Thank you for standing by, and welcome to the Woodside Energy WDS half year 2022 Results. 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 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, Chief Executive Officer and Managing Director. Please go ahead. Good morning, everyone, and thank you for joining our 2022 half-year results investor call. It's a pleasure to be talking with you all again. 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 country. This morning we published our half-year report and results briefing pack for release to the Australian, New York, and London stock exchanges. I am joined on this call by our Chief Financial Officer, Graham Tiver. This is the first set of financial results released since the merger with BHP's petroleum business completed in June. It was 12 months ago that we announced our intentions for the merger the night before our 2021 half-year results. I'm thrilled to be here now in the knowledge we did what we said we would, and that the combined business is delivering the benefits we expected. Today's Woodside Energy is a significant player in the global energy sector. Today, I will provide an overview of the company's performance in the past six months. Graham will then describe the financial results, and I will close the presentation before opening the question-and-answer session. Please take the time to read the disclaimers, assumptions, and other important information on slides two and three. I'd like to remind you that all dollar figures in today's presentation are in U.S. dollars, unless otherwise indicated. Starting with slide four, the first half of 2022 has been extraordinary. Completing the merger transformed the company by providing scale, resilience, and further strengthening the balance sheet. We sold down a 49% stake of Pluto Train 2, which reduces our future capital expenditure for the strategic investment, and the execution of our major and minor projects is continuing well. We are executing on our strategy of thriving through the energy transition and progressing a number of opportunities to invest in lower carbon products and services. Looking at the numbers, it's clear that this has been a very good half for Woodside, our shareholders, and the governments to whom we pay taxes and royalties. First half profit of $1.6 billion is up four-fold from the first half of 2021. We have backed out some one-off extraordinary costs associated with the merger to deliver an underlying profit of $1.8 billion. This, combined with the cash received on completion of the merger, has enabled us to reward shareholders with a $1.09 per share, fully franked dividend. Importantly, the operating cash flow of $2.5 billion means we have remained cash flow positive despite the capital expenditure commitments across Scarborough, Pluto Train 2, and Sangomar major projects. These numbers highlight the strong demand for our core products. Slide five provides further demonstration of the value delivered by our high-margin, low-cost operations. Our diversified portfolio of assets generated $5.8 billion of revenue and $2.6 billion in free cash flow, which includes all major CapEx. These results include the one-month contribution of the former BHP assets since the merger completion date of 1 June 2022. The average portfolio realized price of $96.40 per barrel of oil equivalent reflects sustained strong demand and the benefits realized by our marketing and trading business. Operationally, we've had some great results, producing 54.9 million bbl of oil equivalent and achieving improved LNG reliability. We continue to look for and implement opportunities to extract further value from existing assets. As an example, the Pluto to KGP interconnector has come online in a very strong market and allowed us to accelerate production of Pluto gas. The investment of approximately $230 million started up ahead of schedule and paid for itself within three months of operations. We've delivered subsea tieback and improvement projects across North West Shelf, Pluto, Wheatstone, and Shenzi, all ahead of schedule and under budget. On slide six is the one part of our performance this year, so far this year, that I find personally disappointing, our safety performance. The year-to-date total recordable injury rate of 1.81 is higher than we want it to be, and each asset is developing improvement plans, targeting the root causes of these incidents. Woodside, for many years, has been known as a sector leader in personal safety performance, and we need to keep doing everything we can to drive down injury rate. Environmental performance has been good, with just one Tier 2 loss of containment event recorded, which resulted in no impact on the environment. Moving to slide seven. You might recall the items in the circles as the key benefits we communicated when discussing the strategic rationale of the merger. The merger completed almost three months ago, and we are clearly seeing that these benefits are being realized, and to an even greater extent than we had hoped. I've talked to the value being delivered by the expanded portfolio and the cash it generates. The balance sheet is very well-positioned for this point in the investment cycle as we head into a period of significant CapEx in the coming few years. For the dividend, we've been able to maintain the 80% payout of underlying NPAT, and we are also paying out 80% of the merger completion payment adjusted for working capital. We have a range of opportunities across oil, gas, and new energy, and we've made a strong start on realizing the expected synergies of the merger. Far, we have locked in $100 million of the $400+ million per year targets. Slide eight demonstrates the way the oil and gas markets have changed over the past 18 months. There is no doubt that energy security has become a fundamental issue for world energy markets in the wake of Russia's invasion of Ukraine, and we are seeing that translate into commodity prices. The average realized price across the portfolio more than doubled compared to the first half of 2021. Our exposure to gas hub pricing for the half was approximately 18% of produced LNG, and we are tracking for the full year to be in our target range of 20%-25%. The chart on slide nine shows Woodside's dividend performance for the past five years. The board has prioritized the prudent return of cash to shareholders, considering our capital commitments, credit rating requirements, and balance sheet protection through volatile market conditions. It is pleasing to be able to maintain Woodside's traditionally high dividend yield, particularly given the number of shares on issue was almost doubled on completion of the merger three months ago. The board's confidence in declaring the $1.09 per share interim dividend was boosted by the balance sheet's strength delivered by the merger. To update you on our major projects, slide 10 demonstrates the progress being made on the Sangomar field development in Senegal. In