Beach Energy Limited

Hello and welcome everyone to the Beach Energy half-year results presentation. My name is Morne Engelbrecht and I'm the Acting Chief Executive Officer of Beach. Putting me in 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. Then I'll be over to Anne-Marie, who will run through the financials, 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 two includes our disclaimer as well as information regarding our reserves disclosure. I will leave this with you to read in your own time. Let's move on to the main part of today's presentation. The first half in FY22 was one that not only delivered against our growth agenda, but also saw the continued execution of our strategy. This 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 is important to note that we now have some of the key building blocks in place to start realising incremental production volumes over the next year. The Oslo gas plant is now in a position to deliver increased production thanks to the commencement of the Geograph 4 and 5 wells. Further to this, CUPE is again running at its full 77 terajoules a day capacity following the commission of the inlet compressor. On the financial results, our statutory impact for the first half was $213 million, a 66% increase on the corresponding half in FY21. Again at the half in a net cash position of $74 million with a $600 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, FY24, with the start-up of Coupe, the continued drilling of wells in the offshore Otway, and the signing of the LNG Heads of Agreement with BP for white seal volumes. Given the strong progress we have made towards our base production target, we are now starting to look at the projects that could enable Beech to deliver above that target. This includes planning an exploration campaign in the Perth Basin, building a better understanding of the nearshore and offshore potential in the Otway Basin, investigating near yellow north and west exploration opportunities in the Bass Basin to complement the potential trefoil development, and planning for a Kupai East development well in the Ternaki Basin to further extend the production plateau for Kupai. Flight 4 speaks for itself. but it's an excellent illustration of the strong financials we enjoy at Beach. Our sales revenue increased 11% to $786 million and a half. This leads to an EBITDA figure of $513 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 frank interim dividend of $0.01 per share. Moving to slide five, and you can see Beech continues to record strong safety performance, notwithstanding the fact that we are on 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 and a half with our Ottawa gas plant, reaching seven years without a recordable injury. However, the first half 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 six, I just want to quickly give you all a reminder of what we outlined yesterday, September last year. The takeaways from this were a base business production growth target of 28 million barrels of world equivalent, FI24, We funded balance sheet to support this target with only low levels of gearing reached. The delivery of material steady cash flows from eight gas plants across four 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 Beecher's first task 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 off every box. As mentioned, we brought the Cooper Inlet Compression Project online in September, which has seen the Cooper gas plant return to its full capacity. In the Victorian Otway Basin, we delivered the first volumes from our Otway Offshore Development Campaign. The Geograph 4 and 5 wells were drilled, connected, and commissioned, with gas now being delivered into the East Coast gas markets. We also commenced the final phase of the offshore drilling program, successfully drilling the thylacine north one well in line with pre-drill expectations. In the west, we commenced construction at weight shear stage two with the project on track and site works are now 42% complete. We also reached an historic milestone by signing a heads-up agreement to a BP for all of each of 3.75 million tonnes of LNG from the project. Finally, we sanctioned the Moonberg carbon caption storage project by joint venture partner and operator, Santos. We did 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 three remaining offshore wells to drill into the thylacine field. Drilling is 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 Hathaway gas plant. In the Perth Basin, construction activity will continue at Waitseer Stage 2, with our focus also now including the development drilling campaign. With our operator Mitsui, we intend to drill a minimum of five gas development wells targeting the Kingyear and Highcliffe 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 or our guidance, so any discoveries would help deliver upside. On the sustainability front, the key achievement and a half was the sanctioning of the Moomba carbon capture and storage project by JV participant operator Santos. This project forms a key pillar of our aspiration to reach net zero emissions by 2050. It's by far the biggest investment we have made to date to reduce our operational carbon footprint and will deliver the state change and beaches CO2 emissions profile. In our zone test, this month booked 100 million tonnes of CO2 storage resource in the Cooper Basin in South Australia. As you're aware, Beaches' 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 together with all our other reserves and resources projects in preparation for the report in August. Slide 9 provides our unchanged FY22 guidance. We have maintained our FY22 guidance range of 21 to 23 million barrels of oil equivalent. Guidance is maintained based on the fact that we are outperforming our annualized decar rate of 35 to 45% in the western flank as development wells come online. We've also connected the geographic wells, albeit production is subject to customer nominations. This is offset by the lower than non-operated production performance in the Cooper Basin JV experienced in the first half. Capital expenditure guidance has also been maintained to be between $900 and $1.1 billion. 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.

