Thank you for standing by and welcome to the Beach Energy Limited FY 2022 full year results conference call. All participants are in a listen-only mode. There will be a presentation followed by a question and answer session. If you wish to ask a question, you will need to press the star key followed by number one on your telephone keypad. I would now like to hand the conference over to Mr. Morné Engelbrecht, Chief Executive Officer. Please go ahead.
Good morning and welcome to the FY 2022 full year results presentation for Beach Energy. My name is Morné Engelbrecht, and I'm the Chief Executive Officer of Beach. Joining me on the webcast today is our Chief Financial Officer, Anne-Marie Barbaro, and other members of the Beach executive team. For today's presentation, I will first provide an overview of our results and progress for the year. I'll be over to Anne-Marie to run through the financials, and then I will provide an update on sustainability, our markets, and the outlook for FY 2023 and beyond. Following that, we will open the lines for Q&A. Before we commence, slide two includes our disclaimer, price assumptions, as well as information regarding our reserves disclosure. We will leave this with you to read in your own time.
Our key message for today is that FY 2023 is the year of focused project execution as we deliver the foundation for growth in FY 2024 and beyond. For FY 2022, we delivered a strong set of financial results and delivered on major project milestones. Operationally, albeit production was lower, key project milestones were delivered against a challenging backdrop of COVID, adverse weather events, labor shortages, and international supply chain pressures. Financially, the increase in demand and focus on energy security strengthened the market prices supporting the growth in our earnings and cash flows. As this slide conveys, not so subtly, we are focused on delivering on our growth objectives. We are focused on growing our gas supply from each of our assets and materially from the Otway and Perth Basin in particular.
Growing our exposure to key gas markets, including expanding our share of the East Coast gas Market and entering the international LNG markets. Growing our free cash flow and financial strength, and growing our business sustainably. We are committed to the emissions reduction journey. To this end, I'm very excited to announce today our new emissions intensity reduction target. We are targeting a 35% reduction in our net equity emissions intensity by 2030. More about this later. Turning to progress in the field on slide four. It was a very productive year for Beach, with several highlights and milestones, and in particular, demonstrated our ability for delivering complex projects. The delivery of the biggest offshore drilling program in Beach and the Otway Basin's history was a clear highlight.
The drilling campaign was completed safely and successfully, with the campaign yielding one gas discovery and six development wells with an increase in reserves to boot. The first two development wells were connected to the Otway Gas Plant, which supported a 47% increase in Otway Basin production. In the onshore part of the Otway, we also took a Final Investment Decision for connection of Enterprise discovery to the Otway Gas Plant. In the west, the transformational Waitsia Stage 2 project commenced with good progress made, the gas plant construction on the way, three of the six development wells drilled, and the LNG sale and purchase agreement with BP now also finalized and signed. Slide five summarizes the strong set of financial results.
While production was lower than last year, we did progress our major growth projects to start lifting our production to key oil, liquids, gas, and LNG markets. We are reporting material improvements in earnings and free cash flow before major project CapEx, with revenue from our operations hitting an all-time high. Results demonstrate the benefit of Beach's diverse asset portfolio and strong leverage to commodity prices. We also ended the year in a net cash position with liquidity of AUD 760 million, and this is after our biggest CapEx year on record as well. The board declared a AUD 0.01 final dividend, with our current focus remaining on prudent balance sheet management as we deliver on our major growth projects. Turning to slide 6, which summarizes our FY 2023 activity. Our overarching objectives are clear and aligned with our strategy.
In FY 2023, there will be much focus on completing the bulk of the work programs in Otway and Perth Basins. We're also very focused on maximizing plant output and extending asset lives through ongoing workover and optimization activities. Looking beyond project delivery, we will continue planning for FY 2023 drilling in the Bass and Taranaki Basins to bring gas plants back to capacity rates. Exploration efforts will continue across the portfolio to drive longer term growth and potential facility expansions with Perth Basin exploration drilling to commence in FY 2023 and Otway Basin drilling planned for FY 2024-2025. As we grow, we do so sustainably with the progression of the globally significant Moomba CCS project. East Coast and West Coast acreage is integral to our growth aspirations. Slide seven touches on the East Coast.
Gas supply challenges have been well documented, and the market fundamentals are attractive for Beach. Our objective is to support the market through developing new resources of gas supply and have been investing to do so. The chart on this slide highlights our East Coast contracted and uncontracted gas exposure over the coming years. As existing contracts roll off and then new enterprise and Thylacine volumes come online, uncontracted gas volumes grow and coincide with already tight market fundamentals. We are therefore well-positioned to realize our gas growth and play our part in providing energy security for decades to come. Slide eight summarizes an exciting milestone which we announced last week, the signing of the LNG sale and purchase agreement with BP. This is a highly valuable contract which will provide a material revenue stream to Beach over its five-year term.
In summary, BP has committed to buying all of Beach's share, the Waitsia LNG volumes, up to 3.7 million tons. To put this into context, this is equivalent to roughly 200 million MMBtu of the SPA in line with the type of contract you would expect us to enter into considering the current backdrop of the market. Pricing is based off a mix of JKM and Brent linkage with full upside exposure and also leverages BP's leading LNG shipping capability and cost structure. We also have downside price protection, which in itself delivers a commercial rate of return on our investment. Beyond pricing, the SPA contains terms, conditions such as flexibility to align first LNG sales with Waitsia Stage 2 commissioning. We are very excited to have BP as a long-term partner and look forward to delivering our first LNG cargo.
Slide nine is important as it highlights our target production of up to 28 million barrels of oil equivalent by FY 2024. Although we maintain our target, we note that this is dependent on the successful delivery of our major projects being on time and without any adverse or unseen events. The main drivers for reaching the target can be summarized as follows. Overall, it assumes performance in line with forecasts for all of our current assets, including production remaining flat in the Cooper Basin. In the Otway Basin, it assumes production will benefit from the greater well deliverability from the start of the FY 2024 year from the Thylacine and Enterprise wells. Customer nominations for the OGP is also assumed to be in line with a full well deliverability and therefore above take or pay levels.
In the Perth Basin, we are targeting steady production before first gas from the Waitsia Stage 2, expected in the second half of calendar 2023. Turning now to slide 10, which summarizes reserves and resources movement during the year. Reserve additions this year was challenging while our development projects were progressing with a lack of exploration in FY 2022 outside of the Cooper Basin. This is a key issue which we'll be addressing in FY 2023 and 2024. The decline in reserves was mainly driven by production and reclassification of the Athena reserves as we flatlined in May. In the Cooper Basin, revisions were due to outcomes from work programs during FY 2022, including poorer than expected fracture stimulation results in the Balgowan Field and infill drilling at the Kalladeina Field and production performance at Bauer.
