Woodside Energy Group Ltd

Good morning and thanks everyone for joining our 2023 Half Year Results Investor Call. We are presenting the results today from Sydney and I would like to begin by acknowledging the traditional custodians of this land, the Gadigal people of the Eora Nation, and pay my respects to their elders past, present and emerging. I also extend my respect to all other aboriginal nations, the future generations and their continued connection to countries. This morning we released our Half Year Results and Briefing Pack to the market. I am joined on the call with our Chief Financial Officer, Graham Tipper. Together we will provide an overview of our first half's 2023 performance before opening up the call to a Q&A session. Please take the time to read the disclaimers, assumptions and other important information on slides 2 and 3. I'd like to remind you that all dollar figures in today's presentation are US dollars unless otherwise indicated. Starting with slide 4. In June we celebrated one year since completing the merger with BHP Petroleum. The strong results this half highlight the benefit the merger has realized. We delivered a record first half net profit after tax of $1.7 billion. Our operating capability was reflected in our continued reliable operations and the safe execution of two major turnarounds. We are investing in the business with our major projects progressing well and additional growth sanctions with the TRION project in Mexico. Just two weeks ago we announced the sale of a 10% interest in Scarborough. This has been a strategic priority, reducing our capital commitment and bringing a great partner into the joint venture. Our disciplined approach to capital management has positioned us to be able to invest in the business and return value to shareholders. The directors have determined an interim dividend of 80 US cents per share. The dividend will be fully franked for eligible Australian shareholders. Slide 5 highlights our strong operational and financial performance. We produced 91.3 million barrels of oil equivalent, reflecting the strength of our larger portfolio in a half that included major turnarounds at two of our facilities. We achieved reliability of .7% at our operated LNG facilities. While we saw prices recede from the record highs of 2022, we realized an average portfolio price of $74 per barrel of oil equivalent, indicative of ongoing strong demand for our products. This resulted in $7.4 billion of operating revenue and a record first half EBITDA of $4.9 billion. The balance sheet is well positioned, allowing us to invest in the business and return value to shareholders. Slide 6, our strong operational and financial performance provides the means to deliver our strategic imperatives. We've said consistently that we were aiming to sell down a portion of Scarborough to the right partner at the right value, and we are really pleased with the outcome. I am delighted to welcome LNG Japan to the Scarborough joint venture. Additionally, the TRION FID was a major milestone. We have a solid execution plan and we see that this project can deliver enduring value. Underpinning these impressive results is a strong focus on sustainability. We are on track for our 2025 emissions reduction targets and continue to mature our decarbonization plans. We paid a record $3.7 billion Australian dollars in Australian tax and royalty. Slide 7 shows our safety performance. The death of a worker at the North Rankin offshore platform was a tragedy. We have implemented changes to our operational practices based on the preliminary findings and shared our learnings with the broader industry. I am not satisfied with our current safety performance. Across all our operations, we are committed to increasing our focus on safety and we are determined to return to leading safety performance. Slide 8 highlights the strong operational performance across our larger global portfolio. We continue to achieve outstanding reliability at our LNG facilities, reflecting our operating capability and experience. The interconnector continues to add value, enabling an additional 5.4 million barrels of oil equivalent of flue gas to be processed at the Caratha gas plant. We are progressing a significant program of work to decommission wells and equipment that are no longer in use. In the U.S. Gulf of Mexico, Mad Dog Phase 2 achieved a significant milestone by producing first oil in April and is expected to continue ramping up through the year. Our project teams continue to effectively deliver subsea tiebacks, with Shenzi North production now expected in 2023 ahead of schedule. Slide 9 shows Woodside's dividend performance over the last five years. The interim dividend of 80 U.S. cents per share represents a payout of 80 percent of underlying profits and an annualized yield of 6.9 percent. With this, we will have