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Beach Energy Ltd
Earnings Call Analysis
Q4-2023 Analysis
Beach Energy Ltd
The company is focusing on a range of development projects, with capital expenditures forecasted at $850 million to $1 billion. This will support projects like Waitsia and Otway, as well as drilling programs in the Cooper Basin and other locations, which aim to contribute to production gains later in the financial year and extend into 2025 and beyond.
Production underpins financial results and this year has witnessed a shift towards more gas production, especially with the Thylacine North wells coming online. While sales revenue saw a small decrease of 8% to $1.6 billion, which was chiefly due to lower production, a rise in gas prices by 9% helped cushion the impact. This adjustment forecasts a continued trend with upcoming gas supply from other projects like Waitsia Stage 2 and Thylacine West wells.
The focus on project execution resulted in robust financial outcomes, though there was a decrease in earnings and cash flow by 12% in underlying EBITDA to $982 million and operating cash flow to $929 million. An increase in depreciation and higher financing costs contributed to a decline in net profit. Conversely, capital expenditure was significant, indicating a reinvestment of $484 million into growth projects.
The financial positioning is strong, with a slight increase in net debt to $166 million, still maintaining a cautious net gearing of 4%, quite below the target of less than 15%. Liquidity remains solid, and the company expects to generate increased production rates and cash flow by the end of the next fiscal year. A new dividend policy has been implemented, resulting in a 100% increase in dividends compared to the previous year, now at $0.04 per share.
The company is not just focused on its bottom line but is also committed to sustainability, targeting a 35% reduction in emission intensity by 2030, with significant reductions already achieved this year. Given the business's nature, it's susceptible to commodity price fluctuations, which are expertly managed within the financial framework provided.
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Good morning, everybody. Thank you for joining us this morning for the Beach Energy FY '23 full year results webcast. Bruce Clement is our Interim CEO and he will be leading the call today, and with us also is Anne-Marie Barbaro, 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 Chief Executive Officer of Beach. I'd like to begin today by acknowledging that I am 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 Beach's key markets.
So just roll on to 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.
So moving on to Slide 3. Here is a summary of what we see is 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. As I said, 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 the 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 development -- of growth that we are already pursuing today.
And on the sustainability front, CCS 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. Thus 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 breadths and depths of our business and our investments and what we are doing at Beach.
From -- 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 Thylacine wells to the OGP and delivered additional production and well deliverability into that plant. Later this year, we are planning to drill the Kupe 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 Waitsia, I'll talk to this in more detail later, but the Stage 2 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 and 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 our 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 in -- when we bring Waitsia online. We will have 8 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 70% complete at year-end. We are pursuing and assessing other initiatives that leverage our expertise and assets in this space.
So 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 TRIFR performance was down to 2.4 this year. We had a period of 6 months injury free across the organization, and in a couple of our plants, Otway and Beharra 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 our -- one of our seismic programs in South Australia.
So 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 dive into these in more detail, but you can see there, 19.5 million barrels of production, reduced 6.1 million barrels of reserves, and underlying EBITDA of $1 billion, which is a very strong performance. We've seen increased domestic gas prices and we were 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 are delivering on our growth projects. Thylacine North 1 and 2, we 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 mobilizing a rig to Kupe 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 will see, for the offshore Victoria drilling program planned for financial year '25.Let's 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 Waitsia. 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 4 development wells and we've increased the Otway Gas Plant well deliverability to 170 terajoules per day, supplying into the East Coast domestic market. Part of that drilling program, as I said, we -- 3 wells in particular represented significant and the longest horizontal drilling campaign we've conducted there, 8.1 kilometers of horizontal sections in those wells, and they are delivering into that gas plant now.
And we received an APPEA Safety Project Excellence Award for our performance during that drilling program. So on the next slide, Waitsia Gas Plant, as we recognize, this is -- this project, we recognize 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 and re-establish it, and it now has momentum going forward.
We are 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 $450 million 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 North West 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 million 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 start-up 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 are forecasting $850 million to $1 billion of capital expenditure, and you can see there the breakdown between development, exploration and appraisal, and our stay-in-business CapEx. On the development side, clearly Waitsia and Otway are in there, as well as Kupe, 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 '25 and beyond.
