Ladies and gentlemen, good morning and good afternoon to you all. I'm Wael Sawan, the Upstream Director at Shell, and I really appreciate you taking the time to join us for this session for our Upstream Strategy. For those of you who don't know me, I joined Shell some 24 years ago as a project engineer, and I've had the opportunity since then to work in our Upstream, Downstream, and our Integrated Gas businesses. Before taking on my current role in 2019, I led the Deepwater business for four years, and before that, I had the opportunity to lead our businesses in Qatar. Today, I'm joined by various members of the Upstream Leadership Team. Firstly, Sinead, the CFO of our Upstream Business, will join me to discuss in more detail some of our broader Upstream strategic elements that we introduced at our recent Strategy Day. We will also be joined by Paul, Gretchen, and Zoë, who lead our Deepwater, Shales, and Conventional Oil and Gas businesses respectively, and who will update you on some of the exciting opportunities across our portfolio. We plan to first run through around 45 minutes of plenary presentation and leave plenty of time thereafter for your questions. To ask a question, you'll need to be dialed in via the phone line found in your invite materials. Before we dive in, let me first show our cautionary note that we always share relating to any forward-looking statements. Let me begin with our investment case. We believe Shell has an important role to play in the energy transition. At our Strategy Day in February, Ben introduced you to Powering Progress, our strategy to accelerate the transition of Shell into a provider of net zero emissions energy products and services. Our Upstream business is going to be a crucial part of this strategy. Powering Progress is set around four main goals with the intent to deliver value for our shareholders, for our customers, and for society as a whole. Generating value for our shareholders means delivering strong returns by taking a dynamic approach to managing our portfolio, continuing with our financial discipline, and ensuring we are ready to realize future opportunities in the energy transition. Powering Progress also means powering lives. From supplying affordable and reliable energy that is crucial to the global economy today, to the work that we are doing to become one of the most diverse and inclusive organizations in the world. It's also about achieving net zero emissions by partnering with customers, with businesses, and society as a whole to address the problem of greenhouse gas emissions in the atmosphere. Shell's target is to be a net zero emissions energy business by 2050 or sooner, in step with society. This means net zero emissions from our operations, our Scope 1 and Scope 2 emissions, and also net zero from the end use of all the energy products we sell, our Scope 3 emissions. Powering Progress also means respecting nature by stepping up our environmental ambitions to protect and to enhance biodiversity. Shell has three integrated business pillars, and each has a critical role to play in delivering our strategy to ensure that we have a strong, profitable, and resilient company now and well into the future. Our Upstream business, which we will focus more on today, aims to responsibly manage our advantaged oil and gas resources. This Upstream business has a clear purpose: to build on the legacy we have of delivering reliable and affordable energy that are essential for modern life, while at the same time generating material cash flow that underpins shareholder distributions and funds our growth pillar through the energy transition. This transition is already happening, of course. Around 70% of the world's global CO2 emissions is covered by net zero commitments that have either been adopted or are in the process of being adopted by national governments across the world. At the same time, our customers are increasingly demanding lower carbon energy products. The pace of this change will vary depending on the customer and the region, and Shell is playing an important and a leading role in that transition. Even the most ambitious scenarios tell us that as the world transitions, it will continue to need oil and gas for many decades to come. You'll no doubt have seen analysis of the International Energy Agency's net zero by 2050 scenario that was published just last week, including its assertion that in that scenario, there would be no further need for new oil and gas supply projects. While it sets out an alternative pathway to our own Sky 1.5 degrees Celsius scenario, both underscore the urgency and the importance of ambitious policy, unprecedented collaboration, and dramatic changes in the way the world consumes and produces energy. For us, this all means that we must have the highest quality Upstream business possible. An Upstream business that is focused and leverages our core strengths. An Upstream business that is resilient to oil and gas prices, as well as to carbon. An Upstream business that is highly competitive. This has been and will continue to be our focus going forward. As we look to the future of Upstream, we do so from a starting position of strength with a business that over the last five years has been focused on value over volume. Our Upstream business has generated more than $75 billion in cash flow from operations, excluding working capital over the last five years at an average oil price of $55 a barrel. Over that same period, has generated around $25 billion in organic free cash flow to Shell. While of course we are proud of this performance, make no mistake, this does not mean business as usual for us in Upstream. Powering Progress will radically transform Shell over the next 30 years and will require our Upstream business to step up even further if we are to achieve Shell's ambitions in the energy transition. This will be reflected by the portfolio choices we make as we high-grade and strengthen our Upstream portfolio. It will be reflected in our investment choices as we focus our CapEx program on our differentiated core positions to sustain material cash generation. It will be reflected in the way we do work every single day, aiming to safely grow our margins by leveraging the strength of our integrated capabilities as an enterprise and digitally enabling our people. I firmly believe that digitalization will be a key enabler to help us get to our full potential as a business. It's fundamentally changing the way we work, helping enhance our recovery from reservoirs, reducing development time and costs, as well as improving performance, reliability, and safety along the way. Let me give you just a couple of examples. We're using advanced data analytics on our critical equipment, such as our valves, to prevent incidents and avoid unplanned interruptions. We've also applied analytics in our subsurface, where if you take an example of the Gulf of Mexico, we have taken some 3,300 trouble events over 25 years of well history, integrated them into a user-friendly tool, and complemented them with six AI models, allowing us to streamline the process of identifying subsurface hazards and optimizing well plans to avoid or mitigate risks. This saves millions in costs. It saves on emissions due to less non-productive time. Of course, it improves safety of our operations. That's just scratching the surface of the full value potential that I think we can unleash from digital. Our ambitions all begin with being the most responsible operator possible. This starts with safety. In 2018, we rolled out our process safety fundamentals, which was not about new requirements, but a renewed focus on the rigor that we had to have in following our existing operating practices. Over the past five years, we have achieved an almost 50% reduction in the higher-risk process safety incidents. Operating responsibly is also about protecting the environment by delivering on our climate targets. Today, our Upstream business has made good progress. We have reduced the total Scope 1 and Scope 2 emissions of our portfolio by more than 25% since 2016, and we've cut our routine flaring in our operated assets by more than 65% in that same time period. We're on track to fully eliminate routine flaring by 2030. Our Upstream activities are also essential for the economic development of the countries in which we operate, from providing vital energy for homes, businesses, and transport, to supporting economic growth, and of course, to the investment in and the development of local talent. It's this talent base that we have across Upstream that will deliver our ambitions. As we reorient our company towards the energy of the future, our people will continue to proudly deliver the oil and gas that the world needs today while supporting the Shell Group in areas of adjacency, such as developing offshore wind farms, materially growing our carbon capture and storage business, and leveraging our current positions to support our host governments on their own transition journeys. We have outstanding people that are committed to playing their part in support of Shell's transformation by ensuring that Upstream delivers to its full potential. It's the same group of people that have already delivered significant improvements over the past five years. We've reduced our unit development costs by around 50% since 2015 and reduced our unit operating costs by more than 25% over the same period. Our controllable availability has also significantly improved, reaching around 90% last year. This means more uptime for our assets and more cash generation, even in a world like what we saw in 2020, where our people were also managing through the pandemic. All of these improvements have led to an almost 70% increase in our Upstream unit cash flow from operations versus where we were in 2015, recognizing as well that in 2015, oil prices were higher than what we saw in 2020. Our focus over the last few years around resiliency, operational excellence, reducing costs, and high-grading our portfolio are what puts us in a position of strength. When we look at our combined Upstream and Integrated Gas business to be able to compare with our peers, not only are we by far generating the highest cash flows compared to our peers, they are also the highest quality cash flows, as you can see when you look at the cash flow from operations per barrel metric. We also have the most diversified portfolio, diversity that provides us optionality. We have long plateau advantaged positions in our conventional oil and gas business, short cycle opportunities in our Shales business, and world-leading high-margin Deepwater and Integrated Gas businesses. On our carbon metrics, which are an important part of our investment decision-making process. We also are well ahead of other operators when it comes to carbon intensity on a Scope 1 and Scope 2 basis. As I said earlier, we are not satisfied with the status quo. It is this track record of improvements, this position of strength, and this organization and its capability that gives me great confidence in being able to achieve much more. What do I mean by more? For Shell Upstream, this means structurally reducing risks while delivering material cash flows and improving returns. We will do this by becoming more focused, more resilient, and even more competitive. We will focus our portfolio on our nine core positions that generate around 80% of our CFFO. This is a unique and diversified portfolio with access to significant price upside, where we have deep expertise and where we have leadership positions with decades of history. As we high-grade our portfolio, we will use both an economic and a carbon lens in our decision-making. Our positions outside of our core ventures will be operated under a lean venture model, which Zoë will talk about in just a moment. There are also parts of our core positions where we are reviewing portfolio options. At Strategy Day, we talked about our onshore oil portfolio in Nigeria, where we have faced a consistent environmental challenge, mainly because of leaks caused by sabotage and theft in areas where security is a serious problem. The balance of risk and reward associated with our onshore oil portfolio in Nigeria is simply no longer compatible with our strategic ambitions. We have started discussions with the Nigerian government to align on a way to move forward. From an investment perspective, we will be disciplined in our deployment of capital and will look to make replicable project investments with low breakeven prices and faster payback times. We will continue to look to reduce our cost structure further with an aspiration to reduce costs by an additional 20%-30% by 2025 compared with our 2019 cost base. This focus, discipline, and continued drive for improvements in our underlying performance will enable us to provide the energy that the world needs and, at the same time, to provide the best returns for our shareholders. Now, with that, let me hand over to Sinead to talk through our funnel of opportunities that will drive our cash flow generation. Thank you, Wael Sawan, and hello to everyone on the call. My name is Sinead Gorman. I'm the Executive Vice President of Upstream Finance. Since I joined Shell in 1999, I've held a variety of positions in different parts of Shell, including trading, mergers and acquisitions, Shales, and exploration and production finance for Integrated Gas and New Energies. I've been in E&P finance for Upstream since