returned over $6 billion to our shareholders since the completion of the last five years. Slide 10 shows global oil and gas prices. Prices have reduced from the record highs of 2022 as the energy market has stabilized and adjusted to changing oil and gas trade flows. We continue to see buyers focus on energy security and we are actively engaged in discussions for short and long-term supply. Slide 11 shows the U.S. Gulf of Mexico's oil and gas market. Moving to slide 11, we realized an average price across our portfolio of $74 per barrel of oil equivalent. This compares favorably with the first half for the last five years. You will also note that we are increasing our gas hub exposure guidance for the year to 27 to 33 percent. On slide 12, analysts are forecasting continued growth and global demand for LNG, our key product. Across a number of scenarios, developing markets in Asia make up a significant portion of this demand growth. While new projects are coming online, the market is expected to remain finely balanced. In recent weeks, for example, we have seen rapid and significant movement in European gas prices based on speculation about Australian LNG supply. We make an important contribution to delivering the energy the world needs. Longer term, we anticipate demand growth to outpace supply, which creates strong conditions when Scarborough will be producing LNG. Moving to slide 13, we are making significant investments in our traditional business. The Sangamore oil development in Senegal is now 88 percent complete. We updated our target first oil dates to mid-2024, and our focus today is on completing the city commissioning work on the SPSO in Singapore. In Senegal, 12 of the 23 wells have been drilled and completed, and the subsea work scope is 95 percent complete. On slide 14, Scarborough is now 38 percent complete. Fabrication of the train two liquefaction modules and the floating production unit are well underway. Upstream pipeline manufacturing is complete, and the site works at Pluto Train 2 are making good progress. We are working with the regulator on outstanding secondary approvals, and we're pleased to see the approval of the Marine Seismic Survey Environmental Plan, Binopsema. Moving to slide 15, in June, we made our final investment decision on the Trion development. The joint venture approved the field development plan, and it was submitted to the regulator. We have started executing key contracts, including the floating production unit, or SPU, engineering procurement and construction contract, and the drilling rig contract. Slide 16 provides a view on the potential growth of hydrogen demand across different sectors. While the hydrogen market is still maturing, momentum is building for it to play a key role in our customers' decarbonization efforts. Hydrogen production leverages our core capabilities in LNG, including developing and operating industrial facilities and collaborating with customers and partners across the value chain. Slide 17 outlines the portfolio we have created of new energy opportunities. We are working multiple options across Australia, the United States, and New Zealand, and see opportunities both domestically and in export markets. On slide 18, HQOK is the most advanced of our new energy opportunities. The technical work is well-progressed, we have purchased the land, and have been progressing agreements for water and power. We are currently focused on off-take discussions to help underpin this investment. We continue to target final investment decision readiness for later this year. Slide 19 shows the steps we have taken to develop a carbon capture and storage position. We have secured permits to progress studies in four areas in Australia, and commenced front-end engineering design on the opportunity in southeast Australia. Our capabilities are well-suited to carbon capture and storage. Informed by the IPCC, we believe that CCS will play a critical role in global decarbonization, and we are working to address the technological, commercial, and legislative challenges to unlock these opportunities. Slide 20 shows the progress we have made on our decarbonization plans. I am proud of our operational teams for their continued focus and innovation in this space. We have now developed asset decarbonization plans for the former BHP-operated assets, and are focused on implementation. Since we issued our 2021 climate report, we have identified a further 640 kilotons of CO2 equivalent that can potentially be updated by design out and operate out. An example of this is Woodside Solar, which is an opportunity to provide solar power to the PLETO LNG plants. During the PLETO turnaround this year, we took the opportunity to install electrical tie-in points for Woodside Solar. We are targeted being FID ready this year. I'll now hand over to Graham to cover our financial results.