Thanks, Mornay. Good morning, everyone, and thank you again for joining us today. My name is Anne-Marie, and I've been with the company for three 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 Morna has already highlighted, each announced a reported net profit after tax of $213 million for the first half of FY22, up 66% on the same half last year. Our EBITDA of $513 million reflects a 26% increase on the corresponding half. Cash from operations jumped 105% to $605 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 $0.01 per share, fully franked. Slide 12 highlights our NPAT in comparison to the first half of FY21. The 11% rise in revenue during the first half was primarily driven by a 75% increase in realised 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 FY21 asset acquisition. Slide 13 highlights our strong cash position with total cash of $213 million at the end of the half. As mentioned earlier, operating cash flow of $605 million was up 105% on the corresponding half. This cash flow included $29 million of income tax paid and a $42 million receipt for settlement of Coupé carbon tax arbitration. Our free cash flow pre-major growth investment was $329 million. Turning to slide 14, and you can see our balance sheet continues to be extremely strong with a net cash position of $73 million at the end of the half. Our total liquidity stands at $673 million, a result of a successful refinancing of our debt facility to $600 million with favourable 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 Waitseer Stage 2 developments. This is reinforced by the fact we expect our net gearing to remain below 10% despite a capital-intensive FY22 work program. Before I hand back to Mornay, 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 200 to 300 million positive impact on operational cash flows over the next three 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 FY24. With that, I would like to hand back to Mornay to run through our markets and operating assets.