late 2019. In order for us to provide the energy that the world needs today, we must ensure we have a strong project funnel and resilient future development opportunities. Our current funnel of projects is robust with more than 400 kboed of new projects under construction and a multiple of that which are pre-final investment decision. The projects listed here are only a subset of our portfolio, representing around 50% of volumes including Shales. If I look at our broader 2P and commercial 2C resource base, we have over 20 years of production in our funnel. Our Upstream business will attract around 30%-40% of Shell's total CapEx between now and 2025. With this $7 billion-$9 billion per annum of CapEx, we will be selective in the projects we pursue. They will be projects where we have clear competitive advantages, subsurface expertise, strong integration value, and can offer the highest returns. We currently have an attractive portfolio of forward projects with an average forward-looking breakeven price of around $30 per barrel and an average portfolio internal rate of return between 20%-25%. Going forward, approximately 80% of our investments will be into our core positions, and the majority will be in our Deepwater business. We've been focused on value over volume for many years now, and this has been key to driving our increase in unit cash flows. The future projects we choose to bring to a final investment decision will also have this same focus. Replenishing our portfolio to sustain material cash flows into the 2030s will also require some continued exploration with a focus on differentiated opportunities. Our exploration team has made a significant discovery in the U.S. Gulf of Mexico with our Leopard discovery that we announced earlier this month, extending our track record in the deepwater U.S. Gulf of Mexico after the Blacktip discovery in 2019. We have also seen continued near-field exploration successes over the last few years with multiple wells in Petroleum Development Oman, Malaysia, and in Brunei Shell Petroleum, Brunei. We have added exciting new exploration acreage to our portfolio with the Côte d'Ivoire last year, for example. Going forward, we will spend around $1.5 billion per annum on Upstream exploration, and we'll develop projects that meet our expectations of payback by 2035. Our exploration strategy, like our development strategy, will be focused on value delivery, not volume. The majority of our exploration spend will also be focused on our core positions, ensuring that we continue to keep our hubs full and leverage off our quality positions and deep expertise. There will be some frontier and emerging exploration we will pursue, and this will be focused on basins where we believe we have differentiated subsurface understanding. An area of focus for us will be pursuing opportunities around the Atlantic Margin basins as you can see here. We have an exciting exploration drilling campaign in the next years, mostly in deepwater, for example, in Gulf of Mexico, both on the U.S. and Mexico sides, São Tomé, Suriname, and Namibia, to name a few. After 2025, we will not pursue any new entries into frontier positions. I believe that our top quartile drilling performance and our focus on basins where we have deep subsurface knowledge gives us a real competitive advantage. Paul will go into this a little bit more in a minute. Before we move to hear from the various business leaders, let me spend one more minute on cash flow generation. Wael mentioned earlier, with our combined Upstream and IG businesses delivering higher total and unit CFFO than our peers, we have demonstrated not only how we can maximize value from our assets, but also how we can generate differentiated value from integration. With the changes we are now making to our strategy, we expect to continue strong performance across a range of commodity prices. If I just take 2020 as an example, our core assets delivered $5 per barrels of oil equivalent higher unit CFFO compared to the rest of the portfolio. As we talked about at Strategy Day, our total oil production is expected to have peaked in 2019, and we expect our oil production to gradually decline by 1%- 2% a year, including divestments, until 2030. We also expect the percentage of total Shell gas production in our portfolio to gradually rise to around 55%. Our Upstream Business is free cash flow positive at $40 a barrel, and our positions have significant assets to price upside. For every $10 increase in Brent, we expect our Upstream Business to be able to generate an additional $4 billion in cash flow per year. This underpins the material and resilient cash generation we expect from our Upstream business into the 2030s. With that, let me hand over to Paul Goodfellow. Thank you, Sinead. Hello, I'm Paul Goodfellow, Executive Vice President for our Global Deepwater business. I've been with Shell for 30 years, where I've worked in operational and leadership roles in wells, deepwater, onshore, offshore, and shales. For two years, I served as the VP for the U.K. and Ireland before being appointed as the EVP of Wells in 2017. I took over as the EVP of Deepwater in 2019. As Wael mentioned, delivering our strategy requires the best possible Upstream. That will mean unlocking greater value from Deepwater. Our four-decade history is filled with great successes, notable challenges, and a resilient spirit. Today, with two prolific basins, an exciting exploration portfolio, and a track record of strong operational performance, we have a significant competitive advantage in Deepwater. Over the last few years, we've also proven we're capable of further improvements, and we have many examples that bring this to life, but a few that stand out. In 2018, our availability across Deepwater was 85%, and in 2020, we reached 90%. This advance resulted from improving our asset management systems, allowing us to identify and mitigate risks to our production. We reduced our unit development costs by around 50% and our unit operating costs by 40% since 2015. Last year, we drilled our lowest cost, most efficient Deepwater wells ever in Brazil. At a cost of $34 million, our Saturno well went from spud to total depth in 20.6 days, a best-in-class result, and 25% and 35% below the median time and cost performance across the industry in Brazil pre-salt wells. In totality, these examples and many more like it mean that in a $60 a barrel oil price environment, we're able to realize CFFOs greater than $30 a barrel. As others have mentioned, Shell's strategy includes increasing investments in lower carbon energy solutions while continuing to pursue the highest returns and most energy-efficient Upstream investments. The Gulf of Mexico isn't just about cash generation. Our U.S. Gulf of Mexico production is amongst the lowest greenhouse gas intensity in the world for producing oil. Even with these improvements and advantages, we know that there's more to do. Let's take a look at how we'll generate even greater value from our assets. We aren't focused on doing deepwater everywhere. We're focused on delivering greater value from our advantage positions. For example, as part of the Perdido phase II topside turnaround, we increased capacity by 30,000 bbl per day. Through data science and analytics, Perdido, originally designed for 82% availability, is currently operating at 93%. We look at our portfolio as a collection of urban communities or corridors that can learn from each other and work together to drive better outcomes on a larger scale. Corridors give us the options and alternatives that you just don't have if you're a single block operator. As Sinead mentioned earlier, we'll focus our exploration spend and invest over 70% of that in deepwater. Let me give you a sense of what that looks like. In the Perdido corridor, we've been able to explore for bigger opportunities like we've done with Whale, Blacktip, and Leopard. With this focus, we can optimize our infrastructure, including pipeline to shore, to unlock the full value potential of our discoveries. This urban planning isn't unique to Perdido. It is at the heart of value creation in Deepwater and speaks to the value that these strategic corridors represent. Here is a very simple example which highlights the benefit of this coordination. In 2015, we had more than 60 supply vessels to support our Gulf of Mexico operations. To improve planning and resource sharing, we reduced that to less than 15. In Brazil, by taking a similar approach, we have realized a 25% cost reduction for supply vessels over the last two years. Now let us look at how replication is making a difference. Prior to our Vito final investment decision, we recognized an opportunity to reproduce the host for Whale, which is up for final investment decision later this year. By leveraging the construction and supply chain of Vito, Whale will go from discovery to first oil in approximately seven and a half years. Featured top quartile subsea facilities. This cycle time includes the impact from COVID cash preservation efforts that delayed the project FID by approximately one year. With a 99% replicated hull and 80% replicated topsides, the benefits go beyond reducing cycle time. We've realized months of reduced engineering time, resulting in significant savings in engineering costs on both the hull and topsides, as well as greatly improved manufacturing outcomes for the replicated topsides equipment. While I trust the power of our corridors is clear, it's actually our unique capabilities and advantage positions that show our true upside. We'll build on our strengths to drive better business outcomes, not just at an asset level, but across Deepwater. We've proven that we're best in class at well delivering, but we know there's an opportunity to take even more cost out. We've adjusted to a franchise model, where we've gone to a limited number of standardized well types that cover our global Deepwater portfolio. We've gone from 18 well archetypes to three, and from 14 completion archetypes to four. This method is similar to the franchise models of fast food restaurants around the world, bringing together the right materials, services, people, and procedures to reliably deliver world-class business outcomes regardless of location. This launches a domino effect of efficiencies internally and in the supply chain. From a supply chain perspective, we're partnering with key suppliers to develop standard work packages based on a set of well archetypes that can be deployed globally. This simplified and standardized approach has delivered an additional 20% cost reduction in the last two years in the Gulf of Mexico, where we've been developing it. We know our more recent successes aren't enough. With our advanced assets, we are capable of more. We'll build on our strengths and learn from all our challenges so that we can deliver even greater value for this business. With that, let me hand over to Gretchen. Thanks, Paul. It's a pleasure to be here today. For those of you who don't know me, I'm Gretchen Watkins, Executive Vice President of our Shales business and President of Shell in the U.S. I took up those roles when I joined Shell in 2018. Before that, I was the CEO of Maersk Oil based in Copenhagen and previously worked for Marathon Oil and BP. Shales has been on a significant improvement journey over the last couple of years, a journey that's transformed our business by focusing on a high-graded portfolio, improved capital efficiency, strong operational performance, and a simplified operating model that has significantly reduced costs, all of which underpins strong cash flow generation. To achieve a high-graded portfolio, we've divested from non-strategic assets for strong valuations, allowing capital to be focused in our preferred basins. We divested our dry gas positions in the Haynesville and Appalachia in the United States. In Canada, we exited our Foothills sour gas business. In April of this year, we completed the divestment of our Fox Creek and Rocky Mountain House assets. In fact, our current portfolio has generated more CFFO in 2020 versus 2017, despite a smaller asset footprint, the impact from COVID-19, and prices that were 23% lower. This cash generation is a testament to the progress that we've made on our competitiveness journey. In 2020, we also transformed our operating model, resulting in more disciplined execution and 40% fewer handoffs. Our operating model puts us on track to see a further 30% reduction in costs by the end of this year. More importantly, we are a smaller and more nimble organization. We have clear accountabilities, simplified processes, which enable our teams to boldly take the business forward. Let me highlight a couple of our assets. In Canada, our Groundbirch Montney natural gas asset continues to show additional potential for resource maturation and excellent well performance. The Groundbirch asset is uniquely positioned at the inlet of the Coastal GasLink pipeline. By sharpening the focus on execution and cost reductions in the Shales portfolio, Groundbirch has reduced its breakeven price by some 20% since 2018, and it will offer a lower cost of supply than the local Alberta energy company oilsands market. We can confirm today that Groundbirch will provide the majority of the feedstock for liquefied natural gas Canada Trains 1 and 2. Our Argentina asset sits in the Vaca Muerta, where reservoir quality matches the Permian. We have a large position in the best part