Welcome, everyone, and thank you for joining us today. I'm joined by Graham Winkelman, Head of Carbon Management, Alejandro Tapia and Anna Wiley, who are the vice presidents of our planning and technical functions in the Americas and Australia, respectively, as well as our Head of Decision Evaluation, Patrick Collins. They have deep expertise in these areas. Graham has been with BHP for nine years and leads our decarbonization strategy and positioning across both operational and value add chain emissions, leveraging the effort and dedication of so many across BHP in the pursuit of emission debates. Alejandro has been with BHP for 19 years and held various leadership roles, including Head of Projects, Pampa Norte, Project Director, Integrated Operations, and General Manager, Concentrate Escondida. For those that don't know, Alejandro will soon move into the role of Asset President of Escondida Copper Mine in Chile. Anna has been working in the mining industry for over two decades in senior operational leadership and functional roles. She joined BHP six years ago as the Head of Asset Management in the global maintenance function before transitioning to her current role, where she has, amongst other things, led the decarbonization strategy for our Australian operations for the past 18 months. Patrick has been with BHP for 12 years, providing evaluation support to our assets on their most material investment decisions. He has held leadership roles as Head of Decision Evaluation for Minerals Americas and now Minerals Australia. As part of his current role, he is responsible for embedding decarbonization and social value pillars into our decision-making processes. So we're in good hands. After the presentation, you'll have an opportunity to ask questions. Before we go into the detail, here's a traditional disclaimer slide. I'd like to highlight that the nature of this presentation is inherently forward-looking and in an area that is rapidly changing, so it's not a guarantee or prediction of future performance. Our plans include reliance on technological developments and the relative economics of these, regional and global policy developments, and a myriad of other uncertainties and risks. The only thing that is certain is that our plans will change. We want to highlight in this briefing our current thinking on how we hope to achieve our target and goal, as well as some of the risks and opportunities that we may see along the way. With that, I'll hand over to Graham. Thanks, Tristan, thanks to all of you for the opportunity to present on this topic. The world faces a critical challenge to respond effectively to the risks of climate change. Every segment of society has a role to play, and BHP certainly recognizes our vital role, both in supplying commodities that the world needs to decarbonize and in making sure we do so as sustainably as possible. Let's start with a few key messages that I hope will resonate throughout the presentation today. We are on track to deliver our credible FY 2030 target, and we have an aspirational goal to achieve net zero emissions in 2050. Both this target and goal relate to our Scope 1 and 2 or operational greenhouse gas emissions. To be successful, step change technology solutions driven by collaboration in the value chain will be necessary. As we grow our business to meet increasing demand, the pathway will not be a straight line, nor will it be smooth. By integrating decarbonization into how we plan, we can find the most cost-effective way to achieve these outcomes. Demand for commodities that we produce is underpinned by the intensifying global trends shaping our society and our economy. By 2050, global population is expected to increase to almost 10 billion people, while the urban population is expected to grow by 50% to almost 7 billion. More people and more urbanization means a greater need for commodities. Over and above this, it is expected that demand for our products will be driven by the strengthening push across the world to decarbonize. BHP's key products are expected to play a vital role in enabling the world's response to climate change. We plan to grow our production to meet this demand while simultaneously working to decarbonize our operations. Investment in such things as a copper-intensive shift to electrification and nickel-intensive batteries, both of which are required under our 1.5 degree scenario, would contribute to significant increases in demand in the next 30 years compared to the last 30 years. This scenario also sees amplified demand for crude steel for such things as wind turbines. The world clearly needs more mining to meet this demand. We must continue to produce more with less. Today, we're gonna talk about the credible target and goal that we have in place for operational emissions and the approach we are taking to reach them. Not a path founded only in optimism, but a realistic acknowledgement that the roadmap for such a journey will be neither linear nor easy, but is achievable. BHP has a history of taking action, and we have been setting and achieving targets for operational emissions since the 1990s. Today, we have among the lowest absolute emissions of the