On the next slide, just -- this is a timeline to give you a sense of activities and when they are happening and going to be delivered or coming to the market as the information. You can see there 5 key areas for the company that we're working in.
Kupe, we have the Kupe 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.
On the Cooper Basin, we have -- or on the joint venture, I should say, we have 4 to 5 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 a 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 Waitsia start-up first gas mid-calendar year '24 to a considerable amount of work to be done there, and we're -- we've seen accelerated activity there and performance from the contractors has improved significantly. And on the -- 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 Waitsia post the development drilling earlier this financial year. We have a good contingent reserve -- resources base, and we'll be pursuing that through drilling across the portfolio in the Otway, WA, Cooper, and to a degree, in New Zealand with Kupe.
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 FY '23 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 brought online late in the year. This trend will continue in FY '24 and beyond with substantial new gas supply to come from enterprise, Waitsia 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 revenues flow through to the 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 unwind of liabilities flow 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 FY '23, which, as mentioned earlier, is largely impacted by production and sales volumes. Higher cash cost 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 cost the result of an increase to discount rates on liabilities. This is offset by higher realized gas prices, as I mentioned earlier, along with lower restoration expenses with FY '22 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 higher income tax and restoration payments during FY '23. It was a year of elevated capital expenditure with $484 million of capital expenditure directed towards our growth projects.
Sustaining and stay-in-business capital expenditure of $687 million also increased from FY '22 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 FY '23. We generated $221 million of pre-growth free cash flow during FY '23, 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 remained 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 FY '24 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, utilize our franking credits, which are roughly $600 million, and reward our shareholders for their ongoing commitment to our strategy. Having implemented the policy, as highlight -- 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 Beach's 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 our environmental -- 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.
Let's 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 is -- has been reported by Santos, will 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 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, but 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 wanted to just talk a little bit, but 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 liquids market and we will be, once we have Waitsia 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.
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 will be tightening, and also importantly, delivering gas that can support that transition into renewable energy supply. Just on the bottom right, you can see there 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 3 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 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 working much more -- working -- continue to work strongly with our local communities in delivering a safe and -- safe operation in the future. So I'll leave it there and we can go to questions. And back to all.
[Operator Instructions] The first question today comes from Dale Koenders from Barrenjoey.
Just a couple of questions on production and CapEx guidance, which looks a little bit soft. What are you assuming around Otway production within that FY '24 guidance noting the industry data shows that asset's 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 at 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 AEMO data prior to this financial year, they were taking up to 170 terajoules a day. So there is deliverability there and we can supply the contract that we have in place.
Obviously it's 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 offtaker.
Can you give us any hint as to what FY '25 looks like? You've spoken a lot of times about investing for growth. What does production in FY '25 look like versus '24 or what are the key moving pieces you see?
We can't talk -- we're not providing a forecast into or out into fiscal year '25. But the key moving pieces in that will be things like Waitsia coming online in that period and that's a 250 TJ 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 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 Kupe South 9 well 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 CapEx guidance, can you provide any breakdown by project? I guess, it's quite rare for a company just to talk about how much it's 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 stay-in business, you'll understand that's across the portfolio of assets particularly probably focusing on Cooper Basin, West Flank 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 in particular even the quarterly reports where the CapEx has been spent. We would anticipate similar expenditure levels across the Cooper Basin, West Flank and joint venture and Waitsia 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 Otway that we're planning as well as obviously bringing those extra 2 wells on in fiscal year '25.
The next question comes from Tom Allen from UBS.
Congratulations, Bruce, on your appointment as Interim CEO. Just following that last question, which presumes some conservatism in FY '24 production guidance due to the uncertainty of Otway nominations. Assuming all going well, over what timeframe might you expect the Lattice price review arbitration to conclude?
I can't comment on when that will conclude. We have a negotiation or a price review in process right now and I can't really comment. That's a commercially sensitive area that I can't comment on.
Can we reasonably assume there, 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 that available capacity at the Otway Gas Plant. Can you share some color on the process to secure that native title approval to enterprise? Like, are there any unique sensitivities that could add material risk to the timeline to secure that approval just recognizing that you've broadened guidance for first flow from year-end to second half fiscal '24?
