Woodside Energy today is a very different company than we were a year ago. When we announced the merger with BHP Petroleum, we highlighted a number of the strategic benefits that the combination would provide, and we outlined a compelling investment case. Those benefits are visible in our performance today. We have increased geographic and product diversification. We have doubled production and operating cash flow. We have strengthened the balance sheet. Three key elements comprise Woodside's investment thesis. First off, we have a high-quality portfolio. Our foundation is high-performing, cash-generating operating assets, and we have future value coming from scale assets that are under development today. Secondly, we have a disciplined framework for capital management. The framework provides a strong balance sheet and the ability to provide both strong shareholder returns and invest in quality opportunities. Finally, we are well-positioned to navigate the energy transition, building on our traditional energy capabilities and maturing opportunities to produce lower carbon energy and provide integrated carbon solutions. When we compare against other companies in our sector, Woodside does present a differentiated investment opportunity. When you look across a number of key measures, Woodside has a track record of delivering strong margins from our operations and delivering value to shareholders. We are also biased towards gas developments, which we believe will be increasingly attractive in the energy transition. The former Woodside and BHP Petroleum portfolios are highly complementary, each containing high-quality assets and developments. Merged, the business has a regular cadence of new production from major projects that are under construction today. Those projects, including Mad Dog Phase Two, Sangomar, Shenzi North, and Scarborough, will deliver greater than 4% compound annual production growth rate between 2023 and 2027. Furthermore, we have options to invest in opportunities that could continue to grow production beyond 2027. Matthew, Andy, and Shaun will discuss these opportunities. I'll now spend some time discussing how we see the global energy landscape, what that means for oil and gas demand, and how Woodside is responding. The energy challenge faced by the world today is complex. The world needs energy that is affordable, reliable, and has lower carbon intensity. Now, too often when energy transition is discussed, the only focus is on carbon intensity. A stable transition for a decarbonizing world, however, requires solutions that effectively balance these three attributes. Energy must be affordable. Real growth in energy demand comes from developing nations with aspirations to improve their standards of living and grow their economies. Even in developed nations, industry and economic prosperity is underpinned by access to affordable energy. Energy must be reliable. Customers expect immediate access to power, to heat, to transportation. As renewables are increasingly deployed, we believe natural gas can partner with renewables to firm power supply and stabilize electricity networks. Finally, if the world is to meet the goals of the Paris Agreement, our energy mix does need to evolve. We need to meet energy demand, but with lower carbon emissions. Changing the world's energy mix to reduce carbon whilst supporting economic growth through reliable and affordable energy is a tremendous challenge. To inform our strategy, we need to understand how the transition might unfold. Woodside evaluates a range of scenarios to help inform our strategic thinking and decision-making. For today's discussion, we will reference scenarios from the recently released World Energy Outlook, produced by the International Energy Agency. The three scenarios are the stated policies, the announced pledges, and the net zero emissions scenario, and the net zero emissions is a scenario with 1.5 ° C of global warming. Let's start with the fundamentals. The charts show that as the world's population increases and living standards improve, GDP will also rise. There's a range of possibilities for energy supply, but in any event, total demand remains strong. There's variability across the globe. We see the energy demand of OECD nations as being likely to decline slightly due to increased energy efficiency, but non-OECD nations will see a greater increase as their standard of livings improve. This is an essential point. There is a huge number of people today who still don't have access to clean cooking fuels or even electricity. What does this mean for hydrocarbons? The charts illustrate oil, gas, renewables, and hydrogen demand out to 2050, and we can see from the charts that oil and gas demand is likely to remain strong through the period. The global energy transition can take many different pathways, including those that require strong demand for natural gas, particularly as the world phases down coal. What the last two years have demonstrated is that the energy transition is unlikely to be a smooth, linear progression. We are entering a period of highly volatile energy markets and prices. An enormous amount of investment is required in all forms of energy in the coming decades to meet demand under all scenarios. It's also important to note the scale of hydrogen demand growth. It will take decades and trillions of dollars of investment in hydrogen to develop the scale required to meaningfully replace other fuels. Natural gas, and particularly LNG, plays a key role in energy security. We are very positive on the continued role for gas. We've seen this year the turmoil caused in energy markets by the Ukraine crisis and the consequent threat to accessing reliable and affordable energy. LNG is part of the solution, allowing buyers to secure energy from suppliers from all around the globe. The price chart, which shows two years of data, indicates the growing disconnect between oil and gas pricing and the increased volatility of gas pricing, which began even before Russia's invasion of Ukraine. This highlights the strong demand for gas. It's also important to understand that only about a third of gas demand is for power generation. Other uses for gas, such as feedstocks for industrial processes, cannot be replaced by renewables. With that context on the role of hydrocarbons and particularly gas in today's world, I'd now like to describe Woodside's approach. Our strategy, as we announced to the market about a year ago, is to thrive through the energy transition, and I believe that remains the right approach. We intend to optimize value and shareholder returns through developing a low-cost, lower carbon, profitable, resilient, and diversified portfolio. The merger certainly added resilience and diversification to the portfolio, enabling us to be more profitable. When it comes to cost, the expected cash flow breakeven oil price in 2023 is approximately $30 per barrel. This excludes major projects, trading, exploration, and hedging, which are in some ways all discretionary choices. This competitive breakeven cost gives us confidence in our ability to create value through the cycle. Following completion of the merger, we have a portfolio of diversified, high-quality operating assets and projects. All of our production comes from conventional developments, with a heavy emphasis on offshore resources. Whilst we are still very much an Australian company, we have high-quality assets in North America, including large, long-life operating assets in the U.S. Gulf of Mexico. Our Senegal development is 72% complete, and we continue work towards first production in 2023. We are also developing a portfolio of new energy opportunities to further diversify our activities and support our customers' decarbonization plans. The benefits listed on the top of the slide really do highlight the characteristics of the portfolio that give me confidence in Woodside's ability to deliver enduring value. I'd like to briefly reiterate our capital allocation framework, which informs how we think about future investment options. The framework is unchanged from what we have presented previously. As an energy company, we intend to continue developing oil and gas resources and, in parallel, to bring forward opportunities in new energy. We will be disciplined in our investment decisions, with clear targets for financial returns expected from each of our potential investments. For new energy, we have confidence in delivering these targeted return measures. We are focused on parts of the value chain with a higher barrier to entry and which complement our skill set as a producer of bulk energy. Shaun will discuss this further. Within the capital allocation framework, we have a healthy pipeline of opportunities across each type of energy: oil, gas, and new energy. Some opportunities have progressed to the execution phase, and others are being matured for potential future investment decisions. The key benefit to the breadth of the portfolio is we have development optionality. We can be increasingly selective and only progress the best opportunities. The team will provide further detail on these opportunities and the projects that are shown here. When we announced the merger in August 2021, we outlined the strategic rationale for the merger and the key benefits. Our presentation has already shown that we are realizing many of these benefits. We are also continuing to capture the synergy benefits of the merger. We have now implemented initiatives to deliver $200 million-plus of post-merger annual synergies, and we are on track to meet our target of $400 million by calendar year 2024. The synergies cover a range of items, some of which are shown on the slides here. Our strategic review has also reaffirmed that our portfolio composition is sound. Both heritage companies have taken actions over the past years to high-grade the asset base, and we do not anticipate further high-grading. We do continue to engage potential Scarborough joint venture partners. Given the strength of the balance sheet, we can be discerning and ensure we get the right partner at a value that is accretive for Woodside shareholders. We are progressing a number of activities in support of our emissions reduction targets. One thing that we've highlighted previously that we'll talk about a little bit more is our progress in developing asset decarbonization plans. Brayden will talk about this in more detail, but to highlight, we have identified opportunities across our Heritage Woodside assets, and we are investing to implement these opportunities across the Australian business. It's important to reiterate once again that development of any future oil and gas opportunities will be aligned with our decarbonization targets. ESG performance is absolutely woven into the way we run the business. It starts with integrity in what we do and transparency and accountability to our stakeholders. I have an expectation of everyone in the company that we work in a way that builds and maintains trust. The slide presents several material topics that underpin our focus areas and our actions. We clearly have a strong focus on activities related to emissions and climate change, but we also have important work underway across the spectrum of ESG topics. Now at this point, I'd like to welcome Graham Tiver to the stage to discuss how we are managing the balance sheet and our use of capital in the coming years. Welcome, Graham. Thank you, Meg. Good morning, everyone. My name is Graham Tiver. I'm the Chief Financial Officer for Woodside. It's great to be here in Sydney for my first Woodside Investor Briefing Day. Woodside is in great shape. Our post-merger portfolio of well-run operating assets is generating significant cash flow. We are currently supported by a very strong market, just as we are investing in major projects that will deliver new production for decades to come. At the same time, we are delivering healthy returns to our shareholders. Over the last 12 months, we've paid $2.14 per share of fully franked dividends to our shareholders, with current cash flow generation supporting ongoing returns. My job is to ensure the balance sheet enables the execution of the strategy, and we do that through disciplined allocation of capital, managing the balance sheet prudently, making sure we can fund our expenditure commitments, and rewarding our shareholders. Today, I'll take you through what I'm doing to achieve these goals. Woodside is really well placed to realize and return value in the coming years. The balance sheet is well-positioned and set up to fund our major capital projects with low gearing and high liquidity. One of the reasons I'm confident is because of the resilience of our low-cost portfolio to generate cash through the cycle, and that's due to our cash breakeven of $30 per barrel, which Meg touched on. However, strong cash generation only delivers value if the cash is put to good use. Meg has touched on the capital allocation framework and how we look at different types of investments, but we also have a robust capital management framework shown here on the slide, which informs our decision-making on how to optimize the allocation of cash to investments and shareholders. You will have seen this framework before, and we continue to deliver in line with it. There are three boundary conditions we work within. First, we must meet our investment expenditure commitments. Second, we are committed to maintaining an investment-grade credit rating. Third, our dividend policy is to pay out a minimum of 50% of our underlying profit and currently targeting a range of 50%-80%. It's worth noting pretty well over the last