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 in the call today is our acting Chief Financial Officer, Anne-Marie Barbaro. We're 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. I'll be over to Anne-Marie, who will run through the financials. 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 reserve's 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 in FY 2022 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 bbls 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 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, Cooper is again running at its full 77 TJ a day capacity following the commissioning of the Inlet Compressor.
On the financial results, our statutory NPAT for the first half was $ 213 million, a 66% increase on the corresponding half in FY 2021. We ended the half in a net cash position of $74 million with a AUD 600 million revolving facility providing us with strong levels of liquidity. We also made excellent progress towards our base 28 million bbls of oil equivalent production target in FY 2024 with the start-up of Cooper, 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 made towards our base production target, we are now starting to look at the projects that could enable Beach 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 new Yolla North and West Exploration opportunities in the Bass Basin to complement the Potential Trefoil Development, and planning for a Cooper East Development well in the Timor Sea Basin to further extend the production plateau for Cooper. Slide four speaks for itself. It's an excellent illustration of the strong financials we enjoy at Beach. Our sales revenue increased 11% to $ 786 million in the half. This led to an EBITDA figure of $ 513 million at 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 AUD 0.01 per share. Moving to slide five, 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 seven 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 six. 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 bbls of oil equivalent in FY 2024. A 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 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 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 Geographe-4 and -5 wells were drilled, connected, 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-one well in line with pre-drill expectations. In the West, we commenced construction at Waitsia Stage two, 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 tons of LNG from the project. Finally, we sanctioned the Moomba Carbon Capture and Storage Project, our 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 on the way at Thylacine West-one, 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 to the Otway Gas Plant. In the Perth Basin, construction activity will continue at Waitsia Stage two, with our focus also now including the Development Drilling Campaign. As our operator, Mitsui, we intend to drill a minimum of five gas development wells targeting the Kingia and High Cliff Sandstone Formations.
Finally, in the coming weeks, we will 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 nor 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. It's 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. We heard Santos this month booked 100 million tons of CO₂ storage resource in the Cooper Basin in South Australia.
As you're 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 together with all our other Reserves and Resources Projects in preparation for the report in August. Slide nine provides our unchanged FY 2022 guidance. We have maintained our FY 2022 guidance range of 21 million bbls-23 million bbls of Oil Equivalent. Guidance is maintained based on the fact we are outperforming our annualized decline rate of 35%-45% in the Western Flank as development wells come online. We've also connected the Geographe wells, albeit production is subject to customer nominations. This is offset by the lower than non-operated production performance in the Cooper Basin JV we've experienced in the first half. Capital expenditure guidance has also been maintained to be between $ 900 million 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, Morné g ood 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, as Morné has already highlighted, Beach announced a reported net profit after tax of AUD 213 million for the first half of FY 2022, up 66% on the same half last year. Our EBITDA of AUD 513 million reflects a 26% increase on the corresponding half.
Cash From Operations jumped 105% to AUD 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 AUD 0.01 per share, fully franked. Slide 12 highlights our NPAT in comparison to the first half of FY 2021. 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 2021 Asset Acquisitions.
Slide 13 highlights our strong cash position with total cash of AUD 213 million at the end of the half. As mentioned earlier, Operating Cash Flow of AUD 605 million was up 105% on the corresponding half. This cash flow included AUD 29 million of income tax paid and a AUD 42 million receipt for settlement of Cooper carbon tax arbitration. Our Free Cash Flow, pre-major growth investment, was AUD 329 million. Turning to slide 14, you can see our balance sheet continues to be extremely strong with a net cash position of AUD 73 million at the end of the half. Our total liquidity stands at AUD 673 million, a result of a successful refinancing of our debt facility to AUD 600 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 Two Development. This is reinforced by the fact we expect our net gearing to remain below 10% despite a capital-intensive FY 2022 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 AUD 200 million-AUD 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 FY 2024.