Thank you Anne-Marie. I'll just quickly run through the current gas market dynamics we are seeing before jumping into our assets portfolio. Slide 16, you will see the beaches geographical diversity and market distribution is across three gas markets. The fourth to be added soon. Australian East Coast gas market, the Australian West Coast gas market, New Zealand domestic market. As I said, soon to be the global LNG markets. There are four incredibly robust markets where gas is desperately needed. The Australian energy market operator continues to see gas shortfalls within the East Coast gas market from as early as next year's winter, while the ACCC believes the shortfall could come this year. On the West Coast, IEMO's latest outlook says there could be a potential domestic supply gap from around 2025. We are already seeing the energy supply tightness forecast between 2022 and 2025 starting to rear its head. 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. 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 out of the development campaign in FY22. As previously mentioned, the first half saw beach-connected Geograph 4 and 5 wells at the Otway gas plant. Both wells are now producing gas to East Coast Gas Market and represent the first new volumes from the offshore development campaign. We also drilled the first of the Phyllocene Wells, Phyllocene North 1. This well was successfully drilled and intersected 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 four Thylacine wells will be connected back to the Otway gas plant in the second half of FY23. 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 FY23. From an operational perspective, it was an excellent first half at the Ottawa gas plant, and we should operate it 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 Ottawa gas plant. It would be understandable to assume that the combination of high reliability plant and the connection of Geograph 4 and 5 see daily production set 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. When looking through beach off-way gas plant production, it's important to remember that it isn't a reflection of beaches' well capacity or plant reliability. but more so the daily nomination arrangements, which are lastly set by the customer. Nonetheless, because of the take-a-pay arrangements, the annual volumes going through the plant will be balanced by the end of each calendar year. It's important to remember Beech has the right to market volumes for Lavella 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 off-way gas plant. As you can see from the chart, beach will reach the 205 terajoules a day capacity at the off-way gas plant once the thylacine wells are connected. However, based 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 height of activity in the first half of FY22. Construction commenced at Waitseer Stage 2 gas plant as of 31 December, construction was 42% complete. The first half also saw Beach sign its first ever LNG Hedgehog Agreement with BP, which is 3.75 million tonnes from Waitseer Stage 2. Waitseer JV has also secured Eastern Well rig to drill the upcoming Perth Basin development drilling campaign. Also of note was the fact that the Bahara 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 five gas development wells of Wadesia, targeting the Kenya and Haikou Sansa informations. This development drilling program is scheduled to span 12 months, from Q1 2022 to Q1 2023. At Waitress Stage 2, development of off-site 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. Given the potential for domestic gas shortages in the Western Australian market in the near to medium term, this will progress further development and exploration drilling opportunities surrounding acreage with a view of leveraging the recently secured rig. Moving to Slide 20, when we turn our attention to the Western flank, The first half saw us arrest some of the production declines in our oil acreage. In addition, we drilled four horizontal oil development wells with a 100% success rate, with a fifth well drilling ahead. On the exploration front, we experienced a 33% success rate from our gas drilling program in Expel 106, with successes at Rose Bay 1 and Lowry South 1. However, the media action happens in the second half as we'll soon commence the oil exploration campaign. We'll drill three appraisal wells in the Expel 104 martlet oil field before kicking off the oil exploration campaign with 11 oil exploration wells with additional wells planned after an assessment of the results. Important to reiterate, this has factored in no exploration success in the Western Flank as part of the base business production target. Any success would deliver additional production. I look forward to updating you on the results of that campaign in due course. On the Cooper Basin and looking at the Cooper Basin JV on slide 21, our strategy remains to pursue high-value, 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 wool equivalent was down 13% on the corresponding half, to unplanned downtime at Moomba and upstream operations, as well as some planned maintenance at Moomba and natural fuel decline. We shall continue to work with Operator Santos to ensure we maximise production from those facilities. We each plan to participate in 35 to 40 wells in the second half. On slide 22, we start to turn our attention to projects where we believe we can start to deliver upside to our base growth targets. In the Bass Basin, the first household beach reprocessed seismic data, and in doing so, we identified new exploration opportunities, Yolo West and Yolo North. These prospects could be developed with jack-up rigs on the Yolo 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 FY23, 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 treadfall project in the event that the project, which is currently in feed, is sanctioned. To that end, we acquired the prime 3D seismic in the first half with the data now being processed to support a potential FID for the treadfall development and quantify the potential of the nearby white ibis and bass prospects. Moving across the Tasman 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 Cooper Inlet Compression Project online, the first gas introduced into the plant two weeks ahead of schedule. As a result, the plant's throughput returned to the full 77 TJs a day. Plasty and plateau production rates are expected from the Cooper Field through FY23. 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 Cooper gas plant to deliver upside on our base production target. As such, we continue to assess a potential development well, Cooper East, which could be drilled from the existing Cooper platform. Running of that well has been considered for FY23, again, subject to approvals and RIC 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 toward the 28 million barrels of oil equivalent target achieved today. Offload is first gas from the Octway offshore wells, and the fact that Cupe is again running at 77 TJ spec capacity. However, we know the job is far from done, and in the second half, we're still focused on delivering key milestones towards our growth target. This includes drilling the remaining three wells in the offshore waterway campaign by the middle of this year, pushing FID on the enterprise pipeline project, commencing the development drilling for the Waitier Stage 2 project, and signing the agreement with BP for BESA's 3.7 million tonnes of LNG from Waitier. The second half will also see us refining a focus on projects that have the potential to deliver production above our stated growth target. These include the Western Flank Oil Exploration Campaign, to which any discoveries could serve above our base case target, progressing our plans in the Perth Basin to conduct an exploration campaign at the conclusion of the Waitian Development Drilling Program, better understanding the nearshore potential of the Otway Basin following our success at the enterprise, executing the YOLO Enfield Program to extend the life of YOLO, as well as progress feed on trefoil, and finalized plans to drill the Kupe East development well in the Taranaki Basin to extend plateau at Kupe. These first three points are supported by our final takeaway, which is the continued strength of our balance sheet. We retain a net cash position of $73 million with liquidity of $673 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.

