Earnings Transcript for BPT.AX - Q2 Fiscal Year 2022

Morné Engelbrecht: Hello, and welcome, everyone, to the Beach Energy half year results presentation. My name is Morné Engelbrecht, and I'm the Acting Chief Executive Officer of Beach. Joining me on the call today is our Acting Chief Financial Officer, Anne-Marie Barbaro, also joined by some of the Beach executive team. For today's presentation, I will first provide an overview of the current state of play at Beach Energy. And I'll be over to Anne-Marie, who will run through the financials, and then I'll provide an update across our portfolio of assets. Following that, we will open the lines for Q&A. Before I begin, Slide 2 includes our disclaimer, as well as information regarding our reserves disclosure. I will leave this with you to read in your own time. Now, let's move on to the main part of today's presentation. Beach's first half and FY '22 was one that not only delivered against our growth agenda, but also saw the continued execution of our strategy. Beach recorded production of 11 million barrels of oil equivalent in the first half. While this was down 20% on the corresponding first half last year. It's important to note that we now have some of the key building blocks in place beside realizing incremental production volumes over the next year. The Otway gas plant is now in a position to deliver increased production, thanks to the commencement of the Geographe 4 and 5 wells. Further to this, Kupe is again running at its full 77 terajoules a day capacity following the commission of the inlet compressor. On the financial results, our statutory NPAT for the first half was AUD213 million, a 66% increase on the corresponding half in FY '21. We ended the half in a net cash position of AUD74 million with a AUD600 million revolving facility, providing us with strong levels of liquidity. We also made excellent progress towards our base, 28 million barrels of oil equivalent production target in FY '24, the startup of Kupe, the continued drilling of wells in the offshore Otway and the signing of the LNG Heads of Agreement with BP for Waitsia volumes. Given the strong progress we have paid towards our base production target, we are now starting to look at the projects that has enabled Beach to deliver above that target. This includes planning and exploration campaign in the Perth Basin, building a better understanding of the nearshore and offshore potential in the Otway Basin. Investigating near Yolla North and West exploration opportunities in the Bass Basin to complement the potential Trefoil development and planning for a Kupe East development well in the Taranaki Basin to further extend the production plateau for Kupe. Slide 4 speaks for itself. But it's an excellent illustration of the strong financials we enjoy at Beach. Our sales revenue increased 11% to AUD786 million in the half. This led to an EBITDA figure of AUD513 million and a 65% EBITDA-to-revenue margin. I think a key point to highlight is the fact that 37% of our revenues came from fixed CPI-linked gas production. The Board has also maintained a fully franked interim dividend of AUD0.01 per share. Moving to Slide 5, and you can see Beach continues to record strong safety performance, notwithstanding the fact that we are in a period of high activity. We have now recorded more than 5 million work hours without a lost time injury across the business. The company also recorded another milestone in the half with our Otway gas plant reaching 7 years without a recordable injury. Over the first half, we did see an increase in the total recordable injury frequency rate. While most of these incidents represent relatively minor injuries. We are addressing this through a series of targeted safety campaigns in the second half. Moving to Slide 6. I just want to quickly give you all a reminder of what we outlined in our Investor Day, September last year. The takeaways from this were a base business production growth target of 28 million barrels of oil equivalent in FY '24, simplifying the balance sheet to support this target with only low levels of gearing reach, the delivery of material steady cash flows from 8 gas plants across 4 markets. With this material free cash flow generation providing optionality and our continued commitment to sustainability with our aspiration to be net zero by 2050. I'm proud to say, Beach's first half saw a very strong period of delivery towards these ambitions. We effectively had a checklist of things we needed to achieve in a very active half, and we successfully ticked up every box. As mentioned, we brought the Kupe inlet compression project online in September, which has seen the Kupe gas plant returned to its full capacity. In Victorian Otway Basin, we delivered the first volumes from our Otway offshore development campaign. The Geographe 4 and 5 wells were drilled, enacted and commissioned with gas now being delivered into the East Coast gas market. We also commenced the final phase of the offshore drilling program, successfully drilling the Thylacine North 1 well in line with pre-drill expectations. In the West, we commenced construction at Waitsia Stage 2, with the project on track and site works are now 42% complete. We also reached an historic milestone by signing a Heads of Agreement with BP for all of Beach's 3.75 million tonnes of LNG from the project. Finally, we sanctioned the Moomba carbon capture and storage project, a joint venture partner and operator, Santos. We had a lot of heavy lifting in the first half. However, some key objectives remain as we look to close out the year. We still have 3 remaining offshore wells to draw into the Thylacine field. Putting us currently underway at Thylacine West 1, and we are on track to complete drilling campaign around the middle of the calendar year. In the coming months, we will take the final investment decision for the Enterprise onshore pipeline project. This is a low-risk project that ties in the 2020 Enterprise discovery of the Otway gas plant. In the Perth Basin, construction activity will continue at Waitsia Stage 2 with our focus also now including the development drilling campaign. With our operator Mitsui, we intend to drill a minimum of 5 gas development wells targeting the Kingia and High Cliff sandstone formations. Finally, in the coming weeks, we'll recommence our oil exploration program in the Western Flank, with a drilling program of at least 11 wells. It's important to remember that success from any of these wells is not factored into our base production growth target and our guidance. So any discoveries would help deliver upside. On the sustainability front, the key achievement in the half was the sanctioning of the Moomba carbon capture and storage project with our JV participant and operator, Santos. This project forms a key pillar of our aspiration to reach net zero emissions by 2050. By far the biggest investment we have made to date to reduce our operational carbon footprint and will deliver the step change in Beach's CO2 emissions profile. Santos this month booked 100 million tonnes of CO2 storage resource in the Cooper Basin in South Australia. As you are aware, Beach's reserves and resources process occurs at 30 June each year. We're currently working through that process, and we'll consider the Moomba CCS project to better with all our other reserves and resources projects in preparation for the report in August. Slide 9 provides our unchanged FY '22 guidance. We have maintained our FY '22 guidance range of 21 million to 23 million barrels of oil equivalent. Guidance is maintained based on the fact that we are outperforming our annualized decline rate of 35% to 45% in the Western Flank as development wells come online. We've also connected to Geographe wells, albeit production is subject to customer nominations. This is offset by the lower-than-nonoperated production performance in the Cooper Basin JV we experienced in the first half. Capital expenditure guidance between AUD900 million and AUD1.1 billion. Our barrel -- our per barrel guidance for unit field operating costs and unit DD&A guidance are also unchanged. With that, I'll hand over to Anne-Marie, who will run through the financial results.

