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, was driven by the contribution of the former BHP Petroleum assets and the Pluto KGP Interconnector. This was in a period where we completed 2 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 investments we are making in our projects today, which will deliver near-term growth. While earnings per share has dropped to USD 0.92 per share, the driver of this reduction is primarily the lower realized 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 '24. We are delivering Sangomar 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 NPAT 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 USD 0.80 per share fully franked. This reflects an annualized yield of 6.9%. While this dividend is lower compared to the half 1 2022 dividend of USD 0.109 per share, the 2022 dividend included…

[Operator Instructions] Your first question comes from James Byrne with Citi.

Question for Graham first up. Look, the EBITDA for the half was, call it, $1 billion higher, but your operating cash flow only around $400 million higher versus the half year 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. And 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 if you can maybe talk through that.

Yes. 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 a 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 Scarborough. So I see we're still awaiting secondary environmental approvals. Could you perhaps give a bit of a time line 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 pipelay, which I understand should have started now based on the presentation you gave at Scarborough FID back in 2021? Marguerite O’Neill: Yes. Thanks for the question, James. So you'll be aware that following the court decision that overruled NOPSEMA's approval of some [indiscernible] [ 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 Scarborough EPs as well as for EPs associated with the base business. I think the real positive signal is that NOPSEMA a couple of weeks ago approved 2 EPs, one for the Nganhurra [indiscernible] EP and the second one for the Scarborough seismic EP. So I hope -- 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 Scarborough secondary environmental plans associated with things like drilling, trunkline 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 industry and the regulator as to what complete consultation and what appropriate consultation looks like following the court decision. And we're, I'd say, cautiously optimistic that the work we've done on the other Scarborough secondary EPs will also meet NOPSEMA's expectations.

Yes. But -- that's great, Meg. But just regarding how should we think about the contingency you have within schedule for things like drilling and pipelay? If I look at something like Barossa Santos to talk about maintaining schedule by drilling fewer wells upfront, not drilling the backup wells for production, I'm wondering to what extent you also have flexibility on that schedule if the... Marguerite O’Neill: Yes, the critical path for Scarborough 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. So 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. And 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.

Your next question comes from Tom Allen with UBS.

Just following the recent announcement of the LNG SPA with Sojitz and Sumitomo. Can you please provide an update on the current LNG marketing activities for Scarborough, just recognizing there's still a lot of LNG, particularly given the current legacy Pluto LNG offtakes expire shortly? Marguerite O’Neill: Yes. Thanks for the question, Tom. And we're very excited about the MoU that we signed with LNG Japan. So that includes the parent companies, Sumitomo and Sojitz, as you noted, on LNG offtake. I think that was -- it's a very positive sign, but 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 counterparties on potential LNG offtake. And when we have something to say that's conclusive, we will communicate to market. But I would let you know that those -- there's discussions with a number of what I would describe as quality counterparties that are well-advanced because the market does need LNG.

Can we assume that those counterparties are all Asian-based buyers? So recognizing Woodside sell from a portfolio basis now? Marguerite O’Neill: Yes.

Also recognizing that the LNG at Scarborough will all be sold into North Asia. It certainly implies that there's a lot more counterparts you need, particularly in the North Asian market? Marguerite O’Neill: Yes. So 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 cargoes between and the bulk of our production does go to those Asian buyers.

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 gas or LNG development? Marguerite O’Neill: Yes, Tom, it's worth differentiating 2 kinds of CCS options. So first is 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 1 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 Carnarvon Basin, Angel and the Gippsland, 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. And so there are 2 really different types of use cases for CCS. And I won't give you indicative unit cost. 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 3 are in the concept development stage. So it would be premature to give unit costs.

Your next question comes from Cameron Taylor with Bank of America.