Thank you very much. We will now begin the question and answer session. If you wish to ask a question, please press star 1 on your telephone and wait for your name to be announced. If you wish to cancel your request, please press star 2. If you are on a speakerphone, please pick up the handset to ask your question. The first question comes from the line of Daniel Levy from Citi. Please go ahead.

Thanks, Monty and Anne. A couple of quick ones from 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?

Hey, Daniel. Thanks for the question. In terms of CapEx, we've maintained our CapEx guidance for FY22. Obviously, the Otway Offshore plays a big part in that guidance. We don't see any creep in terms of the CAPEX from an 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 $1.1 to $1.3 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.

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?

Oh, yeah, no, definitely. So the weather has definitely been kinder to us over the last two or three 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.

Fantastic. That's great news. 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 like that from you guys, given how healthy futures pricing is at the moment? I think at the quarterly result, you said you had zero hedging in place?

Yeah, 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 CPI-linked contracts. So from that perspective, we don't see an immediate need to do any hedging. Obviously, with, you know, 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 questions, Daniel.

Yep, it does. And sorry, I'll just sneak one more quick one in there. I noticed the quarterly you were drilling the Bean Bush deep crossing 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?

You want to go for Sam? We've got Sam here as well.

Yeah, I'll go on. I'll be exact for exploration subsurface. Yeah, that's so well operated by Santos, so I think it's appropriate for them to come on in that particular operation.

Okay. Understood.

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

Good morning everybody. Just two questions please. I was just maybe wondering if you could please talk a bit more about when we might have an announcement around the appointment of a CEO or obviously one of your active CEO at the moment. I was just wondering if you could please talk to how that search is going for both domestically and internationally and when we might get an announcement on that and then just got one more question after that please.

Good morning, James. Thanks for the question. Obviously, the CEO search has been conducted by the board. 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. So I think I'll leave it at that point. And obviously the board is working, like I said, very diligently in 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.

Yeah, thanks. Okay, understood. And then the second question was just really around The Perth Basin, just in terms of the Waitier project, you know, 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 Waitier Stage 2 and then also, I guess, the timeline for that project, please.

Can I 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 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 if Thomas is on the line, he can speak to that more broadly. In terms of the 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 said to the market previously, which is the second half of 2023 in terms of first LNG from that project. Okay, thank you. Thomas, you're on the line. Do you want to expand on the cost side of things?

Yes, I can. Thank you. Good morning. Look, the only comment I would add to what you said, Mona, 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 turnkey contract that was designed, negotiated and executed during the height of COVID. So both CLUF, the EPC contractor, as well as the Mitsui Beach Joint Venture have allowed both allowances and contingency to help safeguard and protect that $700 to $800 million gross guidance capex number that we've put in the market. Perfect. Thanks a lot. That's great. Thank you.

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

Morning, morning, Anne-Marie and team. Just a quick question, firstly, 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 modelling that you might apply on that asset going forward, just to help build confidence in what the resource will produce in the coming years?

Great, thanks, Tom. I might throw it to Sam on that question.

Yeah, sure. So the... The commentary there relates to two things, really. Firstly, we have undertaken a reservoir pressure maintenance strategy for the Bower field, which has shown some really positive results. So production in Bower is flattening out. It's declined quite materially. And the second thing, obviously, is that we've drilled five development wells in the western flank, and we're looking forward to the production of those wells those wells will deliver to us in the second half of the year.

All right. Thanks, Sam. Mornay, can you please just elaborate on a little bit more on your capital management options going forward?

That's a continual discussion with the board as well in terms of our capital management framework and how we think about it. where we sit right now in terms of our capital program we're spending a billion dollars this year and a billion dollars next year which um as you would expect uh is is is quite a big capital program in terms of our market cap so represent two-thirds of our market cap currently uh so we want to make sure that we can deliver on those uh those projects over the next year or two um and obviously complete the offshore program drilling program as well uh over the next six to 12 months. So, you know, 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 different 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 and YG 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. Yeah, so it's a continual discussion and assessment as we go through the program.