Anne-Marie Barbaro: Thanks, Morné. Good morning, everyone, and thank you again for joining us today. My name is Anne-Marie, and I've been with the company for 3 years, most recently as General Manager of Finance. I was elevated to the role of Acting CFO in November last year. I have the pleasure of speaking to you today to provide an update on a very positive set of financial highlights. Turning to Slide 11, and as Morné has already highlighted, Beach announced a reported net profit after tax of AUD213 million for the first half of FY '22, up 66% on the same half last year. Our EBITDA of AUD513 million reflects a 26% increase on the corresponding half. Cash from operations jumped 105% to AUD605 million with stable cash flows from our fixed price CPI-linked gas business, which alone excluding associated liquids, delivered approximately 37% of our Group revenue. We also announced an interim dividend of AUD0.01 per share fully franked. Slide 12 highlights our NPAT in comparison to the first half of FY '21. The 11% rise in revenue during the first half was primarily driven by a 75% increase in realized oil price. Reduced tariffs and tolls and depreciation are the result of lower production volumes. This was partially offset by a 40% increase in royalties and third-party purchases, driven primarily by increased commodity prices and a 6% increase in field operating costs following FY '21 after acquisitions. Slide 13 highlights our strong cash position with total cash of AUD213 million at the end of the half. As mentioned earlier, operating cash flow of AUD605 million was up 105% on the corresponding half. This cash flow included AUD29 million of income tax paid and a AUD42 million receipt for settlement of Kupe carbon tax arbitration. Our free cash flow pre-major growth investment was AUD329 million. Turning to Slide 14, and you can see our balance sheet continues to be extremely strong with a net cash position of AUD73 million at the end of the half. Our total liquidity stands at AUD673 million, the result of a successful refinancing of our debt facility to AUD600 million with favorable terms and margins. This means we are well positioned to fund our future growth strategy, including the committed capital towards the offshore Otway drilling and Waitsia Stage 2 development. This is reinforced by the fact we expect our net gearing to remain below 10% despite a capital-intensive FY '22 work program. Before I hand back to Morné, I'd like to quickly highlight, we expect to be a beneficiary of the federal government's economic recovery initiative, allowing businesses to immediately deduct eligible capital assets. At this stage, we estimate this will have a AUD200 million to AUD300 million positive impact on operational cash flows over the next 3 financial years. This remains unchanged from our estimate discussed at Investor Day in September. This will ensure we're in good shape to pursue growth above our previously stated base production target of 28 MMboe in FY '24.With that, I would like to hand back to Morné to run through our markets and operating assets.