Thank you, Meg, and good morning, everyone. Starting off with slide 22, we have achieved record operating revenue of $7.4 billion and a 6% increase in net profit after tax of $1.7 billion. This was driven by the contribution of the former BHP petroleum assets and the PLETO KGP interconnector. This was in a period where we completed two major turnarounds and global oil and gas prices were lower following the highs of 2022. We have been positioning our balance sheet to be flexible through the cycle, whilst delivering strong shareholder returns, and our liquidity of $7.5 billion supports the major investment we are making in our projects today, which will deliver near-term growth. While earnings per share has dropped to $0.92 per share, the driver of this reduction is primarily the lower realised price in the half. The impact of the merger itself is EPS accretive. Moving on to slide 23 and our capital management framework. We are managing the balance sheet with discipline to provide flexibility through the commodity cycle. This allows us to balance investments with shareholder returns. We are in a period of high capital expenditure, particularly through 2023 and 2024. We are delivering Sangamah and Scarborough and made a final investment decision on Trion in June. We are committed to maintaining our investment grade credit rating, which enables us to access debt competitively. Our dividend policy is to pay a minimum of 50% of underlying impact, and we target to pay between 50 and 80%. In the first half, we delivered at the top end of this range with an interim dividend of 80 US cents per share fully franked. This reflects an annualised yield of 6.9%. While this dividend is lower compared to the half one 2022 dividend of 109 US cents per share, the 2022 dividend included a 33 cent contribution from the merger completion payments. At 30 June, our gearing was 8.2%, just below our target range of 10 to 20%. If we were to incorporate the payment of the interim dividend, our gearing would increase to 12.1%. Given the volatility we've seen in oil and gas prices and our capital expenditure commitments over the next few years, we feel it is prudent to remain at the lower end of our targeted gearing range. And this is consistent with what we said in our full year 2022 results in February. Slide 24 shows a first half comparison of our operating revenue EBITDA and underlying impact over five years. All three have outperformed on this five yearly comparison. As I mentioned previously, the key drivers of our strong financial performance for this half are the contributions of the merged assets and the Pluto KGP interconnector, which have been partially offset by a lower realised price, the planned turnaround and operating costs including depreciation relating to the merged assets. Slide 25 shows the first half comparison of operating, investing and free cash flows over the five years. We've had an increase in operating cash flow despite higher tax payments relating to higher profits in 2022 and 2023. Our investing cash flow is also up significantly as we progress the Sangamah and Scarborough projects. It is important to note we remained free cash flow positive in the half. Slide 26 compares our first half production cost performance over five years. Our cost performance was impacted by the Pluto LNG and the GiniIN FPSO turnarounds during the half. Our unit production cost was $8.80 per barrel of oil equivalent. If we exclude the 90 cent impact of the planned turnarounds, our UPC would be $7.90 per barrel of oil equivalent. While UPC is up from the 2022 first half, the underlying costs of the heritage woodside assets remain in line with H1 2022. We do have a full six month contribution from the merged assets which has changed the cost mix. The Pluto KGP interconnector also adds to the cost base but is highly value accretive. We have a total of $8.80 per barrel of oil equivalent through six additional cargoes compared to the first half of 2022. So to summarize, there are several moving parts to our unit costs through turnarounds, the addition of the BHP assets and the Pluto KGP interconnector which do not impact the underlying cost performance. We continue to focus on cost performance and are managing inflationary pressures in our operations. Slide 27 outlines the resilience of our cash margin. We continue to maintain a strong cash margin of 80% even in a lower price environment. While unit production costs have increased due to the turnaround activity, we have kept other cash costs at approximately 7%. Slide 28 shows our net debt and gearing over five years as well as our 10 year debt maturity profile. Our gearing of .2% is low, we have no significant near term debt maturities and our cost of debt is competitive. These all reflect the strong positioning of our balance sheet enabling us to navigate market volatility while investing in the near term growth and maintaining shareholder returns. Slide 29 outlines our liquidity profile over the past five years. Our liquidity remains strong at $7.5 billion providing ample capacity to meet our expenditure commitments. This is important in the context of the investment program we have in the coming years as we complete Singamah, Progress, Scarborough and Treon. Additionally, we have the added flexibility from the Scarborough sell down proceeds to be received in early 2024. Slide 30 shows our overall Australian tax contribution. In the first half of 2023 we paid $3.7 billion Australian dollars in Australian tax and royalties reflecting the recent strong business performance in 2022 and 2023. This is a record contribution for Woodside and demonstrates that the mechanism for paying taxes is working. When Woodside profits, higher taxes are paid. To put this into further context, over the past 12 months to 30 June we have paid more than $1 billion Australian dollars in PRRT. Our global all ineffective tax rate at 30 June was 42% when excluding the one offs. The one offs are the recognition of the Treon deferred tax asset and the derecognition of the Pluto PRRT deferred tax asset. The contribution we make to the Australian economy and other jurisdictions we operate in is something we are really proud of. So to summarize, our half won 2023 financial performance has been strong and our business is in great shape. We are generating positive free cash flow while investing in near term growth and balancing shareholder returns. We are well positioned for the capital expenditure ahead of us and we will continue to be disciplined in our approach to capital management to ensure that business remains resilient. With that, I will now hand back to Meg.