decade, we've paid to the top end of that range. Maintaining an investment-grade credit rating is important to us and a primary driver for how we manage the balance sheet. As it's forward-looking, it's an independent assessment of the financial strength of the company and allows access to competitive debt capital markets. Another metric which we use to gauge the health of the balance sheet is Gearing, which has a target range of 10%-20% through the cycle. We tested this range across a number of scenarios and determined that it was robust to various price decks, investment decisions, and returns. The 10%-20% range is appropriate for our business, which features large capital commitments in a volatile pricing environment. We may, at times, sit temporarily outside of the range, subject to internal and external factors. Once we meet our CapEx commitments, target credit metrics, dividend obligations, and consider the external factors, we'll make a call on how to use any excess cash. This includes potential additional returns through special dividends or share buybacks. Looking at the strength of our balance sheet, our investment-grade credit rating is important and is currently BBB+ and Baa1. Which were both reaffirmed recently. Our liquidity continues to strengthen, underpinned by strong operational performance and buoyant markets for our products. At the end of October, our liquidity was $9.4 billion, of which undrawn debt facilities were $4.1 billion. Our debt maturity profile is well managed, with an average portfolio term to maturity of 3.6 years and minimal maturities in the near term. Our strong balance sheet ensures we are well-positioned as we work through this period of high major capital expenditure. The chart on the screen shows an indicative forecast capital expenditure over the next five years. This is for committed activities only. If we were to take FID on additional major projects such as Trion, Calypso and H2OK, then the CapEx would be additional to the values shown here, and the total CapEx would be broadly aligned to the dotted line shown on the chart, the blue dotted line. Our capital expenditure is expected to peak next year, and we are guiding to a total investment expenditure range of $6 billion-$6.5 billion for 2023. This total amount includes some CapEx, which is being rephased from 2022 into 2023 and 2024. Both Sangomar and Scarborough remain on budget and on schedule. These investments are important to us, and the likes of Sangomar and Scarborough will maximize and generate future production and cash for decades to come. Our cash flows differentiate Woodside as an investment proposition. Today, we're presenting five-year indicative pro-projections for both operating cash flow and free cash flow. Once again, these are based on a range of assumptions, including a price deck representing the current forward curves for our products. Under these conditions, the business is expected to remain free cash flow positive through the current period of heightened capital expenditure. That is, we are essentially self-funding both Scarborough and Sangomar, even at current equity levels. Over the next five years, on the assumptions as outlined, we will generate on average $8 billion per annum of operating cash flow and $4 billion per annum free cash flow. This speaks to the value being delivered by the merger. I'd like to reflect on Woodside's dividend performance over the last five years. Our history of strong shareholder returns is something we are very proud of. Our disciplined approach to capital management provides a framework to ensure we continue to return value to our shareholders, and that is through the cycle. At the half year, our dividend represented an annualized yield of 9% and as mentioned previously, current cash flow generation supports ongoing returns. It's an exciting time for Woodside, and it's an exciting time for me as the CFO. We're in the middle of developing our first post-merger full-year results. As a result of the scale of the company and the additional reporting requirements following the merger, there has been a lot of change to how we report. I do appreciate your patience through this period of transition. We're finalizing the accounting impacts of the transaction, including items such as the purchase price allocation and depreciation as examples. Look forward to sharing the outcome with you in February. I'll now pass over to Mark Abbotsford, Executive Vice President, Marketing and Trading, to talk about our marketing strategy and activities. Thank you. Firstly, thank you, Graham. Good morning, everyone. It is an absolute pleasure to be here today at Woodside's Annual Investor Briefing Day. For those who don't know me, my name is Mark Abbotsford. I'm Executive Vice President of Marketing and Trading. As noted by Meg, global energy markets have undergone unprecedented change in the last couple of years. We've experienced two tail or black swan events. Whilst exceptional pricing is being realized across our portfolio, price volatility is at heightened levels and risks, including that related to counterparty performance, remain elevated. Tragic events had led to reduced pipeline gas supply to Europe with a significant swing towards LNG to meet that shortfall. These events have compounded conditions that were already evident in 2021, when gas prices were rising largely as a consequence of rising coal and carbon pricing within the European Union. Underinvestment in new LNG production has constrained supply both growth just at the point that the market needs it most. These events have fundamentally reshaped global energy markets. We have transitioned from being supply balanced to being supply short. They have also highlighted the importance of three key things to market participants. Firstly, the importance of access to affordable and reliable energy. Secondly, the importance of access to important infrastructure, specifically LNG shipping and LNG regasification capacity. Thirdly, the importance of possessing the capability to manage global market shocks and risks across the value chain. Against this macroeconomic backdrop, Woodside is positioned to capture value and manage risk underpinned by three key tenets. Firstly, Woodside has a diverse and flexible marketing portfolio of supply and delivery points across both the Asia Pacific and Atlantic basins, positions that we expanded through the merger with BHP Petroleum and which we look to grow. By way of example, the recent term deal with Uniper provides Woodside with certain cost-competitive physical access to the European gas hub market. Woodside is looking to continue to grow its portfolio and new markets, including through cost-competitive and flexible access to new LNG supply out of the United States. Secondly, our portfolio sales strategy is underpinned by ex-ship sales and strong logistics. Whilst LNG shipping is often taken for granted, access to shipping has become extremely constrained, with spot shipping rates recently hitting levels of approximately $400,000 a day. During 2022, Woodside has committed to a further six LNG carriers on long-term charter to support our growth, to reduce our operating costs and reduce emissions. Taken together, these two items provide a platform to create value upside and manage risk through shorter-term trading and portfolio optimization. As we look forward, Woodside will continue to be disciplined in seeking new term arrangements, leveraging our strong global customer relationships to layer volumes into the market throughout the cycle. This will provide a balance between oil-linked deals which provide portfolio optionality and gas hub-linked deals that provide portfolio flexibility. While much focus is on the near term, we are now seeing a renewed focus for long-term security of supply from our key buyers, often complemented with a desire for new energy initiatives. With uncommitted volumes in our portfolio and a growing portfolio of new energy projects, Woodside is very well positioned to meet these buyer needs. This provides a useful segue into the detail of our portfolio composition. Following the merger with BHP Petroleum, Woodside portfolio has a more diverse product and price mix, both of which serve to increase portfolio resilience. The portfolio has a greater weighting towards oil in the near term, with optionality and flexibility in the longer term from our growth projects and as contracts expire, including our Pluto foundation contracts from Q2 2025. This, along with confidence in the liquidity of the LNG spot market, provides an opportunity to consider an increase in gas hub indexation in our broader portfolio. As we specifically look at our equity LNG portfolio, Woodside expects to increase its exposure to gas hubs from current levels of approximately 20%-25% pre-Scarborough start up to 30%-35% in the longer term. These levels are post further oil-linked sales and potential reductions in Scarborough equity through any future sell down. The impact to the total equity produced portfolio will be a reduction in the overall indexation from oil and a reweighting towards gas. This portfolio mix is complemented by our low volatility portfolio of predominantly pipeline gas sales from Western Australia, Eastern Australia, Trinidad and Tobago, and the United States. At the right points, Woodside will seek to secure flexible oil-linked deals in its portfolio to regenerate optionality and to provide firm outlets. For example, Woodside recently concluded a term sale with a large end-end buyer in the Asia Pacific, providing Woodside with gas hub exposure for the first two years of that arrangement before reverting to strong, flexible hybrid pricing in the medium term. I would note that this slide does not include our trading portfolio, which is also exposed to gas hub pricing. As we have previously advised, Woodside's hedging program has largely mitigated downside outcomes in both 2023 and 2024. Our trading gas hub exposure is expected to grow in 2023 and further grow in 2024 and beyond. Moving closer to home. Woodside's Australian domestic gas portfolio has increased significantly as a result of the merger. As at 2023, Woodside's share of domestic gas production is expected to supply approximately 18% of the West Australian market from four supply points and 20% of the eastern gas market. 100% of the gas that Woodside produces and sells in Eastern Australia is consumed domestically. Prices have been increasing in both regions. New supply sources are key to meet demand. Woodside is proud to continue to make available and supply reliable gas in both WA and Eastern Australian gas markets. By way of example, Woodside has recently conducted an expression of interest in Eastern Australia for the sale of approximately 50 PJ of gas over 2024 and 2025. Over 20 companies were invited to participate. The expression of interest closed significantly oversubscribed. Woodside is now in the process of finalizing arrangements with selected parties will look to release further supply during 2023. Woodside is a signatory to the Gas Code of Conduct, we see gas as being critical to energy security across Australia, particularly as firming power demand becomes even more critical with falling coal generation and increasing penetration of renewables. To this end, we continue to progress our discussions with Viva Energy regarding the potential to supply LNG into Victoria. We work closely with our Gippsland JV partner to ensure that we maximize available supply into Eastern Australia in both the short and longer term. With that, I'll close and I'll hand across to our EVP of Projects, Matthew Ridolfi. Before Matthew joins us, we have a short video to share with you. Thank you very much. Located off the coast of Senegal is the world-class Sangomar oil field. Woodside Energy, as operator, has been working closely with its joint venture partner, PETROSEN, and the government of Senegal to progress the development of the Sangomar field. The Sangomar Field Development will be Senegal's first offshore oil development. The project is expected to deliver significant revenue to the Government of Senegal while providing social and economic benefits for generations to come. The development will be phased, focusing initially on the oil reservoirs which will support over 20 years of oil production and will be designed to support potential future phases. The first phase, called the Sangomar Field Development Phase 1, includes 23 wells linked to a network of state-of-the-art subsea systems, delivering the hydrocarbon resources to the Sangomar production facility. Following first oil, once the system is operational and fully commissioned, its design capacity will be 100,000 barrels of oil per day. This project provides an opportunity for Senegal to realize its energy potential and support a growing oil and gas industry. The Scarborough Gas Resource, located 375 km off Western Australia's north coast, is a resource well-suited to our times. Woodside's Scarborough interests include three gas fields, Scarborough, Phoebe, and Jupiter, with a combined gross best estimate resource base of 13.1 trillion cu. ft of gas. Gas will be transported through an approximately 430 km pipeline for processing at the Woodside-operated onshore Pluto liquefied natural gas or LNG facility, where a second gas processing train will be built, Pluto Train 2. The Scarborough development will process up to 8 million tons of LNG every year for international and domestic markets, with first cargo targeted for 2026. The expansion of Pluto LNG includes the construction and installation of additional domestic gas infrastructure with a production capacity