Morné Engelbrecht: Thank you, Anne-Marie. I'll just quickly run through the current gas market dynamics we are seeing before jumping into our assets portfolio. On Slide 16, you will see the Beach's geographical diversity and market distribution is across 3 gas markets, the fourth to be added soon. Australian East Coast gas market, the Australian West Coast gas markets, New Zealand domestic market, as I said, soon to be the global LNG markets. The 4 incredibly robust markets where gas is desperately needed. Australian energy market operator continues to see gas shortfalls within the East Coast gas market, almost early as next year's winter. While the ACCC believes the shortfall could come this year. On the West Coast, AEMO's latest outlook says there could be a potential domestic supply gap from around 2025. We are already seeing the LNG supply tightness forecast between 2022 and 2025 starting to rear its head with no new greenfield LNG supply anticipated until post 2025. Our strategy has long been about delivering gas into the right markets at the right time, and we feel our portfolio is perfectly positioned to achieve just that. On Slide 17, we start with the Otway Basin, which is undergoing its biggest year of activity part of the development campaign in FY '22. As previously mentioned, the first half saw Beach connect the Geographe 4 and 5 wells to the Otway gas plant. Both wells are now producing East Coast gas market and represent the first new volumes from the offshore development campaign. Beach also drilled the first of the Thylacine wells, Thylacine North 1. This well was successfully drilled and intercept that the reservoir in line with pre-drill expectations. The Ocean Onyx is currently drilling the Thylacine West 1 well before finishing off the campaign in the middle of this year with the Thylacine West 2 and Thylacine North 2 wells. The 4 files wells will be connected back to the Otway gas plants in the second half of FY '23.From an onshore perspective, we expect to take FID on the low-risk enterprise pipeline project in the coming months as we look to tie that discovery back to the Otway gas plant also in the latter part of FY '23. From an operational perspective, it was an excellent first half at the Otway gas plant, and we should operate at 99.9% reliability. Moving to Slide 18, and this is an important slide because it helps explain the intricacies of our gas production and sales from the Otway gas plant. It would be understandable to assume that the combination of high reliability plant and the connection of Geographe 4 and 5, we see daily productions of between 160 to 180 terajoules per day. However, this is not necessarily the case. It's dependent on customer nominations. Current CPI-linked take-or-pay gas sales agreements have considerable flexibility for the customers to nominate. This means there will be daily production volatility. I've been looking through Beach Otway gas plant production, important to remember that it isn't a reflection of Beach's well capacity or plant reliability, and also the daily nomination arrangements, which are largely set by the customer. Nonetheless, because of the take-or-pay arrangements, the annual volumes going through the plant will be balanced by the end of each calendar year. It's important to remember, Beach has the right to market volumes for better and new discoveries, including Enterprise and Artisan independently of the existing gas sales agreements and their nomination rules. This process is currently underway for our Enterprise volumes, which we are targeting to tie in to enable additional optionality and increase the utilization of the Otway gas plant. As you can see from the chart, Beach will reach the 205 terajoules a day of capacity at the Otway gas plant once the Thylacine wells are connected. We have a base on the GSAs, there will be periods where the plant isn't at full utilization. On Slide 19, we turn to the Perth Basin, which is the second of our major growth basins. Similar to the Otway Basin, the Perth Basin saw a hype of activity in the first half of FY '22. Construction commenced at Waitsia Stage 2 gas plant. As of 31 December, construction was 42% complete. The first half also saw Beach sign in its first-ever LNG Heads of Agreement with BP for Beach's 3.75 million tonnes from Waitsia Stage 2. Waitsia JV has also secured Easternwell rig to draw the upcoming Perth Basin development drilling campaign. Also of note was the fact that the Beharra Springs facility returned to near full capacity in mid-November, following the successful rectification of the CO2 membrane issues. In the coming weeks, drilling will commence at the first of minimum 5 gas development wells at Waitsia, targeting the Kingia and High Cliff sandstone formations. This development drilling program is scheduled to span 12 months from Q1 2022 to Q1 2023. At Waitsia Stage 2, development of offsite fabrication will continue while the site construction will progress in earnest as we look to have the plant online in the second half of 2023. Drilling our potential for domestic gas shortages in the Western Australian market in the near- to medium-term, Beach will progress further development and exploration drilling opportunities in surrounding acreage with a view of leveraging the recently secured rig.Moving to Slide 20, and we turn our attention to the Western Flank. The first half saw us [rest] some of the production declines in our oil acreage. In addition, we drilled 4 horizontal oil development wells at 100% success rate with a fifth drilling ahead. On the exploration front, we experienced a 33% success rate from our gas drilling program in ex PEL106 with successes at Rosebay 1 and Lowry South 1. Over the [media] action happens in the second half, as we will soon commence the oil exploration campaign. We'll drill 3 appraisal wells on the ex PEL 104 Martlet oil field before kicking off the well exploration campaign of 11 well exploration wells with additional wells planned after an assessment of the results. Important to reiterate, Beach has factored in no exploration success in the Western Flank as part of the base business production target. Any success would deliver additional production. We look forward to updating you on the results of that campaign in due course. Turning to Cooper Basin, and looking at the Cooper Basin JV on Slide 21. Our strategy remains to pursue high-value and low-risk opportunities. To that end, Beach participated in 32 wells, an overall success rate of 88% in the first half. Our first half production of 3.7 million barrels of oil equivalent was down 13% on the corresponding half, due to unplanned downtime at Moomba, and upstream operations, as well as some planned maintenance at Moomba and natural fuel decline. Beach will continue to work with operator Santos to ensure we maximize production from those facilities. Beach plans to participate in 35 to 40 wells in the second half. On Slide 22, we started to turn our attention projects where we believe we can start to deliver upside to our base growth targets. In the Bass Basin, the first halves will be to reprocess seismic data. And in doing so, we identified new exploration opportunities, Yolla West and Yolla North. These prospects could be developed with jack-up rigs on the Yolla platform and deliver increased and extended production through the Lang Lang gas plant. This is something we look to progress in the coming months with a view to potentially commence drilling these prospects at FY '23 subject to approvals. In addition to the production boost, these wells could provide, they would also deliver a level of flexibility around the timing of the Trefoil project in the event that the project, which is currently in feed is sanctioned. To that end, we acquired the Prion 3D seismic in the first half with the data now being processed to support a potential FID for the Trefoil development and quantify the potential of the nearby White Ibis and Bass prospects. Moving across the attachment to New Zealand, and on Slide 23, we turn our attention to the Taranaki Basin. As previously mentioned, in the first half, we brought the Kupe inlet compression project online, the first gas introduced into the plant 2 weeks ahead of schedule. As a result, the plant throughput returned to the full 77 TJs a day, capacity and plateau production rates are expected from the Kupe field through FY '23. This figure has been updated slightly to reflect data coming through since the completion of the compression project. In a similar vein to our Bass gas assets, we are now assessing options to extend plateau production at the Kupe gas plant to deliver upside on our base production target. As such, we continue to assess a potential development well, Kupe East, which could be drilled from the existing Kupe platform. Drilling up that well is being considered for FY '23, again, subject to approvals and rig availability. In closing out today's presentation, I want to hone in on a few key points. Our growth program is on track with several key deliverables towards the 28 million barrels of oil equivalent target achieved to date. Our flow is first gas from the Otway offshore wells and the fact that Kupe is again running at 77 TJs day capacity. However, we know the job is far from done. And then in the second half, we are still focused on delivering key milestones towards our growth target. This includes drilling the remaining 3 wells in the offshore Otway campaign by the middle of this year, reaching FID on the Enterprise pipeline project, commencing our development drilling for the Waitsia Stage 2 project and signing the agreement with BP for Beach's 3.7 million tonnes of LNG from Waitsia. Second half will also see us refining our focus on projects that have the potential to deliver production above our stated growth targets. This include the Western Flank well exploration campaign to which any discoveries sit above our base case target, progressing our plans in the Perth Basin to conduct an exploration campaign at the conclusion of the Waitsia development drilling program, our understanding the nearshore potential of the Otway Basin following our success at the Enterprise, executing the Yolla in-field program to extend the life of Yolla, [progress] FEED on Trefoil, and finalize plans to drill the Kupe East development well in Taranaki Basin to extend plateau at Kupe. These first 3 points are supported by our final takeaway, which is the continued strength of our balance sheet. We retained a net cash position of AUD73 million with liquidity of AUD673 million. This provides us with significant flexibility to execute and expand our growth opportunities among other capital management options. With that, I'll hand back to the operator for the Q&A session. Thanks, operator.

