Beach Energy Limited (OTCPK:BEPTF) Q4 2022 Earnings Conference Call August 14, 2022 8:00 PM ET
Company Participants
Morne Engelbrecht – Chief Executive Officer
Anne-Marie Barbaro – Chief Financial Officer
Stephen Algar – Group Executive
Conference Call Participants
James Redfern – Bank of America
Mark Wiseman – Macquarie
Mark Samter – MST Marquee
Daniel Butcher – CLSA
Nik Burns – Jarden Australia
Gordon Ramsay – RBC Capital Markets
Saul Kavonic – Credit Suisse
Adam Martin – Morgan Stanley
Tom Allen – UBS
Scott Ashton – SHA Energy Consulting
Morne Engelbrecht
Good morning, and welcome to the FY ’22 Full Year Results Presentation for Beach Energy. My name is Morne 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. Then it will 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 ’23 and beyond. Following that, we’ll open the lines for Q&A. Before we commence, Slide 2 includes our disclaimer, price assumptions as well as information regarding our reserves disclosure. We’ll leave this review to read in your own time.
Our key message for today is that FY ’23 is the year of focused project execution as we delivered our foundation for growth in FY ’24 and beyond. For FY ’22, we delivered a strong set of financial results and also delivered on major project milestones. Operationally, albeit production was lower, key project milestones were delivered against a challenging backdrop of COVID, weather events, labor shortages, 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’re focused on delivering on our growth objectives. We’re focused on growing our gas supply from each of our assets and materially from the offline Perth Basin in particular, growing our exposure to key gas markets, including expanding our share of 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 4. 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 6 development wells with an increase in reserves to boot. The first 2 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, 3 of the 6 development wells drilled and the LNG sale and purchase agreement with BP now also finalized and signed.
Slide 5 summarizes a 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 heading 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 also our biggest CapEx year on record as well.
The Board declared a AUD 1.10 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 ’23 activity. Our overarching objectives are clear and aligned with our strategy. In FY ’23, there will be much focused on completing the bulk of the work programs in Otway and Perth Basins. We are 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 ’23 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 purpose and exploration drilling to commence in FY ’23 and Otway basin drilling plan for FY ’24-’25. 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 7 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 for developing newer sources 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 new enterprise and piloting volumes come online, our own contracted 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 8 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 5-year term. In summary, BP has committed to buying all of Beach’s share with Waitsia LNG volumes up to 3.7 million tonnes. With 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 of 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’s Phase 2 commissioning. We are very excited to have BP as a long-term partner and look forward to delivering our first LNG cargo. Slide 9 is important as it highlights our target production of up to 28 million barrels of oil equivalent by FY ’24. 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 driver for reaching the target can be summarized as follows. Overall, [Indiscernible] performance in line with forecast 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 wealth deliverability from the start of the FY ’24 year from the Thylacine and Enterprise wells. Customer nominations for the OGP is also seemed to be in line with a full well deliverability and therefore both take pay levels. And 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. Reserves additions this year was challenging, while development projects were progressing of a lack of exploration in FY ’22 outside of the Cooper Basin. This is a key issue, which we’ll be addressing in FY ’23 and ’24. The decline in reserves was mainly driven by production and reclassification of as Bass Basin reserves as we flagged in May.
In the Cooper Basin, revisions were due to outcomes from work programs during FY ’22, including poorer-than-expected fracture stimulation results in the Balgowan field and infill drilling at the Kalladeina field, and production performance at Bauer.
Our Bauer production was underperforming due to higher-than-expected water influx from the Namur to the McKinley reservoir. This was remediated by reinstating the [Indiscernible] water producers to cool water away from McKinley. This has improved production performance, but not yet recorded it completely. We are committed to growing our reserves base 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 [ pacing ] 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?
Anne-Marie Barbaro
Thanks, Morne. 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 our strong set of financial results for FY ’22. Turning to Slide 13, and as Morne has already highlighted, Beach ended FY ’22 in a strengthened financial position, setting us up well to deliver our growth projects in FY ’23 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 ’23 with liquidity of AUD 765 million at year-end, and we are targeting a net cash position throughout FY ’23. Our results this year again demonstrate capital management discipline, which is particularly important during periods of [Indiscernible] capital expenditure. As we complete our current major growth projects, we target growth in free cash flow in FY ’24. Slide 14 sets the scene with our production figures for FY ’22. This year, we produced 21.8 million barrels of oil equivalent, which was in line with guidance.