At Bauer, production was underperforming due to higher than expected water influx from the Namur to the McKinlay Reservoir. This was remediated by reinstating Namur water producers to pull water away from McKinlay. This has improved production performance, but not yet corrected it completely. We are committed to growing our reserve space with the Perth Basin exploration program commencing later this year, being the next major catalyst for reserve additions. We're also announcing our inaugural Cooper Basin carbon storage reserve. I'll finish this first section with health and safety and environment on slide 11. Recorded pleasing outcomes this year, particularly given it was a year of record hours worked across the organization, more than 3.3 million hours. Highlights included a number of safety awards, extended injury-free periods, and significant reduction in spills.
We maintain our focus on continued improvement, and I thank all of our people for their dedication, demonstrating through action that safety does take precedence in everything we do. I'll now hand over to Anne-Marie to talk through the financial results. Anne-Marie?
Thanks, Morné. Good morning, everyone, and thank you again for joining us today. I have the pleasure of speaking to you today to provide an update on a strong set of financial results for FY 2022. Turning to slide 13, as Morné has already highlighted, Beach ended FY 2022 in a strengthened financial position, setting us up well to deliver our growth projects in FY 2023 and beyond. Beach reported operating cash flow of AUD 1.2 billion, with AUD 752 million free cash flow pre-growth expenditure. We are fully funded to deliver the growth agenda for FY 2023, with liquidity of AUD 765 million at year-end, and we are targeting a net cash position throughout FY 2023. Our results this year again demonstrate capital management discipline, which is particularly important during periods of heightened capital expenditure.
As we complete our current major growth projects, we target growth in free cash flow in FY 2024. Slide 14 sets the scene with our production figures for FY 2022. This year, we produced 21.8 million barrels of oil equivalent, which was in line with guidance. We have diversity of production from five basins, and our gas to liquid split is now 65% to 35%, respectively. Slide 15 highlights a strong set of financial results which demonstrate the benefit of Beach's diversified portfolio and diversified exposure to energy prices. Cash from operations jumped 61% to AUD 1.2 billion, with stable cash flows from our fixed price CPI linked gas contracts, which delivered approximately 31% of total revenue. Meanwhile, unhedged exposure to oil and liquids underpinned the material increase to revenue.
We announced an underlying net profit after tax of AUD 504 million, up 39% on the previous year, an Underlying EBITDA of AUD 1.1 billion, up 17% on FY 2021. We announced a final dividend of AUD 0.01 per share, fully franked. While we complete our major growth projects, we consider it prudent to not increase the dividend for this period. Slide 16 shows the comparison of FY 2022 Underlying NPAT to FY 2021. The 15% rise in revenue during FY 2022 was primarily driven by a 79% increase in the realized oil price. Reduced depreciation is the result of lower production volumes, and lower exploration expense is the result of FY 2022 exploration activities being capitalized in accordance with our area of interest policy.
The increase in cash costs was primarily driven by a 56% increase in royalties and a 45% increase in third-party purchases, both driven by increased commodity prices. Tariffs and tolls were 24% higher than FY 2021, driven by the successful arbitration outcome in relation to carbon recognized in FY 2021. Restoration expenditure of AUD 30 million reflects the increase to restoration provisions in relation to assets in abandonment phase in the Cooper Basin. Slide 17 highlights our strong cash position with cash reserves of AUD 255 million at the end of FY 2022. As mentioned earlier, operating cash flow of AUD 1.2 billion was up 61% on FY 2021. This cash flow included AUD 110 million of income tax paid and a AUD 42 million receipt for settlement of the carbon tax arbitration.
Our free cash flow, pre-major growth expenditure was AUD 752 million. Turning to slide 18, you can see our balance sheet remains in great shape with a net cash position of AUD 165 million at the end of the year, and total liquidity of AUD 765 million. During the year, we successfully refinanced our debt facility and upsized it to AUD 600 million with improved terms and margins achieved. This means we're well-positioned to fund our future growth strategy, including the committed capital for the connection of the Thylacine wells and Enterprise discovery in the Otway Basin.
Waitsia Stage 2 plant construction and development drilling and Moomba CCS. FY 2023 will be a capital intensive year, which will see the bulk of the work programs for our major growth projects completed. This sets the foundation for targeted growth in production and cash flow in FY 2024, which has been our clear focus over recent years. With that, I'll hand back to Morné Engelbrecht.
Thank you, Anne-Marie. I'll now turn to sustainability on slide 20. Highlights this year include our community involvement, including sponsorships, volunteering and training, and the announcement of our new emissions intensity reduction target. A highlight for me is the number of volunteering hours given by our staff to great causes within the communities in which we operate, with almost 1,000 hours being donated in time. This includes volunteering at organizations like Habitat for Humanity, Food Banks and Clean Up Australia. Also very excited about our new partnership with Deakin University's Blue Carbon Lab. This involves trialing a new technology that assists the recovery of coastal wetlands, which we know are excellent for carbon sequestration. Our 2022 sustainability report was also released today, which I encourage you to review.
Turning to slide 21, the environment we operate in is clearly very important, and Beach is committed to the emissions reduction journey. That is why we are targeting a 35% reduction in emissions intensity by 2030. This is relative to 2018 levels when the Lattice Energy assets were acquired. This target takes into account all assets in the portfolio, not just our operated assets. We are already making progress towards this target with the emissions reduction project on the way across the operations, including Moomba CCS. Also pleasing to note that more than 90% of our customers have a 2050 net zero carbon emissions target. Slide 22 summarizes the exciting Moomba CCS project, a globally significant project. Taking the FID for Moomba CCS was another key achievement in FY 2022.
We are firm believers that CCS will be critical for sustainable gas production and for the world to reach net zero, with the Cooper Basin depleted reservoirs making it ideal for CCS. We will initially be targeting up to 1.7 million tons of gross CO2 injection annually, with our share being roughly 500,000 tons per annum. We are progressing well with the operators. We target first CO2 injection in 2024. I'll touch briefly now on our key markets. Slide 24 summarizes the five key markets Beach has exposure to. Supply gas to the East Coast, West Coast and New Zealand markets. Oil and liquids to global markets, and we'll soon be supplying LNG to the global market as well.