of the basin, and we are ramping up oil production while continuing to appraise and unlock development potential. Wells that we have already drilled in the black oil window have exceeded our expectations. Now to the Permian, which delivers the majority of our high margin volumes and free cash flow for our Shales business. Permian is an Upstream core asset, and it will attract the majority of the capital within our Shales portfolio. We have a very attractive Permian position with more than 500,000 acres in the Delaware Basin in areas with the thickest formations. We have some of the highest oil yields in the basin and have de-risked 8+ years of Tier 1 inventory. We've seen a nearly 60% reduction in drilling and completion costs and a 53% reduction in unit OpEx since 2015. Here, technology is an enabler to the significant reduction in well costs. We use remote real-time monitoring and automation in our drilling activities. This capability allows us to deploy Shell proprietary AI techniques to optimize and continually refine our drilling parameters, leading to more capital-efficient wells. We are looking for cost-saving opportunities everywhere. For example, we've reduced our flowback costs through automation and simpler designs. This also improves our cycle time and increases early production by almost 20%. Additionally, we've started using our own sand traps and tanks, eliminating more expensive rental equipment. We continue to progress development while looking for opportunities to consolidate and enhance our footprint. We're focused on strong operational performance and competitive cost structure. With prior infrastructure investments, we are now in our drill to fill stage here. We have forward-looking IRRs greater than 50%, breakevens of about $30 a barrel, and paybacks within two to three years. We also capture additional commercial value through our trading and supply business. This integration enables Shell to reach the highest value markets and manage price exposures to increase the resilience of our investments. As communicated in our first quarter results, the Permian has delivered three consecutive quarters of positive free cash flow. Now I want to talk about our efforts in the Permian to reduce flaring emissions. Shell places a high priority on reducing methane emissions, and we support the direct regulation of methane. We have actively worked to significantly reduce our emissions and as a company, have announced a target to maintain methane intensity below 0.2% by 2025 for operated oil and gas assets. This is an area that I personally am very passionate about. Today in the Permian, we have top quartile performance in limiting methane emissions, and we are already below our 0.2% methane intensity target. Since 2017, we have reduced our greenhouse gas and methane intensity by around 80%. We also have reduced flaring by more than 80%, all while increasing our production of Shell-operated assets by nearly 120%. We've implemented infrared cameras along with drone technology as a means to improve methane emission leak detection and improve the speed of repair times. For example, drone-mounted detection cameras feed information to an artificial intelligence-based analytical platform, which is able to detect and analyze methane leaks from images collected by this camera. This produces a simple data analytics set, and within 24 hours of a drone survey, we have all the information that we need to identify a potential leak, dispatch a maintenance crew, and remediate that leak. We've also stopped all routine flaring in the Permian Basin since 2018. We applaud others who are moving in that direction now. With that, let me hand over to Zoë to talk about our Conventional Oil and Gas business. Thank you, Gretchen. It's great to be with you all today. I'm Zoë Yujnovich, the Executive Vice President for Conventional Oil and Gas. Let me also briefly introduce myself. Prior to my current role, which I took on in January of 2020, I was the Executive Vice President and Country Chair for Shell in Australia, where I was responsible for our Integrated Gas assets. Before that, I was in Canada leading our heavy oil business, including both oil sands and unconventionals. This is where I joined Shell in 2014. Before then, I worked for Rio Tinto as the CEO of our Iron Ore Company of Canada, and prior to that, with the company president for Brazil. Conventional Oil and Gas is the heart of our Upstream business as it spans our legacy positions, which we've developed and operated over decades. Over the years, this portfolio has proven to be a material cash engine. The diversity of the portfolio also provides price resilience given the mix of production sharing contracts and tax royalty agreements. This was evident in 2020 when our conventional business delivered around 60% of the $4 billion organic free cash flow for Upstream. We're also well-positioned to take advantage of price recovery and upside, as we demonstrated in our recent Upstream quarter one results. To sustain this cash generation capacity into the future, we're focusing the majority of our capital and resources on six core positions, three key operated countries in the U.K., Nigeria, and Malaysia, and three non-operated positions in Oman, Kazakhstan, and Brunei. We have unique leadership positions and competitive advantages in these countries based on our subsurface knowledge, integrated value chains, decades of production experience, deep relationships with governments and partners, and very talented local staff. These six core positions provide longevity through production optimization, new project developments, and also have near-field exploration running room, which will allow us to sustain cash delivery well into the 2030s. As we focus on our core positions, we are significantly reshaping the portfolio. We've made good progress with the divestments of non-core assets, as you can see on the map. Earlier this year, we announced the divestment of our onshore Egypt assets, and last week we signed a deal to sell our interest in Malampaya in the Philippines. The divestment of our ventures in the Baram Delta in Malaysia is in progress, and we're also intending to hand back our upstream licenses in Tunisia to the government in 2022 when the Miskar license expires. In Nigeria, we divested Oil Mining Lease 17 earlier this year, and as Wael mentioned earlier, we're also discussing portfolio options for our remaining onshore oil positions in Nigeria with the Nigerian government. Looking forward, we will concentrate our efforts on our deep water and gas value chains in country. Focusing our portfolio will also allow us to further drive our operational performance and project delivery. Already, our capital efficiency has improved by around 45% over the last five years, and we've reduced our unit operating costs by around 10%, while keeping our controllable availability close to 90%. There's more improvement potential as we leverage our extensive subsurface and operational data through advanced data analytics and digital technologies. In PDO, for example, the team implemented a new digital web-based system called Takaamul, the Arab word for collaboration. This optimizes well planning and delivery, coordinating more than 30 rigs, more than 100 fields, and more than 700 wells. In 2020, almost 2 million bbl were accelerated, generating an incremental cash flow of more than $200 million. The other unique feature of our core positions is that these Upstream assets are part of an integrated value chain with Integrated Gas, trading, and Downstream. This allows us to maximize the value of our molecules and positions us strongly for the development of new value chains as we move towards net emissions or net zero emissions. Let me turn to the U.K. as a great example of what we're doing in this space. The U.K. is a core part of our portfolio. We operate around 10% of the total U.K. oil and gas production. Our cash flow from operation unit margins in the U.K. are very attractive and resilient and among the best in our Upstream portfolio. Our U.K. team increased production by more than 50% since 2015 after divestments, and the seven major project FIDs we took in the last few years, and with several upcoming, will result in further growth in the years to come. Our U.K. portfolio can essentially be segmented into two parts. The first is the high-margin oil Floating Production, Storage, and Offloading where we'll focus on project replication, standardization, and selective growth. The second is in natural gas, where we expanded our unique integrated value chain from wet gas to chemicals. We realize that the external context is changing at pace in the U.K., and the U.K. government is a frontrunner in developing policy and legislation to achieve net zero emissions. We are also committed to achieving net zero emissions in the U.K. and have made good progress to reduce our Upstream emissions over the last five years. As the landscape changes and shifts quickly, so are we, and we need to do much more. As we continue to develop our U.K. portfolio, we're actively pursuing a funnel of projects to further reduce our direct emissions through brownfield abatements, offshore electrification, and selective portfolio high grading. We're also well-placed to develop new value chains for blue hydrogen in combination with carbon capture and storage, addressing both Scope 1 and Scope 3 emissions by leveraging our gas assets and strategic infrastructure positions. For example, we're participating in the Acorn project, one of the largest and most mature carbon capture and storage and hydrogen projects in the U.K., which is centered around our St. Fergus gas plant. St. Fergus receives large volumes of natural gas from U.K. offshore production and Norwegian imports and plays a critical part in supplying the U.K.'s energy needs. By reforming the gas into blue hydrogen and storing the carbon dioxide into nearby depleted fields through currently Shell-owned and operated infrastructure, the Acorn project has the potential to decarbonize industry and homes across Scotland and the U.K., and the ability to store over five million tons per annum of CO2. To enable these types of developments, the Upstream industry and the U.K. government have recently entered into the North Sea Transition Deal, in which Shell is a partner. This deal brings together a package of commitments and measures that will facilitate supply decarbonization while building policy frameworks, capability, supply chains, and investments in clean technologies, all while supporting jobs. It's a powerful example of what can be achieved when government and our industry work together towards a common goal and can serve as a blueprint for other markets. Let me also spend a few words on what we're doing in our lean portfolio. Last year, we identified 11 lean positions in our conventional portfolio, including countries such as Italy, Norway, Netherlands, and Iraq. Since then, we've taken this number down to eight with the portfolio decisions I mentioned earlier, showing evidence of our early action despite the challenges of 2020. My ambition for the lean portfolio is twofold. Firstly, to drive high performance in the assets, evidenced by reducing OpEx by more than 40% in the next three years, increasing free cash flow by more than 30% compared to a 2019 baseline, and turning them into agile organizations demonstrating our ability to drive a fit for purpose control framework in Shell. Secondly, to assess if these ventures have the potential to become core by unlocking significant materiality, and if not, to divest for value over time. Critically, the value in segmenting our conventional portfolio is not only in the focus that this brings to our lean assets, but the clarity of purpose for the Shell group on our core asset positions as well. We will manage our lean assets with a new operating model based on six key principles. More frontline autonomy and decision authority within the ventures, a small supervisory team with lower central overheads, and more stringent investment hurdles for projects and exploration steering towards faster paybacks. The differentiated operating model means that in general, the lean ventures will function with more autonomy, be liberated from the complexity so that they can focus on cash generation. Learnings will be taken from lean and implemented broadly across our Upstream organization at every relevant opportunity. We've already taken the first steps to implement this model, and I'm confident we can achieve these objectives within the next few years. Now, let me hand back to Wael. Thank you for that, Zoë. Let me now wrap up before we open up for questions. At our strategy day in February, we introduced you to Powering Progress, our strategy to transform Shell. Today, we build on that, hopefully helping to explain how this translates to the Upstream business. In short, we believe our Upstream business has a critical role to play in responsibly providing energy that the world needs today and providing the financial strength to transform our company and to fund our shareholder returns. In recent years, our three lines of business have made good progress building a compelling investment case through their competitive portfolios, attractive growth options, and differentiated operating models. To support Shell's ambitious transformation, Upstream needs to continue to push for more. We need to become more focused, more resilient, and