Thank you, Graham. It has been a strong half. Moving to slide 32, the results discussed this morning support the case for investing in Woodside. Our high quality portfolio and disciplined approach to capital management allow us to invest in producing the energy the world needs and deliver shareholder returns through the price cycle. Slide 33 is our capital allocation framework, which I am sure you are used to seeing and shows the standards we hold ourselves to as we bring new projects forward. We are and will remain disciplined in future investment decisions. To close, slide 34 shows our priorities for the second half. We have strong core assets and are focused on operating them safely. We are investing in the business and so a key priority is safe project execution on budget and on schedule. Everything we do is done with a focus on sustainability and we are preparing for some exciting decisions in this space in the coming months. We will now open up for the question and answer session.

Thank you. If you wish to ask a question, please press style 1 on your telephone and wait for your name to be announced. If you wish to cancel your request, please press style 2. If you are on a speakerphone, please pick up the handset to ask your question. We ask that you please limit your questions to two per person. If you wish to ask further questions, please rejoin the queue. Your first question comes from James Byrne with Citi. Please go ahead.

Good morning team. Question for Graeme first up. Look, the EBITDA for the half was called at a billion dollars higher but you're operating cash flow only around $400 million higher versus the half year for 2022. As I kind of dig through the cash result versus what the street was expecting, it does seem like there was a pretty material miss on the cash taxes. I was hoping we might be able to just pick through whether there were any one offs in cash taxes versus things that might have structurally changed from a cash perspective. So you could maybe talk through that.

Yeah, sure James. So has anything structurally changed from a business perspective? No. I guess what I would say is in the higher price environment, the extremes of 2022, as I mentioned in my presentation, we will pay more taxes in particular around PRRT. So I think you can see in the cash flow there we paid more than $2.2 billion in taxes made up of income tax and PRRT for the first half. But in terms of your question, has anything structurally changed? No. But in the higher price environment, we will certainly pay more taxes and that is a combination of PRRT or where PRRT really kicks in.

Great. Okay. My second question is just around SCARBRA. So I see we're still awaiting secondary environmental approvals. Could you perhaps give a bit of a timeline here to the extent that you can around receiving those and at what point, if it continues to drag out, at what point does it become critical path for drilling and the pie play, which I understand should have started now based on the presentation you gave at SCARBRA FID back in 2021?

Yeah, thanks for the question, James. So you'll be aware that following the court decision that overruled NOPSEMA's approval of some Barasa EPs that happened in December, we've been working very closely with NOPSEMA to understand the enhanced consultation requirements and we have been progressing the enhanced consultation for a number of EPs for SCARBRA EPs as well as for EPs associated with the base business. I think the real positive signal is that NOPSEMA a couple weeks ago approved two EPs, one for the Mangura Riser Turret Mooring EP and the second one for the SCARBRA Seismic EP. So I would suggest that the market should take that as a sign that the enhanced consultation requirements are now clearly understood and that Woodside has fulfilled those for a number of our EPs. The other SCARBRA secondary environmental plans associated with things like drilling, trunk line installation and surf installation, we have been working with NOPSEMA on those. We continue to complete the consultation. But I would look at the recent EP approvals as a sign that there is now clarity in the marketplace between the industry and the regulator as to what complete consultation and what appropriate consultation looks like following the court decision. We are cautiously optimistic that the work we have done on the other SCARBRA secondary EPs will also meet NOPSEMA's expectations.

That's great Meg, but just regarding how should we think about the contingency you have within schedule for things like drilling and pipeline? If I look at something like BROSA, Santos talked about maintaining schedule by drilling fewer wells up front, not drilling the backup wells for production. I'm wondering to what extent you also have flexibility on that schedule if the... Yes, the critical

path for SCARBRA is and always has been through the floating production unit, which is in fabrication right now. The other elements of the project, we do have a bit of schedule flexibility. There still is a bit of time, but I would note and the presentation flags it that receiving those approvals is one of our key risks. Then the legal challenge that might be brought is also an area that we continue to work very closely with NOPSEMA and with the government on.

Got it. Thank you Meg.

Thanks Dan. Thank you. Your next question comes from Tom Allen with UBS. Please go ahead.

Morning Greg, Graham and the board of team. Just following the recent announcement of the LNG SBA with Sojit and Sumitomo, can you please provide an update on the current LNG marketing activities for SCARBRA? Just recognizing that there's still a lot of LNG to deal with, particularly given the current legacy Pluto LNG off takes expire shortly.

Yes, thanks for the question Tom. We're very excited about the MOU that we signed with LNG Japan. So that includes the parent companies, Sumitomo and Sojit as you noted on LNG off take. I think that was, it's a very positive sign that the Japanese market still is interested in Australian LNG and still sees Australian LNG as essential to meeting their energy security needs whilst they also tackle the question of climate change. To your broader question, we are in a number of discussions with a number of counter parties on potential LNG off take. And when we have something to say that's conclusive, we will communicate to market. But I would let you know that those, you know, there's discussions with a number of what I would describe as quality counter parties that are well advanced because the market does need LNG.

Thanks, Meg. Can we assume that those counter parties are all Asian based buyers, so recognizing Woodside sell from a portfolio basis now. Also recognizing that the LNG out of Scarborough will all be sold into North Asia. It certainly implies that there's a lot more counter parts that you need, particularly in the North Asian market.

Yes, sorry Tom, you cut out midway through, but I think your question was around confirming that the buyers are in Asia and yes, happy to confirm that's the natural market for our Australian produced LNG. The market now has enough flexibility between the Atlantic and Pacific basins that trading can often move cargos between and the bulk of our production does go to those Asian buyers.

Thanks, Meg. You've called out the CCS options that Woodside is building. Can you share some color on the indicative unit costs that you're estimating across some of your CCS concepts and also can you confirm that the cost of CCS would be included in the project economics that you'd have to, that must satisfy your hurdle rates for a gas or LNG development?

