Harbour Energy plc (HBR) Earnings Call Transcript & Summary

Hello, and welcome to today's Harbour Energy Capital Markets Day. I would now hand you over to Linda Cook, CEO, to begin. So Linda, please go ahead.

Welcome, and thanks for joining Harbour Energy's first Capital Markets Day. Of course, we would have preferred to host an in-person event, but given the fast-changing COVID situation, it just wasn't advisable. In fact, a couple of people on our own team had to self-isolate or quarantine over the past few days. So in order to avoid any last-minute surprises with speaker availability, we actually prerecorded these presentations. But our Q&A sessions will still be live, so you'll have a chance to see all of us virtually in a short while. Turning to the agenda. We've divided the event into 2 parts. In the first, I'll be joined by my fellow Executive Directors, Phil Kirk and Alexander Krane. We'll cover key topics, including strategy, recent performance, capital allocation and guidance. This will be followed by our first opportunity for Q&A. Then in part 2, our speakers will go into more detail about our key assets, with a second opportunity for questions after that. I'll get us started now with a summary of Harbour's history. Founded by private equity back in 2014, we made our first acquisition in late 2017, acquiring producing oil and gas assets in the U.K. from Shell. This was followed 2 years later by the acquisition of Conoco U.K., and then earlier this year by the reverse merger into Premier Oil. The result of these 3 transactions is that we went from 0 to 200,000 barrels per day and became the largest U.K. listed independent Oil and Gas company with a market cap today of around $5 billion. While the majority of our current production is in the U.K. We do have a global spread of assets, including operations in Vietnam and Indonesia, along with attractive potential growth opportunities in both Southeast Asia and Mexico. Consistent with our strategy, we recently announced plans to exit exploration licenses in Brazil, as well as the large Sea Lion development project in the Falkland Islands. We're financially strong, even though we invested around $1 billion this year in total capital expenditures and completed 3 major transactions in under 5 years, we're generating material and resilient cash flow, and our leverage ratio is projected to be around 1.0x at year-end. Given this position, we're pleased to have announced today the introduction of our dividend policy of $200 million per year, equivalent to 16p per share to be paid in equal semiannual installments. Our first $100 million distribution or 8p per share will represent our final dividend for 2021 and will be made following approval at our AGM in the spring. Another topic very important to us is the energy transition, and you'll be hearing more about our plans in this area throughout the presentation. Keeping on the theme of ESG, we're also committed to strong corporate governance and have assembled a world-class Board of Directors who hold myself and our leadership team to a very high standard. The Board includes 2 appointees from EIG, our private equity founder, but it is majority independent, and includes a very experienced Senior Independent Director in Simon Henry. On the right, you see our senior management, a mix of executives from legacy companies and new hires, all of which bring decades of U.K. and international Oil and Gas experience. So why invest in Harbour Energy? At a time when major oil companies are deemphasizing their upstream businesses. we provide pure-play exposure to oil and gas production. We're not investing in midstream or downstream, and we're not intending to launch into wind or solar. Our focus for now remains firmly on oil and gas production. And we do this at scale. Our strategy of focusing on material acquisitions helped us avoid the trap of buying something small and ending up with subscale illiquid portfolios. Today, we're the largest oil and gas producer in the U.K. and the largest FTSE listed producer by some margin other than the major Shell and BP. Size, however, wasn't our only priority. We also had a goal of building a diverse and cash flow positive portfolio. At first, that meant exposure to multiple key producing hubs in the U.K. North Sea. Then we further diversified through the Premier merger, which added production in Southeast Asia, as well as interest in some exciting potential new opportunities in Indonesia and Mexico. The resulting portfolio is resilient, includes a good mix of oil versus gas and has embedded in it a wide range of relatively low risk high-return investment opportunities. These enable us to keep production relatively flat in the near term while, at the same time, continuing to generate substantial free cash flow. I referred to the energy transition earlier. Our goal is to be a responsible oil and gas producer and through a combination of activities to aim for net zero by 2035. It's an ambitious target, especially for an independent oil and gas company like Harbour Energy, but one that we're committed to working towards. Another key aspect of our investment proposition is our conservative approach to the balance sheet. After completing 3 multibillion-dollar transactions in less than 5 years, we won't end 2021 with leverage of around 1.0x by accident. The strong balance sheet is the result of proactive risk management, an approach we'll continue to adopt going forward. Because of that, we're able to introduce our dividend policy today. we believe a commitment to shareholder distributions is an important part of our equity story and are excited to be making the plans for our first distribution in the coming months. Finally, we've grown the company through M&A and believe the opportunity set in the near to midterm will be fairly rich, especially given the shifting strategies of many major oil companies. We're a proven, capable and well-capitalized buyer and feel there will be limited competition. Having said that, we don't have to transact today, we'll continue to be patient and very focused on strategic fit, value creation and affordability. Next, a few words about the business environment, starting with the outlook for oil supply and demand. While the transition away from liquid hydrocarbons has begun, it's not practical to quit Cold Turkey. In my view, the ramp-up of abundant, reliable and affordable supplies of renewable energy will take some time. This introduces a level of uncertainty around long-term oil demand. But at the same time, however, there's uncertainty over supply, due to lower levels of global investment in the exploration for and development of new fields. And this is compounded by more limited access to capital for the oil and gas sector. All of this has influenced our strategy at Harbour. Our main strategic focus is on creating value through the acquisition and operation of existing producing assets, and not on exploring for new multibillion-dollar oil accumulations, which may not start production or pay out for 10 years or more. We're more focused on the near to midterm. Turning to natural gas. The outlook for demand is much stronger given its lower carbon impact versus oil or coal, and the role it can play to supplement renewable power generation. In particular, in the U.K., as we've recently witnessed, the need for domestic natural gas is clear, especially with limited local storage, the uncertainty of Russian supplies and the competition with Asia for LNG. The impact has been local natural gas prices upwards of 200p per therm, equivalent to about $26 per MMcf in U.S. terms. Today, our production is close to 50% natural gas, with the forecast for that to increase somewhat during the course of the next couple of years, giving us good exposure to this local market. What does all of this mean for our strategy? We aim to continue building a global, diverse, independent oil and gas company focused on 3 things: creating value, generating cash flow and allocating that wisely. Starting on the left, as already mentioned, we're focused on being a responsible operator. While these days, we may talk a lot about the environment, we should leave no doubt that safety remains our #1 priority at every level of our company. Our next strategic pillar is maximizing value from our existing portfolio in the U.K. This includes through the use of technology, through investing in organic low-risk drilling opportunities and continuing to realize synergies from our acquisition integration efforts. Through all of these, we have the potential to maintain production levels and generate considerable positive cash flow for some time. Next, we aim to continue to diversify through M&A, with the goal of establishing a material producing platform in at least one other region. We'll be very selective, focusing as we've done in the past on conventional producing assets. And we'll remain true to our commitment to actively manage risk, to protect the balance sheet and to protect our ability to distribute cash to shareholders. In addition to talking about what we will do, sometimes I find it's helpful to also be clear about what we want. I've touched on many of the themes on this page already, but just to emphasize a couple. Our intention in the near to midterm is to remain focused on oil and gas production. And while we might invest in low-risk, near-field, near infrastructure exploration. We will not invest in greenfield exploration in areas where we don't have an existing producing presence, as evidenced by our recent decisions to exit exploration licenses in Brazil and the Falkland Islands. Given lower risk opportunities for us to grow and uncertainty over long-term oil demand, these sort of investments just don't seem to make sense for our company. And we also won't enter new regions by taking small non-operated positions in subscale assets. We see the value of scale of having diverse portfolios, and we'll maintain a discipline around that. And while not specifically listed here, we'll ensure our portfolio remains predominantly OECD. Again, given the current environment and opportunities available to us, I'm just not sure it makes sense or is necessary for us to expose ourselves to a large degree of geopolitical risk. Turning now to our net zero commitment. The definitions for a lot of the terms used in this space continue to evolve. So let me start by explaining what it is we mean when we say net zero by 2035. It starts with deciding which emissions to include. As we are an independent oil and gas company without a downstream or retail presence, our focus is on our Scope 1 and Scope 2 emissions. And we include emissions from our share of both our operated and non-operated assets. This is how we account for reserves, for production, expenditures and earnings so we believe it makes sense for us to account for our emissions in the same way. How will we get to net zero? Given the changing regulatory landscape and uncertainty around CO2 taxes and other aspects, it's actually not easy to carve a path in stone, but we're not just sitting around waiting for the rules to be set. Instead, we're already involved in a wide range of activities that have the potential for material impact and for helping us reach our goal over time, as illustrated on this page. The most important element of this strategy is to lower our own emissions. This includes things like replacing inefficient equipment and more ambitious projects, such as electrification of offshore assets in the U.K. North Sea. Our strategy also includes being involved in CCS, or the capture and storage of CO2. In the U.K., we have the potential to use our infrastructure and offshore depleted fields to store massive amounts of industrial CO2, which is very exciting for us. However, today, it's not exactly clear whether and how Harbour's investment in these projects will actually count towards our goal or whether it will ultimately make economic sense. Nevertheless, we're moving forward with preliminary engineering and other efforts, while we await clarity around the regulatory and commercial framework, with the hope of advancing the projects towards investment decisions in the coming years. Finally, we have a commitment to acquire high-quality credits over time to address our remaining residual emissions so that we are net zero by 2035. So what have we done so far? In our first 9 months as a company, we worked to establish an emissions baseline and standardized measurement systems. And we instituted economic guidelines for use in screening potential emissions reductions activities and testing the resilience of our portfolio. We also ensured we're incentivized to deliver these reductions through our annual bonus scheme as well as through an incentive embedded in our main debt facility. Our emissions baseline is shown on this chart. This year, we anticipate total emissions of just under 2 million tons. While we work to bring that down, we've already started to purchase offsets with our first investments anticipated to be in 2 projects in Brazil: Forest conservation and landfill gas capture. The total credits being acquired are 1.2 million tons to be purchased for a cost of around $10 per ton. We currently intend to apply 1/3 of these to offset our emissions in each of 2021, '22 and '23. The result is a net reduction in our emissions of approximately 20% per year, an important first step for us. Turning back to the growth component of our strategy. In spite of the recent spike in commodity prices, we do see a fairly favorable environment for potential M&A. The sector outlook is for over $80 billion of possible asset divestments in the near to midterm, mostly coming from major oil companies but also from small companies looking for scale and private companies looking for liquidity. At the same time, there aren't many buyers like us: Credible, well capitalized and with a track record of funding, closing and integrating major transactions. What do we look for? Mainly value, and finding this in conventional producing assets. Assets that are accretive from a portfolio standpoint, meaning margins, emissions per barrel and reserves life; and assets that are accretive financially, meaning cash flow. But we're not in a hurry to transact. We'll continue with the same disciplined targeted approach that has served us well so far. Here's a high-level summary of how we created value with our last 3 transactions. There are similarities in the Shell and Conoco acquisitions where we purchased assets no longer deemed strategic from 2 mega producers. We know firsthand that once a company decides to sell an asset or exit a region, they tend to starve those assets of capital. This means these sort of deals typically present opportunities for us to lower operating costs and to make small, low-risk investments to improve operations at reserves and extend field life. With the Premier merger, we do have some of that. But it's just a smaller portfolio, so the scale of these opportunities is less material. But what this merger did bring was some geographic diversification with some embedded longer-life organic opportunities, and substantial financial synergies. Okay. Last slide for me before I hand over to Phil. On this page, we show Harbour's progress from 2017 to today. Illustrating the growth in terms of volumes, reinvestment, profits and cash flow and the fact that we've been able to do this while keeping leverage low. We're ending the year in a strong position, producing 200,000 barrels a day from a diverse mix of high-quality, cash-generative assets with good visibility to sustain this for the near term. This, together with our strong balance sheet enables us to introduce a $200 million annual dividend and to fund reinvestment in our portfolio, while retaining significant optionality over our future capital allocation. Now over to Phil Kirk, feels responsible for our European assets, which today account for more than 80% of the business. He'll give you an overview of our global portfolio, our performance in 2021 and a look ahead to next year. Over to Phil.