even more competitive. Our Upstream business is well-positioned to deliver that. With that, time to go to our questions. Ally, if I can ask you to invite the first question. Thank you. To ask a question, you must be dialed in via the telephone numbers provided in the invitation materials. If you have a question, please press star one. If you wish to be removed from the queue, please press star two. We'll go ahead and take our first question from Oswald Clint from Bernstein. Please go ahead. Oswald. Good afternoon, everyone. Thank you very much for your time. Two questions. First one, really around exploration first, please. Really, de-risking these frontier exploration plays and enabling for you to feed your hubs going forward. Just one example here, I'm just thinking about risks. The Norphlet play was a good Shell success story, but then I think you've ended up taking a bit of an impairment on Appomattox. It's really a question around subsurface risks as you try and de-risk the exploration plays. Anything going on there with seismic imaging that could really help unlock a bit more resource? Some of your peers talk about this in recent years. Secondly, a question on production. Obviously, it feels a lot easier to manage to a 1% - 2% decline in oil than trying to grow 1%- 2%. You're very offshore exposed, and of course, decline rates here are obviously an order of magnitude higher than 1%- 2%. Just getting a sense of your confidence around managing to this number. Should we expect it maybe to be a bit more lumpy some years, and some years higher, some years lower? Is this really down to Paul here and his wells team to just enable you to do the 1%- 2%? Thank you. Oswald, good afternoon to you. Thank you for the questions. Let me start with the production one and then dovetail into exploration and hand over to you, Paul, maybe to talk a bit about Appomattox, specifically the North Flank and subsurface risks in general. Oswald, for the production declines, I think it's important to contextualize that the 1%- 2% that we talk about is on the overall portfolio, and that's going to be driven, the majority of it is going to be driven through some of the divestment activities that we expect to see going forward. The majority of our nine core positions we will look to keep flat or to slightly grow, and that's where we are focusing the majority of our capital. With 80% of that capital going into those core positions, we have high confidence that we are able to continue to drive that sustainability in those positions. I think to your point around the nature of offshore positions and the higher decline rates, what I would say is we do have a very diversified portfolio. If you look at our Oman position, if you look at our Nigeria position, if you look at our Brunei Malaysia position and others, those tend to be lower decline rates and therefore easier to manage at that rate. From an offshore perspective, the majority of our exploration spend, around 70%+, goes into deep water to be able to sustain some of the levels that we talked about. That's how we come up with the $79 billion of CapEx that we feel is important to be able to sustain the cash flow generation from this business well into the next decade. Just on the exploration piece, what I would say is indeed, we are more geared towards deep water exploration. We have had many successes in this space. I think in particular, as I'll hand over to Paul on Appomattox, that is an area where it's important to look at the entire [urban corridor] that Paul was referring to and maybe give him an opportunity to reflect on both the subsurface but also some of the plays that surround. Paul. Thank you, Wael. Oswald, thank you for the question. Specifically on Appomattox, if I take a step back then, Appomattox was the play opening development of the Norphlet play. Clearly it's not the only opportunity that we have within the Norphlet. It came on stream ahead of schedule and ahead of budget, and availability has been very good since we started that asset up. Clearly, we've seen more complexity from a subsurface perspective that we have. Now that we've got a year or so of production behind us, we've been able to really sort of integrate that into our overall thinking of what that means going forward of how we position future infill wells, but also how we think about the satellites that we already have from a discover point of view. Dover, Rydberg, and Fort Sumter. As well as with the other exploration opportunities that we have within [urban theater] in totality. Whilst, yes, we have clearly learned from the subsurface, and that often happens with play opening developments such as Appomattox and the Norphlet, it's clear that the technology, some of the examples that we spoke about in terms of how we integrate that insight to further then reflect that in upcoming opportunities that we have, will be absolutely key, and seismic, that you mentioned, is just one of those technologies that we are using heavily. Yeah, I will say that whilst the subsurface is more complex at Appomattox, we do see pressure connectivity there. We did start our first water injection well at the end of 2020, and that is progressing well. With that, Wael, let me hand back to yourself. Appreciate that, Paul. Thank you. Ally if we can ask for the second question, and also Paul, thank you for that first question. I'll go ahead and take our next question from Martijn Rats from Morgan Stanley. Please go ahead. Hey. Hi, it's Martijn. Thanks for this presentation. Very useful. I've got two questions, if I may. Wael i n your introductory remarks, you mentioned a little bit about the International Energy Agency report from last week, but it's come as such a marked set of conclusions, so to say, that I did want to ask you to elaborate a little bit about it. Reading the report myself, there seems to be quite a wide gap between the detail in the report and some of the media reporting, but the perceptions of it are not necessarily insignificant. I was wondering if you have a view on how this might still, despite all the plans that you have, impact your ability to move forward with major FIDs and things like that. That's one thing. The second thing I wanted to ask relates to the Permian. You speak very positively about the Permian, but I was wondering about this. 12-month forward West Texas Intermediate is trading a little over $60 a barrel, and you're talking about breakevens that are $30 a barrel. That's a rather wide gap of $30. Yet, we're not seeing super major oil companies like Shell adding any rigs. We see privately owned companies adding oil rigs, but the super majors, including Shell, are not really adding oil rigs. Now I can sort of understand a bit, perhaps, capital discipline sort of constrained framework, sort of why that might be the case. I was wondering if you could say a few more words about how you're thinking about allocating capital to Shell. Are you in effect saying, "Look, we want to do these short cycle projects perhaps later in the decade, when really we can only do short cycle projects, so we don't want to do them now, we want to do them in the future." Is there sort of thinking behind it like that? Martijn, thank you for those two questions. I'm going to kick off with the first one and invite Gretchen to talk to the second one, including how we think about the capital allocation from an Upstream perspective. I think maybe let me start with the IEA report, which, of course, like you, I had the opportunity to review. I think firstly to say, we, as a company, of course, welcome that IEA report. One can dispute, of course, the plausibility of some of the assumptions that underpin that scenario. We do find quite a lot of common ground with it. Maybe just to be a bit more specific. If the world is to achieve the net-zero emissions by 2050, the report rightly points out, as we have been trying to point out for a long, long time now, it will take unprecedented levels of collaboration across all the countries with real policies and regulations that need to be implemented immediately. It also refers to that those policies, but also customer behaviors needing to change very quickly to be able to fundamentally impact the demand side of the formula. Right? It talks about the uptake of electric vehicles, the installation of heat pumps, solar panels in the houses. It refers to, for example, business travel being constrained to what we experienced in 2020, which, at least from my perspective, was minimal. You put all that context, what it tells you is that you do need policies and regulations, and you do need significant demand shift if we are to achieve the ambitions that are set by the report. If I take it one step further, the report rightly points to a significant amount of capital being required to achieve that. It talks about $5 trillion per annum, which is a significant step up from the roughly $2 trillion or so that we spend at the moment, which is absolutely right, but also plays to our conviction and the underpinning of the Powering Progress strategy that we introduced in February. Which is that if we are to truly move towards the ambitions of Paris, if the world is to collectively move there, it will require the right incentives to be able to create a pool for that $5 trillion per annum of capital to come through. Therein will lie a number of opportunities for companies like ours who have the customer connects through our retail sides and B2B businesses, but also companies like ours that are able to integrate across the entire energy value chain. That is very much the underpinning of why we talk about wanting to move with the transition, wanting to start to redirect capital towards our growth pillar, and wanting to at least look to pivot, prove, see that we can create value, and then pivot even further. If I then step back for a moment and say, that's how our strategy drives it. What does it mean for the Upstream business? I think it's very consistent with where we have been going, albeit it looks at a different time frame, and it is a scenario, after all. I can give you 100 different scenarios. What we have done is already guided towards that 1%-2% oil production decline with a peak in 2019. What we have done is we have also talked about no longer going for frontier exploration post 2025. We are already in a mindset that plays into the scenario. The question is simply going to be, is the pace going to materialize or is it going to be slower? I hope for the best, but we need to be able to be wary and be ready to go in step with society rather than go too far ahead of it. Let me maybe pause on that question and then hand over to you, Gretchen, to talk a bit about the Permian. Thanks, Wael. And thanks, Martijn, for the question. Yeah. From a capital allocation perspective, we actually feel really good with where we are right now in terms of allocating capital to the Permian. We're running three rigs that are operated by Shell. There's three to four rigs are operated by our non-operated partners. We're in a free cash flow positive position right now, which is right where we want to be. We've been there for the last three quarters. We plan to stay there. As you say, the price environment is looking positive, we have the ability to ramp up if and when we would like to do that. Right now, we're enjoying the free cash flow that's coming in from that. I mean, attribute that really to the fact that we've reduced our drilling and completion costs by almost 60% over the last five years. We've reduced our unit operating costs by 53% over the last five years. We've taken a lot of efforts to simplify our operating model, reduce our costs, really get clear on accountabilities. We feel like that free cash flow that's coming in right now is exactly where we want to be. We do have an opportunity to increase our capital when we want to. We've got 8+ years of Tier 1 inventory de-risked at this point with an opportunity to de-risked more over time. We feel like that flexibility of inventory and capital when we want to use it is available for us. Thank you for that, Gretchen. Martijn, thank you for that question. That was a good question. Thanks. Ally, if we can go to the next question, please. I'll take our next question from Christyan Malek from JP Morgan. Please go ahead. Hey, good afternoon. Wael, thank you for that presentation and some really excellent insights from the team. Appreciate it. Two questions from me. First of all, just going back to the slide 12 where you share your planning assumptions of the median term for oil price and in the context of that and luckily some of the variables you've talked about in terms of decline rates are $79 billion. The first question is around that, which is, well, say we are in a sort of sustained higher oil price, $60, $70, whatever. Does that dollar amount change? Would you then solve for potentially moving the needle towards no decline per annum? I just want to understand the reaction function of oil price to strip to your CapEx assumption in the context of that. It strikes me as slightly odd that if oil is at $70, you'll still be sticking at the low end of your, or whatever, $79 billion of Upstream investment when it would be more tempting to spend and generate more cash flow, particularly some of the inventory that you have in the deep water. The second question I have is regarding this argument around a sustained period of underinvestment and just how the National Oil