We have diversity of production from 5 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 dropped 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, and underlying EBITDA of AUD 1.1 billion, up 17% on FY ’21.
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 ’22 underlying NPAT to FY ’21. The 15% rise in revenue during FY ’22 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 a result of FY ’22 exploration activities being capitalized in accordance with our area of interest policy.
The increase in cash cost 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 ’21, driven by the successful arbitration outcome in relation to carbon recognized in FY ’21. 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 ’22. As mentioned earlier, operating cash flow of AUD 1.2 billion was up 61% on FY ’21.
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, and 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 in Moomba CCS.
FY ’23 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 ’24, which has been our clear focus over recent years.
With that, I’ll hand back to Morne.
Morne 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, Foodbank and Clean Up Australia.
We are 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 assets were acquired. This target takes into account all of full assets in the portfolio, not just our operated assets. We’re already making progress towards this target with the emissions reduction project underway 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 ’22. We are firm believers that CCS will be critical for sustainable gas production and for the world to reach net-zero with the Cooper based and depleted reservoirs making it ideal for CCS. We are initially retargeting up to 1.7 million tonnes of growth of CO2 injection annually with our share being roughly 500,000 tonnes per annum. We are progressing well with the operator as we target first CO2 injection in 2024. I I’ll touch briefly now on our key markets.
Slide 24 summarizes the 5 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 has placed attractive fundamentals with tightening supply-demand outlook. Current themes of energy security and increasing demand have seen elevated commodity prices over the past year. Higher cost of capital and lack of stable investment policy have led to under-investment over recent years [Indiscernible] added current supply issues, which further supports our material investment and new gas resources. This gas market dynamics are set out on 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 the 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 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 as set out on 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 on 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 under investments 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 ’23 and beyond. Slide 29 summarizes our FY ’23 guidance. As I mentioned earlier, FY ’23 will continue our momentum from ’22 as we focus on executing major growth projects. Capital expenditure is expected to be of a similar order to FY ’22, a slight change the composition reflects the progress made with our major projects, particularly in the Otway Basin.
Also have additional spend on the Cooper Basin JV from 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 ’23 is straightforward. In the Otway Basin, production will benefit from recent connection of Geographe 4 and 5, greater well delicability will not occur until the Thylacine wells are connected. We have not assumed any incremental production from Thylacine or Enterprise in FY ’23.
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 ’23. It should also be noted that the Otway gas plant will be down for approximately 3 to 4 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 ’24, thus natural field decline in the order of 15% to 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 in Beach’s existing fields demonstrate the extensive nature of the Perth basin. Most of the remaining prospectivity in the Perth Basin are now viewed within the Kenya gas play and out 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.
Once Waitsia Stage 2 development drilling is done, we’ll kick off the exploration program with Mitsui operated well, Elegans. The full program will compromise 2 material private levels and up to 6 beach operated wells with the sequence still to be locked in as it’s dependent on regulatory approvals for some of the wells. Trigg 1 will be the Beach’s first operated well of the campaign with the team excited by this prospect.
It’s on trend and up dip from the West Erregulla discovery and has very similar characteristics to the Lockyer Deep. Discovery here would be quickly apprised as we see the potential for material volumes. So the Otway basin now on Slide 33. You can see here our extensive position in the offshore and nearshore acreage. In FY ’23, much focus will be on connecting the Thylacine wells and Enterprise discovery to the Otway gas plant.
However, we’re also very focused on activity and growth beyond FY ’23. We will include exploration in both the onshore and nearshore acreage. Slide 34 looks at our offshore acreage, which cycles from a number of reasons. First, we have 5 prospects identified, which are located at closed 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 our prospects chance of success and has led to a 100% success rate in Beach’s acreage to 16 successful discoveries from 16 wells drilled. We are improving our seismic data quality currently and with encouragement will consider exploration drilling in FY ’24. If successful, we would look to develop these discoveries in conjunction with development of Artisan and La Bella in a cost-efficient manner. We’re also excited by our nearshore Otway acreage that is set up on Slide 35. We are focusing on 3 high-impact targets located close to Enterprise.
