Beach Energy Limited (BEPTF) Q2 2023 Earnings Call Transcript

Beach Energy Limited (OTCPK:BEPTF) Q2 2023 Results Conference Call February 12, 2023 6:00 PM ET

Company Participants

Morne Engelbrecht – Chief Executive Officer

Anne-Marie Barbaro – Chief Financial Officer

Stephen Algar – Group Executive-Exploration & Subsurface

Derek Piper – General Manager Investor Relations

Conference Call Participants

Tom Allen – UBS

Mark Samter – MST

James Byrne – Citi

James Redfern – Bank of America

Dale Koenders – Barrenjoey

Saul Kavonic – Credit Suisse

Mark Wiseman – Macquarie Group

Adam Martin – E&P Financial

Daniel Butcher – CLSA

Gordon Ramsay – RBC

Nik Burns – Jarden Australia

Henry Meyer – Goldman Sachs

Sarah Kerr – Morgan Stanley

Scott Ashton – SHA Energy

Morne Engelbrecht

Thank you, Darcy. Good morning, and welcome to the FY ’23 half year results presentation for Beach Energy. My name is Morne Engelbrecht, and I am the Chief Executive Officer here at Beach. Joining me on the call today is our Chief Financial Officer, Anne-Marie Barbaro, also joined by the Beach executive team.

For today’s presentation, I will first provide an introduction on the recent activities at Beach, as we progress towards our step change in production and free cash flow. Then it will be over to Anne-Marie, who will give an update on the financials, including the new dividend policy that we announced this morning, and then I’ll provide some insight into the forward outlook for our portfolio as well.

Following that, we will open the lines for Q&A Slide 2 is our compliance statements, which I will leave to you to read in your own time. On to Slide 3. We have been working hard in the first half of FY ’23 to progress and derisk our major growth projects. I want to highlight the following key messages from today’s update. First of all, Beach is growing its gas and LNG business. There’s been good progress during the first half in FY ’23 on this front.

Over on the East Coast, we are planning for the connection of our Otway Thylacine wells in the coming months, which will allow the Otway gas plant to produce at its nameplate capacity of 205 TJs per day. This milestone will be the first catalyst for the uptick in our production and cash flows that we have been forecasting over recent years. Furthermore, the enterprise near-shore well is being connected to the plant, and we now expect to be ready for first gas mid-FY ’24.On the West Coast, the Waitsia development drilling campaign is now complete, plant construction progressing and agreement reached with Webuild to take over the construction of the project from the administrator. Webuild and the JV are targeting first gas by the end of this calendar year. Second, Beach is growing strong free cash flow. Once we complete the Waitsia gas plant, we will have 8 gas plants supplying local and international markets.

Stronger diversified cash flow will position us for enhanced, disciplined capital management, delivering increasing returns to shareholders, while continuing to fund future growth. Third, our strong balance sheet allows us to invest in future growth beyond our major project pipeline. With $609 million in available liquidity and increasing free cash flow, we will be able to find new gas projects and other growth opportunities that are necessary beyond FY ’24.Today, we are planning drilling in each of our operating basins. This includes our much anticipated Perth Basin exploration campaign, which has already delivered on success from 2 Mitsui operated wells, while the Beach operated campaign begins in Q4 this financial year. Finally, as we all know, the energy transition is underway globally with Beach supporting this through our investment in gas, CCS and other abatement and new energy initiatives. We know that demand for natural gas is not going to disappear soon.

We also know that our industry must decarbonize. Beach is doing this day primarily through our investment in Moomba CCS, but this is just the beginning. We have a 35% emissions intensity reduction target for our portfolio, and we are investigating new energy opportunities that will support our business as those new markets emerge. I hope you will see today that Beach’s plans are progressing and as our free cash flows and production increases materialize, Beach is looking forward to the future while rewarding our shareholders for their loyalty. Moving to Slide 4, and there’s nothing more important to me than the safety of our people. Beach’s [ACC] performance in the first half began with a few minor safety incidents. However, I’m very pleased with how the team has responded.

Pleasingly, 2 of our sites have just recorded major milestones. Otway gas plant achieving 8 years and Beharra Springs achieving 4 years recordable injury-free. We’ve also just clocked up 3 years with out-of-lost time injury in the Western Flank. Well done to those teams. We’ve also seen a strong period in our environmental performance to-date. I also want to give a shout out to the Dombey survey team, who received the South Australian Premier’s Award for Energy and Mining in the environmental category.

This was for the approach to using new technologies to eliminate the need for land clearing during the Dombey seismic survey in the SA Otway. Congratulations to the seismic team. Turning to Slide 5 and our first half financial results. Beach performance was largely driven by lower production and sales volumes, while sales revenue were up 3% at $813 million. EBITDA was down slightly at $491 million, while underlying NPAT was down 10%. In line with our newly announced dividend policy, you will notice today that we have implemented the policy and confirmed a $0.02 per share interim dividend, a doubling of the $0.01 per share dividend Beach has paid for many years and with more than $0.5 billion in franking credits available, there’s still more to come. Turning to Slide 6.

And less than 2 weeks ago, we provided our FY ’23 second quarter update. Since that time, there have been 2 important milestones achieved on our key growth projects. First of all, the Beach environmental plan was approved by NOPSEMA for our offshore Otway well connection activities. This EPA allows for the remaining subsea work to be completed, with the DOF Subsea vessel now on location. Both the Thylacine wells are commissioned and connected to the Otway gas plant, it will allow for an additional 100 terajoules a day to be available for the East Coast gas market. The second major development of the last few weeks was the news that Webuild will take over construction of the Waitsia Stage 2 project.

This is part of our broad acquisition of Clough. Beach provided an update to the market at the time, including a modestly increasing CapEx guidance range. When you consider the possible alternatives from the voluntary administration process, this is the best outcome where all involved in the project would have hoped for. [indiscernible] and the Thylacine EP approval moved both projects closer to completion, which will allow for Beach to deliver the step change in production and free cash flows from FY ’24.Turning to Slide 7, which provides a further summary of the milestones achieved across the business in FY ’23. Perhaps most notably, back in July, Beach completed its largest ever drilling campaign, the largest ever in the Otway Basin’s history, with gas now flowing from the Geographe wells.

And as mentioned, we are now progressing the Thylacine well connections as well. In New Zealand, negotiations are progressing for our forthcoming Kupe development well, which we aim to drill at the end of 2023 calendar year. We also announced a new emissions intensity reduction target of 35% by 2030, as we progress the Moomba CCS project with operator Santos. And I’ve already touched on the Webuild transaction, with development drilling complete and our SBA in place with Customer BP. Our Perth Basin exploration campaign has also really delivered one discovery with the Mitsui operated Gynatrix well, and we have some exciting prospects ahead in the Beach operated phase of the campaign, which kicks off in early April this year. It has been a productive period for the first part of FY ’23, and that is despite some of the headwinds that Beach and our industry has faced. We look forward to continuing this momentum as we move towards the end of FY ’23.Moving to Slide 8; today, Beach has unveiled a new dividend policy, which Anne-Marie will speak to in more detail shortly.

Over many years, Beach has demonstrated financial discipline through our philosophy of diversifying revenue streams, prudently managing the balance sheet and ensuring sufficient liquidity for growth and dividend payments. This philosophy is reflected in our capital management framework, which put simply, has 3 objectives; maintain balance sheet strength by targeting to keep net gearing below 15%, reward shareholders through our new dividend policy, which will recognize increasing cash flows and utilize our substantial balance of franking credits, currently more than $0.5 billion, and continue to invest in growth, both from within our existing portfolio and other opportunities. We trust this framework and the dividend policy provides more transparency, as to how Beach will manage capital and how we will fund growth and higher returns to shareholders going forward. On Slide 9 and looking to the second half focus areas for Beach. In the Cooper Basin, we are focused on clearing the backlog of Western Flank oil connections, and we are then also focusing on development drilling for the remainder of the year. This should see us delivering an uptick in Western Flank oil production with oil prices on the up, as the second half progresses. Connecting the Thylacine wells into the Otway gas front is also key.

