Woodside Energy Group Ltd (WDS) Earnings Call Transcript & Summary

Thank you, Ashley. Well, good morning. Good evening, everyone, and thank you for joining us for this investor presentation. It is a pleasure to speak with you. I'd like to begin by acknowledging the First Nations people of the various lands on which we live and work and pay my respects to their Elders past and present. I'd also like to acknowledge that today in the United States is the Juneteenth Federal Holiday, which commemorates the emancipation of the enslaved people in the U.S. This is my first opportunity to speak publicly with you since the death of Michael Jurman at our North Rankin Complex in Western Australia earlier this month. Michael worked at North Rankin as a contractor and his tragic death is felt steeply and broadly. Our hearts go out to Michael's family, friends and colleagues. Investigations are underway into the incidents by the relevant authorities and Woodside to identify how we can ensure that our people are safe at work each and every day. Our excitement around today's announcement is tempered by sadness around Michael's passing. I'd now like to turn to the announcement we have released to the market. I'm pleased to announce Woodside has made a final investment decision to develop the Trion field. This is an important day for Woodside. Trion is the first major investment decision for the company following the merger with BHP Petroleum last year. And it is an asset that was part of the BHP Petroleum portfolio. Trion will be our fourth major project in the Gulf of Mexico, adding to our Shenzi, Atlantis and Mad Dog assets. It is a large, high-quality resource that will contribute to meeting the world's energy needs. It is important to note that the development remains subject to joint venture approval and regulatory approval of the field development plan, which is expected in the fourth quarter of 2023. Today, I will provide an overview of the proposed developments, why we are developing Trion and key considerations that have been undertaken before making this decision. We'll then open the call up to a question-and-answer session. Please note the standard disclaimer on Slides 2 and 3, advising that, amongst other things, this presentation does include some forward-looking statements and that our reported numbers are all in U.S. dollars unless otherwise indicated. Let's start with a summary of the investment rationale on Slide 4. Trion is a large, high-quality conventional resource, and we are targeting the development of an estimated 479 million barrels of oil equivalent of gross 2C Contingent Resource. The subsurface has been extensively appraised with 6 well penetrations across the field. This informs Woodside's understanding of the resource and provides confidence in the development plan. We have a clearly articulated capital allocation framework that includes targets to help guide investment decisions. The expected returns from Trion comfortably exceed these investment targets. The investment is expected to deliver an internal rate of return greater than 16% and a payback period of less than 4 years. This investment expands our global portfolio and assists in delivering long-term value. With the strong investment returns, Trion will be a key contributor to Woodside's cash flows and allow us to generate shareholder returns and fund future developments in oil, gas and new energy. Our capital allocation framework also requires new investments to be subject to Woodside's emissions reduction targets, Trion is no exception. Our net equity Scope 1 and 2 greenhouse gas emissions reduction target of 30% by 2030, and our net zero aspiration by 2050 remain unchanged. Scope 1 and 2, net equity emissions from Trion will be managed through our decarbonization strategy, which focuses on avoiding, reducing and authoring offsetting our emissions and is summarized in our climate report. Woodside has undertaken an extensive risk assessment, which supports this new country entry. We have a continued strong relationship with PEMEX, our joint venture partner,and have the confidence that the development is aligned with Mexico's ambition to grow production. We are very excited to be investing in Mexico. Slide 5 contains key project data. The offshore development will have a capacity of 100,000 barrels of oil per day through a new floating production unit. This will be connected to a floating storage and offloading unit or FSO with a capacity of 950,000 barrels. The FSO will be leased. With it's short payback, and the fact that 2/3 of the resource is expected to be produced within the first 10 years after startup, stranded asset risk is significantly reduced. In addition, Trion has a lower-than-average expected carbon intensity of 11.8 kilograms of CO2 equivalent per barrel of oil equivalent over the life of the field. Trion is well placed to compete in the global market. We have competitively tendered major scopes of the development, resulting in approximately 70% of total capital expenditure forecast as lump sum or fixed rates. The tendering process and direct engagement with contractors has confirmed both capability and capacity and has informed our forecast capital expenditure of $7.2 billion on a 100% basis. Woodside's share of total capital expenditure is $4.8 billion, which includes approximately $460 million of capital carry for PEMEX remaining as of the time of this decision. Slide 6 contains a conceptual image of the full integrated development. Trion is located in a water depth of 2,500 meters, approximately 180 kilometers of the Mexican coastline, and 30 kilometers south of the Mexico U.S. maritime border. Phase 1 of the development will be 18 wells , 9 producers, 7 water injectors and 2 gas injectors with an anticipated total of 24 wells drilled over the life of the Trion field. Crude is expected to be shipped to international markets and the development will include down-dip water injection and crestal gas injection improving recovery. The $7.2 billion forecast total capital expenditure covers the full 24 well development. Moving on to Slide 7. The Trion development leverages Woodside's proven expertise in deepwater project execution and we have taken this time required to optimize and mature the development concept. Front-end engineering design is complete following 30 months of engineering, which provided a high level of definition. Recognizing market volatility, we recently updated the tenders for major scopes to ensure confidence in the cost and execution plan. On the right side of this slide is a structure map of Trion. The 6 well penetrations are dispersed across the field. This coupled with high-quality seismic, including ocean bottom node seismic provides a high level of definition to support the development plan. Slide 8 contains an indicative graph of what we expect our capital spend will look like for Trion across the next 8 years with first oil targeted for 2028. The intention of this stylized chart is to demonstrate how peak capital spend in 2025 is matched to some of the key work strength on the project, to give an indication of the integrated project schedule. We don't expect the capital commitment in any year to exceed $1 billion Woodside share. The CapEx profile shows some spend will continue after first oil, which is targeted for 2028. This is in line with the drilling program with 18 wells targeted in Phase 1 and 24 wells targeted over the full developments. We are expecting to progressively execute key contracts following joint venture approval of the project. Moving on to Slide 9. We have the focus and discipline to move forward only those opportunities that are consistent with our vision to build a low-cost, lower-carbon, profitable, resilient and diversified portfolio. This slide demonstrates 6 key climate-related considerations which we factor into investment decisions. We believe that Trion is resilient in a decarbonizing world because of several factors. First, the short payback period of less than 4 years. Second, the fact that 2/3 of the resource is expected to be produced within the first 10 years after start-up. Third, our portfolio free cash flow resilience testing in the IEA net zero scenario. And fourth, Trion having an all-in breakeven below USD 50 a barrel, if you exclude the capital carry of PEMEX, the breakeven is below $43 a barrel. If we move to Slide 10, demand for oil is expected to continue across a range of climate pathways to 2050, including the net zero emissions or NZE scenario. Under these pathways, global oil supply will not meet future demand without additional investment. Our view is that this projected demand requires investments in existing fields or new fields like Trion, and that improved global emissions reductions outcomes could be achieved by investing in new low-cost and lower-carbon opportunities. On Slide 11, we've been hard at work reducing emissions through our design out philosophy. Designing out emissions is always our first preference and one of the 3 key pillars of our decarbonization strategy. In many cases, it not only reduces emissions, but also cuts costs and increases production of salable product. For Trion, this has been achieved through 2 key areas. The first of these is through increasing efficiency and design. For example, selecting high-efficiency compressors and utilizing heat recovery methods, which in turn reduce fuel consumption. The second area is through the design of reduced venting and flaring. Trion is designed for 0 routine flaring and includes a vapor recovery system, further reducing estimated emissions. Trion is well placed to help fill projected oil demand, given its expected carbon intensity of 11.8 kilograms of CO2 equivalent per barrel of oil equivalent averaged over the life of the field. It is among the lower intensity sources of oil as shown by the chart on this slide. Slide 12 provides an overview of the benefits of investing in Mexico. This development will be among Mexico's first deepwater developments and is well matched to Woodside's capabilities. Developing Trion delivers value for Woodside shareholders and significant benefits for Mexico, including jobs, taxation revenue and social benefit. We have developed a strong partnership with PEMEX. They benefit from our deepwater capability, and we benefit from their technical input and understanding of the regulatory environment. In closing, I want to take this opportunity to highlight once again the benefits of developing Trion. There are not a lot of undeveloped resources the size of Trion with the credentials of this development. It is a large, high-quality resource, which has been well-appraised. We have the right development plan and have recent market data to underpin our cost estimates and execution plans. We are making strong progress as we move into the next phase, targeting first oil in 2028. For Woodside, Trion is a disciplined investment, which is consistent with our strategy and capital allocation framework. It is expected to deliver significant returns with project economics of greater than 16% internal rate of return, an approximate 4-year payback period and a low all-in breakeven cost of less than $50 per barrel. Our strong balance sheet allows us to make this type of investments while balancing shareholder returns and protecting our investment-grade credit rating. Trion's lower-than-average expected carbon intensity means that it is well placed to fill demand for oil, which is expected to continue across a range of climate scenarios to 2050. Importantly, our corporate emissions reduction targets remain unchanged. With projects like Sangomar and Scarborough already in execution, I'm excited about adding Trion to the next phase of projects, maintaining momentum and continuing to build on our growth into the future, delivering energy the world needs. I'd now like to open the session up to your questions. Please limit your questions to 2 per person so we can ensure we get to everyone.

