Beach Energy Limited

Thank you for standing by and welcome to the Beach Energy Limited FY23 full year results briefing. All participants are in a listen only mode. There will be a presentation followed by a question and answer session. If you wish to ask a question, you will need to press the star key followed by the number one on your telephone keypad. I would now like to hand the conference over to Derek Piper, General Manager, Investor Relations. Please go ahead.

Good morning, everybody. Thank you for joining us this morning for the Beach Energy FY23 four-year results webcast. Bruce Clement is our interim CEO, and he'll be leading the call today. And with us also is Anne-Marie Fabara, our chief financial officer, and other executives are in the room as well. So with that, Bruce, I'll hand over to you.

Thanks, Derek. Yes, this is Bruce Clement, and I am the interim CEO Chief Executive Officer of BEACH. I'd like to begin today by acknowledging that I'm speaking to you from the lands of the Kaurna people of the Adelaide Plains, and BEACH pays respect to their elders past, present and emerging. For the presentation today, I plan to provide an overview of our results and achievements for financial year 23, provide an outlook for financial year 24, And then I'll pass to Anne-Marie to run through the financials in detail. And following this, I'll come back and provide a brief update on our sustainability activities and plans, and also a view on some of Beech's key markets. So I'll just roll onto the next slide. And this is our compliance statements, and I'll draw your attention there to the disclaimer, the assumptions, and some of the reserves disclosure, and leave that for you to read at your leisure. Moving on to slide three, here is a summary of what we see as Beach Energy's value proposition and I think it's an excellent value proposition. We're executing key projects, we're continuing our investment in growth and we have a strong operational performance underlying that. Targeting delivery of material uplift in production beyond financial year 24, we have a number of projects we're aiming to deliver during this year and into the calendar year 24 that will deliver increased production and moving forward cash flows. We are supplying key markets and supporting the energy transition in Australia and New Zealand in particular with our domestic gas. We're in a strong financial position, and Anne-Marie will talk more to that, and we have in place a capital management framework to support that and also return dividends to shareholders. As I said, strengthening cash flows will support those dividends and our ongoing growth plans, and we have multiple organic growth opportunities for the next stage of growth that we are already pursuing today. And on the sustainability front, BCS is a key part of our business, but we are pursuing carbon reduction activities across our business in addition to the key Moomba project that's planned to be delivered in calendar year 24. Just moving on to the next slide, and I'll dwell on this for just a couple of moments or a few moments. What I want to identify here is that we are delivering key or critical new gas supply, but also want to identify the breadth and depth of our business and our investments and what we are doing at Beach. We are targeting growth in production, delivering projects through this next financial year and into financial year 25 and beyond. We expect to see production improvements. This year, we connected the phyllocene wells to the OGP and delivered additional production and well deliverability into that plant. Later this year, we're planning to drill the coupe development well, aiming for increased production into the New Zealand gas market. We installed the enterprise pipeline, and we're planning to hook that up later in fiscal year 24. And wait here, I'll talk to this in more detail later, but the stage two, first gas is targeted for mid-calendar year 24. We do have a pipeline of further organic growth. We have Perth Basin exploration underway. We're continuing our western flank exploration appraisal as well as in the Cooper Basin joint venture. We have a rig secured for the offshore drilling program in Victoria in fiscal year 25 and we are continuing efforts on ongoing production and performance optimization across the business. We have built and are building a unique market position. We've got diversified markets in core regions, in particular in the domestic markets in Australia and New Zealand, as well as obviously in the international liquids market and moving into the LNG space when we bring weights here online. We will have eight plants to supply local and global markets, and we're exempt from the Australian Code of Conduct price cap exemption. We have an exemption, I should say, for that. We are in a strong financial position with good liquidity to support our development activities and growing production from financial year 25 onwards. Importantly, we have set ourselves a sustainability goal of 35% emissions intensity reduction for 2030, and we are building a sustainable business around this. Our gas is key to the transition in energy in Australia and New Zealand and globally as we move into the LNG space. One of those key projects is Moomba CCS, which is at 70% complete at year end. We are pursuing and assessing other initiatives that leverage our expertise and assets in this space. On to the next slide. And I want to focus on our health, safety and environment performance this year. It was another strong year or a very strong year for us. Our second best safety performance on record. You can see the TRIFA performance was down to 2.4 this year. We had a period of six months injury free across the organisation. And in a couple of our plants, Otway and Bahara Springs in particular, we reached milestone performance during those years. during this year, I should say. On the environmental front, it's been another robust performance with no significant spills. And yes, we did get an award, the Premier's Award for our performance on one of our seismic programs in South Australia. Moving on to the next slide. These are just some of the headline results, financial results for this year. I'll leave Anne-Marie to to dive into these in more detail. But you can see there 19.5 million barrels of production, produced 1.6 million barrels of reserves and underlying EBITDA of a billion dollars, which is a very strong performance. We've seen increased domestic gas prices and we're able to deliver an increased dividend this year. And as I said, liquidity is in a good position and gearing is low moving into completion of our development programs. Next slide. This is a slide to identify some of our key milestones achieved during 23 and also looking a little bit forward into 24. We're delivering on our growth projects. Thylacine