As I said, the DOF vessel is now on location, and we remain on track for first gas mid-year. Meanwhile, we look to make an investment decision on the next phase of Otway Basin drilling as well. We look forward to sharing details once the investment has been sanctioned. At Waitsia Stage 2, we are working towards keeping the project on schedule towards first gas by the end of this year. our Beach operated exploration campaign in the Perth basin is expected to commence in early Q4 of this financial year, with the spudding of Trigg-1. We’ll go into some further detail on that campaign a bit later.

In New Zealand, we look forward to signing up the rig for the Kupe development well, which we are planning to drill before the end of the year as well. Turning to Slide 10 and our FY ’23 guidance update. Today, we’ve lowered our production guidance from FY ’23 to 19 million to 20.5 million barrels of oil equivalent. Narrowed capital expenditure guidance of $900 million to $1 billion and increased our operating cost guidance of $13.75 to $14.75 per BOE. The lower production guidance reflects unplanned challenges that occurred in the first half, when — then impact production in the second half of the year as well. We remain confident that the material step change in production and cash flow will arrive in FY ’24, but we will no longer be referencing the FY ’24 production target, as the Perth production target remains subject to timing of major project delivery, which has in recent times, been impacted by the tough administration process and regulatory approval uncertainty. FY ’24 production guidance will be provided for full year results in August 2023, as it’s normally the case in which time, we will have greater certainty and clarity on both Waitsia startup and the Otway well connections.Capital expenditure guidance reflects high estimates for Waitsia stage 2, offset to a degree by efficiencies achieved in other programs.

The outlook for operating costs reflects industry-wide cost inflation, as well as higher Cooper Basin JV cost as apprised by the operator due to increased workover activities and unplanned maintenance. On Slide 11, I want to give you a clear picture of what we expect to deliver on the East Coast gas market as we complete the Thylacine well connections. Beach is uniquely positioned as a domestic focused producer on the East Coast, and we will increase our market share to 16% in FY ’24, up from 12% currently. This is underpinned by production from Thylacine wells, which will enable Otway gas plant to meet its nameplate capacity of 205 terajoules per day. We also have the enterprise well to connect it to FY ’24, in further opportunities both nearshore and offshore, including the existing Artisan and La Bella discoveries that can be developed. Our message here is, the Otway Gas plant will become a core driver of Beach’s production and cash flow step change, and we have a plan to maintain high production levels for many years into the future. Slide 12 and moving to the West Coast, Beach is already contributing to the WA domestic market to our Beharra Springs Springs and Xyris gas plants, which together delivered a 22% production increase in the half.

We are committed to WA domestic gas market, evidenced by our investment in exploration, which we hope will provide more supply certainty to the market in future years. At our Q2 results, we reported the news of our reserves revision, but that does not change our commitment towards LNG or domestic gas. Like you, we are, of course, eager to see the first LNG cargo delivered to our customer BP. Our JKM and Brent pricing structure will deliver the type of revenues that you would expect from the current market conditions. We appreciate that many of you would like further detail on the pricing structure for our LNG contract. But as we stated previously, for confidentiality reasons, we can’t disclose details.

What we have done here is provide illustrative pricing ranges, based on Brent and JKM prices over the past year. Hopefully, what this chart demonstrates, is that there’s a premium pricing ahead for LNG cargoes, with this revenue stream to continue through to the end of 2028.On the Perth Basin, my message is that no one else has the reserves, the assets, the prospectivity and the capability to deliver like the Beach and Mitsui JV. Beach intends to capitalize on our dominant acreage positions in the Perth Basin for the full benefit of our shareholders and our gas customers, both domestically and overseas. Turning to Slide 14 and the Beach’s progress on emissions reduction. First, a quick mention of the proposed changes to the Safeguard Mechanism. While there is still more detail required before Beach can fully understand any direct impacts to our business, it’s focus on emissions intensity reduction is broadly consistent with Beach’s ambitions to drive down intensity by 35% by 2030.

We are already actively pursuing the policy objectives through emissions reduction activities across our portfolio. Beach has commenced the select base on Otway Basin and CCS proposal. This would be Beach’s first operated CCS facility. Meanwhile, in the Kupe Basin, we are near completion on a prefeasibility study on ammonia production, while at Kupe, we are participants in a study on wind power generation using our offshore facility to gather data. As you know, we are investing in one of the nation’s biggest emissions reduction projects in Moomba CCS. Operator Santos tells us the new facility is about 40% complete, with first CO2 injection currently anticipated in 2024.Finally, it was pleasing to see the federal government’s chapter review highlighting the important contribution that CCS could make to limiting climate change. Let’s hope this is a sign of more things to come, as the CCS skeptics start seeing the growing evidence base for this important technology.

Now I’ll hand over to our Chief Financial Officer, Anne-Marie Barbaro, who will provide an update on our financial performance for the half.

Anne-Marie?

Anne-Marie Barbaro

Thank you, Morne. Good morning, everyone, and thank you again for joining us today. This morning, I’ll take you through the financial results for the first half of FY ’23 and provide an overview of the new dividend policy, which we’re pleased to announce today. Beginning with Slide 15 and our key financial metrics. Our first half FY ’23 results were influenced by a reduction in production and sales volumes, as we continue to deliver our key growth projects. During the half, Beach recorded higher sales revenue of $813 million, up 3% on the first half of FY ’22, with higher realized prices offsetting lower sales volumes.

Underlying EBITDA and NPAT were down, with an increase in cost of sales, in part the result of the current higher cost environment. Gas sales accounted for 41% of our sales revenue mix, with liquids accounting for 59%. We also ended the half in a net cash position. Moving to Slide 16, which shows the comparison of the first half FY ’23 underlying NPAT for the corresponding prior period. The 10% reduction in underlying NPAT was driven by a few factors, including lower production and sales volumes, which includes a one-off noncash impact on sales volumes and revenue in the first quarter of FY ’23, driven by a change in contractual terms on Cooper Basin liquids, which resulted in a revised revenue recognition point. This is not expected to have a material impact on full year FY ’23 earnings. Higher cash costs are primarily driven by an increase in third-party purchases, both through increased volumes and higher prices, as well as a 14% increase in field operating costs, which were mainly the result of the heightened inflationary pressures, as well as higher Cooper Basin JV costs, as advised by the operator due to additional workover activity and unplanned maintenance.

And higher financing costs were driven by a noncash increase in the unwinded discount on restoration provisions, as a result of increased long-term bond rates. These impacts are partly offset by stronger gas and liquids commodity prices, and higher third-party sales realized in the first half of FY ’23.Slide 17 outlines our cash flow movements for the period, with cash reserves of $189 million at the end of the half. Operating cash flows were $404 million for the first half of FY ’23, and included within operating cash flows were income tax payments of $97 million, compared with $29 million in the prior corresponding period. We also saw elevated levels of capital expenditure continue in the first half of FY ’23, as we progressed our major growth projects. Of the $527 million cash spend, $217 million of this expenditure was to fund our major growth projects.

Pre-growth free cash flow for the first half was $84 million. This figure forms the basis for our dividend payment this period, in line with our new dividend policy. On Slide 18, you’ll see our balance sheet remains in great shape. We ended the half in a net cash position with $609 million in available liquidity. This strong position enables Beach to maintain balance sheet flexibility, invest in growth projects, and deliver higher returns to our shareholders. As we move towards a period of strength in free cash flow in FY ’24, once major growth projects in the Otway and Perth basins come on stream, we have the capacity to deliver growth and pay higher dividends, while retaining optionality when it comes to other growth opportunities. Turning to Slide 19 and following on from Morne’s comments earlier about our capital management framework, which aims to balance our growth objectives against improved shareholder returns. A core component of the capital management framework is our new dividend policy.