Companies that you're interacting with are responding to your selection process around where you invest. In other words, how are the NOCs, without wanting to sort of single out one, responding to yourself and other majors' CapEx discipline and sort of in some cases under-investment versus previous years? How are they able to then sustain their own production levels without that funding that you've long put in there in the past? Thank you. Christyan, good afternoon to you, and thank you for both those questions. I'm going to start with the second one, in particular, the context of the national oil companies. Sinead, I'll come back to you to maybe reflect a bit on how we're thinking about capital going forward. Christyan, I think it's fair to say that there's a very different dynamic that we have seen over the past, I'd say five years, but that has accentuated in the last couple of years. I think the discussion around energy transition, the discussion around stranded assets has changed the dynamic. In particular, as we have all, as a sector, I think, held back on capital, and we've talked about it from a value over volume perspective at Shell. I think it's changing the narrative and the interactions with many of our counterparts. Not that there is anything that we're doing to hold back. It's much more to be able to try to get across in our discussions that we do need sanctity of contract. We do need the stability of investment climate. We do need the right support and the right fiscal incentives to be able to do that. That, I have to say, has landed a lot better in the last couple of years than I have seen in the last two decades, I would suspect, in our sector. You'll see multiple examples of that around the patch. I mean, just earlier today, a deal that we have been working on for a few years to try to close with our counterparts in Nigeria. Extension of the OML 118 Bonga block was finalized. That's taken us a long time, but it gives us now a deal that is commercially attractive and one that allows us to be able to continue to look at further opportunities there. Many of these things, I think we find ourselves at a point in time where there's a lot more sensibility in the discussion, and that there is a recognition that capital will simply leave the country if it is not given the right level of protection and the right incentive. We're trying to be as open and clear with our counterparts that we need to be able to have that environment if we are to continue to invest. Let me hand over to you, Sinead, maybe at this point, to get your perspectives. Thank you, Wael, and thank you, Christyan. Indeed. It's interesting to watch the oil price area, as you say, at the moment. At $79 billion of CapEx is a significant amount without a doubt. That range gives us flexibility, as we discussed earlier. You will see variability depending on which year it is. In some years, you'll see us at the lower end, some years you'll see us towards the higher. We will flex that according to both the readiness of our opportunities and, of course, what's happening in the macro situation as well. We have flexibility, which is definitely there. Beyond that, as I discussed, we have a significant portfolio or funnel of options coming towards us. We're not short of opportunities without a doubt. We talked about 400 kboed of just things in pre-FID coming towards us at the moment. We will use those as they become ready to begin to ramp up further as comes through. We've also talked about the options that we have in Shell, so we have that ability to swing between the different elements. Going back to that, I would say the cash flow that comes from this portfolio, as you rightly point out, with price going up, is significant. That $4 billion per annum factor CFFO for every $10 is just very significant and allows us a good point of view and ability to consider what we do with that when we transition and how we return them to shareholders, as we discussed before. Wow. Thank you for that, Sinead. Operator, before I go to you, Christyan, again, thank you for that question. Maybe the only thing to leave with you is, we don't plan to jump outside of that $7 billion-$9 billion range. We would like to very much be able to ride the various cycles within that space, it still gives us $2 billion of flex. What we don't want to do is the sins of the past, where we get excited by a short-term oil price reality, by the time the project comes in, the oil price has gone through the cycle. Expect to see us really disciplined in staying within that space. Thank you, Christyan. Operator? Thank you. Ally, if I can go to you for the next question? We'll take our next question from Jon Rigby from UBS. Please go ahead. Hi. Good afternoon. Thank you for taking my question. Four questions, actually. A couple, and then just one clarification. Can you talk a little about how the way you run the business has changed since you moved to a value over volume strategy? How have costs, activities, and behavior changed? I think one of the conundrums that we have had externally, in looking at oil companies and their financial performance, is that they advertise extraordinarily good IRRs very often on a project basis and deliver extremely poor return on capital employed. There's always been a sort of gap between projects and corporate. I just wondered whether, as you sort of change strategic behavior, whether there are things that drop out, either just absolute cost or risk or whatever. I just wondered whether you could talk about that and maybe talk about how we can reconcile better between those two numbers. The second question is there a risk as you pursue a strategy about value over volume? I assume that you will be more selective about the projects that you go ahead with. The way that you shape them will be focused on an IRR and a short payback. Yet governments and resource holders may well be sort of focused on something else, like a maximization of resources under the ground, et cetera. You may have issues in, I guess like Nigeria, where you want to exit bits of your portfolio but still pursue other bits. I just wondered whether there were any sort of issues of obstacles or sort of grit in the way of pursuing this strategy that arise because you're not aligned with stakeholders in the way you might have been before. Just one point of clarification. You sort of laid out the FID, but Groundbirch isn't on it. How does that fit into your plans? Thanks. Jon, thank you for those questions. I'm going to give Gretchen the opportunity in a moment to maybe clarify the Groundbirch ones. I'll take the first one, then maybe I'll come to you, Paul, given the amount of capital we're spending in the deepwater space, I think worthwhile to sort of reflect on this move from pure Net Present Value maximization to one that tries to balance NPV and IRR and the like, maybe in the context of V1, V2, Wave, et cetera. I'll try to address your first question there, Jon. I think it's a great question, and it's one where I have to say we've evolved over the past five years, so it's not been a value over volume, therefore you can see a change overnight. It has progressed. Before I get into that, maybe let me first acknowledge your point around the return on average capital employed. There's nothing more painful nor more transparent than the reality that the sins of the past continue to weigh us down. We still have, in our Return on Average Capital Employed, a significant number of projects where our breakeven prices were closer to $70, $75 in the heyday of the early 2010s. It's going to take us until the early part of this decade to be able to really get past them and to get the ROACE impact of the projects where we have been investing in the last four or five years in a much more value over volume mindset. What does it mean, though, value over volume in the way we work? I think it starts with the fundamental assumptions around oil price when you look at projects into the future. In the past, it would be one where you believe that oil prices are in perpetual inflationary mode. We don't look at that in the same way anymore. We look at one, the resilience as determined by the breakeven price. We look at the resilience against a set of different oil prices, including the high that we would get in a high oil price. That mental model of what we are measuring for when we invest in a project has fundamentally changed from where it was. I'd say another element of value over volume that you also see at the moment is our appetite to be able to really go after the tail of our portfolio. When we were much more focused on volume, and I mean by that both production and reserves bookings, it made us not want to move on some of these opportunities. When we have liberated the organization to say, "Where do we truly get value out of our time and out of our capital?" It's allowed us to really be a lot more scrutinizing of the portfolio and to focus on the key areas that make a big difference. Maybe the third and the last one I'll mention in terms of practical ways of where value over volume has changed the way we think about things is in the exploration space, where again, a volume over value mindset, or at least a volume centric mindset, was one where you are perpetually looking to put your exploration dollars into the highest potential contingent resource opportunities. The value, of course, typically sits in your near-field exploration opportunities. Even if you only get 30 million bbl, 40 million bbl, it can be much more valuable than a 200 million bbl discovery in a totally new environment. You can tie it back very quickly, you can leverage existing infrastructure, you can leverage existing organizational structures. You see us shifting 80% of our capital towards those core countries where we are truly focused on the value creation. I hope that just gives you a flavor of some of the things, and I have a long list I can describe to you of what we're doing, but it is this evolving change in the way we think and measure and screen how we do work that I think is an important element of this strategy. Let me now maybe go to you, Paul, to talk about the implications of that for some of the projects. Thank you, Wael. Thank you, Jon, for the question. Maybe if I pick up where you left off, Wael. Clearly it's a shift from NPV maximization to a suite of metrics that help us think about the business where IRR is a key one, but also cash breakeven, what that payback time is. Clearly that results in us thinking about a number of pathways that we have in a business such as deep water, where we have two tremendous basins and a very exciting frontier portfolio. Near-field exploration is one of those, and the ability to quickly tie back projects such as PowerNap or the Kaikias project that's been offstream for a couple of years. It's also as we think about those frontier exploration plays, how do we minimize cycle time and actually start off with a view of what will it take to de-risk and polarize? I think you see that in our entry into Mexico, where we went from lease signing to spotting the first well within two years. Once we sort of think about development, it's really about how do we think about developing the core and building options above that? You see that on Vito, where we took FID on sort of Vito as a core project, but now have options to think about water flood as an add-on on top of that. I think, in a maximize NPV world from five, 10 years ago, we would have looked at the totality of that in one, which adds complexity, cost, scope, scale, and size, not necessarily for the betterment of sort of the value piece overall. I think you'll see a similar type of thinking as we bring Whale towards FID, as we think about other pre-FID options such as Gato do Mato in Brazil. It really is about thinking about the holistic whole, how do we sort of lock in the core, then how do we give ourselves options to build on top of that to further enhance value through the capabilities that we have. Thanks for the question, Jon. Wael, let me hand back to you. Yeah, thanks, Paul. Indeed, to Jon's point there, I think we will continue to have to work with our partners, with our governments, to go in this direction, because that's the only basis under which we're going to be investing capital, as for our strategy. Otherwise, I think we go back to where we were. Maybe, Gretchen, just to close it off on the clarification around Groundbirch. Yeah, thanks, Jon. Groundbirch is a great asset. We have enough resource there to be matured through the whole 40-year window of LNG Canada Operating window. Since we FID LNG Canada, we've actually increased our volumes there through some commercial deals that we've worked, and we've reduced our cost significantly. Our cost to supply LNG Canada is down 20% since FID. As I said in my talk earlier, we're now able to supply LNG Canada Trains 1 and 2 at below the AECO market. We're really pleased with where we are there. We are planning to start ramping up drilling again in anticipation of LNG Canada probably late this year, early next year. The reason you don't see it as an FID is we just don't FID Shales projects in the same way we do major projects. You saw that on the slide, I think that Sinead showed at the very bottom where we have a constant capital allocation that's ongoing into our Shales businesses. We just look at it differently in terms of batches and how we performance-manage on a more short interval basis than we do on our big major projects. Thanks, Gretchen and Jon, thank you for those questions. Ally, can we go to the next question, please? I'll take our next question from Michele Della Vigna from Goldman Sachs. Please go ahead. Thank you. It is Michele here from Goldman Sachs. I wanted to ask you about your ambition to reduce OpEx by 40% over the next three years. It is clearly very important for the returns in the business. It is very ambitious. I was wondering if you could unpick some of the moving parts there. How much is cash versus non-cash? How much accounts from portfolio change? When I look back since 2015, you reduced your unit OpEx by 26%, and that was a period of major improvement in availability of broader cost deflation in the industry. 