country, the development well drilling continues at pace with the recent addition of a second drill ship, and the subsea installation campaign is underway. We are preparing for the FPSO to move from China to Singapore for the completion of integration and commissioning activities. This will help manage COVID disruption risk in the final phase of construction as we progress towards first oil. On slide 11, work is really ramping up on Scarborough and Pluto Train 2. All the major equipment items for Scarborough have been procured, including long lead items such as turbines. Just last week, we commenced construction at the Pluto Train 2 site in Western Australia. Subsea equipment manufacturing is progressing to schedule, including 25% of the pipeline manufacturing now complete. Looking forward to how the market could evolve in the future on slide 12, analysts expect to see increasing demand for our core product, LNG, in the decade ahead. Existing LNG projects and those under construction are not expected to keep up with growing demand. The LNG story is now more than just Asia, with Europe emerging as a major demand center as Western Europe seeks to reduce reliance on Russian pipeline gas. Woodside is ideally placed to supply both Asian and European markets from our portfolio of assets in OECD nations. We will do this responsibly. Slide 13 highlights our commitment to strong ESG performance across all parts of our business and the entire value chain. Woodside is a company that does the right thing and fulfills its environmental performance obligations and decommissioning commitments. We invest heavily in the communities in which we operate, and we are committed to reconciliation action in Australia. We are a major taxpayer and have paid approximately AUD 12 billion in taxes, royalty, and excise since 2011. On slide 14, we are making meaningful progress on activities in support of our emissions reduction targets. All of our operated assets are developing plans to identify and implement opportunities to improve efficiency and reduce emissions. We have also been awarded two greenhouse gas assessment permits, which are analogous to an exploration permit, but for carbon capture and storage. These permits allow us to progress feasibility work on CCS in the Browse and Bonaparte basins. On slide 15, we continue to build out our portfolio of new energy and lower carbon services opportunities. We started the year by awarding a FEED contract for the H2OK renewable hydrogen project in Oklahoma, and we continue to refine the project scope, schedule, and cost. We are also collaborating with several companies to drive the development of carbon capture and utilization technologies, which could provide Woodside with the means to turn our carbon emissions into useful products. We have invested in a CCU technology company and have signed a term sheet for a pilot CCU project in Western Australia. I'll now hand over to Graham for his review of the financial results. Thank you, Meg, and good morning, everyone. Starting off with slide 17, every financial metric points to the improved performance compared to the first half of 2021. The key drivers behind these positive outcomes are our continued strong operational performance, higher prices for our products, and the addition of the former BHP assets to the portfolio. The impact of the merger and these half-year results mean that our balance sheet is well-positioned for the major capital expenditure ahead, and we've been able to continue to deliver strong shareholder returns. Slide 18 shows the key contributors to our net profit after tax or NPAT. Each bar shows the increase or decrease in each category compared to the first half of 2021. Increased pricing and increased production volumes resulted in a $3.3 billion increase to sales revenue. Production volumes were boosted by the acceleration of Pluto volumes through the Pluto KGP Interconnector, and the contribution of the new merged assets for one month. Other positive contributors to NPAT include the derecognition of the Corpus Christi onerous contract provision as a result of a strong market conditions and the sale of a 49% stake in the Pluto Train 2 joint venture to Global Infrastructure Partners, which completed in January 2022. We incurred over $400 million of merger transaction costs, which include items such as stamp duty. Trading costs also increased due to higher commodity prices despite a decrease in trading activity. We also recognized hedging losses as outlined in the half-year report, and incurred significantly higher taxes, royalties, and excise liabilities, resulting in a reported NPAT of $1.6 billion. The underlying NPAT of $1.8 billion, which is used as the basis of the dividend calculation, removed the one-off impact of the merger transaction costs and the benefit of the Corpus onerous contract provision derecognition. Slide 19 shows a five-year comparison of operating revenue, EBIT and underlying NPAT. This is by far the best first half result in recent years. Our underlying NPAT of $1.8 billion is in fact the best first half result we've ever recorded. It is important to note that our strong earnings have resulted in higher income tax and PRRT expense. Slide 20 demonstrates the cash generating strength of our business. Our operating cash flow of $2.5 billion is underpinned by higher prices and the contribution of one month of the new merged assets from 1 June this year. This has been offset by increased payments related to tax and approximately $770 million of decommissioning costs. The increased investing cash flows shown in the chart is primarily due to execution of Scarborough, Pluto Train 2, and Sangomar. Free cash flow of approximately $2.6 billion incorporates the completion payment and is up 688% from the first half of 2021. I'd like to talk to production costs on slide 21. Unit production costs are up, but the majority of the increase is driven by structural changes in the portfolio and how we report rather than inflationary pressure. Some of the increase is due to the inclusion of the new merged assets into the portfolio, which have a different cost structure. Phasing of maintenance across the portfolio has also had an impact, as well as the planned turnaround at Wheatstone. There is also an impact due to the change in conversion factors described in our second quarter report released last month, which resulted in a small decrease to the reported production numbers and hence increase in both realized price and unit production costs. The commencement of tolling Pluto gas at the Karratha gas plant through the Interconnector has also increased unit production costs. This is a new mode of operation for us and involves purchasing some gas from the other Pluto joint venture partners and paying a toll to North West Shelf to process the gas. As a result, our unit production cost increased to $7.20 per barrel of oil equivalent, but it's important to highlight the benefit these changes bring, particularly for