WOODSIDE ENERGY GROUP LTD — Call Transcript 2023

Jun 20, 2023

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Woodside Energy Group Ltd ACN 004 898 962 Mia Yellagonga 11 Mount Street Perth WA 6000 Australia T +61 8 9348 4000 www.woodside.com

ASX: WDS NYSE: WDS LSE: WDS

Announcement

Wednesday, 21 June 2023

TRION TELECONFERENCE TRANSCRIPT

Date: 20 June 2023 Time: 11:00 AEST / 09:00 AWST (20:00 CDT on Monday, 19 June 2023)

Start of Transcript

Operator: Thank you for standing by and welcome to the Woodside Energy Group investor update. All participants are in a listen only mode. There will be a presentation followed by a question and answer session. If you wish to ask a question, you will need to press the star key followed by the number one on your telephone keypad. I would now like to hand the conference over to Ms Meg O'Neill, CEO and Managing Director. Please go ahead.

Meg O'Neill: 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 would 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 would also like to acknowledge that today in the United States is the Juneteenth federal holiday which commemorates the emancipation of enslaved people in the US.

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 deeply and broadly. Our hearts go out to Michael's family, friends and colleagues. Investigations are underway into the incident 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 would now like to turn to the announcement we have released to the market. I am 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 highquality 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 development, why we are developing Trion and key considerations that have

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been undertaken before making this decision. We will 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 US 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 six 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 four 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 cashflows 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 decarbonisation strategy which focuses on avoiding, reducing and offsetting our emissions and is summarised 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 the capacity of 950,000 barrels. The FSO will be leased.

With its short payback, and the fact that two thirds of the resource is expected to be produced within the first 10 years after start-up, 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 rate. The tendering process and direct engagement with contractors have 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 metres, approximately 180 kilometres off the Mexican coastline and 30 kilometres south of the MexicoUS Maritime Border. Phase 1 of the development will be 18 wells, nine producers, seven water injectors and two 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 downdip water injection and crestal gas injection improving recovery. The $7.2 billion forecast total capital expenditure covers the full 24-well development.

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Moving onto slide 7 . The Trion development leverages Woodside's proven expertise in deep-water project execution and we have taken the time required to optimise and mature the development concept. Front end engineering design is complete following 30 months of engineering which provided a high level of definition. Recognising 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 six 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 eight years, with first oil targeted for 2028. The intention of this stylised chart is to demonstrate how peak capital spend in 2025 is matched to some of the key workstreams 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 that 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 development. We are expecting to progressively execute key contracts following joint venture approval of the project.

Moving onto 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 six key climate related considerations which we factor into investment decisions. We believe that Trion is resilient in a decarbonising world because of several factors. First, the short payback period of less than four years. Second, the fact that two thirds of the resource is expected to be produced within the first 10 years after start-up. Third, our portfolio free cashflow resilience testing in the IEA net zero scenario. And fourth, Trion having an all-in break even below US$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 investment 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 have been hard at work reducing emissions through our design out philosophy. Designing out emissions is always our first preference and one of the three key pillars of our decarbonisation strategy. In many cases it not only reduces emissions, but also cuts costs and increases production of saleable product. For Trion this has been achieved through two key areas. The first of these is through increasing efficiency and design, for example, selecting high efficiency compressors and utilising 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 zero routine flaring, and includes a vapour 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 development 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 benefits. We have developed a strong partnership with Pemex. They benefit from our deep-water 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 estimate and execution plan. We are making strong progress as we move

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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 four 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 investment 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 am 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 would now like to open the session up to your questions. Please limit your questions to two per person so we can ensure we get to everyone.

Operator: Thank you. If you wish to ask a question, please press star one on your telephone and wait for your name to be announced. If you wish to cancel your request, please press star two. If you are on a speakerphone, please pick up the handset to ask your question. Your first question comes from Mark Samter with MST Marquee. Please go ahead.

Mark Samter: (MST Marquee, Analyst) Yes, hi Meg. A couple of questions if I can. Just a first one on - obviously you are 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 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 selldowns 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, I know Browse is a long way off, but obviously thinking JV partner movements there with these kind of assets. Can you just tell us how you contextualise the future capital deployment on new projects?

Meg O'Neill: Okay. Well, look, 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.

Mark Samter: (MST Marquee, Analyst) Thank you.

Meg O'Neill: 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 are 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. 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 three things, you know, make sure we protect our credit rating, make sure we can pay dividends to shareholders and take on that new investment.