After considering various capital management initiatives, Beach decided that a free cash flow based dividend payout ratio to be the best way to provide increased returns to our shareholders. The policy has been designed to provide transparency, utilize our franking credits, which are in excess of $0.5 billion, and reward our shareholders for their ongoing commitment to our strategy, as we yield the benefits of our major investment period. The dividend payout ratio targets a range of 40% to 50% of Pre-growth free cash flow. This is defined as operating cash flow, less investing cash flow, excluding acquisitions, divestments and major growth capital expenditure, less lease liability payments. The Board will retain discretion to ensure that broader capital management framework is preserved, in particular, target gearing levels during heightened periods of investment. The new dividend policy has been implemented and will take effect as of FY ’23, which results in a $0.02 per share interim dividend announced today. We expect the dividend to grow in FY ’24, as our free cash flow step change is delivered.

With that, I’ll now hand back to Morne.

Morne Engelbrecht

Great. Thank you, Anne-Marie. I will now talk a bit more about the future outlook, including our plans for future growth across Beach’s portfolio. On Slide 21, Beach has exposure to 5 key markets, and these markets all have strong fundamentals. We know that the East Coast gas market will continue to face supply challenges, with AEMO predicting potential shortages in the near, medium and long term.

As I said in the past, we need policy settings that are geared towards getting more Australian gas out of the ground, [indiscernible] and gas producers and especially domestic gas producers like Beach with more regulatory burden. On the East Coast, it will be remiss of me to not mention the potential damage to the future investment, which may be caused by the government’s management code of conduct and the recently priced provision. There is much uncertainty to be cleared here. For example, any price regulation must take into account complex industry nuances, such as exploration risk of significant capital required, and multi-decade investment horizons. As I said publicly before, removing investment uncertainty is imperative as new gas supply is the only answer for lower prices. In the West, we know the domestic market is tightening, just as Beach seeks to continue to grow its domestic gas share. In New Zealand, we see how anti-gas policy settings have created supply constraints, at times when energy needs are high with continued reliance on coal.

Once again, Beach will do its part to meet the needs of this tight market. A long time involvement in global oil markets extend to LNG markets, as we complete the Waitsia project, where Beach has unhedged exposure to Brent and liquids pricing. Beach aims to continue to increase our share of these markets, and as the world transitions to clean energy, our products will become more important than ever to global energy security. Turning now to Slide 22, and I want to give you a glimpse of our future, both plans and potential opportunities across Beach’s portfolio. Starting in the Perth Basin and working clockwise, and we’ll begin with the Perth Basin exploration campaign in Q4, further series of Waitsia development wells to be drilled and the Skipper 3D seismic as planned for FY ’25, conform the future exploration and appraisal program. In the Western Flank, we will be drilling continually and targeting the Birkhead formation for appraisal and exploration potential still to be pursued in the Namur. The Cooper Basin JV will stay busy with the drill bit with 4 to 5 rigs operating, targeting up to 100 wells per year. In New Zealand to focus on the Kupe development well, which aims to bring the plant back to capacity.

In the Bass Basin, our prime seismic interpretation gives us more informed data on Trefoil, White Ibis and Bass, all of which could be pursued, as a further phase of Bass Strait drilling in FY ’25 and beyond. In the offshore Otway, we have discoveries at Artisan and La Bella to appraise, while further exploration of Hercules, Anateus, Thistle, Up-Dip and Themis provide potential further opportunities. While on enterprise, the Calico 3D seismic survey is planned for the near-shore Otway Basin, where we can use the existing enterprise well pad to target near shore opportunities. So as you can see, there is significant opportunity across the portfolio, to develop our existing assets, to explore for new reserves and to fill our gas plants. And Beach has the balance sheet position to make this happen.Looking deeper into these assets and starting with the first basin on Slide 23, I want to go into our achievements in the half, which have already been discussed, but our forward-looking focus is to progress construction of the 250 terajoule a day Waitsia gas plant, continue the Perth Basin gas exploration program with the first Beach operated wells, and to complete the select phase of Beharra permeate recovery project. On Slide 24, we’ve laid out the current schedule for the campaign, which shows Trigg-1 to commence in early Q4. From there, the rig will move to Trigg Northwest and then Beharra Springs deep development well. From there, we have 3 further exploration wells at Tarantula Deep, Redback Deep and Peacock, all targeting the Kingia formation.

Beyond that, a number of follow-up wells are planned, which will in part be dependent on the outcomes of the earlier wells. For the Beach-operated acreage, we have 19 prospects and leads identified and 9 of these have 3D seismic data. We have contracted the Ventia 106 rig to FY ’24, which will initially drill up to the 6 wells of the Beach operated campaign. We think this could be just the beginning though, and subject to JV and other approvals, we will target exceeding the rig contract to drill the follow-up opportunities mentioned. I look forward to updating you on the campaign throughout the year, and we wish the team success. On Slide 25, we drill down a bit further on — and look at Trigg-1, which we see as being an on-trend with West Erregulla and South Erregulla discoveries. If Trigg-1 is successful, there’s an opportunity for a sidetrack well to test a broader Trigg structure.

Success at Trigg will also derisk the Southeast part of the basin. There’s also a significant follow-up potential at Trigg South, Cottesloe and the Lakeside prospects. On Slide 26, the Otway Basin is at the core of East Coast gas growth, which increased production by 32% compared to the first half of FY ’22. Our priorities looking forward, include the connection of Thylacine wells to the Otway gas plant connecting activities for the enterprise discovery, maturing offshore exploration related prospects, planning for near-shore and onshore 3D seismic acquisition and refine our CCS study for a potential 200,000 tonne per annum facility. On Slide 27 and in the Bass Basin, we are progressing planning for Yolla waste drilling in the first half of 2024. Also update Trefoil, White Ibis and Bass Resource estimates from the Prime 3D seismic survey, and this will inform our development strategy for these opportunities. On Slide 28, over the ditch, the Kupe plant remains a highly reliable facility and an important part of Beach’s portfolio. During FY ’23, while we are finalizing negotiations on the rig contract, we are targeting the mobilization of the rig for Kupe South 9, which we aim to spud by the end of 2023, subject to JV and regulatory approvals. Back down to dry land and Slide 29 looks at the Western Flank, which has been highlighted by a high level of drilling success.

We have 10 oil wells to be connected before the end of FY ’23 and continue drilling, which aims to increase production rates in the second half. As reported at the quarterly, the production performance in the Cooper Basin has been a result of operational impacts, not reservoir performance. Finally, to Slide 30 on the Cooper Basin JV, where the focus is on the five rig campaign targeting mostly gas development. The JV has performed well in the recent quarter, with Moomba production maintaining plateau, although a higher operating cost environment has been experienced by the operator, which is a material part of our increase in production cost guidance today. We are excited about the progress on the Moomba CCS project, which is reported to be 40% complete, as well as on time and on budget. Before I move to Q&A, I’d like to once again remind you of the key takeaways from today. First, we are growing our gas and LNG business.

Our 2 key growth projects are progressing well with some important developments in the recent period. Second, Beach is growing its free cash flow and starting today, we are rewarding our shareholders through our new dividend policy. Third, our strong balance sheet allows us to invest in future growth projects. The drill bit will be very busy at Beach in the coming years as we further develop our onshore and offshore plans. Finally, we will grow sustainably through the energy transition, and this while our existing products are going to be needed for many years to come.

With that, I would like to throw the lines open for Q&A.

Question-and-Answer Session

Operator

[Operator Instructions] Your next question comes from Tom Allen from UBS.

Tom Allen

Just regarding the new distribution policy announced today, with the payout ratio defined on a pre-growth basis, can you share some detail on how the Board intends to balance priorities between paying out stronger dividends versus investing in new growth that’s additional to the exploration plans that you’ve outlined in today’s presentation?