One could be drawn from the Enterprise platform, significantly reducing development cost and time line. 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 result in decline accelerating earlier than expected. We are now focused on drilling up to 2 development wells to a rest field decline and return the plant to higher processing rates.
Planning is underway, and we are targeting drilling the first well in FY ’24. Turning to Slide 37 and the Bass basin. As always, our focus on 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’re hoping to drill Yolla West this summer, but lack of a [Indiscernible] rig means that we are now targeting the summer of ’23-’24.
We also defer decision on the trial development to allow more time with interpretation of the newly acquired 3D prime seismic survey and to fully assess project economics. Turning now to the Cooper Basin with a look at the Western Flank on Slide 38. It was a challenge year at the Cooper Basin with heavy rains disrupting activity in several occasions. This meant the backlog of workover activity and well connections has been carried over into FY ’23. 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 Namur 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 have already had one oil exploration success this year, Rocky-1, which discovered oil in the Birkhead reservoir.
Gas exploration and appraisal drilling is under consideration for the second half of FY ’23. We have a number of continued wells ready to go, depending on the outcomes of drilling in the first half. With near reservoir management strategies helping arrest the decline in oil production in FY ’22 and much activity planned for FY ’23, we are confident in targeting flat oil production this year. Heavy grain 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.
The rates of campaigns will be undertaken, including appraisal in development drilling and continuation of successful campaigns from FY ’22, such as the Moomba South program. [Indiscernible] is now drilling to catch up on planned activity and address production declines witnessed during FY ’22. I’ll close-out with our key takeaway on Slide 40. As I said, our key messages for today is that FY ’23 is a year of focused project execution as we deliver the foundation for growth in FY ’24 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 open for Q&A. Thank you, operator.
Question-and-Answer Session
Operator
[Operator Instructions] The first question comes from the line of James Redfern with Bank of America.
James Redfern
Just 2 questions, please. The first one is just around the contracted gas market. The slide on your presentation has a midpoint of around AUD 12 a gigajoule for gas to be supplied in FY ’23. I’m just wondering if you can make some more comments around what you’re seeing for contracted gas prices for volumes let’s say 3 to 5 years starting in mid-’23, please, because that’s when, I guess, the gas price reset will begin for Beach Energy.
Morne Engelbrecht
So in terms of the pricing, obviously, the ACCC’s more recent report sort of focus more on the period from January to February of ’22. I think didn’t have a lot of visibility in terms of term contracts beyond the February ’22 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 2 contracts coming up for a price reset both in the Otway and that will reset from the 1st of July 2023. We are starting on that process right now and 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.
But I think — and those rely on contracts over a similar term of the contract that we’re negotiating. So 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 increases in spot prices locally, but also internationally as well from an LNG perspective, that does impact the local market.
And 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 year forward.
James Redfern
Okay. And I just had just one second question, please. Just wanted to understand the production profile for the Otway Gas project. So at least you are expecting to reach nameplate capacity of 205 TJs a day, mid-count of 23. I’m just wondering, are you expecting a plateau for a couple of years and then the natural field decline of, say, 10% per annum or do you have a different view to what I just said.
Morne Engelbrecht
So 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 while also being targeted for connection mid-2023 with the well stock, so the full Thylacine wells and Enterprise and then Geographe 1, 5 that we’ve recently added. We can see that, that plateau will be maintained for a number of years post FY ’24. And obviously, as I’ve just gone through as well, we would be looking to expand and drill in FY ’24, which will then give us the well stock defeat at the back end of the current well stock. So we do see a plateau in that plant for a number of years beyond that as well.
Operator
This is the operator. I’ve already promoted Mr. Dale. Mr. Dale, are you there.
Dale Koenders
Just on the Cooper Basin JV, 5 rigs, 100 wells, AUD 250 million to AUD 300 million CapEx net, a further AUD 150 million to AUD 200 million in the Western Flank, but you’re only targeting flat production year-on-year. Is this slots needed for flat production outlook on these assets going forward?
Morne Engelbrecht
There’s a few things there. Obviously, there is the catch-up, as we said previously, in terms of the backlog of activity from ’22. So 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 ’23 versus FY ’22. And we drilled 69 last year, going up to 100 this year.
We’re also looking at other changes in terms of the electrification project that we’re starting with Santos more broadly and then also starting out the CCS project as well, which add to the CapEx profile there.