I mean look, that process is [intrain] and happening and we are confident we'll come through with a solution that works for everybody involved. These processes, and as you'd be aware, regulatory processes subsequent to that take time. They're never quick and I can't give you specific timeframe, but we're obviously working as hard as we can to get it resolved and get it finalized and we're working with native titled 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. 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 anymore really on the release that was made. The decision being made to obviously replace Morne 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 and I'm here for that 6-month interim period.
The next question comes from James Byrne from Citi.
Firstly on Waitsia, what could you say to us in the public markets to make us little bit more comfortable that this is the last downgrade?
Well, I think you can see from where we are today is that 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 not just with the contractor company; with their employees, with their subcontractors, with 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 double 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 we 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 site of the Clough 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 and liquefaction contracts?
Yes, we are. Obviously that's an initiative we're taking. We have some additional Xyris 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.
Any steer on the volume of that gas? Like is it sort of low number petajoules, low single digit?
No, I can't. I mean we're working on that, but I can't give you specific numbers, but you can probably draw some conclusions from the size of Xyris relative to the size of Waitsia as well.
The next question comes from James Redfern from Bank of America.
I was going to ask about the FY '24 production CapEx guide. Bruce, you've covered on that. Just maybe if you could please dig into the Otway gas projects in terms of the capacity that you talked about 170 TJs a day and then nomination to 50 TJs a day. Maybe just for my understanding is Origin the sole offtaker for gas from the Otway? And I guess just maybe some color there why they are 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 anytime soon?
A tricky question given that we don't really know what the drivers are for Origin in their offtake arrangements. Yes, they are the offtaker 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. The gas is 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. And my second question is just maybe on the gas markets. Just in terms of I guess where market pricing is for sort of 3 to 5-year contracts at the moment? Is it still kind of $11, $12 a gigajoule?
I'm really not able to talk about commercial and confidence contract pricing. So I'll have to skip that one.
The next question comes from Saul Kavonic from Credit Suisse.
A few questions from me. Look, I want to just come back on the new Waitsia guidance, particularly the startup in the calendar year '24. I mean, Bruce, can you give us some more color on exactly what is this new guidance based on and the reason behind it? Because I think it's now widely felt in the industry that this isn't just an issue of the Clough insolvency, but it's also an issue of operator competence here. And what reason is 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 Waitsia. But look, I would certainly say that the biggest disruption was most definitely the Clough position of insolvency and the consequential knock on 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 Beach's position and our estimate of when it's going to be complete is that mid-'24 and that cost estimate.
Right. The level of really here being 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 Clough 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.
Jumping to enterprise, it seems the language has also changed here a bit to now targeting startup in H2 FY '24 versus I think it was only a month ago you talking about mid-FY '24. Has there been reason to -- is this where the approvals you're 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 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. And just look, a couple more just on pricing. WA gas prices, my understanding is your domestic contracts roll every year or so there. As the latest numbers reflected the higher gas price we've seen in WA because now we're seeing spot pricing over $10 versus I think your contracts over a year ago were close to $5. Is that being reflected in 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 Xyris gas into that market and Beharra gas into that market and it's improving.
And just last one then is 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-in is going to push back some of the production subject to the Lattice price reviews kind of backwards beyond this half? Depending on how the price reviews kind of play out, does that actually see those volumes exceeding a higher price than it's actually being produced in this half because that won't be subject to any cap this half, but could be on an uncapped repriced 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 we're expecting, as we've shown on the slide, we're going to have a significant proportion of uncontracted gas and most of what we've got is going to be repriced over these next few years as well. So we're pretty confident about where we're going with the Otway Gas.
The next question comes from Adam Martin from E&P Financial.
Just back on Otway, it's obviously an important asset. Is there anything that 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 also invested capital here. Is there a sort of minimum nominating quantity over time? Does that change because obviously selling 50 TJs is not a lot of gas?
It's a reasonably complex question you are 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 will see the numbers that are being reported on take and availability. In terms of going forward, 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 offtakes, but we'll be starting from a higher base so to speak in terms of deliverability in future years.
Okay. And just 1 other question. Just on costs, what are you seeing both on operating costs, Cooper Basin, Otway, what are you seeing there and obviously also drilling CapEx going forward, please?