Morne Engelbrecht

Yes, Tom, I’ll let Anne-Marie cover off on some of the details. But at a high level, the Board will manage that through — looking at our growth program and our capital forecast and budget for the year ahead. It will balance that and obviously adjust for significant material projects, infrastructure projects, material drilling, material projects and adjusted free cash flow on that basis, before then calculating the dividends, which is set out at the 40% to 50% of that free cash flow number. But maybe Anne-Marie, you can cover some of the details?

Anne-Marie Barbaro

Yes, sure. Thanks Morne. So essentially, we’ve set up a range of 40% to 50% of pre-growth free cash flow to enable sort of a steady-state operational cash flow to sort of support both returns to shareholders, as well as continuing to fund major growth, noting that we do have strong liquidity. And I guess the Board is sort of included within that sort of a target gearing ratio that we’d like to stay below as well. So it’s just managing sort of the 50% of that operational cash flow, 40% to 50% to enable those dividend returns.

And obviously, in periods where we are looking at potential major growth, the Board may need to exercise their discretion to maintain our target gearing as we move forward. But essentially, that pregrowth — that growth capital that we’re talking about is really major construction of facilities and major drilling campaigns. That’s what we’re sort of talking about when we talk about the major growth. And then, obviously, M&A and divestiture as well.

Tom Allen

Yes, sure. Just a little bit of extra color on that major growth regarding M&A. I remember — recall last year, you mentioned that Beach would consider new growth opportunities that could leverage your existing infrastructure. Is that still a key requirement for your growth pursuits that are more at scale? And then recognizing that tighter supply outlook on the East and now the West Coast, with both regions now facing increasing government intervention risk, which areas present the strongest return profile and why?

Morne Engelbrecht

Look, I think in terms of the major capital that we’re looking to employ going forward, obviously, that still relates to the Waitsia project, finalizing that and connecting the Thylacine Wells. Beyond that we are looking to further invest in our offshore acreage as we’ve outlined today in terms of the Otway offshore and looking at how we link that in with the Bass development as well from an infrastructure point of view. So again, the main aim is there to have as much gas going through those plants into the East Coast gas market, which as AEMO has reported is going to be short gas in the short, medium and long term. So we do see value and obviously bringing more gas to bear into the market, but also through our gas bonds currently. So in terms of major capital spend around our infrastructure, that’s probably where that’s going to come from. And then in terms of the highest returns, I think when you look at our portfolio, especially specific to your question, Tom, around the East Coast gas market, we see that coming from Otway offshore and Otway nearshore as well. I think when you look at our portfolio there, we’ve got quite a number of prospects.

We’ve obviously got Artisan and La Bella, which we still need to connect up. But there’s a lot of potential and running room left there for us to explore. And if we look at how we develop that and we can develop that in conjunction with the Bass Strait as well, you start looking at some significant capital savings from that perspective as well. So from a return perspective, that’s probably high on the list of potential capital activities that we want to look at, and then the continual drilling in the Western Flank and obviously Cooper Basin as well that will feed into that market.

Tom Allen

Sure. That’s clear. Just if I can sneak one more. You’ve mentioned a couple of times that the drill-bit will be busy. What proportion, if any, of your planned growth in exploration and appraisal spend on the East Coast is subject to changes being made to this exposure draft legislation, regarding the reasonable price provision?

Morne Engelbrecht

Look, the reasonable price provision obviously impacts the East Coast gas market. So in terms of looking at our plans, if you look at the Bass Basin and the Otway offshore activity that will obviously form part of that, if that’s the final mandatory code of conduct and the final sort of settling of the words there. But in terms of the way we look at it, the East Coast gas market is going to be short gas and that’s based on current forecast. That’s without projects being delayed, potentially due to regulatory policy being developed as well, and that’s very fluid at the moment. So I think from our point of view, we do see an opportunity there to bring more gas to market in that setting.

Operator

Your next question comes from Mark Samter from MST.

Mark Samter

Just wondering if I could ask on the — around the dividend policy framework, but you guide to your view of, I guess, sustaining CapEx being $310 million for the half, so annualized $620 million a year. Can you just give us a feel because — I mean, I look at my numbers, and I look at consensus numbers a couple of years out and everyone’s doing at $350 million, $400 million CapEx for the whole business, but we obviously have production tailing off with that. Can you just give a sense for what you’re defining as sustaining CapEx? Is that the CapEx that just — is a lot of that just fixed asset CapEx that doesn’t really dwindle with production? Just the profile of that number as we go forward, or is there a risk we are underestimating with go-forward sustaining CapEx?

Morne Engelbrecht

Look, from a sustaining CapEx point of view, we do count in the Cooper Basin drilling. So we’ve got in the CB JV, as I said, we’ve got 5 rigs running there, Mark. So that we see as sustaining capital that’s linked to production. So the more rigs we’ve got running there and targeting the 100 wells per year, that will support our production staying flat. And similarly on the Western Flank, we’ve got the one rig running.

And then on the offshore side of things, that’s mainly fixed operating costs, in terms of maintenance costs that we’re referring to there, and that will be similar on the West Coast as well, once we get that plant up and running. So I think the — in terms of what we see as sustaining CapEx, it may be the variance of the difference there is that you’ve got 5 weeks running in the Cooper Basin JV, which we see as sustaining CapEx.

Mark Samter

Awesome. I might just make — one other quick question if I can, I know we’re dealing with a pretty large range on that illustrative guidance for the LNG SPA. But just when you talk about — based off average Brent prices over the last 3, 6 and 12 months. Can you just make clear traditionally LNG contracts are obviously on a JCC, and Brent — on a lag, I guess, can you tell us if your contract has that traditional 3-month push lag and Brent indicative prices you used in that — assume that same lag as well?

Morne Engelbrecht

Look, I think in terms of what they said out there is trying to just show an average over those periods, and it’s traditionally — and as we said previously, Mark, the contract we have with BP is linked to JKM and a slope to Brent. We haven’t said what sort of combination is in terms of percentage, but we’ve tried to apply an average of that across the average offer prices that we’ve reflected on the slide there. And it’s just to give an indication of potential ranges, it’s not a reflection of what you would expect, but it’s trying to give more clarity around, if you look at the market over the last 3, 6, 12 months. That’s sort of the pricing we would have looked at if we had LNG going into that contract.

Operator

Your next question comes from James Byrne from Citi.

James Byrne

So look, first question on gearing target being less than 15%. If I look at the business, a lot of the riskier parts of the CapEx cycle behind you, a decent portion of your revenue is CPI-linked, your dividend policy obviously flexes with commodity prices. So is 15% really most efficient number, as opposed to a range such as 15% to 25%? And again, like if I think about the history of Beach, Morne, you were CFO, when you acquired Lattice and your predecessor as a CEO, used to talk about how the debt funding of that acquisition and the gearing going to 25% had created a significant amount of value to shareholders. Today’s presentation slides, you’ve got M&A on there as an option for growth.

So I’m just wondering whether this 15% is a soft stealing or not?

Morne Engelbrecht

Yes. Look, I think, James, from a Board perspective in terms of setting that ceiling — obviously, setting up the policy today, we wanted to set that ceiling there. So people can sort of know where we’re going in terms of potential gearing. Noting that, obviously, that excludes — in terms of dividend policy initially, the major capital that we’ve spoken about. I think it’s an appropriate target in terms of gearing, from where we sit right now with all the uncertainty that we’re dealing with in terms of still having to complete the 2 major projects.