[Operator Instructions] Your first question comes from Mark Samter with MST Marquee.

Meg, a couple of questions if I can. Just the first one on obviously, I'm making this FID from the position of an exceptionally strong balance sheet. But I guess, as we go through a period of slightly weaker macro at the moment relative to where we were at least. And obviously, some of the execution risks that still remain over the other projects being built. How should we think about any future FIDs? Do we think they need to be funded by sell-downs or potentially addressing the dividend and how that looks in the future? Or do you think you still have balance sheet capacity to take. I don't know Browse is a long way off but obviously thinking JV partner movements there with these kind of assets. Yes, so can you just tell us how you contextualize future capital deployment on new projects?

Okay. Well, it's great to have you on the call, Mark, and really appreciate the opportunity to have one final call with you before you head off to your new job opportunity. As always, a good question about balance sheet. One of the things that we spent quite a bit of time on ahead of this decision was really testing the resilience of the balance sheet. Our capital management framework is quite clear. We're very committed to protecting our strong investment-grade credit rating and protecting our ability to return value to shareholders through the cycle through our dividend policy. So when we look at the investment opportunities like Trion and anything that might come along after Trion, we run a number of scenarios to test the resilience of the balance sheet to ensure that we have the funding capacity to do all 3 things, make sure we protect our credit rating, make sure we can pay dividends to shareholders and take on that new investment. So the modeling we've done for Trion give us confidence that we are able to do all those 3 things. Future investments. If you look at the profile of our capital spend for the ongoing projects, Sangomar is about 84% complete now. So we're getting close to the tail end of spending with that project. Scarborough, of course, still has a few years to go. So we'll be looking at that total capital load as we look at potential future investments. But as we've signaled, Mark, there's not a lot more in the hopper for this year. The Oklahoma project is the next big one. And when I say big, it's not in the same order of magnitude as Trion.

Okay. Perfect. Meg, just one more question if I can. I appreciate it's a very different project, but Equinor last week, I lose track of time, last week or the week before deferred their FID on Bay du Nord citing cost pressures. And I guess, whilst they are different projects, there might be a level of similarities and obviously that North American cost pressures that we're seeing. Can we talk through, a, I guess, what happened to the cost estimates as you went through the feed process? And b, how much exposure there is to run. I know you said about 70% being fixed, but just talk through some of the pressures you're seeing there and should we think about that 70% that you said will be contracted over the coming -- I can’'t remember what you said, months but in the near future, are those prices all locked? Or is there still some price risk around those as well?