Thank you, Linda. I'm going to take you through a review of Harbour's recent operational performance. You'll see how our production levels have recovered in the fourth quarter, what we can expect in 2022, a little bit about how the integration is going and a bit more about what makes us excited about the future. Later on, you'll hear from Bob Fennell and Stuart Wheaton, and they're going to take a more detailed dive into the business. Firstly, you will have already heard we're reiterating 2021 production guidance. So on a pro forma basis, we're at 185,000 to 195,000 and a reported basis 170,000 to 180,000 barrel of oil equivalent per day. On the reported basis, we're forecasting 175,000 barrels, which is right in the middle of that guidance range. There's only a few more weeks to go, but nearly there. Secondly, you'll have seen that we're guiding 2022 production between 195,000 and 210,000 barrel equivalent. And we've got a good line of sight staying around that 200,000 barrel a day mark that Linda and I have been speaking about for the next few years. I'll also take the opportunity to update you where we are with Tolmount. You should also take away that our operating costs are firmly in the $15 to $16 per BOE range. And again, as we begin to deliver on the organization, the integration, the associated synergies we gain more comfortable that this level of unit cost is sustainable. The projects we have in the hopper, not just for next year but for the 3-year short-term plan, are high quality and generate material returns. I'm going to talk about that a little bit later. But the majority of our projects in 2022 deliver returns to over 50% and potentially even more at current pricing. As I look back at '21, the majority of our projects have been delivered safely on time and to budget. And we continue to learn from our decommissioning work and have a good execution plan for the next 5 years on that, showing around the $300 million mark per year, pretax spent on decommission that we've talked about before. Later on, I'm going to talk about our CCS projects. And I'll finish on a reminder how we've delivered value through our previous acquisitions of low-risk producing asset portfolios whilst maintaining a robust balance sheet. Harbour is committed to operating responsibly and never compromising our HSES standards. We're very focused on the prevention of major accidents and controlling the houses around our business 2021, has not been a bad year by industry standards, thanks to the efforts of our staff and contractors, but we still have much to learn and can always improve. Since the half year, we've not had any further Tier 1 or Tier 2 incidents come in a loss of primary containment, this is good. But we've seen recently an increase in occupational safety incidents, albeit with no life-changing injuries. We're still running at lower incident rates than some of our peers who are working hard with our staff and the supply chain to ensure we stay focused and learn from a number of high potential incidents we've seen. As we look at our emissions in 2021, you'll see the impact of a more active year and lower production. Positively, we're beginning to see a number of initiatives impact on our greenhouse gas total emissions. And apart from a number of capital projects, which have delivered reductions, we've seen material improvements with different ways of working, particularly looking at efficiency and challenging previously held operating paradigms, such as moving to single train operations from 2 train as a good example. Now this chart shows production performance by field across the complete Harbour portfolio. We've discussed our last update some of what happened, but you can see easily on this graph, the Elgin-Franklin outage together with the summer shutdowns centered around June and the slow ramp up thereafter. You can pick up the fields as we talked about in September that were slow coming out of shutdown and some of the issues that we had. What I like is as we move over to the right, you can begin to see a little bit of straight line. You can see us doubling production compared to where we were at the low over summer when the shutdowns will be going on. Production in October and November has been around the 215,000 barrels a day mark. And it looks like we're going to have a strong finish to the year. Some of the work that we did in the shutdowns is paying off. We've seen production efficiency around the 90% mark, even briefly above that hovering in that market. And that's right across the operated portfolio. We've had new wells coming on stream, Buzzard Phase 2, EIG on Elgin-Franklin. We've had some good wells drilled at Clair. We're seeing good wells on the operated portfolio and looking for a few more to come on. But this is the sort of graph on the right-hand side that we like to see, stable production. Stable production also means safe and cash generative. Whilst Tolmount has been the source of some frustration, I can report good progress. We've gone to the bottom of the previously reported a tax electrical issues and fixing them. We now expect to have first gas in the first quarter with initial rates around 20,000 BOE per day unchanged. The inspection repair campaign is around 97% complete, nearly finished. We've inspected 2,250 items, and there's around about 100 remaining. We found over 50% faults, although the vast majority of those have been repaired and the other repairs are progressing well. We've got around 150 key repairs to do before we can start full system commissioning. Critical long-lead items that we're worried about are now all delivered offshore. We have the Valaris Norway in place at platform to support future repair work. Although the schedule has been impacted by the number of repairs, COVID and also the weather. Now we're saying first gas is expected in Q1, but we and the team are hopeful that if everything goes according to plan, we'll be producing around the end of January, but this is heavily dependent on the weather. Now, the Tolmount drilling campaign was completed safely. We have 4 wells, development wells completed and available for production at first gas. But as we mentioned in our interim results, the third well encountered a shallower gas water contact than we expected. Whilst initial production rates are going to be around that 20,000 barrel a day mark, they're unchanged. Unfortunately, the current and preliminary estimate of net reserves is around 20 million to 30 million barrels of oil equivalent. That's round about 25% to 50% lower than is sanctioned. On the more positive side, we took the final investment decision on Tolmount East in July, which when that's developed as a single well tieback to toman infrastructure will have robust economics, and we continue to expect first gas in 2023. Elsewhere, we've seen some good drilling results since the COVID slowdown, and Harbour will soon be bringing on a number of new wells into production in the U.K. Obviously, we've had the disappointment on Tolmount, but I've talked to you about that. But we've had some really exciting wells Jade South in the J-Area, which should be coming on in January. We have the East Everest LAD well, which is a tieback to the Everest platform that's going to be coming on soon as well January, I hope. You'll notice quite a few of these opportunities are gas. There's around about 75% of the new production coming on. And for the group is U.K. gas, which is really accretive barrels. You can see, we've been active across the operated by other portfolio. Buzzard Phase 2 has come on stream. We've got the latest EIG, Elgin-Franklin well, working again with both of those operators to see what the future may hold. We've had good appraisal well results on our own fields, both in the U.K., on Talbot in the J-area, which is an area where obviously we spend a lot of capital, but see a lot of potential. And then further afield, we've had great results on the Juno field in Indonesia. 2022 is going to be a busy year across the portfolio. Bob and Stuart will say a little bit more later about what we're doing. But just before I finish on this slide, I talked about how much potential there was in the J-area. A well to watch is the Donate exploration well that we're drilling at the moment on the J-Area. We should have those results in the first quarter, but that has the potential to add a net 50 million barrels on the mid case to Harbour Energy. Really exciting well. On a downside case, it'd be lower volumes but perhaps tied in quicker and benefit in production. So a really interesting well that I look forward to talking to you about in the new year. I've been heard Linda and I speak about the forward hopper and organically keeping the portfolio around the 200,000 a day mark. You can see from this graphic that we're confident we can deliver that as we head into 2022 and through into '23 and '24. You can also see where we've come from we've grown the portfolio over the last few years, what we're going to deliver this year in 2021. And then how we actually intend to get to the '22 guidance that we've told you in the market. We have natural decline, North Sea. If we did nothing in some of the fields, they were decline quite rapidly. So we do a lot of infill work. We do a lot of well work. It's really important to manage that well stock. You can see the impact of the different planned shutdowns from '21 to '22. So we're going to have less planned downtime. And we'd hope with some of the work that we've done, some of things that we've learned, we'll have less unplanned time to. You can see what we're going to add with Tolmount. But over on the right, you can also get a flavor for some of the new wells that are going to be coming on stream through the year. You've heard us talk about the 3 wells we'll be drilling in the Catcher area. We've got production coming on in Southeast Asia through an infill program. We've had Buzzard Phase 2. We're going to see more production levels through next year. And we will be bringing on the LAD well, hopefully, early in the new year. J-Area, we've got really exciting program. Bob will talk a little bit more about that, but we have the Jade South well that's going to be coming on around the year-end, and we'll see production from that and the rest of the program through in 2022. You can see also here we show '23 and '24. We've talked quite widely about sustaining CapEx roundabout $12 a barrel mark for the production we take out of the ground to keep delivering on that portfolio. And this is the first time I think we're actually showing that we believe we can deliver that for the next few years, which I think is a really important takeaway. We have good line of sight to the 200,000 barrel a day mark for the next few years. As you can see from this slide, our OpEx per BOE is broadly flat, and the U.K. business remains below the sector average. That takes a lot of hard work. We've