And then looking at what we invest in further — in terms of further development as a bio plant in terms of Bass and Otway offshore as well. So I think it’s appropriate for where we are at this point in time. Obviously, the Board can review that and adjust that as we go along and some of the projects are delivered, and we’ve got more confidence in cash flows and CapEx going forward. But I think for today, it’s an appropriate guide to the market. And referring back to — in terms of what you’ve outlined, in terms of the Lattice acquisition and the — in terms of the debt funding of that particular acquisition, that was obviously done at those levels, because we were comfortable with the cash flows that we were seeing coming out of the business. If we look forward in terms of potential M&A for us as well, and as we’ve said previously, we will only look at M&A from a value perspective. And if it doesn’t stack up from a gearing perspective, as with Lattice in terms of throwing out significant cash flows to do gearings on a quick — quickly from that point of view, then we won’t do it, right? So I think going to high gearing levels would require, whatever you look at from an M&A perspective through our significant cash flow, so you can dig here at a rapid rate.

James Byrne

Yes, again, that’s very clear. Just on Slide 22, which is the map with FY ’24 and ’25 potential activity, all of the offshore work, aside from one of those seismic surveys is either expected or not firmed. Now you’ve talked about policy settings needing to be more certain to be able to invest CapEx, does that also pertain to your exploration expenditure?

Morne Engelbrecht

Yes. Look, I think it’s across the board. So in terms of policy settings, we do want further clarity in terms of how that plays out, especially on the East Coast side of things. I think from a WA perspective, we are very comfortable with our exploration activity there and going ahead, like I said, with the 19 prospects we have with — from a Beach perspective, and what we’re going after in the initial round, we’re very comfortable in terms of the capital we are playing there. very comfortable with what that could mean from a domestic gas point of view and meeting our obligations there as well.

And we’re very excited about the growth potential in the Perth basin from our point of view. We’ve obviously got significant acreage there, significant reserves and us together with Mitsui, very keen to go after the exploration activity there. Similarly in — obviously, exploration in Western Flank and otherwise and CB JV as well, keen to go after that, I think the offshore component has still got some time to go in terms of how we plan that and how we sort of put it together. And therefore, you see the darker blue ones there expected, that’s in the planning phase. They are not firm, that’s obviously on the cards, but that’s further than the foreseeable future in terms of how we bring that to market. But definitely, having clarity on the policy setting will help our decisions and how we view those prospects going forward.

James Byrne

Yes. Okay. So the question about gearing and exploration really just kind of leads me into a question about distributions, which is — there’s obviously a lot of this uncertainty on East Coast gas markets, which might affect how much capital you’re able to deploy in development projects or exploration? Maybe you don’t find anything at scale in Perth Basin. And there’s no guarantee you’ll ever find anything to buy M&A-wise.

That sort of hypothetical scenario few years out, your balance sheet is going to be slush with surplus cash. I’m wondering whether you’d consider unlocking more of that franking credit balance via like temporarily higher distributions than what you’ve guided to today?

Morne Engelbrecht

Yes. Look, James, that’s total theoretical sort of question. I’m hoping that we don’t get there, that we’ve got great success out of the third phase and lots of development there and great success on the offshore and Bass Basin as well, and we can redeploy capital on those fronts as well because that is higher returning, so shareholders should want us to invest more on high-returning assets. But in that case, I would assume in your scenario, the Board will reconsider and relook at the dividend policy at that point in time. But again, for now, today, the dividend policy is in line with how we’re thinking about the business, including the safe guide in terms of the 15% net gearing.

Operator

Your next question comes from James Redfern from Bank of America.

James Redfern

Just a few quick questions, please. I just want a follow on to Mark’s question around the sustaining CapEx. Just with regards to calculating the free cash flow, pre-growth CapEx, so should we assume that the sustaining and exploration CapEx is going to be flat going forward, about $240 million per annum? And I’ve got 2 more.

Morne Engelbrecht

James, I don’t think we guided to $240 million going forward. I think if you look at our current CapEx outlay, you will see that we’re sort of looking at that sort of Mark — plus then if you look at sustaining CapEx, as I said to Mark as well, you need to include the Cooper Basin JV drilling and the 5 weeks we currently got operating there as part of that sort of sustaining CapEx as well.

James Redfern

Yes. Okay. Okay, good. Now just in relation to Waitsia, that’s sort of the [indiscernible] with regards to the FY ’24 production guidance. Just wondering if you could please provide or confirm what percentage of the Waitsia project is currently complete, please?

Morne Engelbrecht

Yes. Look we have — on that front, James, we are just waiting for Webuild well to take the reins from the administrator before we come into market and confirm what level of percentage complete that is. I think it’s just prudent to wait until they get behind the wheel before we come out to market with the completion.

James Redfern

Okay. Good. One last quick one. Just in regards to the price caps of $12 per gigajoule for the 2023 uncontracted gas. I mean, whilst no one really likes government intervention and price cuts, is it fair to say that Beach is largely only impacted by this, given the realized price of $840 in the last half and the amount of contracted gas to Origin Energy that your sort of internal models and cash flows are affected by these price gaps.

Is that fair?

Morne Engelbrecht

Yes, I think that’s fair, James. So I think we’re not materially impacted by those price caps. As you’ve outlined, most of our gas is sort of contracted and at fixed prices as well.

Operator

Your next question comes from Dale Koenders from Barrenjoey.

Dale Koenders

Just wondering if you could provide some color on the 10 drilled but uncompleted wells in the Cooper Western Flank. What sort of exit rate of production you’re targeting for FY ’23 and on a go-forward basis with the 30 wells per annum, what do you think these will then do in terms of reserve replacement and production?

Morne Engelbrecht

Yes, maybe I’ll throw it to Sam for that question. I think from a — in terms of connecting the 10 wells, the team is obviously working on that. At the moment we have the workover rig running 24/7 more recently in terms of progressing that as fast as we can, after the weather events and some of the supply chain issues as well that was caused by that. So the plan is to get them all connected by the end of this financial year. We haven’t guided to what that means from a production uplift point of view, because it’s just structurally complex in terms of flowing the well. So we want to actually flow some wells, get the production and then that will give us the indication of what we can expect from a production point of view going forward.

And that’s part of the reason why we’ve got quite a wide range in terms of the guidance we give for FY ’23, because there could be a low side outcome, there could be an expected outcome or it could be a high side outcome from the flow of those wells. So I don’t want to guide to that just yet. And Sam — that’s the answer. Sorry, say again?

Dale Koenders

And the ongoing drilling, do you think that your 30 wells per annum is there something that can then replace all production in terms of reserve position and continue to grow oil production from the Western plant?

Stephen Algar

I think that’s obviously something which we’ll work through, as Morne highlighted quite rightly. The production going forward is — will be informed by the production that we get out of these wells, which we’re waiting on connecting up. So that’s an important component of the answer to your question. The second component to it will be in FY ’24, we’re looking at doing quite a lot more exploration and appraisal. So it will also depend upon the success of that. So as we work through that information, obviously, we’ll give some better understanding of what that might look like.

Dale Koenders

Okay. Perth Basin, you’ve called out sort of ’19 targets. Can you give a steer in terms of, whether it’s a risked or unrisked potential of these targets combined, and probability of success rates you’re considering?

Morne Engelbrecht

Yes, we haven’t guided to that. So we purposely just wanted to show that…

Dale Koenders

Hence the question.

Morne Engelbrecht

Yes. So that’s — we wanted to show that there’s a lot of prospects there. We do feel there’s a lot of prospectivity there in terms of — and that’s why we’re spending the capital to go after it. And you can see that there’s quite a long list of wells that we’re going to be going after and drilling. And obviously, some of them are reliant on the success of the earlier ones.

But we’re very excited about the acreage in the Perth Basin and adding to our reserves in the future. So we don’t want to guide to anything there until, again, we’ve drilled and got the results and then we can report on the results.

Dale Koenders

Okay. I might ask one final question, hope to get more of a definitive answer. 7 or 8development wells at Waitsia, that’s flagged for FY ’24 and ’25. I’m a bit surprised that you’re drilling so soon again in the field. Is that to sustain production or would that potentially grow versus current production capacity?