Just a couple of questions on behalf of James Redfern, please. Firstly, can you provide some color on what the key issues are with offshore Alliance and whether you think an agreement can be reached tomorrow to avoid any production impacts? Marguerite O’Neill: Yes, we continue to have a number of very constructive bargaining discussions with our employee representatives as well as their -- the unions that they're associated with. Look, thematically, it's pay and conditions. I would highlight that over the course of bargaining, we have come to agreements on or, I think, substantive agreements on a number of items that have been important to our workforce and we will continue to engage constructively in these open discussions with our employees.

Okay. Secondly, the guidance for gas hub exposure in 2023 has increased from 20% to 25% to 27% to 33%. Can you just explain what the driver for this is, given the larger LNG markets and weather at the moment? Marguerite O’Neill: Sure. Look, a lot of the driver goes down to reliability. So as we noted, Pluto reliability for the first 5 months of the year was 99.99%. So really outstanding operational performance. And the -- Cameron, it's probably worth nuancing a bit. So the way the LNG cargo schedule is put together, 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.

Your next question comes from Dale Koenders with Barrenjoey.

The slides mentioned the common gearing target at 10% to 20% through the cycle, which infers a level of comfort above this range. But then Graham, you also said that it's prudent to be at the low end of this range, which you already are with first half dividend payment. Noticing we -- it's really you've paid CapEx or increased PRRT payments. So I'm just kind of wondering, Meg, you keep saying dividend policy, 50% payout but Graham keeps paying out 80%. What would you need to see to consider a lower payout ratio or [indiscernible]? Marguerite O’Neill: Yes. 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% 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% and we're comfortable with that recognizing that we do have continued capital spend the rest half -- the rest -- sorry, the second half of this year as well as through 2024. Our dividend policy is clear that's a 50% payout ratio, but the range is 50% to 80% 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 used 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 like the next stage of growth, does that -- a lot of CCS projects Browse, you've also got Calypso and other projects. Does that all have to wait for after cash flows coming from Sangomar? Again, timing it correctly? Marguerite O’Neill: So the -- yes. So 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 gas investment opportunities, things like Browse, Calypso and Sunrise. We have new energy investment opportunities. So beyond H2OK, that's looking at things like H2 Perth and the Southern Green hydrogen project in New Zealand. We've got CCS opportunities. So we do have a hopper full of opportunities. Look, we -- when we think about the pace at which we're maturing the balance sheet factors in, but a number of other factors are important regulatory approvals, partner alignment, technical maturity, commercial maturity. So we're continuing to work on those fronts on a range of opportunities. And I feel like we're in really good shape for the investments that we've sanctioned thus far, which includes Scarborough, Sangomor and Trion.

Your next question comes from Saul Kavonic with Credit Suisse.

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, you're seeing multibillion dollar moves in European gas markets. I guess Woodside's probably benefiting from some of that. But I mean, can you just like for clarity, do you see any material risk to Woodside's production guidance from potential industrial action over the next few months? Marguerite O’Neill: Look, thanks for the comments, Saul. And appreciate your observations. I think the way the European markets have reacted as a sign of just how fragile those markets are and how tightly balanced supply and demands 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, call it, 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. And 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. And I feel good about the way the bargaining has progressed to this point. And we look forward to just continuing to have those good discussions.

Fair enough. My second question is just coming to some of the smaller assets, like noting Pyrenees has been impaired, which sometimes companies do this before they look to sell assets. Do you see assets -- more assets like Pyrenees and maybe like Macedon still being in the Woodside portfolio in a few years? Or are they kind of sort of investment? Marguerite O’Neill: Look, we're really pleased with the assets that we've acquired in the BHP 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 the drilling program that was not as successful as we had hoped it would be.

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

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 we're 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? Marguerite O’Neill: Yes. Thanks, Adam. What 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, be 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. And just a second question, this is sort of $5 billion in 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? Marguerite O’Neill: Yes. Thanks for the question, Adam. So we still are committed to the target of profitably investing $5 billion 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 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.