40% over the next three years certainly looks quite ambitious. Thank you. Michele, thank you for that question. What I want to do is to split this one between Sinead and Zoë. The reason I do that is just to clarify, we will be looking for roughly a 20%-30% improvement or reduction in our cost structures between 2019 and say 2025. The 40% is very much what we're looking for the lean ventures portfolio, which we believe we have disproportionately more that we can take out of it. Maybe I want to invite you, Sinead, just to talk about what we're doing across Upstream to Michele's point around cost, what's cash, what's not, and then give you the opportunity, Zoë, to further a bit what specifically we think we can do in the lean portfolio. Sinead? Thanks, Michele. You're right. You've seen that we've reduced our unit operating costs by more than 25% since 2015. At the same time, actually, just as we talk about impact to cash, our unit development cost has come down by around 50% as well during that time. We'll continue to look to reduce that further, and we're looking to reduce cost by an additional 20%-30% by 2025 compared with our 2019 cost base. To your point, how are we doing that? Part of it is by building a simpler portfolio that'll be powered by a leaner organization. I'll stay away from lean specifically and let Zoë talk about that. We are focusing on making sure we're more agile, increasing the project standardization and replication, and that flows through, of course, not only in capital, but it also flows through in terms of what you see in OpEx as well. You see it in terms of just having platform designs and operating platforms run in similar ways. Certainly on the design bit, which I realize impacts capital more, but you've seen it in Gulf of Mexico, and Paul talked about it a little bit, but also where we're seeing nearly 80% of the Vito design replicating into our Whale development. That's showing through in terms of just reductions cost specifically. More specifically on OpEx, we're being very focused on where we use our own expertise and where we turn to the external market. Recognizing where we truly differentiate and how to drive the most value from our differentiators and not reinvent. We will go externally when somebody else is more cost-effective to do something. Wael also spoke, of course, about the digital technologies that are flowing through at the heart of our transformation. I think he made it very clear about the absolute potential to drive cost down through those as well, both in terms of cost, but also improving performance line as well, which helps on the UOC element. If I take a step back and say, "Well, where's my confidence level?" Certainly our business plan, we've line of sight to 20% OpEx reductions over the next years. That includes efficiency improvements in the assets. It also includes the reduced staffing levels that we're seeing as a result of the recent restructuring that we've talked about, and also, of course, selective divestments in there. Also beyond that, we're continuing to challenge each of the assets to close their full gap potential and try and find further yield to bring that 20% up to the 30%, which is where we want to be. Zoë, I think you can build on that in terms of the specifics around the lean portfolio. Thanks, Sinead. I won't repeat some of the areas you've already explored around fundamentally how we want to go after the value stack that really will help us to drive the broader efficiencies in our underlying OpEx. I think worthwhile probably stepping back on our lean ventures and sort of remind ourselves that the broader synergies come really in two parts. It comes in our lean portfolio and our drive for additional efficiencies, and I'll come to that in a moment. But also in ensuring that the broader Shell organization, all of our functional expertise, our drive for project replication and standardization, is duly focused on the core of our Upstream business. What we intend to achieve is a significant momentum and pace of delivery in our core business, which of course is what will sustain our cash flows into the forward decade and indeed be the most significant part of where we attract our capital investment. For the lean ventures, indeed, our focus is really on three key themes. I mean, the lean assets are broadly categorized into three areas, what we call developing assets, mature assets, and those that we're divesting. The developing assets are those that we're still maturing, but we believe could have the potential for significant materiality or longevity. The mature assets are those that we're looking to maximize cash generation. Of course, those that we're divesting are those where we're driving the safe performance to maximize short-term value optimization. These are largely around those things that we have recognized are unlikely to make a significant material shift to our business over time. The shorter-term focus on the lean businesses is really around our governance and making sure that we can really go after our above asset costs, making sure that we have significant, leaner and simpler businesses. It also includes the way we're organized, our operating model. I think in addition, as I mentioned in the earlier part of our speech, making sure that we're really focused on those payback periods and those shorter-term hurdle rates to maximize our benefits. Hopefully that gives you a bit of a flavor, at least for the lean. We're really focusing on driving the efficiencies. Thank you for that, Zoë. Thank you. Thank you for the questions and I think as both Sinead and Zoë said, lots more to do. Since 2019, if you compare to Q1 results, we are 12% down in terms of costs, and therefore we're making good momentum. We still also have, of course, potentially headwinds coming our way around inflationary pressure. The real focus right now is to go even faster than that and make sure we can get closer to that 30%. Thank you for the questions. Ally, if I can go to the next question, please. I'll take our next question from Irene Himona from Société Générale. Please go ahead. Thank you very much. Good afternoon. I have two questions. Firstly, Wael, leaving aside things you don't control, like oil and gas prices, what to you is the key risk to Shell's Upstream business as you look ahead to the next four to five years? My second question, thank you for your presentation. Clearly, you presented today a strong progress made over the last five years in terms of your key metrics and further targeted improvements. In 2016, when you acquired BG Group, you presented that deal as an opportunity to reset the Shell portfolio. Looking today, on the one hand, at the progress made since 2016 and on the other, on your projected further quite material improvements to these key metrics, would you say that that post-BG portfolio reset in the Upstream has worked well, or is it something that is still, let's say, unfolding and in progress? Thank you. Irene, thank you for both questions. Let me address them both. Maybe starting with the second one. I have to say, I'm incredibly proud of what the organization has done since that BG acquisition. Indeed, we have set our stall there, and I think by and large, everything we said we would do, we have done. On the Upstream side, we have driven the rigor, we have driven the portfolio rationalization, we have done the improvements that we talked about. I think it's fair to say that this leadership team is not happy with doing better. We really want to achieve the full potential of this business. In all honesty, I don't think we're there. I think there's a lot more to do. I think we have moved a long way forward. We have through our reorganization, our corporate-wide reorganization called Reshape, we have reduced the number of staff. You're looking at a significantly smaller group in Upstream as well. We do believe that we're going to be able to fundamentally liberate that staff base that we will have left to be able to go after even more opportunities as we drive accountability deeper into the organization, as we look to leverage the capability of the organization we have. I'm in no way satisfied with where we are. I also realize that there is massive urgency in us getting there, both from us to being able to really continue to support RDS on its journey, also to be able to, I think, demonstrate that we can continue to generate significant value for the group and for our shareholders. I think that plays into the first question you asked, and I can come at this in multiple ways. I mean, fiscal concerns as in particular, a number of governments put a significant amount of their capital in support of a post-COVID recovery. Will there be fiscal threats to our business? I think all those are going to be important and clearly are risks on our horizon. The singular one that if you were to say the one that trumps all, in my mind, would be losing the passion, the energy, and the spring in the step of our Upstream organization. As the outside world sometimes tries to delegitimize an oil and gas business that for decades has been an incredible force for good for society, which is maybe why behind me here you see this pride in Upstream. To me, that is going to be the key issue, retaining that passion in our staff, irrespective of where they sit in the world. Letting them recognize that not only do we have a responsibility to continue to provide reliable and affordable energy, not only do we have a responsibility to support Shell in funding itself through the energy transition. We also have capabilities that Shell absolutely needs as we go through the transition. I touched on things like Carbon Capture and Storage, I touched on offshore wind, but also we have some incredibly strong legacy positions where our relationships with the government will serve us incredibly well. Our staff there have to help some of those governments as they transition with the energy transition. Making sure that as an enterprise, we continue to support that is going to be a top of mind for me and my leadership team. Irene, I hope that addresses the question. Thank you very much. Thank you. Thank you. Take care. We'll take our next question from Biraj Borkhataria from RBC. Please go ahead. Hi, thanks for taking my questions. A couple, please. On the Groundbirch, this question might be for Martijn, but I guess it's a kind of joint Upstream and IG development. How are you thinking about the timing of trains three and four? I suppose you'll be ramping up the Upstream spend alongside that, and there's probably some economies of scale there in terms of timing. Secondly, at the Upstream division level, you put out the targets in terms of unit development cost and things like that, but can you talk about return on capital and how you expect that to evolve under your price scenarios once you hit those targets? Thank you. Biraj, thank you for those two questions. I'm going to invite Gretchen to talk about Groundbirch ramp-up with the caveat maybe before I hand over to Gretchen to say no decision's been taken on Trains 3 and 4 at all at this stage, Biraj. The focus very much is on landing or starting up Trains 1 and 2 as and when we can. Nothing more on that space, but maybe just how we are thinking about the symbiotic relationship between Groundbirch and LNG Canada Trains 1 and 2. In the first instance, I'll have Gretchen speak to it, and then maybe invite you, Sinead, to reflect on where we are from the return on capital employed. Gretchen? Yeah, thanks, Wael, and thanks, Biraj, for the question. Our Groundbirch asset is one that we haven't been drilling there for the last couple of years in anticipation of ramping up when LNG Canada Trains 1 and 2 are close to coming on stream. As I said earlier, we anticipate that that's going to be somewhere around the end of this year or early next year. We've spent a lot of time, though, while we haven't been drilling, doing great work in that business. From a commercial perspective, the NPV of that business has gotten better. We've actually added resources around the edges of that. Our reliability is up above 97% right now. We have a very well-operated, safe, and highly valuable asset there that is poised and ready to be the primary feedstock for LNG Canada Trains 1 and 2. We look towards trains three and four, we'll be evaluating. Certainly Groundbirch has 40+ years of resource available to it. It will be there, and the team is there sort of ready and waiting to be part of that. I think the other thing I would add is that we look at this very much as an integrated business. While the Groundbirch team sits in my Shell team, they're very much part of an integrated value chain