Sure. So look, obviously, the market condition was one of the key reasons for us to go back out to the market last year. So prior to the merger, the organization had done a round of tendering and had preferred contractors identified but given the escalation in the inflationary environment we were in that was one of the reasons for extending the feed process and going back out into the market was to get confidence that we have bids that reflect current market conditions. We have that now. So we've -- for some of the key elements, selected the contractors. We've got the key contractors selected for the floating production unit and the FSO, for example. And for all of the other major costs scopes were down to a short list of 2 to 3 players underpinned by firm bids. So the cost confidence that we have is quite strong. Look, there are things that will continue to evolve as we go through detailed design, but we always maintain a bit of contingency and allowances, and that's really a normal part of the project cost estimating process.

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

I just had a question on the PEMEX capital carry of roughly $460 million for the development CapEx just wondering if you could please talk through the timing of that? And then I guess after that CapEx carry has been sort of completed then Woodside will fund their share of CapEx based on 60%. So just if you could please talk through the timing, please, of that for our modeling purposes?

Sure. So the way the initial buy-in to Trion happened was through a commitment to carry PEMEX through the first -- kind of the first tranche of spending. So the PEMEX carry will be spent in the first phases of the project once that is exhausted, then we revert to normal working interest funding. So we'll go to 60%, and they will go to 40%. And that split is reflected in the notional cost curve presented in the pack.

And then maybe just one last quick one. Just in terms of the oil quality at Trion, just with regards to the assumed discounted Brent that we should be assuming, any sort of guidance on that, please?

That's quite a detailed matter, James. We'll have the IR team follow up with you.

Okay. Okay. Well, I guess for simplicity, should we assume pricing based on WTI versus Brent crude?

Look, we're planning to export it. But as you can imagine, the nearest refineries to Trion are in the U.S. Gulf Coast, and so that's likely where the product will end up.

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

Meg, I was just wondering if you could talk about just different risk factors between sort of Senegal, Trion obviously both oil projects, one you're nearly finished there and one you're about to start. So is there anything that sort of stands out to you from a drilling or production perspective that you're sort of monitoring or looking out for?

Look, it's a great question, Adam, and I'm really pleased actually with how the project organization has come together. So it has been a great opportunity for the Trion team, who's a couple of years behind the Sangomar team to have a lot of dialogue around what's going well, what's been challenging. I'll remind you, of course, that Sangomar, we started -- we took FID in early 2020. So a lot of the early phase execution was influenced by COVID. And so the team had to come up with some creative ways to do things like manage quality when you had limited ability to physically get to sites. So we've certainly shared those experiences. The resources are a bit different. So Trion is more like the traditional Gulf of Mexico oil field. It's not sub-salt, which is worth noting. So the imaging quality is quite high and the drilling complexity is lower than many other Gulf of Mexico resources. Yes. Look, the 2 teams are collaborating really well and sharing information, but each is going to have its own unique risk factors.

Okay. That's good. And just second question, just on this sort of lease payment for the FSO, it's not in the $7.2 billion number. I'm assuming that's a pretty big part of operating costs. And is that a -- is that sort of various production over time? Or is it sort of fixed over the life of the contract?

No, it's over the life of the contract.

So pretty just fixed amount per year, effectively is the way to model it?

More or less for your modeling purposes that would be closest. Yes, from that contractor's perspective, it doesn't matter if they're processing any barrels or 950,000 at a parcel. So yes, for the contractor's risk management perspective, they want to have certainty in payments.

Your next question comes from James Byrne with Citi.

Congratulations on the FID. First one just around the field development plan. Look, obviously, Mexico is a pretty oil and gas friendly jurisdiction. Should we consider that FDP approval as a mere formality? Is there anything that could go wrong around FDP?