of up to 225 TJ per day. Modification to the existing Pluto Train 1 will enable processing of up to 3 million tons, combined with the 5 million tons capacity of Pluto Train 2. Scarborough will support a strong economy, creating thousands of jobs in Western Australia, providing ongoing supply chain opportunities, and generating revenue to governments through taxes for decades to come. Good morning. My name is Matthew Ridolfi. It's my pleasure to be here today to talk to you about the projects business which I lead for Woodside Energy. Woodside's post-merger project portfolio has scale and is underpinned by strong project delivery capability. Our major operated projects are going well, and you just saw the video of Sangomar and Scarborough, and I'll come back and give you some further details on those projects shortly. We have a healthy pipeline of new opportunities, including the Trion development, which we're making ready for a final investment decision next year. Today, I'll provide you with an update on our project status, including how we've set ourselves up to take advantage of our global scale, manage risk in the current environment, so that we can deliver our projects safely at low cost and lower carbon. In bringing the two organizations together, we've combined the expertise of the two projects groups across oil, gas, LNG, onshore and offshore. We see benefits from the new organization in the way we can share knowledge between projects, also in the terms of our increased scope and scale that we have with our contractors and suppliers. We've seen strong performance. In the last 12 months, we've successfully executed the Greater Western Flank 3 project, the Pyxis Hub, and the Shenzi Subsea Multiphase Pump project, all ahead of schedule and under budget. You heard from Meg before about our broader strategy to ensure we remain competitive in a quickly changing world. This applies and holds true to projects as well, where we need to be safe, low cost, and provide lower carbon solutions. Safety is fundamental to everything we do and remains our number one priority across all of our activities, and we're always looking for ways to improve our safety performance and reduce risk. For our projects to compete in our capital management process, we need to be low cost, and we do so by focusing on being low cost but for the benefit of returns and value. Projects also has a major part to play in lowering carbon and meeting our emissions targets. The design decisions that our teams take early in the facility's life live with that facility throughout its production life. Moving on now to look at our projects pipeline across the conventional oil and gas businesses. You can see we have a strong mix of sanctioned projects and a healthy pipeline of new opportunities. We're very focused on our sanctioned projects of delivering them on time, safely, and under budget. We're also planning the developments of the future like Trion, and I'll come back and give you some further details on what we're doing on Trion. We work closely with the exploration and development team led by Andy Drummond to ensure that we properly plan and prioritize those opportunities that his team secures. Likewise, we work closely with the Australian and International operations teams on their brownfield subsea tieback opportunities that we have throughout our producing assets. Now, all of these opportunities need to compete for capital and are evaluated in an open and transparent way in accordance with our capital management framework that Graham outlined earlier. Now returning to our major operated projects currently execution phase. Firstly, the Sangomar team has been doing an outstanding job over the last couple of years in progressing the project despite the impacts of COVID since we took FID in early 2020. I'm pleased to say the project is now 72% complete. Our current focus is on three delivery areas. Firstly, the drilling program is progressing well, and we've drilled and completed six out of the 23 development wells. We've drilled a further two that are waiting to be completed, and another eight have actually started drilling through our batch drilling activities. We're very pleased with the drilling performance, including with respect to safety, and the reservoir results to date have also been in line with expectations. Secondly, the FPSO conversion activities have recently wrapped up in China, and the FPSO is on its way down to Singapore for inspection, commissioning, and final integration activities. The FPSO conversion is where we saw the greatest impact of COVID, with multiple lockdowns and reduced workforce availability. This is some footage of the FPSO being towed down from China to Singapore. It's a credit to the Sangomar team that we've been able to deliver the scope, remain on budget, and remain on target for first oil in 2023. I'd also like to acknowledge the excellent safety performance that was achieved in the yards in China with over 16 million hours worked without a lost time event. Finally, on Sangomar, the subsea equipment is nearing completion, and the offshore construction has commenced. We've already installed 69 km out of 101 km of rigid pipe in the field and also installed 64 out of the 111 permanent subsea structures that form the field. Now turning to our second major operated project, Scarborough, which is just past one year since we took final investment decision. The project is currently 23% complete and remains on budget and on schedule. Here our current focus is on completing detailed design, procurement, and early fabrication activities. Construction works at Pluto Train Two have commenced and are progressing safely. Recently, we opened the first phase of the workers' accommodation village in Karratha, which is a major milestone for the project providing 600 beds. We'll continue the construction of this facility in 2023, we'll peak at 2,000 beds being available. The Scarborough trunkline fabrication is also ahead of schedule with 254 km of pipe already manufactured out of a total of 440 km. All of the subsea trees that are required for startup of Scarborough have been delivered or are in Perth. The floating production unit procurement is progressing, and we now have fabrication yards up and running in China, and we're also leveraging the lessons that we took away from Scarborough, how to manage COVID in those yards. Really great progress overall on our major operated projects. While we've had great progress, we continue to also actively monitor market conditions for any potential impact, and I'll talk about some of those risks now. We currently see common risk themes across the industry as well as some that are unique to particular projects or particular regional operating environments. Our approach to dealing with these is the same. We seek to understand early, engage broadly with the critical stakeholders, and minimize any cost or schedule impacts to maximize value. Inflation and supply chain pressures are currently affecting all parts of our industry. We've been able to mitigate some of these through our contracting strategies, and we continue to work with our contractors to minimize any impacts. On Sangomar, we are 72% complete, and as such, a large portion of our project costs and rates are now locked in. At Scarborough, we front-end loaded the project's scope definition and execution planning, which has helped mitigate these risks. We also secured our contractors early before the pandemic and the Ukraine conflict. This has enabled us to build very strong relationships and work with our contractors through these difficult times. We also secured a large portion of expenditure at fixed rates or lump sums with contractual mechanisms to manage cost pressures and supply chain disruption. Our increased scale also helps us again here, where we can leverage learnings across our projects and benefit from the broader relationships that we have with our suppliers. On Scarborough, we are continuing to work with the regulator to secure the secondary approvals that we need for the offshore part of the project. Some delays have been experienced in obtaining environmental plans in federal waters following the outcome of the recent federal court decision associated with the Santos Barossa proceedings. At this stage, there has been no impact to the Scarborough critical path. Turning our attention to a new region of the world for Woodside, Mexico. Mexico provides us with an opportunity to leverage our deep water US Gulf of Mexico experience as we progress our pipeline of conventional opportunities. The specific opportunity that we have at this stage in Mexico is Trion, which is a significant discovered oil resource that has a fast payback period. We've built a strong relationship with our joint venture partner, PEMEX, and the other key stakeholders in Mexico. We are on track for FID readiness in 2023. This next slide provides an overview of the proposed conceptual development of Trion. The floating production unit would be a semi-submersible with production capacity of up to 100,000 barrels of oil a day. The initial field development would also include gas injection and water injection wells. The expected Scope 1 and Scope 2 emissions from Trion at 12.6 kg of CO₂ equivalent per BOE are below industry average for deepwater development. We've achieved this through efficient design, and we will continue to look for further ways to reduce our emissions. The Trion subsea infrastructure is designed to allow tiebacks and in-field opportunities and also includes a link to a gas export link to existing infrastructure in Mexico. Trion is a mature investment opportunity in Woodside's portfolio. The technical work is well advanced, and we have a clear pathway to FID in 2023. The key remaining item in FID readiness is to select the FPU contractor, and we're on target to do that in the first half of 2023. In closing, we have a strong projects delivery capability and a material operated portfolio that enables us to deliver effectively. Our major operator projects are progressing well. We're aware of the risks that we're facing in the current environment, and we're actively working to mitigate them, and we have a healthy pipeline of future opportunities. That concludes my section covering projects. Thank you for your time. I'll now hand over to Brayden. Thanks, Matthew. Thank you all for joining us here today. For those I haven't met, my name is Breyden Lonnie, and I'm the vice president of the North West Shelf. I've been with Woodside for 18 years now, and I've worked in a variety of roles across operations and across project delivery, culminating in the last seven years where I've been based in Karratha with responsibility for the Karratha gas plant. Today I'd like to talk about how we are maximizing value across all of our Australian operating assets. The map on the right provides the overview of our Australian operating assets post the merger with BHP Petroleum earlier this year. The merger has given us a number of things in the Australian operating business. It's provided exposure to Australia's East Coast domestic gas market through the Bass Strait assets. It's doubled our interest in the North West Shelf joint venture, and it's provided other additional oil and gas assets by way of the Pyrenees asset and Macedon. With increased scale comes the opportunity to run our business more efficiently and also to take greater opportunity of the synergies as we look to share learnings across an increased base of operating assets. We have a very simple framework for how we maximize value from our operating assets, and that is to focus on safe, reliable, low cost and lower carbon operations. The safety of our people is absolutely our highest priority. The process safety performance measures and high consequence injuries are at or below target, including zero high consequence injuries year to date. Personal safety performance is not at target across our Australian operating assets, but it is improving. We have implemented specific improvement plans that focus on the foundations of good safety performance that continue to build on a culture of care and that strengthen our ability to respond to changes that may arise in the future. Back to process safety performance. Process safety performance for us at Woodside is an absolute non-negotiable. It keeps our people and our assets safe. Our process safety systems and processes are embedded across our operational roles and activities, and there is an ongoing program to make sure that we administer, that we assure, and that we continue to learn from process safety events. It's essential that we keep our costs under control without compromising safety. This is fundamental to remain competitive and delivering high margins. Cost control is more challenging in an inflationary environment and also with the North West Shelf in reservoir decline. The solution is to innovate how we run our business and also how we employ technology to become more efficient. We have recently implemented a new operating model across operations, which creates a major, a more enabled workforce through stronger line accountability. We're leveraging technology through the use of digital tools, such as our new digital permit to work system, which has fundamentally improved tool time for our frontline operations and maintenance workforce. The majority of Woodside Scope 1 and 2 emissions come from our operations, so how we operate our facilities has a direct impact on our progress towards our corporate emissions reduction targets. Across our heritage Woodside assets, we have been developing asset decarbonization plans which we