WOPEF Woodside Energy Group Ltd (PK)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 6-K

REPORT OF FOREIGN PRIVATE ISSUER

PURSUANT TO RULE 13a-16 OR 15d-16

UNDER THE SECURITIES EXCHANGE ACT OF 1934

For the month of June 2024

Commission File Number: 001-41404

Woodside Energy Group Ltd

(ABN 55 004 898 962)

(Registrant’s name)

Woodside Energy Group Ltd

Mia Yellagonga, 11 Mount Street

Perth, Western Australia 6000

Australia

(Address of principal executive offices)

Indicate by check mark whether the registrant files or will file annual reports under cover of Form 20-F or Form 40-F.

Form 20-F ☑    Form 40-F ☐

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1): ☐

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(7): ☐

EXHIBIT INDEX

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Dated: June 12, 2024

Exhibit 99.1

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, 12 June 2024

SANGOMAR FIRST OIL TELECONFERENCE TRANSCRIPT

Date: 11 June 2024

Time: 11:30 AEST / 09:30 AWST / 20:30 CDT (Monday, 10 June 2024)

Start of Transcript

Operator: Thank you for standing by and welcome to the Woodside Energy Group Limited Investor Call. 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: Welcome everyone to this call. 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, present and emerging.

Today I am joined on the call by Shiva McMahon, our Executive Vice President for International Operations. We are very pleased to be here today, having achieved first oil from the Sangomar Field offshore Senegal. This is a momentous occasion for Woodside, our joint venture partner PETROSEN, the government and the people of Senegal.

Please note the standard disclaimer on Slide 2 advising that, among other things, this presentation does include some forward-looking statements and that our reported numbers are all in US dollars unless otherwise indicated.

Slide 3. Let me begin with a brief overview of our business. As you saw in our first quarter 2024 report, the business is in great shape. We have been making significant progress on our three major growth projects, Sangomar, Scarborough and Trion.

For Scarborough, we have completed the sale of a 10% interest in the project to LNG Japan and entered into an agreement with JERA for the sale of a further 15.1%. We recently signed a loan agreement with the Japan Bank for International Cooperation, or JBIC for short, to fund the Scarborough Energy Project.

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Collectively, these agreements build on our long relationships in Japan and reinforce the strategic importance of Australian LNG to Japan.

Additionally, in February 2024, we signed a long-term LNG offtake contract with KOGAS, further demonstrating the market demand for our key product.

The Trion project continues to progress engineering procurement and contracting activities and we look forward to first steel cut for the offshore platform later this year.

Today, we are here to talk about Sangomar. The achievement of first oil at Sangomar is a key milestone and represents delivery against our strategy. We are providing products that help meet the world’s demand for energy. The crude quality of Sangomar is similar to grades such as Oman and Johan Sverdrup. We expect the crude to be mainly processed by refineries in Europe and Asia and we are seeing solid demand for our product in the market and have already sold our first few cargos, both of which are expected to go to Europe.

Now to recap the development, the Sangomar Field’s development phase 1 features the FPSO Léopold Sédar Senghor, named after the first president of Senegal. The FPSO is located approximately 100 kilometres offshore of Senegal. Production capacity is approximately 100,000 barrels of oil per day and the vessel is moored above the fields in a water depth of approximately 800 metres.

The development for phase 1 has 11 producers, 10 water injectors and two gas injectors which are all subsea wells. The RSSD joint venture has also approved a twenty-fourth well. We are very pleased with the drilling progress and have achieved well results in line with expectations. Over 80% of phase 1 production comes from the S500 reservoirs. These are high quality continuous reservoirs.

Phase 1 also includes a pilot of the upper S400 reservoirs. These reservoirs are more complex but contain large amounts of oil in place. The focus of the pilot is de-risking communication between the injectors and producers in the S400 reservoirs.

This development plays well to our deepwater capabilities. The pipelay alone was identified as one of the most challenging reel pipeline scopes undertaken by our contractor. This complex operation required an upgrade of the pipelay vessel to enable the lay of the pipeline with multiple heavy subsea structures.