Yes, Tom, it's worth differentiating two kinds of CCS options. So first are the CCS projects that allow us to progress new developments. So browse is probably the most prominent of those. So for browse, we've said that we are pursuing CCS from day one and the costs associated with that will need to be included in the browse investment decision. The other CCS options that we described in the slide in the North Panarvon Basin, Angel, and the Gipsland, that is where we are looking at CCS as a service we can offer to our customers. So for other industrial emitters, we are working on opportunities to offer them sequestration as an alternative to offsets or an alternative to finding new energy sources. So there are two really different types of use cases for CCS. And I won't give you indicative unit costs. It's still reasonably early days with all of these. The Southeast Australia CCS opportunity is the only one that is in the engineering stage. The other three are in the concept development stage. So it would be premature to give unit costs.

Okay, thanks Meg.

Thank you. Your next question comes from Cameron Taylor with Bank of America. Please go ahead.

Good morning Meg and team. Just a couple of questions on my name's red phone please. Firstly, can you provide some colour on what the key issues are with offshore alliance and whether you think an agreement can be reached tomorrow to avoid any production impacts? Thank you.

Yeah, we continue to have a number of very constructive bargaining discussions with our employee representatives as well as the unions that they're associated with. Look, systematically it's pay and conditions. I would highlight that over the course of bargaining we have come to agreements on or I think the key issues are important to our workforce and we will continue to engage constructively in these open discussions with our employees.

Okay, thank you. Secondly, the guidance for gas hub exposure in 2023 has increased from 20 to 25 percent to 27 to 33 percent. Can you just explain what the driver for this is given the larger LNG markets and where they're at at the moment?

Sure. Look, a lot of the driver goes down to reliability. So as we noted, Pluto reliability for the first five months of the year was 99.99 percent, so really outstanding operational performance. And the camera is probably worth nuancing a bit. So the way the LNG cargo schedule is put together, you know, we are often a little bit conservative in our assumptions around the LNG cargo delivery schedule. And so whenever we have plant performance that exceeds the planning basis, that results in increased cargoes available for shorter term sales. So that's the key factor to the increase in gas hub exposure.

Okay, thank you very much.

Thank you. Your next question comes from Dale Conders with Barron Joey. Please go ahead.

Good morning, Megan Graham. The slides mentioned the common gearing target at 10 to 20 percent is through the cycle, which infers a level of comfort above this range. But then Graham has also said that it's prudent to be at the low end of this range, which you already are with the first half of the dividend payment. And I'm noticing we get to really hit peak capex or increase PROT payments. So I'm just kind of wondering, Meg, you keep saying dividend policy is 50 percent payout, but Graham keeps paying out 80 percent. What would you need to see to consider lower payout ratio or reinstating the DRP?

Yeah, look, thanks for the question, Dale. And I think we've been pretty consistent through the last couple of periods around our gearing target ratio is 10 to 20 percent through the cycle. There may be periods where we're a little bit above and maybe periods where we're below. Right now we're below at about 8.2 percent, and we're comfortable with that recognizing that we do have continued capital spend the rest half, sorry, the second half of this year, as well as through 2024. Our dividend policy is clear. That's 50 percent payout ratio, but the range is 50 to 80 percent. And we appreciate that our shareholders, many of our shareholders, value the cash yields that Woodside offers. So again, every time we get to a dividend paying period, we take a look at all of the factors, the cash flow that we've generated in the period, the outlook for expenditure that's ahead and make the decision based on the forecast on the day. Graham, maybe you want to elaborate? I

think the only thing to add, Meg, is that we weigh up, Dale, in the context of our capital management framework each period, the dividend. We look at our capital in front of us. We look at our metrics of our balance sheet. But we also look at what's happening macro as well. And as you know and see, it's uncertain at the moment. So I think I'd use the word prudent. I think where we are today is prudent in the context of where we are in our capital projects, where the global markets are, and set ourselves up to continue to balance that shareholder return and invest in these near-term growth projects.

Is there anything you can say in terms of the next stage of growth? A lot of CCS projects, BROWS, you've also got Calypso and other projects. Does that all have to wait for after cash flows come in from Sangama?

So Dale, I'm timing

it correctly.

Yes, timing, of course, is an important consideration. But one of the things that I'm really pleased about post-merger is the health of the future investments portfolio. So we have GAAP investment opportunities, things like BROWS, Calypso, and Sunrise. We have new energy investment opportunities. So beyond H2OK, that's looking at things like H2PERS and the Southern Green Hydrogen Project in New Zealand. We've got CCS opportunities. So we do have a hopper full of opportunities. When we think about the pace at which we're maturing the balance sheet factors in, but a number of other factors are important, you know, regulatory approvals, partner alignments, technical maturity, commercial maturity. So we're continuing to work on those fronts on a range of opportunities. And with that, I feel like we're in really good shape for the investments that we've sanctioned thus far, which includes Scarborough, Sangama, and Trion.