Each market displays attractive fundamentals with tightening supply and demand outlooks. Current themes of energy security and increasing demand have seen elevated commodity prices over the past year. High cost of capital and lack of stable investment policy have led to underinvestment over recent years, accentuated current supply issues, which further supports our material investment in new gas resources. These gas market dynamics are set out in slide 25, many of which I've already mentioned. Recent market studies continue to be concerned with sufficiency of gas supply to the East Coast and increasing prices with a lack of coal-fired power generation and renewables not being able to fill the gap. This has been reflected in significant increases in spot gas prices this winter. As stated in the slide, the ACCC is concerned the higher spot prices will flow through to term contract prices.
This is already evident, as shown here on the ACCC chart. The similar story in the West are set out in slide 26. Existing supply sources are decreasing and new demand sources are emerging, leading to tightening supply demand outlook. Again, it's a similar story for a global LNG market as set out in slide 27. LNG supply and pricing has attracted a lot of attention of late. The Ukraine situation and decreasing gas flow from Russia have led to increasing energy security concerns globally and heightened the demand for LNG, particularly in Europe. A similar story of underinvestment over recent years has also exacerbated the current elevated prices. We've seen significant increases in LNG spot and future prices this year, as shown in the forward curves on the slide. I'll finish now with the outlook for FY 2023 and beyond. Slide 29 summarizes our FY 2023 guidance.
As I mentioned earlier, FY 2023 will continue our momentum from 2022 as we focus on executing major growth projects. Capital expenditure is expected to be of a similar order to FY 2022. A slight change to composition will affect the progress made with our major projects, particularly in the Otway Basin. We also have additional spend on the Cooper Basin JV for Moomba CCS and an additional rig and optimization activities. Slide 30 provides more detail on our underlying guidance assumptions. Basin by basin, the production path for FY 2023 is straightforward. In the Otway Basin, production will benefit from recent connection of Geographe 4 and 5. Greater well deliverability will not occur until the Thylacine wells are connected. We have not assumed any incremental production from Thylacine or Enterprise in FY 2023. Otway Basin production will also depend on customer nominations, which can be difficult to forecast.
Our base case therefore implies a slight increase in Otway Basin production in FY 2023. It should also be noted Otway Gas Plant will be down for approximately three to four weeks for well connections and maintenance. In the Cooper Basin, we are undertaking active work programs which provide the confidence to target flat production for both the Western Flank and the Cooper Basin JV. In the Bass and Taranaki Basins, there will be no drilling until FY 2024, thus natural field decline in the order of 15%-20% should be assumed. In the Perth Basin, we are targeting steady production. First gas from Waitsia Stage 2 is not expected until the second half of calendar 2023. Turning to the Perth Basin on slide 32. The Perth Basin has generated much excitement with recent significant discoveries at Lockyer Deep and West and South Erregulla.
These discoveries and Beach's existing fields demonstrate the extensive nature of the Perth Basin. Most of the remaining prospectivity in the Perth Basin in our view is within the Kingia Gas Play and held by Beach and joint venture partner, Mitsui. Beyond Waitsia Stage 2, exploration will drive the next phase of growth, with drilling now commencing at the end of 2022 and will continue through 2023. If we can prove up in excess of 500 BCF, there will be a strong support for facility expansions or backfill of the Waitsia plant. When the Waitsia Stage 2 development drilling is done, we'll kick off the exploration program with Mitsui-operated well Elegans. The full program will comprise two Mitsui-operated wells and up to six Beach-operated wells, with the sequence still to be locked in as it's dependent on regulatory approvals for some of the wells.
Rig one will be the Beach's first operated well of the campaign, with the team excited by this prospect. It's on trend, an update from the West Erregulla discovery, and has very similar characteristics to the Lockyer Deep discovery. Discovery here would be quickly appraised as we see the potential for material volumes. To the Otway Basin now on slide 33. You can see here our extensive position in the offshore and nearshore Otway acreage. In FY 2023, much focus will be on connecting the Thylacine well and Enterprise discovery to the Otway Gas Plant. However, we are also very focused on activity and growth beyond FY 2023. We will include exploration in both the onshore and nearshore acreage. Slide 34 looks at our offshore acreage, which excites us from a number of reasons.
First, we have five prospects identified which are located close to existing fields and existing infrastructure and reservoirs we understand. Second, these prospects all have seismic amplitude support similar to the other discoveries and fields in the basin. Amplitude support increases a prospect's chance of success and has led to 100% success rate in Beach's acreage. 16 successful discoveries from 16 wells drilled. We are improving our seismic data quality currently and with encouragement, we'll consider exploration drilling in FY 2024. If successful, we would look to develop these discoveries in conjunction with development of Iris and La Bella in a cost-efficient manner. We're also excited by our initial offtake agreements as set up in slide 35. We are focusing on three high-impact targets located close to Enterprise. One could be drilled from the Enterprise platform, significantly reducing development cost and timeline.
A quick run through now on other basins, starting with the Taranaki Basin on slide 36. In New Zealand, demand for our gas continues to be strong, and we've been drawing on our wells to the maximum extent possible. This results in field declines accelerating earlier than expected. We are now focused on drilling up to two development wells to arrest field decline and return the plant to higher processing rates. Planning is underway, and we are targeting drilling the first well in FY 2024. Turning to slide 37 and the Bass Basin. As always, our focus in the Bass Basin is to keep our gas plant processing at higher rates for longer. We recently provided an update on activities, which included identification of the Yolla West infield opportunity from our reprocessed 3D seismic.
We were hoping to drill Yolla Bolly this summer, but lack of a suitable rig means that we are now targeting the summer of 2023-2024. We also deferred a decision on the Trefoil development to allow more time with interpretation of the newly acquired 3D prime seismic survey and to fully assess project economics. Heading now to the Cooper Basin, with a look at the Western Flank on slide 38. It was a challenging year in the Cooper Basin, with heavy rains disrupting activity on several occasions. This meant the backlog of workover activity and well connections has been carried over into FY 2023. Pleasingly, we completed an active drilling campaign, including well exploration and appraisal activities, with outcomes and learnings to inform our program this year.
Activity includes near-field exploration and appraisal drilling targeting the Moomba and Birkhead reservoirs, follow-up appraisal drilling in the Martlet field, and an extensive horizontal well development campaign of Bauer, Growler, and Spitfire fields. We've already had 1 oil exploration success this year, Rocky One, which discovered oil in the Birkhead reservoir. Gas exploration and appraisal drilling is under consideration for the second half of FY 2023. We have a number of contingent wells ready to go, depending on the outcomes of drilling in the first half. With new reservoir management strategies helping arrest the decline in oil production in FY 2022 and much activity planned for FY 2023, we are confident in targeting flat oil production this year. Heavy rain also disrupted activity within the Cooper Basin JV, which is summarized on slide 39.