While we saw some challenges during construction related to execution activities in China during the height of the COVID-19 pandemic, the decision to complete construction and remediation work in Singapore has proven to be the right decision. We have been very pleased with what we have seen in country while commissioning the facility.

We are proud of the relationships we have built with PETROSEN, our contractors and the government. The Sangomar development has already delivered benefits to Senegal. Overall, the project, including our contractors, employed more than 4,400 Senegalese people and has spent approximately $177 million with local suppliers. We will continue to work closely with our contractors to build local capability for the operations phase.

I would like to take this opportunity to congratulate the recently elected President Faye. We look forward to continuing to work with the government of Senegal. The new government has been appointed and Shiva was recently in country where she had a positive meeting with the Minister of Energy Petroleum and Mines, Minister Diop.

Going to Slide 5, the fiscal framework in Senegal is different from our main operating areas in Australia and the Gulf of Mexico. In Senegal, we have a production sharing contract. At the highest level, 75% of revenue can be used to recover costs, including operating expenditure, capital expenditure from the execution phase, capital expenditure that predates the FID decision and fees that are paid to the government. The remaining revenue is split, with the government’s share of 15% to 20% at our expected production rates. Corporate income tax is 33% and there is a 10% branch income tax applied to income after income tax. Additionally, there are minor levies and payments.

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Going to Slide 6 and back to our strategy, delivering Sangomar is a key milestone for Woodside. We took final investment decisions on Sangomar and Scarborough at a time when many companies were scaling back. 2023 was our peak CAPEX year and with Sangomar first oil we will begin to realise the benefits of these decisions. Achieving first oil from Sangomar will be the start of cash generation from these major capital projects, with Scarborough targeting first LNG cargo in 2026 and Trion targeting first oil in 2028.

I appreciate your interest in the Sangomar development and am proud we are delivering on our strategy. With that, I would like to open up to any question you may have and appreciate if we would keep the questions focused on the Sangomar developments.

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 Wiseman from Macquarie. Please go ahead.

Mark Wiseman: (Macquarie Group, Analyst) G’day Meg and team. Congratulations, huge milestone today. I just wanted to ask around crude pricing. There were reports that you’d sold a couple of cargos for delivery in July. Could you just confirm the - my understanding is the medium viscosity, medium sulphur crude, should we be thinking about this being priced relative to Dubai or Brent and do you have any comments on the pricing outcomes that you’ve achieved so far? Thanks.

Meg O’Neill: Thanks for the question, Mark. Look, I’d flagged that the grades that the Sangomar crude is quite similar to are Oman and Johan Sverdrup. I’m sure you can find the analogues and the data for that. I guess to be specific from an API perspective, it’s 31 API and about 1% sulphur.

Mark Wiseman: (Macquarie Group, Analyst) On the pricing, are you able to confirm the two cargos that you’ve sold, what they were benchmarked to?

Meg O’Neill: I’ll confirm that we’ve sold two cargos, but I’m sure you would appreciate that any time you’re bringing a new product to market, the refiners want to have a fair amount of data. We’ve provided assays and samples to the refiners that we’ve been meeting with to give them confidence and a better understanding of the quality of the crude but, as I said, Oman and Johan Sverdrup are probably the best benchmarks for you.

Mark Wiseman: (Macquarie Group, Analyst) Okay, great. Thank you.

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

Tom Allen: (UBS, Analyst) Morning Meg. Congratulations to you and the team on the first oil milestone. Given the geology of Sangomar is believed to be relatively complex, can you please share an estimated well performance range, or a productivity index that Woodside is expecting from the first phase producing wells that are targeting the lower risk deeper S500 sands?

Meg O’Neill: Yes, thanks Tom. I know there is a lot of interest in the well performance, and so maybe it’s good to set the stage a little bit for how the wells have come in. For those of you who know me well, you know I’m an engineer, I’m a reservoir engineer, or a reformed one, so I watch this very closely. I get the daily drilling reports and I’ve seen the log data from every well we’ve drilled.