are now working to embed. The plans identify opportunities to reduce emissions, such as improving the efficiency of our gas turbines, which are economic when considering the improved performance from those machines, as well as the cost of carbon abatement. Another operate out initiative that we are assessing is the use of solar power to generate electricity for the Pluto LNG facility. The electricity could be supplied from the proposed Woodside solar project, which will be based in Karratha in Western Australia. This would reduce our Scope 1 greenhouse gas emissions and increase the amount of gas from Pluto that could be directed to sale as opposed to power generation. Beyond our focus on safe, low cost and lower carbon operations, we have other ways to maximize value from our operating assets. Clearly, maintaining high facility reliability is a key metric for us. A reliable plant is a safe plant, but it is also an efficient plant. Our October year to date LNG reliability at Pluto is 98.5%, and across the Karratha Gas Plant is 98.7%. We look forward to 2023, we have a turnaround at Pluto LNG planned for the second quarter of next year, which is expected to be approximately four weeks long. On the Bass Strait, operator has continued to maximize production, enabling the asset to respond positively to East Coast market conditions. For example, in June of this year, the pipeline network was optimized, which increased production capacity from 970 TJ per day to 1,020 TJ per day. To maximize utilization of our existing infrastructure, we have also delivered a number of drill and tieback programs this year. This includes the Greater Western Flank 3 project, Lambert Deep project, and Julimar-Brunello Phase 2. Each of these projects were delivered ahead of schedule and under budget. The Xena-2 Well achieved ready for startup in November of this year, and this was delivered on schedule and under budget as well. Infield and near field drill and tieback opportunities generally have a lower cost of capital and have a faster payback period. We're also thinking creatively about how we can leverage our position as an operator across multiple facilities. An exciting milestone occurred this year when Pluto gas was transported through the Pluto-KGP Interconnector into the Karratha Gas Plant and processed using available capacity at the North West Shelf. 8 million barrels of oil equivalent from Pluto was accelerated and sold into high price markets, creating significant value upside for Woodside. Now that this has proved the concept for tolling other resource operators' gas, we are looking for other opportunities to take third-party gas into the North West Shelf. The chart on the right demonstrates the indicative contribution of the Australian assets to Woodside's production over the next five years. Following 2023, which is the first full year of production post-merger, Australian production does taper off primarily due to the North West Shelf being in decline. If the North West Shelf utilization remains below 100%, we will consider taking off one of the LNG trains, taking it offline in 2024, which will help with both cost and emissions efficiency. Towards the end of this period, Australian operations production ramps up, and that is due to Scarborough coming online. I briefly spoke about asset decarbonization plans earlier. The chart on the right demonstrates the potential impact of asset decarbonization plans and what it could do to reducing Woodside's net equity Scope 1 and Scope 2 emissions, which is up to 300 kt by 2030. It's important to note that this chart reflects the decarbonization plans associated with Woodside Heritage assets, and that we have plans in place to develop decarbonization plans for our Heritage BHP assets in the near future. The final topic I'd like to discuss is decommissioning. Woodside has both operated and non-operated interests in several late life assets, and decommissioning will be an ongoing feature of our activity plans in the future. The chart provides indicative cumulative decommissioning spend over the next seven years. We are collaborating across the industry to identify opportunities to learn and get better in the space of safety, environment, and cost. We're also investing in the National Decommissioning Research Initiative. I would like to also highlight that decommissioning expenditure is nearly all local content, provides significant benefits to local contractors, and by extension, impact to local communities. As you can see, there is a lot of activity across our Australian operating portfolio. Woodside has never been better set up to deliver outstanding operational performance. The merger has increased the potential for efficiencies of scale. We have consolidated two great heritage organization with a much broader experience base that we can take advantage, and we are absolutely focused on doing the right things extremely well. On that, I'd like to pass over to Shiva McMahon, who will discuss our International operating assets. Thank you. Good morning, everyone. I'm Shiva McMahon, EVP for International Operations, and it's an absolute pleasure to be here today to talk to you about our International operations business. We have world-class assets with a great embedded growth options. This is a high-margin business, and our teams continue to identify opportunities to expand the value of these assets. Consistent with the broader Woodside strategy, I'm focused on our business being safe, low cost, and lower carbon to deliver value and shareholder return. The key elements of our International business today are our Caribbean assets and our Gulf of Mexico position. These are both basins that we have operated and co-owned in for many decades and have an established track record of safe operations. One of the areas that I'm quite proud of is around how our mature safety processes show up and are prioritized in field leadership. We have a combined culture of safe of field leadership between our contractors and our employees. We work as one team at our sites where everyone feels empowered and an integral part of the team. This is fundamental to building a strong safety culture. We also have a long-standing focus on cost discipline. Over the last couple of years, we also restructured our operations to be most cost competitive. This has positioned us for resilience well into the future, regardless of the oil price environment. Our teams are focused on maintaining safe as well as efficient operations. One example is the recent extension of our living quarters at Shenzi. The progress of our maintenance program, as well as some of our value-adding projects, were constrained by availability of bed space offshore. Our engineering and operations team were able to demonstrate that extending the existing living quarters was actually more cost effective than deploying short-term rental accommodation or flotels. This was the right thing to do from an asset integrity perspective, but also from a value lens. It shows the continuous improvement mindset that our teams apply every day. Our assets are also lower carbon. The Gulf of Mexico is one of the lowest emissions intensity basins globally, and this has been highlighted amongst others through a recent Wood Mackenzie study on greenhouse gas intensity. It has favorable fluids, facility design, and operating practices that limit emissions. Our assets are consistent with that. Our portfolio is shown on the right. Our Gulf of Mexico position has a remaining resource base of almost 1 billion barrels. I'll come back to that in just a moment. In the Caribbean, where we've had operating presence for over 20 years, we've built very strong relationships with the government, and we've also had a positive impact on the community. Here, where our producing assets are later life, our focus is on safe operations and on optimizing our performance. Safely maximizing the base while we evaluate opportunities for growth in the region, and you'll hear a lot more about that in Andy Drummond's section. This is one area where knowledge-sharing across the merged organization has already borne some fruit. Australian operations have significantly reduced their ongoing fabric maintenance backlog through leveraging a single-coat paint system that also reduces reliance on dedicated paint crews. That is now being piloted in the Caribbean, and I'm pretty confident it will help us reduce our man-hours offshore, our costs, while also reducing our risk to our business. Looking at slide 48, it shows our current Gulf of Mexico position. We are the 6th largest producer in the Gulf of Mexico by volume, and we have a demonstrated capability of managing the resources for value and moving them through to production. Today, we have three anchor assets. Shenzi is operated, and we also have non-operated positions in Atlantis and in Mad Dog. These are deepwater, high-quality oil assets, and these large fields have already had multiple phases of development since they were first sanctioned in the early 2000s. Each of Shenzi, Mad Dog, and Atlantis have one of the top 10 most prolific wells in the Gulf of Mexico. We also have a track record of executing profitable projects to extend the life of these assets. Over the last 12 months at Shenzi, we brought online the subsea multiphase pump that Matthew talked about earlier on. This helped us improve production from our base wells, it's also expected to help us with some of our development wells as well. We also brought on a sidetrack. Right now we are executing the Shenzi North project, which is a two-well near-field tieback opportunity. This is just an example of the constant optimization that our teams do on our assets. We learn more about the field from our production. We identify opportunities to extend the value. We execute them systematically. Mad Dog and Atlantis are very similar. At Atlantis, we see remaining growth in additional wells, in subsea expansion, and in facility modification to help with water injection and water handling. All of this gives us a very healthy pipeline of future opportunities. As Mad Dog Phase 2 starts, we expect to learn more about the reservoirs as well and use the information to further inform value-adding projects. Given the infrastructure is already in place and these reservoirs have quite large volumes, these projects are generally pretty short payback and high return, and you'll see that in a later slide that I'm gonna show. I'll now move to slide 49. The indicative production profile shows that our Gulf of Mexico production, which is the dark blue on the screen behind me, is actually increasing, and this increase is more than offsetting the underlying base decline. This includes a number of tiebacks and, of course, project optimization, production optimization projects, it also includes Mad Dog Phase 2. While, as you know, the operator is working through some commissioning delays, we absolutely expect it to start up in 2023. The production profile also shows our Caribbean production, and when we bring on Sangomar, the growing contribution of International operations into the Woodside portfolio. Moving to slide 50. This highlights the return or some of our unsanctioned projects in the Gulf of Mexico. One of the technologies that's been absolutely instrumental to our infill drilling program and water injection optimization projects has been the ocean bottom node seismic surveys, or OBN. At Atlantis, for example, we've just acquired our fifth OBN survey. This gives us a 4D view of the reservoir, which allows us to target unswept oil. To wrap up, our I nternational business is very well-placed to continue to deliver value safely and reliably. It has an exciting portfolio that will expand further when Sangomar starts up. With that, I'd like to hand over to Andy, who's gonna take us through our exploration and development portfolio. Thank you very much. Thank you. Thank Thank you, Shiva. Hello, good morning. I am Andy Drummond, Executive Vice President for Exploration and Development. Today, I'll be talking to you about the front end of our oil and gas growth pipeline. This includes both our exploration and development business, where we take discovered options through to concept select before handing over to Matthew in Projects. We believe this model can increase the pace of developments by reaching concept select recommendations faster and allowing projects to move straight into design and execution activities. Based on our conversations to date, I know you would like to hear three things: How do we think about the need for future hydrocarbons, and what's the role of exploration? What will make us successful? What do we think of our current development growth options? Meg shared the global outlook. It is clear that in a transitioning world, the hydrocarbon molecules that will be developed to satisfy demand will be lower carbon, low-cost molecules. In a number of those scenarios Meg showed, there are enough discovered resources around the world today to satisfy demand. However, there are a number of these resources that, in our opinion, will not or should not be developed. That may be because of cost, carbon intensity, technology, or geopolitical reasons. The role of exploration at Woodside is to add valuable opportunities to the portfolio that are more competitive from a cost and carbon perspective. Moving to slide 52. To be successful, we are focused on building a portfolio that delivers quality through choice. We want a diverse set of options that will be assessed through risk and value lenses. We manage the risk of the portfolio by creating diversity of play types, geologies, and proximity to existing