The modelling we have done for Trion give us confidence that we are able to do all those three 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 will be looking at that total capital load as we look at potential future investments, but as we have signalled 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.

Mark Samter: (MST Marquee, Analyst) Okay, perfect. Thanks Meg. Then 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’re different projects there might be a level of similarity and obviously the North American cost pressures that we're seeing.

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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 can you just talk through some of the pressures you're seeing there and should we think about that 70% that you've 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?

Meg O'Neill: Sure. Look, obviously the market conditions were one of the key reasons for us to go back out to the market last year. Prior to the merger the organisation had done a round of tendering and had preferred contractors identified but given the escalation and 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 in the FSO for example.

For all of the other major cost scopes, we’re down to a short list of two to three 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.

Mark Samter: (MST Marquee, Analyst) Cool, perfect, thanks. Thanks Meg and congrats again.

Meg O’Neill: Thanks Mark.

Operator: Your next question come from James Redfern with Bank of America. Please go ahead.

James Redfern: (Bank of America, Analyst) Hi Meg, hope you’re well. 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, for that, for our modelling purposes.

Meg O’Neill: Sure. So the way that initial buy-in to Trion happened was through a commitment to carry Pemex through 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%. That split is reflected in the notional cost curve presented in the pack.

James Redfern: (Bank of America, Analyst) Thank you. Thank you very much. Then maybe just one last quick one, just in terms of the oil quality at Trion, just with regards to the assumed discount to Brent that we should be assuming, any guidance on that please?

Meg O’Neill: That’s quite a detailed matter, James. We’ll have the IR team follow up with you.

James Redfern: (Bank of America, Analyst) Okay, well I guess for simplicity, shall we assume pricing based on WTI versus Brent crude?

Meg O’Neill: Look, we’re planning to export it, but as you can imagine, the nearest refineries to Trion are in the US Gulf Coast, so that’s likely where the product will end up.

James Redfern: (Bank of America, Analyst) Okay, great. Okay, thanks Meg, thank you.

Operator: Your next question comes from Adam Martin with E&P Financial. Please go ahead.

Adam Martin: (E&P Financial, Analyst) Yes, morning Meg, just wondering if you could talk about different risk factors between Senegal, Trion, obviously both oil projects, one you’re nearly finished there and one

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you’re about to start, so is there anything that stands out to you from a drilling or production perspective that you’re monitoring or looking out for?

Meg O’Neill: Look it’s a great question, Adam and I’m really pleased actually with how the project’s organisation has come together, so it has been a great opportunity for the Trion team who is 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, 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 site. So we’ve certainly shared those experiences.

The resources are a bit different. So Trion is more like a traditional Gulf of Mexico oil field. It’s not subsalt, 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 two teams are collaborating really well and sharing information, but each is going to have its own unique risk factors.

Adam Martin: (E&P Financial, Analyst) Okay, that’s good and just second question, just on this 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 various production over time or is it sort of fixed over the life of the contract?

Meg O’Neill: No, it’s over the life of the contract.

Adam Martin: (E&P Financial, Analyst) So pretty, just fixed amount per year effectively is the way to model it.

Meg O’Neill: More or less for your modelling purposes, that’d be the closest.

Adam Martin: (E&P Financial, Analyst) Okay.

Meg O’Neill: Yes, from that contractor’s perspective, it doesn’t matter if they’re processing any barrels or 950,000 at a partial, so yes, for the contractor’s risk management perspective, they want to have certainty in payments.

Adam Martin: (E&P Financial, Analyst) Yes, that makes sense. Okay, thank you.

Operator: Your next question comes from James Byrne with Citi. Please go ahead.

James Byrne: (Citi, Analyst) Thank you, good morning, 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?

Meg O’Neill: Look we have been working very closely with Pemex and the regulator, so the regulator is CNH, the Commission National Hydrocarbon, so they have a 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 yeah, we now have a bit of experience with working with the regulator to get the approvals that we need to be able to progress. 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.

James Byrne: (Citi, Analyst) Yes, exactly and so you’d have the confidence, I guess, to be ordering long lead items ahead of that approval?

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Meg O’Neill: Yes, absolutely. We’ve actually ordered long leads already and once the joint venture formally approves, 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.

James Byrne: (Citi, Analyst) Great, okay. Second question – go ahead.

Meg O’Neill: Then, sorry James, then full notice to proceed after the FDP approval.

James Byrne: (Citi, Analyst) 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 licences in Gulf of Mexico and three 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?