diversified mining majors, as represented by the size of the bubble on the chart. We have among the lowest emissions intensity on a revenue basis, as shown by our position towards the left of the chart, and as we continue to make significant progress in reducing our emissions against our FY 2020 baseline, indicated by position towards the bottom of the chart. On the latter point, the display chart shows an average of 12% annual emissions reduction across BHP since our baseline year. That represents our 24% reduction over the past 2 complete financial years. We know that different companies will have very different decarbonization pathways that are influenced at different times by a range of factors, including the composition of their business, the location of their operations, their mining methods, and of course, growth plans. The key point here is that BHP is well-positioned among peers and has a strong foundation for further progress towards our target and goal. At BHP, we are very deliberate in how we set targets. We work with BHP's asset teams to determine what's possible. Our targets are set on the basis of seeing a credible pathway. Our FY 2030 target of at least a 30% reduction gives us focus, and our long-term goal of net zero emissions by 2050 orients us towards a net zero future. Let me be quite clear, we're not planning to change our 2030 reduction target. Rather, we're focused on action to deliver our plan. Taking action means working with others to identify solutions through studies, undertaking proof of concept trials, and executing the outcomes. Anna and Alejandro are here today to further explain the actions that we're taking across our global operations. As Patrick will speak to later, we've integrated our decarbonization response into our corporate planning, capital allocation framework, and our decision making. In FY 2022, our operational greenhouse gas emissions were 11 million tons of CO2 equivalent, adjusted for divestments and methodology changes. It's a good start from our FY 2020 baseline and has been achieved primarily through introducing renewable electricity at many of our operators' sites, most notably in Chile. The path to 2030 is more challenging. Our emissions profile is now weighted towards diesel, and while technology solutions for diesel displacement are emerging, many are not yet available at scale. In addition, our business activity is expected to grow to FY 2030, which under the current circumstances, would lead to some growth in emissions. This is shown as the orange box labeled, 'organic growth.' Countering this growth, we plan additional deployment of renewable energy before FY 2030 and further effort to deliver abatement across other emission sources, including diesel, fugitive methane, and natural gas. Our potential future emissions pathways are summarized in the two charts you can see before you. Let's start on the left. First, we maintain visibility of our do-nothing emissions pathway, shown in the chart as organic growth with no decarbonization. To be clear, this represents the expected emissions pathway associated with our increasing production, were we not to implement decarbonization projects. Beneath that line is our decarbonization pathway. That's the thicker orange line. You will see that we're currently well ahead of a straight line contraction to FY 2030. This decarbonization pathway aggregates all planned structural abatement projects and incorporates planned business growth, excluding OZ Minerals assets for now. While we've seen further emissions reduction progress in the current financial year, FY 2023, we do expect some near-term increase in emissions from production growth. To move faster than our decarbonization pathway, we will be reliant on the availability of technology that is still under development. On the chart, we have labeled this potential abatement the range of uncertainty, and we can see a conceptual pathway to our goal of net zero in 2050. Despite effort to date and our plans going forward, the challenge of eliminating natural gas and removing fugitive methane emissions, in addition to the viable advances needed in diesel displacement technology, continue to shape BHP's future emissions pathway. On a cumulative basis, and as shown on the right of the slide, we remain ahead of a net zero trajectory until around 2035-2040. We maintain the option to use high-integrity carbon credits for greenhouse gas emissions that cannot reasonably be entirely avoided. While unlikely to be necessary for our FY 2030 target, we can anticipate the need for some carbon credits to deliver on our net zero goal. Of course, we may be required to source and relinquish carbon credits in coming years to meet compliance obligations, including under Australia's Safeguard Mechanism. I'd like to reiterate, the path ahead of us is not linear, but remains consistent with our target and our long-term goal. Our clear focus drives our ambition. We are taking action where it matters, and we continue to integrate decarbonization into the very core of BHP's plans. Over to you, Alejandro. Thanks, Graham. I'm going to focus on local action, at least locally for me, by talking about our Minerals