Look, we have been working very closely with PEMEX and the regulators. So the regulator is CNH, the Commission National Hydrocarbon. So they have good understanding of what we're planning to submit. We've worked closely to understand their expectations, but they are an independent regulator, and they will exercise their authority. But as I said, the joint venture has worked closely with them, built a very effective working relationship. I think probably the proof point is the fact that we've been able to drill a number of appraisal wells. So we now have a bit of experience with working with the regulator to get the approvals that we need to be able to progress. And again, I'd say being partners with the national oil company is very helpful in this situation. They've got a very long history with the regulator and understand what they're looking for and what sorts of things that we, as project developers need to present.

Yes, exactly. And so you'd have the confidence, I guess, to be ordering long-lead items ahead of that approval?

Yes, absolutely. We've actually ordered long leads already. And once the joint venture formally approve -- as I noted, this is the Woodside decision that the joint venture has to formally approve, but we'll be issuing limited notice to proceed to our main contractors.

Great. Okay. Second question -- go ahead, yes.

And then -- sorry, James, then full notice to proceed after the FDP approval.

Yes. Okay. Okay. So my second question, I think it was in your last quarterly, there was disclosure that Woodside had picked up 12 exploration licenses in Gulf of Mexico and 3 in Africa. I'm really interested to understand some of the rationale around that sort of increase in exploration exposure outside of Australia. Should we consider this as maybe providing the business a bit more optionality around -- outside of Australia?

Yes, so one of the things that was clear when we completed the merger and when we progressed the merger opportunity was the fact that the merger would give us greater optionality than either a heritage organization had. Exploration is part of that. If you ask how do we get growth in 10 or 15 years' time. We've got to start doing that organically. M&A, of course, is another tool that is in the toolkit, and we continue to explore. But we want to make sure that we do preserve the ability to develop assets by the bit. Now we're being pretty focused and very targeted. So we're focusing on basins that we know. We do have a footprint in the Gulf of Mexico with 3 very significant assets producing already. In Africa, we have the Sangomar opportunity, and we're securing some exploration opportunities near there as well. Now the key focus with exploration is managing cost risk. So you will note that we've been picking up blocks and/or farming down, trying to get to a more modest working interest than we might have carried historically. And we're also very keenly focused on pathway to commercialization. So as the team pursues exploration opportunities, it's with that mindset of how do we get things online fast.

Yes. I mean just picking up on that 10- to 15-year sort of time frame around that optionality, though. I mean you've already been copping a little bit of heat for sanctioning Trion from those you'd expect. But 10 to 15 years' time, we're well into the energy transition. We could debate about what energy demand might look like for oil and gas over that sort of time horizon. But are you confident in actually being able to create optionality with exploration now in the context of transition?

Sure, James. And James, part of the reason why we had 3 slides on energy transition in this pack was to really address those exact questions. And I would draw your attention to Slide 10, which presents the range of IPCC scenarios that are consistent with 1.5 degrees C of warming. And this shows that in both 2030 and 2040, to meet the world's energy demands, there needs to be new supply brought online. That can be through investments in existing fields or investment in new fields that offer the world's diversification from an energy security perspective, or offer a more competitive carbon intensity, which is the sort of thing that Trion offers. And so we do believe that oil will continue to be important into the 2040. This slide is the IPCC. So this is the world's set of pre-eminent scientists to study climate matters. And if you just eyeball the chart, that midpoint, the IEA APS, it's in that 75 million to 80 million barrels a year, 5 million barrels a day range. And so the world is going to continue to use oil for a very long time period.

Your next question comes from Gordon Ramsay with RBC Capital Markets.

Congratulations on moving forward with this project, Meg, I'm quite excited about it. I think the third well drilled on it had one of the biggest oil columns that were found in the Gulf of Mexico. Very quick question on the production volumes. I noticed on Slide 6 you've indicated flexibility to go to 120,000 barrels a day. But previously, the floating production unit capacity has been quoted at 100,000. Does that involve additional CapEx? And I'm just interested to get some comments on how you would get to 120,000?

Great question, Gordon. So nameplate of the facility is 100 kbd when we're producing early days with no water breakthrough, we can process 120,000. So first plateau period we are expecting to be handling 120,000. Not yet, but with your normal downtime, we won't average that over the year, but that's the sort of peak rate we're expecting as the facility is designed today.