Meg O’Neill: 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 heritage organisation 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 three very significant assets producing already. In Africa we have the Sangomar opportunity and we’re securing some exploration opportunities near there as well. The key focus with exploration is managing cost risks, so you’ll 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 commercialisation. So as the team pursues exploration opportunities, it’s with that mindset of how do we get things online fast.

James Byrne: (Citi, Analyst) Yes, I mean just picking up on that 10- to 15-year sort of timeframe 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 in terms of it 10 years’ time, we’re well into the energy transition, we could debate about what energy demands 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 the transition?

Meg O’Neill: Sure James, and James, part of the reason why we had three slides on energy transition in this pack was to really address those exact questions. 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 demand there needs to be new supply brought online. That can be through investment in existing fields or investment in new fields that offer the world diversification from an energy security perspective or offer a more competitive carbon intensity, which is the sort of thing that Trion offers.

So we do believe that oil will continue to be important into the 2040s. This slide is the IPCC, so this is the world’s set of preeminent scientists who study climate matters and if you just eyeball the chart, that midpoint, the IEA APS, in that 75 million to 80 million barrels a year, sorry, million barrels a day range. So the world’s going to continue to use oil for a very long time period.

James Byrne: (Citi, Analyst) Great, okay. Thanks so much, Meg, appreciate it.

Meg O’Neill: Thanks James.

Operator: Your next question comes from Gordon Ramsay with RBC Capital Markets. Please go ahead.

Gordon Ramsay: (RBC Capital Markets, Analyst) Thank you very much and 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

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biggest oil columns ever 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. Does that involve additional capex and I’m just interested to get some comments on how you would get to 120.

Meg O’Neill: So 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.

Gordon Ramsay: (RBC Capital Markets, Analyst) Perfect.

Meg O’Neill: So first plateau period, we’re expecting to be handling 120. Not yet, 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.

Gordon Ramsay: (RBC Capital Markets, Analyst) Excellent and my second question just relates around royalty rate. We’ve estimated it to be around 15%. Is that a fair assumption?

Meg O’Neill: 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.

Gordon Ramsay: (RBC Capital Markets, Analyst) Yes, thank you very much.

Meg O’Neill: For the rest of you on the call, we’ll make sure we include it in the transcript. [Clarification: The royalty rate is a sliding scale, based on a US$70/bbl assumption the overall effective rate is expected to be between 12% to 14%].

Gordon Ramsay: (RBC Capital Markets, Analyst) Yes, thanks.

Operator: Your next question comes from Tom Allen with UBS. Please go ahead.

Tom Allen: (UBS, Analyst) Congratulations Meg and the broader team. I’m hoping you can please share some colour 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 recognising that you expect to produce two-thirds of the resource within the first 10 years.

Meg O’Neill: Yes, look we haven’t put that out there Tom, but I think we’ve given you enough data to calculate your own production forecasts with ultimate recovery and the quantity that gets recovered in the first 10 years.

Tom Allen: (UBS, Analyst) Okay, sure. I can run with that. Just secondly, I note the FID has taken on a contingent resource, obviously not a reserve, can you just outline 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? Maybe just outline some of the outstanding subsurface work in approvals before you bring in the reserve auditor and put it on the books.

Meg O’Neill: Yes, so we need to have the field development plan approved, so that’s the critical milestone for reclassification from contingent to P+P.

Tom Allen: (UBS, Analyst) Sure. That’s the only item outstanding?

Meg O’Neill: Correct, there’s no further technical work anticipated.

Tom Allen: (UBS, Analyst) Okay, thanks Meg.

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Meg O’Neill: Thanks Tom.

Operator: Your next question comes from Nik Burns with Jarden Australia. Please go ahead.

Nik Burns: (Jarden Australia, Analyst) Thanks Meg and thanks for the slide pack and presentation today. Just wanted to ask a question about the subsurface risks at the field. Slide 7, the map there, you make the comment that there’s six well penetrations disbursed 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, just wondering about your confidence on that part of the field please.

Meg O’Neill: 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, so basically removes 2500 metres of water noise in your seismic data. That’s provide us with really high-quality imaging. So the team of course in their modelling have 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 characterised asset actually.

Nik Burns: (Jarden Australia, Analyst) Great. 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 take – to sell some of the gas onshore or is that now not part of this plan? Thanks.

Meg O’Neill: So 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 estimate. As I said, we will be doing crestal gas injection at the beginning, but there will be a point in time where we’ll be able to export that gas and sell it to the local market.

Nik Burns: (Jarden Australia, Analyst) Perfect, thanks Meg.