Americas operation. I will start with Chile, where I have spent most of my career. Then I will look at our newest project, Jansen, in Canada. BHP is at the forefront of more sustainable mining in Chile. By always having the future in mind, we have been an early mover in each step we have taken. On this slide, you can see the decarbonization transition we have made. Prior to 2011, the northern Chilean power market was highly concentrated. Assets were thermal coal power. In 2013, BHP started the development of the gas-fired Quellaveco power plant through an outsourcing model, allowing us to take control of our power cost and supply by entering the power generation market. From 2017, Chile had its first wave of optimizations, as renewable penetration was increasing materially, and the interconnection between the northern and central power system came online. BHP was one of the first mover in capturing this benefit at a scale by securing renewable PPAs for Escondida and Spence, which commenced in 2021. This meant we could terminate our coal-fired generation PPAs early, reducing unit energy costs at both sites by around 20%, and displacing an average of 3 million tons of CO2 per year, or around 70% of our Chilean assets' operational greenhouse emission. Even after the cost of canceling the coal-fired PPAs early, this move was NPV positive. With Escondida and Spence representing about 9% of Chilean power demand, so a massive amount of electricity, this change to renewable have been a significant step forward. This move also helped cover the power requirements and stabilize power costs associated with the shift to 100% desalinated water at Escondida in 2019, and then desalination plant for Spence growth option that came online in 2020. I would highlight that desalinated water at Escondida requires around 10 times more power than water drawn from the aquifer, and we have to pump it from sea to site. This accounts for around 25% of Escondida's total power requirements. As we look forward, while renewable penetration is expected to continue to increase gradually, backup generation is not being developed at the pace required, which is creating transmission bottlenecks and intermittency issues, and increasing system costs associated with reliability. Even with these challenges, we aim to maintain fully renewable supply at competitive costs for an expected increase in our required power demand at site. I will go into how we expect to do this shortly. As you know, our Chilean operations are focused on copper production, an energy-intensive process. In FY 2020, prior to the commencement of our renewable PPAs, most of our operational greenhouse emissions came from electricity consumption. They accounted around 80% and 60% of total emissions in Escondida and Pampa Norte, respectively, as you can see in the pie charts. I'm pleased to be able to check that Escondida and Spence have transitioned to 100% renewable energy three years ahead of schedule, reporting for the first time net zero Scope 2 emission throughout calendar year 2022, up until the end of May this year. The focus for us now will be maintaining 100% renewable energy with expected increased power demand. While much smaller in terms of overall operational emissions from our Chilean assets, our next challenge is to displace Scope 1 emissions from diesel consumption at our operations. This will require further electrification. Along with projects needed to enable growth, we expect an increase of up to 70% in our power demand, as you can see on the right of the slide, as we get to the first stage of Trolley Assist, which I will talk about later. Of course, we're aiming to meet this using fully renewable power. Initiatives are already in place to work towards electrifying all our operations, which will reduce emissions in the near term. I will now give you a couple of great examples of what we are doing on the ground. On the Scope 1 emissions from diesel consumption at Escondida and Spence, 80% is from haul trucks, 13% from ancillary equipment, and 7% from water boilers used in the electrowinning process in the cathode area. The first project I would like to highlight is our intention to displace 100% of our diesel consumption in the water boilers. For reference, the boilers are used to increase the temperature of mineral-rich solutions, where the electrowinning process takes place to produce cathode. Cathode production in FY 2022 for Escondida and Spence represent 29% of total cathode production. We expect to replace these diesel-fired boilers with zero-emission heat sources through combining a thermo-solar and electric boiler solution. This would leverage the efficiency associated with Escondida location in a region with one of the highest level of UV radiation globally, save about 30 million tons, 30 million liters of diesel per year, and reduce our Scope 1 emissions for our Chilean assets by about 7%. It will avoid about 1,000 round trips for diesel trucks to and from our mine sites, improving both our diesel supply chain dependency and safety on site. Escondida project would be one of the largest thermo-solar energy production facilities in the world. The projects involve investment