With that, I would like to hand back to Morné 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 asset's portfolio. Slide 16, you will see Beach's geographical diversity and market distribution is across three gas markets, with a fourth to be added soon. The 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. These 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 as 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 2022. 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 gas to the East Coast Gas Market and represent the first new volumes from the Offshore Development Campaign, which also drilled the first of the Thylacine wells, Thylacine North-one.
This well was successfully drilled, and intersected the reservoir in line with pre-drill expectations. The Ocean Onyx is currently drilling the Thylacine West-one well before finishing off the campaign in the middle of this year with the Thylacine West-two and Thylacine North-two wells. The four Thylacine wells will be connected back to the Otway Gas Plant in the second half of FY 2023. 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 2023. From an operational perspective, it was an excellent first half at the Otway Gas Plant, and we should operate it at 99.9% reliability.
Moving to slide 18, 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 will see daily production sit between 160 TJ-180 TJ per day. However, this is not necessarily the case, as dependent on customer nominations. The current CPI-linked take-or-pay gas sales agreements have considerable flexibility for the customers to nominate. This means there'll be daily production volatility. When looking through Beach's Otway Gas Plant Production, it's important to remember that it isn't a reflection of Beach's well capacity or plant reliability, but more so the daily nomination arrangements which are lastly 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 La Bella, 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 TJ a day capacity at the Otway 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 hive of activity in the first half of FY 2022. Construction commenced at the Waitsia Stage Two Gas Plant. As at 31 December, construction was 42% complete. The first half also saw Beach sign its first-ever LNG Heads of Agreement with BP, which is 3.75 million tons from Waitsia Stage Two. Waitsia JV has also secured Ensign Rig to Drill 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 five 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- Q1 2023. At Waitsia Stage two, development of offsite fabrication will continue while the site construction will progress in earnest as we look to have the plant online 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 and surrounding acreage with a view of leveraging the recently secured Rig. Moving to slide 20, 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 at 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 PEL 106, with successes at Rosebay-1, and Lowry South- 1. However, the immediate action happens in the second half as we'll soon commence the Oil Exploration Campaign. We'll drill three appraisal wells in the PEL 104 MacKillop 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, 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. 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 to low-risk opportunities.
To that end, Beach participated in 32 wells, with an overall success rate of 88% in the first half. However, first half production of 3.7 million bbls 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 field decline. We shall continue to work with operator Santos to ensure we maximize production from those facilities. Beach plans to participate in 35-40 wells in the second half. On slide 22, we start to turn our attention on projects where we believe we can start to deliver upside to our base growth targets. In the Bass Basin, the first half saw Beach reprocess seismic data. In doing so, we identified new exploration opportunities, Yolla West and Yolla North.
These prospects will be developed with jackup 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 2023, 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 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 Kupe Inlet Compression Project online, with first gas introduced into the plant two weeks ahead of schedule. As a result, the plant throughput returned to the full 77 TJs/day capacity, and plateau production rates are expected from the Kupe Field through FY 2023. This figure has been updated slightly to reflect data coming through since the completion of the compression project. In a similar vein to our BassGas Assets, we are now assessing options to extend plateau production at the Kupe Gas Plant to deliver upside on our base production target. Aside, we continue to assess a potential development well, Kupe East, which could be drilled from the existing Kupe Platform. Building up that well is being considered for FY 2023, 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 bbls of Oil Equivalent target achieved to date. Of note is first gas from the Otway Offshore wells and the fact that Kupe is again running at 77 TJ per day capacity. However, we know the job is far from done, and in the second half we are still focused on delivering key milestones towards our growth target. This includes drilling the remaining three wells in the Offshore Otway Campaign by the middle of this year, issuing FID on the Enterprise Pipeline Project, commencing the development drilling for the Waitsia Stage 2 project, and signing the agreement with BP for Beach's 3.7 million tons of LNG from Waitsia.