Okay, thanks, Mone. Appreciate it.

Next slide. Thank you. The next question comes from Mark Samter from MSD Marku. Please go ahead.

Yeah, morning, guys. A couple of questions, if I can. I appreciate some of this will be commercially sensitive, but it seems to be causing such a big deviation in actual 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 that... they thought was expensive versus what else they can procure gas at. And you're heading into another arbitration, or maybe not say arbitration, sorry, a price review, which might end in arbitration next year. They obviously have a bit of power over you into that. How low can production go if this gas isn't favourably priced for origin?

Hey, 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, those specific contracts are coming up for renegotiation 1 July 2023. So we probably review those prices and start negotiations the second half of this calendar year. Apart from that, you know, normally historically, as you would know from a seasonal perspective, we've seen low nominations in the summer months and high nominations in the winter months. So we'll see whether that plays out this year as well.

Okay. Okay, yeah. I'm going to try and ask the question another way. The nominator, year-to-date, obviously since the Wells have been tied in, actual production's only been, I think it's just over 70 DJs a day. Would that level be sustainable for the whole year, or there's seasonality in the numbers that have allowed that at this time of year versus being able to sustain that through the whole course of the year?

Yeah, again, it's dependent on nomination, seasonality, We did see, as you would have seen as well, Mark, in the back end of December, 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, you know, we've got those takeover provisions to protect our revenue for the calendar year. And then we depend on nominations from a seasonal perspective.

Okay, perfect. Next question if I can. Just the, there's $13.6 million at the completion adjustment on acquisitions. Am I right in thinking that's just the payment from Mitsui to take BASCAS and TREFOL off their hands? And in the context of that, I noticed any reference to an FID in the second half of this calendar year has been removed from TREFOL and on a go-forward basis, Mitsui were willing to pay you to take these assets off their hands, can we infer from the removal of the comment about NFID that that project might have more challenges than you first thought and you're not as committed to NFID as you were six months ago?

Thanks for the question, Mark. So on your first question in terms of the completion adjustment, yes, it's mainly right to the, you know, the adjustment on the past gas assets, and then the second answer to your question in terms of FID. We did outline in the presentation today that we are progressing through FEED. There are 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's been two exploration prospects we do want to have a serious look at in terms of YOLA North and West. So we're assessing that at the same time. So the other thing that's playing into the timing for Troy Coil would be the successful wireline we just completed as well. So you would have seen with YOLA 6, we've added about five kJ a day. And then stage two of that wireline campaign on YOLA 4 and 5, in this quarter. So all those things combined will provide us with the information to make an assessment on FID and TREP oil, but also an assessment on Yolan North and West.

Yeah, okay. And just from a reserve booking perspective, obviously, unfortunately, you guys already carry TREP oil and booked 2P. I guess whilst you're going through feed, that can stand true at this end of year reserve statement. You'd have to proactively decide not to take FID to have to write down the reserves?

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 a possible FID for trefoil. So obviously that will come in the first half of FY23 in terms of that assessment. And that will be flown into the reserve process as well. That will go through in August of this year as well. 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 Triforce.

Okay, perfect.

Thanks, Morning.

Thanks, Bob.

Thank you. The next question comes from Dale Coenders from Ballantyne. Please go ahead.

Morning. Two quick questions, firstly, on Obway Gas Plant. Just wondering if there's any thoughts towards increasing capacity at the plant or removing the dam or dominations from contracts or potentially using storage to increase production?

Yeah, look, thanks for the question. Also, we just, in terms of looking the other way offshore, obviously we're focused on delivering those tylosine 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. But we do feel comfortable with the current plant capacity and obviously the life of the asset there. and the ability to manage that going forward with enterprise coming in.

Okay. And then just quickly on weight here, I know you're still working on finalising the SPA with BP. Just wondering how we should be thinking about sort of contract pricing. Is it set based on where terms were six months ago when LNG contracts have been signed with loads of 12, or is there scope to give them the run that's happened in LNG markets? you know, short-term contract now being signed in 13s and 14s. Will you benefit from that upside?