Dale Koenders
So can you give us in terms of what production step-up you’re targeting in FY ’24 for the level of spend?
Morne Engelbrecht
For the Cooper Basin, we are looking to at least keep the production flat. So 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 ’22. And then in our own fields, we’re looking at obviously expanding on the exploration and development program there. So we go through the Western Flank side of things.
The first 3 quarters of the year, we’ll look at development and appraisal drilling in the markets, Spitfire and Growler fields. And then also looking at the exploration and the into Callawonga, Hanson and Carton fields. And then obviously, looking at how we expand around the specifically Martlet and then looking at the last quarter of the year, expanding on our exploration or appraisal program as well. So there’s quite a bit out of the program that relates to production increases in the back end of ’23, but then mostly ’24 as well.
Dale Koenders
So I guess the production guidance of FY ’24, up to 28 MMboe, is 28 achievable? And if so, what is needed? Is it all Victorian gas projects starting mid-calendar year ’23, customer lean nominations, wait here basically a full second half calendar year ’23. What’s needed to hit that number?
Morne Engelbrecht
Yes. That’s basically correct, Dale. So as we set out on this slide, in terms of the base production, we would expect our current assets to producing a base in terms of the Cooper Basin. As I said, from a Cooper and Bass point of view, there’s an underlying decline of 15% to 20%, and we’re not looking to draw the auto well until the summer of ’23 ’24. So 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 piloting wells coming in from the 1st of July 2023 and obviously, Enterprise being connected at that point in time. And then looking at the West in terms of the first LNG shipments we said second half of ’23. So those are the things that add the specific material volumes in terms of Otway and Waitsia. So if there’s any slippage of that timing to the right, then obviously, that target will be at risk.
Dale Koenders
Okay. And then maybe finally, just a comment around targeting a net cash position through FY ’23 kind of effectively targeting a lazy balance sheet for the next 12 months. Can you talk us through what thinking for that is? Is it a lack of trust in execution, production outlook, oil price or sort of what is it that you need so much conservative I assume?
Morne Engelbrecht
Look, we’re still in a very — in terms of the world we’re operating in and in terms of the risk that involves the projects, we thought a prudent approach is better and especially in terms of FY ’23 and the CapEx year. If you look at our market cap, we’re still spending at close to a third of our market cap in CapEx for FY ’23. So it is significant. It is still a high CapEx spend. So 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 whether those exist in the current market. So it does give us the flexibility to look at all of our options for FY ’23 and then obviously look at the material increase in cash flows for FY ’24 and what that then means for our capital management framework going forward. So from our point of view, it is still prudent to keep the balance sheet as balance as we can for FY ’23 until we can lock away the cash flows commencing FY ’24.
Operator
Next question comes from the line of Mark Wiseman with Macquarie.
Mark Wiseman
Thanks for the update today. Just had a question on the East Coast gas market and the contracted exposure. You had talked about Morne, another contract on Enterprise and maybe from the portfolio more broadly, should we be expecting Beach to announce a contract at some point?
Morne Engelbrecht
Yes. We are engaging with the market, we’re starting to engage with the market on the Enterprise volumes. Obviously, targeting that to come in mid-2023, but I wouldn’t expect any announcement this half. Probably second half, we’ll probably make an announcement on those volumes. And as you say, they are uncontracted and is flexible part of the portfolio going forward from an [Indiscernible] point of view.
Mark Wiseman
And for FY ’23, the 11% uncontracted, should we assume that that’s flexibility and sold into the spot market?
Morne Engelbrecht
No. Obviously, that is the representation of currently contracted volumes. We’ll probably look to lock that away in terms of future term contracts as well and some of that might play in the spot market. So you shouldn’t see all of that spot market, but there might be a combination of the 2 going forward.
Mark Wiseman
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?
Morne Engelbrecht
Look, Mark, obviously, as you can imagine, I can’t talk to any specifics on the contracts. Obviously, commissioning and confidence. What we can say is, obviously, there’s a mix of that [Indiscernible] which allows us to take advances 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.
So it allows us to vary the first shipment day depending on the commissioning of the plant. And as I said, as well during my talk as well, is that it is an agreement that you could entirely expect us to have entered into in the current market environment. So that’s probably as much as I can say and willing to say.