This year, the joint venture is targeting up to 100 wells with a primary focus on gas. A range of campaigns will be undertaken, including appraisal and development drilling and continuation of successful campaigns from FY 2022, such as the Moomba South program. A third rig is now drilling to catch up on planned activity and address production declines witnessed during FY 2022. I'll close out with our key takeaway on slide 40. As I said, our key messages for today is that FY 2023 is a year of focused project execution as we deliver the foundation for growth in FY 2024 and beyond. We are focused on growth, growing our gas supply, growing exposure to key gas and LNG markets, growing free cash flow and financial strength, and growing so sustainably. On that note, I'll ask the lines to be opened for Q&A. Thank you, operator.
Thank you. If you wish to ask a question, please press star one on your telephone and wait for your name to be announced. If you wish to cancel your request, please press star two. If you are on speakerphone, please pick up the handsets to ask a question. The first question comes from the line of James Redfern with Bank of America. Please go ahead.
Hi. Good morning, Morné. Just two questions, please. The first one is just around the contracted gas market. The slide in your presentation has a midpoint of around AUD 12 a gigajoule as the gas to be supplied in FY 2023. Just wondering if you could make some more comments around what you're seeing for contracted gas prices for volumes for, say, three to five years starting in mid-2023, please, because that's when I guess the gas price reset will begin for Beach Energy. Thanks a lot.
Good morning, James. Thanks for the question there. In terms of the pricing, obviously, the ACCC's more recent report sort of focused more on the period from January to February of 2022. I think didn't have a lot of visibility in terms of term contracts beyond the February 2022 period. The midpoint for that ACCC report was around, I think, the AUD 10.98 per gigajoule in terms of the latest report. We obviously we've got two contracts coming up for a price reset both in the Otway and that will reset from the first of July 2023.
We are starting on that process right now and at end of this year to be able to have those prices reset by beginning of next financial year. As we previously noted, that process is well documented in terms of the arbitration process and the basis for agreeing those prices going forward. I think that those rely on contracts over a similar term of the contract that we're negotiating. We point to the ACCC, that's probably the best I can point you to in terms of the current term market. Obviously, we're seeing a lot of you know increases in spot prices locally, but also internationally as well from an LNG perspective that does impact the local market.
Again, as you would have seen in the latest ACCC report, that points to a potential impact to future term pricing and term contracts as well. That's probably the most I can elaborate on that, James, in terms of the way forward.
Okay, thank you. I just have one second question, please. Just wanted to be able to understand the production profile for the Otway Gas Project. So the Beach is expecting to reach nameplate capacity of 205 TJ/day , mid-calendar 2023. I'm just wondering, are you expecting a plateau for a couple of years and then a natural field decline of, say, 10% per annum or do you have a different view to what I just said? Thanks.
Thanks, James. In terms of the production profile, if we connect the Thylacine wells, that will take us up to nameplate capacity. Obviously, we've got the Enterprise well also being targeted for connection mid-2023, with the well stock, so the full Thylacine wells and Enterprise and then Geographe 4 and 5 that we've recently added. We can see that plateau will be maintained for a number of years post FY 2024. Obviously, as I've just gone through as well, we would be looking to expand and drill in FY 2024, which will then give us the well stock to feed at the back end of the current well stock.
We do see a plateau in that plant for a number of years beyond that as well.
Okay, great. Okay, thanks. I'll hand over. Thank you.
All right. Thanks, James. Sorry, operator. Next, question. Operator, are you in the line?
Yes, this is the operator. I've already promoted Mr. Dale. Mr. Dale, are you there?
Hi. Yes. Ashimi, can you hear me?
Please go ahead with the question.
Thanks. Just on the Cooper Basin JV, 5 rigs, 100 wells, AUD 250 million- 300 million CapEx net, a further AUD 150 million- 200 million on the Western Flank, but you're only targeting flat production year-on-year. Is this what's needed for a flat production outlook on these assets going forward?
Thanks, Dale. There's a few things there. Obviously, there's the catch up, as we said previously, in terms of the backlog of activity from 2022. That will add to not only production this year, but going forward as well. We've increased the number of wells that we're drilling in FY 2023 versus FY 2022. From you know, we drilled 69 last year, going up to 100 this year. We're also looking at you know, other changes in terms of the electrification project that we're starting with Santos. More broadly. Then also starting out the CCS project as well, which add to the CapEx profile there.
Can you give a steer in terms of what production step up you're targeting in FY 2024 for the level of spend?
For the Cooper Basin, we're looking to at least keep the production flat. We're not guiding in terms of the actual potential increase in production we're seeing there. I think it's prudent to first see how that program sort of pans out in terms of the activity we have with obviously Santos, the operator there, in terms of trying to alleviate and deal with the decline we've seen in FY 2022. In our own fields, we're looking at obviously expanding on the exploration and development program there. We go through the Western Flank oil exploration side of things. You know, the first three quarters of the year, we'll look at development and appraisal drilling in the Martlet, Spitfire, and Growler fields.
Looking at the exploration in the Rincon, Callawonga, Hansen, and Kyton fields. Obviously looking at how we expand around the specifically Martlet, and then looking at the last quarter of the year, expanding on our exploration and appraisal program as well. There's quite a bit out of the program that relates to production increases at the back end of 2023, but then mostly 2024 as well.
I guess for the gas production guidance of FY 2024 up to 28 MMBOE, is 28 achievable? And if so, what is needed? Is it? Yeah, all gas, Victorian gas projects starting mid-calendar year 2023. No customer nominations, you know, Waitsia, basically a full second half calendar year 2023. What's needed to hit that number?
Yeah, that's basically correct, Dale. As we set out on the slide, you know, in terms of the base production, we would expect our current assets to producing at base in terms of the Cooper Basin. As I said, from a Cooper and Bass point of view, there's a underlying decline of 15%-20%, and we're not looking to draw the Yolla well until the summer of 2023, 2024. That's an exploration well, so we're not counting on that coming in. With the Otway, again, that's keeping the plant full, and that's wells coming in from the first of July 2023. And obviously Enterprise being connected at that point in time.