Operator: The next question comes from Henry Meyer with Goldman Sachs. Please go ahead.

Henry Meyer: (Goldman Sachs, Analyst) Thanks Meg and congratulations. First question, there’s a significant opportunity I guess to use the Trion FPU to establish a new hub and spoke model on the southside of the border. Have you had any discussions with Pemex around potentially developing Maximino, Nobilis, Supremus into Trion? If so, just any details on the potential tieback or concept for a development of those fields as well please?

Meg O’Neill: Yes, 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 utilise 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.

Henry Meyer: (Goldman Sachs, Analyst) Great, thanks Meg. My other question just on skew of risk in the reserve estimates, conscious you haven’t provided a higher or lower side estimate, but could you comment on some of the risks in how they’re skewed between static and dynamic properties and if during the drilling process you might be able to confirm a higher level of confidence, please?

Meg O’Neill: Look, we’ve done quite a bit of technical work, modelling 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 [blank audio].

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Operator: This is the conference operator. We have temporary lost connection with the speaker line. Please continue to hold, the conference will recommence shortly.

[Pause]

Operator: Thank you all for holding, The conference is now reconnected.

Meg O’Neill: Hello Henry, can you hear me?

Henry Meyer: (Goldman Sachs, Analyst) Hey Meg, yes, back now.

Meg O’Neill: Okay, sorry about that, not sure what happened. I think you had asked about skew of risk in reserve estimates. Look 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, 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.

Henry Meyer: (Goldman Sachs, Analyst) Got it, thanks Meg. 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 the Northern Fault and maybe 25% of that could be recovered. Is this drilling plan expected to test those resources as well?

Meg O’Neill: No, it’s not Henry.

Henry Meyer: (Goldman Sachs, Analyst) Okay, thank you.

Operator: Your next question comes from Robert Stein with CLSA. Please go ahead.

Robert Stein: (CLSA, Analyst) Hi Meg and thanks for the opportunity. Just a quick one from me; on the enhanced oil recovery from day one, just wondering what the risk of that 100,000 barrels a day estimate is? Is the IRR based on a midpoint estimate or have you factored in downside and potentially upside opportunities in coming up with that number?

Meg O’Neill: Yes, Robert we do quite a bit of extensive sub-surface modelling, looking at variations to the geology and then variance on the production plan, the depletion plan, modelling different rates of water breakthrough for example in different fault transmissibilities.

But as Gordon eyeballed, we actually have the capacity to produce 120,000 barrels a day when we’re water free. So we do expect actually to have water free production for a period. All of that has been modelled and accounted for in the economics.

Robert Stein: (CLSA, Analyst) Thank you.

Meg O’Neill: Thanks Robert.

Operator: Once again, if you wish to ask a question, please press star one on your telephone and wait for your name to be announced. Your next question comes from Rob Koh with MS. Please go ahead.

Rob Koh: (Morgan Stanley, Analyst) Good morning. Thank you very much and 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 are not abating, just what kinds of emissions they are. Then secondly, I believe Mexico actually has an ETS and is this project a liable entity within that or how have you modelled your carbon cost within your IRRs and payback please?

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Meg O’Neill: Okay, so the emissions largely are from the power gen on the facility. 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 minimise the power demand and minimise the gas that we have to consume in operations. We’ve got things like low pressure vapour capture, on both of the facilities. So that’s helped bring the emissions down. The main sources are through the power gen.

So the question on the Mexico ETS, we don’t wish to - I’ll get back to you if I’ve changed but we don’t believe this 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 modelled 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. 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 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.

Rob Koh: (Morgan Stanley, Analyst) Okay, thank you so much.

Operator: There are no further questions at this time. I will now hand back to Ms O’Neill for closing remarks.

Meg O’Neill: All right, well thanks everyone for taking time to participate in this call. In terms of upcoming events, Woodside Second Quarter 2023 Report will be released on 19 July and our half year reports for 2023 on 22 August. I look forward to speaking with you in August and thanks again for your interest today.

Operator: That does conclude our conference for today. Thank you for participating. You may now disconnect.

End of Transcript

Contacts:

INVESTORS

MEDIA

Matthew Turnbull (Group) Christine Forster M: +61 410 471 079 M: +61 484 112 469 E: christine.forster@woodside.com

Sarah Peyman (Australia) M: +61 457 513 249

Rohan Goudge (US) M: +1 (713) 679-1550

E: investor@woodside.com

This announcement was approved and authorised for release by Woodside’s Disclosure Committee.

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