worked over the last few years to deliver that performance and demand is real focused on what's important, spending the right dollars and making sure there isn't waste in the business. And that's been done through COVID, that a lot of society has had enormous problems with, and I'm really proud of the effort that the team has put in. We've also become the integration of the 2 businesses. So there are costs in here that I don't intend or be in the operating base for the long term. You may see improvements on the onshore elements of that cost. It's going to take a little time to deliver. Now over the near term, we're targeting that $15 to $16 per BOE range. And subject to foreign exchange, you may remember the vast majority of our costs in the U.K. and therefore, the group are in sterling was subject to that production performance. I'm confident we're going to deliver at those per BOE ranges that we've discussed. Now we are beginning to see the benefits of the merger and the subsequent integration. We've seen some inflationary headwinds right across the portfolio. That won't be a surprise, anything linked to energy costs, a little bit of steel, some specialist people skills. But at the moment, by working with the supply chain, the long-term relationships that we have, and of course, the materiality that is Harbour's business, we're managing to avoid too much inflationary cost at the moment. That's going to take some time to improve on where we are to deliver tangible cost savings. But we're ready to have completed our office and systems rationalization by the end of '22. And we should have a final state organization in place. The interim reorganization is nearly complete, but it's going to take some time for us to really see benefits. At the moment, we have different operating models in the U.K. business. People do things in different ways. We have a number of logistics firms and supply bases. We use different companies for our ops and maintenance. And it's only as the organizations come together we're going to be able to address those and deliver some of the benefits that I hope to talk about in the future. Some of you will have seen this slide before, or similar. We use it to reiterate the high quality of our portfolio and the sort of things that we're chasing after on a to-do list. You can see our capital spend down the right-hand side. You can see where we're actually putting that money to work and also some of the metrics that we're generating. The majority of our portfolio is delivering returns in excess of 50%, which is a pretty impressive number in my book. Set out here, you can see each of the hubs, the ones that we operate where we have good control, and the non-operated portfolio where we work with other companies and they're lucky to have good alignment and good sight of what's coming next. If you go down on the list, you can see Great Britannia area, AELE, J-Area, our U.K. hubs and Southeast Asian. You can see the non-operated hubs. And you go across, you can see the areas that we focus on. Some of the easy wins where we're doing things to improve plant and efficiency, infill drilling targets. And you'd be pleased to know that we have a great subsurface team working across the portfolio. So we work with outside operated assets to generate drilling opportunities, but obviously, a real focus on our own hubs looking for infill and step-out opportunities, infrastructure-led investments. But that's the nature of the portfolio, the investments that we make. We're not a massive development led company. We're making incremental investment decisions with super high IRRs that you see. We spend a lot of time talking with other companies looking at the area, stepping out from the hubs and delivering an area strategy. Part of that is looking at potential exploration upside and also third-party business. And in some ways, the North Sea has moved on quite some way from 10 years ago. And we, as a company, as Harbour, lead in those initiatives, working really closely with other third-party owners where we would hope to bring their volumes across our platforms by improving our own unit cost materially. And you'll have seen us do that with the Finlaggan field that's come across every time this year. Bob and Stuart will talk a little bit more about some of the opportunities. You can see here the type of work that we're doing, how we focus the team and some of the areas where we'd look to be generating even more value over the next few years. The wheel below shows our full spend and actually under Other includes the integration costs that we're incurring as we go with the news organization. We're always asked about decommissioning, and Alexander will talk about managing the balance sheet and our spend profile. But we just wanted to reiterate here the significant confidence we have in the organization around decommissioning, and the fact we continue to safely execute a large program year in, year out using the same team. We are increasing cost efficiencies and improving well P&A performance year-on-year. We've seen cost savings of over $0.5 billion, largely already delivered with more potential to follow. Key is effective use of technology in the supply chain and ensuring flexibility with the people we work. Early project management is also really important, close engagement and collaboration with the asset and operations teams. What we've also historically done is through drilling and targeted investment with deferred cessation of production. That's happened on a number of fields and that has the added benefit of pushing out decommissioning spend. That, coupled with the confidence we have a real double benefit for Harbour. This slide shows some of our emissions reduction work. With $150 million forecast spend on emission reduction activities in '22, '23, '24 across a variety of projects. They've been reviewed as part of our annual budget process. And that's target to the things like improving process efficiency, power generation and compression upgrades, energy efficiency, plant optimization, finding fugitive emissions, low carbon design for the future. Most of the projects have low-cost and robust returns. But as we head into looking deeply at electrification of the key assets in the North Sea, this is going to need much more. It's going to need collaboration between industry, government and a variety of regulators to make it happen. Harbour has interest in 2 of the 5 potential carbon capture clusters in the U.K. We and our partners and [indiscernible] continue to work with the regulators and government to progress our cluster plans, either as Acorn, a reserve to the potential track 1 process or as V Net Zero, currently in Track 2, but with the potential 2023 FID and then first capture and storage in 2027. Acorn is well placed to help decarbonize Scotland and especially the central industrial belt. But V Net Zero undoubtedly one of the most secure subsurface storage sites and closest to the U.K.'s most dense industrial area. You can see from the map on the bottom of the slide that reinforces the potential of that area for carbon capture and hydrogen. Now we don't yet know the full business model nor the government's ambition, but are excited to be playing such a pivotal role in decarbonizing the U.K., protecting jobs and industry and leveraging our subsurface expertise and the existing infrastructure we have. To finish, we wanted to show you a couple of slides that reinforce both our track record on reserve replacements but also value-accretive acquisitions. Since Harbour did its first deal in 2017, we've more than replaced production through 3 areas, really the drill bit, investing to get more efficient and material growth through low-risk production-led acquisitions. Our strategy is a balance of those pillars, protecting the balance sheet through the cycle. And I'll show more of this track record on the next slide. We continue to invest to convert resource into reserves while maintaining production and generating significant excess cash flow. You can see from this chart how reserves have stayed flat. We have where production has been. And also how we're aiming to convert contingent resource into reserves and indeed bring prospective resource near to our hubs through the chain and it rapidly into production, something that we've been doing around the J-Area and some of the other assets in the U.K. On the bottom chart, you can see our contingent resource position, which doesn't include [ CLA ]. But it does include some of the contingent resource that we acquired with the merger as the 2 companies came together, but from the Premier side. And you'll hear more about the successful appraisal results we've had on Tuna and progress we're making with the Zama potential development in Mexico. We've used this slide or similar before to reinforce what we've delivered over our 2 previous acquisitions, the Shell and ConocoPhillips U.K. portfolios, and also to show you what we aim to deliver in the future. You can see with both deals, we've increased production above our original CPR reports and actively managed OpEx in parallel with that performance. Not only has production been ahead, but OpEx per BOE has been at or below our deal expectations. OpEx is always a balance of cost versus efficiency and can go hand-in-hand with safety. We need to ensure we spend our money wisely to protect our people and performance. You can see on the portfolio we acquired from Shell, we nearly replaced production from a standing start. If you then consider we use the excess equity cash in conservative levels of debt to then acquire the ConocoPhillips U.K. portfolio, we more than replace production, and that's reiterating the message on the previous slide: Invest to convert resource into reserves whilst maintaining production, keeping people safe and generating significant cash flow for the business. I'll just finish by speaking briefly about the integration of the Chrysaor and Premier businesses. As I said earlier, we finished our organizational design and are implementing that design with a new organization fully in place shortly and line of sight to our final state at the end of 2022. By that time, at the end of the year, we intend to have one suite of systems across the U.K. You can see our onshore headcount is already reduced from the pro forma totals, and we expect to see that number reduce even further as we align operating models and particularly back office ways of working and systems. In the first quarter of '22, we'll consolidate to one London office, and plans are already in train to consolidate in Aberdeen, albeit from 3 to 2 offices in the short term. We're seeing potential savings across the supply chain, and those benefits will continue to be delivered over the next 2 years. Thank you. I'll now pass over to Alexander, our CFO, who'll us talk through the financial framework and our approach to capital allocation.