Operator: [Operator Instructions] The first question comes from the line of Daniel Levy from Citi.

Daniel Levy: Couple of quick ones for me. Can we please get an update on how CapEx is tracking in the Otway, just given it's a big component of your market cap? Is there anything left in the contingency for that project?

Morné Engelbrecht: Daniel, thanks for the question. I mean, in terms of CapEx, we've maintained our CapEx guidance for FY '22. Obviously, the Otway offshore plays a big part in that guidance. We don't see any creep in terms of the CapEx from our Otway offshore point of view, and it's still within the range that we previously spoke about at the September Investor Day, which is around the AUD1.1 billion to AUD1.3 billion gross. There's no change to any of that. And as you would expect, we do have contingency in place for a project of this size.

Daniel Levy: So just in terms of operationally, has the weather been a bit friendlier in this half in terms of executing the drilling on those wells?

Morné Engelbrecht: Yes, no, definitely. So the weather has definitely been kind to us over the last 2 or 3 months. And that's been reflected in the drilling performance we've seen on the Thylacine wells to date. So, we're pleasing to see the drilling performance there, and well done to the team there.

Daniel Levy: And then just another quick one. We've seen some of your peers start to ramp-up their hedging for this year and next year. Can we expect anything from -- like that from you guys given out healthy futures pricing at the moment? I think at the quarterly result, you said you had 0 hedging in place?

Morné Engelbrecht: Yes. Look, Daniel, it's something we do assess on an ongoing basis. I think from our perspective, we obviously got a great balance sheet. So we don't need to do it from a balance sheet point of view. We've got a great set of assets in terms of our gas portfolio. So most of our gas is sold into fixed-price and CPI-linked contracts. So from that perspective, we don't see an immediate need to do any hedging. Obviously, with going forward and seeing how things sort of play out, that might change over time. But for the moment, we're very comfortable in terms of being unhedged. So I don't know, that's probably -- hopefully that answers your question, Daniel?

Daniel Levy: Yes. It does. And sorry, I'll just sneak one more quick one in there. I noticed the quarterly you were drilling the Beanbush [degaussing] gas wells. I didn't see any kind of more news on that in this result. Can you give me a bit of an update on that exploration program?

Morné Engelbrecht: Do you want to go for it, Sam? We got Sam here as well.

Sam Algar: Yes. [indiscernible] for Exploration and Subsurface. That's a well operated by Santos. So I think it's appropriate for them to comment on that particular operation.

Operator: The next question comes from James Redfern from Bank of America.

James Redfern: Just 2 questions, please. I was just maybe wondering if you could please talk a bit more about the -- about when we might have an announcement around the appointment of a CEO, or obviously, Morné, you're the Acting CEO at the moment. Just wondering if you can please talk to how that search is going for, both domestically and internationally. And when we might get an announcement on that? And then I just got one more question after that, please.

Morné Engelbrecht: James, thanks for the question. Obviously, the CEO search has been conducted by the Board. So the Board is conducting a thorough search process. As you said, domestically, internationally to find the best possible candidate for the role. I think it's fair to say that the Board will go through a thorough process and there's no fixed timing in terms of announcing a possible candidate for the role. I think I'll leave it with at that point. And obviously, the Board is working, like I said, very diligently and conducting that search. So, I'll probably leave it at that, but there's no rush in terms of any timing from that perspective. Obviously, the Board want to make sure that they put the best possible candidate in the role.

James Redfern: Okay. And then the second question which is really around the Perth Basin, just in terms of the Waitsia project, the border closures and so on and cost inflation in Western Australia. I just want to confirm that there's no changes or no concerns to the, I guess, the CapEx guidance for Waitsia Stage 2 and then also, I guess, the timeline for that project, please?