the Interconnector. The Interconnector added $1.10 per BOE to Woodside's UPC that has delivered $419 million of revenue, and the capital investment was repaid within three months of operation. While inflation is a hot topic at the moment, we've been managing inflationary pressure on our assets and will continue to do so. Moving to slide 22. This puts production cost in the context of our cash margin, which we have maintained above 80% for the last three years. Our cash margin this half is approximately $77 for every barrel produced by Woodside, underpinning our balance sheet strength. Slide 23 demonstrates that when prices go up, so does Woodside's tax expense. The total government all-in tax has increased from the first half of last year to almost $1.5 billion, which is a consequence of the significant increase in our earnings. Our income tax, income tax expense was $824, which equates to an effective statutory income tax rate of approximately 33%. PRRT, which is designed to increase during periods of high profitability, is $424 million, and royalties, excise, and other taxes is $228 million. The end result is an all-in effective tax rate of approximately 47%. High prices do translate to higher taxes. Slide 24 summarizes our capital management framework. We take a disciplined approach to capital management to optimize value and shareholder returns through the investment cycle. We are committed to maintaining an investment-grade credit rating, and our dividend policy is unchanged at a minimum of 50% of underlying impact, targeting a range of 50%-80%. The only change to this chart, what we have presented previously is the target gearing range. The merger structurally changed Woodside's balance sheet. We nearly doubled the number of shares on issue, which increased our equity, and the new merged assets entered our portfolio debt-free. In light of this, we have reviewed our target balance sheet metrics and determined that a target gearing range of 10%-20% through the investment cycle is more appropriate than the previous range of 15%-35%. Our analysis shows that this provides the guardrails to maintain an investment-grade credit rating and strong shareholder returns through the cycle. Based on our balance sheet at 30 June, our current gearing is approximately 7%, and we expect that once the current interim dividend is paid, our gearing ratio will be around 13%, which is within the new range. Being at the lower end of the target range is prudent in a volatile commodity price market and ahead of a period of increased capital expenditure. We are expecting to spend approximately $9 billion of capital on Scarborough, Pluto Train 2, and Sangomar from 1 July 2022 to the end of 2024. Woodside's capital management framework is designed to ensure stakeholders are appropriately rewarded. The Woodside board considers a range of options for returning value to shareholders, which can include special dividends and buybacks. Moving to slide 25. We have this morning declared a fully franked interim dividend of $1.09 per share, which equates to a total return to shareholders of approximately $2.1 billion. The dividend is comprised of two components. The first component is based on a payout ratio of 80% of underlying NPAT, which is at the top end of our target range of 50%-80%. This equates to $0.76 per share. The second component is based on the merger completion payment from BHP. Woodside received approximately $1.1 billion, which represents the net cash generated by BHP Petroleum from the effective date of 1 July 2021. Woodside's board has decided that 80% of this completion payment, adjusted for minimum working capital requirements, will be returned to shareholders, equivalent to $0.33 per share. This brings the total interim dividend payment to $1.09 per share, which represents an annualized yield of approximately 9% at yesterday's closing share price. We are pleased to note that this is the highest interim dividend declared since 2014. It reflects the strong performance of our assets and the benefits that have been realized as part of the merger. It also demonstrates Woodside's ongoing commitment to shareholder returns. Our dividend reinvestment plan, or DRP, remains active. However, the 1.5 discount previously applied to the DRP has been reduced to nil. Woodside previously issued new shares to be distributed as part of the DRP, but now intends to purchase the shares on market, which means non-participating shareholders will not be diluted. Under the DRP rules, only eligible shareholders, which does not include U.S. persons, can participate in the DRP. Eligible shareholders will have until 12th of September this year to change their DRP election if they wish to. Onto slide 26. This slide shows that our balance sheet strength is well primed for the period of increased capital expenditure ahead. Our investment-grade credit ratings of BBB+ and Baa1 were both reaffirmed during the half. Our debt maturity profile is well balanced with minimal near-term maturities. Liquidity remains high at $7.9 billion. Excluding the value of the interim dividend, liquidity would be approximately $5.8 billion. This strong position will help protect the balance sheet against market volatility in the coming years. I'll now hand back over to Meg. Thanks, Graham. I'd like to close by revisiting Woodside's capital allocation framework on slide 28, which guides our investment decisions across the three pillars of oil, gas, and new energy. One of the key tasks for my team and the board, now that the merger is complete, is to perform a strategic review of our expanded asset portfolio and ensure we're allocating effort and resources to the highest priority opportunities. We will be doing this with discipline and in accordance with the criteria set out in the framework. Slide 29 lists our key priorities for the remainder of the year. First, in operations, we have a strong focus on improving our safety performance, which is critical both in day-to-day operations and when executing planned maintenance campaigns. Second, capturing the synergies made possible by the merger will help improve our cost and efficiency performance. We've made a good start by delivering $100 million of annual savings and identifying opportunities to achieve our $400 million+ targets. Realizing these opportunities will be a key focus for the entire organization in the coming 12 to 18 months. Third is the safe delivery of Scarborough, Pluto Train 2, Sangomar, and Shenzi North. We have proven our project delivery capability with successful execution of multiple projects over the past two years, and we will apply the same discipline and focus as we progress these major investments. We also need to keep the hopper full, so we will be preparing for the next phase of growth projects. An essential component of this will be prudent and disciplined balance sheet management, enabling the efficient deployment of capital. Fourth is to progress our work on new energy and carbon