infrastructure. We manage the risk of the options by characterizing both the subsurface and above-ground elements, such as the fiscal and regulatory environment. Leveraging joint ventures can help manage our risk exposure by supplementing capabilities and giving access to technology or infrastructure. We recently announced two joint ventures in our Western Gulf of Mexico position. This allows us to test more for the same spend and has brought additional views of the subsurface to the table, along with additional seismic volumes to evaluate the option set. From a value perspective, we are focused on exploration options that can be commercialized fast. Fast to market is a key driver for improving returns on our exploration dollars. However, all opportunities must still compete within our capital allocation framework. To compete, options will need the right combination of reservoir rock and fluids paired with proven development concepts and have access to markets. We are seeing industry trends to improve development costs. This can include phased developments and the use of standardized development designs to reduce cost. We now have detailed designs for Sangomar, Scarborough, and Trion. Similar facilities may be appropriate for discoveries with similar fluids and ocean conditions. Let me talk about the budget. We will execute this strategy with a moderate budget. This moderate budget challenges us to be disciplined on what opportunities we progress and ensures we progress them in a cost-effective manner. This is a key component to our quality through choice strategy. To that end, we have reduced our budget from the combined heritage companies. Annually, we will need to balance the budget between additional data and acquisition costs to bring new options into the portfolio and testing new and existing options through drilling. Let's move on to some of the current development options where we have a great hopper of options in the portfolio today. Our focus is on addressing the key items to unlock each option and how they fit in our capital allocation framework. Moving to slide 53. First is Calypso, which is a series of discoveries in the deep water of Trinidad and Tobago. Why do we like it? To date, we have discovered over 3.2 TCF of gross 2C contingent resource in a country with a great market outlook. First, there are LNG trains with ullage. Second, there is a petrochemicals industry that relies on gas as a feedstock. Third, there is a domestic gas market. As Shiva McMahon mentioned, we have a long history in country and a great relationship with the government who are keen to support this development. With that, our focus at present is selecting the development concept and identifying the best commercial and marketing solutions. Slide 54 is Browse. Browse is a large discovery off west coast of Australia. As mentioned earlier, the Karratha Gas Plant is starting to see ullage. Browse is a natural backfill for this ullage. From a development perspective, leveraging the existing infrastructure would enable a competitive option to feed the Asian LNG markets while providing additional domestic gas security for Western Australia. The three focus areas for Browse are a carbon solution to ensure it's a low-carbon development, commercial agreements for tolling through the North West Shelf, and acquiring the environmental approvals. Slide 55 is Greater Sunrise. Another material gas discovery in the waters between Australia and Timor-Leste. Again, well-placed for the expected longer-term Asian LNG demand. The field has a couple of development options, including sending the gas to Australia to leverage existing LNG plants or a greenfield LNG train in Timor-Leste. Both have the opportunity to aid the communities in Timor-Leste. The current focus is on agreeing the terms of the production sharing contract between the two countries and the joint venture and selecting the development concept. Thank you for the opportunity to talk to you today. In summary, I would like to leave you with, we remain committed to exploring for hydrocarbons. We will enable success by building a portfolio that delivers quality through choice, and we currently have a great set of development options to choose from. With that, I'll hand over to Shaun. Thanks, Andy. Thanks, Andy. Good morning. My name is Shaun Gregory. I head up Woodside's new energy team. The scale of the energy transition and decarbonization journey is unlike anything we've seen before. It took over a century to build today's integrated energy infrastructure and several decades to create today's global LNG industry. We need to build an entirely new energy supply chain, one that does not yet exist while maintaining uninterrupted supply. This is complex. It must be orderly. It must be affordable. This is why we start with the customers. It is with the customers that we get insights into what they want and when in regards to the energy transition. The development of new energy markets is very similar to the development of the LNG industry many years ago. We are building relationships across the value chain and are aligning solutions to those customers with options to scale to match the pace of the energy transition. This is an important point. The transition timing is very uncertain. We're developing the options to match that pace however it plays out. Our new energy products target hydrogen and ammonia production, leveraging our experience as a safe and reliable energy producer. Producing hydrocarbons is a complex process, and Woodside has been doing it for almost 40 years. It is our core capability, and we are leveraging it going forward. We also have integrated carbon solutions to help decarbonize and reduce emissions for our business and for those of our customers. Building on our carbon management strategy, where we are focused in three areas: offsets, carbon capture and storage, and carbon to products. On offsets, they are important because they are available to us now and in the short and medium term for emissions that cannot otherwise be avoided or reduced. We have continued to build a diverse portfolio of high-integrity offsets to support Woodside's 2030 net emissions reduction targets for our merged business. Our second focus area is CCS. We're leveraging the capabilities that Andy has in exploration and development to identify reservoirs suitable for CCS. We see potential for large-scale CO₂ storage, which will be important to making a step change in abatement for ourselves and our customers. Woodside, as a participant in various joint ventures, was recently awarded three licenses across the Australian basins to study CCS. Our third focus area is carbon to products. Woodside is investing in technology advancement to convert carbon into useful products. This is an emerging technology. Woodside has been collaborating with several companies to drive the development of these CCU technologies. It's an exciting future to watch. Let's talk about end-use markets that we target for hydrogen and ammonia. First, heavy-duty transport. We're focused on liquid hydrogen as a potential substitute for diesel. Truck manufacturers are developing fuel cell-based trucks that need liquid hydrogen as fuel. Our H2Oklahoma project targets this end use. Second, we're targeting investment in ammonia for power generation. It can help in decarbonizing a coal-fired power generation at scale, where co-firing of ammonia is a large-scale opportunity that we are collaborating with customers in Japan and beyond. Third, our ammonia projects will also target the shipping and marine fuels market. It is one potential fuel that can contribute to the decarbonization of the maritime supply chain. Finally, hard-to-abate sectors such as industrial and chemicals. There is increasing opportunity for lower carbon hydrogen and ammonia to replace existing industrial feedstock. Turning to our portfolio, this slide summarizes our announced new energy projects. It's the starting point. We aim to grow and be flexible in line with customer demand. All of these projects are scalable. Brayden already mentioned the solar opportunity in the Pilbara to decarbonize our base assets, where this week we announced an indigenous land use agreement. Also this week, we were selected as the preferred partner for the Southern Green Hydrogen Project in New Zealand. This project, along with H2TAS, are well-positioned to access advantaged renewable hydropower. In H2Perth, we are advancing through pre-FEED and have begun market inquiry for feedstock renewables. Before we talk about H2OK, I can't forget Heliogen, a breakthrough AI-enabled solar technology that addresses the intermittency problem of renewables. We look forward to helping progress this technology to commercial scale. I want to take a moment to discuss our most advanced hydrogen project that in H2OK in the U.S. The passing of the Inflation Reduction Act has catapulted the U.S. to the forefront of global energy transition by accelerating key markets through policy and economic support. This provides a potential opportunity to increase the returns for the H2OK project. Woodside is well-positioned as we are looking to develop H2OK, as it is in a strategic transport and supply chain corridor, making it close to customers who wish to adopt hydrogen as a fuel in the heavy transport sector. We secured electrolysers in October and are expecting to finalize FEED this month and are targeting to be final investment ready in 2023. Just a few comments on how we see the new energy value chain. The oil and gas value chain is typically described in three segments: upstream, midstream, and downstream. We believe that the new energy value chain is thought of in similar segments. Upstream is about the location for power, water, and other infrastructure. We target our facilities in location that have advantage access to low-cost renewables and enabling infrastructure. Midstream is our focus, where we're leveraging our experience as a safe and reliable energy producer and supplying industrial-scale volumes to customers. We see this as a competitive advantage for us in the processing, electrolysis, and liquefaction as we embark on our new energy journey. Customers is about relationships, which we have been investing in for decades with our traditional LNG buyers, as Mark mentioned, we're extending that to new and emerging customers in new energy. To wrap up, this is a critical time for our industry and a fascinating time to be involved in new energy. We have made some big steps forward in our strategy to develop the products and solutions to help decarbonize our own business and that of our customers. We're targeting the parts of the value chain that not only play to our strengths, but should also deliver the best return on investment. I'll hand back to Meg now to close. All right. Thank you, Shaun. We've covered a lot of territory today, and I'm sure you're impressed as impressed as I am with the capability, strength, and depth of leadership that we have on the Woodside executive team. I believe the investment case in our company is compelling, and I hope that after what you have seen today, you will agree. We have a quality portfolio. We are oriented towards LNG. We have high-quality opportunities to grow the business, both in the near term and in the longer term. We have a disciplined approach to capital management, where we ensure that we are able to make investments, that we protect the balance sheet, and we are able to return value to shareholders through the cycle. Finally, we are very well-positioned to navigate the energy transition and provide the energy that the world needs as it seeks to secure energy that is affordable, reliable, and lower carbon. We'll take a short break, about a five-minute break, and then we'll be back for questions and answers, and we look forward to hearing from the floor at that point in time. Thank you. Welcome back to the second half of the Investor Briefing Day 2022. We have around 45 minutes for Q&A. There are a few roving mics. We've got Sham, Rowan, and Sarah wandering around. If you'd like to ask a question, please just raise your hand and they will come to you. When it's time to ask your question, please ensure you use the microphone so people on the webcast can hear. Please also state your name and where you're from. I would like to ask if you could please limit your questions to two. We wanna make sure everybody has an opportunity to be heard. With that, I'd like to welcome Meg to the stage again, and we'll get going. Mark. Can you hear me okay? Number 11. Hear me now? Yeah. Perfect. There we go. What a change from Woodside Investor Day, I get the first question. Thank you. It's Mark Samter from MST. First question, Meg, just with the Scarborough sell down, and it sounded like maybe a bit of a push on the process there. Can you give us any indication there's been a process running for a while? Mm-hmm. Did you reach the stage where you got bids and you weren't happy with the bids, or was it perhaps international potential owners are looking at the debacle of Australian energy policy at the moment and not wanting to act? Can you just give us some color maybe how the process played out? Well, thanks for the question, Mark. We're always pleased to field questions from you. From a Scarborough sell down perspective, we have been talking to a number of quality counterparties, potential counterparties. One of the things that our the merger provides for us is a strong balance sheet. We've got the ability, and we've got probably the luxury of being able to be quite selective about a sell down. In fact, potentially selecting not to sell down. We've been very