OK, thank you.

Thank you. Your next question comes from Saul Kavernick with the Credit Suisse. Please go ahead.

Thank you, Meg, Graham. A couple of questions. I'll come back. I just want to come back on the industrial action risk here because every time there's a bit of news that comes out of this, we're seeing multi-billion dollar moves in European gas markets. I guess Woodside's probably benefiting from some of that. But Meg, can you just clarify, do you see any material risks to Woodside's production guidance from potential industrial action over the next few months?

Thanks for the comments, Saul, and appreciate your observations. I think the way the European markets have reacted is a sign of just how fragile those markets are and how tightly balanced supply and demand are. Look, our employees who are union members have supported protected industrial action. There are a number of different actions that they might take, ranging from things that would have a modest impact on the business to things that would have a more significant impact on the business. I don't know what the unions are going to call. What we can control is the engagement that we have with our employees, the engagement we have in the bargaining process. As I said, we've been very constructive. We've been listening, trying to really understand the things that our employees are concerned about and coming up with solutions. I feel good about the way that the bargaining has progressed to this point. We look forward to just continuing to have those good discussions.

Thanks. Fair enough. My second question is just coming to some of the smaller assets, like noting Pyrenees is being impaired, which sometimes countries do this before they're able to sell assets. Do you see assets, smaller assets like Pyrenees and maybe like Macedon, still being in the wood-side portfolio in the two years, or are they kind of the sort of essence?

Look, we're really pleased with the assets that we've acquired in the BHC petroleum merger. Macedon is a nice little asset that provides domestic gas in Western Australia, where the market is increasingly tight. So we're pleased to have these assets in our portfolio at this point in time. The Pyrenees impairment was associated with a drilling program that was not as successful as we had hoped it would be.

Thank you. I'll jump back in the queue.

Thanks, all. Thank you. Your next question comes from Adam Martin with E&P Financial. Please go ahead.

Yeah, morning, Meg Graham. Well done on the sell-down process at Scarborough. I mean the 10% was probably lower than the 25 to 50 that you historically talked about, although you were probably closer to 25 over time. I'm just wondering, is there more to sell there? Is that a short-term opportunity or is that more of a medium to long-term opportunity? Just any observations there, please.

Yeah, thanks, Adam. Well, we've said all along that the Scarborough sell-down was a nice to do, not a must do, and that we were going to be patient and look for the right partner who was willing to offer value that was commensurate with the value of the asset. And we're really exceedingly pleased that LNG Japan has, after a very long period of due diligence, has decided to come into the asset at a value that we think is quite attractive for Woodside shareholders. So we're comfortable with 90%. If others want to continue to come in, well, we've now got a very clear price marker in the marketplace. So if you happen to have that kind of funds available, happy to talk to prospective buyers. But we're pleased to proceed with 90%. If you look at our track record, we took Pluto forward with 90%. So it's a crown jewel for us, and we're going to continue to be really disciplined about bringing anyone into the venture.

That makes sense. Just a second question. This is sort of 5B and new energy spend target. Obviously, 2030 is a long way out, but it's also coming relatively quickly. I mean, what's your sense here? Are you going to be spending this capital in the next few years? Any particular projects that you're excited about or that might – because it's sort of hard to see where you're going to spend that capital.

Yeah, thanks for the question, Adam. So we still are committed to the target of profitably investing 5B in new energy projects between essentially now and 2030. It does require a ramp-up in activity. H2OK will be the first really material step on that journey. Look, at this point, I'd say we do still have confidence that the market will grow and will support profitable investments in that space. That's part of why we included the chart on the hydrogen market and how that is going to be growing over time. And whilst there have been questions around how fast will that grow, I think the clear signals that we're seeing from places like Europe, places like North Asia, it's very clear that those industrial economies need something different to be able to meet their climate change commitments. So we do see growth in the hydrogen market, and that is underpinning our strategy to profitably invest in these sorts of projects. So the short version of the answer is yes, I think we'll get there, but we do have a lot of work to do between now and then.

Okay, thank you.

Thank you. Your next question comes from Gordon Ramsey with RBC Capital Markets. Please go ahead.

Thank you very much. My first question relates around the strike action. Megan, I just want you to confirm that for Woodside, it's the offshore North West Shelf production facilities workers there. And I guess what I'm asking is the difference between that and perhaps the LNG plant workers going on strike. In other words, these workers have no inability to affect LNG exports from the North West Shelf plant itself. Is that correct?