North 1 and 2 were connected this year and added significant volumes to the Otway gas plant deliverability. We've had another successful Cooper Basin drilling campaign, both in the joint venture and the western flank drilling. Our Moomba project, as I said, is 70%. The CCS project is 70% complete. And the Waitsia development drilling was completed during the year, and we're moving forward there into an exploration and further development program in this financial year operated by BEACH. The enterprise pipeline was installed, and we're looking to connect that later in this financial year. In the Waitsia gas plant, I'll talk to this in more detail, but we have turned that project around as a joint venture with WeBuild, and we're moving forward there to start first gas there in mid-calendar year 24. We are currently mobilising a rig to Coupe South, planning to spud that well later this calendar year, and targeting bringing on more gas into the domestic market in New Zealand. And on the western flank, as I said, 22 new oil producers. And we have secured a rig, as you'll see, for the offshore Victoria drilling program planned for financial year 25. So just move on to the next slide if we can. Just want to address a couple of our key projects, Otway and Perth Basin with weights here. The Otway project has been a significant success for us. It was. the largest drilling program completed in the Otway Basin, which we finished earlier in this financial year. We've now connected four development wells and we've increased the Otway gas plant well deliverability to 170 terajoules today, supplying into the East Coast domestic market. Part of that drilling program, as I said, three wells in particular represented significant and the longest horizontal drilling campaign we've conducted there, 8.1 kilometres of horizontal sections in those wells and they are delivering into that gas plant now. And we received an APS Safety Project Excellence Award for our performance during that drilling program. So on the next slide, Waitsier Gas Plant, as we recognise this is This project, we recognise, has had its problems, particularly around the insolvency of Clough, our major contractor, in late 22 and into 23, which obviously had a disruptive effect on the project. We have worked together as a joint venture to move this project forward, re-establish it, and it now has momentum going forward. We're seeing significant progress being made there, and we anticipate first gas being delivered in mid-calendar year 24. We've recast our capital expenditure forecast for 50 to 500 million net to beach. First gas from the plant is planned to be sold into the LNG international market up to 3.75 million tonnes over the period to 2028. We have a hybrid pricing model for that or hybrid pricing contracts for that. And we're LNG processing through the Northwest shelf. And that was secured in 2024. I'll just move on to the next slide. This is our guidance slide for fiscal year 24. You can see we're guiding production in the 18 to 21 million barrels of oil equivalent range. The range is a little larger than what we had forecast for this year, and that will be driven by potential timing of startup of a couple of our development projects, as well as the offtake arrangements in the Otway, given we now have additional well capacity there and our contract offtake will determine to some degree the amount of gas we produce and sell out of Otway. On the capital expenditure side, we're forecasting $850 million to $1 billion of capital expenditure, and you can see there the breakdown between development, exploration, appraisal, and our stay-in-business capex. On the development side, clearly Waits here and Otway are in there, as well as Coupé. But the ongoing Cooper Basin Joint Venture and Western Flank Drilling programs are also in there. So significant activity still on the development front from which we're expecting to see results later in the financial year and into 2025 and beyond. On the next slide, this is a timeline to give you a sense of activities and when they are happening and going to be delivered coming to the market as information. You can see there are five key areas for the company that we're working in. Coupe, we have the Coupe South 9 well being drilled or planned to be spudded later this year, aiming to bring that production on during the financial year and into the gas market in New Zealand. On the western flank, we have an ongoing drilling program. This year, focusing a little more on appraisal and exploration program. But again, bringing wells into production there, we would expect during this financial year and on into the future as well. In the Cooper Basin, we have, on the joint venture, I should say, we have four to five rigs operating there across exploration, appraisal and development. And again, bringing more oil and gas production into the basins, into the Moomba plant. In the Otway Basin, we have... Significant amount of activity planned. We've tied in, as I said, the Thylacine North 1 and 2 wells, and we've seen extra production now into the gas plant. We plan to hook up the enterprise wells into the pipeline that's been installed later in this financial year. And then moving into financial year 25, we're planning to bring on the Thylacine West 1 and 2 wells, again, delivering gas into that Otway plant and into the East Coast gas market. And we have the offshore Victoria gas project planned to be active during fiscal year 26, and we'll be getting prepared for that in the coming years. In the Perth Basin, as I said, we're targeting Waitsea Startup first gas mid calendar year 24 to a considerable amount of work to be done there and we've seen accelerated activity there and performance from the contractors has improved significantly. In the background or in the foreground now, we have an exploration program going on in the Perth Basin as well as some further development drilling planned across discovered fields during this financial year. Move on to the next slide, and this is a summary of our reserves and resources position. We have a very good reserves and resource base for the company. I won't dwell on this for too long, other than focusing on the change in 2p reserves for the year, which saw us. The delta there is driven by production, 19.5 million barrels, and the remainder is largely the revisions to weights here post the development drilling. earlier this financial year. We have a good contingent resources base and we'll be pursuing that through drilling across the portfolio in the Otway, WA, Kupa and to a degree in New Zealand with Kupa. So I'll leave it here but the message should be that we're in a very good position moving forward into this financial year. We have a number of projects we're delivering and I'll pass over now to Anne-Marie to talk more in detail about the financials.