of $85 million for Escondida and Spence, and is expected to deliver results in Escondida by 2035, becoming the first major step in safely reducing Scope 1 emissions in our Chile operation. That's is the first major initiative. Secondly, we're studying trolley-assisted haul trucks to drive those Scope 1 emissions farther down. The figure on the top left shows the electric fleet transition we hope to achieve. For those unfamiliar, our diesel haul trucks are progressively being replaced by diesel-electric trucks over the coming years, which means they use diesel engine to drive electric wheel motors, so-called diesel-electric trucks. We will approach trolley assist in two stages. First, we will implement trolley assist with diesel-electric trucks. Second, next decade, we will expand the trolley infrastructure to assist a transition from diesel-electric to the next generation of battery-electric haul trucks. Trolley assist works like an electric tram or train network. Electric infrastructure that haulage trucks can connect to while moving, to receive electricity to power their electric drives, and therefore displacing diesel use. We will soon begin testing diesel-electric trolley assist at Escondida, followed by Spence, with implementation of the first stage expected to start in fiscal year 2028 and fiscal year 2029, respectively. This timing is mostly driven by permitting, component lead times, and retrofitting. Once diesel-electric trolley assist is fully deployed, we expect to reduce Scope 1 haul trucks emission by around 30%. Before we implement trolley assist, we will roll out autonomous haulage at both mine. This made the most sense, as it means we can optimize routes, battery charging cycles, and avoid the cost of refitting trucks. We have thought deeply about the approach here, in terms of timing and scale, to maximize value, and our plans are based on how to maximize NPV. Therefore, we will only install trolley in ramps when it makes sense to do so for value. At the second stage, the trolley will not only power the electric drive, but it will also charge the batteries while the trucks are operating, reducing the need to stop for a static charge. Once the autonomous trolley and battery electric trucks are proven, we're planning a wide strip adoption across our asset, which would enable an efficient, low-risk, zero-emissions material handling solution by 2040. As I mentioned a bit earlier, haul trucks emissions account for about 80% of our Scope 1 emissions across Escondida and Spence. This would have a huge impact. That was some detail on a couple of our priorities. Let's have a look at how all of our infrastructure initiatives come together to maximize sustainability at Escondida and Spence. Our vision for the electric mine of the future is one that uses entirely renewable power to create a fully electrified operation, including fleet and no use of continental water. To maintain 100% renewables for all the new power needed for this electric mine of the future, we're looking to combine two approaches. One, additional renewable PPAs, and two, power generation at site. Behind the meter, with a focus on solar generation and storage. We will also maintain optionality through the studies of less mature technologies that may possibly accelerate this transition or leverage value creation if they can be fully scaled up. For example, technologies like synthetic fuels or long-duration storage solution. Before I hand over to Anna to go through our plans on the other side of the Pacific, I will touch briefly on what we're doing farther north. Development of our Jansen project in Canada is very exciting. As a new operation, we have been able to do it, to design it, to be one of the world's most sustainable potash mines from the start. We expect Jansen to have carbon emissions about 50% lower per ton of product produced, compared to similar operations in the region. As you can see in the pie charts, almost 60% of Jansen Stage 1 operational emissions will come from electricity. Our electricity is sourced from SaskPower, the local government electricity utility, which holds the sole right to generate and transmit electricity in the province. Most of SaskPower generation is from coal and natural gas, but the good news is that they share similar goals to BHP to reduce emissions. We're working with them on options to lower emissions from electricity, following from our strategy in Chile and success in incentivizing investment in low carbon emissions power in the province. Jansen's second highest source of emissions, at almost 40%, is associated with the use of natural gas in the processing plant. Here, we're exploring a range of potential technologies to mitigate or reduce reliance on natural gas, including carbon capture and storage, hydrogen, and even nuclear technology opportunities. By design, this will make up only a very small portion of Jansen's operation and emission. More than 80% of the underground fleet will be battery-electric when Stage 1 come online, and our plan is to have this fully electrified by the next stage. In summary, we believe it is clear from our plans underway to improve our operations in Chile and the exceptional