Well, I could say I'm seeing lower cost, but that would be an absolutely misleading statement. I think the industry as a whole, and you'd be aware of this, is seeing cost increases 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 that's a focus for our business and everyone's business at the moment. But yes, the underlying move is upwards in costs.
The next question comes from Max Vickerson from Morgans.
Bruce, I won't peck you with questions on Otway given I think that's been pretty well covered. But just wanted to understand with Waitsia, look, previously indications were labor shortages and some of the key holdouts on the project, particularly E&I trades people. Given the CapEx guidance today and then just the shift outwards in time, is it still fair to assume that it was that labor shortage or are there other potential engineering related issues that may be posing some delays? Any other kinks that need to be worked out there?
Look, I think the labor shortage and remembering that Clough were in a difficult position in terms of engaging subcontractors and contractors to work for them. Yes, there was a labor shortage earlier this year. We have resolved that with the joint venture with Webuild. We've actually got more accommodation on site in camps and available. We've been able to access additional E&I staff or contractors on site and we are getting over -- we're past that hurdle or not past it, but we've got a solution for it and we're moving forward.
Yes, as I said, we are seeing performance improvements, significant improvements over prior periods. And based on that and our forecast, our estimates of the project performance we expect to be first gas middle of next year.
Fine. Look, maybe will try my luck on Otway then and just ask. Look, how relevant do you think spot markets are? I know you can't really comment too much on Origin's thinking. But are spot markets the relevant benchmark here for relative attractiveness of your gas or what do you think the broader portfolio that Origin might have?
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.
The next question comes from Nik Burns from Jarden Australia.
Just some clarification questions on FY '24 guidance. First of all on production, how you assumed any contribution from Waitsia Stage 2 in that range at all? Just making that comment in relation to the Slide 11 that does show the potential for Waitsia to startup for the end of FY '24. So just understanding whether there was any contribution potentially at the upper end of that range?
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 we're not talking about many millions of barrels of oil equivalent, but getting gas into the pipeline and up into the Northwest Shelf.
And just on Western Flank oil, not much commentary in the result here about it. But at the quarterly there was talk about switching from a development focus to a more exploration and appraisal. Just thinking because of the shift, should we expect lower oil output in FY '24? If I do that 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 it to Sam Algar to give you a response on that one.
Thanks for the question. We're not guiding on any specific production decline for the Western Flank, but you're right we are shifting towards more 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 part of the answer to your question is dependent upon the outcome of those wells, exploration obviously is much less predictable than the production wells, which we had great success in FY '23, 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 financial year. So they're unlikely to have an impact. So what you'll see in FY '24 is predominantly a decline at the existing assets offset by any infield work, which we obviously are focusing on too.
Got it. No OpEx or DD&A guidance released today. Why is that?
Anne-Marie?
We've kept it simple with production and capital. OpEx and DD&A cost per BOE obviously very largely driven by production and given the wide range of production that we put forward today, didn't feel appropriate to put guidance out around OpEx and DD&A.
Okay. Just final one from 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 6 months ago and the follow activity 6 months ago had a date of second half FY '24. It's now labeled as TBC. Can you just talk about what results you need to see from the drilling in first half FY '24 to commit to those additional wells and whether cost of those conditional wells is included in your FY '24 CapEx guidance range?
I might get Sam again to address this one.
Thanks for the question. Probably a complex one to follow through with uncertainties in the drilling results. Obviously we are drilling ahead with the Trigg Northwest 1 as we speak. That would have a bearing on our level of interest in pursuing Trigg North. The other wells, the 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 Waitsia 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.
Yes, that could be included certainly in the upper end of the range.
The next question comes from Gordon Ramsay from RBC Capital Markets.
Nice to see you back at the helm of the ship, Bruce, it's been a few years. Just very quickly on the contract for the new vessel for the Thylacine flowline. Where does that sit at the moment?
I'll get Ian Grant to address that one.
We're still working through the options, Gordon, at the moment.
So no feel on timing on that?
Yes. I mean, there's opportunity, there are a few vessels there that we're looking out. So we still feel that in line with the guidance that we've provided, we'll still be able to achieve -- get online in the second half of FY '24. There's no real issues we're concerned about.
Okay. And this maybe comes back to Sam. Timing on Trigg 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, no. It's all entirely in line with expectations and yes, we're close to the objective.
That's on the time of that curve.