Thanks, Bruce. Good morning and thank you again for joining us today. This morning I'll be taking you through the financial results for FY23, starting with slide 14. Our financial results are largely underpinned by production, and this year we produced 19.5 million barrels of oil equivalent. The decline in production of 11% was a solid result in a year where production catalysts were limited, as we focused on delivering major growth projects. Production composition continues to shift more towards gas as the Thylacine North wells were bought online late in the year. This trend will continue in FY24 and beyond with substantial new gas supply to come from Enterprise, Waitier Stage 2 and the Thylacine West wells. Our headline financial metrics are set out on slide 15. It was a robust set of results in a year of focused project execution. Sales revenue was down 8% to $1.6 billion, with a higher realized gas price partially offsetting lower production. A 9% increase in gas prices reflected the continuing tightening of domestic markets and additional volumes directed to the spot market in the second half. Lower revenue flowed through to lower earnings and cash flow, with a 12% decline in underlying EBITDA to $982 million and operating cash flow of $929 million. Higher DD&A from increased Otway Basin production and higher financing costs from higher discount rates on non-cash unwindable liabilities flowed through to our underlying NPAT of $385 million. A breakdown of our underlying NPAT movements is set out on slide 16. Lower revenue was a key driver of our reduced NPAT in FY23, which, as mentioned earlier, is largely impacted by production and sales volumes. Higher cash costs is largely driven by an increase in third-party purchases, noting this is offset by higher third-party revenue, with accelerated Cooper Basin JV activities increasing field operating costs. Higher DD&A is a result of increased Otway Basin production, with higher non-cash financing costs as a result of an increase to discount rates on liabilities. This is offset by higher realised gas prices, as I mentioned earlier, along with lower restoration expenses, with FY22 including revised restoration estimates for assets in abandonment phase. Slide 17 sets out movements in cash reserves. Operating cash flow was 24% down to $929 million. Again, this was largely driven by lower revenue and higher cash cost impacts, along with high income tax and restoration payments during FY23. It was a year of elevated capital expenditure, with $484 million of capital expenditure directed towards our growth projects. Sustaining and staying business capital expenditure of $687 million also increased from FY22 levels, largely due to an accelerated work program and additional activities undertaken in the Cooper Basin. We drew down on our debt facilities to support major growth projects during FY23. We generated $221 million of pre-growth free cash flow during FY23, supporting the declaration of a $0.02 per share final dividend, a 100% increase on the previous year. Turning briefly to our financial position on slide 18, we ended the financial year with net debt of $166 million as our major growth activities progressed. This represents net gearing of 4%, which is well within our target gearing of less than 15%. Available liquidity remains strong at year-end at $434 million. Combined with our strengthening cash flow outlook, BEACH is in a great position to deliver our current growth projects targeting a material uplift in production rates and cash flow by the end of FY24 and beyond. You may have seen slide 19 from our half-year results when we implemented the new capital management framework and dividend policy. Our policy was designed to provide transparency, utilise our franking credits, which are roughly 600 million, and reward our shareholders for their ongoing commitment to our strategy. Having implemented the policy, A highlight this year was the 100% increase in declared dividends, increasing from $0.02 per share last year to $0.04 per share this year. Our capital management framework is a core component of setting the foundation for continued growth and increasing returns to shareholders. Now I'll hand back to Bruce to provide an overview of Beaches' sustainability performance and our markets.

Thanks, Anne-Marie. Firstly, I'd just like to address sustainability. And in particular, the slide here shows the Royal Flying Doctor Service aircraft. This year, we're celebrating our 21st year of support for the Royal Flying Doctor Service. And it's a key part of our ongoing support for communities, particularly in regional and remote Australia. And RFDS obviously supports us in our activities in the Cooper Basin. So just moving on to the next slide, we are building a sustainable business at Beach. We are actively pursuing emissions intensity reduction. As you can see on the slide, we have set our target for reducing intensity emissions by 35% by 2030. And this year, with projects that we've implemented, we've achieved an 18,000 tonnes of CO2 equivalent reduction this year. The Moomba CCS project will be a big step change in reduction of carbon emissions when we bring that online in 2024. And we are focusing clearly on improving our performance there and on reducing our environmental footprint. On the social side, we are engaged with local communities. We've contributed significantly in local communities. both through money and also through volunteering, which is an important part of connecting beach staff with our local communities. We have good governance and we are actively and properly reporting our sustainability performance. I'll just move on to the next slide. One of those key projects on sustainability is the Moomba project. And, yes, we're targeting a 35% emissions intensity reduction by 2030. And the Moomba CCS project, which has been reported by Santos to be 70% complete at year end, moving forward for commissioning and start-up in calendar year 24. Targeting initially a 1.7 million tonnes per annum of CO2 storage, 0.5 million net to... to beach with the potential to go to 20 million tonnes a year. This is a big project, biggest in Australia obviously, and globally a very large project and important to us and will be a cornerstone of improving or reducing our carbon emissions. We're also looking at several early stage initiatives that I won't go into here, but clearly all of this material is covered in detail in our sustainability report that we have released today to the market. I'll just move on to the next slide. And I want to just talk a little bit, not a great deal about markets, because you're obviously going to be most familiar about these. And go on to the next slide. We are supplying energy into a number of key markets, importantly into the Australian domestic gas market, East Coast and West Coast, and in the New Zealand domestic gas market and LPG market as well. But we are selling liquids into the global markets liquids market and we will be once we have weights here up and running selling LNG into that global market as well. Selling gas in Australia and New Zealand is an important part of supporting the local economies and supporting the transition, the energy transition that's underway. We see in all these markets a tightening of supply and beach is well positioned as it moves forward to supply into these tighter markets. We have been, whilst much of the industry has been cutting back on investment in exploration and development, beach has been investing in these activities and we're going to see the benefits of those as we bring additional production into those markets in financial year 25 and beyond. Just on one of those key markets, next slide. is the East Coast Australia market, and I think most people are familiar with this slide showing supply and demand and the supply shortfall coming in later this decade. That's a key part of our business. We'll be supplying into that market, which we'll be tightening, and also, importantly, delivering gas that can support that transition into renewable energy supply markets. Just on the bottom right, you can see there where our position, particularly in relation to East Coast Gas and our contract position. At the moment, we have largely contracted gas, but we're moving into uncontracted position over the next three years with around 50% or more of our gas currently not contracted that we're expecting to sell in that period. We have price renewals going on as well through this period. So Beach is well positioned to sell into tightening markets where we're expecting good pricing for our gas. So can I go to the next slide? And that's where I'd like to end today and just provide you with a wrap-up and we'll go to the next slide and follow this with Q&A from those online. This is the value proposition I put up at the beginning. I think it's valid and I think it's a very strong position that BEACH is in. I believe we are going in the right direction and we're going to increase our production beyond 24 and we're going to see further growth in the company as we pursue additional initiatives in our exploration and appraisal programs. And underlying all that will be our move into providing a much more sustainable business, reducing our carbon emissions intensity and continue to work strongly with our local communities and delivering a safe operation in the future. So I'll leave it there. And we can go to questions and talk to all. 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 then 2. If you're using a speakerphone, please pick up the handset to ask your question. The first question today comes from Dale Coenders from Baron Joey. Please go ahead.