opportunity we are leveraging in Canada, that our plans for emission reduction and maximizing sustainability in our Minerals Americas operations are real, achievable, and genuine. I will now hand over to Anna Wiley, my counterpart in our Minerals Australia business, to talk further about the work BHP is doing across Australia. Thanks, Alejandro, and h ello, everyone. Today, I'm going to share some of the decarbonization work we have underway across our operations in Minerals Australia. I will cover some of the biggest technical challenges we need to solve, including our ambitious plans for diesel elimination, how we're going to work to reduce natural gas in our Pilbara operations, and how we are managing our future emissions at BMA. Before I talk about these specifics, let's take a moment to touch on where our emissions come from and the work we have done so far. On the screen, you can see a breakdown of our emissions in Minerals Australia, which are all reported on a 100% basis. The chart on the left shows the combination of each asset to the total. The charts across the top show the source. It's not surprising that these pie charts look different when you consider each of the four assets produces a different commodity, uses different mining methods, moves different volumes of material, and requires different amounts of energy. The way we decarbonize will be different in each, and different from our path in Minerals Americas that Alejandro has shared. I will start with purchased electricity, which, as you can see, is something common to all of our assets. Like in Minerals Americas, we have made good progress in this area through leveraging PPAs to do so in a capital-efficient manner. As the charts along the bottom show, these agreements have us on the way to reducing emissions by at least 50% by 2025, and our aim is to eliminate them entirely by 2030. Not only have these PPAs reduced our emissions, but they have supported over 1.2 GW of new wind and solar generation and battery storage assets around Australia. As Alejandro mentioned, we also expect to see power demand increase, in our case, by 3 - 4 times as we move on to eliminating emissions from diesel in the future. Each year, our Australian operations use roughly 1,500 megaliters of diesel in over 1,000 pieces of equipment. As the chart here shows, over half of this is used in our truck fleets. Electrification is the preferred pathway to eliminate this diesel. One of the reasons for this is energy efficiency, which is shown on the table on the right in 3 fields: electricity, hydrogen, and diesel. Let me take a moment to expand on this. The first row represents the fuel movement from source to the equipment. Using hydrogen as an example, we see that the greatest losses at this phase are due to generation, storage, and transmission, compared to minimal losses in electricity generation and transmission. Once on board, the fuel needs to be transferred to energy. In both today's diesel-electric technology and in a hydrogen system, the fuel is used to generate electricity to drive the electric wheel motors, which has additional losses compared to direct feed. Putting this together, in the bottom row, we can see that around 80% overall efficiency from electrified pathway, compared with less than half of this for hydrogen. There would be some downsides to offset this comparable efficiency advantage for, is a comparable efficiency advantage from electrification, such as how we resolve long-term storage and constraints to mining operations due to power infrastructure. However, our view is that an electrified mining fleet is more economic and more achievable than the alternative fuel sources. We are helped on this journey when we consider that some of our core mining equipment is already available in electrical configuration. For example, both BMA and Alejandro's asset, Escondida, operate electric shovels today, and Escondida also has electric drills and has done so for many years. It's not just about buying new equipment. Replacing diesel requires us to develop a whole new operational ecosystem to surround the fleet, and every part of the mine will be touched by this change. There are still a lot of unknowns in our future concept of operations that we need to consider: how we plan our mines, how we charge our equipment, how we manage power demand, the skills we will need as part of this transition, and most importantly, the additional safety considerations these changes will bring. To build on our knowledge and firm up our plans, our approach is to collaborate with equipment manufacturers and others across industry to accelerate this development. When available, we will trial the equipment at our sites to validate our assumptions and learn how the equipment will operate in practice. As can be seen in the table on the left, this approach is reflected in the comprehensive program of trials that we are planning. The development of equipment will move through multiple phases as it matures. Recently, I visited the Tucson Proving Grounds and witnessed both Cat, Caterpillar, and Komatsu prototypes in operation in battery mode, which was really exciting to see. We expect to have our