business of LNG Canada. There really are no organizational boundaries that inhibit that. As we get closer to being operational with LNG Canada, that will get more and more tight in terms of that integrated business and that integrated value chain. Thank you, Gretchen. Sinead? Indeed, thank you. If I take a step back again and think about our return on capital employed, it is true, and I think Wael raised this, that we have a significant balance sheet. We have several projects on our books that are clearly were done at different times and really have break-evens with much larger prices than we would look to today. What that drives, of course, is what we see is a significant depreciation flowing through from the Upstream business at the moment. Remember, you see over $3 billion per quarter coming through for us. That weighs heavily on the returns that you've seen coming through. Of course, what we're now trying to do is to make sure that we turn away from that and we learn from the different experiences that we've had. We've laid that out very, very clearly in terms of the discipline that we will have around our capital. You can see that the new projects are very much focused on value. To do so, we're using that suite of products that we've discussed. Whether that is IRR, whether that's NPV, whether it's payback periods, break-even prices, et cetera. That allows us to look at the full risk spectrum that we have and make sure that we are increasing those margins as they come through. This is all about driving discipline, of course, and making sure that at the end of the day, we're improving those returns. You'll start to see that flowing through with all of these metrics in place and that continued discipline. Alongside that, of course, as we discussed, our returns will be helped by the fact that we're driving that cost structure down further with the aspiration to further reduce costs by the 20%-30% that we've talked about by 2025 as well. That should start to show a significant impact on our return on capital. Wael? Thank you, Sinead, and indeed, Biraj. I think that is also largely why we have been very clear around the 18% internal hurdles on Upstream, 20%-25% average of our portfolio. That, as Sinead says, with time, you're going to see that start to filter through into our ROACE. Thank you for the question. Ally, if I could invite the next question, please. We'll take our next question from Lucas Herrmann from BNP Paribas Exane. Please go ahead. Thanks, thanks very much for the opportunity. A couple if I might. Nigeria onshore. Can you give any indication of where you'd like to end up, as regards Nigeria's onshore and how far in that direction your discussions with government might propel you? Wael, Argentina, it's non-core, but you talk about it as though it's a core asset. What's the disconnect? What am I missing that explains why it's sitting in a particular bucket, but as yet, you seem less than convinced that it will stay? Those are the two. Thank you. Thank you very much for both questions, Lucas. Let me invite Zoë to speak to the first one and then invite you, Gretchen, to speak to the second one. Thanks, Wael. Thanks, Lucas, for the question. I think perhaps firstly, of course, we've said a number of times now in various forums that the onshore oil operations in Nigeria, which are continuously exposed to some of the third-party interference and illegal activities in sabotage and theft and so forth, has put those assets outside our risk appetite. I think you talked about what does endpoint success look like, and I'd probably touch on a couple of principles that are guiding the discussions that we're having at the moment. The first, I think it's really important that we continue to work with our host governments on the way in which we want to look to exit some of our onshore oil assets. The engagement that we're having and the collaborative discussions with the Federal Government of Nigeria are core to that. The second thing I would say is that we, of course, always seek to ensure that in any exit that we have, that we do so in a responsible manner. That includes what that looks like in terms of our historical footprint in-country claims, liabilities, and so forth, and that we have a mechanism through which that we can continue to focus on the way in which those historical issues are resolved. Finally, importantly, I think for any of our exits in onshore oil, we find it important to see that Shell Petroleum Development Company as a joint venture and the way that that exit is conducted ensures that we have a sustainable business that is indeed remaining in the country. Of course, in that regard, we can say that the work that we have done as the operator of SPDC has seen some significant improvements in the SPDC world-class performance. The capability that resides within SPDC is, of course, world-class, including some of the operational improvements that we have seen around their spill response, and their ongoing improvement to the underlying competitive business performance. I think the best thing I can say at this stage, I think, Lucas, in response to your question, is that we're very clear about the principles that we are seeking to engage as an endpoint. We're working closely with the various stakeholders, and venture partners, in the pursuit of our ambitions there, and that we need to continue to keep those live in discussions. It does, of course, I think Wael mentioned it before about OML 118, we do continue to see bigger opportunities, I should say, in Nigeria holistically. We do continue to hope to be able to unlock the value that we see in our deep water and our Integrated Gas value chains. Perhaps I'll leave it there, Lucas. Over to you, I think. Can I ask, any idea on timelines for those items? I think, Lucas, Wael will be saying that like with any kind of ongoing commercial discussions, best that we don't talk timelines at this stage. It's important to say that this is something that certainly has our attention and is an active discussion with our key partners and stakeholders. Thank you for that, Zoë. Gretchen, on Argentina? Thanks, Lucas, for asking about Argentina. It is a great asset, and it sits in the category that Zoë spoke about just a few minutes ago called lean assets. Inside lean, as she discussed, there are three different buckets. This very much sits in the developing bucket. It is an asset that we are investing in right now. We are primarily investing in the black oil window. We're highly optimistic with the well results we've seen so far have been above our expectations. It comes with a different set of non-technical or above-ground risks. Of course, we proceed cautiously there. We've got good relationships with our partners. We operate most of what we own there. We do collaborate, of course, with YPF, the national company there. They operate a bit of what we have as well. So far all of that's going well. Again, we keep our options very well open there and make sure that we have the ability to sort of ramp up and ramp down as those risks become or shift over time. The other thing I would just say about Argentina and frankly, the whole Shales portfolio, a number of you have asked about cost reductions. We have aspirations and frankly, plans in place to reduce our costs over the next few years. Inside the Shales portfolio, we've actually gone through a big change already. We've brought our cost down just over the last 18 months by about 30%. That came with a lot of effort. We completely re-baselined our operating model. We exited about 45% of our people. As a result, our operating model is very simplified. We have very few handoffs now. That also is something that gives us confidence when we look at our operations in Canada and the U.S., but also, of course, Argentina. Thank you for that. Just a follow-up question on Argentina. Has it been easy for you to repatriate funds historically? Maybe invite Sinead, do you want to say a word on that? Sure. At the cycle that we're in at the moment, of course, we're actually investing at the moment. It's a developing asset as Gretchen rightly put, so it's not something that we've had too much of an issue with in recent years. Of course, you rightly point out to the risk of Argentina, and we stay very close to it. We do have a breadth of businesses there, as you know. I'm not going to step too far outside of Upstream at the moment, but as you're aware, we've got some Downstream businesses as well, which gives us a bit of diversity and a bit of an implicit hedge as well then. Thank you for that, Sinead. Lucas, thank you for those questions. Just to take stock of where we are. We plan to run to the top of the hour, so suggest another 20 minutes or so, and Ally maybe would invite the next question. We'll take our next question from Roger Read from Wells Fargo. Please go ahead. Hey, thank you, good afternoon. Two questions for you. One, a little more involved. Second one's pretty straightforward. The first one is we're looking at the transition out to 2030. You're going to get a 55% gas breakevens today, $30. If you're going to add more gas, I'd expect your breakevens actually should go lower. I'm wondering, as we look at all the cost reductions that you're looking at and guiding to in the near term, how does that maintain pace with what is likely to be a lower overall capture at the revenue line? Do breakevens stay $30? Do they also go down, given that we would expect you to be getting something less than a pure oil price for the majority of production as we go through the decade? That's question one. The second one, as we look at Perdido, the commentary about it going from the low 80s to the low 90s on utilization, curious how that compares to expectations across the rest of your portfolio. In other words, was that a significant improvement, or is that relatively normal for what you see across your overall portfolio, deepwater or otherwise? Thanks. Roger, good day to you, and thank you very much for that. I want to invite Paul to talk about Perdido, and I'll maybe touch on the first one. If I just step back for a moment, when we think about this transition to 2030, just to remind everyone, in the Upstream business, we have a portion of the gas production. Of course, our Integrated Gas business also has some significant gas production that is tied into the full integrated value chain that typically is LNG, but of course, also includes GTL in the case of Qatar and Malaysia. Today, we are roughly 2/3 up to 70% liquids production in Upstream. Indeed, as we guided, that will sort of decline at 1%-2%. Once again, I'll just sort of stress, that's more through portfolio moves, more so than the underlying decline in our core assets that today generate the majority of our cash flow, which is why we continue to have high confidence in our ability to generate that consistent and steady cash flow well into the next decade. I think what you see us doing here is firstly setting some clear boundaries around our returns expectations of any project we invest in, whether that's oil or gas doesn't matter. We are looking at 18+% IRRs when we invest in these opportunities. We're hoping through a very clear hurdle rate to be able to maintain the sorts of margins irrespective of what commodity we're investing in. When I look at the broader portfolio, when we do invest in a full LNG value chain, then indeed you will see that we can make quite a bit of the incremental money, not just from the Upstream, but of course from the trading optionality that it gives us to bring gas into the portfolio. That can be significant, as you've seen in many quarters of late with the delivery of our Integrated Gas business. I think that the last thing I would say is our challenge to reduce costs is not driven by a 2030 outcome. It's a fundamental view that as we have really looked at our portfolio and challenged ourselves asset by asset, what is the full potential? Who are the best in operating an asset like this? What's the sort of availability they can achieve? What's the sort of cost level they're running at that? Irrespective of whether it's a major, a minor, an independent, who are the best of the best? We are pursuing for every single asset, the bridging of that value gap that we see. That's why we believe that we have another 20%-30% to go and are not satisfied with where we are today. You put all that together, I think the total picture is one that with lower production, you're still going to see the same level of cash flow through this decade at least. Maybe a segue then to you, Paul, in that context for Perdido. Thanks a lot, and thanks, Roger, for the question. Maybe a couple of points that I'll make. The first one is you can invest in a capital sense for reliability and availability by having sparing philosophies, redundancy, et cetera. You can also think about in terms of how do you operate efficiently from a maintenance perspective, from a turnaround perspective, in terms of the rigor with which you drive continuous improvement and the standardization of the underlying core processes. I think on Perdido, that's what you've seen. At the time of the capital build of that project, the choice was that from a capital structure and capital cost point of view, we designed for an 83% availability. What we've actually done through thinking about where the weaknesses are, where the potential of that asset is by driving rigor, minimizing turnaround time, maximizing the