Morning Bruce and team. Just a couple of questions on production capex guidance which looks a little bit soft. What are you assuming around wave production within that FY24 guidance noting that industry data shows that asset sitting around 50 TJs a day through July and August? And why is the customer only taking minimum volumes?

Dale, on the production side, we can currently deliver 170 terajoules a day into the plant. I can't comment on why our customer is only taking it 50 TJs a day. I can speculate, but can't comment on what their decision-making process is for that. You will have seen, if you're looking at the AMO data, that prior to this financial year, they were taking up to 170 terajoules a day. So there is deliverability there and we can supply it. The contract that we have in place obviously is a heritage contract we acquired through the lattice acquisition and we are working to sell as much gas as we can. It's there and available, but I can't speak for our off-taker.

Can you give us any hint as to what FY25 looks like? You've spoken a lot of times about investing for growth. what does production in FY25 look like versus 24, or what are the key moving pieces you see?

We're not providing a forecast into or out into fiscal year 25, but the key moving pieces in that will be things like weight here coming online in that period, and That's a 250TJ a day plant, of which we have a 50% equity, delivering into the LNG export market, as well as continuing to deliver gas into the domestic market in Western Australia. We'll see additional gas getting into the Otway gas plant, but again, the Otway gas plant You know, above 200 TJs a day is pretty limited at the moment, but we're looking at opportunities there. And we'll also see some additional gas from the Coupe South Ninewell coming into the market in New Zealand. So we haven't given a forecast on fiscal year 25, but you can see quite significant upticks across the business in delivering of volumes.

Okay. And then just in terms of the CAVEX guidance, can you provide any breakdown by project? I guess it's quite rare for a company just to talk about how much is spending on development versus exploration. Just trying to understand where all that money is going.

We haven't provided the detailed breakdown by project, but in terms of staying in business, you'll understand that's across the portfolio of assets, particularly probably focused in Cooper Basin projects. Westflank and the joint venture in particular because there are significant spends on old kit there. The development side we have and you can see from the report and particularly in the quarterly reports where the capex has been spent we would anticipate similar expenditure levels across the Cooper Basin, Westflank and joint venture and weights here obviously is a key part of this as well. We have a well in New Zealand we're drilling and we have some tie in work in the way that we're planning as well as obviously bringing those extra two wells on in fiscal year 25.

Okay, thanks. I might jump back in the queue.

Thank you. The next question comes from Tom Allen from UBS. Please go ahead.

Good morning, Bruce and Marie and the broader team. Congratulations, Bruce, on your appointment as interim CEO. Just following that last question, which presumes some conservatism in FY24 production guidance due to the uncertainty over Otway nominations, assuming all going well, over what time frame might you expect the lattice price review arbitration to conclude?

I can't comment on when that will conclude. We have a negotiation or price review in process right now and I can't really comment. That's a commercially sensitive area of the that I can't comment on. Yeah.

Can we reasonably assume, though, Bruce, that given that negotiation has already been through an arbitration last time, which set the process, and so having a better understanding of how that process will work now, is it reasonable to assume it doesn't take as long as the last arbitration?

I think arbitration you can't make any assumptions about. The time it will take, because the arbitration will be There'll be different players involved. But we are working hard to get it resolved and get it through.

No doubt. Also, with Enterprise Gas well positioned to pick up some of the available capacity at the Otway gas plant, can you share some colour on the process to secure that native title approval enterprise? Like, are there any unique sensitivities that could add material risk to the timeline to secure that approval? Just recognising that you've broadened guidance for first flow from year end to second half fiscal 24?

I mean, yeah, look, that process is in train and happening, and we're confident we'll come through with a solution that works for everybody involved. These processes, and as you'll be aware, regulatory processes that are subsequent to that take time. They're never quick, and I can't give you a specific timeframe, but we're obviously working as hard as we can to get it resolved and get it finalised. And we're working with native title parties, partners in this case, who are working to achieve the same results. So we're positive about the outcome and moving forward, just the timing is never certain on these processes.

Okay, thanks. And then just regarding the new CEO appointment, Bruce, can you please share some insight on the specific skill set that the board were looking to strengthen within Beach in appointing Brett Woods as the new CEO?