disciplined in who we talk to, wanting to make sure that we're talking to quality counterparties who share our view of LNG as a strategic commodity. We wanna make sure that we get the right price. We're not schedule-driven by the process, we'll continue talking to interested parties. I think it is worth sharing, just to maybe give a bit of color, that there are multiple quality parties that we are continuing to talk to. You know, when we have something to announce, we'll announce it, but we're not schedule-driven. Thanks, Meg. Second question, if I can. I don't know if this is for you or for Graham. I think when we look and it's great that you've given us those, operating cash flow and free cash flow numbers. Mm-hmm. I suspect the next couple of years, they favor a bit less than the market has. I just wonder, in that context, when you consider the Trion potential FID. Mm-hmm. Do you have a view on your base case macro assumptions, whether you can FID Trion and sustain the payout ratio at 80%, or do you think it's a bit of an either/or? As Graham has described, there are a few guardrails in our capital management philosophy. We are committed to strong investment grade credit rating. We have a dividend policy that pays out 50% of net profit after tax, excluding underlying or excluding ex-exceptional events. We've got a track record, as Graham showed, of paying out at the upper end of our target range, the 50%-80%. Those are two counterpoints that are very important as we think about our funding capacity. Everything in between, you know, we have investment commitments that we've already made. As you saw from the slides, you know, we've provided guidance for next year, which is $6 billion-$6.5 billion. If you look at the charts for 2024, it's in the $4.5 billion-$5 billion range. We do need to make sure that we can fund those projects. We do need to make sure that we're able to do that if there is a price shock. Any potential investment decision that comes in over the top of that, we'll take a look at, you know, what's the capital requirement in particularly 2023 and 2024, and will we be able to afford that or not. Our current assessment is that we can afford to take FID on Trion, and we can afford to take FID on Oklahoma. Those are both investment decisions that we want to be ready to make next year. It'll depend on the economic merits. As Matthew stated, we're in the contractor market today, getting bids on the FPU, which is one of the significant cost components. That'll help inform that decision. The team clearly understands the sort of return and payback periods that we need to be getting from those sorts of oil investments. You know, that's the work that's underway as it stands. Similar on H2OK. You know, Shaun's team is out talking to potential customers, looking for offtake deals, wanting, you know, we need to secure our power, purchase agreements, and, you know, firm up the cost of the development. All of that'll inform those investment decisions. Thanks, Meg. Can we get Tom down here? Sham? Do you want to Tom it? We should do. All right. I'll ask it. Sorry. Daniel Butcher from CLSA. Just wondering firstly, in the context of the rumored gas price cap that's coming in, would you ever just provide us with a little bit of color where you can on the contractual profile for Gippsland Basin JV, Bass Strait in terms of the roll-off, any contracts you have, and maybe a rough split of oil linked versus fixed price versus spot sales? Thanks. Sure. As Mark noted, we actually went through an EOI process just a few months ago to offer to the market 50 PJ of gas. The process was run in a quite transparent way. You know, we asked the potential gas buyers to say, "Well, how much gas do you need?" What's the, you know, the preferred pricing mechanism for you as a customer? You know, we got great uptake of the offer. We have been signing agreements with customers, we'll continue to progress agreements. As Mark noted, we'll continue to put volumes on the market ratably. One of the things that we have with the Bass Strait, you know, with the decline profile we're in, and with a seasonal demand profile in Eastern Australia, you know, where winter demand tends to spike, and we saw that very clearly this past year, we need to make sure that we are ratable in our contracting. You know, we don't wanna get in a situation where we are unable to meet our customers' needs. That's why we go out with these parcels year after year. Look, we don't talk about the specifics of any contracts. That's, you know, kind of private business between us and the customers. I would say that they're prices that both the seller and the buyer think are fair. That means those are prices that, again, the buyer thinks they can continue to run their business in a profitable manner. I'll commend the buyers who have participated in that process for taking care of their business and ensuring that they have reliable energy for the future. All right. Thanks. If I could maybe just try a second one on Trion. Thanks for the CapEx range there. Do you have in mind roughly what the breakeven oil price would be that would be for that project with your 15% IRR that you're targeting? Maybe could you give us maybe a little bit more color on what sort of Mexican gas price linkage there is and whether the FPSO would be leased or owned in that CapEx figure? Yeah. We haven't put out a breakeven target price on a project-by-project basis. What hopefully was useful for you to understand is our current operating business cash breakeven, which is that $30. You know, read the footnote 'cause it's got clarity on what's included in that calculation. We haven't put that out to market. The gas does go into the Mexican market. Look, I would say that that's not a huge driver of the value of the Trion opportunity. Our starting position is that the FSO will be leased. All right. Thanks. Sorry, Tom. Maybe we'll go to this side of the room, but you'll be in the on-deck circle, to use a baseball analogy. Dale Koenders from Barrenjoey. I just wanted to dive a little bit deeper on the free cash flow chart that Mark was talking about before. you know, that doesn't actually include the CapEx for Trion and for the Oklahoma H2 project. It doesn't include that for future growth CapEx for Calypso or Sunrise or Browse, and it doesn't include, given it's not sanctioned, the $5 billion on new energy spend. Is that the way to think about that outlook? That's correct. What we have in there is everything that's sanctioned, so that's spend on those projects, that is anticipated for next year, but not any of the significant investment. Graham's CapEx chart showed what the CapEx profile would look like in 2024 and beyond. It's worth noting that CapEx doesn't move a whole lot in 2023 if we do or don't sanction those projects, so it's probably in the width of the line or your round off. But for 2024 plus, you can get a sense for what that future capital looks like from the chart that Graham provided. That was inclusive of Calypso, Trion and H2 Oklahoma. I guess consensus dividend forecast through Visible Alpha around $4 billion per annum really does chew up the remaining of that free cash flow before thinking about growth. As Woodside progresses as a company and gets towards 2024 and 2025 and has this next wave of growth, do you know think there is a decision point where you might need to pull back your dividend payout, which is really, I think, Mark's question, if you want to progress with some of these really exciting growth opportunities that you have in the portfolio if forward oil price is right and if there are no asset sell downs? Is that the right way to think about the outlook? Our shareholders have been very clear, and a number of shareholders are in the room about the value they place on the Woodside dividend. We went through a pretty comprehensive analysis last year to explore the dividend policy and to examine alternatives, you know, surveilling the market and understanding what others do, and we reaffirmed that our policy is to pay out 50% of net profit after tax. We find that gives a more stable and predictable return for our shareholders, you know, and avoids some of the wild swings that you might see if you used other metrics. The 50% commitment is the 50% dividend payout policy is a commitment to our shareholders. As I noted, we've been paying out at 80%. Market conditions this year have allowed us to continue to do so. We will assess each dividend paying period, again, as we look at the projection for forward capital, as we look at the projection for forward pricing. Make those decisions at that point in time. Okay. Thank you. Okay. We'll go back to Tom. Tom. Yeah. Sure. Thanks, Meg. I was hoping you'd just please provide some more detail on the key takeaways that came out of the strategic review. You mentioned that you didn't find any more opportunities for high grading. Mm-hmm. Can you confirm whether your aspirations included asset consolidation opportunities? I recall earlier this year you'd mentioned that there were attractive opportunities in the Gulf of Mexico that might have allowed Woodside to expand its operatorship in the region. Is that still a live option? Absolutely. If you look at the Gulf of Mexico, I think Shiva's presentation nicely articulated our current business. You know, we've got three deepwater tier one assets with quite a bit of running room, and I think a key chart to take away is the undeveloped potential in our existing asset base. You look at what's going on in the Gulf of Mexico, it's a basin where there's always been a lot of deal space. We will continue to look at opportunities to grow the business in North America. Any guidance on the size of opportunity that you're looking at there? No. No worries. You can only try. Also just extending the previous question on the capital demands of the business into the longer term. The chart there on, I think slide 25 was very helpful, but the only energy transition project in there was the H2OK, the Oklahoma project. Maybe a little bit more clarity on how you plan to deploy the remainder of that $5 billion from the very end of the decade, just on maybe the key project buckets and... Sure. Shaun outlined a number of the projects that we are working on. I know the capital chart only went out for a five-year period with those projects. The Oklahoma project is the most advanced. You know, FEED is nearing completion. We're approaching a point where we can make an investment decision next year. There is a series of dominoes that follow in pretty quick succession. It depends on a number of factors. We need to progress the technical work. We need to progress regulatory approvals. We need the right sort of commercial agreements, both for, you know, purchase of input commodities, things like power and water, and then on sale agreements to customers. We would want to be able to progress those projects through a series of investment decisions, you know, as we move into the middle period of this decade. You know, Oklahoma in 2023. You know, our aspiration is to be ready to take another FID in 2024. Again, it depends a bit on all those factors lining up and having success in progressing the project. We do have a plan that says we can get to the $5 billion spend with those opportunities that we have described already. But we're working through all the details. You know, I'm keen on making sure we don't promise too many things and then not make it, 'cause there are still a lot of open switches on it. As Shaun noted, the key factor is customer demand and how fast is that customer demand going to grow. We've heard big numbers. You know, things like Europe is aspiring to be importing 15 million tons of hydrogen or ammonia by 2030. They're at zero or very small numbers today, so it's a very steep growth curve. We wanna be part of that growth curve, but again, it depends on the customers being ready to make that growth as well. Mm-hmm. Hi, Meg. James Redfern from Bank of America. Two questions, please. The first one is on Browse. Just in relation to the carbon solution for the Browse project, is it fair to say that the project will only go ahead if there's a viable CCS project, as opposed to buying carbon credits or offsets? Just wonder if you could please talk about that. Thank you. Sure. For Browse has been around for a long time, and most of the previous iterations of Browse had developments where we would be venting the CO₂ that comes out of the reservoir. We recognize in today's world to confront climate change and take action, we can't do that. What we have been working on and what we intend to build into the design plan is CCS of, and this is important, of the reservoir CO₂ from the beginning. The Browse concept, you know, with the FPSOs locally and then taking the gas to the Karratha Gas Plant, even the 20, you know, 19 version of Browse, we were always maintaining space on the FPSOs to be able to do CCS, but our base case will now incorporate CCS from the beginning. Now we're working through, you know, what does that mean for our regulatory approvals? The technical work is well matured, but there are some injection permits. You know, we received the license, but there's regulatory processes associated with that as well, but that is our intention. There is other CO₂ of course, from Browse. The FPSO itself, it generates power, and we use gas for power, so there's emissions there. Then there's emissions at the Karratha Gas Plant. As part of the state's process for approving the life extension for the Karratha Gas Plant, there are quite significant emission reduction commitments in that plan. We're working through what