Then looking at the west in terms of the first LNG shipments, we said second half of 2023. Those are the things that add the specific material volumes in terms of Otway and Waitsia. If there's any slippage of that timing to the right then obviously, you know, that target will be at risk.
Okay. Maybe finally, just a comment around targeting a net cash position through FY 2023, kind of effectively targeting a lazy balance sheet for the next 12 months. Can you talk us through what the thinking for that is? Is it, lack of trust in execution, production outlook, oil price, or sort of what is it that you need so much conservatism?
Look, we still in a very you know, in terms of the world we're operating in terms of the risk that involves the projects, we thought a prudent approach is better and especially in terms of FY 2023 and the CapEx year. If you look at our market cap, we're still spending you know, close to a third of our market cap in CapEx for FY 2023. It is significant. It is still a high CapEx spend. We are being prudent in terms of balance sheet management.
It does give us the ability and the cash flows to deliver those growth projects, and it also gives us the ability to look further afield in terms of potential inorganic opportunities as well, and, you know, whether those exist in the current market. It does give us the flexibility to look at all of our options for FY 2023 and then obviously look at the material increase in cash flows for FY 2024 and what that then means for our capital management framework going forward. From our point of view, still prudent to keep the balance sheet as balanced as we can for FY 2023 until we can lock away the cash flows commencing FY 2024.
Okay. Thank you.
Thank you. Next question comes from the line of Mark Wiseman with Macquarie. Please go ahead.
Well, good day, Morné and Anne-Marie. Thanks for the update today. Just had a question.
Hey, Mark.
Good day. Yeah, just on the East Coast gas Market and the uncontracted exposure, you had talked about signing another contract on Enterprise and maybe from the portfolio more broadly. Should we be expecting Beach to announce a contract at some point?
Yes. We are engaging with the market or starting to engage with the market on the Enterprise volumes. Obviously targeting that to come in mid-2023. I wouldn't expect any announcement this half. Probably second half, we'll probably make an announcement on those volumes. As you say, they are uncontracted and it's the flexible part of the portfolio, going forward from an Otway point of view.
For FY 2023, the 11% uncontracted, should we assume that that's flexibility and sold into the spot market?
No. Obviously that's the representation of currently contracted volumes. We'll probably look to lock that away in terms of a future term contract as well. Some of that might play in the spot market. You shouldn't see all of that as spot market, but there might be a combination of the two going forward.
Okay, great. That's clear. Just a couple of others. On the BP contract, it was almost a year between the HOA and the SPA with BP, and the world obviously changed in that year. Could you just maybe explain, did any of the pricing parameters or contract terms change during that period of time?
Look, Mark, obviously, as you can imagine, I can't talk to any specifics in the contracts. Obviously it's commercially in confidence. What we can say is obviously there's a mix of that JKM and Brent, you know, which allows us to take advantage of those favorable price movements in the North Asia winter periods. We've got full upside exposure, downside protection, which I said gives us a nice return from a commercial point of view. Anyway, from a project point of view, it does give us that flexibility in terms of the start date as well, in terms of the terms and conditions.
It allows us to vary the first shipment date depending on the commissioning of the plant. As I said as well, during my talk as well, it is an agreement that you could entirely expect us to have entered into in the current market environment. That's probably as much as I can say and willing to say.
Just finally from me, just on the dividend. You're obviously sitting on a large cash pile, but I appreciate you have a lot of CapEx this year as well, as has already been discussed. I guess, can we just clarify, for the next couple of dividends in FY 2023, while you're still executing on the growth, should the market just assume a flat AUD 0.01 per half dividend? Is that a fair assumption, or will there be a point in time where you start to have that discussion around raising the dividend?
Look, that's obviously a decision for the board to make over the coming year. What I can say is that, as I said before, we do still have a big CapEx year in FY 2023. We do wanna lock away the projects, the growth projects and get to FY 2024, where we do see a material increase in our free cash flow going forward. I think from FY 2023, I wouldn't expect any increase necessarily in dividends. We will look to have that discussion with the board in terms of how we look at our capital management framework going forward, and whether that means an increase in dividend, share buybacks and other capital management initiatives. Also we still have a great balance sheet now.
We've got the ability to go after growth, be that what's already on the cards or be that growth, additional growth. Looking at M&A as well when that makes sense from a value point of view. We do have all of those available to us, and we do have the flexibility to go after all of those things, at the same time. That's not mutually exclusive as well.
Okay, great. Thanks, Morné. Cheers.
Thanks, Mark.
Thank you. Next question comes from the line of Mark Samter with MST Marquee. Please go ahead.
Yeah, morning everyone. Morning. First question, if I can, just to follow up on the initial question around the price review with Origin, and I appreciate obviously I'm not gonna try and push you for any comment on where that ends up, but it's something that I certainly think I encounter a lot of confusion with where among investors. Can you just confirm for us, I guess, like we saw with the arbitration process last time around, it doesn't set a price that's determined as if that contract was being negotiated on the day of the price review. It takes into account deals done in the intervening three-year period, which is a benefit to you guys, obviously, last time it came round.
Can you just confirm that this price review isn't, you're sitting there on the first of July 2023, and you'll get what the market is then? It's a reflection of more of an average over the previous three years. Is that a fair interpretation?
Yeah, I think. Hey, Mark. I think in terms of the disclosure around that, we were pretty fulsome in our when the arbitration outcome was announced in our previous ASX announcement. I think it was worth to that effect in terms of it looks at contracts over a similar period of time over the preceding period. Obviously delivering in those similar markets as well. I think we were pretty fulsome in that disclosure. I think that still stands.
Perfect. Thank you, Morné. Just another question around Waitsia, and I guess when we think about when it does start producing. Can you give a little bit of a picture on the initial ramp profile, particularly I guess if we're starting to head right towards Northern Hemisphere winter of 2023, 2024, how much we get in that early stage. Just around that, with the contract with BP, is there any seasonality in the portion that is sold spot or do you get to sell them at the best or the worst of times?
Yeah, good questions, Mark. The initial rate, obviously, the ramp up, is to the 250 terajoules. Ours is obviously the 125 terajoules. There's only I mean, obviously, the number of shipments, the gas that's needed for the shipments will obviously fit into the North West Shelf at that point in time. When we say about half, the second half of 2023, we assume that that ramp up will be, obviously, done by that point in time. When we talk about volumes and the target for 2028 by 2024, that assumes that sort of ramp up period as well, which will take a couple of months to ramp up to that sort of full capacity of the plant.