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 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. Better understanding the nearshore potential of the Otway Basin following our success with Enterprise. Executing the Yolla Infill Program to extend the life of Yolla, as well as progress FEED on Trefoil and finalize plans to drill the Kupe East Development well in 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 one on your telephone, and wait for your name to be announced. If you wish to cancel your request, please press star two. If you are on 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, Morné. 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. I mean, in terms of CapEx, we've maintained our CapEx guidance for FY 2022. Obviously, the Otway Offshore plays a big part in that guidance. We don't see any creep in terms of the CapEx from a Otway Offshore point of view. It's still within the range that we previously spoke about at the September investor day, which is around the AUD 1.1 billion-AUD 1.3 billion gross. There's no change to any of that. As you would expect, we do have contingency in place for a project of this size.
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, n o definitely.
Okay.
The weather's definitely been kinder to us over the last two or three months. That's been reflected in the you know the drilling performance we've seen on the Thylacine wells to date. We're pleased to see the drilling performance there. Well, done to the team there.
Fantastic. That's great news. Just another quick one. We're seeing 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 how healthy futures pricing is at the moment? I think at the quarterly result you said you had zero hedging in place.
Yeah, l ook Daniel, it's something we do assess on an ongoing basis. I think from our perspective, we obviously got a great balance sheet, so you know, 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. 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 pretty comfortable in terms of being unhedged. I don't know. That's probably. Hopefully that answers your question, Daniel.
Yep. It does, s orry I'll just sneak one more quick one in there. I noticed at the quarterly you were drilling the Beanbush 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 wanna go for it, Sam? We've got Sam here as well.
Yeah.
Hi, Sam.
I'll go on a exec for exploration subsurface. Yeah, that's a well operated by Santos, so I think it's appropriate for them to comment on 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.
Oh, good morning, everybody. Yeah, just two questions, please. Maybe one, if you could please talk a bit more about when we might have an announcement around the appointment of a CEO. Or obviously, you know, one of your acting CEO at the moment. Just wondering if you could please talk to how that search is going for, you know, both domestically, and internationally, and when we might get an announcement on that. Just got one more question after that, please.
Morning, James. Thanks for the question. Obviously, the CEO search is being 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. I think I'll leave it at that point. Obviously, the board is working, like I said, very diligently in conducting that search, so I'll probably leave it at that. There's no rush in terms of any timing from that perspective.
Obviously, the board wanna make sure that they put the best possible candidate in the role.
Yeah, thanks. Okay. No, understood. Then the second question was just really around the Perth Basin, just in terms of the Waitsia 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 Waitsia Stage Two, and then also, I guess, the timeline for that project, please.
I look, James, from like all other industries in terms of COVID, we are dealing with you know 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. The team is working diligently to make sure that we can get people there in an efficient, and safe manner as well. You know, 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.
Yeah, in terms of the Clough Contract, you know that represents about 60% of the overall capital program, which is based on a Fixed-P rice Turnkey sort of contract. But in terms of the capital inflation, we're not seeing that playing out at the moment. 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, t hank you.
Thomas, are you on the line? Do you wanna expand on the cost side of things?
Yes, I can. Thank you, g ood morning. 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 Turnkey Contract that was designed, negotiated, and executed during the height of COVID. Both Clough, the EPC contractor, as well as the Mitsui and Beach Joint Venture, have allowed both allowances and contingency to help safeguard and protect that $ 700 million-$ 800 million gross guidance CapEx number that we've put in the market.
Perfect, t hanks a lot. That's great, t hank you.
Thanks, James.
Thank you. The next question comes from Tom Allen from UBS. Please go ahead.
Morning, Morné and team. Just a quick question firstly on Western Flank Oil. 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 in what the resource will produce in the coming years?
Great. Thanks Tom, I might throw to Sam on that question.
Yeah. Su re, t he commentary there relates to two things really. Firstly, we have undertaken a reservoir pressure maintenance strategy for the Bauer Field, which has shown some really positive results. Production in Bauer is flattening out. It's declined quite materially. The second thing obviously is that we drilled five development wells in the Western Flank and we're looking forward to the production that those wells will deliver to us in the second half of the year.
All right, t hanks Sam. Morné, can you please just elaborate on a little bit more on your capital management options going forward?