Yeah, just to clarify, Gordon, so the workers that have started the process for negotiating an enterprise agreement are the workers on the North West Shelf offshore platform. So that's North Rankin, Goodwin, and Angel. So they operate the platforms that feed the Karate gas plants. So, you know, they again operate the facilities that provide the feedstocks, not the LNG operations themselves. Now, it's worth noting, of course, that the Karate gas plant processes both LNG and Dom gas. And so if there's a disruption to inputs to the Karate gas plant, it makes it challenging for it to deliver either of its products.

OK, and the second question, just on the successful appraisal of Mad Dog Southwest, the independent expert previously estimated an extension has potential to add around 87 million barrels to the project. Is that kind of in line with Woodside's expectations moving forward with that project?

It's difficult to say, Gordon. So as we noted, the appraisal well was successful and we're very pleased with that outcome. I think the operator described the economics as some fairly glowing terms. I think it was fabulous, might have been the adjective that the operator provided. Look, we still need to do a bit of work. The opportunity hasn't even gone through feed. So we're working closely with the joint venture on Mad Dog about how we would progress this opportunity. But suffice it to say, and this is something that was clear in the IER, is that the subsidy tiebacks in the Gulf of Mexico do offer quite attractive economics because you've spent the big dollars already on the physical infrastructure. So we're excited about the opportunity, but too early to give you any numbers on volumes or economics.

Thank you.

Thank you. Your next question comes from Henry Mea with Goldman Sachs. Please go ahead.

Morning, Megan Graham. Thanks for the updates. The first question for me is on the Sangamai delay. The understanding might be limited on commentary on behalf of the contractors, but can you share any details on, from your perspective at least, what led to the delay, what processes or controls might have failed internally to catch the issues, and what's changed internally to avoid that going forward?

Yeah, thanks for the question, Henry. So it's probably worth reminding you and the rest of the audience that the Sangamari FPSO was constructed in China, largely in a period of COVID-related travel restrictions. The issue that we found when the vessel arrived in Singapore was around material quality, not meeting our expectations and so having to do remedial work on piping, valves. The individual scopes were individually small, but a reasonable number of them. And so unfortunately that remedial work slowed down progress in the shipyard in Singapore. Absolutely fair question, and it's one that I've challenged the team on because we're constructing the Scarborough floating production unit also in China. So we've taken a number of the learnings from the Sangamari project around quality control, positive material identification, travel restrictions have changed, so we're able to get our experts in quality and our project leadership to the Scarborough facility and yard more regularly. So we have, we do understand the reasons for the remedial work, and we are taking actions for Scarborough to ensure that we don't encounter the same challenges.

Okay, great. Thanks, Nick. And second question on Calypso. I guess good to see that the preferred development concept has been selected as an in-field host. I'm not sure any details on the scope of that development, what existing infrastructure can be utilized and what would be required to develop the field. And then maybe also just touching on preferred marketing opportunities if you'd want to toll through Atlantic LNG, pick up equity interest or still supply into TNT's pet cam industry.

Yeah, thanks. Thanks, Henry. So yeah, Calypso is quite an interesting asset that came to us through the merger. So we have gone through the concept select phase. So we have selected the in-field host. There would be really, I'd say, little to no use of existing infrastructure, just given the location of the Calypso field relative to the existing shallow water infrastructure. And the commercial options actually are something that are being explored live as we speak. And one of the really attractive things about Trinidad and Tobago is the fact that we do have a range of different downstream customers. We can consider all of those options, tolling through the plants and lifting our own LNG. We can consider selling to the pet cam industry. So we're continuing to look at all the options. And the plus for us is that commercial attention should improve the economics for us as the Calypso resource holder.

Great. Thanks, Megan.

Thanks, Henry. Thank you. Your next question comes from Nick Burns with Jardin Australia. Please go ahead.

Yeah, thanks, Megan, Graham. Just a question around Scarborough and Capex. Appreciate 90% is covered by lump sum contracts, but you must be aware your contractors are exposed to significant cost inflation and escalation at the moment. Do you still have most of your contingency left for the project or some of that being utilized to manage this inflation risk and the potential delays to drilling and trunk line installation? Thanks.

Yeah, thanks, Nick. So at this point in time, and we look at the Scarborough cost outlook with great regularity, because as you know, there are pressures in the marketplace. We still do have confidence that we'll be able to bring the project in for our FID, the demand that we sanctioned at FID timing. But it's something that we're continuing to monitor very closely and work with our contractors very closely.

Got it. And maybe just a question on H2OK. You continue to flag FID targets second half this year. We've yet to see a formal cost estimate for the project or finalized any customer agreements for offtake. Do you remain confident that hydrogen customers will be there and willing to pay the price that will allow you to take your investment return hurdles of greater than 10% or may you need to accept a lower return here but leverage the learning from this project to reduce costs for future hydrogen projects?