Morne Engelbrecht

I think that’s — and I am looking at Sam here, yes, but that was always the plan to drill it in that segment. So it’s not earlier or later in terms of the sequencing. The first 6 wells we drilled was needed to get up to production and maintain production. And obviously, there’s a timing aspect to it in terms of when you bring the new capital or new wells on board in terms of when you spend the capital. So nothing is earlier or later on that front.

Operator

Your next question comes from Saul Kavonic from Credit Suisse.

Saul Kavonic

Just one quick question for me, and it’s coming back to the illustrative LNG contract pricing chart you put out there with the very wide ranges, depending on the contract terms, which you’re saying basically evolving over the term of that SBA. Now if I run — just very quick high level, if I assume, say, a 12% FOB slope, then that range accounts for your LNG spot linkage ranging from anywhere from about 10% to 40% of the volumes over that period. Would I be ballpark correct in assuming, that the spot LNG exposure in this contract changes over time, and you perhaps managed to get greater spot exposure at the early part of this contract when we’re expecting LNG spot prices to potentially be higher?

Morne Engelbrecht

Yes. Thanks for the question, Saul, and I can’t really answer that question because it’s commercial in confidence. But in terms of the ranges there, I think when you look at the contract over the term of the contract, the range in terms of JKM versus Brent linkage sort of remains the same over that period. So that’s probably as much as I can say, I suppose, from that perspective.

Saul Kavonic

Perhaps I guess the follow-up would be if the spot versus — following [JKM] versus Brent linkage isn’t changing. And I mean what you’ve given there applies to fixed historic JKM and Brent links. What is actually changing, that can account for that large range?

Morne Engelbrecht

[indiscernible].

Derek Piper

Derek here. Just jumping in. So I guess one of the messages on that slide is that, there are changing parameters at SPO over time, and it’s a complex SPA, and it’s very difficult to talk to. So when you look at — we know what the prices were over the past 12 months, commodity-wise and FX. When you apply those to the Brent SPA parameters over time, over the 5 years, you get those ranges.

So I realize it doesn’t answer any question precisely, but hopefully, it gives you a bit of an indication and helps convey the fact that there’s some complexity to them.

Morne Engelbrecht

Yes. I think the other thing to note, Saul, is that I think you mentioned FOB, this contract is a days contract in terms of we — sorry, FOB, sorry. Yes. So BP takes the shipping risk attached to the contract.

Saul Kavonic

Understood. But I guess it’s not really helping in terms of indication here. I mean, we’re trying to — we want to model this — the difference between $20 and $30, is huge. And you’re saying you can’t give us an indication of what we should look for, whether it’s going to be closer to the 20% or the 30% over the — for the 2022 period.

Morne Engelbrecht

Yes. That’s what we are saying Saul, a sorry about that, but we can’t give you any more detail than that. So we try to be helpful with the slide, but that’s as much as we can provide, unfortunately.

Operator

Your next question comes from Mark Wiseman from Macquarie Group.

Mark Wiseman

Just on Waitsia, obviously, you’ve spent a lot of CapEx there and taking the first move in the basin with a couple of other very high-profile players with big resource. Are there discussions taking place around sharing of gas processing infrastructure and perhaps Beach and Mitsui taking on a processing role for other gas? Are those discussions taking place or do you expect them to take place?

Morne Engelbrecht

Look, I don’t want to comment on any discussions. But I think if you look at the base, and I said this last year at a conference, but if you look at the basin and you look at the plants there, we obviously own and operate [indiscernible] Mitsui, 3 gas plants in the area. I think from our perspective, you definitely don’t need more plants in the area. So I think it would make sense to have those discussions. But I can’t say whether those discussions are happening or not, but I think it would make sense.

Mark Wiseman

And how much additional capacity do you plan to install on the existing site, in the event that you have more discoveries here?

Morne Engelbrecht

Look, I think from a — again, we said this previously, but from a Waitsia plant point of view, we can probably add about 100, 150 TJs a day there in terms of the current footprint of the plant. Obviously, this is subject to tons of approvals from environmental and regulatory point of view. There’s also expansion ability at the Beharra Springs plant that we can look at. So I think from a Xyris point of view, that’s probably doing as much as it can do at the moment. So that’s probably between those, Beharra Springs plant and the Waitsia plant, that we’re probably looking at expansion.

Mark Wiseman

Okay. Great. And just on enterprise, I think there was a discussion previously around — you were contracting — you were marketing that gas for an interruptible contract. Is that going to be effectively spot gas when it comes onstream, or are you still planning to contract that up?

Morne Engelbrecht

No, we’re still planning to contract that up. So negotiations are ongoing with Enterprise. Some of that will depend on when the gas actually hits the market, whether it’s within 2023 or 2024, but the negotiations are ongoing.

Mark Wiseman

Okay. Great. And just finally, for me, the Otway CCS project, could you maybe just help us to understand what the business model is going to be here? Are you intending to take third-party CO2 into that CCS assets? And if you’ve got any context on how those discussions are occurring post the safeguard reforms?

Is that something that is exciting you at the moment, in terms of the prospects of taking third-party CO2?

Morne Engelbrecht

Look, we — in terms of looking at the project, initially, we look at taking out the CO2 from the — obviously, the operations at Otway. So from our own production and those of our joint venture as well — joint venture participants as well. I think on that basis, from a timing perspective, we do see it making a good return for us with our third-party involvement. I think the third-party side of things will come later once we’ve sort of exhausted the development opportunities and keeping the plant full with our acreage and production. So I think that’s not something we need in terms of sanctioning the projects. So we see that from our own production, that that project will pay dividends.

Operator

Your next question comes from Adam Martin from E&P Financial.

Adam Martin

Just confidence around sort of hitting the Otway uplift target middle of the year, you sort of flagged risk, but just — and obviously, sort of walked away from the FY ’24 production uplift you’re going to provide in August. But just give us your confidence levels there on hitting that target for us?

Morne Engelbrecht

Yes. Look, I think from an FY ’23 point of view, looking at the target there in the 19% to 20.5%. We have more confidence in terms of getting the gas in by middle of this year from the Otway and connecting up with Artisan wells after the EP has been approved by NOPSEMA. So definitely more confidence there. We do — we did mobilize the vessel over the weekend.

So it’s now sitting across the wells, and we’ll start doing the work that’s necessary to connect the Thylacine wells. That is dependent on obviously the weather and how we go there with that program and then there’s the brownfields work to do at the site as well. So that reflects the upper end of that sort of guidance. So if we can get that in early, then obviously, we’ll end up at the high end of the guidance, all things being equal on other fronts. So in terms of confidence levels, we’re feeling very confident in terms of reaching our target there.

Adam Martin

Good. Good. And just another question just on costs. I think you mentioned or Anne-Marie mentioned just about the Kupe JV, just around production costs. Are there any other assets that you’re seeing that or should we assume most of those costs of the Santos JV that are coming through in terms of higher numbers?

Morne Engelbrecht

Yes. Look, the material component of that is the CB JV. I think the other component of that is obviously the production, the guidance that we provided today as well. So in terms of production being lower, that impacts that range as well. But from a gross operating cost point of view, CB JV is the major contributor.

Adam Martin

And just final question of $400 million to $450 million, you’ve talked about for Waitsia for net CapEx. How long does that take you out, just thinking about the extra drilling you talked about in ’24-’25. Is that in that number or is that additional — just wondering how far out that CapEx guidance goes for?

Morne Engelbrecht

Yes. Look, Adam, that guidance is just for the Waitsia gas plant. So that’s just — you can see the Waitsia gas plant get the first gas out of the door. And with the other CapEx guidance, we’ll obviously include that, as we go through the guidance. So the drilling we’re going after in terms of exploration, drilling in Perth Basin, that’s included in our FY ’23 guidance range.

And then when we get to FY ’24, we’ll obviously add to all the other wells there from a WA perspective as well.