Thank you, Phil, and good morning, and good afternoon, everyone. Like my fellow presenters, I am truly happy to be here presenting at our very first Capital Markets Day for Harbour Energy plc. In my section, I will cover essentially 2 topics: First, I will cover our guidance, 3-year outlook; and secondly, I will convey some thoughts on capital allocation. Linda and Phil have walked you through the strategy and the portfolio of the company. We have a cash-generative portfolio and aim to deliver reliable and predictable cash flows through the cycle, supported by a diverse asset base where no single asset accounts for more than 25% of our cash flow. We have a disciplined approach to hedging, to protect the downside and underpin a minimum revenue stream. We have a strong focus on managing our cost base, leveraging our position as the largest independent producer in the U.K. allows us to realize benefits from economies of scale. We are an operator of around 60% of our annual CapEx spend. As such, we have significant control over timing and allocation of this expenditure. You heard from Linda earlier that our strategy is to create value through acquisition and operation of existing producing assets and not on exploring for new multibillion oil accumulations. As such, our CapEx is dominated by relatively small, low-risk, infrastructure-led drilling projects, which typically target high IRRs and a quick payback. You heard from Phil earlier that over 40% of our P&D CapEx spend next year is aimed at projects which deliver a return in excess of 50% and have a breakeven of less than $30 per barrel. The majority of our CapEx is allocated towards maximizing the value of our existing production base by investing in our assets to increase uptime, improve recovery and add reserves, thereby extending fee life and deferring decommissioning. We're operator of most of our decommissioning projects and have significant in-house decommissioning expertise as a result of the Conoco acquisition. Now I will try to put some more numbers and details behind our financial outlook for both next year and the upcoming 3-year period. So let me start at the top with our revenues. We a fairly balanced portfolio of oil and gas and a small proportion of NGLs. Over the next couple of years, we expect this mix to remain balanced, but with a relative increase of gas. We are fortunate to have Stasco, or Shell Trading, help us market a significant portion of our hydrocarbons. Although after the merger earlier this year, we have marketing -- we are marketing some of our products in-house. We do have a mix of grades with some achieve a premium to Brent and some at discounts. On balance, we are probably at Brent pricing, maybe just slightly better. Repaying the $400 million Shell junior facility expected to be value accretive overall by strengthening our marketing position and providing us with more flexibility for any new volumes added. We will still enjoy the support of Shell Trading in the short term and then assess our marketing arrangement for the longer term. Today, we aim to hedge through the full commodity price cycle, and we're hedging a significant part of our production in compliance with hedging requirements set out in the RBL, or reserve-based lending facility. Through a regular and disciplined hedging program, we look to manage commodity price risk and underpin the availability of debt. Here, we have illustrated just exactly how much we have hedged in the past 2 years and in the upcoming 3-year periods. This conservative hedging profile has served us very well in the past, most notably during the low commodity price environment in 2020. While today, we have an unrealized loss position for 2022 to 2024 hedges, as both oil and natural gas prices are higher than our hedged prices. For 2022, we've hedged around 60% of our total production; for 2023, around 40%; and finally, for 2024, we've hedged just over 10%. When it comes to our hedging policy, we are reviewing the future policy. But we have, just this week, received majority lender approval to a number of amendments to the RBL, including a request to fully remove the year 3 minimum hedging requirement of 30%. We still have the year 1 and the year 2 minimum requirements and the same maximum requirements. So after revenues, hedging, let's move on to expenditures, starting with the operating costs. Here, we are showing the buildup of our cost base for operating expenses. OpEx is expected to stay fairly flat over the next 3 years, staying in a range around $15 to $16 per BOE. Total OpEx is expected to be higher in 2022 compared to corresponding 2021 numbers on a reported basis. As Tolmount is coming on stream, this increases total expenditures, but the field contributes lower OpEx per BOE. The CapEx element on Tolmount is classified as lease costs, and I will get back to total lease costs in a couple of minutes. OpEx per BOE varies across our portfolio. To the right, we've included a split of total OpEx across our assets for the next 3 years. For 2022 and onwards, we have included budgeted integration costs and operating costs and in the OpEx per BOE metric. We've also included CCS expenditures of $35 million for 2022. Now as mentioned by Phil, OpEx is sensitive to changes in the sterling U.S. dollar FX rate since a lot of our expenditures are in sterling. These estimates are based on FX rate of 1.35, and the strengthening in sterling will then increase our OpEx. Moving on to CapEx then. Phil just spoke about our organic investment opportunities. Spending on our capital project can be a bit lumpy depending on the mix of projects and fields. For 2022, we expect production and development CapEx of around $800 million, and exploration and appraisal of an additional $200 million. Most of the 2022 P&D spend is in the U.K., with international only accounting for around $100 million. We expect 50% of the spending next year to be concentrated around 5 key operator hubs, with J-Area being the single most active hub, accounting for approximately 25% of the spending. You will get to see some more of J-Area in part 2 of this Capital Markets Day. E&A is a mix of activities and wells across the U.K., Norway, Mexico and Indonesia. We're planning 1 to 2 wells in the U.K. and 2 to 3 wells in Norway. In the international BU, we have the 2 commitment wells, Wahoo and Pike in Mexico. And then we are excited about the Timpan-1 well in the Andaman Sea and Indonesia. Looking ahead to 2023 and 2024, we have less visibility, but we do expect CapEx to remain between $800 million and $900 million. Today, we're estimating spending to be a little lower in 2023, but this will depend on both follow-up work on any exploration success in Indonesia, in particular, and timing of capital projects. The increase you can see in 2024 spend is mainly a result of Tuna in Indonesia and Zama in Mexico kicking off. However, both these projects, they remain subject to final investment decisions being taken. Next, let's move on to decommissioning spend. Managing and optimizing our decommissioning program is very important to us. As illustrated at the bottom of this slide, we see a fairly stable activity level over the next couple of years for our decommissioning team at around $300 million in pretax spend. Beyond this, we see the spending level trending downwards. We also expect a significant part of the decommission activities to take place after 2035 for several of our fields. At the half year mark, we booked decommissioning liabilities of $5.7 billion. Now it's important to note that this is a pretax number and it's estimated using a risk-free rate of return. Applying a higher discount rate like 10% and looking at post-tax numbers, will both materially adjust this liability. Now when it comes to taxes, we paid around $250 million now in 2021 and we paid $190 million in 2020. As a result of prior year's investments, Harbour currently has a U.K. tax loss position of approximately $4 billion. When looking ahead, we estimate lower group tax cash payments in the next few years through the utilization of those losses over time. But this will be subject to the group maintaining its profitability and CapEx investment profiles during this period. We still expect to pay taxes in the U.K. and internationally, while exploration activities in Norway reduced overall cash taxes with the refund received. For 2022, the most significant cash tax payment will be in January as we will then pay the third and last payment on account installment for the fiscal year 2021. Then finally, in this Part 1 guidance section, let's cover the capital structure. Today, our capital structure is quite straightforward. We have secured bank facility and one unsecured bond. The $4.5 billion RBL facility remains the cornerstone of our capital structure. We have a really good group of banks in the syndicate that remain supportive to the company. There are no significant near-term debt repayments on this facility. Still, we believe it is sensible to diversify the capital sources of the company. Therefore, we decided to obtain a public credit ratings this and subsequently issue our debut bond in the international capital markets. In a volatile market, we raised $500 million for a 5.5% coupon. For 2022, we estimate an average cost of debt below 5%. As illustrated here, we expect interest costs to decline as stories under the RBL reduce. Three of our assets, Catcher, Chim Sao and now Tolmount from first gas in early 2022, have lease costs or tariffs associated with them as a result of how the developments were originally funded. On the bottom right of this slide, we're illustrating how we expect these costs to develop over the next 3 years. So let's transition from guidance and spending to capital allocation. This is how we think about our financial framework. You will probably recognize the operational inputs on the left here. It all starts with being a responsible, safe operator, managing costs and driving performance. We are selectively reinvesting in our existing assets, and at the same time, we're able to do mergers and acquisitions that create value. Lastly, we have robust risk management policies and procedures to help us identify and respond to adverse scenarios. This gives us strong, predictable operating cash flows. When it comes to capital allocation, we're aiming to balance 3 equally important priorities: firstly, safeguard our balance sheet; secondly, make sure that we have a diversified and robust portfolio of assets; and thirdly, return value to our shareholders. I will walk through these 3 capital allocation principles in turn, starting with principle #1, safeguarding our already strong balance sheet. As an oil and gas company in 2021, soon 2022, I believe in a conservative approach to the balance sheet, making sure we never run out of liquidity. Our $4.5 billion RBL has a $1.25 billion letters of credit sublimit and a borrowing base currently set at $3.3 billion. This borrowing base will be redetermined at June 30 next year. As I mentioned a couple of minutes ago, we now have a $500 million bond outstanding that is due in October 2026, and it's callable after 2 years. After recently repaying the $400 million junior Shell facility, this bond issuance has helped us increase liquidity to well above $1 billion at year-end. I have already talked about the hedging policy that we have in place. This policy ensures predictability in revenues and our ability to service our debt. Well, Phil and I had talked about our CapEx spend, and I will get back to this in a minute. Although the company has completed a series of mergers and acquisitions since 2017 and increased the debt levels in the process, net leverage has been held relatively low -- at relatively low levels at around 1x. Since the closing of the merger in Q1 this year, we've seen a significant deleveraging. We had net debt of $2.9 billion on March 31, down to $2.6 billion at June 30. We now expect net debt to end the year in the $2.3 billion to $2.4 billion range. These net debt numbers do not include any amortized fees, which would have reduced the net debt number further. This would mean a net leverage at around 1x at year-end. Our second capital allocation principle is to reinvest in our portfolio, making sure we capture the high return opportunities that exist. For projects to make it into our business plans, certain metrics and investment hurdles must be met. We are still very much in the process of going through the entire portfolio and mapping all opportunities, but we do see a lot of good projects with attractive economics. Here, we have outlined some of the metrics we are targeting in order for projects to be sanctioned and get funds allocated. Projects in the combined company will continue to compete for capital, making sure we prioritize the best projects in the portfolio. In her introduction, Linda touched upon the M&A landscape. We will continue to assess possible M&A opportunities that fit our skill sets and portfolio. We will be diligent and carefully assess implications on the balance sheet when looking at such inorganic growth opportunities. At the same time, we will assess investment opportunities in CCS and other initiatives to reduce emissions. When it comes to returning value to shareholders, we are happy to announce today the introduction of a dividend payment commencing next year. There are, of course, a lot of different things to consider when assessing how to best return value creation to shareholders. In addition to assessing the 2 aforementioned capital allocation principles, we believe an initial distribution should be affordable from free cash flow. It should be sustainable through the cycle, and at the same time, it should be predictable and clearly defined. For Harbour Energy, we believe an initial set amount of $200 million meets these targets and strikes a good balance. This is a meaningful level set out initially, and then we will review this level again annually as we deliver on the strategy of the company. This dividend is subject to approval at the Annual General Meeting in the second quarter of 2022. The intention is to pay out $100 million in the second quarter after AGM approval and then another $100 million in the fourth quarter. On the next slide, we have illustrated our 3-year capital allocation outlook. Starting with post-tax cash flow and deducting decommissioning expenditures estimated at 15% of cash flows, we are then looking at capital expenditures to E&A and P&D of around 50%. This leaves us with around 1/3 in free cash flow to pay down debt and to pay dividends. We believe it's possible to balance reinvestments in our existing portfolio at attractive rates of return and shareholder distributions with a continued strong balance sheet. If we assume the initial dividend amount from the previous page is distributed annually, well, then we project that net debt will continue to drop every year. And finally, moving to the summary of our guidance for 2022. Now before we talk about next year's guidance, let's take -- start on where we see 2021 ending. On production, we expect to end the year in the middle of the range. On operating costs, we should end at around $16 per BOE. We guided for total CapEx of $1.1 billion, and we expect to spend a little less than this by December 31, likely around $75 million less, as some of these activities were deferred into 2022. Then looking forward to 2022, I think we have an exciting year ahead of us. We are guiding on 4 items. Production. We're setting a range of 195,000 to 210,000 barrels of oil equivalents per day, where the exact timing of Tolmount start-up is the largest uncertainty. We expect OpEx to be in the range of $15 to $16 per BOE. CapEx is estimated at $1 billion. And we estimate abex to come in at around $300 million on a pretax basis. And as mentioned earlier, we also expect to initiate a dividend next year with equal installments in the second and the fourth quarters of $100 million. With this, I will pass it back to Linda to wrap up this first section of the Capital Markets Day. Thank you.