I’m really pleased to report that the reservoir quality has been very, very close to our pre-drill prediction. So, the S500, this is the lower sands, very high quality, highly continuous reservoir. This is the sweet spot that we’re targeting with the phase 1 development.

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We’ve seen the high-quality reservoir sands that we were expecting and we’ve been drilling very long, horizontal wells, so something like 1,500-metre horizontal wells. The geo-steering technology we’re using enables us to place the well very precisely and understand offset from things like gas cap and water contact.

The drilling performance has really been outstanding and reservoir is coming in right on prediction. The S400, as I said in the opening remarks, is an aerially extensive large reservoir, geologically more complex. The permeability is a bit lower but again, we’ve been really successful in geo-steering those wells and being able to penetrate the targets exactly as we had expected.

Now, from a well capacity perspective, in the S500s we are seeing capacities up to 20,000 barrels a day and the first well that we’re flowing has been flowing at 20,000 barrels a day for our target first oil period of 72 hours. So, really pleased with the deliverability.

The caution I’ll give you, Tom, though is you can’t take that number and multiply it by 12 for all of our producers because of the subsea architecture that we have. We have a fairly complex subsea architecture with two flow loops, one to the north of the field, one to the south of the field, and we will be comingling the production wells into those flow loops. So, we do expect over the course of the rest of the year to be ramping up towards nameplate capacity as we bring those wells online in a stepwise manner but the individual well capacity in the 500s particularly is very strong.

Tom Allen: (UBS, Analyst) Thanks, Meg. Are you able to share a P50 range for what you think your producing wells might flow at peak oil?

Meg O’Neill: I’d be averse to doing that, Tom, because we’ll be facility or flow-line constrained. So, as we’ve said, nameplate is 100,000 barrels a day; that’s at the facility. There is a fairly delicate balancing operation to get the two flow line loops balanced well. We need to get water injection and gas injection up and running. As we optimise the field, we’ll be opening chokes on certain wells and choking back other wells. But from an overall headline performance perspective, we do expect to be meeting our production range outlook that we had already communicated to markets with this result.

Tom Allen: (UBS, Analyst) Okay, great. Thanks for the colour, Meg.

Meg O’Neill: Thanks, Tom.

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

Adam Martin: (E&P Financial, Analyst) Morning Meg and Shiva. Maybe - there’s obviously been some market concern around the incoming President talking about adjusting fiscal terms. Maybe you could address that, maybe a good opportunity for Shiva given her recent visit there as well, but perhaps you could discuss that, please.

Meg O’Neill: Sure. Take it away, Shiva.

Shiva McMahon: Thanks, Meg. Yes, as Meg mentioned, I visited Senegal the week before last and as you know, many of the government officials have now been appointed so we’ve been—we’ve started to hold introductory meetings with them. I had the opportunity to meet with the Minister of Energy, Petroleum and Mines Minister Diop and it was basically to provide an update on the progress that we’ve made on Sangomar, and also to reiterate our commitment and the fact that Woodside is really looking forward to working with the government of Senegal going forward. It was a very good meeting, it was a very positive meeting, and Minister Diop also reiterated and reinforced the importance of respecting of contractual obligations by all parties.

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I know there have been different rumours in the market but the reality is and our experience has shown that the most successful jurisdictions are those that have been working together with the industry, respecting contract sanctity, and those that create a stable investment environment. We also conduct our business with integrity and work well and support governments that hold the same values. We know that the Senegalese Government is committed to these principles as well.

We appreciated the President’s recent comments welcoming private partnerships and reinforcing the state’s commitment to upholding the rule of law and of protecting investor rights. Overall, I would say it was a very positive visit and a very positive start to our relationship with the new government.

Adam Martin: (E&P Financial, Analyst) Okay. Thank you. Second question just on the pilot program in the S400 reservoir, I think it’s about 270 million barrels of 2C across oil and gas in those upper zones. Could you just talk through what your objectives are, when we might learn the outcomes of that, etc?