first Caterpillar truck for trial in BHP in 2024, and we'll move to Komatsu soon after. In rail, we have also seen prototypes operating. We'll be receiving four locomotives, two each from Wabtec and Progress Rail, for trial in 2024. After the completion of these successful trials, we anticipate our first battery-electric truck sites and loco consists will be in operation from the late 2020s. We are applying the same approach across other equipment where development is more advanced, but there is learning to be done in the application. Later this year, our iron ore operations will receive a Liebherr R 9400 E electric excavator, one of the first in Australia. We have trials underway underground in the Olympic Dam Mine, where we are testing our fully electric jumbo drill from Epiroc. Excitingly, our new partners at Oz also bring their own trials, including one underway now for battery-electric road trains. As part of this ecosystem, we will need to consider how our trucks will charge. The exact design will depend on the mine itself, but we anticipate having both static and dynamic charging in place. For static charging, we are working through the CharIN Mining Taskforce with over 60 other mining companies and vendors to develop a standard, so our equipment will charge with the same connectors. For dynamic charging, as Alejandro called out earlier, conventional trolley assist is available today, and we are encouraged by the innovation we've seen to lower the cost and improve mobility. However, implementation is difficult because as the areas we mine change, the infrastructure will need to be moved. We are looking towards innovation. We are supporting one of the Charge On Innovation Challenge participants, BluVein, who are developing side-mount dynamic charging systems to improve both mobility and cost effectiveness. To better understand how these systems will interact, we have completed extensive modeling of our operations. The example on the right is for one of our iron ore pits, with the dynamic charging in two locations and several static charging points that you can see. This modeling has been completed in hundreds of configurations across our coal and iron ore mines over multiple decades of mine plans and mine life. From this, the insights are helping us better understand the economics, trade-offs, and limitations of the technologies as we design our future operations. Staying on economics, we are often asked whether we believe we will see operating cost savings with battery electric trucks. Our initial modeling suggests that the cost will be the same or less to operate compared to diesel. We have illustrated some of the variances in the chart, and let me speak to a couple of these points. Starting with fuel. As we transition from diesel to electricity, we will spend less on carbon exposure, but we will need to spend more on electricity. We expect the cost will be less overall, given the efficiency of the battery electric trucks and the expected energy price differential. We also expect to see overall savings in truck maintenance, as without a diesel engine or mechanical drivetrain, there are significantly fewer moving parts, making the trucks simpler to maintain. By far the most uncertain area, are some of the costs associated with operating these new technologies. For example, we don't expect that the battery will last as long as the truck itself, so it will need to be replaced over the truck's lifetime. The method of charging will also have an impact, as will the number of times we need to relocate our charging systems and trolley lines. As the technology evolves and we learn from our trials, we will continue to refine our modeling, optimizing our concept of operation per site, the battery size and specification, the number and size of trucks, the location and configurations of static and dynamic charging systems. Before I move on from diesel, I wanted to summarize that we are stepping up to the challenging task ahead and seeking to learn as much as we can, as fast as we can. We are focused on providing the best technical and emissions reduction solutions while making sure we achieve competitive economic outcomes. One of the things we do know for certain about the transformation is that we are going to need a lot more power. I spoke earlier about how we manage this when we purchase power, how do we manage this when our mines are remote and we are not connected to a grid? Our iron ore operations in the Pilbara are an islanded network, and as such, power cannot be purchased through the market. As you can see on the T-chart at the top, electricity is currently supplied by our highly efficient Yarnima gas-fired power station, which produces power at 35% lower emissions per MWh than the Australian average. Over the decade, we will increase the volume of renewables and anticipate having up to 200 MW each of wind and solar, and 150 MW of battery energy storage installed capacity by 2030. We have already completed solar resources assessments to understand its potential, and are undertaking wind assessments and surveys right now. In terms of whether we buy it or build it, we are open to all options, and we are engaging with the