exactly does that mean? You know, how do we tackle decarbonizing the Karratha Gas Plant? Thank you. Second question is just on the LNG market. I think roughly two-thirds of the gas or LNG volumes for Scarborough is uncontracted. Mm-hmm. I just wonder if you could please talk to where you're seeing slopes at the moment for oil into LNG contracts for, you know, so midterm, you know, five, 10-, 15-year terms. Thank you. Sure. What we have is market surveillance. There's not been a lot of published data on what slopes folks are signing up for. If we went back to 2020, so when the COVID pandemic hit, there were deals that were reported with slopes around 10%. Our understanding is they've recovered to, you know, the 12% and 13% range. Again, a lot of those announced, recently announced deals, haven't been publishing slopes. It's probably worth also commenting that a lot of deals, a lot of the big deals have been coming out of Qatar, and the terms and conditions that they ask the buyers to take, are often quite stringent. One of the things that we want to be able to do is to position ourselves as a supplier that offers more flexibility, which is beneficial to the buyers and ourselves. You know, we feel pretty confident that we'll be able to get attractive pricing by virtue of offering greater flexibility to buyers. I think maybe we can go to Saul. Thank you, Meg. Two questions. I wanted to touch on spot exposure. You've guided to now, or guided, but indicated 20%-25% for the next few years. Could you just explain then perhaps as we head into 2024 and we don't have a Pluto turnaround, why doesn't the spot exposure go up? Also, as we head into 2025, I recall, I think Peter Coleman a few years ago talked about the Pluto contracts expiring and the option to extend not happening from 2025. So can you just clarify the status of where those Pluto? Contracts roll off, do you then gain that increased spot exposure and at what point that is? To clarify, the market guidance we put out for next calendar year is that 20%-25%. Our ability to, you know, operate towards the upper end of the range, whether where we land in that range depends on a few factors, one of which is operational performance. You know, this year we're really pleased with how the plants have operated. The Interconnector has also allowed us to be, you know, at the top end of our range for calendar year 2022. As we look forward, the indication we put in the pack is an indication for the three years. It's not guidance for each of those three years. It's a range just to give you calibration for your model. Again, any given year it'll depend on a number of different factors. It'll depend on the other turnarounds. Of course, Pluto is the most significant one with a 90% stake for us, but we will have rolling turnarounds through the business, you know, over that three-year window. Upside reservoir performance, upside LNG plant performance, you know, that those are all positive factors. Of course, now that North West Shelf is on decline, we've also got the risk of downside reservoir performance. That's why we've given you a bit of a range. The Pluto contracts do roll off in 2025. You'll note that on that chart we didn't talk about 2026. 2026 is a year that will have a fair amount of uncertainty. It'll be the commissioning year for the second LNG train and the year when we start up Scarborough. We felt it was premature for us to try to guide or give you an indication on 2026, 2027 and beyond. Strategically, where we'd like to be positioned is to have that 30%-35% available for the spot market or for gas hub pricing. Some of it might be an actual spot sale, some of it might be, you know, strip deals, for example. To be able to take advantage of the JKM and TTF pricing indices. Thanks. Just to follow up, I guess if Pluto contracts roll off in 2024, that's almost half of your entire volumes. Why does spot stay under 25%? Why can't spot go to 50% in 2025 just on that simple math? Yeah. Look, we've been doing some things to recontract volumes. You know, we wanna make sure that when a significant contract goes off, that we're not left without a home for our LNG. We have been doing recontracting activities to ensure that we are able to place those volumes in calendar year 2025. As it stands today, you know, 2027 and beyond, we do have opportunity to continue to do sales deals. There is more unsold LNG today in that 2027 plus window. But part of what the marketing team is gonna be doing in the next few years is firming up some of those sales so that we have confidence in being able to place our volumes. Okay. My second question is just on the outlook here, because, you know, we've got, I think, quite a number of years where investors have seen Woodside miss a lot of targets, and even the guidance put out on Tuesday for next year was lower than what was in the merger docs in April. Mm. Are you confident now that what you've put out in these kind of 7—, this outlook to 2027, you're confident you're gonna hit that? Are these targets or is this a conservative outlook? We've put out guidance for next year. I think it's worth reminding, and part of why we put the guidance out earlier this week was so that we could spotlight some of the things that were important to note. The conversion factors is a change, so versus the explanatory memorandum that was the old methodologies used by the two Heritage companies simply summed. You know, we knew we were going to have to align methodologies, but we hadn't yet decided on what factors we were going to use. There, there is that adjustment, and that's gonna be a bulk adjustment from everything that was in the EM. We have had some project delays, and Mad Dog is probably the most notable. We were expecting to have Mad Dog production next year, and that's not going to happen. Now looking at the forward plan, you know, when we look at our project delivery, when we look at how things are going at, you know, Sangomar, at Scarborough, we did put quite transparently our assumption for Mad Dog Phase 2 starting up mid-year. Shenzi North is on track, so, you know, we are putting a plan out that we have confidence that we can deliver. All right. If it comes to some of the metrics, you know, the operating cash flow and free cash flow, I'd encourage you to read the footnote 'cause that's price sensitive. The production numbers are the things that we control the financial outcomes. You know, we do our best. We control our OpEx, we control our CapEx, we control our production, but the price of our commodity can be variable, and over the past two years has been quite variable. Just encourage you to read that footnote carefully. Sorry. Just to follow on from that. From 2024 onwards, the cash flow outlook you put out there, you're saying the only change is the price? There's, for example, increases in CapEx versus what was put out in April, because on my math, it sort of looks like there's been an increase in CapEx. Sangomar project is on budget. We update that quite regularly and got an update from the team just a couple of weeks ago, and we're still tracking to budget. There's been a bit of phasing changes, but that's still tracking to budget. Perhaps the team, you know, if you have some more detailed questions, can work through those. Scarborough and Pluto Train 2 also remains on the forecast, the $12 billion. The base GOM business, 'cause that's where it looks like it was higher than, you know, we kind of interpolated from earlier. The base GOM business, it's worth noting that's quite activity dependent. Infill drilling in the Gulf of Mexico is a bit lumpy, so there'll be years where we'll do a fair amount, and there'll be years where we do less. That will cause a bit of kind of variability year on year. Same is true in Australia. If we do an infill campaign or a subsea tieback in Pluto with 90% equity, you know, that has a different effect than if we do one in North West Shelf. That's why there is a little bit of variability in our, we'll call it notionally sustaining CapEx. It still is in that, you know, $1 billion International, $1 billion Australia range, again, plus or minus any given year. Thanks. I'll give it to someone else. Yep, go ahead here. Hi, Meg. Thanks very much for the presentation this morning. My question's about Sangomar. You've said it's on budget. What about timing? You don't have any production in your 2023 guidance from that project. Can you update us on the timing? Our commitment when we took an investment decision was first oil in 2023. We still are tracking to have first oil in 2023, but to be conservative, we've not included any production uplift. Look, I think it's fair to say that with the challenges in executing the FPSO, in particular in the Chinese yards, that's gone a little bit slower than we'd anticipated, but we are still on track for that first oil calendar year 2023. Assuming the end of the year. Just on third-party LNG sales, the margin that you got in the September quarter was exceptional. Mm-hmm. We got some guidance today that you plan to increase third-party sales next year. Mm-hmm. What kind of margins can we look forward to? Can you repeat the stellar performance we've just seen, or will we move back to single-digit type margins? Look, for planning purposes, I would suggest modest margins and, you know, the challenge to Mark and his trading team is to beat those. The planning basis should be that we use, you know, we use trading for a couple of purposes. We're able to trade to optimize our base business. As Mark talked about, we have a shipping fleet, which gives us some advantages in being able to participate in trades that other players in the sector don't have. I would suggest, you know, your planning assumption ought to be modest margins on that part of the business, and that'll give us the opportunity to surprise to the upside. Thank you. Okay. Mark Wiseman from Macquarie. First question, just on Trion. You've talked about the $6 billion-$8 billion of CapEx, which is helpful. Could you just explain the dynamics with the carry? How much of the $6 billion-$8 billion does Woodside need to deploy in that upfront phase? Look, I'll probably call Matthew to the stage. The carry, the mechanism for the carry was agreed in the initial bid, to get into the Trion development. A good portion of the carry has been liquidated thus far. I'll let Matthew speak to how the rest of the carry gets liquidated over the coming period. Yes. You described it well, Meg. The carry was about $1.9 billion, and the amount left going forward is of the order of $4 million-$450 million. The expectation is that PEMEX would have to start contributing cash in about 2025. Okay. Thanks, Matthew. Okay. That's clear. Thank you. Just secondly, on the Sunrise project, I think previous management had described the onshore Timor greenfield concept as not viable because of the Timor Trench. It sounds like this project's making real progress now. Could you maybe just talk around the two options and why that greenfield Timor option is now viable? Over the years, we've looked at Sunrise, many, many different times. We have done technical pipeline studies to understand the feasibility of going across the trench. Those studies have always indicated that, you know, with kind of the right will, the right engineering, the right execution plan, that you can execute that scope of work. The challenge has always been the economics, and if you look at Darwin, there's two LNG plants in Darwin. They both have port infrastructure. There's space at both of those locations to build additional trains. You know, the cost of LNG processing capabilities, you have a longer pipeline, but you know, just have to build a train, not all of the associated greenfield equipment, which would have to be built in Timor. That said, there's been a lot of work in the industry over the past few years. You can look at some of the things that have been done in the Gulf of Mexico, for example, looking at modular construction, looking at different approaches. You know, the Commonwealth LNG project that we've signed offtake agreements with is one that's using a modular construction and very different design. You know, the Timorese are very keen to have that development in country, and we recognize it's an important national project for them. We feel like it's appropriate to reopen the concept evaluation, understand the technologies, understand the technical challenges. Look, Timor-Leste has a lot of international friends, and international friends may want to help with some of that infrastructure that doesn't exist today in Timor that would exist if we went to Darwin. Okay. Go down to Adam. Yeah. Yeah. Morning, Meg. I'm Adam Martin, ENP. Just on Scarborough and the primary and secondary approvals, you know, we're seeing, you know, one of your competitors have issues here on another project. Just, can you just tell us where you're at on the secondary and if there's any risks there, please? We are working on a number of different secondary approvals, so we need, and the specific document is we need environment plans, for things like drilling, seismic shoots, subsea installation, pipeline installation, for example. We're working very closely with the regulator to understand, their expectations and what they need to see from us, for them to be able to approve those, secondary documents. We are certainly concerned, and it has, you know, processes are slowing down, to be really frank. At this point in time, it's not critical path, and the team is working really hard to ensure that it stays off critical path. We're working very closely with both the regulator and the government to make sure