Meg O’Neill: Sure. The key question, Adam, in the S400 is the ability for water to sweep from the injection wells to the production wells. Some of the complexity is - we see in the seismic data that there are what we call geo bodies, so smaller geologic bodies, and we believe that there should be communication along the length of these bodies. We were verry successful in placing the wells, and as I said, drilling through the different geo bodies that we have targeted, but the key is to get that dynamic data. That dynamic data will start to come in towards the backend of this year. We’ll need to have a bit of time to understand how the reservoir is performing, update our models. So, I’d say it will take 12 to 24 months to really understand what’s happening in the S400s and what that means for future phases of development.

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

Meg O’Neill: Thanks, Adam.

Operator: Thank you. Your next question comes from Gordon Ramsay from RBC. Please go ahead.

Gordon Ramsay: (RBC, Analyst) Hi. I just wanted to congratulate Woodside for bringing this project onstream. It’s been a long time coming and sounds like a very good start. I’ve just got a follow-up from Adam’s questions. I’m really interested in the S400 and I guess you’ve said back end of this year, 12 to 24 months you’ll have a better understanding. Would that enable you to commit to a phase 2 for the S400, which in my understanding has a significant volume of oil in place and it would be nice to recover as much of that as you can. So, will these four wells enable you to potentially move to a second phase or will you need more drilling to do that?

Meg O’Neill: Thanks, Gordon, and appreciate the congratulations. I know you’re also a subsurface person so hopefully you appreciated the additional detail there. You’re spot on. The S400 is where there is significant in-place oil potential. Just to clarify, we have four injector producer pairs, so we’ll get a reasonable amount of dynamic data in this first phase of development, and that data will inform what future phases look like. Now, bear in mind that of course we’ll have the data, we’ll be updating our reservoir models between the decision points and execute will take a bit of time. We’ll have to do more feed work, but we have designed the facility to enable that expansion potential. So, we’ll certainly be keeping you and the market updated as we get that data in and as we mature our thinking on phase 2.

Gordon Ramsay: (RBC, Analyst) Just one other one from me, Meg, thank you, just on your nameplate. I think I asked you about Trion before. When you talk about 100,000 barrels of oil per day, you did mention water and gas injection up and running. Does the facility have capacity obviously for total liquids to be much higher than that? In other words, could we have sustained that circa 100,000 barrels a day of oil production for longer with the addition of the water and gas or with the 100,000 barrels a day the actual fluid limit on the FPSO?

Meg O’Neill: So, 100,000 barrels a day is the oil limit. The total liquid handling is bigger. I don’t have that number at hand right now but we can have the team follow up with you. That is the oil peak rate. That’s what we would expect would be the peak. It’s probably worth reminding all of you who are building models that it’s appropriate to consider a certain amount of downtime, particularly with new facilities as we get the equipment up and running.

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Gordon Ramsay: (RBC, Analyst) Excellent. Thank you very much, really appreciate it.

Meg O’Neill: Thanks, Gordon.

Operator: Thank you. Your next question comes from Henry Meyer from Goldman Sachs. Please go ahead.

Henry Meyer: (Goldman Sachs, Analyst) Morning, Meg and Shiva. Congratulations and thanks for the updates. I’m hoping, if we can, to try and expand a little bit on the ramp-up profile please. I guess we’ve been spoiled with a bit of information in the past from the BHP acquisition. In that report, we had a low case peak average annualised rate around 65,000 barrels, best case getting towards 75. Is it fair to assume that this information or forecast is still the best estimate or have you received any more information that might mean you could sustain in plateau rates for longer?

Meg O’Neill: Well, if that’s the independent expert report, so that’s a few years old. That probably would have been based on the FID plan and would have been early drilling results. Look, let us get back to you on that particular question, Henry. I’d say that again, the well results have come in very close to expectation. The reservoir quality looks good, the well placement has been fantastic, but it is a complex facility especially with the subsea architecture to operationalise and we’ll need to go through and check the assumptions that were used in that independent expert report.

Henry Meyer: (Goldman Sachs, Analyst) Got it. Thanks, Meg. Maybe if you can expand a little bit more on the S400s. Obviously, considering the recovery fractures on the S400s is incredibly low and you’ve more or less completed drilling now, has there been any more encouraging static data, the thickness or otherwise, that could support a bit more positivity or encouragement in going for a phase 2 development or potentially a larger resource size?