Look, I can't expand any more really on the release that was made, the decision being made to obviously replace Mornay with Brett. Yes, they come from different backgrounds, but I can't really specifically address anything further beyond what was put into that ASX release. Yeah, and I'm here for that six-month interim period. Okay, thanks, folks.

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

Good morning, Bruce. Glad to reconnect with you. Firstly, on weight CR, what could you say to us in the public markets to make us feel a bit more comfortable that this is the last downgrade?

Well, I think you can see from where we are today is the joint venture has worked really hard with, I guess, rejuvenating and getting past the hurdle of the Clough insolvency. That is disruptive. That disrupts on many fronts, you know, not just with the contractor company, with their employees, with their subcontractors, with the supply chain. Whenever you're in that insolvency position, nothing really is being progressed. So we've had to basically restart this with WeBuild. We've now got a significantly larger workforce on site than we've had previously, almost doubled the numbers over this calendar year. And we are seeing progress and good progress being made. Nothing is ever certain here, but we have confidence that we're going to deliver this first gas in the middle of calendar year 24. The cost side is our expectation against that delivery timeframe. So yes, we are confident, but you can never be certain.

Got it. Okay. And my understanding was that Beach had some gas that was held in storage that could be withdrawn from the start of the calendar year when that LNG contract goes live. Is that what is meant in the footnote that you're looking at offsets to that $65 million charge for your transportation liquefaction contracts?

Yes, we are. Obviously, that's an initiative we're taking. We have some additional xyrus gas that we are able to put into storage there locally and we would hope to be able to utilize that to meet some of that contractual commitment yeah any any steer on the volume of that gas like is it sort of low number of petajoules low single digit i can't i mean we're working on that i can't give you specific numbers but you can you know you can probably draw some conclusions from the size of Ziris relative to the size of weights here as well.

Yeah, got it. All right, I'll leave it there. Thank you, Bruce.

Thank you. The next question comes from James Redfern from Bank of America. Please go ahead.

Good morning, Bruce and team. I was going to ask about the FY24 production and capex guide, which we've covered on that. Maybe if we could please dig into the Otway gas projects in terms of The capacity that you talked about, 170 TJs a day and then nominations of 50 TJs a day, maybe just from my understanding, is Origin the sole off-taker for gas from the Otway and I guess just maybe some colour area why they're taking such little gas, I guess. Is that due to weak customer demand or is that weather and do you see that kind of changing any time soon? Thanks.

Tricky question, given that we don't really know what the drivers are for Origin in their off-take arrangements. Yes, they are the off-taker under the contracts there. And they have obviously been... They took 170 TJs a day for periods up to the middle of the year, and they're now taking around 50 TJs a day for gases there and available into that East Coast market. But it's locked away under that contract, so can't talk to why they're doing it. Clearly they have different sources of supply that they can draw on but we are working with them on the price arbitration and we'll see where that takes us in the very near future.

Okay, thanks Bruce. My second question is just maybe on the gas markets just in terms of I guess where market pricing is for sort of three to five year contracts at the moment. Is it still kind of $11, $12 a A gigajoule?

Thanks. I'm really not able to talk about, you know, commercial incompetence contract pricing, so I'll have to skip that one.

No worries. Okay. Thanks, Bruce.

Thank you. The next question comes from Saul Kavanick from Credit Suisse. Please go ahead.

Hi, folks. A few questions from me. Look, I want to just come back on the new eight-year guidance, particularly the start-up in mid-calendar year 24. I mean, Bruce, can you give us some more colour on exactly what is this new guidance based on and the rebound behind it? Because I think it's now widely felt in the industry that this isn't just an issue of the class insolvency, but it's also an issue of operator competence here. And, you know, What really goes actually behind this mid calendar year 24 number, because what's stopping that being end of calendar year 24 and there's another $65 million charge in addition to the delay that could occur here?

What is behind this is we've had a rigorous review of project status with the operator and with the primary contractor and their project management teams. We've been through that on both schedule and costings. And at this point in time, this is our forecast, and it's a beach forecast of where we expect the project to be delivered. Yes, there are risks in project delivery, absolutely, and we've all seen that to date on weights here. Yeah, but look, I would certainly say that the biggest disruption was most definitely the – position of insolvency and the consequential knock onto into everything when you're in an insolvent position no one's dealing with you and you are struggling to get work done and things delivered to a project in that state so that was a major disruption we've worked hard over the last few months to I guess redirect the ship and get it going in the right direction and this is the result of that a lot of work by the operator and the joint venture and beaches position and our estimate of when it's going to be complete is that mid-24 and that cost estimate.

Right, so has the level of rigor here been significantly higher than, I guess, when you gave us an updated guidance back in January, February?

Look, I don't really want to pursue it too far, but January, February was in total disruption under the CLUF contract. We've now had a period of time with WeBuild there. We've seen performance on site. We've seen a lot of initiatives taken and delivered in terms of getting people on site, running day and night shifts, those sorts of simple project things that are being done now. And we now have good project management tools and people in place. And on the back of that, that's where our estimates are coming. Thanks.

Jumping to enterprise projects, It seems the language has also changed here a bit to now targeting start-up in H2, FY24, versus I think it was only a month ago you're talking about mid-FY24. Is there any reason to, you know, is this where the approvals are looking at causing a delay by a few months?

