months, not years. Okay. Very good.

And the final one might not be. Yep. Let's just clarify that, Daniel. So in terms of, that's why we're looking at the other wells we're connecting up in terms of Arazona and La Bella, and when that comes in is to keep the plant at plateau for longer. in terms of what that looks like. I suppose I was just trying to clarify that it depends on nominations and when the wells are connected. So if we connect the wells earlier and origin nominate at high levels, that is going to be dependent on when we can get enterprise connected and when the timing on that is.

Right. Okay. Thanks.

Maybe if I can ask it, you know, sort of If you look at Coober 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 in Waitsea, it's obviously about 15% of the Waitsea gas, excluding your Bahara Spring stuff, was downgraded just a couple of weeks ago. Beaches usually carry a bit more 2p for Coober Basin JV than Santos has pro rata, if my memory serves me correctly. So I'm just curious, how can we be confident that there's no downgrade coming for Altway reserves before all is said and done? And is there any risks you see to misestimation or any misunderstanding of the reservoir that could be pointed to as variabilities that would be upside or downside to the currently booked reserves?

Yeah, look, Daniel, I don't want to cover all ground, but obviously there was reasons for Western Bank downgrade reserves. And as we've outlined with weights here, that was obviously informed by the drill bit in terms of what we found. And 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. And, 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. So, 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. So we've drilled the two geographic wells and we've drilled the four thylacine wells. So that has informed our view on the reserves that we have currently in play. So I think from a reserve point of view, we're feeling comfortable in terms of what we have out there at the moment. But maybe I'll get Sam to maybe comment in more detail on that as well.

Yeah, just one clarification. You mentioned on the Cooper Basin joint venture, FY22, to be 100% clear here, we believe our reserves are almost identical to Santos'. There is no difference. I want to be very clear on that. That's from FY22, and we see no reason why that will not change going forward. There's a very good alignment there. And then, yeah, in regards to other changes, I think we want to clarify that with weights, yeah, there was always a very wide range, 1p to 3p. Anytime you have that, then it is reasonable when you get your data to expect the numbers will move around. So in that respect, I think these things are all very reasonable and significant new information. And as Morne has highlighted, we've already reviewed the wells from offshore upway so we have some we believe stability there and then also a stability in the Cooper Basin and we've clarified our position in the weights here in the Perth Basin so I think we're actually in pretty good shape but as always whenever we get new information we'll analyse that and come out to the market as soon as we can.

Great, thanks very much guys for the answers. Thanks David.

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

Thank you very much, and congratulations, Mornay, on your new capital management program. Very pleased to see that.

Thanks, Gordon.

Good morning. Just a very quick question on the FY24 guidance. You've withdrawn that, and your previous aspirational target was 28 MMVOE, but you did highlight risk to that. The commentary today just specifically mentioned the CLUP administration process and regulatory approval uncertainty. And I just want to get some more granularity from you on that because clearly from the CLUP administration process viewpoint, the recent guidance has implied around a six-month delay on timing, and you've given the cost indication. So does this come down to other projects and specifically potential for enterprise to push out? beyond your previous guidance?

Thanks, Gordon. So in terms of what we've set out, in terms of the reasoning, like you've outlined, the club administration process has had a time to the project, so there's no doubt about that, and that's what we've revised our guidance to, and obviously the capital cost as well. I mean, if you think about the Whiteshare plant, you know, net beach, our 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 FY24 production target. So that is the main part of it. The other part, as you've outlined, as well as from an enterprise point of view, we've indicated the FY24. We've still got a few hurdles to go there in terms of, you know, specifically the weather. has impacted us there. So 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 cup administration process is the main process on that. That's impacted that.

Thanks, Morten. And just with enterprise, I think you previously mentioned there was some permitting issues. Maybe that's your regulatory comment. Can you just provide more detail on that?

Yeah, we just need approvals from the Victorian government around actually starting construction on the enterprise well side. So 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. So we're just waiting on that, and once we have clarity on that, we can then start construction on the well side as well.

Okay, just one other from me, Mornay. 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?

Okay, that's just what we outlined here today, Gordon, in terms of talking about the archway 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. And then looking at and how we sort of link that up into our offshore developments there as well. So that's what's meant by that.

Excellent.

Thank you very much. Thank you.

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

Thanks, Mornay and everyone. Look, 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 22 at an 88% success rate. What's changed here in terms of both the quantity and the quality of the drilling targets you're going after here, and how should we read this in terms of the outlook for production? Obviously, there's been a few quarters in recent times we've seen quarter-on-quarter decline in gas production, but should we infer from this that higher production is ahead? Thanks.