Excellent. And my second question just relates around royalty rate. We've estimated it to be around 15%. Is that a fair assumption?

We'll have to circle back to you on that, Gordon. The terms are all published publicly. So Mexico, when they opened up the sector to international investors were very deliberate in ensuring public transparency on these matters. I don't have the number off the top of my head, but the team will get back to you and for the rest of you on the call, we'll make sure we include it in the transcript.

Your next question comes from Tom Allen with UBS.

Congratulations Meg and the broader team. Hoping you can please share some color on how long you expect to be able to maintain peak production? Just considering the CapEx staging that you've outlined, it extends a heavy CapEx burden years into first production. And then recognizing that you expect to produce 2/3 of the resource within the first 10 years?

Yes. Look, we haven't put that out there, Tom, but I think we've given you enough data to calculate your own production forecast with the ultimate recovery and the quantity that gets recovered in the first 10 years.

Okay. Sure, sure. I can remember that. And just secondly, I know the FID has taken on a contingent resource, obviously not a reserve. Can you just outline what the conversion that the team are expecting comes across from a 2C into a reserve and is implied to be produced in today's presentation? And maybe just outline some of the outstanding subsurface work and approvals before you bring in the reserve auditor and put it on the books?

Yes. So we need to have the field development plan approved. So that's the critical milestone for reclassification from contingent to P plus P.

Sure. That's the only item outstanding?

Correct. There's no further technical work anticipated.

Your next question from Nik Burns with Jarden Australia.

Just wanted to ask a question about the subsurface risks at the field at Slide 7, the map there. You've made the comment that there's 6 well penetrations dispersed across the field. All penetration seems to be on the eastern side of the field. Just wondering what gives you confidence around the crestal structure and the plan -- you're planning to drill a couple of gas injectors there, but also on the Western flank as well, you've got the fault there. I'm just wondering about your confidence on that part of the field, please?

Sure. So as I said, the seismic quality is very high over this field. One of the things that was done early on as well was to shoot ocean bottom node seismic. So that's where you basically instead of dragging the seismic array in the water column near the surface, you actually lay it down on the seabed. And so basically it removes 2,500 meters of water noise in your seismic data, that's provided us with really high-quality imaging. And so the team, of course, in their modeling has tested parameters like fault transmissibility. But with the data we have, we've pulled quite a bit of core. So it's quite a well-characterized asset actually.

Okay. Great. And my second question, I think at the investor briefing, your development concept for Trion discussed the possibility of a gas export pipeline. There was no mention of that here. I'm just wondering, is the plan still to build a gas pipeline and takes to sell some of the gas onshore? Or is that now not part of this plan?

There is a gas export pipeline. I'm looking at the cartoon on Page 6. I thought it was in here. Yes, it's there, it's the pink line that kind of goes around the subsea infrastructure on the seabed. So there is a gas export pipeline that is included in the $7.2 billion, 100% cost estimates. As I said, we will be doing crestal gas injection at the beginning, but there'll be a point in time where we will be able to export that gas and sell it to the local markets.

Your next question comes from Henry Meyer with Goldman Sachs.

Congratulations. First question, just there's a significant opportunity, I guess, to use the Trion FPU to establish a new hub and spoke model on the south side of the border. Have you had any discussions with PEMEX around potentially developing Maximino, Nobilis, Supremus into Trion? And if so, just any details on the potential tieback or concept for a development of those fields as well, please?

Yes. Well, thanks for the question, Henry. So our focus has very much been to get Trion over the line. That's the asset that we farmed into and have equity position in. Look, I'm sure, in due course, we'll continue to explore opportunities to utilize the hub. But at this point in time, our focus is getting the Trion decision and then moving into the execute phase, getting the hub built and then we can look at spokes to tie in. But you're absolutely right, I mean, it is -- there are other discoveries nearby, we're well aware of that, PEMEX is as well. So I'm sure in due course, we will be able to mature those conversations.