Operator

Your next question comes from Daniel Butcher from CLSA.

Daniel Butcher

First one is just on the Waitsia CapEx again. It was reported in the news that Webuild contract is reimbursable. I’m just sort of curious, given that we had a short time to do DD on the project, which is well publicized by administrator, how confident are you, that the new quote is accurate given, that they can pass on increases down the [indiscernible]?

Morne Engelbrecht

So in terms of the DD that’s performed, we will obviously spend quite a bit of time before Clough went into administration, looking to buy the Clough business. And then Clough went into administration and then obviously, there’s some more DD. So they probably got — I would speak about 4, 5 months of DD behind them in terms of looking at the various projects. The other thing that we did do is, obviously look at alternatives in terms of — if we didn’t go with Webuild, what else is out there, who else can do the work. And obviously, that formed part of our decision to sign with Webuild as well, in terms of that process. But in terms of what we saw from other providers, in terms of what we’re guiding to, it was thereabouts or materially the same sort of numbers.

Daniel Butcher

Right. Similar numbers, okay. And just curious if you can give us a bit more detail on what you think about the average nominations you expect from Origin for throughput at Otway gas plants versus the actual capacity of 205? And perhaps just a second part of that question, could you just give it a feel for when it would start to go off plateau in terms of average 205, both before and after Enterprise once it’s all done?

Morne Engelbrecht

Yes. Look, in terms of the nominations of Origin, obviously, Origin has got a very complex book that they’re balancing on their side in terms of the various assets and gas that they can pull on. And you would have seen over the last 6 or so months, that that’s been variable. So that has been down when some of the LNG plants have gone into maintenance, where they then nominated that well on the Otway side of things. So in terms of the nominations, traditionally in winter, we do see full nominations and then in summer traditionally, that’s dropped off. So going forward, that’s I suppose the expectation in terms of winter and summer.

And when these wells are connected, we expect nominations to be high or nominating the full plant, at least in winter. What happens beyond that is then, they take or pay levels and then there’s the maximum level that we obviously inform Origin that the wells can produce, and the nominations will be within that range going forward. So I suppose it’s not a — I suppose, an answer in terms of maximum 205 terajoules a day. It’s an answer in terms of that — complex in terms of the nominations from Origin and the they’re balancing their side of the gas equation as well.

Daniel Butcher

Okay. And just a follow-up on the second part of the question.

Morne Engelbrecht

Yes. Yes, in terms of the plateau, obviously, it will depend again on nominations, and then when we actually connect then the Thylacine wells, whether that’s through the high nomination period potentially in the winter period versus summer, when they might drop off, but then at the plateau. But definitely, if enterprise comes in at the time that Thylacine is still producing at high nominations, we do expect that to plateau for a number of months beyond that.

Daniel Butcher

Okay. So a matter of months, not years, okay. Very good.

Morne Engelbrecht

And just to clarify that, Daniel. So in terms of — that’s why we’re looking at the other wells we’re connecting up in terms of Artisan and Labella, and when that comes in, is to keep the plant at plateau for longer in terms of what that looks like. So just — I suppose what I was just trying to clarify, that it depends on nominations and when the wells are connected. So if we connect the wells earlier and Origin nominate at high levels, that plateau is going to be dependent on when we can get Enterprise connected and when the timing on that is.

Daniel Butcher

Right. Okay. Maybe a final one if I can ask it. Sort of — if you look at conventional reserve downgrade at Western Flank, the other year is about nearly 50% on remaining reserves post production at the point in time. And then Waitsia, is obviously 15% of Waitsia Gas, excluding the Beharra Spring, stuff was downgraded just a couple of weeks ago.

Beach has usually carried a bit more for 2P for Cooper Basin JV than Santos has pro rata if memory serves me correctly. So I was just curious, how can we be confident that there’s no downgrade coming from [indiscernible] reserves before all is said and done? And if there are any risks you see to misestimation or any misunderstanding of the reservoir that could be pointed to as variabilities that would either be upside or downside to the currently booked reserves?

Morne Engelbrecht

Yes. Look Daniel, I want to cover all ground, but obviously, there was reasons for Western Flank downgrade reserves. And as we’ve outlined with Waitsia, that was obviously informed by the drill bit in terms of what we see. And as we outlined here, it’s very dependent on the seismic you have, whether you’ve got 2D or 3D seismic, there’s obviously a lot of faulting in the basin. And the other reason for that was the high cliff wasn’t as well developed as we expected in a couple of areas, especially the southwest of the basin. So in terms of looking forward in terms of Otway, we did — last year do a full audit on our reserves.

Obviously, the reserves we have for Otways in 4 and 5, including results we have at the moment. So we’ve drilled the 2 geographic wells, and we’ve drilled the 4 Thynacine wells. So that has informed our view on the reserves that we have currently in play. So I think from a reserve point of view, we’re feeling comfortable in terms of what we have out there at the moment. So maybe I’ll get Sam to maybe comment on more detail on that as well.

Stephen Algar

Yes. Just one clarification. You mentioned on the Cooper Basin joint venture, FY ’22 to be 100% clear here. We believe our reserves are almost identical to Santos’. There is no difference.

I want to be very clear on that. That’s from FY ’22, and we see no reason why that will not change going forward. There’s a very good alignment there. And then, yes, in regards to other changes, I think we want to clarify that with Waitsia, there was always a very wide range from 1P to 3P. And any time you have that, then it is reasonable when you get your data to expect the numbers will move around. So in that respect, I think these things are all very reasonable and significant new information.

And as Morne has highlighted, we’ve already reviewed the wells from offshore Otway. So we have some — we believe, stability there and then also a stability in the Cooper Basin, and we’ve clarified our position in the Waitsia and the Perth Basin. So I think we’re actually in pretty good shape. But as always, whenever we get new information, we’ll analyze that and we’ll come out to the market as soon as we can.

Operator

Your next question comes from Gordon Ramsay from RBC.

Gordon Ramsay

Congratulations Morne on your new capital management program. Very pleased to see that. Just a very quick question on the FY ’24 guidance. You’ve withdrawn that, and your previous aspirational target was 28 MMBoe, but you did highlight risks to that. The commentary today, to specifically mention the Clough administration process and regulatory approval uncertainty.

And I just want to get some more granularity from you on that, because clearly, from the Clough administration process, your recent guidance has implied around a 6-month delay on timing, and you’ve given the cost indications. So does this come down to other projects and specifically potential for Enterprise to push out beyond your previous guidance?

Morne Engelbrecht

Thanks, Gordon. So in terms of what we set out in terms of the reasoning there, like you have outlined the Clough administration process has at the time to the project. So there’s no doubt about that, and that’s what we’ve revised our guidance there, and obviously, the capital cost as well. I mean if you think about the Waitsia plant, and net Beach, our share, you’re looking at about up to 600,000 barrels a month, it doesn’t take a lot to start moving the dial in terms of the potential there from our production impact on the FY ’24 production target. So that is a main part of it. The other part, as you find as well as from an enterprise point of view, we’ve indicated that in FY ’24.

We still got a few hurdles to go there in terms of — specifically the weather has impacted us there. So in terms of starting the pipeline construction, there has been some supply chain issues there as well, and we still need some regulatory approvals to go on that one as well, before we can actually produce the gas. But in terms of what we’ve outlined, really, the Clough administration process is the main process on that. That’s impacted that.

Gordon Ramsay

And just with Enterprise, I think you previously mentioned there were some permitting issues, so maybe just your regulatory comment? Can you just provide more detail on that? Is that onshore?

Morne Engelbrecht

Yes. We just need approvals from the Victorian government around actually starting construction on the Enterprise well site. So once we have that, we can actually start the works and can actually start bringing stuff in to start connecting up from that point of view. So we just are waiting on that and once we have clarity on that, we can then start construction on the well side as well.