Morning, Nick. So just to answer your question, I think we definitely got a higher proportion of development wells that we've agreed to 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. So there's quite a good collaboration between the technical teams around what we should be going after in the basin. So I think that's paying dividends for us and Santos as well. And then the other question you had there is around production. So we do see production stabilizing and slightly increasing from where we've seen over the previous quarters. Again, we reported on some of the unplanned maintenance that happened last year and then impacted by weather as well in the basin. So I think 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. So I think all around good focus from the operator on production and getting production back up.

That's great. Thanks, Mornay. Cheers. Thanks, Dave.

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

Hi. Morning, all. I'm conscious of time. Just a couple of quick ones from me. Obviously, more to play out on the east coast of regulatory environments. If logging artisan and labella is expected, is it fair to assume that you'd be happy to develop those fields at $12 a gigajoule, perhaps inflating forward?

Yeah, look, I think, you know, in terms of developing those fields, it would be great to get more clarity around the code of conduct and reasonably priced gas and 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. So I think there's some clarity needed before we, you know, get things going on that front. But in terms of, you know, $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 of $12, then I would assume that, you know, you would go ahead with those projects But 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, Mornay. And maybe just a quick follow-up then. 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? And if you could share any IRR hurdle rates or otherwise that are required to sanction?

Yeah, Henry, I think we don't share the hurdle rates, but obviously it needs to be above our cost of capital and make us a return above our cost of capital. But in terms of looking at the projects, they go through quite a significant and detailed hurdle gate process as per usual. So we do assess them against a number of metrics, including returns and return on capital and They need to obviously compete against capital from other projects around our portfolio as well before they're sanctioned, but they go through a rigorous process. And as you would expect, we do stress test the projects in terms of low case outcomes, B50, 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. So that's kind of the full gamut of how you would look at a project before you sanction it.

Okay, great. Thanks, Morne. 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 FY22 results presentation you had 77% of FY24 East Coast gas volumes up for repricing or were uncontracted. I was wondering if we could get an update on the percent of FY24 East Coast gas volumes that have been contracted so far?

Yeah, look, thanks, Sarah. So in terms of looking at our position currently in FY24 or looking ahead for 2024, we are, you know, one of those key contracts that's going to come up is around our Otway gas plant. So we are currently in negotiation around that, and obviously that's with Origin. And as we 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. So we are currently negotiating that contract. So that will be the main contract that comes up in FY24 in terms of what we need to, I suppose, contract from a pricing point of view.

Thank you. And 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 off-way. The next one would be a year later, which is relating to the Cooper Basin JV volumes.

Yep. Okay, great. Thank you. And my second question might be for Sam. With your trig prospect being located down dip of Strike South Arigala discovery, I was just wondering what your new 3D seismic survey was telling you about any potential spill risks with strikes 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 Saragola discovery. So 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 strikes area. So we're pretty clear on that. to a knot link directly.

Fantastic. Thank you so much.

Thanks, Sarah.

Thank you. Your next question comes from Scott Ashton from SHA Energy. Please go ahead.

Good morning, Monet and Sam. Just on the back of that last question, in the event of success for Trig, how do you expect that to be developed? Is it daisy change into Waitsea or Bahara? a success case is being developed.

Yeah, thanks for the question. Yeah, and a good one of that. I think our position on this has been it's very much dependent upon the scale of the volume. So 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 weights here is certainly something we would always consider as well. So not yet defined.

Yeah, I suppose, you know, given you've got a participant in the Perth Basin that shows South Aragulla going into your block, so is unitisation 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.

Yep. Okay. And just very cognizant of the time, that'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 those targets there are sort of anywhere between sort of 100 to 300 BCF to justify optimising developments in the basin rather than having all these sort of scatter gun approach to plants that are sort of, you know, of Bahara Springs type scale. Are you looking to sort of, you know, take meaningful volumes?

Yeah, look, I think Scott's been, again, not giving any guidance on potential here, but I think from your question, it's definitely obvious that we'll go for the bigger prospects and targets first. uh before we go for the smaller ones so um you know definitely want to see what that means for us in the basin and how we think about development and whether there's expansion of of plants that could be driven by this or whether it's back full to plants going forward so but definitely from our perspective we're excited about the whole basin so that's why we're going after these wells uh quite quickly and spending their capital and we're quite excited what that means for us going forward in terms of obviously supplying domestic gas market and looking at how we progress the basin. So 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.