Mark Wiseman
Okay. And just finally for me, just on the dividend. You’re obviously sitting on a large cash pile, but 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 ’23, whilst 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?
Morne Engelbrecht
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 here in FY ’23. We do want to lock away the projects, the growth projects and get to FY ’24, where we do see a material increase in our free cash flow going forward. So I think from FY ’23, I wouldn’t expect any increase necessarily in dividends, but 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 additional growth and looking at M&A as well when that makes sense from a value point of view. So 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. So it’s not necessarily exclusive as well.
Operator
Next question comes from the line of Mark Samter with MST Marquee.
Mark Samter
First question, if I can, just to follow-up on the initial question around the price review with Origin. And I appreciate obviously not going to try and push any comment on where that ends up, but it’s something that I certainly think I encounter a lot of confusion amongst 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 determined as if that contract was being negotiated on the day of the price review. It takes into account deals done in the intervening 3-year period, which is a benefit to you guys.
Obviously, last uptime, it came around. But can you just confirm that this price review isn’t you’re sitting there on the 1st of July 2023, and you’ll get what the market is then. It’s a reflection of more of an average over the previous 3 years. Is that a fair interpretation?
Morne Engelbrecht
Yes. So in terms of the disclosure around that, I think we were pretty fulsome now when the arbitration outcome was announced in our previous ASX announcement. And 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. So then obviously, delivering in those similar markets as well. So I think we were pretty fulsome in that disclosure.
So I think that still stands.
Mark Samter
Perfect. Then 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 have go towards Northern Hemisphere winter of ’23-’24. How much were we getting that early stage and just around that with the contract with BP, is there any seasonality in the portion that is sold spots or do you get to sell them at the best or the worse of the times?
Morne Engelbrecht
So the initial rate, obviously, the ramp-up is to the 250 terajoules, so is obviously the 125 terajoules. There’s only, I mean, obviously, there are a number of shipments, the gas that’s needed for the shipments will obviously get into the North West Shelf at that point in time. So when we say about half, the second half of 2023, we are seeing that ramp-up will be obviously done by that point in time. So when we talk about volumes and the target for ’28 by ’24, it 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. And then 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.
So we do have arrangements where over the 5-year period, we will get, I suppose, an equal exposure to those winter and summer periods.
Operator
Next question comes from the line of Daniel Butcher with CLSA.
Daniel Butcher
I’m just curious, a couple of things. The first one is just on OpEx. You’ve raised your OpEx guidance by sort of AUD 0.5 a barrel or so, just sort of curious, is there a production mix to higher cost fields or you’re seeing general cost inflation in the field? What’s sort of driving that?
Morne Engelbrecht
So that’s probably a combination of all those things in terms of the cost per barrel, it’s towards the high end of the production capacity in terms of where that production is coming from, which may further [Indiscernible] as well, but it’s coming from the fields that carry the higher costs and then also production decline that’s coming through FY ’23 as well compared to FY ’22 before we actually reach the new volumes coming in from FY ’24 onwards. So these are a bit of a component that is fixed price as well. So we do need to have that OpEx there in terms of waiting for the volumes to come in line from FY ’24. So that’s largely unavoidable for ’23.
Daniel Butcher
Okay. And second one, just on your guidance. What nominations have you assumed, assuming it basically produces at the full capacity you’ve got or are you seeing some sort of seasonality given the current environment where people take as much cash as they can with not much seasonality for next year? Just sort of curious what you’ve assumed.
Morne Engelbrecht
Yes. We are assuming, as I said, just above take-or-pay levels for FY ’23. There is a bit of seasonality in it. So we haven’t assumed that our customers will nominate to 100% of the well deliverability in FY ’23. So we have been conservative on that point of view.
Daniel Butcher
Okay, great. And one final follow-up from 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? And second part of that question is, could some of that production be exported through Northwest shelf as well if you find a significant amount.
Morne Engelbrecht
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, very 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 per patient as a result of the exploration program and 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 get to a point, obviously, with government approval and blessings in terms of expanding the plant, say, by ’26, ’27 to actually expand the plant and hopefully get more LNG into the market after we’ve taken care of the domestic market.