capture opportunities while continuing to deliver on our emissions reduction targets. Woodside Energy has an exciting second half ahead. With the merger behind us, the whole organization will be focused on achieving these objectives and delivering on our strategy. We will now commence the question -and -answer session. Thank you. If you wish to ask a question, please press star then one on your telephone and wait for your name to be announced. If you wish to cancel your request, please press star then two. If you are on a speakerphone, pick up the handset to ask your question. Our first question will come from Tom Allen of UBS. Good morning, Meg, Graham and the broader team. Congratulations on a solid result. Just on capital management. Gearing still towards the bottom end of your new range after paying out the interim div, business well positioned to generate strong free cash. Can you share some further color on how Woodside is gonna balance your capital returns with growth over the next couple of years, recognizing Graham's comment there on the $9 billion of CapEx between now and the end of 2024? As I mentioned, there were special dividends and buybacks. Should we consider a Trion investment decision and/or a sell down on Scarborough or Sangomar, the catalyst for further capital management activities? Yeah, thanks for the question, Tom. As Graham articulated, we've been spending quite a bit of time working through our capital management framework, and the adjustment to our target gearing range is one that we think is prudent. It reflects the balance sheet of the new post-merger Woodside Energy Group. It reflects the fact that we've got considerably more equity in the markets, and lower debt. You know, we've taken a look at some things that are important guardrails for us. First off is protecting our strong investment-grade credit rating. Secondly is our commitment to return value to shareholders through the cycle. As we mentioned last year, the board has reaffirmed the dividend policy of 50% payout. As you see today, we've been able to deliver an 80% payout ratio recognizing the market conditions that we're in. As we go forward, you know, obviously these guardrails will be informing some of those future capital investment decisions that we might take when it comes to other project investment opportunities. There's a number of things in the Trion, of course, is one that's relatively mature because it's been through FEED. There are other things in the new energy space, for example, and other projects that we're evaluating. We wanna make sure that we're well-positioned to be able to execute the work that is currently underway, as well as keep the door open to some of those future investments. Thanks, Meg. That's clear. Just a question on your spot sales exposure. Over the June quarter, the realized price for produced LNG was $13.80 MMBtu, and that was slightly lower than the March quarter at $14.60. That's despite JCC oil and JKM prices increasing during the June quarter. Can you provide some color on why the data coming through or that trend is softer than what we're seeing in the market? Particularly if there's arrangements in contracts such as extended lag pricing or gas banking from offtakers that explain the trend. Yeah, Tom, it's really a question of mix. We sell LNG on a variety of price indices, Brent, JCC, some of the gas hub indices, as well as we have one gas contract that is, we'll call it a pseudo-fixed price contract. And the quarterly outcomes is just a result of the mix of the portfolio at any point in time. Okay. I might have to follow that up, offline for a little bit more. Thank you for that. Just quickly, one on Scarborough. If we could get an update on Scarborough gas contracting. Obviously, it's a strong market to sell LNG. We've seen numerous long-term LNG SPAs announced from new LNG coming along in the U.S. from 2026 over the last few months, but nothing yet on Scarborough. Any feedback you can share on that process and how the gas marketing team is going on that front? Sure. We continue to talk to a number of players about Scarborough. We're talking to a variety of potential buyers, and when we have something that's announceable, we will communicate to the market. Okay. No worries. Thanks, Meg. Thanks, Tom. The next question will come from Mark Samter of MST. Morning, everyone. Apologies if I ask questions that have been already covered in the session. I was in a Father's Day breakfast. Sorry. First one, I think it's around the Scarborough sell-down. It's been going on 13 months now, certainly from when you told us publicly that it had commenced. Not saying the press is always right, but there was some press, I think a week or two ago, saying it wasn't going so well. Can you tell us where that process is at, if you're still expecting to sell down to 50% and how much maybe challenges in that sell down process has driven the 10%-20% gearing target? Yeah, thanks for the question, Mark. Good to speak with you again. We continue the sell-down process. As we have communicated our goals with the process is to find the right partner at the right price. When we reflect on Scarborough is an extraordinarily important asset for Woodside. It's going to be a significant contributor to our cash generation starting in 2026 for 20 years, 15-20 years after that. It really is important that we get the right partner and we get the right price. We're not going to be schedule driven with this process. We do continue to have discussions with a number of high-quality prospective partners, and we'll continue those discussions and hopefully land something. Again, we're not going to fire sale this critical asset. Would it be a fair interpretation to say nothing done after 13 months that maybe you're not seeing offers at the level of the price that you believe is the fair price for it? Is that a fair interpretation, or have we still not had any bids tabled after 13 months? Mark, we're continuing to work it. You know, the calendar, I guess you can sort of debate how long we've been trying to sell it down. We had a pretty hard push ahead of FID, and then after FID, we took a bit of a pause because with that milestone, we have significantly de-risked the project. Post-FID, we've seen players come to us, you know, and we continue to have interest in the market, particularly as the LNG marketplace changes globally. We're continuing to talk to a number of high-quality potential partners, and, you know, hopefully, we'll be able to land something. Okay, great. Then just on the $9 billion of CapEx to end of 2024, we're saying that is just for Sangomar and Scarborough / Pluto 2. Is there anything you can say on the rest of the business CapEx just on base business? Because I guess when I think about that 10%-20% gearing target, is it again fair to assume that the oil hedging you've done is as great as gearing is now when you're returning as much capital and dividends as you have this half? If oil goes to $50, $60, $70, and spot LNG comes down a bit, all of a sudden, you'd be reasonably materially free cash flow negative over that period. Is there any color you can give on rest of business CapEx for the next couple of years as well? Yeah. Thanks, Mark. Look, the $9 billion is, as you note, just for the major projects, so Sangomar, Scarborough, Pluto Train 2. We haven't put guidance out for the rest of the capital profile. We have provided guidance for 2022 full year. From that, you can get a bit of a sense of baseline capital, but we'll provide the market with more information as we head into 2023 around what the baseline capital looks like in that time period. I'll address your comment as well on hedging. You're absolutely right. The reason we have hedging in place is to protect against a price shock. That's one of the tools in our toolkit as we head into this period of higher capital spend to ensure that we have resilience and we'll be able to protect the balance sheet in the event of a price shock. You know, you know as well as we do that it was only two years ago that we were at record low pricing. We think that's a prudent step to protect our balance sheet. Yeah, absolutely. I completely agree. Just one really quick question then, if I can, on Sangomar. Obviously, having to move the FPSO to a different country, I presume that's logistically challenging. How much issue does that create with, I don't know, liability over work and particularly schedule around that, too? I would have thought that's a pretty, A, costly, and B, timely process to go through. Yeah. Thanks for the question. Look, the key driver for moving the FPSO actually is to give ourselves schedule certainty. The FPSO, which MODEC is contracted to deliver, is currently being fabricated in China at a number of different shipyards. All of the elements are being integrated as we speak. The reason for repositioning to Singapore actually allows us to get after the commissioning with reduced risk of COVID-related disruptions. Just to describe a little bit more detail, this phase of the project, when you're in the commissioning phase, you need tremendous support from all of the different equipment vendors. The travel restrictions in China make it a bit difficult today to do that. Moving the FPSO to Singapore actually gives us greater schedule confidence that we will be able to complete this really complex portion of the late-stage construction. The contracting and responsibility for that lies with MODEC. We've, of course, been closely working with them to understand the plans, but we fully support it, and we think it does actually improve our schedule certainty and keeps us on track for that 2023 first oil. Brilliant. Thank you, Megan. Thanks, Mark. The next question will come from Dale Koenders of Barrenjoey. Morning, Meg and Graham. I guess I just wanted to expand on Tom's question. When you asked Meg about the balance between returns and future expenditure, your answer was purely focused on setting the balance sheet up for further investment. I look at slide 24, and I might be reading too much into it, but excess capital, special dividend share, value back in future investment. Future investment is the only one with a tick. Then your capital allocation framework, most people will talk about returns on that slide. You've only spoken about what you're spending money on. Just, can you give us some certainty about what returns will come going forward, or is this really a pivot of the company is shifting more towards growth going forward? Yeah, Dale. As we have said before when we put this slide out, one of the things we want to do is ensure that we've got a variety of tools in the toolkit to return value to shareholders. Special dividends would fit in that category. Buybacks would fit in that category. In addition to our existing dividend policy, which provides pretty healthy returns to shareholders, particularly when we pay out at this 80% ratio that we're providing today. When we looked at the current financial position, we said the right thing for us to do at this point in time is to focus on returning value through that dividend at the upper end of our target range and preserving the ability to do future investment. It's not to rule out the possibility of specials or buybacks in the future. Again, when you set the guardrails of strong investment-grade credit rating, that target gearing range and the dividend payouts, this is the recommendation that we're at for today. Again, the door is open as we go forward in time to looking at some of those additional levers. Maybe I'll ask Graham to elaborate a little bit. Yeah. Sure. Thanks, Megan, and thanks, Dale, for the question. I think, you know, I don't wanna get caught up into the slide, but, you know, the ticks are what we've sort of achieved for this period. I guess the emphasis of the capital management framework and the gearing ratio of 10%-20% is really to provide that ability to be able to return value to the shareholders while being able to continue to invest in our major projects over the next few years. Gearing is definitely a point in time, and when we are determining dividends and shareholder returns, management is looking forward. We're looking at sort of the business circumstances. We're looking at forward pricing. We're looking at our capital obligations, and we balance that up to be, to provide balanced returns to our shareholders as we move forward. Okay. Maybe just changing tack then to the LNG. At 8.5% year to date, still full year at 20%-25%, indicating sort of second half, 25%-30% exposure to spot pricing. Is that higher rate more indicative of what you'll be seeing in 2023 and going forward? Then a second part to the question, in terms of your hedging program, where you sort of announced a bit more on your LNG contracts, can you talk a bit more about the timing and are you effectively locking in the large spreads we're seeing today? Yeah. Thanks, Dale. First off, we haven't put out any guidance for 2023 gas hub pricing. We will put that out per our normal course of business at the end of the year, probably during our investor briefing day. We haven't signaled that. When it comes to hedging, what we have done, and I think the hedging is pretty comprehensively disclosed in the report, is we've placed a number of hedges on oil indexation. Again, as I commented in Mark's question, the purpose of that is to protect the balance sheet in the event of a price shock. For Corpus Christi, the hedging that we have put in place locks in positive returns. Okay. You can't give any more steer on sort of have you been locking in better returns than you've been making in prior years? Look, I'd encourage you to look at the segment reporting. I think what you would see is that, our marketing segment, actually did a pretty positive result in the first half of this year. Okay. Thank you. Thanks, Dale. The next question comes from Gordon Ramsay of RBC Capital Markets. Oh, thank you very