maintenance that we do in a predictive sense versus a reactive sense, been able to drive that above 90% as I mentioned. That's a view that we take across the totality of the portfolio. The Deepwater portfolio, as I mentioned, delivered 90% availability last year. We see that journey continuing. We're very much driven by the benchmarks that are out there, really what is best in class, making sure that we understand what the gap is between our own performance and that best in class. How do we do that? Not at any cost, but whilst also driving down our unit operating costs. I think you saw that on the slide as well that says we have driven up availability. We've also driven down our unit operating costs. It's about good investment that actually gives us greater yield. That's not just specific and unique to Deepwater. That's something that we're driving across the totality of the Upstream portfolio. Well, back to yourself. Thank you for that, Paul, and thank you for the questions, Roger. Ally, if we can go to the next question, please. We'll take our next question from Peter Low from Redburn. Please go ahead. Hi. Thanks for taking my question. The project list on Slide 27 doesn't have any future developments in three of the nine core regions, Oman, Brunei, and Kazakhstan. Can you perhaps give some color on how you plan to maintain production in these countries? Is it just that there are a number of smaller brownfield-type projects which don't feature in the list, or is it down to lower decline rates in those regions? Any color would be great. Thanks. Peter, thank you for that. Zoë, maybe I can invite you to respond, given the majority sit in your portfolio. Peter, thanks for the question, and I'm pleased that you asked because indeed, we maybe don't list them in the slide, but there is a significant opportunity funnel in all of the three countries that you talked about. I think both in Oman, in Brunei, but also in Kazakhstan, we have some very active and quite competitive projects on the horizon that we continue to invest in. I'm not sure how much time I have to go through all the specifics, but I can say that all three countries do continue to be core countries because we do see that longevity and competitiveness in the backfill. I think we've got a number of projects that we are pursuing in combination with our partners in Kashagan related to the development of phase II-B i n particular. We've got a number of debottlenecking projects which are also on the horizon, some of which are taken to FID, some of which are in commissioning, some of which we are in the development funnel. Similarly for Karachaganak as well in Kazakhstan. In Brunei, we also have a significant portfolio, and similarly for Oman. I might keep it at the high level, but indeed, happy to follow up offline with some specifics for each of those countries in the broader project funnel that we have. Thanks, Zoë. Peter, I think you asked and answered it well as well. Indeed, there is a decline rate question, which is lower than Deepwater, and there is indeed a lot of brownfields. Zoë, thank you for that. Ally, if we can go to the next question, please. We'll take our next question from Lydia Rainforth from Barclays. Please go ahead. Thanks. Good afternoon, everyone. I have two quick questions if I could. The first one, can we go back to the digital side of things and the idea as to how much of the cost reduction is actually coming from the digital side versus Project Reshape? How far along that journey are you? I think in the past, we've said there's a lot of work that goes in to get the infrastructure right on the digital side before you see almost a hockey stick effect. Just in terms of the idea of developing pathways to net zero emissions for the Upstream operations, can I ask why not have a more specific plan at this stage in terms of, it does say we're developing pathways. At what point do they actually become developed pathways? Thanks. Lydia, my apologies. That second question, I'm not sure I fully got. Can you just repeat it one more time for me? Yeah, sure. I think in one of the slides, it does refer to basically this idea of getting to net zero emissions for Upstream operations and developing pathways to get there. From what I understand, you're putting CCS into all of the projects already, or they're all carbon capture ready. I'm just wondering why not a more specific plan as to when you want to get to net zero emissions from those Upstream operations. Just wondering if you can comment on that. No, thank you for that clarification. Let me quickly touch on those two. I think on the digital one, I recall you and I had a discussion, and at the time I said to you, we are literally 20%-30%. We've moved from that, but we haven't moved a huge amount. I think we continue to make good progress along a number of different areas, but I still think the potential is significantly beyond where we are today. Let me maybe just say a few words on that. As an enterprise, as Shell, we have sort of quantified around $1 billion- $2 billion per annum of incremental value that digital has been contributing. I think at one point, Harry had spoken, I think a couple of years ago, about the $1 billion per annum. We see that closer to the $2 billion per annum. Important to recognize it's not just driven by cost. It's driven by improved availability. It's driven by improved margin in our customer-facing businesses and so on and so forth. What I would say right now is digital was an add-on to the way we were doing work. We were doing work in an analog context, and then we tried to supplement with digital. Through Reshape, we are fundamentally remapping all of our workflows. The way we do exploration, the way we do development, the way we do production, we're remapping it with a digital lens, an integrated value lens, and we're looking to digitally enable those workflows. It is going to be much more fundamental to the way we do business. What will it achieve? It will allow us to really derive insights a lot quicker where we need to get them. It'll force a different level of integration than we have ever seen in the past. I think it'll unleash the excitement and the energy of our people as they work on it. I won't venture to put a number as to how much we can unlock from it, but suffice it to say that everywhere we've looked, we found value. I think to your second question around the net zero emission pathways, we are in the midst of developing those pathways. As you rightly say, we're looking at it from a project perspective, but there's several elements we're looking at. Firstly, how to make our existing assets, the ones that are producing, as low carbon emission as possible. I think Gretchen spoke very eloquently around what's happened in the Permian as a great example. If I then look at Paul's shop and where we're investing in new projects, as you rightly said, we're looking there at certain project specifications around carbon that are a lot tighter than we would have done just a couple of years ago. If you look at Zoë's example around what's happening with Acorn in the U.K., and how we're trying to leverage CCS opportunities to be able to create sinks, not just for our own CO2, but to fundamentally leverage those sinks to also create a customer sink, as we bring our carbon-facing businesses to make sure that they support our customers in decarbonizing their own value chain. You put all that together, and when we talk about these pathways, they are evolving at a certain pace, driven by local legislation, driven by carbon pricing, driven by technology advances, and we expect them to continue to move. I suspect reality in five years' time will be very different than what we see it today, simply because we have a lot more levers to be able to pull than what we have had in the past. Lydia, I hope that addresses what you had. Thank you. Lydia, invite Ally to ask the next question, please. We'll go ahead and take our next question from Paul Cheng from Scotiabank. Please go ahead. Thank you. Good afternoon. Two questions, please. If I look at page seven of your presentation, your show look like the unit cost is flat from 2019 to 2020, given the supply cost has come down quite a lot last year, and your controllable availability have gone up. I imagine that the reason why it's flat is because of the negative impact from the OPEC+ government mandate production cut. Can you tell us then what is that impact? In other words, in a more normal world, without that production cut, what's the unit cost look like in 2020? That probably is a better baseline we can use to project forward. The second question is go back to Permian. It's still unclear to me what is the game plan for Permian on the longer term, not so much about this year or maybe even next year. If I look out five years, is the Shell's expectation to grow the Permian production and increase the activity level? Or that the expectation is you're going to run it as a cash cow and maintain the current production and current activity level? If you do increase the activity level and CapEx, given your overall Upstream CapEx is $7 billion-$9 billion, relatively fixed, so where are you going to get the money? Which area are you going to reduce? Also, can you tell us what's Permian production currently? Yes. Thank you. Paul, thank you for those. I'm going to come to you, Sinead, in a moment to ask a quick response to the unit cost 2019 to 2020. Gretchen, if you're okay, I'll quickly maybe address the portfolio question, given I suspect it's on a few minds. I think, Paul, what I would say there is we have not shied away in the past from saying we don't think we have the scale that we typically need. We have a subscale Permian position, but we've also been very clear that it does not take away from the need for us to do all the things that Gretchen has talked about to really create an exciting, very competitive position. We're investing our time and effort over the past year and continue to do so to get the best business we can get to. We want to retain options as to what we want to do with the portfolio, whether to grow it or any other options that we might want to conceive at the time. What we want to do is to make sure we're in the fittest state before we make that next decision. If we do choose to put more capital into the Permian, the $7 billion- $9 billion, as you rightly say, is across Upstream, but you also know how lumpy our capital spend is. Once we've invested in a few of the ongoing projects in the quarter, we will create a bit more capacity unless our exploration team discovers some more resources. We will optimize and constantly high-grade t o make sure that capital is going to the right places, including the Permian, when the right opportunities come through. Did you want to quickly, maybe Sinead, address the first question? Sure. In the interest of time, it will be quick, so my apologies. It's a great question, Paul. 2019 to 2020 is a difficult one. You rightly point out the fact that, of course, the impact from OPEC hit us, but it was much more than that as well. Of course, with COVID, we made some strong choices. Some of that was cash preservation, which meant, of course, we pulled back. Particularly, Gretchen's area, Shales, is a key one there. We dropped rigs, but we also shut in wells in many places. In other places, we also had the situation where we simply couldn't get people out to platforms. In some cases, we took the opportunity to either incur maintenance or to literally shut in. That means, of course, that what you're seeing is unit costs coming down to flat across those two years. What you do see as you move into Q1 of this year is a continued focus on costs coming through, and you'll see that continue to flow out. You'll get those proof points as we go through this year, as it becomes a little bit more normal, and we see the OPEC impact, which is still there, but very small at the moment, continuing to roll through and as we catch up on some of the maintenance. I apologize. I realize that's very quick, Wael, but I recognize you need to close off, so I will hand back to you. Thank you for that, Sinead. Paul, just to close out your last question, roughly 160,000 bbl-170,000 bbl per day production in the Permian. I'm looking to Gretchen in case I've gotten that wrong. Okay, good. Thanks, Gretchen. Paul, thank you for those questions. Let me maybe now move to close out. Firstly to apologize if we haven't been able to cover all the questions. Thank you for the interest. Our commitment is through our IR team, we will make sure we come back to you to be able to address any lingering questions that you might have or potentially to draw on some of us, which the IR team can do if needed. Just to close off and say a huge thank you on behalf of the entire Upstream Leadership Team. More broadly on behalf of everyone in Shell. Thank you for the interest to join this call and for your active participation as well. I have to say, I'm incredibly excited about our Upstream business and fundamentally believe we have a critical role to play in the Shell strategy going forward. I and this leadership team look forward to continuing this conversation with you over the coming days and months and look forward to hopefully meeting you in person when the opportunity allows itself. Thank you, everyone, and have a good rest of the day. With that does conclude today's call. Thank you for your participation. You may now disconnect.