market to determine the best solution for BHP. As the volume of renewables increases, the way we will use Yarnima will evolve. The second chart shows an example, 24 hours for a typical day in the future. Here, we can see the solar in the daytime mode, in the daytime, more wind generation at night, and energy provided from batteries and Yarnima providing to the base load of power and filling the gaps when required. Longer term, as more options for carbon neutral power become available, we expect Yarnima's use to taper off. We want to ensure the ongoing supply of reliable and affordable energy to our mining operations and the local communities. To support this, we will continue to collaborate with partners and review options, including interconnection to the electricity grid in the future. To close out on the third challenge I mentioned, I wanted to speak to coal. We saw in the charts earlier that methane accounts for around one-third of all BMA's operational emissions. Methane is released as part of the coal mining process and has a higher global warming potential than carbon dioxide. BMA is one of the lowest carbon intensity emitters among our competition. That's how much carbon we produce in production. We are around the lower quartile, as you can see in the chart here. This is due in part to our active management of methane at our underground mine, Broadmeadow, where today, methane is captured and flared to reduce its overall emissions impact. In open-cut mines, it is not quite as straightforward. Methane is currently released as the coal seams are broken up. In the future, we will need to pre-drain and extract this before we mine. This can be done, although it is not common practice today across the industry. With current technologies, we expect around 50% of BMA's methane can be pre-drained and used. Over time, we hope to increase this percentage, and we will continue innovation and new technologies to advance this. Once extracted, methane can be used for relatively low emissions power generation or be sold for other industrial processes, both options that we are investigating today. Any residual methane that we cannot extract will need to be offset to reach our goals. In wrapping up, I hope you can see that while the challenges are formidable, we don't think they are insurmountable. We are working at pace, investing in creating solutions, and collaborating with others to set ourselves up for a lower emissions future. I will now hand over to Patrick Collins, Head of Decision Evaluation, who will take you through how we think about our decarbonization program overall in terms of capital allocation. Thanks, Anna. Thanks, everyone. Well, we've heard a lot so far about the work going into finding the best solutions for operational emissions reduction. Part of my role is to make sure that the solutions we choose are also the best fit for us in terms of capital allocation. After all, this is a balancing act. We need the best solutions that allow us to both supply the metals and minerals the world needs and optimize value and returns for all our stakeholders, including our shareholders. Decarbonization projects are incorporated into our annual corporate planning process, which is critical to creating alignment across BHP. This process, which you can see on the left of the slide, guides the development of plans, targets, and budgets to help us decide where to deploy our capital and resources. Now, I cannot stress enough how important it is that the assets own these commitments. They plan the work and deliver on the execution with support from Alejandro and Anna's teams. As many of you know, BHP's capital allocation framework, shown on the right of the slide, is our overarching hierarchy for the potential uses of operating cash, and this is used for short, medium, and long-term decision-making and planning processes. Capital is prioritized to ensure maximum value and returns. A couple of years ago, we formally added operational decarbonization projects into our maintenance capital category within this framework, so they are prioritized along with risk reduction and asset integrity projects. Like other projects, the individual decarbonization projects must justify and compete for capital based on a number of metrics, such as abatement efficiency, technology readiness, and operational impact. After all, a ton of carbon is essentially a ton of carbon. Whichever project demonstrates the best risk-return metrics will win. Embedding this asset-owned, bottom-up approach that feeds into a top-down group strategy process is critical. It not only creates alignment, but strengthens commitment and delivery across the organization. Here you can see the outcome of this latest prioritization process. The chart on the left shows the profile of spending by emission source, top right shows the allocation of capital across assets. We still expect to spend around $4 billion on decarbonization capital until FY 2030. The majority of this spend is allocated to our most diesel-intensive assets and will be weighted to the back end of the decade, allowing technology to mature. Just to be clear, the capital we've shown here only includes the incremental