much, and congratulations on a strong result, Meg. Capital management, in particular the dividend policy, isn't it time for Woodside to update its policy? I mean, 50% of underlying NPAT and you're paying 80% the last few years. Is there any thought to moving to a free cash flow-based dividend and one that takes into account growth CapEx and other priorities in the company so that there's some improved visibility going forward on what the dividend may be? I mean, some of the majors even have floors on their dividends and will you guarantee buybacks if the oil price is above a certain level. Any thought about improving that dividend policy and making it more visible for investors? Yeah. Thanks for the question, Gordon. Our finance team has done really extensive modeling of dividend options. We believe that the dividend policy we have, which is to pay out on NPAT, is one that is appropriate for us and is something that will be enduring through the cycle. I'll let Graham elaborate a bit on the choices that we've contemplated and why we've stuck with what we have. Thanks, Gordon. Now look, as a part of reviewing the capital management framework across, or post the merger, we've tested it across multiple scenarios, price scenarios, business scenarios, et cetera. As Meg's saying, we still believe that this is, you know, using the EBIT or the NPAT measure is still the best path forward for the organization as we move forward. Okay, thanks. Meg, on Sangomar, I mean, there's nothing in the presentation in terms of target startup date, but I heard you say earlier, are you still targeting 2023 for first oil from that project? Yes, we're targeting second half of 2023. Okay. That's all for me. Thank you. Thanks, Gordon. Our next question will come from Mark Wiseman of Macquarie. Oh, hi, Meg. Hi, Graham. Thanks for the update. I just had a couple of questions. Firstly, on Sangomar, I just wondered whether the CapEx on that project has changed since the prior guidance with the move of the FPSO. It has not. Okay, great. Just on the Trion project, I'm just interested in you're talking to an FID in cal 2023. I'm just wondering, would you consider selling that down, bringing in another partner prior to FID? I was just wondering, could we discuss some of the supply chain issues? It sounds like you're being a little cautious, if I'm correct, just on, you know, the costing of that project going into an FID. Could you maybe just elaborate on that? Sure. Look, I think it's appropriate to be cautious heading into any FID of this magnitude. With Trion, we have completed the FEED work, so the front-end engineering work. The marketplace that we're in today is a very different one from the marketplace when FEED was started, which was about a year ago. We're seeing inflation through the supply chain. We're seeing uncertainty in delivery times, you know. These are, sorry, just to clarify, for projects that are being quoted today. Of course, projects like Sangomar and Scarborough are past that point of uncertainty. What we want to do with Trion is make sure that we've got really good understanding of the cost. We're reviewing the contracting approach. We're looking to get greater confidence in the cost estimates. That's a significant piece of work that we are doing in the intervening period here. In terms of our ownership stake, you know, right now we've got 60% with Pemex, the national oil company, holding the other 40%. As I alluded to on the capital management slide, one of the pieces of work we're doing right now is taking a look holistically at our portfolio. At this point in time, we're not, you know, pursuing sell downs for Trion. Okay, that's great. Thanks. Just finally, on Trion again, is there any ability to slide that back to better marry up with your gearing target? In terms of just, you know, as some of the CapEx on Senegal is coming off, it would be nice to have Trion more in 2024, 2025, and less so in 2023. Is there an ability to push it back? We're looking very closely at the impact that Trion would have on our capital outlook, and on the balance sheet and on our gearing range. Would be premature to comment on potential timing changes at this point in time. Okay, thank you. The next question comes from Nik Burns of Jarden Australia. Oh, thanks. Just a question on the Scarborough sell-down process. Can you just walk through how you're thinking on the appropriate level of upstream equity, and the project has evolved. The world's changed a lot since you flagged selling a 50% stake a year ago. We've seen some of your peers finding it challenging to close the gap in terms of price expectation, in particular for projects that are a few years away from first revenue. Your capacity to retain a higher equity piece must be increasing by the day as LNG prices increase. Should we be shocked if you announce in future that you plan to retain your entire 100% stake? Thanks for the question, Nick. As I said, I think to Mark's question, with Scarborough, it is an extraordinarily important asset for the future of Woodside. As we think about reducing our equity position, we wanna ensure that we bring in the right partner, so that's somebody who, you know, shares our vision of the asset and shares our desire to progress the asset. We wanna make sure that we get fair value so that our shareholders get appropriately financially rewarded if we do dilute our interest in this opportunity. We're not being schedule-driven. That said, you know, given the LNG market conditions today, we are continuing to talk to a number of really high-quality prospective partners, and we'll update the market when we have something firm to say one way or the other. Got it. My other question just relates to the BHP Petroleum assets. Since the merger information was sent to Woodside shareholders back in May, we've had some negative updates from you in terms of some of the growth projects acquired from BHP, either no longer going ahead or being pushed back. Can you just talk through why you still believe the merger was a good one for Woodside shareholders from a relative value perspective? And which of the BHP Petroleum growth projects are you most excited about? Thanks. Well, I think you look at our results, Nick, and that is pretty clear as to why the merger is good for Woodside shareholders. You know, the strength of our financial results, underpinned by increased production at a point in time where the world needs the products that we produce, the strengthening it provides to the balance sheets, which allows us to continue progressing the investments that are already underway. It unlocks our ability to invest in new energy opportunities, and we see the opportunity to capture cost synergies by bringing the two businesses together. I think the strategic rationale for the merger remains very positive. Obviously, with any business, you know, things will change a little bit over time, but the overall assets, as we get to know them better, we're very pleased with