Thanks, Alexander. It's been a long session but I hope informative. I'm going to end it here with a reminder of our investment proposition. I think you've seen evidence around all 6 of these elements through the course of the presentation so far. And you'll hear more about our portfolio and assets from the guys and gals actually responsible for running them in part 2. But we thought this would be a good point to stop and take some questions. So we'll turn now to our live session, coming to you from our offices in London.

Hello. Welcome. So now we're coming to you live from London. I'm here with Alexander and Phil Kirk, and we're happy to have this opportunity actually to be with you live. I mean honestly, we've received some feedback from people who've already watched the video saying that maybe we could have smiled a bit more or maybe waved or a bit stilted. Sorry about that. It's a good thing none of us aspire to be TV presenters, but we will try our best during the Q&A session to show you how genuinely excited we all are about the company and its prospects for the future. So with that, let's open it up for questions.

[Operator Instructions] Our first question comes from Nathan Piper of Investec.

Thanks very much for the presentation. I've got a couple of questions just at this stage, if that's okay. First of all, around development of your 2C resources. It's great that you've given a sort of line of sight on the 200,000 barrels a day over the next couple of years. I don't want to put this the wrong way, but is that it? Would we expect to see this portfolio decline quite sharply after that? Or could the existing 2C resources do more? Is there potential to extend that plateau further? Or effectively, do you need to have some either new discoveries at the [ North there ] or appraisal success to push out this 200,000 barrel a day base case? That's my first question. Maybe ask you about that first before we go to the next one.

Great. Nathan, thank you. I'll take that question. So first, I'll remind you that in our 2P resources, our [ over PR ] reserves life is somewhere between 6 and 7. So we don't have to completely just rely on the 2C to go beyond 3 years of production. And then second, in the 2C resource base, some of the bigger things that we have are things like Zama and Tuna. And both of those are projects were in our CapEx forecast for year 3 2024. We actually have quite a material amount of forecast spend for both of those projects in that year. So that's part of the spend that you see, but not any of the production because, of course, those projects don't start producing until after that time. So yes, it's possible. We can continue to maintain production at a level of 200,000 barrels a day for longer than the 3 years. Certainly, we have the resources and reserves to be able to do that. I think at this point in time, though, we're just giving a line of sight over -- for the next 3 years, given the stage we're at, only 8 months as a company and still coming to grips with some of the details in our actual schedule of investment.

That makes sense. That's also reassuring. Two other quicker questions, hopefully, or straightforward. On a CO2 per barrel basis, you've given us lots of guidance over the next couple of years. Can you give us a kind of a direction of travel on that [ out to ] the same sort of time line towards 2024? And then the other quicker question, so far, not too much in terms of cost pressures from oilfield services. But how do you see the outlook, particularly in the U.K. North Sea as you go into the next couple of years? It'd be interesting to get a bit more color on that, please.

Yes. Thank you. Let me say a little bit about our CO2 intensity, and then Phil can talk about inflation because he's right smack in the middle of all of that in the U.K. So our emissions per barrel are kind of in the mid-20s, not exactly sure where we're going to end up this year. And keep in mind that we -- everyone measures them a little bit differently. So we're looking at Scope 1, Scope 2, operated and nonoperated. And that's probably we're around average in the U.K., maybe a little bit better than that. Does it mean that, that's satisfactory for us? And we listed -- both Phil and I talked a lot about all the things we're doing to try to drive that down over time. It's hard work. A lot of the low-hanging fruit has been done 2 or 3 years ago, in particular in the U.K. But as you saw in, I think, one of my charts, we have some interesting and more ambitious ideas where we can try to offset those in a variety of ways, and we'll continue to work towards that. But let me let Phil talk about the inflation question because it's one we get a lot.

Thank you, Linda. And I think our emissions actually include mobile units, which some people don't include. So there is another difference. We've obviously stepped up activity in '21 with less production. In terms of inflation, that's a really interesting question we've been asked a lot recently. Where we're mainly seeing an impact at the moment with shortage of resources in lead times, delivery times and scheduling. We're quite a large player in the basin. And so we tend to have close relationships with the supply chain. As yet, we haven't seen a lot of inflationary pressures -- some, but not as much as one would anecdotally expect that may come, but maybe because of our position and our good relationships with their core business in a way. We do see where people have shut down manufacturing facilities around the world that there is pressure on lead times. And undoubtedly, in times of more activity, then there will be more challenge to get the right resource at the right time. But traditionally, we do look after our supply chain, as you all know. So we would hope they would stand with us.

The next question is from Chris Wheaton from Stifel.

Two questions, if I may, please. Firstly, to Phil, Slide 36, you're talking about OpEx, and it looks like you're planning to get that down quite significantly '23 and then '24 and hold it there versus '22. And I wondered if you could talk about the drivers. There's some -- it sounds like there's some -- ones related to the Premier merger, but it feels like there's got to be more than that to get that level of OpEx down that you're talking about. And then I have a second question to Alexander on the financial strategy, but perhaps I should stop there first.

Thank you. Thank you, Chris. '22, we're -- on a per BOE, we're obviously driven as well by production levels. But if we set that aside in previous years and in '22, we do have integration costs. We do have other one-off costs feeding through. Simplistically, I have -- we have a lot more offices than we would like, a lot more locations, a lot more systems, a lot more ways of working. And a lot of effort of the integration as we bring people together is to standardize on the way we work. And that's not just how we pay invoices and financial systems. That's easy to understand. But that's in maintenance regimes, operating models offshore, the contractor base and supply base that we use. And we have multiple suppliers for all sorts of services, and that takes some time, particularly with COVID and particularly as we just bring in the organization together. So I think we're being conservatively realistic about where we're looking at future projections for OpEx. And I -- we're already beginning to rationalize offices. Our systems work is going well. Despite COVID and all the other challenges everybody is facing, seem working really well. So I think through '22 and into '23, you're going to see us deliver more efficiency and more performance on the operating cost side. Hopefully, that helped, Chris.

That's great. Can I have a follow-up and ask what you're assuming for your uptime over that period you talked about on Slide 36? Is there material change in uptime and therefore, the delivery of production from the portfolio?

Is there material change? We had some disappointing performance through 2021, perhaps with COVID and some other excuses. But I won't look for excuses. You've seen the level of performance that we've managed to put in for the last few months, which is stepping up from September that we're all really pleased with. And that, as I think I said on the video -- our operated assets have been over 90%, and there's a portfolio around 90%, which is really good, is ahead of the U.K. traditional average. So we have made slightly less bullish assumptions that, that performance will be maintained for throughout '22 and '23. But where we think is realistic -- we do hold ourselves to high standards. So traditionally, a lot of the platforms would be towards the top quarter, but we've been realistic about our estimates.

That's brilliant. I mean -- my last question to Alexander, if I may. Your presentation, Alexander, could you talk about the -- where you think the balance sheet envelope should be and the leverage that the company should be at current commodity pricing? Because it's quite clear that you think while you want to stay below 1x net debt to EBITDAX, that's going to flex with commodity prices. And why therefore, you might want to be below 1x at the moment. I'm just interested if that's the case. And if so, how much below 1x net debt to EBITDAX do you think you ought to be if your price is $80 and perhaps more pertinently, we're seeing gas prices [ but we are on the screen ] at the moment.

Yes. No, thanks, Chris. And no, as you know, it's a complex calculation that is not just commodity prices, it's -- well, it's hedging, it's spending levels. There's many things that goes into that. And I think what we've said is that just through the cycle and when we think about possible acquisitions and the things that we've seen in the past, we've said that it should be below 1.5x. But then I also think when -- if you have commodity prices at $80, so you have 200p, well, it's a good sensible thing to do to pay down debt in that period when commodity prices are high. So now going from a little below 1.5x at the closing of the transaction with Premier and Chrysaor now down to closer to 1x, I think that's in line with what we've said and strategy to delever post such acquisitions. So being below 1x when oil prices are high, yes, that feels comfortable. But again, it's just going to be a capital allocation decision on how much money do we want to spend in new projects, paying down debt and then introducing the dividend.

[Operator Instructions] The next question is from Werner Riding from Peel Hunt.

I've got a question similar to Nathan's earlier, I suppose. Linda, you made it clear that you won't carry out any exploration that is an ILX- or PLX-led. And so I'm just interested to hear how that fits with us providing line of sight on material organic resource and ultimately, production growth outside of M&A so that you can more than just fight declines. Or should we think about Harbour's future growth as likely to come almost entirely from M&A?

It goes to the heart of our strategy and to capital allocation and almost everything else we talked about today. We believe our existing resource base, the one that has been formed through the combination of the 3 transactions we've completed over the last few years, we believe this resource base is sufficient to help us continue to reinvest in it, maintain production levels at around 200,000 barrels a day and generate material free cash flow and to do that for the next 3 years. So for the near term, maybe longer, too early to say, and that's what we tried to lay out today. Beyond that, we've said we want to diversify. We have most of our production today in the U.K. It's great. We love our portfolio there. It's serving us well. But over the very long term, we're already the largest producer in the region. It's a bit hard to assume that we can live on that region alone for many, many years and maintain production levels at a material place. So we do have the aim to diversify, to establish a material base of production in another region and likely to do that through M&A and not by exploring in new countries where we don't have an existing presence. And why do I say that? I think it's a less risky route for us. We focus on buying diverse portfolios of cash flow, of conventional-producing, cash flow-positive assets. There are sellers of those assets out there, we believe, that the opportunity set is going to be pretty rich for us in the coming years. And we just believe that's a lower risk way for us to grow, and we have a proven track record doing it that way as opposed to exploring for new oil and gas deposits that may take 10 years or longer to pay out.