So we’ll see whether we can make that work in terms of the volumes coming out of the exploration program. But that’s totally dependent on the actual program and how successful we are there. And there’s also the opportunity, the Waitsia plant to have further backfill and extend the life from the volumes there, again, if successful. But I’ll maybe hand over to Sam just to talk about the prospectivity itself.
Scott Ashton
Yes. I mean we’re lucky to have a portfolio of prospects here with a wide range as you can see from the map. And 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, but I think if you look at the area of our prospects in relation to the discovered resources that have had recent reserves announced, and I think that’s a good yardstick to go by.
And in regards to risk, like I said, there’s some variability there, proximity to existing discoveries is positive, but we do regard the 2 Mitsui operated Elegans and Gynatrix to be slightly higher risk than the other prospects. But I think the whole point here is we’re drilling a lot of exploration wells and so we certainly anticipate success. And as Morne 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.
And 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. And 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 ’24 as well.
Operator
Next question comes from the line of Nik Burns with Jarden Australia.
Nik Burns
Just a couple of questions from me. On the East Coast gas contracted position, so back on Slide 7, I just want to clarify something, if I can. For FY ’24, you’re showing contracted gas of 33% and then 68% in FY ’25. Just trying to understand why that’s increasing. Can I assume that, that 68% in FY ’25 also includes the price reset volumes from FY ’24?
Morne Engelbrecht
Yes, that’s correct, Nik. So that’s obviously contracted by FY ’25 and then the 8% you can see there relates to the Cooper Basin, Cooper Basin volumes in terms of the 8% we said.
Nik Burns
Do you have any sense of, I guess, if you just think about your East Coast gas sales in FY ’22/’23, 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 ’25?
Morne Engelbrecht
I’m just looking across the table, we don’t have that. Maybe, Nik, if you call us back afterwards, we can look at whether we can provide that more broadly, but I don’t have that here for you today.
Nik Burns
No worries. And look, I might just talk about — just a quick couple of questions on Waitsia Stage 2. There’s no mention of cost update there. I think at FID, you’re talking AUD 350 million to 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 and what’s the remaining key risk here in the remainder of the program?
Morne Engelbrecht
That’s correct, Nik. So we haven’t updated any of that CapEx. So it’s still within that range. We’re still currently holding that range. So I haven’t updated that in terms of the current progress that we see there.
So I mean the main risk for us is in terms of the WA market is around the compressor timing. And well, there’s 4 compressors really and then obviously, liquidating the work on site. So we are talking to [Indiscernible] in terms of how that could be brought forward in terms of timing. So we are looking at whether we say, for example, air freight, some of the valves in versus putting in ownership, bringing over the compressors one at a time and then commissioning them versus, again, waiting for compressors to be completed before a chip. So we are looking at how we can accelerate the timing in terms of the Waitsia delivery.
But that’s basically the risk there is the liquidation of the work on-site and how we can better manage that in terms of sequencing and potentially bringing that forward.
Nik Burns
Got it. Just a final one from me. Just around the Perth Basin exploration approval program. So you’ve sort of outlined, I think it was like 6 to 8 wells. I think previously, you’re talking 3% to 6%, so a good increase there.
But 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.
Morne Engelbrecht
Nik, the Perth Basin program, the development well is going pretty well at the moment. So they are running on schedule. So we expect that to be completed by the end of calendar 2022 and then we’ll kick off the exploration program from there. So the first well is a material operated well named Elegans and then we’ll progress it from there.
Operator
Next question comes from the line of Gordon Ramsay with RBC Capital Markets.
Gordon Ramsay
Morne, just a question about capital management and kind of strategy going forward. Clearly, your net cash, AUD 165 million this year, you’re going to be net cash next year. You’ve got strong free cash flow 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 a little bit of insight 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?
Morne Engelbrecht
So 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 ’23 that now is not the time to come up with a revised capital management framework, acknowledging in terms of what you’ve just said, it does make sense. But from a current FY ’23 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 ’23 to maintain that. It does not mean that we’re not discussing that with the Board on an ongoing basis, and then we were not looking at how we filled 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 ’23. But in terms of formalizing that capital management framework, FY ’23 is not going to be the year where we announce a formal capital management framework.
So I think that will be the latter part of ’23. We’ll be looking at what that means for us going forward from FY ’24 when we see material free cash flow coming into the business.