Morné Engelbrecht: Look, James, from -- like all other industries in terms of COVID, we are dealing with, obviously, getting people in and out of WA and assisting the operator there in terms of [indiscernible], in terms of dealing with that. We haven't seen any material impacts to that operation and the project and any of our other operations as well. So the team is working diligently to make sure that we can get people there in an efficient and safe manner as well. From a capital perspective, we haven't seen any major capital inflation in terms of that project. As you would know that most of the project there and maybe Thomas is on the line, he can speak to that more broadly. In terms of the [club] contract, that represents about 60% of the overall capital program, which is based on a fixed price turnkey sort of contract. But in terms of the capital inflation, we're not seeing that playing out at the moment. And then in terms of timing, we still hold the timing in terms of what we've said to the market previously, which is the second half of 2023 in terms of first LNG from that project. Thomas, if you're on the line, do you want to expand on the cost side of things?

Thomas Nador: Yes, I can. Look, the only comment I would add to what you said, Morné is that, something like 70% of the project is Australian content. So that significantly helps mitigate potential COVID-19-related supply constraints. And secondly, it is a lump sum Turkey contract that was designed, negotiated and executed during the height of COVIC. So both [ plus ] the EPC contractor, as well as the Mitsui Beach joint venture have allowed both allowances and contingency to help safeguard and protect that AUD700 million to AUD800 million gross guidance CapEx number that we've put in the market.

Operator: The next question comes from Tom Allen from UBS.

Tom Allen: Just a quick question first thing on Western Flank oil. So with decline rates outperforming your expectations and guidance range, can you just talk to any change in your technical approach to reservoir modeling that you might apply on that asset going forward just to help build confidence and what the resource will produce in the coming years?

Morné Engelbrecht: I might throw it to Sam on that question.

Sam Algar: Yes, sure. So, the commentary there relates to 2 things, really. Firstly, we have undertaken a reservoir pressure maintenance strategy for the Bauer Field, which has shown some really positive results. So, production in Bauer is flattening out, it's declined quite materially. And the second thing, obviously, is that, we have -- we've drilled 5 development wells in the Western Flank, and we're looking forward to the production on those wells will deliver to us in the second half of the year.

Tom Allen: And Morné, can you please just elaborate on a little bit more on your capital management options going forward?

Morné Engelbrecht: Yes, look, I mean, that's a continue discussion with the Board as well in terms of our capital management framework and how we think about it. Obviously, from where we sit right now in terms of our capital program, we're spending AUD1 billion this year and AUD1 billion next year, which, as you would expect, is quite a big capital program in terms of our market cap, so it represents 2/3 of our market cap currently. So we want to make sure that we can deliver on those projects over the next year or 2. And obviously, complete the offshore program, drilling program as well over the next 6 to 12 months. So we want to drive completion of those and then look at how things pan out over the next 12 months to reassess how we think about our capital management options. I mean, some of those might include the usual suspects in terms of looking at our dividend policy and framework or other capital management initiatives that might come up. We're not discounting any of those right now, but we need to get through our heavy investment in our offshore project in Waitsia in particular before reassessing that. We feel very comfortable with our balance sheet at the moment and that that can support our growth profile going forward. Yes. So it's a continued discussion and assessment as we go through the program.

Operator: The next question comes from Mark Samter from MST Marquee.

Mark Samter: A couple of questions, if I can. Morné, I appreciate some of this will be commercially sensitive, but it seems to be causing such a big deviation in natural production versus capacity. Can you give us any guidelines on what the lower end of the nomination range origin can exercise? Because, obviously, it's a contract that they've been pretty public but they thought was expensive versus what else they can procure gas at and you're heading into another arbitration or maybe the [Otway] arbitration sorry, price review, which might have an arbitration next year, perhaps you have a bit of power overview into that. How low can production go if this gas isn't favor revise for Origin?

Morné Engelbrecht: Mark, thanks for the questions. I mean, first of all, obviously, as you would know that's commercial sensitive information, so we can't disclose any of that information. What we can say is that, those provisions obviously apply for the calendar year. And as we said, nominations can vary on a daily basis. So they are flexible, and that's reflective in the prices, obviously, as well. As you note, that those specific contracts are coming up for renegotiation 1 July 2023. So we probably review those prices and start negotiations in the second half of this calendar year. Apart from that, normally, historically, as you would know, from a seasonal perspective, we're seeing low nominations in the summer months and higher nominations in the winter months. So we'll see whether that plays out this year as well.

Mark Samter: Okay. Yes. I try and ask the question another way. The year-to-date, obviously, since the wells happening tied in actual production has only been I think it's just over 70 TJs a day. Would that level be sustainable for the whole year or that best seasonality in the numbers that have allowed that at this time of the year versus being able to sustain that through the whole course of year?

Morné Engelbrecht: Yes. Again, it's dependent on nomination seasonality. We did see, as you would have seen as well, Mark, in the back end of December is quite high nominations during that time. And then in January, it's been very variable in terms of the nominations that we've seen. So, I'm not sure how that's going to play out in terms of the rest of the year. But as I said, we've got those take-or-pay provisions to protect our revenue for the calendar year and then we depended on our nominations from a seasonal perspective.

Mark Samter: Okay. And then next question, if I can. Just the AUD13.6 million of the completion adjustment on acquisitions. Am I right in thinking that's just the payment from Mitsui to take BassGas and Trefoil off their hands? And in the context of that, I noticed any reference to an FID in the second half of this calendar has been removed from Trefoil and on a go-forward basis, Mitsui are willing to pay you to take these assets off their hands. Can we infer from the removal of the comment about FID that that project might have more challenges than you first thought and you're not as committed to an FID as you were 6 months ago?