I mean, that's a continual 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 $1 billion this year, and $ 1 billion next year, which, as you would expect, is quite a big Capital Program in terms of our market cap. It represents 2/3 of our market cap currently. We want to make sure that we can deliver on those projects over the next year or two and obviously complete the Offshore Program, Drilling Program as well, you know, over the next six-12 months.
You know, we wanna drive you know, completion of those, and then look at spanning 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 P roject, and Waitsia in particular before reassessing that. We feel very comfortable with our balance sheet at the moment, and that can support our growth profile going forward. Yeah, it's a continual discussion, and assessment as we go through the program.
Okay. Thanks Morné. Appreciate it.
Thanks, Tom.
Thank you. The next question comes from Mark Samter from MST Marquee. Please go ahead.
Yeah, morning guys. A couple of questions, if I can. Morné I mean, 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? Cause obviously it's a contract that they've been pretty public that they thought was expensive versus what else they can procure gas at. You're heading into another 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 favorably priced for Origin?
Hey, Mark t hanks for the questions. I mean, first of all, obviously, as you would know, that's commercially 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. 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 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 higher nominations in the winter months.
We'll see whether that plays out this year as well.
I'm gonna try, and ask the question another way. The nomination year to date, obviously since the wells have been tied in, actual production's only been, I think it's just over 70 TJ a day. Would that level be sustainable for the whole year or that 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?
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. In January, it's been very variable in terms of the nominations that we've seen. Not sure how that's gonna play out in terms of the rest of the year. As I said, you know, we've got those take-or-pay provisions to protect our revenue for the calendar year, and then we're dependent on nominations from a seasonal perspective.
Yeah. 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 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 year has been removed from Trefoil, 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 an FID that that project might have more challenges than you first thought, and you're not as committed to an FID as you were six months ago?
Thanks, for the questions Mark. On your first question there, in terms of the completion adjustment, yes, it's mainly in relation to you know, the adjustment on the BassGas Assets. 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 you know, information and data available through the 3D seismic we recently acquired as well. We're looking at how that could impact, and further inform a potential FID on the project. We're definitely moving ahead in considering Trefoil and getting to an FID stage.
As we've also outlined, there's been two exploration prospects we do wanna have a serious look at in terms of Yolla North and West. We're assessing that at the same time. The other thing that's playing into the timing for Trefoil would be the successful wireline we just completed as well. You would have seen Yolla six, we've added about five terajoules a day. Then stage two of that wireline campaign on Yolla four and five later in this quarter. 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.
Yeah. Okay, j ust from a reserve booking perspective, obviously, unfortunately, you guys already carry Trefoil and booked 2P. I guess while you're going through FEED, that can stand true at this end of your reserve statement. You'd have to proactively decide not to take FID to have to write down the reserves.
Yeah, 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 a possible FID for Trefoil. Obviously, that will come in the first half of FY 2023 in terms of that assessment. You know, that will be flow into the reserve process as well, that will flow through in August of this year as well. Don't wanna 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.
Okay p erfect, t hanks Morné Engelbrecht.
Thanks, Mark.
Thank you. The next question comes from Dale Koenders from Barrenjoey. Please go ahead.
Morning, t wo quick questions. Firstly, on Otway Gas Plant. Just wondering if there's any thoughts toward increasing capacity at the plant or removing the downward nominations from contracts or potentially using storage to increase production.
Yeah, look thanks for the question, Dale. We just, in terms of looking at the 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, you know, further utilization of the plant more so than you know, extending the plant capacity. 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, a nd then just quickly on Waitsia, I know you're still working on 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 six months ago, you know, when LNG Contracts are being signed with slides to AUD 12? Or is there scope to given the run that's happened in the LNG Markets, you know, short term contracts now being signed in AUD 13 and AUD 14, is there, you know, 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 of Agreement will be the terms and conditions that will be in the SPA as well. What we can say is obviously that 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 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. Overall, in terms of the contract we have there, we very happy where we are.
Okay, thank you.
Thanks, Dale.
Thank you. The next question comes from Adam Martin from Morgan Stanley. Please go ahead.