Okay. Got it. And in terms of a new potential hub geography outside of core areas in the U.K., when thinking internationally, that sort of leads me to think sort of Asia Pacific, I think, as I've heard you talk about before. You've also built a license -- a growing license position in Norway but haven't really yet seemed to build comparable or a good size production base there. Could size M&A happen in Norway as well?

Yes. We look in a number of regions, and this is a question we oftentimes again. So Norway is a logical place for us to look because it's across the fence from our main heart of production today. The challenge with it is -- well, the good news is high-quality assets, costs can be relatively low, emissions per barrel can be relatively low, relatively long-life portfolios in some cases. The challenge is there are some really strong regional players and a couple of other companies who would love to have higher quality and more assets in that region as well. So we would expect there to be competition. And that's not a dynamic that we tend to like if we have other options. So that's Norway. We like it, may be hard to really create value if there's a strong competitive dynamic. Southeast Asia is another place. It's a logical place for us to look. We have good production today in both Vietnam and Indonesia. There is strong energy demand for a long time to come, in particular, for natural gas in the region. So yes, another logical place for us to look, conventional-producing assets. On the other hand, the challenge is there, you have to build a material portfolio in the region by being in multiple countries. That can be a little bit less efficient. And there are still today some pretty strong national oil companies and 1 or 2 regional players who can provide competition. And so that makes it sometimes maybe a little bit harder for us to create the kind of value we'd like to create and we aim to create through M&A. So where else do we look? U.S. Gulf of Mexico is kind of a logical place for us to look, and I've said that before. Conventional offshore production like we have in the North Sea, most major oil companies still producing there with relatively large portfolios. What they will do over time with those portfolios, TBD. But given their strategic shift and how they're allocating capital away from the upstream, that may present an opportunity for us in that particular region. So those -- just to give a bit of color around 3 of the regions that might be of interest to us. Hope that's helpful, Werner.

The next question comes from Matt Smith of Bank of America.

Thanks for the presentation so far. A couple of questions I had would, first of all, be around the production guidance for 2022 and if the sort of first plans, piecing -- putting the pieces together, if this has looked sort of a slightly conservative outlook if you think about the production performance you've had towards the end of the year. You've listed sort of around about 40,000 barrels of sort of new projects coming up online as well for the year. I guess if I look to Slide 23 and you have that quite useful sort of waterfall chart, I'm wondering if sort of the reason for this conservatism, I think that's the right word, is because the natural decline portion perhaps looks larger than the sort of 10% to 15% that I think was referenced before. And I'm wondering if that is what's playing into the sort of higher CapEx number going forward versus the current year. So that would be my first question, put a bit of color around that if that's okay. And then the second question would be around the dividend policy that you've announced today. I just wondered whether the Board discussed sort of the option of a buyback and why you sort of favored the dividend and if the buyback could become part of discussions going forward, please.

Yes. Thanks, Matt. I'll turn it to Phil to help with the first one, and I'll take the second one. But on the first question, just remember, the 2 15 we produced in October and November, that's after all the maintenance season. And so we had really strong reliability and availability during those 2 months, which over the course of a full year, won't be the case. But let me let Phil talk about natural decline in the guidance for next year.

Thank you, Linda. And it's a good question, and Linda nearly stole my thunder. So if you look at that decline, you should think about it versus the end of the year run rate that we've given, and then it is much more in line with what I've said. Two key things in there that you should also think about, I've got a really -- we have a really great well on Britannia -- in the Britannia area, one of the Callanish wells. It's producing fantastically. At some point in time with those reservoirs, that well will decline rapidly from about 8,000 a day to a couple of thousand a day and then go on for a long time. That is baked into what you see here. And you also know that Catcher has been producing really well. At some point in time, we're going to get an increasing water cuts on Catcher. Some of that water cut is also based into this decline. We've not necessarily seen it yet. That's not -- needing to -- needed to flag anything, but that is part of how we're looking at decline through '22. There's those 2 key numbers in that large orange block that you can see. And we've always said, which I'll remind, at the moment, everything is going really well, fingers crossed, touch wood. But we have a portfolio. There'll be some months when everything is working really well and some months where we have 2 or 3 problems and production is hit. And so we have to take a view as to where we think the range is, and we're very happy with this level of guidance.

Yes. Great. Matt, back on your question about buybacks. Yes, of course, the Board discussed a whole range of things around fixed, variable, progressive, buybacks, special dividends, et cetera, as we were debating and discussing what to do for our first dividend at Harbour Energy. And the decision this time around was let's start out with something simple. Let's make sure that it is sustainable. So let's stress test it over a really wide range of commodity prices and different economic worldview scenarios so that we introduce something that we have a high degree of confidence in, which led us to a very simple policy of $200 million a year. Going forward, we said the Board will review the policy regularly or annually like all Boards do. We do have quite a bit of cash flow this year, $500 million to $600 million. We say we're expecting a current forward curve, commodity prices to generate a lot more than that next year. So should all these things play out, depending on what else happens around the world, what's happening with commodity prices, we'll have another good discussion, I'm sure, next year about exactly what to do. Topic of buybacks, for us, this year, it's a little bit of an odd discussion because we have had so many of our shares under lockup for a good part of the year. We still have 37% of the shares under lockup until April 1 of next year, and that comes into our thinking around does it make sense to introduce buybacks into the equation when we have a lot of shares under lockup and a lot of investors talking about wanting increased liquidity in the share price. So that's just another dimension for us to think about.

Nothing further in the queue at present. [Operator Instructions] We have no further questions at this time. So I'll hand back to Linda.

Great. Well, thank you for the questions. As I mentioned on the video, we have divided the presentations up into 2 parts. So this was kind of corporate-level part, a high-level view. Starting at 2:00 U.K. time, the videos for the part 2 presentation will start. So this is mainly Bob Fennell, Stuart Wheaton. They're going to go through asset by asset, all of our key producing fields and talk a lot about the opportunities. So they'll help answer some of the questions you've already asked today about our resource base. So I think you'll find it interesting. Then we have a couple of videos actually coming from location from some of the people who are a bit closer to the coal phase that I think you'll enjoy as well. Then we'll come back here. We'll have Stuart and Bob Fennell with us, and Phil and Alexander will be with me as well, and we will have a second round of Q&A at that point in time. And that will happen around 2:30 or 2:35 U.K. time. So we hope to see you back then. Thank you. [Break]

Welcome back from the break and to part 2 of our Capital Markets Day event. In this session, you'll see presentations from Stuart Wheaton, who will talk about our producing assets and exciting growth opportunities in Southeast Asia and Mexico. And you'll see Bob Fennell, who, because of COVID restrictions, had to complete his filming remotely in Aberdeen. He'll share insights about our U.K. production, including a video from some of our asset leaders. And I'll turn it straight over to Bob now to introduce himself and to get us started.

Thank you, Linda. Good afternoon. Before I run through our U.K. assets, I'd like to tell you a little about my experience. I'm a graduate petroleum engineer and joined BP in the mid-80s as a drilling engineer. I spent the first 20 years of my career in various drilling completions roles globally, including Elgin Franklin and Buzzard, which I'll come back to later. The last 15 years has been spent in the type of role I'm in now, looking after drilling and production operations and projects. I've worked in most basins around the world. I've lived in France, Norway, Yemen, Canada and even in [ Great Amethyst. ] After the assets I'm about to discuss, I've spent time offshore on 10 of the installations. The U.K. portfolio is a diversified asset base with a high level of operational control either directly or indirectly via relationships and asset knowledge, diversified in terms of asset spread, geology, oil/gas mix, export routes and a range of operators and partners, which is great for knowledge share. Over 90% of Harbour's production is covered in this section, and our operated assets are currently running at over 90% production efficiency. I'm going to pick out a couple of key messages from each asset. But firstly, I'd like to highlight 4 operational themes, which hold true across the portfolio. Firstly, protect the base. Our focus is on major accident hazard prevention. It's about people, such as workforce engagement. It's about process, operational integrity. And it's about plant, looking after asset integrity and maintenance backlog. Secondly, a balanced -- the desire for high production efficiency and reliability with cost management and be proportionate to the life cycle stage of the asset. In other words, we need to invest wisely. Thirdly, reduction of emissions. The first way to reduce emissions is to have a smooth operation. Secondly, we need to change operating paradigms if necessary and work on a single train rather than dual trains. Thirdly, the introduction of new technology and finally, heavy investment such as electrification, where it makes sense. The fourth area is looking at the upside. So we have dedicated subsurface teams within the hubs. We invest in seismic and tools. We maximize the use of existing infrastructure, and we have a very experienced well delivery team, able to tackle the more challenging targets cost effectively. So moving on to Greater Britannia Area. Greater Britannia Area comprises of the Britannia field and a series of fields called the Brit sets, and it is our largest producer with sector-leading production efficiency and reliability. The main platform has 3-phase separation; gas dehydration and processing and compression. The Bridge Linked Platform is the access route for the 4 subsea tiebacks. Liquid export is via the Forties Pipeline System and gas, via SAGE. And here to tell you more about GBA is Scott Barr, our Senior Vice President for the Operated Assets, who is coming to you from Aberdeen Harbour.