Morné Engelbrecht: Mark, on your first question in terms of the completion adjustment, yes, it mainly relate to the adjustment on the BassGas assets. And then the second answer to your question in terms of FID, we did our plan in the presentation today that we are progressing through FEED there. Obviously, a lot of information and data available through the 3D seismic we recently acquired as well. So we're looking at how that could impact and further inform a potential FID on the project. So we're definitely moving ahead and considering Trefoil and getting to an FID stage. As we've also outlined, there has been 2 exploration prospects we do want to have a serious look at in terms of Yolla North and West. So we're assessing that at the same time.So, the other thing that's playing into the timing for Trefoil would be the successful wireline we just competed as well. So you would have seen Yolla 6, we've outed about 5 terajoules a day, and then Stage 2 of that wireline campaign on Yolla 4 and 5 in this quarter. So, all those things combined will provide us with the information to make an assessment on FID and Trefoil, but also an assessment on Yolla North and West.

Mark Samter: Yes. Okay. And just from a reserve booking perspective, obviously, unfortunately, you guys already carry Trefoil and booked 2P. I guess, what you're going through FEED, they can stand through at this end of year reserve statement, you'd have to proactively decide not to take FID to have to write down the reserves?

Morné Engelbrecht: Look, we haven't said we're not taking FID. We're saying we're going through the FEED, and we will assess all the information to FEED into an possible FID for Trefoil. So, obviously, that will come in the first half of FY '23 in terms of that assessment. And that will be flowing into the reserve process as well, that will flow through in August of this year as well. So, I don't want to preempt any of those. As I said, we're moving through the FEED, and we're gathering all the information that will inform a possible FID for Trefoil.

Operator: The next question comes from Dale Koenders from Barrenjoey.

Dale Koenders: Two quick questions, firstly on Otway gas plant. I was just wondering if there's any thoughts towards increasing capacity at the plant or removing the downward nominations through contracts or potentially using storage to increase production?

Morné Engelbrecht: Yes. Look, thanks for the question, Dale. So, we just -- in terms of looking at the Otway offshore, obviously, we're focused on delivering those Thylacine wells, focused on delivering the Enterprise, FID and connecting the Enterprise well up to the plant. Further to that, we feel comfortable with the plant capacity at the moment in terms of getting that to nameplate and then being able to utilize some of the capacity there to deal with the further utilization of the plant more so than extending the plant capacity. So we do feel comfortable with the current plant capacity and obviously, the [lofty] asset there and the ability to manage that going forward with the Enterprise coming in.

Dale Koenders: Okay. And then just quickly on Waitsia. I know you're still at finalizing the SPA with BP. Just wondering how we should be thinking about sort of contract pricing. Is it set based on where terms were 6 months ago when LNG contracts are being signed with [indiscernible] to 12 or if there's scope to given the run that's happening in the LNG markets, short-term contracts now being signed in 13s and 14s, is there -- will you benefit from that upside?

Morné Engelbrecht: Look, it was done at the time we announced it and those terms and conditions agreed in the Heads of Agreement will be the terms and conditions that will be in the SPA as well. What we can say is, obviously, that we have -- we're still very happy with the contract that we have with BP there. It is reflective of the current market. And we feel very comfortable in terms of, as we said before, it's got the protection to the downside there and it provides us upside in terms of during the [North Asian] winters as well with a link to JKM and Brent. So, overall, in terms of the contract we have there, we're very happy where we are at.

Operator: The next question comes from Adam Martin from Morgan Stanley.

Adam Martin: Just back on Trefoil. Can you just remind us what the Trefoil reserves are? And what potential size is Yolla West and North might be? And I think you previously told that FY '25 is first production to [indiscernible] so when would you sort of need to hit FEED or sorry, FID to hit that milestone, please?

Morné Engelbrecht: Adam, I might refer to...

Sam Algar: On the Yolla West and Yolla North, we don't typically reference any prospective resource size on that. And we're obviously looking through that. And in regards to the reserve, I refer you to a previous disclosure of that last year.

Morné Engelbrecht: So happy to take that up in terms of the Trefoil reserves after the call as well, Adam. In terms of the specific timing, as I said, we're going through the FEED, looking to -- if we reach FID, reset within FY '23. So in terms of the timing, in terms of FY '25, that's still very much the plan in terms of reaching FID.

Adam Martin: Okay. So it's still possible to get '23. All right. And question -- just sort of a volume question that, just comment about maintenance at Port Bonython Q4 FY '22. Can [Technical Difficulty] how long is that going [Technical Difficulty] an impact on that [Technical Difficulty] in place?

Morné Engelbrecht: Yes. We don't see any impact and Santos indicated no impact in terms of production. So I'll use the current [indiscernible] storage to make sure that production is not impacted from that specific facility.

Operator: Next question comes from Gordon Ramsay from RBC Capital Markets.

Gordon Ramsay: Just a comment on the Bauer pressure maintenance. Is that water flooding? I just understood on what you're doing to that field to maintain pressure.

Sam Algar: Yes. So we have a number of water producers. And what we've been doing is modifying the way that that water interacts with oil production just to increase our water -- sorry, our oil production. So we've actually been increasing water production to draw that water away from those oil producers, which has had a very strong impact upon the net oil production.

Gordon Ramsay: And speaking of water, we've had some extreme weather events in Central Australia. I imagine there's some flooding in the Cooper Basin at the moment. Is that expected to have any impact on operations, let's say, in the March quarter?

Morné Engelbrecht: Look, we -- I mean, as you would expect, there was some impact to our drilling operations there, not only in the Western Flank, but also in the Kupe Basin JV, which the teams have been working around. So, we definitely focused on getting that back online as soon as possible and going after the various connections that we need to make and that we're currently busy with. We have some impact, but it's minor, and we're working to make that back within the quarter.