In terms of the shaping in terms of the demand in terms of winter and summer in the Northern Hemisphere, that will be dependent on the shipments during that period of time. We do have arrangements where, over the five-year period, we will get, I suppose, an equal exposure to those winter and summer periods.
Okay, awesome. Thanks, Morné.
Thanks, Mark.
Thank you. Next question comes from the line of Daniel Butcher with CLSA. Please go ahead.
Hi, everyone. Curious, a couple things. The first one's just on OpEx. You've raised your OpEx guidance by sort of half a dollar a barrel. Just sort of curious, is there a production mix to higher cost fields, or are you seeing general cost inflation in the fields? What's sort of driving that?
Thanks, Daniel. That's probably a combination of all those things in terms of you know it's in terms of the cost per barrel, it's towards the high end of obviously the production capacity in terms of where that production is coming from, which may throw this to Emily as well. But it's coming from the fields that carry the higher cost. Also production decline that's coming through FY 2023 as well compared to FY 2022 before we actually reach the new volumes coming in from FY 2024 onwards. There is a bit of a component that is fixed price as well. We do need to, you know, have that OpEx there, in terms of, you know, waiting for the volumes to come in line from FY 2024. That's largely unavoidable for 2023.
Okay, thanks. Second one just on your guidance. What nominations at Otway are assumed? Are you assuming that it basically produces at the full capacity you've got, or are you seeing some sort of seasonality given the current environment where people are taking as much gas as they can with not much seasonality for next year? I'm just sort of curious what you've assumed.
Yeah, we are assuming, as I said, just above take-or-pay levels for FY 2023. There is a bit of seasonality in it. We haven't assumed that our customers will nominate to 100% of the well deliverability in FY 2023. We have been conservative from that point of view.
Okay, great. One final one for me, if I can. You talked about Perth Basin exploration on slide 31. Just sort of curious whether you can give us a bit of color about the size of the prospects or fields that you're pursuing there and your estimated success rate, given it's been pretty successful area for yourselves and your peers nearby so far. Second part of that question is could some of that production be exported through North West Shelf as well, if you find a significant amount?
Maybe I'll cover the second part of the question first, and then I'll hand over to Sam just to talk about the exploration program in the Perth Basin. I think from a Perth Basin point of view, obviously we're excited about the prospectivity there, and that's why we're starting our exploration process at the end of this year with Mitsui. Overall, I think we are aiming to hopefully have a material increase in potential volumes coming out of the Perth Basin as a result of the exploration program.
We are hoping that that will give us the avenue to go and have a discussion around what that means from a domestic versus international point of view, going forward, and whether we can, you know, get to a point, obviously with government approval and blessings in terms of expanding the plant, say by 2026, 2027, to actually expand the plant and hopefully get more LNG into the market after we've taken care of the domestic market. We'll see whether we can make that work in terms of the volumes coming out of the exploration program. That's totally dependent on the actual program and how successful we are there.
There's also the opportunity, the Waitsia plant, you know, to have further backfill and extend the life, from the volumes there, again, if successful. I'll maybe hand over to Sam just to talk about the prospectivity itself.
Yeah. Thanks, Morné. I mean, we're lucky to have a portfolio of prospects here. What a wide range as you can see from the map. They of course have a range in potential size and also risk. In regards to size, as I've said previously, we're not making any predictions there. I think if you look at the area of our prospects in relation to the discovered resources that have had recent reserves announced, then I think that's a good yardstick to go by. In regards to risk, like I say, there's some variability there. Proximity to existing discoveries is positive. We do regard the two Mitsui operated Elegans and Genetrix to be slightly higher risk than the other prospects.
I think the whole point here is we're drilling up a lot of exploration wells. We certainly anticipate success. As Morné highlighted earlier on, we are ready to follow up with appraisal to understand what the resource size is of each of those discoveries as and when they come in. In addition, I'd highlight that, we're also looking at drilling a second well in Beharra Springs Deep, which would prove up our 1P reserves and maintain our gas production. We're also looking at planning 3D seismic over the leads, which will hopefully give us a better understanding of those features and add further to the portfolio so that we can continue our drilling into FY 2024 as well.
All right. Thanks a lot. I'll turn it to somebody else. Cheers.
Thanks, Dan. Thank you. Next question comes from the line of Nik Burns with Jarden Australia. Please go ahead.
Oh, yeah, thanks. Hi, Morné and Anne-Marie. Just a couple of questions from me.
Good day.
Good day. On the East Coast gas contracted position, back on slide seven, just wanna clarify something if I can. For FY 2024, you're showing contracted gas of 33% and then 68% in FY 2025. Just trying to understand why that's increasing. Can I assume that that 68% in FY 2025 also includes the priced reset volumes from FY 2024?
Yeah, that's correct, Nik. That's obviously contracted by FY 2025, and then the 8% you can see there relates to the Cooper Basin volumes. Those are the 8% reset.
Yep. Okay, that makes sense. Do you have any sense of, I guess, if you just think about your East Coast gas sales in FY 2022 plus 2023, what proportion of that 25 volumes would still be exposed to what you consider legacy or current gas prices versus what will be repriced or uncontracted in FY 2025?
Don't have that. I'm just looking across the table. No, we don't have that. Maybe, Nick, if you call us back afterwards, we can look at whether we can provide that more broadly. I don't have that here for you today.
No worries. Look, I might just talk about a quick couple of questions on Waitsia here. Waitsia Stage 2, there's no mention of cost update there. I think at FID you're talking AUD 350 million-AUD 400 million each share. Just wondering whether that's still valid? Are you within that range? Have you seen any sign of cost escalation there? What's the remaining key risk here in the remainder of the program?
That's correct, Nick. We haven't updated any of that CapEx, so it's still within that range. We're still currently holding that range, so haven't updated that, in terms of the current progress and that we see there. I mean, the main risk for us is in terms of, you know, the WA market, is around the compressor timing. Well, there's four compressors really, and then obviously liquidating the work on site. We are talking to Clough and Mitsui in terms of how that could be brought forward in terms of timing. We are looking at whether we, say, for example, air freight some of the valves in, versus putting it on a ship.
You know, bringing over the compressors one at a time and then commissioning them versus again waiting for four compressors to be completed before it's shipped. We are looking at how we can accelerate the timing in terms of the Waitsia delivery. That's basically the risk there is the logistics of the work on site and how we can better manage that in terms of sequencing and potentially bringing that forward.