Morning, j ust back on Trefoil. Can you just remind us what the Trefoil reserves are and, you know, what potential size this Yolla West and North might be? You know, I think you previously told us FY 2025 is first production for Trefoil, so when would you sort of need to hit FID to hit that milestone, please?
Hey, Adam I might refer to.
On the Yolla West and Yolla North, we don't typically reference any prospective resource size on that. We're obviously looking through that. In regard to the reserves, I'd refer you to a previous disclosure of that last year.
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, reach that within FY 2023. In terms of the timing in terms of FY 2025, that's still very much the plan in terms of reaching FID.
Still possible to hit 23. All right, j ust a few question, just sort of a modeling question that was prompted about maintenance at Port Bonython, Q4, FY 2022. How long is that gonna be? Is there a impact on that, which Santos has talked about, please?
Yeah, w e don't see any impact, and Santos indicated no impact in terms of production. They'll use the current oil gas storage to make sure that production is not impacted from that specific facility.
Okay. Great, t hat's all from me t hank you.
All right. Thanks, Adam.
Thank you. Next question comes from Gordon Ramsay from RBC Capital Markets. Please go ahead.
Oh, thank you very much. Just the comments on the Bauer pressure maintenance. Is that water flooding? I'm just interested in what you're doing to that field to maintain pressure.
Yeah. We have a number of water producers, and what we've been doing is modifying the way that water interacts with oil production just to increase our oil production. 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.
Thank you, s peaking of water we've had some extreme weather events in Central Australia. I imagine there's some flooding in the Kupe Basin at the moment. Is that expected to have any impact on operations, let's say in the March quarter?
Yeah, look, 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 Cooper Basin JV, which the teams have been working around. 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 Morné, j ust last question from me, just on the Perth Basin, you previously indicated potential for three-six Exploration wells. I noticed there's no comment on the number in this result. Should South Erregulla be a good gas discovery, will that impact that program? Can you please confirm, are you still looking at three-six Exploration wells potentially after the five development wells on Waitsia?
Yeah. Look, in terms of the success or not success of you know West and South Erregulla, it doesn't really impact our view in terms of our exploration acreage and the prospects we see there. We're definitely looking at the three-six Exploration wells there. Obviously, that's subject to us confirming and discussing that with Mitsui as well, our joint venture partner there, to confirm those wells, but definitely on the cards.
Okay, t hank you very much.
Thanks, Gordon.
Thank you. The next question comes from Saul Kavonic from Credit Suisse. Please go ahead.
Thank you, j ust 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 scope that we could see downside to that, if Origin choose lower nomination levels.
That's probably not a bad way to look at it, Saul. In terms of the actual take-or-pay, as I said, we're not gonna confirm that. There's obviously the seasonality on it as well. There's obviously the variability, and the flexibility that they do have in the contracts, and that's obviously reflected in the price. As we said, going into winter, that's normally the higher nomination period in a specific calendar year. That's probably as much as I can say on all that.
Great, m y second question is about Enterprise tie-in in the second half of FY 2023, and the mention in the presentation how that should enable greater stability, and greater use of capacity in the plants. Could you just provide perhaps some more color exactly on how that works? You know, are those independent GSAs from Enterprise gonna enable you, for example, to sell just more gas in those off-peak lower nomination periods? Or is that additional stability only gonna come from those proportional volumes that are Enterprise and the rest of it is still gonna have these huge swings depending on Origin's nominations, if that makes sense.
Yeah, look I mean, we see how that's playing out. We're 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. In terms of working out a GSA on the enterprise, that will be reflected in that GSA in terms of that optionality.
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, 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.
Great, m y 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 increasing production trajectory, beginning from later in this 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 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 planned for the Bass, the Yolla, the Lang Lang Facility. You know, which will be about three weeks. That will happen in the March quarter as well. So, we should see that having an impact, and obviously, we want to see how the development wells from a Western Flank play out as well during that period.
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 wanna see how that plays out over the next quarter, before putting a stamp on it.
Great, t hank you. That's all for me.
Thanks, Saul.
Thank you. The next question comes from Nik Burns from Jarden Australia. Please go ahead.