Thanks. Yeah, thanks, Nick. So you highlighted two things that we're keenly focused on for the next few months. One is ensuring that we really have an attractive investment. And that means taking a hard look at the facility layout and the cost associated with construction. So we've been out to markets to understand the cost and we'll continue to be refining both the design and the execution plan to ensure that we drive those costs to as low as practical for the facility that we want to construct. And the second key focus for the team is securing customers. We want to make sure that when we start the facility up that we have an outlet for the product. Now it is worth noting that there already is a vibrant market for hydrogen for ground transportation in the California market. You know, if we were able to place all the product there, it would clearly meet our investment thresholds, but we need to make sure we can get into that market. So those are the two things that we're focused on is making sure that we've got a good handle on costs and that we have a good handle on customers.

Got it. Thank you.

Thank you. Your next question comes from Sarah Kerr with Morgan Stanley. Please go ahead.

Thank you, Megan Graham. Congratulations on the result. For my first question, just relating to slide 19 showing Woodside's emerging CCS portfolio, I was wondering if you could please comment on the regulatory approval process for these. And is it broadly similar with standard not sure not seen an offshore approvals? And if you can comment on just Woodside's work on free and prior informed consent with stakeholders for the CCS projects?

Yeah, thanks for the question, Sarah. So a couple of comments. So the regulatory framework or the licensing framework for CCS is reasonably new, but we do have CCS licenses for three of these opportunities. So the angel browse and Bonaparte opportunities, the Southeast Australia is going through the licensing process as we speak. Our understanding of the next step in the regulatory approval process is that it would follow the not seem a process, but we've got a bit of work to do to really understand those pathways that would include, you know, again, assuming it is the same not seen the process that's applied to hydrocarbon extraction. That does include a consultation process and I'll remind you that consultation and consent are two different things. The legislation requires us to consult and we do consult quite extensively. If you want to have a read, take a look at our Scarborough seismic environment plan and that details the extensive consultation that we've undertaken for that particular environment plan.

Oh, great. Thank you. And just for my second question, can you talk to the Northwest Shelf production flexibility and contingency in the event of work stoppages and can alternative personnel or the interconnector from Pluto be ramped up to mitigate a situation like this?

Yes, so as I said to an earlier questioner, there are many different forms that protected industrial action might take and those range from things that are slowdowns of work. You know, I call it headaches and inefficiencies in the business way up to complete stoppages. One of the things that we're very focused on and something that the Fair Work Commission and the unions are also focused on ensuring safety of people and operations throughout. So if we do have protected industrial action, we all want to be working together to ensure safety of people and operations. But as I know, there's a wide range of possible actions that might be taken. As far as production flexibility, very little actually. So without Northwest Shelf gas, the Pluto interconnector gas cannot be processed. One of the challenges with Pluto gas is its high nitrogen content.

Yes. Thank you.

Thank you. Thank you. Your next question comes from Saul Kavernick with Credit Suisse. Please go ahead.

I thought I'd squeeze on in if we've just got the time. But just one last question on the increased gas hub exposure by a couple hundred basis points here. What's been the driver of that and on balance is it likely there's realized higher prices or lower prices than if it had been within the contracted to Brentlink mix?

Yeah, thanks. Thanks, Saul. So I know you've got a good understanding of how the LNG annual delivery plans are put together. Typically, the producers put a certain amount of conservatism in there because we never want to miss a committed cargo. So as the years gone by, we've seen fantastic reliability at particularly Pluto, but also Northwest Shelf. And we've seen better than expected production through the interconnector. So our guess of exposure for the first half is 31 percent. And that uplift we're expecting to carry through the back half of the year. As far as pricing goes, look, it'll depend on the market opportunity. And you see in our pack where .K.M. has been tracking versus .C.C. And one of the things that we signaled is that we like to have a bit of exposure to both markets. If I were to crystal ball, I'd say that the gas of markers would be more likely to increase in the fourth quarter as the northern hemisphere gets cold. But, you know, we'll let you and your colleagues in the modeling community figure out how to how to build that into the models for the business. But honestly, we're pretty pleased with how we've been able to respond. And we're really pleased with the trading teams work to ensure that as those additional cargoes come available, that we're able to place them at attractive pricing.

Thank you. Thank you. All right. That's all the time we have for our question and answer session. I'll now hand back to Ms. O'Neill for closing remarks.

Very good. Well, thank you to the operator. Let me thank everyone for your questions and for joining the call today. In terms of upcoming events, we will release our third quarter report on the 18th of October and host our investor briefing day on the 8th of November. So look forward to seeing everyone then. Thank you.