Gordon Ramsay: And just last question for me. Just on the Perth Basin. You previously indicated potential for 3 to 6 exploration wells. I noticed there's no comment on the number in this result. Should [indiscernible] gas discovery, will that impact that program? And you can -- can you please confirm you're still looking at 3 to 6 exploration wells potentially after the 5 development wells on Waitsia?

Morné Engelbrecht: Yes. Look, in terms of the success or not success of Western South [indiscernible], it doesn't really impact our view in terms of our exploration acreage and the prospects we see there. So we're definitely looking at the 3 to 6 exploration wells there. Obviously, that's subject to us confirming and discussing that with Mitsui as well, our joint venture partner there to confirm as well, but definitely on the cards.

Operator: The next question comes from Saul Kavonic from Credit Suisse.

Saul Kavonic: Just a couple of quick questions on production, if I may. The first one is just coming back to the chart of Otway production. You put out there kind of the dark blue showing the seasonal variance there. Can you just confirm if I was to take that average from kind of that chart across the year of 2022 and 2023, that that's a really firm number on the average? Or is there a scope that we can see downside to that if Origin choose lower nomination levels?

Morné Engelbrecht: Look, that's probably not a bad way to look at it, Saul. But in terms of the actual backup plan, as I said, we're not going to confirm that. And there's obviously the seasonality on it as well. So there's obviously the variability and the flexibility that they do have in the contracts, and that's obviously affected in the price. And as we said, going into winter, that's normally the higher nomination period in a specific calendar year. So that's probably as much as I can say on all that.

Saul Kavonic: So my second question then is about Enterprise tie-in in the second half of FY '23. And the mentioned in the presentation that should enable greater stability and greater to use capacity in the plants. Could you just provide perhaps some more color exactly on how that works? So other independent GSAs from Enterprise going to enable you, for example, to sell just more gas in those off-peak lower nomination periods? Or is that additional stability only going to come from those proportion of volumes that are Enterprise and the rest of it is still going to have these huge swings depending on Origin's nominations, if that makes sense?

Morné Engelbrecht: Yes. Look, I mean, we see how that's playing out is obviously using the Enterprise volumes to come into the market when those nominations are lower. So to make sure we can use the full capacity that's available in the Otway gas plant during those times. So, in terms of working out of GSA on the Enterprise, that will be reflected in that GSA in terms of that optionality.

Saul Kavonic: Should we -- is there an implication there that those Enterprise volumes could therefore achieve an overall lower price because they're only going in when nominations are lower?

Morné Engelbrecht: I mean, we haven't finalized the contracting on those volumes yet. So I don't want to preempt anything. Obviously, as you know, Saul, in the current market and where we see shortages coming, I can't see that we won't get market price for our gas irrespective of nominations.

Saul Kavonic: Great. And my last question is, I guess, on more on that midterm outlook. With production guidance essentially being maintained for the year. My quick math implies that, that means production must tick up, at least from the next quarter. Can you confirm, is Beach finally moving back towards a production -- an increase in production trajectory beginning from later in this financial year, and we should see that kind of increase on average for the next 3 or 4 years?

Morné Engelbrecht: Look, I think in terms of the Geographe 4 and 5 wells being online, obviously, again, it depends on nominations. If you look at historic performance and nominations around the Otway gas plant, we do expect an uptick in terms of production there. The thing I would notice, obviously, from a shutdown point of view, we do have the shutdown plan for Bass or the Yolla, the Lang Lang facility. So, it will be about 3 weeks, that will happen in the March quarter as well. We should see that having an impact. And obviously, we want to see how the development wells from a Western Flank play as well during that period. So, I think it will be a miss of me to say that we will see an increase. Obviously, the -- we try to remain prudent in terms of our production guidance on that front, and we want to see how that plays out over the next quarter before putting a stamp on it.

Operator: The next question comes from Nik Burns from Jarden Australia.

Nik Burns: Looking ahead of what's shaping up to be a very active FY '23 from a drill bit perspective, I think you've got wells planned now in the Perth Basin. You got Bass, Cooper and now the Taranaki Basin. Just probably the one basin you haven't got in there at the moment is Otway. You've got 3 wells to go there. Just wondering what -- if you can explain what happens to the rig after these wells? Is there any temptation to keep it on to drill additional exploration wells in the Otway, given the number of prospects you have there and the flexibility adds to your sales volumes to the plant and the expected tightness in the East Coast gas market?

Morné Engelbrecht: Yes, no, it's obviously a consideration that we need to think about in terms of the rig. Obviously, as you know, mobilizing these offshore rigs and getting the right rig for the offshore program is challenging. So, I don't want to make any predictions or forecasts on any of that, but our focus is on delivering the current Thylacine wells. And as I said before, we're working our way through understanding better the onshore and offshore prospects there and looking at that more broadly and how we could further develop the offshore point of view as well, but also looking more specifically at the nearshore opportunities that's presented there. So I think both nearshore and offshore, we'll look at them and make a decision on in the coming 12 months. But for now, we are definitely focused on delivering those Thylacine wells.

Nik Burns: Got it. And just on the Perth Basin, you've talked about Waitsia development drilling, minimum of 5 development wells. Just wondering what would flex that 5 well number higher? Is it the results from the drilling? And just maybe a bit more color around how long that campaign is due to take? I'm assuming that same rig will then move on to the proposed 3 to 6 development and exploration well campaign in your other Perth Basin permit?