Morning, Morné Engelbrecht and team. Look, just looking ahead at what's shaping up to be a very active FY 2023 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 volumes for the plant, and the expected tightness in the East Coast Gas Market? Thank you.
Morning Nick, t hanks. 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. Don't wanna make any predictions or forecasts on any of that, but our focus is on delivering the current Thylacine wells. As I said before, we're working our way through understanding better the onshore, and offshore prospects there, and looking at it more broadly and how we could further develop the offshore point of view as well. Also looking more specifically at the nearshore opportunities that's presented there.
I think both nearshore, and offshore we'll look at and make a decision on in the coming 12 months. For now, we are definitely focused on delivering those Thylacine wells.
Got it j ust on the Perth Basin, you've talked about the Waitsia Development Drilling, minimum of five development wells. Just wondering what would flex that five well number higher. Is it the results from the drilling? Just maybe a bit more color around how long that campaign's due to take. I'm assuming that same rig will then move on to the proposed three-six Development Exploration & Well Campaign in your other Perth Basin permits. Cheers.
I might throw that to Sam. Anyone over there.
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. 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. It's a key consideration as to when it makes sense to drill those which can be related to their exact position. In regard to the Exploration and additional Development Drilling, yes, that would follow on after those development wells.
In terms of that campaign, I mean, 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 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 focused on Development wells, so that will take us the next 12 months to complete those. During that period of time, we'll get to an agreement with Mitsui on the further Exploration potential, and the wells we wanna drill in the sequence of those wells we wanna go after, and the locations. We'll come back to the market in due course once we've sorted out all that out, which will be in the next, you know, six to 12 months.
Got it, t hank, Morné. Cheers.
Thanks, Nik.
Thank you. The next question comes from Jon Bishop from Euroz Hartleys. Please go ahead.
Hi, t hanks 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've obviously got a reasonable amount of growing capacity now. Spot market looks to be reasonably firm. What are your limits there?
Yeah, look we've got obviously the limits that exist within the various contracts. Obviously, we don't wanna, 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, w ith your other volumes discovered there, particularly Blackwatch, and Halladale, and also others, what's your thinking around bringing that gas to market sooner rather than later?
Yeah. Look, we're sort of looking at that from a sequencing point of view. We're looking at obviously connecting our Thylacine wells in FY 2023, 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. At the moment.
Okay.
In terms of what we can see going forward, we've got Thylacine and an appraisal 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. Just finally on the Perth Basin, 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, you know, touching about 5.5 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. We do see as being commented more broadly in the market, shortages in terms of gas supply there from 2025. We do see those volumes potentially flowing into the Domestic Gas Market there. Obviously, the LNG in Northwest Shelf is ever-increasing as well.
Obviously subject to further approvals by WA Government, but that might be an avenue to extend that in time as well.
Okay, j ust a quick one then. Just around Mitsui. I did think I saw in the press recently that Mitsui were investigating their own sort of midstream to downstream, Mid-West , 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 Mitsui and them to consider in terms of their plans in WA. Obviously, we focused on Waitsia and Beharra Springs. If it makes sense that we do partner with them on those, then we'll do so. There's nothing on the cards just yet.
Okay, I appreciate that. Thanks for taking the questions.
Great t hanks, Jon.
Thank you. The next question comes from Mark Wiseman from Macquarie. Please go ahead.
Oh, hi Morné 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 TJ per day. When you've done your economics on Enterprise, is that based on a sort of interruptible contract where you're only selling for six or nine months of the year? Or have you modeled that on a base load basis?
I might hand that to Lee. Lee is also in the room here.
Can you hear me all right? I'll come down here. Can you hear me there ?
Yeah.
Can you hear me? Yeah. I think as Morné Engelbrecht 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. On that basis, the level of economics we've done is consistent with the way we've explained it today.
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?
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 market. Obviously, we look at optimization across our portfolio as much as we can at all times.
Okay, t hanks Lee. Thanks, Morné Engelbrecht. Cheers.
Thanks, bye.
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.
All right, t hanks, 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.