Hi. I'm Scott Barr, and I've been managing the Greater Britannia Area for the last 6 years. The Greater Britannia Area, or GBA, is the largest producer at over 38,000 barrels a day net to harbor and generates significant free cash flow, which is to continue well into the next decade. GBA's strong is supported by impressive uptime of over [ 95%. ] Through targeted utilization of digitizing our operating surveillance, we have had many success cases of predicting equipment issues and making a timely intervention with what would otherwise have resulted in extended periods of downtime. GBA is also the lowest unitized greenhouse gas emitter, supported by the fact that we have moved to single train operations through plant optimization of our gas processing trains. But what does the future hold for GBA? Well, there are 3 things I'm particularly excited about. Firstly, a significant amount of near-term, short-cycle value creation. It's to be had from optimizing the current well stock, and we have an active well intervention program to achieve that. Secondly, there is a huge amount of remaining potential within the area to get after, including at Callanish, Brodgar and Leverett. These infill opportunities are all close to existing infrastructure. We had success at Callanish earlier this year with the F5 well, which we brought on stream under budget and has delivered to date ahead of predictions. At Brodgar, we are pursuing rerouting the field via our late-life compression module to bring some of the shut-in wells back on stream. The economics of this project are extremely attractive with an IRR in excess of 100% and a development cost of less than $5 per barrel equivalent. Leverett is a discovered field spread across 3 license areas, and we are progressing the significant opportunity with our JV partners in a collaborative, one-team approach. All of these could result in a material step-up in production from GBA in the next few years. And thirdly, there are also multiple [ neothal ] prospects MacLeod, Shirley, [ Britannia Midfield ] and [ Beaumont, ] which our exploration teams are working hard to high grade and mature. In summary, we continue to optimize production from our high-value hope and have an active infill well program, significant inventory of near-field prospects, leads and third-party opportunities to pursue.

Thank you, Scott. So to reiterate, there is good upside potential in the area, which has been refreshed since Harbour took over this asset, and this includes both equity production and third-party business as exemplified by Finlaggan, a 2-well tieback, which has recently been tied into Britannia. So in summary for Britannia, there are 3 areas of upside, intervention on existing well stock, near-field developments and infrastructure-led exploration. Moving on to J-Area. J-Area is a material growth hub with significant multi-geological horizon opportunities from the Paleocene to the Triassic. It comprises of 4 fields, Judy, Jasmine, Jade and Joanne, with Judy as a central processing facility. Jade is a normally unmanned installation. Joanne is a subsea tieback. Jasmine is currently manned, but we're looking at the possibility of controlling Jasmine from Judy and significantly reducing manning and costs. Liquid offtake is via Norpipe and gas, via a CATS. Joining us from the Judy platform is Gatsbyd Forsyth, our VP for the J-Area, to tell us more about it.

Hello. I'm Gatsbyd Forsyth. I'm the VP for the J-Area hub. 2021 has been an exciting year for all of those involved with J-Area. First of all, we have delivered a strong safety performance despite the challenges COVID has given us and continued to maintain strong barriers to ensure we protect our people. Second, we continue to see good reliability from J-Area. And here today, we are running at over 95% operating efficiency. That's a result of past investments in the assets aimed at eliminating single-point failures, maintaining system redundancy and investing in our people. There has been considerable drilling activity on J-Area and now with a second drilling stream running since July. This has enabled us to continue our development and infill campaign to boost near-term production and cash flows but also to drill out some very exciting exploration and appraisal opportunities in the [ hub area. ] For example, as I speak, we are in the middle of an intervention campaign on Jasmine, which has already provided us with production uplift. There is also extensive activity underway on the Jade platform in preparation for the tie-in of the successful Jade South well. Jade South was targeting a previously untested part of the Jade field, and it's the longest well drilled in J-Area thus far and will contribute significantly for the J-Area production next year. Lastly, we furthered the high-input Dunnottar well in October. The well targets a Triassic prospect to the east of Judy with a P50-P10 of circa 75 million to 150 million BOE gross resource and has a commercial chance of success of around 40%. We are also very focused on producing our oil and gas with as low CO2 emissions as possible and to play our part in helping Harbour Energy reach its net-zero commitment by 2035. For J-Area, in particular, our full year forecast in 2021 is already delivering a 15% reduction from our baseline targets. However, the biggest opportunity to reduce emissions is through electrification of J-Area. And this is something that we are actively looking into. In conclusion, I'm very excited about the future of J-Area, which is set to continue to generate a strong cash flow well into the next decade.

Thank you, Gatsbyd. So as you just heard, J-Area has a wealth of opportunity at multiple geological horizons. It's just a question of prioritization and what to drill first. Moving to Catcher. The Catcher Area has demonstrated subsurface outperformance and as much further prospectivity. It is our second largest producer and came to the portfolio through the Premier deal. Future prospects are numerous and albeit modest, they are high value and can be unlocked through a combination of subsurface work plus an improved cost basis in the areas of the FPSO, drilling costs and production chemicals. The FPSO is leased for BW Offshore and has full processing for the 3 fields, which are Capture, Varadero and Burgman. Oil offtake is via shuttle tanker, and gas goes to [ subsurface ] [indiscernible]. We have a heavy-duty jack-up arriving early in the new year for a 3-wells campaign, drilling Catcher North, Laverda and Burgman Far East. And we have just started a gas reinjection program, which is proving very effective for reservoir management and is expected to result in further reserve additions. The FPSO processing plant has had some challenges with calcium naphthenate precipitation. But more recently, we have seen a material improvement in reliability and uptime from better understanding the production chemistry. There is potential for further improvements in production rates through top size debottlenecking, and this is being engineered between Harbour and BW Offshore. So Catcher is a great asset with much future potential, if managed correctly. Moving on to AELE. The AELE Hub comprises of Armada, Everest, Lomond and Erskine, which are late-life assets. So the focus here is on late life asset optimization to extend life. Armada is fully integrated -- is a fully integrated platform of late '90s vintage and exports back to the CATS tower at North Everest. North Everest and Lomond are early '90s vintage and, in effect, sister platforms. Lomond controls the Erskine, normally unmanned installation, which is a high-pressure, high-temperature wellhead tower with limited facilities, and exports to CATS tower also. North Everest and CATS are at the center of the hub and again, a fully integrated platform. Liquid offtake is via Forties Pipeline System and gas, via CATS. So what does late life asset optimization really mean? And how does it differ from the other 3 hubs? Cost management here is more important, but equally important is the need to keep up with asset integrity work and maintenance backlog to keep the infrastructure optionality and defer decommission where it makes sense. For example, Armada has been deferred from 2018 to currently around about 2025 since Harbour took on these assets. The LAD well on East Everest is close to coming online, and there still is potential in the area with the exciting Mickledore prospect. Modest investments in workforce engagement has materially improved operating efficiencies. For example, Lomond and Erskine have production efficiencies less than 50% and now competes in the high 80s. And the need to better understand asset integrity has resulted in the adoption of some interesting new technologies. For example, the use of drones, new inspection techniques and all the platforms now have digital twins, which allows detailed engineering to be done onshore without the need of physically going offshore and surveying. And now moving on to our nonoperated ventures, where we have dedicated subsurface teams to ensure we have an independent view on investment decisions. We also pull on our operated depth to ensure a two-way transfer of knowledge. So starting on the West of Shetlands. West of Shetlands is a very long-life production hub with Clair still under development. Clair Ridge has just drilled well #14 out of 36 planned. Clair Phase 1 will go back to drilling at the end of 2022 with a 4-wells campaign, and Schiehallion is starting planning of a 4-wells campaign starting in 2023. Clair and Schiehallion are both operated by BP. Some good production efficiency improvements have happened. For example, on Clair Phase 1, we've seen material increase in reliability since the main wireline pumps were replaced, but we do see further room for improvement in not only production efficiency, but also the cost base. We are working with the partnerships to support BP on these improvements. Clair Phase 3 is a new project, which includes Clair South. It's still relatively early stage of development but will give Clair an even longer life. Moving on to Elgin Franklin. I'm personally very familiar with Elgin Franklin. I have spent most of the '90s working on the exploration and appraisal and development of the fields when I worked for Elf. Interestingly, when we drilled the discovery well in Elgin, technology did not exist to be able to develop the field due to its extreme high pressure, high temperature nature. This was an interesting challenge for engineers. Elgin Franklin is the U.K.'s highest rate producing field and is one of the world's largest high-pressure, high-temperature developments. It has high volumes for Harbour, even at a 21% working interest, low lifting costs and excellent production efficiency and reliability. Production efficiency was impacted earlier this year by the liquid export route, the Forties Pipeline System, where there was a 20-day unplanned outage at Unity. And then later in the year, the 30-day planned shutdown ended up being 50-odd days due to the export route being unavailable. Elgin Franklin is preparing for a long future. There's an extensive fabric maintenance campaign in 2022 to extend the infrastructure life into the 2040s. In addition, Elgin Franklin lends itself to electrification and is part of the Central North Sea electrification project. Moving on to Buzzard. I'm also very familiar with Buzzard as I moved from Elf to join a small U.K. team of Pan-Canadian in 2001 when we discovered Buzzard or [ Broom ] as it was known at discovery. I spent most of the next 14 years involved in the exploration, appraisal, development and operation of Buzzard in various roles, ultimately having overall production and drilling responsibility. Buzzard is a world-class oilfield with high uptime for the sector. It is a large complex of 4 bridge-linked platforms with most production wells centrally located and water injectors subsea. Buzzard Phase 2 is now online and was delivered within the revised schedule. This is revised for COVID and within budget. Two of the wells were not completed and formed a sidetrack and completion campaign starting late next year. Buzzard has an eye on the future with much asset integrity work having been done and is part of the Outer Moray Firth electrification project. In fact, the initial Buzzard design envisaged power from shore but was dropped at the time due to uncertainties around shore power reliability. OpEx rescaling is now another focus area as Buzzard moves into its next stage of field life. Buzzard is well placed to become the hub of choice in the area for additional equity production and third-party tiebacks. And finally, Beryl. Beryl continues to have exploitation opportunities and has material upside from tertiary play. This can be seen in the increasing production volumes. Production drilling, which happens on Alpha and Bravo, are due to restart after the 2022 shutdown and run into 2024. In addition, we have a [ semi-sub ] drilling the tertiary prospects. Planning has started on a major topside overhaul in 2025, which is tied to the tertiary development opportunities. There are currently 3 compression trains on Alpha with old technology and associated reliability. Here, we have an opportunity to combine a future development with modernized equipment, which would deliver better emissions and reliability performance. Thank you for listening to what is a busy and very exciting U.K. operation. And I'd like to hand over to Stuart Wheaton, who will run through our international business. Thank you.