Meg O’Neill: Well, I think the resource size, there’s no dispute, that that is large. What we’ve seen in the development wells is permeability that’s at the upper end of what we had anticipated pre-drill, so we were thinking it would be 50 to 100 million darcys [Clarification: millidarcy] and what we’ve been seeing through the bit is 100 to 150, so modestly better. What has been really positive is our ability to geo-steer and to see those geo bodies through the bit and with the tools that we’re using.

So, I think our ability to image the reservoir is really strong, but again, the key piece of data that we don’t have yet is the connectivity between injector and producer. So, we’ll be looking to get that as quickly as we can because that really is the critical data that will help us understand how much of the end place we can recover.

Henry Meyer: (Goldman Sachs, Analyst) Great. Thanks, Meg.

Meg O’Neill: Thanks, Henry.

Operator: Thank you. Once again, if you wish to ask a question, please press star 1 on your telephone and wait for your name to be announced. Your next question comes from Nik Burns from Jarden. Please go ahead.

Nik Burns: (Jarden, Analyst) Thanks, Meg and Shiva. Again, congratulations on bringing this asset online. A couple of questions from me. I’m just trying to reconcile your comments that drilling results were broadly in line with pre-drill expectations and the joint venture approving an additional producing well. Can you just explain why there’s a need for an additional producer if results look to be broadly in line? Thanks.

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Meg O’Neill: Yes. In many ways it was opportunistic, Nik. As we’ve been drilling and updating our seismic modelling we saw what appeared to be a high-quality target in the S500s that was potentially going to be undrained with the initial depletion plan. Whilst we had the rig in the field and a spare subsea tree available, we took the decision to go ahead and drill it. It’s far more cost efficient to do that work now rather than to bring the rig back at a future date. So in many ways, it was opportunistic. We saw a part of the reservoir that was not going to be depleted and we wanted to place that additional well and give us a little bit more production capacity.

Nik Burns: (Jarden, Analyst) Got it. You may have partly answered my second question that was just asking about post-startup CapEx excluding any spend on phase 2. Just wondering, should we expect that we have a requirement to bring the rig back at a future stage 2 to drill additional wells on the S500 sand or should we expect all 2P reserves to be classified as developed after the current drilling program is completed? Thanks.

Meg O’Neill: Okay. There’s a couple of elements to that question so let me go through it sequentially. In terms of the scope of work that we took FID on, the capital investment is nearly complete. We have two wells remaining to complete the final section of drilling. Both wells are, I’ll call it half-drilled. We have to drill out into the reservoir section, run the completion. So, we’re down to our final two wells and that work should be wrapped up within the next few months, and that will conclude the bulk of the phase 1 capital spend.

If we see opportunities to drill other wells, we will continue to look at those opportunities but again, to mobilise a rig from afar has a certain amount of cost associated with it so we want to be looking at a campaign which would potentially be a second phase. The reason I paused, Nik, on your question, because you raised the term 2P, I think it’s worth noting for the audience that between the time that we took FID to now, we have moved to reporting our proved reserves and our probable reserves in line with the SEC’s methodologies [Clarification: proved reserves are aligned with the SEC’s methodologies and proved plus probable reserves reporting is aligned with SPE-PRMS.]

An outcome of that is that some of our—the reserves we expect to capture from water injection has been reclassified as contingent. I wanted to flag that with you because it is a technical detail, but it is one that is important and as we get water injection online and get confidence in that water injection performance, we will be migrating reserves from contingent to probable and all the way to 1P in a stepwise manner [Clarification: migrating from contingent to proved and proved + probable reserves in a stepwise manner].

Nik Burns: (Jarden, Analyst) Right. Thanks for that. Just to clarify, how much 2P reserves was reclassified as a result of excluding water injection impact?