Gordon Ramsay
Okay. And just on Cooper, clearly, the compression hasn’t really gone to plan. You’re talking about an additional 2 wells. Is there potential for reserves downgrade there?
Morne Engelbrecht
So we don’t see any reserve downgrade going forward. We did make a small adjustment in the reserves, as you would have seen in FY ’22 and 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 2 further development wells going forward to increase and maintain our plateau for a number of years beyond that as well.
Gordon Ramsay
And just lastly for 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?
Morne Engelbrecht
Unfortunately, I can’t provide that Gordon. So apologies for that. I think there’s a few commentators in the market that’s obviously making some estimates on forecast. So maybe point to them.
Operator
Next question comes from the line of Saul Kavonic from Credit Suisse.
Saul Kavonic
Just a few quick ones then. Can I come back to this BP SPA? I think it was a month ago at the quarterly, it said that terms of materially the same versus when the original HOA was signed. Can you confirm if terms are materially the same, Morne?
Morne Engelbrecht
They’re materially the same. But as I said, the contract we signed is reflective of the current market conditions of what you would expect us to sign.
Saul Kavonic
I was 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?
Morne Engelbrecht
Again, so I can’t really comment on that apart from what I have just said, unfortunately.
Saul Kavonic
All right. And then just looking at the FY ’24 target of 28 million barrels, like language has changed, you’re now saying up to 28 million barrels, and you’ve boosted a number of assumptions there with some of them look frankly pretty optimistic like maximum nominations et cetera. So I agree this to say you might not get 28 million barrels in FY ’24, which would be the fourth production outlook downgrade in many years. Is the guidance we’ve now got in FY ’23 and this risk profile in FY ’24? Is it conservative or are these still targets because we’ve obviously gone through 3 years now of a lot of guidance has been optimistic targets which have been disappointed.
And 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?
Morne Engelbrecht
Look, I would definitely say it’s — when we go through the basis for the production guidance as we’ve gone through, there’s obviously room in terms of the basis we’ve set there. And 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 from my point of view, it’s a target in terms of reaching that target. So for us, we’re working to deliver those key projects, which is basically Waitsia and Otway are the 2 key projects to deliver to make sure we get to that target of 28 million barrels. And we need to make sure that we hit the timing as we set out, which is mid-2023 with [Indiscernible] and second half of Waitsia.
Whether they’re conservative or not, they are the targets we are setting and the targets we are setting for the business in terms of delivery of those specific projects.
Saul Kavonic
Last one, just again on the Otway contract repricing from July 23. You talked about it’s the average of the last few years versus kind of the point in time when it’s done. But I just put a scenario out there, if we were to say some 2 to 4-year fixed price East Coast gas deal side in the next 12 months, say AUD 15, which would be our estimate of say, where the price is. Does that factor into the price review?
Morne Engelbrecht
Yes. So as I said before, it’s over the preceding period over which that contract was in existence. So that will be the 3-year period that applies. So from where we’re sitting right now, there’s still a year to go to get to the 1st of July 2023. So your assumption would be correct.
Operator
Next question comes from the line of Adam Martin with Morgan Stanley.
Adam Martin
Just a question on BassGas. 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, do you sort of revert back to foil or do we assume abandonment comes in quicker? Can you just talk about that asset, please?
Morne Engelbrecht
So in terms of BassGas, as we said, we’re quite excited about the Yolla West opportunity there. So we’re looking to get the week 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. So we are looking at the seismic, the prime 3D seismic in terms of what that means for our resources and then obviously, our reserves to potentially and how we develop that field. So also looking at what that means from a scope point of view, whether we can extend the scope and then we’re also going through a program where we’re looking at all the capital costs that relate to that development and how and whether we can actually reduce the capital cost for that project.
So all of that is 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 pre-fall and Yolla West is not successful, then we would look at what that means from a decommissioning point of view.
Adam Martin
Okay. That’s helpful. And just on Thylacine, looks pretty important in terms of driving that FY ’24 uplift. Can you just talk through what are the key bits of work and what are the risks to getting those or same wells connected on time, please?
Morne Engelbrecht
Yes. Look, I mean, the key pieces of work is both offshore, the flow lines, the laying the flow lines to the [Indiscernible] platform and then the brownfields work that relate to the liquids handling at the Alpha Gas plant as well. So those are the 2 key pieces of work we need to liquidate. So the offshore part of it is reliant on the weather, so we’ll commence that after the winter period. So when this come on weather more predictable weather with the vessels going offshore and 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.