Look, we are including timing in there for approvals, both native title and regulatory approvals that are appropriate. And we've got some work to do, obviously, tying in the well to the pipeline and getting kit and construction activities completed. So, look, aren't we comfortable with that? Yes, it may have moved a little bit from what we were talking about a month ago, but, you know, we are working on native title agreement and subsequently we'll work through the regulator to get final approvals to complete it. Those things do not happen overnight. We've obviously gone back, reviewed our schedule, and that's where we're at. Okay, great.

And just a couple more just on pricing. WA gas prices, my understanding is you have your domestic contracts roll every year or so there. As the latest quarter, latest numbers reflected, the higher gas pricing we've seen in WH is now, you know, we've seen spot pricing over $10 versus I think your contracts over a year ago were close to $5. Has that been reflected in the last quarter's numbers or is that something we're only going to see over the next 12 months as contracts roll?

Look, I may have to take that one on notice. I don't have an answer for that, particularly in relation to those WA contracts at this point in time. But directionally, what you're talking about is correct. As we roll forward, we're into a better spot price market and we'll see contract pricing increase as we move forward. We're selling Zyrus gas into that market and Bahara gas into that market and it's improving.

On the East Coast gas pricing, where you have the price reviews, is there any scope that, I guess, the delay we've seen in some of the tie-ins is going to push back some of the production subjects of the lattice price reviews kind of backwards beyond this half? Depending on how the price views kind of play out, does that actually see those volumes achieving a higher price than if they'd actually been produced in this half? Because they weren't subject to any cap this half, but it could be an uncapped reprice basis from calendar year 24 onwards?

Not sure that I fully understood that question, but the situation there is obviously we're repricing the contract with Origin at the moment or negotiating on that. And as we move forward, those volumes will, they're not going away, they're going to be sold. It's a matter of timing and we expect that there'll be a significant contribution of those volumes into this financial year's results or performance. And rolling forward, you know, we're expecting, as we've shown on the slide, you know, we're going to have a significant proportion of uncontracted gas and most of what we've got is going to be repriced over this next few years as well. So we're pretty confident about where we're going with the Otway gas. Thanks, Bruce. That's all from me.

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

Yeah, morning, Bruce Emery. Just back on Otway, it's obviously an important asset. Is there anything the government can do here or anything you can do just around maybe sending gas to someone else? Because obviously the East Coast gas market needs more gas. And then also you've obviously invested capital here. Is there a sort of minimum nominating quantity over time? Does that change? Because obviously sending 50... TJ's done a lot of gas.

It's a reasonably complex question you're asking here. In terms of the government, I mean, that's up to the government. They're obviously aware of what's going on. They'll see the numbers that are being reported on take and availability. In terms of going forward, yes, as we move into future years, you'll recall that starting this calendar year, we didn't have the extra wells on, so we didn't have the capacity, so arguably we couldn't nominate a higher deliverability. In future years, we'll be able to do that under the contract, but there is a fair range in minimum off-takes, but we'll be starting from a higher base, so to speak, in terms of deliverability in future years.

Okay, that's good. And just one other question, just on costs, what are you seeing both on operating costs, you know, Cooper Base and Otway, what are you seeing there? And obviously also drilling capex going forward, please.

I could say I'm seeing lower costs, but that would be absolutely misleading statement. I think the industry as a whole, and you'd be aware of this, is seeing costs increase across the supply chain in all areas. So, yes, we are working very hard to control costs, as are our partners in projects in WA and in Cooper Basin. And, you know, that's a focus for our business and everyone's business at the moment. But, yes, the underlying move is upwards in costs. Okay, thank you. That's all from me. Thank you.

Thank you. The next question comes from Max Vickerson from Morgans. Please go ahead.

Good morning, Bruce. I won't put a few questions on Otway, given I think that's been pretty well covered, but just wanted to understand, with weights here, previously indications were labour shortages were some of the key hold-ups on the project, particularly ENI tradespeople. Given the CAPEX guidance today and just a shift outward in time, is it still fair to assume that it was that labour shortage or there are other potential engineering-related issues that may be causing some delays? Any kinks that need to be worked out there?

Look, I think the labour shortage... And remembering that, you know, Clough were in a difficult position in terms of engaging subcontractors and contractors to work for them. Yes, there was a labour shortage earlier this year. We have resolved that as a joint venture with WeBuild. We've actually got more accommodation on site and in camps and available. We've been able to access additional E&I facilities. staff and or contractors on site and we are getting over we're past that hurdle we're not past it but we've got a solution for it um and we're moving forward yes as i said we are seeing performance improvements significant improvements over prior periods and um you know based on that and our forecast our estimates of the project performance we expect to be first gas middle of next year excellent thank you

Maybe we'll try my luck on Otway then, Bruce, and just ask, look, how relevant do you think spot markets are? I know you can't really comment too much on origin thinking, but, you know, are spot markets the relevant benchmark here for relative attractiveness of your gas, or do you think the broader portfolio that Origin might have is...?

Yeah, look, we have contracted gas going to Origin. There's absolutely no doubt about that. But I think the spot market is a good indicator of where we're going on repricing in the future and also some of our uncontracted gas coming into the market in the East Coast, both out of Cooper Basin and also Otway. So it's a good indicator of the future, but at the moment we have a contract with Origin. Okay.

That's all for me. Thank you.

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

Yeah, thanks, Bruce and Anne-Marie. Just some clarification questions on the FY24 guidance. First of all, in production, have you assumed any contribution from weights here stage two in that range at all? Just making that comment in relation to the slide 11 that does show the potential for weights here to start up for the end of FY24. So just understanding whether there is any contribution potentially at the upper end of that range. Thanks.