Got it. Just a final one for me, just around the Perth Basin exploration, appraisal program. You've sort of outlined, I think now it looks like 6-8 wells. I think previously you were talking 3-6, a good increase there. Just understanding, I guess, when do you expect to start the first well, i.e., when do you expect to complete Waitsia Stage 2 development drilling, and which will be the first well that's drilled? Cheers.
Thanks, Nick. The Perth Basin program, the development well's going pretty well at the moment. They are running on schedule. We expect that to be completed by the end of calendar 2022, and then we'll kick off the exploration program from there. The first well is a Mitsui operated well, named Elegans , and then we'll progress it from there.
Fantastic. Thanks, Morné.
Thank you. Next question comes from the line of Gordon Ramsay with RBC Capital Markets. Please go ahead.
Oh, thank you very much. Morné Engelbrecht, just a question about capital management and kind of strategy going forward. Clearly-
Yeah.
Your net cash, AUD 165 million this year, you're gonna be net cash next year. You've got strong free cash flow. It's growing net of growth CapEx. Why don't you get on the front foot and put in place a cash flow based dividend policy net of growth CapEx and just have something for investors to look forward to? Because it's a little bit of an insult that the dividend has been sitting where it is for so long, and yet your net cash this year and next year. Can you just comment on that, please?
Yeah. Thanks, Gordon. As I said before, we think in terms of prudent capital management, and the capital that's still at risk and being spent in FY 2023, that now is not the time to come up with a revised capital management framework. Acknowledging, you know, in terms of what you've just said, it does make sense. From a current FY 2023 point of view and the capital spend and the exposure we have there and the risk that's still on the table, we feel it's still prudent for FY 2023 to maintain that.
Does not mean that we're not discussing that with the board on an ongoing basis and that we're not looking at how we build out our capital management framework going forward. It also doesn't mean that we're not looking at how we can expand and grow the business both from an organic and inorganic base in FY 2023. But in terms of formalizing that capital management framework, FY 2023 is not gonna be the year where we announce a formal capital management framework. I think that will be in the latter part of 2023. We'll be looking at how that what that means for us going forward from FY 2024 when we see material free cash flow coming into the business.
Okay. Just on Cooper, clearly the compression hasn't really gone to plan. You're talking about an additional two wells. Is there potential for a reserves downgrade there?
We don't see any reserve downgrades going forward. We did make a small adjustment in the reserves, as you would have seen in FY 2022. The compression project was actually quite successful for us in terms of uplifting our production rates from the asset. We do see the need for those two further development wells, going forward to increase and maintain our plateau for a number of years, beyond that as well.
Just lastly from me on the BP contract on the LNG side, are you able to split the difference between JKM and Brent, so we get a feel for whether it's more of a Brent oil price index contract than JKM?
Unfortunately, I can't provide that, Gordon. Apologies for that. I think there's a few commentators in the market that's obviously making some estimates and forecasts. Maybe point to them.
Okay. Thank you.
All right. Thank you.
Thank you. Next question comes from the line of Saul Kavonic from Credit Suisse. Please go ahead.
Thanks, Morné Engelbrecht and team. Just a few quick ones. Can I come back to this BP SPA? I think it was a month ago at the quarterly, it said that terms are materially the same versus when the original HOA was signed. Can you confirm if terms are materially the same, Morné Engelbrecht?
They're materially the same. As I said, the contract we signed is reflective of the current market conditions of what you would expect us to sign.
I'm just trying to understand. I mean, has there been either an uplift in slope or has there been an uplift in the proportion of spot LNG versus a year ago or not?
Again, Saul, I can't really comment on that apart from what I've just said, unfortunately.
All right. Just looking at the FY 2024 target of 28 million barrels, like the language has changed here. You're now saying up to 28 million barrels, and you've listed a number of assumptions there, which some of them look frankly pretty optimistic, like maximum nominations, et cetera. You know, I'd read this to say, you know, you're now guiding that you might not get 28 million barrels in FY 2024, which would be the fourth production outlook downgrade in as many years.
Is the guidance we've now got in FY 2023 and this risk profile in FY 2024, is it conservative or are these still targets? Because we've obviously gone through three years now of a lot of guidance has been optimistic targets which have been disappointed. I'm trying to get a sense of whether you think we've now got a reset of expectations to a conservative outlook versus an optimistic outlook?
Look, I would definitely say it's, you know, when we go through the basis for the production guidance as we've gone through, you know, there's obviously room in terms of the basis we've set there. There's, if you look at the risks and key drivers for the 28 million barrels, there's risk and opportunities there as well. I do think it's, you know, from my point of view, it's a target in terms of reaching that target. For us, we're working to deliver those key projects, which is basically Waitsia and Otway, are the two key projects to deliver to make sure we get to that target of 28 million barrels.
We need to make sure that we hit the timing as we set out, which is mid-2023 for Thylacine and second half for Waitsia. Whether they're conservative or not, they are the targets we are setting for the business, in terms of delivery of those specific projects.
Thanks. Last one. Just again, on the Otway, contract repricing from July 2023. You talked about, you know, it's the average of the last few years versus, kind of, the point in time when it's done. Look, I'm saying, I'll just put a scenario out there. If we were to see some two to four-year fixed price East Coast gas deal signed in the next 12 months at, say, AUD 15, which would be our estimate of, say, where the price is. Does that factor into the price review?
Yes. As I said before, it's over the preceding period over which that contract was in existence. That will be the three-year period that applies. From where we're sitting right now, there's still a year to go to get to the first of July 2023. Your assumption would be correct.
Great. Thanks, Morné. That's all from me.
All right. Thanks, Saul.
Thank you. Next question comes from the line of Adam Martin with Morgan Stanley. Please go ahead.
Good morning. Just a question on Bass Gas. It looks to be coming off a bit quicker just in terms of production decline. I suppose I'm trying to understand, if Yolla West doesn't come in, sort of what happens to you? Sort of revert back to Trefoil or, you know, do we assume abandonment comes in quicker? Can you just talk about that asset, please?
Yeah. No, thank you, Adam. In terms of Bass Basin, as we said, we're quite excited about the Yolla West opportunity there, so we're looking to get the rig out there end of next year. In failing the successful exploration there, we are still looking at progressing with Trefoil in terms of the FEED there. We are looking at the prime 3D seismic in terms of what that means for our resources and then obviously our reserves there potentially in how we develop that field. Also looking at what that means from a scope point of view, whether we can extend the scope.