Morné Engelbrecht: I might throw that to Sam. Sam, do you want to go?

Sam Algar: Yes, we're in discussions with Mitsui, the operator on the appropriate number and location of the wells. And so, as is normal with any development. And so, we're looking at whether it's 5, whether it's 6 and the timing of those, the overall development of the field requires more wells than that. And so, it's a key consideration as to when it makes sense to drill those, which can be related to their exact position. And then in regards to the exploration and additional development drilling, yes, that would follow on after those developed wells.

Nik Burns: And in terms of that campaign, I mean, you've got the exploration and development, I'm assuming development is around the Beharra Springs deep. But in terms of market for that gas and when you've been in a position to outline our plans for your exploration wells as well. When can we expect an update on that, please?

Morné Engelbrecht: Yes. Look, I think we -- as we said, we're focused on development wells, so that will take us the next 12 months to complete those. So during that period of time, we'll get to an agreement with Mitsui on the exploration potential and the wells we want to drill in the sequence of those wells. We want to go after the locations. So we'll come back to the market in due course once we sort all that out, which will be in the next 6 to 12 months.

Operator: The next question comes from Jon Bishop from Euroz Hartleys.

Jon Bishop: Just around the plant capacity there in the Otway. Can you remind me what limits your ability to sell additional volume into the spot market? Is the Origin gas sales agreement is predicated on a reserve number? I guess, where I'm getting to is, you obviously got a reasonable amount of growing capacity now, spot market looks to be reasonably firm. What are your limits there?

Morné Engelbrecht: Yes. Look, we've got, obviously, the limits that exist within the various contracts. Obviously, we don't want to -- indeed in terms of the volumes that go to the GSAs, they are spoken for. So we do have limited capability and ability to put gas into the spot market from that perspective. The Enterprise well, as we've spoken about and the capacity that will be generated from that will obviously help us in that regard.

Jon Bishop: Okay. And then with your other volumes discovered there, particularly Black Watch and Halladale and also Artisan. What's your thinking around bringing that gas to market sooner rather than later?

Morné Engelbrecht: Yes. Look, we -- Jon, we're sort of looking at that from a sequencing point of view. So we're looking at, obviously, connecting our Thylacine wells in FY '23. And then looking at Enterprise and depending on how that looks from a production point of view, with [NSS] where the other wells might come into the plant and where that makes sense from a timing perspective. So at the moment, in terms of what we can see going forward, we've got the Thylacine and an Enterprise coming up. And then during that time, we'll make an assessment on where we land on the other wells and the timing of the connections of those.

Jon Bishop: Okay. And then just finally on the Perth Basin, a couple of questions on the exploration plans there. Are you able to sort of comment as to what Beach is thinking about in a success case as to where you would take those volumes?

Morné Engelbrecht: Yes. Look, I think in terms of the Perth Basin, currently, as you would know, the market is on the up. We see spot pricing touching about AUD5.5 a gigajoule in WA. There are more demand being created from specifically the resources side of things and petrochemical and other avenues like ammonia and hydrogen as well. So we do see as being commentated more broadly in the market, shortages in terms of gas supply there from 2025. But we do see those volumes potentially flowing into the domestic gas market there. And obviously, the [indiscernible] in Northwest Shelf is ever increasing as well. So, obviously, subject to further approvals by WA government, but that might be navigating to extend that in time as well.

Jon Bishop: Okay. And just a quick one then just around Mitsui. I did think I saw in the press recently, the Mitsui were investigating their own sort of mid- to downstream Midwest development concept around Gorgon or the like. Is that something that you'd be working with them? Or will you guys take that separate?

Morné Engelbrecht: Look, I mean, that's for, obviously, Mitsui and them to consider in terms of their plans in WA. Obviously, we focused on Waitsia and Beharra Springs. If it makes sense then we do partner with them on those, then we'll do so. But there's nothing on the cards just yet.

Operator: The next question comes from Mark Wiseman from Macquarie.

Mark Wiseman: Thanks for the update today. I just had another question on the Otway. Just on the Enterprise well, you've previously sort of talked about more than 50% IRRs. And I understand what you're saying that Origin's got a lot of optionality on the 205 terajoules per day. When you've done the economics on Enterprise, is that based on a sort of interruptible contract we're only selling for 6 or 9 months of the year? Or is it -- have you modeled that on a baseload basis?

Morné Engelbrecht: Look, I might throw that to Lee. Lee is also in the room here.

Lee Marshall: Can you hear me that?

Mark Wiseman: Yes.

Lee Marshall: Yes, I think as Morné said before, it's premature to assume that we will get a material discount to the market price, even if there's flexibility in the volume profile there. So on that basis, the level of economics we've done is consistent with the way we've explained it today.

Mark Wiseman: And just another question, can you sort of optimize your position by signing a multi-asset contract? Or would this Enterprise agreement be just for that asset?

Lee Marshall: Look, potentially, we can't say too much about the nature of how we have to deal with Enterprise other than we do have a right to sell up to the market. Obviously, we look at optimization across our portfolio as much as we can at all times.

Operator: [Operator Instructions] There are no further questions at this time. I will now hand back to Mr. Engelbrecht for closing remarks. Thank you, and over to you, sir.

Morné Engelbrecht: Thanks, operator. Thank you, everybody, for dialing in and look forward to speaking to some of you further in the week as well. Have a good day. Cheers.