Well, there is potential for contribution if we can get the project first gas up and running during this financial year. And in that range, yes, a small amount at the upper end would be delivered. But, you know, we're not talking about many, many millions of barrels of oil equivalent, but getting gas into the pipeline and up into the northwest shelf, yeah.

Got it. And just on Western Flank Oil, not much commentary in the result here about it, but at the quarterly, there was a talk about switching... from a development focus to more exploration and appraisal, just thinking because of this shift, should we expect lower oil output in FY24? If I do the math, I think on slide 10, the percentage contribution looks like there's at least a 10% year-on-year decline in Western flank oil output. Is that a fair assessment?

I might throw to Sam Algar to give you a response on that one.

Yeah, thanks for the question. We're not guiding on any specific production decline. For the western flank, you're right, we are shifting towards for exploration and appraisal. That program's still in the planning stages, pretty advanced. We expect to begin drilling some of the exploration wells imminently, up to about 21 exploration and appraisal wells. And I think the answer to your question is, depending upon the outcome of those wells, exploration obviously is much less predictable than the production wells, which we had great success in FY23. But with some success, we'll be looking to tie those in. Many of them will not be tied in until the latter part of the year, the financial year. So they're unlikely to have an impact. And so what you'll see in FY24 is predominantly a decline of the existing assets offset by any infield work, which we obviously are focusing on too.

Thanks, Sam. No OPEX or DD&A guidance released today. Why is that?

Anne-Marie? Thanks, Nick. We've kept it simple with production and capital. OPEX and DDNA cost per Bowie are obviously very largely driven by production, and given the wide range of production that we've put forward today, it didn't feel appropriate to put guidance out around OPEX and DDNA.

Okay, great. Just a final one for me. Just on Perth Basin exploration, looking at the list of wells on slide 31, it looks like a couple of the wells have fallen off the list that was presented six months ago. And the follow-up activity six months ago had a date of second half FY24 is now labelled as TPC. Can you just talk about what results you need to see from the drilling in first half FY24 to commit to those additional wells and whether the cost of those conditional wells is included in your FY24 CAPEX guidance range? Thank you.

I might get Sam again to address this one.

Yeah, thanks for the question. Probably a complex one to follow through with uncertainties in the drilling results. Obviously, we're drilling ahead with the Trig Northwest one as we speak. That would have a bearing on our level of interest in pursuing Trig North. The other wells, so Redback South Deep, would be somewhat dependent upon the results of Redback Deep. and the other wells are related to the position with our seismic reprocessing largely as well as also just slotting the wells in time wise we have a rig contract or mitsui has extended the rig contract and we want to make sure that we focus on the further weights your development drilling so we want to balance those things out together

So in terms of CapEx guidance provided today, is it fair that the conditional program is what partly drives the upper end of that range?

Yeah, that could be included certainly in the upper end of the range.

Got it. Great. Thanks, everyone.

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

Thank you, and nice to see you back at the helm of the ship. It's been a few years. Just very quickly on the contract for the new vessel for the thylacine flowline work, where is that suited at the moment?

I'll get Ian Grant to address that one. Yeah, hi, Gordon. We're still working through the options, Gordon, at the moment.

Don't feel on timing on that?

Yeah, I mean, there's opportunity. There's a few vessels there that we're looking at. So we still feel that in line with the guidance that we've provided, we'll still be able to achieve that, you know, get online the second half of FY24. There's no real issues we're concerned about.

Okay. And this maybe comes back to Sam. Timing on Trig Northwest, Sam?

People have been asking me that question quite a lot recently.

That's probably the answer, Gordon. Well, is it taking longer than budgeted?

No, it's all entirely in line with expectations and we're close to the objective.

Okay. And lastly, just on the $65 million for LNG costs, am I correct in assuming that's mainly transportation?

It's Yeah, that's right. And processing. It's a transportation processing. We have an agreement, you know, a supply or pay agreement with Northwest Shelf as well.

Why has processing gone up?

No costs have gone up, sorry. No.

Okay.

So the guidance that we've put out is basically noting that we, obviously, as part of all the arrangements that we've locked in place for the processing and sale of LNG, We've had to lock in capacity and obviously some of that cost will still need to be paid whether or not we have gas to flow through in line with that.

Got it. Thank you very much. It's all for me.

Thank you. The next question comes from Sarah Kerr from Morgan Stanley. Please go ahead.

Hi, Bruce and Anne-Marie. Thanks so much. Just again on that $65 million one-off cost that may be incurred from the delay awaits here, can we expect an $11 million cost per month run rate for any further delays to the project?

So what I'd say there, Sarah, is the cost will be incurred whether there's gas or not. So I wouldn't be forecasting additional costs whether there's gas or not. So I would assume that you've already got an assumption around costs for the year. We're just flagging that the costs will start earlier than gas processing.

Okay, thanks. And just one more question, if I may. This one might be for Sam. So just on the independent audit on your reserves, I saw on page 37 of the annual report, I just wanted to understand why only 66% of the 2P reserves were audited and 60% of the undeveloped reserves. And did this include Waitsia and Western Flank Reserve? Thanks.

I might pass that one to Sam. Yeah, go.

Thanks, Sarah. Yeah, so we have a policy of reviewing at least 50%, so that's in line with our policy, and it did include Waitsia and Western Flank.

Okay, great. Thanks so much.