Gordon Ramsay

Okay. And just one other from me, Morne. At the beginning, when you started the presentation, you talked about the strength in the balance sheet and you’re targeting future growth. You mentioned new gas projects and other opportunities, what’s meant by new gas projects?

Morne Engelbrecht

Okay. That’s just what we outlined here today, Gordon, in terms of talking about the Otway offshore, in particular, in terms of connecting those wells, looking at how we progress our acreage more broadly in terms of the opportunity that’s there from an offshore point of view and nearshore as well. And then looking at Trefoil, White Ibis and Bass, and how we sort of link that up into our offshore developments there as well. So that’s what’s meant by that.

Operator

Your next question comes from Nik Burns from Jarden Australia.

Nik Burns

Look, given the time, I’ll just limit my questions to one. Just on Cooper Basin joint venture, just looking at your recent run on the success rate, 95% on 68 wells. This is a huge turnaround of 12 months ago. I think you participated in 32 wells in the first half ’22 at an 88% success rate. What’s changed here in terms of both the quantity and the quality of the drilling targets you’re going after here?

And how should we read this in terms of the outlook for production? I mean, obviously, there’s been a few quarters in recent times, we have seen quarter-on-quarter decline in gas production, but should we infer from this that higher production is ahead?

Morne Engelbrecht

Nick, so just to answer your question, I think we definitely got a higher proportion of development wells that we’ve agreed with Santos, in terms of that sort of 100 well sort of program that we’re going after. I think credit to the teams as well for working together in terms of looking at the prospectivity in the basin, looking at where the next well should be drilled. So there’s quite a good collaboration between the technical teams around what we should be going after in the basin. So I think that’s paying dividends for us and Santos as well. And then the other question you had is surround production. So we do see production stabilizing and slightly increasing from where we’ve seen over the previous quarters.

Again, we reported on some of the unplanned maintenance that happened last year and then impacted by weather as well in the basin. So I think there’s definitely more focus in terms of getting those wells back online and then also focusing on how we support production going forward in terms of looking at better quality development wells, bringing that online as well. So I think all around, good focus from the operator on production and getting production back up.

Operator

Your next question comes from Henry Meyer from Goldman Sachs.

Henry Meyer

Conscious of time, just a couple of quick ones for me. Obviously, more to play out on the East Coast regulatory environment, flagging Artisan and La Bella is expected. Is it fair to assume that you’d be happy to develop those fields at $12 a gigajoule perhaps inflating forward?

Morne Engelbrecht

Yes. Look, I think in terms of developing those fields, it would be great to get more clarity around the code of conduct and recently price of gas and provisions and how that would look like and how that would work and how we need to think about that going forward in terms of, whether it covers operating cost plus return plus exploration risk plus the abandonment costs, within those costs as well, to make an assessment on what — whether that’s reasonable for our projects going forward. So I think there’s some clarity needed before we get things going on that front. But in terms of $12 gas at the moment, when we look at those opportunities and you put those numbers to work on the project, if they make a return at $12, then I would assume that you would go ahead for those projects. But in terms of doing the economic analysis on that, it’s very difficult to do that with unclear regulatory guidance, in terms of how originally priced gas provisions will work going forward.

Henry Meyer

Got it. And maybe just a quick follow-up then, are you able to share any details on the process for sanctioning fields? I mean, do you test against a P50 and a low case outcome? And if you could share any IRR hurdle rates or otherwise that are required to sanction?

Morne Engelbrecht

Yes Henry, I think — I don’t see the hurdle rates, but obviously, it needs to be above our cost of capital and make us a return above our cost of capital. But in terms of looking at the projects, they go through a quite significant and detailed hurdle gate process as per usual. So we do assess them against a number of metrics, including returns and return on capital and they need to obviously compete against capital from other projects around our portfolio as well, before they’re sanctioned, but they go through a rigorous process. And as you would expect, we do stress test the projects in terms of low case outcomes, P50 and then obviously look at whether they — if they are better than expected, what does it mean from follow-on work and expansion of our activities as well. So that should cover the full gamut of how you would look at a project and before you sanction it.

Operator

Your next question comes from Sarah Kerr from Morgan Stanley.

Sarah Kerr

I just have 2 questions, if I may. I was wondering if I could get some further details on East Coast gas contracting? In your FY ’22 results presentation, you had 77% of FY ’24 East Coast gas volumes up for repricing or were uncontracted. I was wondering if we could get an update on the percent of FY ’24 East Coast gas volumes that have been contracted so far?

Morne Engelbrecht

Yes. Look, Sarah. So in terms of looking at our position currently in FY ’24 or looking ahead for 2024, we are — one of the key contracts that’s going to come up is around our Otway gas plant. So we are currently in negotiation around that. And obviously, that’s with Origin.

And as we’ve previously outlined, that contract sets out very clear, how you sort of reprice that contract from a — looking backwards over the last 3 years of comparable contracts in that comparable market. So we are currently negotiating that contract. So that will be the main contract that comes up in FY ’24, in terms of what we need to, I suppose, contract from a pricing point of view.

Sarah Kerr

And just quickly a follow-up, any update on historical Lattice contract repricing?

Morne Engelbrecht

No, that’s the main one that I’ve just mentioned in terms of Otway. The next one would be a year later, which is relating to the Cooper Basin JV volumes.

Sarah Kerr

Yes. Okay. Great. And my second question might be for Sam. With your trade prospect being located down dip of strike — South Erregulla discovery.

I was just wondering what your new 3D seismic survey was telling you about any potential still risks with strikes lock?

Stephen Algar

Yes. Thanks for the question, Sarah. It’s actually not down dip at all. We think it may be up dip and likely separate from the South Erregulla discovery. So yes, we have very clear 3D seismic, which covers the vast majority of it, and then goes 2D seismic into the strikes area.

So we’re pretty clear on that, to not link directly.

Operator

Your next question comes from Scott Ashton from SHA Energy.

Scott Ashton

Morne and Sam, just on the back of the last question. In the event of success for Trigg, how do you expect that to be developed? Is it daisy chained into Waitsia or Beharra, how would you see a success case being developed?

Morne Engelbrecht

Yes, thanks for the question, and a good one at that. I think my position on this has been — it’s very much dependent upon the scale of the volume. So that’s why we haven’t really been talking about that. We could get some very large upside volume, in which case that would give us pause for thought. Otherwise, as you say, putting it back into Waitsia is certainly something we’d consider as well.

So not yet to find.

Scott Ashton

Yes. I suppose given you’ve got a JV — not a JV participant, but you are a participant in the Perth Basin, that shows South Erregulla goimg into your block. So is unitization potentially on the cards here at some point, if you find out that the structure is actually joint?

Morne Engelbrecht

I think we’d have to defer that comment until further wells have proven up, whether that’s the case or not certainly from the data we’ve got at the moment, that’s not justifiable.

Scott Ashton

Yes. Okay. And just the very last one, I’m cognizant of the time. That’s a great table on all the prospects and leads there. I think I asked this question last time.

Obviously, you’re not chasing sort of 30 Bcf top targets. So pretty safe to assume that those targets there are sort of anywhere between 100 to 200 Bcf, to justify optimizing developments in the basin, rather than having [indiscernible] approach to plants that are sort of Beharra Springs type scale, are you looking to sort of take meaningful volumes?

Stephen Algar

Look, I think Scott we are not giving any guidance on potential there. But I think from your question, it’s definitely obvious that we will go for the bigger prospects and targets first before we go for the smaller ones. So we definitely want to see what that means for us and the basin, and how we think about development, and whether there’s expansion of plants that could be driven by this or whether it’s backfill to plants going forward. But definitely, from our perspective, we’re excited about the whole basin. So that’s why we’re going after these wells quite quickly in spending their capital.

And we’re quite excited what that means for us going forward in terms of supplying domestic gas market and looking at how we progress the basin. So we’re looking forward to the results.