Yeah, look, it was done at the time we announced it and those terms and conditions agreed in the heads-up agreement will be the terms and conditions that will be in the SBA as well. What we can say is obviously that we have... We're still very happy with the contract that we have with BPD. It is reflective of the current market And we feel very comfortable in terms of, as we said before, it's got protection to the downside there, and it provides us upside in terms of, you know, 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're at. Okay. Thank you.

Thanks, Dale. Thank you. The next question comes from Adam Martin from Morgan Stanley. Please go ahead.

Good morning. Just back on trefoil. Can you just remind us what the trefoil reserves are and, you know, what potential sizes Yellow West and North might be? And I think you previously told us FY25 is first production for trefoil. So when would you sort of need to hit feed or, sorry, FID to hit that milestone, please?

Hey Adam, I might prefer to.

On the YOLA West and YOLA North, we don't typically reference any prospective resource size on that, and we're also looking through that and in regards to the reserves, I'd refer you to a previous disclosure of that last year.

We're happy to take that up in terms of the 3-4 reserves after the Cool Horse Wall, Adam. In terms of the specific timing, as I said, we're going through the fee, looking to, if we reach FID, reach that within FY23. So in terms of the timing, in terms of FY25, that's still very much the plan in terms of reaching FID.

Okay, so it's still possible to do FY23. All right. And just a question, just a modeling question. It's about maintenance at Port Benison 2400.

Yeah, we don't see any impact, and Santos indicated no impact in terms of production, so they'll use the current LHDN storage to make sure that production is not impacted from that specific facility.

That's great. That's all for now. Thank you.

All right. Thanks, Adam. Thank you. Next question comes from Gordon Ramsey from RBC Capital Markets. Please go ahead.

Thank you very much. Just the comments on the Bower pressure maintenance. Is that water flooding? I'm just interested in what you're doing to that field to maintain pressure.

Yeah, so we have a number of projects. water producers and what we've been doing is modifying the way 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.

And thank you. 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?

I mean, I actually would expect there was some impact to our drilling operations there, not only in the Western Flank, but also in the Cooper Basin JV, which the team's 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. It has some impact, but it's minor, and we're working to make that back within the quarter.

Thanks, Morna. And just last question from me. Just on the Perth Basin, you previously indicated potential for three to six exploration wells. I noticed there's no comment on the number in this result. Should South Araguela via gas discovery, will that impact that program? And can you please confirm, are you still looking at three to six exploration wells potentially after the five development wells on Waitsail?

Yeah, look, in terms of the success or not success of Western South Araguela, 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 326 exploration wells there. Obviously, that's subject to us confirming and discussing that with Mitsui as well, our joint major partner there, to confirm those wells, but definitely on the cards.

Okay. Thank you very much.

Thanks, Gordon. Thank you. The next question comes from Saul Kavonik from Credit Suisse. Please go ahead.

Thank you. Just a couple of quick questions on production, if I may. The first one's 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 could see downside to that if Origin choose lower nomination levels?

Yeah, look, that's probably not a bad way to look at it all, but in terms of the actual cycle pay, 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 of that.

Great. My second question then is about enterprise tie-in in the second half of FY23 and the mention in the presentation how that should enable greater stability and greater use of capacity in the plants. I could just provide perhaps some more color exactly on how that works. So, you know, are those 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 proportional volumes that are enterprise and the rest of it is still going to have these huge swings depending on origins nominations, if that makes sense?

Yeah, look, I mean, we see how that's playing out. There's 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 Altway gas plant during those times. So in terms of working out a GSA on the enterprise, that will be reflected in that GSA in terms of that optionality.

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?

I mean, we haven't finalized the contracting on those volumes yet, so I don't want to preempt anything. Obviously, as you know, it's all in the current market and where we see shortages coming. I can't see that we... market price for our gas, irrespective of nominations.

Great. And my last question is, I guess, more on that mid-term 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 an increasing production trajectory beginning from later in the financial year? And we should see that kind of increase on average for the next three or four years?