that they've got clarity on, what documents are schedule-critical. As I said, nothing is schedule-critical at this point in time, but we do need to be moving those through. We'll continue to work closely with the government and the regulator. Okay, thank you. Just a second question. I think in slide 34, you had some Bass Strait gas opportunities. How are you thinking about that, particularly with this backdrop of a, you know, price cap? If there's a price cap, it's very hard to see those opportunities being attractive, to be really blunt. It's really hard to see LNG import being attractive. The price cap will have exactly the opposite effect. It might feel good for a short period, the outcome will be underinvestment in supply and underinvestment in the kinds of capacity mechanisms, things like FSRUs, that could help alleviate the pressure for the long term. Yep, thank you. Okay. Go down to Nik. Yeah, one here, and then we'll come back. Yeah, thanks, Meg. Nik Burns from Jarden Australia. I have two questions. First one, just a clarification on your cash flow charts. Thanks for putting the oil price assumptions in there. Mm-hmm. I think one of the key reasons why free cash flow has been strong this year has been your exposure to gas hub- Mm. -pricing. You haven't disclosed what your assumptions are going forward. Can you just talk about what they might be in the outer years? Forward curve. Yeah. for gas hub prices. Forward curve. Okay, great. Thank you. That's easy. Second one, just referring back to your gas hub pricing exposure longer term? Mm. You've talked about 30%-35% from 2027. I guess we've seen LNG developed in waves. Mm. In the past, there's a lot of talk about new expansion coming on from Gulf of Mexico in particular, hitting around that type of timeframe. I'm sure if you put that chart up, say, two years ago, we would have maybe not reacted quite the same way to that increase in gas hub exposure. How are you thinking through risk? How are you gonna deal with that risk that you could be confronted with a much lower price environment because of an overbuild that might eventuate in that timeframe? Thanks. You've spotlighted, probably between your question and Saul's question, we've spotlighted the challenge that we're trying to navigate, which is the question of how much LNG demand will there be in the back half of the 2020s leading into the early 2030s. There is new capacity coming online. The Qataris have sanctioned their projects. Scarborough Pluto Train 2 will be coming online, you know, and there are other U.S. projects that are in the works that will bring supply to market. You've got that as a factor saying there's a lot of supply coming. You look at what's happening in Europe today, you look at what's happening with Asian demand growth, you look at the Asian nations' commitments to reduce their emissions, and you say those are things that are quite favorable for LNG demand. As, you know, Sol and others have highlighted, we do have more gas uncontracted in that time period. What we've said is, look, philosophically, we want to plan our portfolio to have about a third of our produced LNG exposed to those gas hub, those gas hub price markers, because we do expect there will be more volatility. We see very strong seasonality already. We saw that even before the Ukraine crisis. The prior two winters, we saw very significant spikes in gas hub prices. We've said, look, deliberately, we want to design our portfolio to be able to take advantage of that. We recognize there's downside risk, there's, you know, comparably a lot of discussion about what's going to happen in the oil markets. You know, is there going to be a recession? What do rising interest rates mean? What's happening in Europe and China? You know, we do our best job to read the crystal ball. The things we can control is where we focus our efforts. You know, I can't control oil price. Australian government, much as they want, can't control international gas prices. We plan our business to be cost-efficient, to tackle our carbon emissions, you know, to be safe and reliable 'cause reliability delivers better production outcomes, you know, more product for us to put in the market at any point in time. I think we had one here. Thanks, Meg. Henry Meyer from Goldman Sachs. Just around Pluto Train 1, I guess, great, the interconnect is accelerating volume into high prices at the moment. Mm. On current 2P reserves, you might deplete gas by 2030. Mm. Do you just have any details around backfill to Pluto Train One? Is WA-404P still the likely candidate? You know, are you comfortable enough with understanding of that reservoir already? What's the potential backfill to Train One? Sure. With the Interconnector, it's probably worth reminding everyone, I think we put this out publicly when we signed the deal, but the Interconnector contract is a four-year contract, 2022 to 2026. It is accelerating Pluto production. When Scarborough comes online, we will be ramping down the amount of Pluto gas that goes through Train 1, so that we can blend the gas feed to Train 1. You know, as you think about, well, when does Pluto come offline, you know, we need to factor all of those things into your calculations. We are out in the market talking to potential gas sources to look at backfill options to Train 1. We would be keen to get additional resource in play. 404P, the challenge with 404P has always been its remote distance and the fact that it's a number of different smaller reservoirs. With the Scarborough trunkline in place, there'll be a point in time where 404P it would naturally be able to tie into that trunkline, and that would help keep the costs down for 404P. Unfortunately, we won't be able to flow gas through that pipeline until Scarborough's kind of on the backside of its life. 404P is still a resource that is in our contingent, but it has been pushed out in time, and we'll be looking for other things to bring into Pluto Train One, just as we're looking for other gas that we can bring into North West Shelf, both in the near term and then ultimately Browse as in many ways, which is the natural backfill for North West Shelf. The compositions are quite close. Joint venture alignment is closer than other assets. You know, that's the plan to try to bring other resource gas into our facilities. Great. Thanks, Meg. Maybe on Sangomar drilling, I guess a disappointing result with SNE North. Mm. Has the team got any early data to support confidence in phase two to five waterflood performance? I mean, would you be considering an earlier development sequence in drilling to sustain production going forward, or would you want more production data from Phase 1 before supporting that extra drilling? Yeah. To remind everyone, Sangomar has two different reservoirs. There's a lower reservoir, which is called the 500s. It's the high-quality reservoir. We've got great confidence in the productivity, as Matthew noted, the early drill well results have been right in on prediction. The shallower reservoir is the 400s. Very large in place. The open question for us is productivity and how effective the water injection's gonna be. We need to get a bit of production data to understand how effective that will, you know, the actual sweep efficiency will be. That data needs to come in before we can make decisions about, you know, significant further campaign. You know, we may look to a few additional infills here and there just based on early well results. A significant Phase 2 campaign, we need that dynamic data. Great. Thank you. I think we have about five more minutes. Have we hit everyone who had a first round of questions? Okay. If we have, we can go to second rounds. All right. Let me start with Saul and then Mark. Thanks, and glad to have the opportunity for one more. I just wanted to touch also on the Gulf of Mexico... Mm. 'cause we haven't heard much about it before. You talked about you converted 2C to 2P of 200 million barrels over the last five years. Mm-hmm. You talked about a rough reading 18%-27% IRRs for yet to be sanctioned 2C. How do you think we should think about the next few years? 'Cause I think there's still a few hundred million barrels of 2C. Mm-hmm. If we give that $10, $20 a barrel, that's worth quite a big number. How do we think, is there potential for another 200 million barrels conversion in the next five years at these same kind of returns? Shiva outlined what we've been doing in the Gulf of Mexico. These are very large fields, 1 billion-plus barrels in place. The technical question, of course, is how do you optimize infill drilling, and how do you get data that informs you about what's actually happening in the reservoir that allows you to then make good decisions about where to place those next wells. Shiva commented we've shot rounds of it's called ocean bottom node seismic. You basically put your seismic receivers on the sea floor 'cause again, the reservoirs are very, very deep into the earth. That helps with the quality of the imaging, and it allows us to get 4D data, so we can understand, you know, how are fluids moving through the reservoir. That helps us get smarter about how we place the wells. It's a technical answer, but the outcome of that is, yes, we do think there are additional phases of drilling possible. If you looked at the production chart for the Gulf of Mexico, you saw production growing over the period. That's things like Mad Dog Phase 2 starting up. It'll start up as we guided. We are assuming it'll start up mid next year and full calendar year effect in 2024. Infill drilling, Shenzi North. I think our track record would show that we continue to gather that data and make good- informed decisions about additional well drilling. That's, you know, the wells will continue to have those strong rates of return because it's relatively modest capital. You've already got the big facility in place. Thanks. The last one would be... it seems we've seen big licks of buying of U.S. investors into Woodside over the course of the year. Have you been spending much time talking to U.S. investors? What's the feedback you've been getting and how they see Woodside versus, I guess, the U.S. names? Sure. We have spent quite a bit of time in the U.S. As part of the merger, we took a secondary listing in London and a secondary listing in the U.S. I think our register right now is about 20% U.S. investors. We have been spending quite a bit of time in the U.S., and they're pretty excited about Woodside. We're different from many of the U.S. players. A lot of the U.S. players are focused on the unconventional, and the unconventional is a capital treadmill. You know, yes, you can turn it off when prices are low, but you're always on that capital treadmill, and what we're seeing in the U.S. right now is actually supply chain constraints limiting their ability to grow their business. LNG, we spend big lumps of capital up front and, you know, that's a bit of the nature of the business. When we're running an LNG plant, it's cash flow for 20 years. They like the fact that we're differentiated. They like the fact that we are gas-oriented. We have a very significant LNG orientation. I think we showed one chart that showed our gas weighting. You know, we're a gas-heavy business. We have heavy LNG exposure from our produced business. You know, we can get access to those customers, and we're able to move our cargoes around depending on where demand is highest and the price signals pull the gas. The US investors are very excited about us. They think we're quite differentiated, and, you know, I think that's why we've got 20% of our register in the US these days. Probably have time for one from Mark. Thanks for the second question. Just on the Pluto turnaround for next year. I think on previous discussions, we had in our notes that that was due in 2024. Mm-hmm. Has that been brought forward? Could you maybe just talk through what the dynamics of that four-week shutdown are? Is there some Pluto Train 2 preparatory work going on there as well? Thanks. Sure. Our, our cycle for Pluto is a four-year turnaround cycle. I don't know, maybe we're not adequately crisp in the past about when the next turnaround might be. Four years is our normal planning cycle. We will be doing some tie-ins for Pluto Train 2 to be able to connect in. As we get to 2026, you know, we likely will have to interrupt Pluto production to be able to start up Scarborough. you know, as we get closer to that point in time, we'll provide a bit more granularity on what those durations might be. We will do some tie-in works to try to be able to minimize the impact on Pluto-based assets, you know, between the 2023 shutdown and Scarborough startup. Well, look, thank you all for attending the 20 22 Woodside Investor Briefing Day. I hope you have found the presentation informative. If I go back to where we started, I think the investment case for Woodside is quite a compelling one. You know, post-merger with BHP Petroleum, we're a bigger company. We have geographic diversity, product mix diversity. We have retained our significant exposure to the LNG market, and we think that is an increasingly important energy commodity as the world tackles climate change. We have an incredibly strong balance sheet. We've preserved our very strong investment-grade credit rating, and we're positioned to be able to invest through the cycle and return value to shareholders. I hope you've enjoyed the discussion today. For those of you on the webcast, thank you. We'll let you drop off now. For those of you in the room, we have a little light lunch out in the foyer and look forward to chatting with you over lunch. Thank you.