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

My first question relates around the strike action, Meg, and I just want you to confirm that for Woodside, it's the offshore north shelf production facilities workers there. And I guess what I'm asking is the difference between that and perhaps the LNG plant work is going on strike. In other words, these workers have no ability to affect LNG exports from the North West Shelf plant itself. Is that correct? Marguerite O’Neill: Yes. 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, Goodwyn and Angel. So they operate the platforms that feed the Karratha Gas Plant. So they, again, operate the facilities that provide the feedstock, not the LNG operations themselves. Now it's worth noting, of course, that across the gas plant processes both LNG and domgas. And so if there's a disruption to inputs to -- across the gas plants, it makes it challenging for it to deliver either of its products.

Okay. And the second question, just on the successful appraisal of Mad Dog Southwest. The independent expert previously estimated an extension had 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? Marguerite O’Neill: Yes. It'd be too early to say, Gordon. So as we noted, the appraisal well was successful and we're very pleased with that outcome. I think the operator describes the economics as with 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 IR is that the subsea 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.

Your next question comes from Henry Meyer with Goldman Sachs.

The first question from me is on the Sangomar delay. I understand you 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? Marguerite O’Neill: Yes. Thanks for the question, Henry. So it's probably worth reminding you and the rest of the audience that the Sangomar 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 a 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 Sangomar 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. And second question on Calypso, I guess, good to see that the preferred development concept has been selected as an infield host. Are you able to share any details on the scope of the 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 supplying to TNT's pet chem industry? Marguerite O’Neill: Yes. Thanks, Henry. So yes, 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 pulling through the plants and listing our own LNG. We can consider selling to the pet chem 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.

Your next question comes from Nik Burns with Jarden Australia.

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 will some of that being utilized to manage this inflation risk and the potential delays to drilling and trunkline installation? Marguerite O’Neill: Thanks, Nik. So at this point in time, when 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 target 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 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? Marguerite O’Neill: Yes. Thanks, Nik. So you highlighted 2 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 costs associated with construction. So we've been out to market to understand the cost and we'll continue to be refining both the design, 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 outlook for the product. Now it is worth noting that there already is a vibrant market for hydrogen for ground transportation in the California market. 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.

Your next question comes from Sarah Kerr with Morgan Stanley.

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 and offshore and NOPSEMA offshore approvals? And if you can comment on just Woodside's work on free and prior informed consent with stakeholders for the CCS projects? Marguerite O’Neill: Yes. 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 3 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 NOPSEMA process, but we've got a bit of work to do to really understand those pathways. That would include, again, assuming it is the same NOPSEMA process that's applied to hydrocarbon extraction, that does include a consultation process and I'll remind you that consultation and consents are 2 different things. The legislation requires us to consult and we do consult quite extensively. If you want to have a real take a look at our Scarborough seismic environment plan and that details the extensive consultation that we've undertaken for that particular environment plan.

Great. And just for my second question. Can you talk to the North West 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? Marguerite O’Neill: 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, I call it headaches and inefficiencies in the business were 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 is 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 North West Shelf gas, the [Frito] interconnector gas cannot be processed. One of the challenges with Pluto gas is it's high nitrogen content.

Your next question comes from Saul Kavonic with Credit Suisse.

I'd squeeze one in if we've just got the time. But just one last question on the increased gas hub exposure by a couple of hundred basis points here. Just what's been the driver of that? And on balance, is this likely to realize higher prices or lower prices than if it had been within the contracted Bradley [ph] mix? Marguerite O’Neill: Yes. Thanks, Saul. So I know you've got a good understanding about the LNG annual delivery plans are put together. Typically, the producer is put a certain amount of conservatism in there because we never want to miss a committed cargo. So as the year has gone by, we've seen fantastic reliability at particularly Pluto, but also North West Shelf and we've seen better-than-expected production through the interconnector. So our guess of exposure for the first half is 31% and that uplift we're expecting to carry through the back half of the year. As far as pricing goes, look, it will depend on the market opportunity. And you see in our pack where JKM has been tracking versus JCC, -- but 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 markers would be more likely to increase in the fourth quarter as the northern hemisphere gets cold. But we'll let you and your colleagues in the modeling community to figure out how to build that into the models for the business. But look, 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.

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. Marguerite O’Neill: 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.