Okay. And lastly, just on the $65 million for LNG costs, am I correct in assuming that's mainly transportation?
And processing. It's transportation and processing. We have an agreement, a supply and or pay agreement with North West Shelf as well.
Why has processing gone up?
No costs have gone up, sorry, no. 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.
The next question comes from Sarah Kerr from Morgan Stanley.
Just again on that $65 million one-off cost that may be incurred from the delay at Waitsia, can we expect $11 million cost per month run rate for any further delays to the project?
So what I'd say there, Sarah, is the costs will be incurred whether there's gas or not. So I wouldn't be forecasting additional cost whether there's gas or not. So I would assume that you've already got an assumption around costs for the year and we're just flagging that the costs will start earlier than gas processing.
Okay. And just 1 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 are audited and 60% of the undeveloped reserves and did this include Waitsia and Western Flank reserve?
I might pass that one to Sam.
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.
The next question comes from Henry Meyer from Goldman Sachs.
I just want to drill into Waitsia some more. Specifically, what are the key milestones over the next year required to complete development and commissioning at Waitsia? And are you planning to provide updates on these through the year?
So I'll pass to Ian just to give you the key milestones. And the answer to that is obviously, yes, we will be particularly through quarterly reports and the like providing updates on Waitsia as we go forward in financial year '24.
So obviously Bruce has already mentioned the fact that the labor 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, will get mechanical completion and then obviously commissioning, which I think for me, I just want to mention that really briefly. 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 lively. So look at the guidance here, we are slightly behind that and I think you'll see results come through over the next few months.
Okay. So is it fair to say that I guess it's really labor and timing there or are there any other long leads required to be shipped and installed on site?
The key thing's really labor as we've already addressed today.
The long leads are under control and we'll meet that schedule as we have. In fact most of the kit is delivered, but the labor for onsite construction, E&I 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 mid-2024 and the costs we put out are where our estimates are at.
Got it. And maybe jumping back on to the resources so you've come through with the 37 million BOE downgrade of Perth Basin 2C. Is this largely from the drilling in the fault block from Waitsia earlier in the year or anything else that's driving that?
I'll let Sam address that one again.
So it's unrelated to activities in Waitsia drilling. That is largely a reclassification. We had a reasonable 2C resource with some tight gas in the Perth Basin and that would require fracking and given we're unable to frac in WA, we decided to move that to development unviable takes it out of our reported 2C.
Got it. Okay. And maybe just a quick 1 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 will wait until next year?
I think it would be prudent for us obviously to look carefully at what information we have and makes 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 the certainty of that development and the timing of that development. So I don't expect you'll see us announce reserves and resources immediately after drilling.
I think it's more prudent to follow through with that later on.
The next question comes from Scott Ashton from SHA Energy Consulting.
Just a very quick question on the $65 million. So is that the provision that's embedded in the non-current liabilities or current liability? The $65 million that's in parallel with the expected startup for Waitsia next year. So it's the full mid-'24 startup penalty for want of a better word.
I'm happy to take that question. So in relation to whether it's embedded in 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've actually -- when the contract is [indiscernible] and incurred. So you might see that liability -- 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. Okay. So it's not sitting in the provisions or in the liability.
No, it's not yet earned or incurred.
So I'm just trying to understand so that $65 million is your best estimate dovetailed to the anticipated startup of the Waitsia 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 1 of the earlier questions.
So the $65 million that we put relates to FY '24 costs. So we've sort of guided to that because we have put guidance out for FY '24 only.
The next question comes from Mark Wiseman from Macquarie.
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 disconnected, you sort of go straight into another CapEx program connecting Artisan and La Bella. Could you just elaborate on what the other work there is? Is the exploration drilling just Yolla West or is there something else there and could you describe the abandonment activity as well?
I'll get Sam to respond to that one.
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 Artisan and La Bella. We are looking at exploration. We're also going to be doing some plug and abandonments and we're also progressing our understanding of what to do in the Bass Basin. So that may include Yolla West so looking at the development at White Ibis and Bass, but all of those have yet to be decided. And I think you'll see us in 2024 making some further declarations of our intention there once we've firmed that up both internally and also with our joint venture partners.
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 months 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 think I'll leave it there and we'll wind up the call and thank everyone for their participation.