Yeah, look, I think in terms of the geographic four and five wells being online, obviously, again, it depends on nominations. If you look at historic performance and nominations around the 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 planned for Bass or the Yola, the Lang Lang facility. So, you know, we told you about three 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 flag play out as well during that period. So I think it will be amiss of me to say that we will see an increase. Obviously, 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.

Great. Thank you. That's all from me. Thanks, all.

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

Oh, hi, Mornay, Anne-Marie and team. Just looking ahead at what's shaping up to be a very active FY23 from a drill bit perspective. I think you've got wells planned now in the Perth Basin. You've 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 three wells to go there. Just wondering 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 it adds to your sales volume to the plant and the expected tightness in the East Coast gas market? Thank you. Morning, Nick.

Thanks. Yeah, 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 and make a decision on in the coming 12 months. But for now, we are definitely focused on delivering those piloting wells.

Got it. And just on the Perth Basin, we've talked about the weightier development drilling. Minimum of five development wells Just wondering what would flex that five well number higher? Is it the results from the drilling? And just maybe a bit more colour around how long that campaign's due to take. I'm assuming that same rig will then move on to the proposed three to six development and exploration well campaign and your other Perth Basin permits.

Cheers. I might throw that to Sam. Anyone want to go?

Yeah, 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 five, whether it's six, 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 development wells.

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

Yeah, look, I think we, as I said, we've focused on the development goals, 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 further exploration potential and the wells. We want to draw 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've sorted all that out. which will be in the next six to 12 months. Got it. Thanks, Monet. Cheers. Thanks, Dave.

Thank you. The next question comes from John Bishop from Euros Hot Leaves. Please go ahead.

Hi, thanks for taking my call. 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 agreements predicated on a reserve number? I guess where I'm getting to here is you obviously got a reasonable amount of growing capacity now. Spot market looks to be reasonably firm. What are your limits there?

We've got obviously the limits that exist within the various contracts. Obviously, we don't want to, you know, 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.

Okay, and then with your other volumes discovered there, particularly Blackwatch and Halladale and also Artisan, what's your thinking around bringing that gas to market sooner rather than later?

Yeah, look, John, we're sort of looking at that from a sequencing point of view. So we're looking at obviously connecting our thylacine wells in FY23, And then looking at enterprise and depending on how that looks from a production point of view, then assess 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 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.

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?

Yeah, 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 $5.50 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 has been commentated more broadly in the market, shortages in terms of gas supply there from 2025. So we do see those volumes potentially flowing into the domestic gas market there. And obviously the knowledge in Northwest Shelf is increasing as well. So obviously subject to further approvals by WA government, but that might be an avenue to extend that in time as well.

Okay, and just a quick one then. Just around Mitsui, I did think I saw in the press recently that Mitsui were investigating their own sort of mid to downstream Midwest development concept around Geraldton or the like. Is that something that you'd be working with them or will you guys keep that separate?

Look, I mean, that's for obviously Matui and them to consider in terms of their plans in WA. Obviously, we focused on Waitsea and Bahara Springs. If If it makes sense that we do partner with them on those, then we'll do so. But there's nothing on the task just yet.

Okay. I appreciate that. Thanks for taking the questions.

Thanks, Sean. Thank you. The next question comes from Mark Waisman from Macquarie. Please go ahead.

Hi, Monet and team. 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 terabytes per day. When you've done your economics on enterprise, is that based on an sort of interruptible contract where you're only selling for six or nine months of the year? Or have you modelled that on a baseload basis?

I think I might... But actually, Lee is also in the room here.

I'll come down here. Can you hear me there? Yeah. Yeah, I think as Mornay 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.

And just another question, can you sort of optimise your position by signing a multi-asset contract or would this enterprise agreement be just for that asset?

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 it to the markets. Obviously, we look at optimisation across our portfolio as much as we can at all times.

Okay. Thanks, Lee. Thanks, Mono. Cheers.

Thanks, Mo. Thank you. Participants, to ask a question, please press star and one. The next question comes from 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.

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.