cost of decarbonization. For example, that which is over and above fleet replacement for internal combustion vehicles, but includes the associated infrastructure requirements. Now, as you heard from the team, most of our emissions reductions in FY 2030 are expected from electricity, mainly through PPAs. PPAs, however, are captured within our operating cost cash flows, not in this capital profile. Around 75% of our decarbonization capital over this period will be on diesel displacement projects. While this spend delivers some emissions reductions towards the end of this decade through the initial deployments, it is critical to advance tech readiness, equipment trials, and begin installation of the supporting infrastructure in order to accelerate the emission reductions in the following decades, as you can see on the bottom right slide. We don't do this, we can still achieve our 2030 target, but we'll be facing a significant headwind to achieving our 2050 ambition. That's the capital expenditure picture. On to the operating costs. The top line of this chart shows the potential operating cost savings from the projects, with investment from FY 2024- FY 2030, including our diesel displacement projects and renewable electricity. It also includes savings from reduced carbon price costs. The pie chart on the top right shows the proportion of savings from each of these. Graham spoke to the range of uncertainty in our decarbonization pathway due to technology readiness, and you heard from both Anna and Alejandro about the uncertainty around operational cost impacts and benefits at this early stage of fleet electrification development. This is driving the range of forecast operating cost savings from our prioritized capital spend and is shown by the bottom line, which excludes any benefits from fleet or rail electrification projects. Out to 2030, we expect relatively minor operating cost savings, and this is because much of the emissions reduction is driven by the replacement of existing power contracts with renewable PPAs, as Anna and Alejandro showed earlier. Notably, this chart excludes ongoing savings from projects already executed, for example, from the move to renewable PPAs in Chile and Australia. Longer term, we expect cost savings to be driven by displacing diesel and the differential in power costs between renewables and non-renewables. Of course, depending on your view of carbon prices, the savings could increase substantially. Just to reiterate, developments and advancements in this space are moving rapidly, and as such, these numbers will also move around continually. Lastly, I'd like to touch on our marginal abatement cost curve, or MAC curve, which brings together the cost benefit proposition for the projects. The MAC curve reflects the present cost of capital investment and operating cost savings, excluding carbon price benefits against discounted emission tons. It's one of the tools we use to support the allocation of capital towards the most economically efficient and effective decarbonization projects at the portfolio level. This curve includes projects additional to those in the $4 billion spend to 2030. It does not include all projects within the range of uncertainty you saw in Graham's pathway chart. The curve is also reflective of the carbon price needed for the abatement portfolio to be cost neutral or NPV breakeven. Projects required to achieve our 2030 emissions reduction target are predominantly on the left side of the curve. That portfolio of projects is expected to generate positive NPV at a carbon price as low as $20 a ton through to $60 a ton, based on the technology readiness of the projects in the upper and lower bounds of our decarbonization pathway Graham spoke about earlier on. Projects on the right-hand side or the higher end of the curve, largely reflect diesel displacement projects. While they currently require carbon price support to be economic, they also have the greatest cost uncertainty. While they are not required to achieve our 2030 target, as I mentioned before, it is prudent to progress with studies, trials, and initial deployments so we can remain on the trajectory to achieve our 2050 ambitions. We expect that as technology matures, costs will come down over time. With that, I'll hand back to Tristan for some closing comments before we turn to Q&A. Thanks, Patrick, and thanks, Alejandro, Anna, and Graham as well. We hope we've been able to convey to you the positive reality of BHP's commitment to operational emissions reduction. Our progress compares well to our competitors, and we expect our path to be real, but also lumpy. We are committed to our target and goal, and we're planning on spending this decade for abatement beyond 2030. We do face challenges, but those challenges are familiar to many in the sector, and the pace of innovation and technological advancement is encouraging. Overall, we want to be clear that we expect that our plan will achieve the aims of reducing emissions and remaining productive and financially responsible, while supporting BHP to continue to produce the commodities the world needs to decarbonize and provide a higher standard of living to a growing population.