Then we're also going through a program where we, looking at all the capital costs that relate to that development and whether we can actually reduce the capital cost, for that project. All of that's hopefully feeding into, that assessment, and then we'll make that assessment, I would think, closer to the end of this calendar year and, see what that means for the asset going forward. Obviously, if, we don't go ahead with Trefoil and Yolla West is not successful, then we would look at what that means from a decommissioning point of view.
Okay. No, that's helpful. Just on Thylacine, looks pretty important in terms of driving that FY 2024 uplift. Can you just talk through, you know, what are the key bits of work and what are the risks to getting those Thylacine wells connected on time, please?
Yeah, look, I mean, the key pieces of work is both offshore, the flow lines, so laying the flow lines to the Thylacine platform, and then the brownfields work that relate to the liquids handling at the Otway Gas Plant, as well. Those are the two key pieces of work we need to liquidate. The offshore part of it is reliant on the weather. We'll commence that after the winter period, when there's calmer weather and more predictable weather with the vessels going offshore. The brownfields work, a similar story in terms of waiting on the winter to pass and rain potential interruptions before we start liquidating that work as well. In terms of the actual work that's been delivered, from a technical point of view, obviously, not as technical as drilling 7 Off-shore wells.
Yes. Yeah. No, that sounds good. All right. That's all for me. Thank you. Thank you, Morne, Anne-Marie.
Great.
Thanks, Adam.
Thank you. The next question comes from the line of Tom Allen with UBS. Please go ahead.
Good morning, Morné, Anne-Marie and the team. Recognizing Beach's net cash position, you've upsized the debt facility and your responses to prior questions about inorganic growth opportunities, can you comment on the broad framework that you might assess at the opportunity set? For example, are opportunities in Australia only or internationally, or greenfield versus further brownfield, or a preference for new gas or oil? I'm looking for some comments on what defines the strike zone.
Yeah. Thanks for the question, Tom. We are focused on Australia and New Zealand in particular. We're not looking at international borders at the moment. In terms of looking at specifically, you know, brownfields or greenfields versus producing assets, we are not focused on any particular aspect of that. We are looking at, you know, if potential assets can feed our current infrastructure, so that's probably priority number one. Obviously, if it's producing, that's a plus, but we're not focused on anything in particular in terms of whether it's greenfields, brownfields or producing. I think what we focused on is definitely adding value, so seeing where we can add value from a Beach perspective. Not looking at M&A for M&A cycle, adding volume or scale. We do need to see a pathway forward on where we can actually add value as Beach, from that perspective.
Okay. That's helpful, Morné. Just following up a few questions in regard to Otway. Just given that Origin can nominate up to the full capacity of the Otway Gas Plant, it looks like it might present some challenges signing contracts for Enterprise Gas. Is there any plan to expand the processing capacity of the Otway Gas Plant further? Or under what commercial arrangements could we see Enterprise Gas contracted other than a few modest gigajoules here and there under a spot sales arrangement?
Look, we're not currently looking at any expansion on the Otway Gas Plant. The enterprise volumes will play an important part in terms of the flexibility we have around that specific asset and the volumes we can put to market. We'll play an important role from that perspective, when the nominations are not obviously nominating the full capacity that's available in the plant. That's how we view Enterprise and how we view that volumes, which will help us balance out our capacity there from an Otway Gas Plant, but not looking to expand it beyond the current 205 terajoules a day.
If Origin can nominate on a day-ahead basis, how long would it take realistically to then have Enterprise up and ready to inject under a spot arrangement? Is it a matter of weeks, months, days?
No, it's immediate, effectively. If the Enterprise well is connected, we can just open the valve and the molecules flow.
Okay, great. Thanks, Morné, Anne-Marie.
Thanks, Tom.
Thank you. Next question comes from the line of Scott Ashton with SHA Energy Consulting. Please go ahead.
Good morning, Morné. Just a quick question.
Hey, Scott.
It follows on the back of Nick and Daniel's question. I thought I heard on the call for the Perth Basin assets, you're looking maybe 500 BCF would be like a threshold volume, my interpretation of whether you expand Waitsia or use it for backfill. Is that what we should be thinking that the exploration program needs to deliver something like 500 BCF? And then on the back of that, if you're talking about expanding the Waitsia plant, is there some sort of talk underway about, you know, the capital that might be needed to accommodate either increased rates or to build in some extra capacity so you're not suboptimizing the plant? Can you just sort of make a few comments around there? I just wanna understand the strategy.
Yeah, look, from a plant capacity point of view, in terms of the current footprint we have and looking at the future potential expansion, if that exists, depending on the results, we can expand that plant to about 100 terajoules a day, if we see the need. Obviously, you're gonna have to reach FID on CapEx and make sure you can get the return on that. But that will only be from, you know, say 2026, 2027 onwards. Again, that'll be dependent on whether there's a market to put those volumes to at that point in time and what market you're putting it to. I might throw to Sam on the BCF question. Sam, how do you wanna answer that?
Yeah, like I said earlier, I think, you know, we've got a lot of prospects in our portfolio, and if you look at the other side of the figures then 500 BCF is eminently achievable. But there's also a range around that which is quite wide.
I suppose where we're sort of going with that is that the inflection point or the trigger point for whether you optimize the plan even further for increased rates?
Look, it might be. It's obviously something we need to discuss and agree with the operator, which is Mitsui, from a JV perspective. I suppose what we're trying to say there is that in terms of the prospectivity of the Perth Basin and what we're going after by the end of this year in terms of starting the exploration program, that is quite significant and material.
Okay. Just a very quick question for Anne-Marie. Just so I've got this right, so apologies if it's already been discussed previously. The AUD 0.48 a barrel NOPTA abandonment levy is that deductible for PRRT purposes? And is the Otway and the Bass Basin stuff paying that at the moment, given it falls within that 2021-2029 timeframe? Can you just maybe make a few comments on how that works with your abandonment liabilities and provisions?
Yeah. We're not currently paying PRRT on any of our assets at the moment.
Correct. [crosstalk] Probably not forecasting to pay any. Yep.
[Crosstalk] We're not forecasting paying it in the near-term future.
I don't think you can get it as a deductible, but,
No, you can't.
From our point of view, it doesn't make a difference.
Yeah, not deductible for us.
Okay, thanks.
All right.
Thank you. There are no further questions at this time. I will now hand back to Mr. Engelbrecht for closing comments.
Thank you, everybody, for dialing in this morning. Obviously, if you've got any further questions, please give Derek or myself a call. Happy to take any questions offline as well. Thank you very much. Cheers.
Thank you. That does conclude our conference for today. Thank you for participating. You may now disconnect.