what we have with what we've brought into the business. As we think about future investment opportunities, as I alluded to, we have quite a few things in the hopper, and that's actually a really great place to be. In addition to Trion, we've got Browse and Sunrise, which were heritage Woodside or legacy Woodside assets. We have Calypso, which is a deepwater gas field in the Caribbean. Then we've got a number of new energy opportunities. It's actually a really pleasing place for us to be able to have a bit of choice, and to have optionality in terms of future investments. Got it. Thanks, Meg. Cheers. Thanks, Nick. The next question comes from James Redfern of Bank of America. Oh. Oh, hi, Meg. Hope you're well. Just two quick questions, please. You mentioned before that Woodside is gonna be undertaking a strategic review of all the assets post the BHP Petroleum merger. Should we read that some of the maybe smaller marginal mature assets might be divested, such as maybe the Australian oil assets? I've got one more question, please. Look, the strategic review will take a look at everything in the portfolio and help inform our thoughts around, prioritization, resourcing, and where we focus, heading into 2023 and beyond. It'd be premature for me to conclude anything, coming out of that review as it's just getting underway. Okay, perfect. Second one, please, Meg. Obviously, Woodside is in a much stronger position now, which is great, particularly post the merger. But obviously the natural field decline in North West Shelf is still an ongoing issue. And the backfill from the Browse project is, you know, one option. Just wondering if you could please sort of maybe step through what the biggest issues are for developing Browse, whether that be having a carbon capture storage solution, joint venture alignment, or the economics of the project, if you were to sort of, I guess, call out the biggest hurdle before we could see potential FID in a few years' time for Browse. Thank you. Okay, thanks, James. Let me first comment on North West Shelf. I'm really pleased that through some great work by the team, we've been able to actually refill the Karratha gas plant. With Greater Western Flank- 3 and Lambert Deep starting up earlier this year and processing gas from Pluto, the Karratha gas plant is once again full. That's only going to last for a few months, but kudos to the team for hard work to bring all of those projects to fruition. Pluto is quite significant in that it's the first opportunity for the Karratha gas plant to process gas for others, and hopefully that'll open the doors to other gas resource holders bringing their product through our facility. When it gets to Browse specifically, there's three things we're working on. One is carbon. The CO2 in the Browse reservoir gas is, we'll call it circa 10% averaged across the various fields. In today's world, we need a CCS solution, and we've been working on that. You would have heard that we received a permit to be able to progress CCS in Browse. So that's good progress on that front. The second item we're working is environmental approvals. Those are progressing through both state and commonwealth regulators. Obviously a lot of interest from a variety of external stakeholders in those approvals, and we continue to work with the regulators on managing those public comments that were provided. The third issue is the gas processing agreement between Browse and North West Shelf, and those commercial discussions are underway. Would be premature to try to forecast any time for which those agreements would conclude. Those are the first three things that we need to get sorted out to be able to move Browse forward. Okay, thanks, Meg. I'll hand it over. All right. Thanks, James. The next question comes from Saul Kavonic of Credit Suisse. Hi, Meg. Hi, Graham. I've just kind of two areas I wanna ask a couple of things on. First, I just wanna focus on the LNG spot exposure, given spot LNG is several times the equivalent price of oil at the moment. You talk about 20%-25% hub exposed in the second half versus for the year versus 18.5% for the first half, so up to just 21%-26% hub exposed for the second half. Should we expect that level of exposure to be maintained or increased in 2023 as well with the interconnector up, so we're gonna see increased spot exposure? Could you also touch on when the Pluto contracts roll off, and what year do we expect the Pluto volumes are gonna be exposed to the new kind of hub exposure, you know, at the moment? Saul, we'll provide guidance on the 2023 outlook for gas hub exposure, probably at our investor briefing day in December. That'll be part of our normal guidance process for the coming year. Not going to comment on that any further today. The Pluto contracts. Look, we'll need to get back to you on that, Saul. I don't know that we have disclosed that previously. Okay. Just quickly also, are you seeing signs that long-term LNG price assumptions being used by industry are increasing, whether that's for contracting purposes or for asset M&A purposes? Well, the short answer is yes. If we contrast to where we were two years ago, there were deals being done, we'll call it with slopes in the tens. What we're seeing now is an uptick from that level. It'd be inappropriate for me to comment on specific numbers, but we certainly have rebounded from the lows that we were at in 2020. All right. Just my secondary question is about the outlook that was provided as part of the merger documentation. There was five-year outlooks provided for production, free cash flow, and operating cash flow. I just wanna confirm with you if, you know, price assumptions aside, if we assume the same price assumptions, has that materially changed in any way? Or can we still expect, you know, roughly speaking on that chart, about $4 billion in free cash flow under those price assumptions for the next several years before growth comes online and increases that from 2027? We'll have to circle back with you on that, Saul. The documents we put out with the merger were not guidance. They were indicative. We'll need to circle back to you with any updated guidance that we might put out to the market. All right. I mean, I guess the question on that is, if you are gonna have $4 billion in FCF per year, and that's roughly kind of what your annualized dividend rate is now, I mean, is it reasonable to expect that the price assumptions you put out early in the year, and prices only got better since then, that Woodside can sustain a dividend yield of 9% for the next, you know, indefinite period? Well, I mean, a yield is a calculation of two numbers, so it kind of depends on what our share price does over that time period. Well, I mean, at the current share price, I suppose. Yeah. Look, Saul, as I said, we're not going to provide guidance on free cash flow. That's not something we typically do. The merger explanatory documents were intended to help shareholders understand the opportunity