Right. And another question just on skew of risk in the reserve estimates, conscious you have provided a higher or low side estimate but could you comment on some of the risks and how they're skewed between static and dynamic properties? And if during the drilling process, you might be able to confirm a high level of confidence, please?

Look, we've done quite a bit of technical work modeling a range of uncertainties. Any field with secondary recovery, the question is always going to be around the rate of water movement through the field. So there are questions in that space, but the rock properties are pretty well defined.

This is the conference operator. We have temporarily lost connection with the speaker line. Please continue to hold, the conference will recommence shortly. Thank you all for holding. The conference is now reconnected.

Hello, Henry, can you hear me?

Meg, yes, back now.

Okay. Sorry about that. I'm not sure what happened. I think you had asked about skew of risk in reserve estimates. Look at, as I said, and I'm not sure how much you heard, we have high-quality seismic, which gives us confidence in the size and shape of the structure. Through the well penetration, we've got a good understanding of the rock quality. Look, the normal factors will come to bear, things like fault transmissibility and the quality of the resource around the perimeter. So I would describe it as a fairly typical range of reserve outcomes. But again, for decision purposes, 479 is the magic number.

Got it. Maybe if I could just squeeze in one other quick one if possible, please. I believe the merger document shared there was maybe another 100 million barrels in prospective resources in Northern Fault and maybe 25% of that could be recovered. Is this drilling plan expected to test those resources as well?

No, it's not Henry.

Your next question comes from Robert Stein with CLSA.

Just a quick one for me. On the enhanced oil recovery from day 1, just wondering what the risk of that 100 barrels a day -- 100,000 barrels a day estimate is. Is that -- is the IRR based on a sort of a midpoint estimate? Or are you sort of have factored in downside and potentially upside opportunities in coming up with that number?

Yes, Robert, we do quite a bit of extensive subsurface modeling, looking at variations to the geology and then variance on the production plan, the depletion plan, modeling different rates of water breakthrough, for example, and different fault transmissibilities. But as Gordon eyeballed, we actually have the capacity to produce 120,000 barrels a day when we're water-free. And so we do expect actually to have water-free production for a period. All of that has been modeled and accounted for in the economics.

[Operator Instructions] Your next question comes from Rob Koh with MS.

Congratulations on the announcement. Just a couple of questions on carbon, if I can. If you could give us a sense of the 11-ish kilos per barrel that you're not abating, just kind of what kinds of emissions they are? And then secondly, I believe Mexico actually has an ETS and is this project a liable entity within that? Or how have you modeled your carbon cost within your IRRs and payback, please?

Okay. So the emissions largely are from the power gen on the facility. So whilst we've taken steps to make sure that, that power gen is as efficient as it can be because of the remote location of the facility, we do have to generate our own power through gas combustion. Now as I said in the narrative, there are some things that we've done, things like heat recovery to try to minimize the power demand and minimize the gas that we have to consume in operations. We've got things like low-pressure vapor capture on both of the facilities, and so that's helped bring the emissions down, but the main sources are through the power gen. So the question on the Mexico ETS, we don't at least -- I'll get back to you if I've changed, but we don't believe this is covered by that system. Now the way we model the cost of carbon is we use an $80 a tonne price. So the carbon intensity that's modeled here, it's worth noting this is average over the life of the field. In the years of plateau production, it's actually quite a bit lower. And so some of you may have seen a report that was issued last week about Gulf of Mexico carbon intensity. Trion is very competitive with that in the early years. This is reflective of a full life cycle and it's very consistent actually with our other Gulf of Mexico assets, but $80 a tonne, to get to your question, Rob, is how we model the cost of carbon.

There are no further questions at this time. I'll now hand back to Ms. O'Neill for closing remarks.

All right. Well, thanks, everyone, for taking the time to participate in this call. In terms of upcoming events, Woodside's second quarter 2023 report will be released on the 19th of July and our half year report for 2023 on the 22nd of August. I look forward to speaking with you in August, and thanks again for your interest today.