But in terms of the actual work that’s being delivered from a technical point of view, obviously, not as technical as drilling 7 offshore wells.
Operator
The next question comes from the line of Tom Allen with UBS.
Tom Allen
So 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 the opportunity set. So for example, 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.
Morne Engelbrecht
Yes. Thanks for the question, Tom. So we are focused on Australia and New Zealand, in particular. We’re not looking at international orders at the moment. And in terms of looking at specifically brownfield, greenfield was just producing assets.
We are not focused on any particular aspect of that. We are looking at 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 its greenfields or brownfields are producing. I think what we are focused on is definitely adding value.
So seeing where we can add value from a Beach perspective. So not looking at M&A for M&As sake, we’re adding volume or scale. So we do need to see a pathway forward on where we can actually add value as Beach from that perspective.
Tom Allen
Just finally, have a few questions in regard to Otway. Just given the Origin can nominate up to the full capacity of the Otway’s gas plant, it looks like it might present some challenges signing contracts for Enterprise gas. So is there any plan to expand the processing capacity of the Otway’s gas plant further or under what commercial arrangements could see on Enterprise gas contracted other than a few more gigajoules here and there on [Indiscernible] sales arrangement?
Morne Engelbrecht
Yes. Look, we went up currently looking at any expansion on the Otway gas plant. So the Enterprise volumes will play an important part in terms of the flexibility we have around that specific assets and the volumes we can put to market. So it will play an important goal from that perspective when the nominations are not obviously nominating the full capacity that’s available in the plant. So 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.
Tom Allen
Okay. But if Origin nominate on a day-ahead basis how long would it take realistically to then have Enterprise up and ready to inject on spot respond arrangement. Is it a matter of weeks, months, days?
Morne Engelbrecht
So it’s immediate effectively. So if the Enterprise well is connected, we can just open a valve in the molecules front.
Operator
Next question comes from the line of Scott Ashton with SHA Energy Consulting.
Scott Ashton
Just quick question, it follows on the back of Nik and Daniel’s question. So 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. So 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 the capital that might be needed to accommodate either increased rates or to build in some extra capacity, so you’re not sub-optimizing the plant. Can you just sort of make a few comments around there?
I just want to understand the strategy.
Morne Engelbrecht
Yes. Look, from a product 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 about 200 terajoules a day if we see the need. Obviously, you’re going to have to reach FID on CapEx and make sure you can get the return on that and that will only be from, say, ’26, ’27 onwards. Again, that will be dependent on whether there’s a market with those volumes to at that point in time and what market you’re putting it to — am I focused Sam, on the Bcf question. Sam, how do you want to answer that?
Scott Ashton
Yes. Like I said earlier, I think we’ve got a lot of prospects in our portfolio. And if you look at the other side of the features, then 500 Bcf is eminently achievable, but there’s also a range around that, which is quite wide.
Scott Ashton
And I suppose we’re sort of going with that is, is that the inflection point or the trigger point for whether you optimize the plan even further to increase rates?
Scott Ashton
Look, it might be. It’s obviously something that we need to discuss and agree with the operator who is mature from a JV perspective. So 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.
Scott Ashton
Okay. And just a very quick question for Anne-Marie. Just so I’ve got this right. So apologies if it’s some already been discussed previously, the AUD 0.48 a barrel knocked abandonment levy. Is that deductible for PRRT purposes and is the Otway and the BassGas stuff paying that at the moment, given it falls within that ’21 to ’29 time frame.
Can you just maybe make a few comments on how that works with your abandonment liabilities and provisions?
Anne-Marie Barbaro
So we’re not currently paying PRRT on any of our assets at the moment in the near future.
Morne Engelbrecht
I don’t think you can get it as a deductible, but less from our point of view, it doesn’t make a difference.
Anne-Marie Barbaro
Not deductible for us.
Operator
Thank you. There are no further questions at this time. I will now hand back to Mr. Engelbrecht for closing comments.
Morne Engelbrecht
Thank you, everybody, for dialing in this morning. Obviously, if you’ve got any further questions, please give Eric or myself a call. Happy to take any questions offline as well. Thank you very much. Cheers.
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