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

Hi, morning all. I just want to drill into Waitseer some more. Specifically, what are the key milestones over the next year required to complete development and commissioning at Waitseer? And are you planning to provide updates on these through the year?

So I'll pass to Ian just to give you an idea the key milestones? And the answer to that is obviously yes, we will be, particularly through quarterly reports and the like, providing updates on weights here as we go forward in financial year 24.

Yeah, so obviously Bruce has already mentioned the fact that the labour issue is being managed. I think the other thing that I'll probably mention here is just the key issues, long leads and stuff, are in good shape as well. So those things will guide the facility through. We'll get mechanical completion and then obviously commissioning, which I think for me, I just want to mention that really briefly. It's really important that we hit RFSU, and we're talking about it here, but there's a lot of work and effort going into making sure that when we commission the plant, it comes online smoothly and reliably. So, you know, look at the guidance here. We're sort of starting behind that, and I think you'll see results come through over the next few months.

Okay, great, thanks. And so it's fair to say that I guess it's really labour and timing now. Are there any other long leads required to be shipped and installed on site?

The key thing is really labour, as we've followed the address today.

The long leads are under control and will meet that schedule as we have. In fact, most of the kit is delivered. But the labour for on-site construction ENI in particular was an area of concern, but that has been addressed and is being addressed as we speak. So we have looked at this in detail and, you know, mid-2024 and the cost we've put out of where our estimates are at.

Got it. Great. Thanks. And maybe jumping back onto resources. So we've come through with the 37 million buoy downgrade of Perth Basin 2C. Is this largely from the drilling in the fault block from weight zero earlier in the year or anything else that's driving that?

I'll let Sam address that one again.

Yeah, so that, no, it's unrelated to activities in weight zero drilling. So that is largely a reclassification. We had a reasonable 2C resource or some tight gas in the Perth Basin, and that would require fracking, and given we're unable to frack in WA, we decided to move that to development on Viable. Takes it out of our reported 2C.

Got it, okay, thanks, Sam. And maybe just a quick one to follow on there. How are you thinking about production testing and appraising and booking resources in the Perth Basin over the next year? Would you be looking to... update the market with any volumes as you go or wait until next year?

I think it would be prudent for us, obviously, to look carefully at what information we have and make sense, in my mind at least, to potentially drill some further appraisal wells in some of the features. Others may not require appraisal wells. We may be able to update the market. Obviously, whether that's resources or reserves will depend upon a number of factors, including their the certainty of their development and the timing of that development. So I don't expect you will see us announce reserves and resources immediately after drilling. I think it's more prudent to follow through with that later on.

Okay, thank you.

Thank you. The next question comes from Scott Ashton from SHA Energy Consulting.

Please go ahead. Good afternoon, Bruce. Just a very quick question on the $65 million. So is that a provision that's embedded in the non-current liabilities or current liability? And the $65 million, that's in parallel with the expected start-up for late year and next year. So it's the full mid-24 start-up penalty, for want of a better word.

Yeah. I'm happy to take that question. Thank you. So in relation to whether it's better than our liabilities, it's not because it's actually not yet incurred. Our contracts are not for yet processing LNG or transporting LNG. So that will only be a liability when we actually, when the contract is on foot and incurred. So you won't see that liability, but you'll notice that it's sitting within the accounts disclosed as an operating expense commitment in the future.

So it's not a contingent... Well, OK, so it's not sitting in the provisions or in the... No, no, it's not yet.

It's not yet earned or incurred.

And then... Sorry.

Sorry, you go.

So I just want to understand, so that $65 million is your best estimate dovetailed to the anticipated start-up of the weight CS next year. So if it comes on earlier, it could be lower. If it slips, it could be higher, as I think someone... potentially alluded to in one of the earlier questions.

So the 65 that we put relates to FY24 costs. So we've sort of guided to that because we've put guidance out for FY24 only.

That's great. Thank you very much.

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

Oh, good day. Thanks for taking the question. And apologies if this has already been touched on. I had to jump off the call for a little while. I just wanted to, on slide 11, ask for a little bit more detail on the offshore Victoria Works program. It looks like once Thylacine West is connected, you sort of go straight into another CAPEX program connecting Artisan and Labella. But could you just elaborate on what the other work there is? Is the exploration drilling just Yola West or is there something else there? And could you describe the abandonment activity as well? Thanks.

I'll get Sam to respond to that one.

Yeah, I mean, planning for this is underway, Mark. And as you'd understand, we don't have the details of that. I think we'll come back to you with more details as time progresses. But you're correct, it would involve the development of Ardazan and Labella. We are looking at exploration. We're also going to be doing some flood and abandonments. And we're also progressing our understanding of what to do in the Bass Basin. So that may include Yolo West. So looking at the development of White Ives and Bass. But all of those have yet to be decided. And I think you'll see us in 2024 making some further decisions declarations of our intention there once we've burned that up both internally and also with our joint venture partners.

Great, thanks Sam. Thank you. At this time we're showing no further questions. I'll hand the conference back to Mr Clement for any closing remarks.

Thank you. Look, thanks everyone for joining the call today and very much appreciated the questions that have come through. As I said, Beach, we believe, is in a very strong position. We're delivering growth projects over the next 12-month period and beyond, and we have a pipeline of opportunity that we're pursuing as well. So we're very confident about where we're going as a business. We have a plan in front of us and look forward to your continuing support. So I'll leave it there and we'll wind up the call and thank everyone for their participation.

Thank you. That does conclude our conference today. Thanks for participating. You may now disconnect.