presented by the merger. Look, understood. The last question on this is, the guidance that's been put out for you, 145-153, if we adjust that to the old conversion factor, add in the BHP production until May, you get a range of 190-198 million bbl for the calendar year 2022, including the BHP assets for the full year. That's a bit soft on that outlook chart of, it was about just over 200, for 2022. Can you explain why there is a difference there? I guess broader question here is, we've had nothing to go on except these five-year outlooks. If we're modeling to these outlooks, you know, we wanna get a sense of if there's risk to the upside or downside from those outlooks, because it already looks like in 2022, there's been a slight miss versus the outlook for 2022 presented in that chart earlier in the year. Yeah. The chart provided earlier in the year, again, as I said, the explanatory memorandum was to help investors understand the potential value of the merger. It wasn't to be providing specific guidance. For what it's worth, your math, 190-198 versus ~200, is pretty much either bang on or in the range. Look, I think the point in time, Saul, where we will provide another view of where the company is headed will be at that investor briefing day in December. Okay. Thanks, Meg. That's all for me. Thank you. The next question will come from Daniel Butcher of CLSA. Hi, Meg. I had a couple, one on exploration, one on spot LNG. Just on the exploration side of things, I think your exploration CapEx guidance before the merger was $50 million, and now after the merger, it's $400 million-$500 million. I'm just trying to reconcile that. Well, firstly, work out what the difference being spent is, and secondly, reconcile that with your synergy target of $400 million, which included $200 million of CapEx on exploration and other low return projects being saved. Could you maybe explain where that extra CapEx on exploration comes from? Sure. The Heritage BHP business does have some exploration commitments in the back half of this year. I think we signaled some of those in the reporting. The Hoodoo-1 well, for example, is one that is going to spud in September, and there is some other exploration drilling that is underway. Of course, there's a bit of seismic also in that number. The two Heritage companies did view exploration a bit differently within their portfolios. The Woodside exploration portfolio was quite limited, and that's why our guidance heading into this year was relatively modest. We do have activity. It's largely focused in the Gulf of Mexico, oriented towards what I'd call the heartland of our new merged business. From a focus perspective, one of the things we are going to be doing is ensuring that our exploration activities are very clearly oriented towards assets that can be matured quickly. I think our industry, unfortunately, has a bit of a track record of finding things where you have a technical success, but commercially struggle to move them forward. Part of the exploration or part of the activity that we're doing as we bring the two exploration groups together is to ensure that we have that right focus. For 2023, we will put out guidance that will give you a feel for how exploration fits within our overall spending outlook. The spend for the rest of this year largely is some legacy commitments that had been made as we were heading into the merger. Okay. Because the marginal amount, $350-$450 extra from the BHP side for seven months, that seems a lot more than one deep water well, plus some seismic that you mentioned. Are there many other big impact wells we should be aware of, on the cards for this half? The Hoodoo well is probably the biggest hitter. There have been a few other exploration wells in the Gulf of Mexico in a non-op setting. Okay. Just quickly, can you maybe just talk about your strategy for unconnected LNG right now? Are you, for example, on the stuff going through the Pluto interconnector, selling that at spot, JKM or TTF hub? Or are you planning on contracting some of that up in the short to medium term? The approach that we've taken, Dan, to our LNG sales is we contract on a portfolio basis. We don't have a strategy that's dedicated to interconnector volumes, for example. We look to sell on a portfolio basis. One of the things that we're doing and we do on an ongoing basis is take a look at the projected future production performance and contract to ensure that we, you know, first off, have confidence that our product will be lifted. But secondly, make sure that we've got the right mix of price indexation. A lot of our long-term contracts are linked to oil indexation, either Brent or JCC. The question for us, of course, is how much do we preserve to be able to sell on a shorter duration basis, using some of those gas hub indices, either JKM, NBP or TTF. The guidance for this year is that we expect to finish the year in the 20%-25% range, and we'll give the market insights into 2023 a little bit later this year. Okay. Thank you. That ties nicely into my final question. I think, you know, last quarter we saw the trading arms of BP and Shell make some big losses on Freeport and Prelude outages. My understanding is that's largely because they sold a lot of their LNG on portfolio rather than for specific projects, so they couldn't declare force majeure. Woodside, as you just mentioned, has moved towards selling on portfolio as well. If you had a blowup at one of your LNG plants, how would you mitigate losses on the trading side? Look, when we look at our existing sales, much of those, the historic sales actually are contracted from specific plants. So the new portfolio sales, that probably represents a smaller portion of our business than some of those companies that have a more established trading position. Right. Okay. Most of your legacy sales from specific plants, but most of the new stuff you're gonna put on portfolio in the future. Correct. Okay. How would that apply to your future strategies as you go forward a few years in time and mostly selling on portfolio? Yeah, you know, the point you make about making sure we're positioned for operational upsets is a very important one. It's something that we look at as we decide how much do we want to have contracted and how much do we want to have available, you know, for flexible sales, just to account for some of those ups and downs that you might experience in an operational plant. Okay. Thank you. I'll leave it there. Okay. All right. Well, thanks for joining us on the call. Sorry, go ahead. Oh, no. I was just going to turn it back to you, Ms. O'Neill, for closing remarks. Go ahead. All right. Well, thank you all for joining us on the call today. I'm looking forward to meeting with many of you in the coming weeks and providing an update on our strategic direction at our annual investor briefing day in December. Thank you. That does conclude our conference for today. Thank you for participating. You may now disconnect.