Meg O’Neill: Look, I’ll point you to two pieces of data. So when we took FID, we indicated we were targeting about 230 million barrels [Clarification: gross] to be recovered. It’s plus or minus still in that ballpark but the 1P booking has been updated following the merger, and that was in our 2022 year-end report. Sorry, half-year 2022 report.

Nik Burns: (Jarden, Analyst) Got it. Thanks, Meg.

Meg O’Neill: Thanks, Nik.

Operator: Thank you. Your next question comes from Rob Koh from Morgan Stanley. Please go ahead.

Rob Koh: (Morgan Stanley, Analyst) Good morning, and let me join everyone in congratulating you on getting to first oil. I guess more of a modelling question; I’m just looking at slide 5, the tax slide, and I mustn’t have had my coffee this morning. Is it possible to just confirm, is the project likely to be cash taxpaying in its first year and is there a rule of thumb for effective tax rate that we could use to calibrate?

Meg O’Neill: Yes. I said it in the remarks. Corporate income tax is 33%, and I think it’s on the slide as well, and then there’s a branch profit tax. But if you look at how the modelling flows, so revenue comes in so $100, $75 of those dollars goes to the cost oil pool, $25 goes to profit oil, that gets split between ourselves and the government, and then there’s income tax applied to that. That’s notionally how it flows through but if you want to interrogate that in more detail, Marcela or Sarah, from the Perth team, can give you a call.

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Rob Koh: (Morgan Stanley, Analyst) Thank you. Yes, we probably will, and when I say we, I mean Sarah. Then I guess the subsidiary question to this is there’s a pool of losses that will go against that 75% of cost oil; some of it’s got a three-year limit and some of it’s unlimited. Are you able to give us any steer on say what percentage of the total loss carried forward has the three-year limit?

Meg O’Neill: No, I don’t have that at hand.

Rob Koh: (Morgan Stanley, Analyst) Yes. No worries, okay.

Meg O’Neill: Yes, follow up with the Perth team.

Rob Koh: (Morgan Stanley, Analyst) Yes. Will do. Thank you so much.

Meg O’Neill: Alright, thanks Rob.

Operator: Thank you. Your next question comes from Saul Kavonic from MST. Please go ahead.

Saul Kavonic: (MST, Analyst) Hi, Meg. Two questions. I guess there’s just - there has been some rumours or concerns circulating in the market about this project, so can you confirm if there’s any audit that has been underway or is underway and if there is any downside risks associated with any audit?

Meg O’Neill: Well look, thanks for the question, Saul. Look, every government around the world audits their books. They audit taxes, audit PSCs. We have audits underway in pretty much every jurisdiction we operate in; that’s standard practice. Look, we have absolute confidence that the costs that we have booked were appropriately booked and were appropriate costs to develop the assets. So yes, we are continuing to talk to the tax authorities in Senegal just like we do in Australia and the US.

Saul Kavonic: (MST, Analyst) Right. I might ask just perhaps more generally then. With all the information you now have on Sangomar to date, is there any indication that it could result in any changes to the outlook you’ve put out for production or free cashflow over the next few years? Or is that all - everything with Sangomar’s consistent with that outlook?

Meg O’Neill: Yes, everything’s consistent with the outlook, Saul.

Saul Kavonic: (MST, Analyst) Great, thank you very much Meg.

Meg O’Neill: Right, I think that was the last question. Probably worth just going back to some high-level points. The reservoir and drilling results have been really very close to pre-drill, I’m very pleased with how the team has characterised the reservoir and how we’ve managed to execute that program. Really pleased with how the FPSO is performing. As I said in the opening remarks, the pitstop in Singapore was invaluable to ensure that when the FPSO arrived in Senegal, it would be ready to hook up, commission and get up and running, so very pleased with how the asset is performing.

We look forward to Sangomar generating value for Woodside and our shareholders for many years to come. Appreciate everyone joining us today. In terms of some upcoming events, our second quarter 2024 report will be released on 23 July, and our half year report for 2024 on 27 August. So, look forward to speaking to everyone again in August, and thank you for your interest today.

Operator: Thank you, that does conclude our conference for today. Thank you for participating, you may now disconnect.

End of Transcript

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Contacts:

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

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