Thank you, Bob. And now turning to the international portfolio. However, please let me introduce myself first to those not so familiar. I'm Stuart Wheaton. I am the Harbour EVP for the International business. Previously, I was with Premier Oil for about 5 years in several roles, culminating in 2020 as Chief Operating Officer just before the COVID pandemic started, as it turned out. I've been in the industry now for over 30 years, starting in Exxon and then with independent companies worldwide, including Lasmo, Cairn and Tullow. My background is in petroleum and reservoir engineering, but I've been fortunate to work in many areas of -- also of production operations and projects in numerous countries. Particular fast -- past favorite roles have included subsurface manager in Cairn India throughout the discovery and development planning of Rajasthan, which became the famous 200,000 barrel per day project there. I was also a development manager in Tullow Ghana, getting Jubilee deepwater online and more recently, the delivery of Catcher project in the U.K. North Sea with Premier. Today, I'll be mainly covering our current interests in Vietnam, Indonesia and Mexico. But firstly, to report, you'll be aware of our previously announced decisions this year to exit the Falkland Islands and Brazil given the clear forward strategy we have now set at Harbour. I can report that in Brazil, our exit is almost complete, and that from Sea Lion, Falkland Islands is progressing positively with ongoing discussions with our partners and the Falkland Island government. News on that in the near future. We'll turn to the next slide now. Many of you will be familiar with our existing footprint in Southeast Asia in Vietnam and Indonesia, based on our producing Chim Sao and Block A fields, respectively. The cartoon schematic on this slide of the overall Harbour licenses in both countries shows we operate substantial infrastructure there today. It's a very sound foundation in the region for both future organic and potential future inorganic growth. In terms of really new things, I'll cover Tuna and Andaman Sea in coming slides. But starting at existing Chim Sao and Block A, these remaining high-performing and attractive cash-generative assets, though both are now maturing. You will note the bullet points listed here on the top left. I'll pick out a couple, the high uptime performance, which for many years, has sat at 90% to 95%, including planned shutdowns when they're needed, a 96% to 98% without the planned shutdowns. This is really excellent and sustained by the strong operating teams in both locations. And b, the attractive prices received for the products. We've seen recent Chim Sao oil sales at over $4 per barrel above dated Brent, while Singapore gas prices ex Block A are back to historic high levels. In fact, the pro forma joint contribution of both assets has been around 16.5 KBD net Harbour production in 2021 or about 8% to 9% of the company's overall production. The 12 shown on the slide here for production is our reported contribution since the Chrysaor-Premier deal completed in April 1. This production contributions remained relatively flat over the last few years as we work to largely offset the natural declines with incremental activities such as infill wells, workovers and tieback projects. As an example, in 2021, a new infill well and work over at Block A added about 23 million scfs a day gross. In 2022, we'll be back again to do the same at Block A. Also at Chim Sao, we've also sanctioned a 2-well oil infill campaign forecast to start around middle of next year. These are very economic activities supported by all partners and governments. Combined with facility upgrade work in both locations, this should keep the production at these assets, again, relatively flat out to late 2024, as shown the production plot on the right-hand side. We'll now turn to Tuna. Now for some really very new news also at Tuna. In the second half of this year, we completed a successful appraisal campaign on the 2014 discovery in the East Natuna Sea, Indonesia. The Noble Clyde Boudreaux drill rig started operations in July and successfully completed them just a few weeks ago. In that time, we drilled 2 step-out appraisal wells and completed an extensive data acquisition in full. This included 3 drill string flow tests across the 2 wells. Two of these tests were focused on wet gas zones and one on an underlying black oil section. The work was delivered safely and very close to budget. You may remember our share of costs were carried in this program by our new 50% partner, Zarubezhneft. Our actual spend only just exceeded the cap carry level. And then that was due really to finding more net pay than we prognosed in our mid cases. The well tests have proved economic flow rates. In some cases, they were limited by the surface test equipment on the rig. Flow rates of 25 million and 10 million scuffs a day gas were delivered in the gas tests and over 3,000 barrels of oil per day in the oil test. Importantly, we also saw high condensate yields in the wet gas tests higher than expected, about 2x higher than the fluid samples from the exploration wells of 2014. Samples we had, had some doubts about, it has to be said. As a result of this positive appraisal program, our initial view is that there is likely an economic project to be developed to Tuna. On this slide, we have a breakeven of NPV 10 for the project of less than $25 per barrel of oil equivalent. As at pre-drill, the basis for any project remains as dry gas sales to Vietnam, and liquids, condensate and some black oil offloaded to market via an envisaged FPSO scheme tied to a dry treat wellhead platform. Total CapEx requirements will depend mainly on whether the FPSO is leased or purchased. But -- and as a guide, for example, in the least FPSO case, we could be looking at around $6 to $8 per BOE unit CapEx cost for the scheme and overall unit technical cost through field life, i.e., CapEx and OpEx and leased altogether of the order of $20 to $22 per BOE. Indications are of a mid-case scheme to develop somewhat over 100 million BOEs gross, with a target production on plateau of around 40 to 50 KBOE per day, gross being approximately 55% gas and 45% liquid sales. We've already initiated the project's technical and commercial work fronts. We are engaged with the Indonesia regulator, SKK Migas, about our forward project time line to sanction with a very positive support indicated thus far. We show a summary time line here, and we believe this is realistic with a sanction decision we're all now working towards in the first half of 2023. After some history here, it's really pleasing to make this progress at Tuna and commence the process of project delivery with a very capable and enthusiastic organization we have in Indonesia. And now turning to an exciting matter even earlier in its life cycle. Here, we have the Andaman Sea position. We have a summary of our position off Northern Sumatra, Indonesia. In particular, our 40% operating position on the Andaman II license. Our partners here in the license are BP and Mubadala Petroleum. We have already contracted a drillship, the West Capella, to drill the Timpan I well. Pending reasonable progress on its previous contract in Malaysia, we forecast that we'll spud Timpan around March, April time next year. As a reminder, we're located here in about 1,200 meters water decks. The cost of the well, including a DST and setting up the remote logistics, is of the order of $80 million to $85 million gross. We expect the area to be gas prone. You can see the Timpan target in the attached seismic section. Timpan really could be a significant player in the region. But of course, nothing in exploration is a given, but we proceed with good confidence. We've carried out various predevelopment studies already. We can see really early commercialization opportunities in the success case. It's a great address for any discovery to supply both domestic and regional energy demand. Importantly, the area already has established oil and gas infrastructure to support our activities. You may remember the very large onshore Arun field and its related LNG export plant, well, it's located right on the adjacent coast to the south of the license. Finally, as these large depleted fields in the area like Arun, which also potentially open up any citing scheme of some scale. This could well involve early carbon capture and storage for emissions disposal. You can envisage a carbon 0 type industrial hub in the very large success cases, making use of the hydrocarbon gas to generate power and blue products with CCS like hydrogen, ammonia and fertilizers. So let's see what we find in the first half of next year. Now we'll move finally to the Western Hemisphere in our international business. So our Mexico position is currently non-operated, with an expected 12.5% share of the very large Zama unit oil discovery and 30% of the Block 30 exploration license. At Zama, progress slowed in the middle of the year as the Block 7 partners of Talos, WDEA and Harbour engaged with Pemex and SENER, the Ministry of Energy in Mexico, of who we finally awaited the initial determination of equities in the unit by third-party expert, and secondly, announcement of who would be the unit operator. The initial equity determination was announced in Q2 this year and Pemex as unit operator in early Q3. Neither outcome has surprised Harbour. We, WDEA and Harbour, have since continued very frequent engagement in country with Pemex, SENER and various other key Mexican government departments. In recent months, these discussions have moved positively in our view, including key subjects such as technical aspects of the field development plan; finalization of a Zama unitization and unit operating agreement, including who will do what in the project delivery; then oil and gas sales agreements required; and finally, project funding and payment guarantees by all parties. These matters are now coming to a head, and we would hope to be able to release further news with respect to Zama progress in coming months. Internally, currently we plan on a first half 2023 sanction decision to be taken by Pemex and the Block 7 partners. It is such a spectacular and large project. Other Harbour activity in Mexico shown in the bottom right-hand box on the slide relates to our Block 30 interest, actually quite near to Block 7, Zama. Here, WDEA are the operator. Plans and rig contracting are in place to spud the first of 2 commitment wells in the second half of next year. This is shallow water jackup rig territory. The first well at Wahoo is a relatively high confidence midsized oil target, and the second, Pike, considered a lower chance of success. If we have success on Block 30, these midsized prospects could be developed relatively quickly by FPSO type schemes or indeed wellhead platforms tied back to the shore, as other operators have done in the areas such as Pan American. So looking back to summarize our current international picture, starting with continued steady performance with incremental investments at Chim Sao and the Tuna Sea, Block A. A successful appraisal campaign at Tuna, I talked briefly about this year, and we've started work to get us to sanction and then first production, an attractive and important project in Indonesia. Then a key and exciting exploration campaign starts in Andaman Sea in the first half of next year, with some amazing large-scale possibilities importantly linked to low-carbon emission schemes in the big success cases. And finally, in Mexico, in our view, some real progress being made to get Zama to sanction in conjunction with partners, as well as later in the year, some further interesting exploration wells on Block 30. So thank you for listening to our current international business summary, and I will now hand back to Linda to make some concluding remarks on our Capital Markets Day. Thank you.

Thank you, Stuart. I hope everyone enjoyed seeing the videos and hearing from both Stuart and Bob, and learning more about our operations and opportunities. We're now at the end of our presentations for the day. I hope they've given you a real sense of Harbour's potential and the opportunity that lies ahead. To reiterate what I said earlier, we're ending the year in a strong position, producing 200,000 barrels per day from a diverse mix of high-quality cash-generative assets with good visibility to be able to sustain this near term. Together with our strong balance sheet, we're able to introduce a $200 million annual dividend and fund reinvestment in our portfolio while retaining significant optionality over our future capital allocation. We'll now go back live to London for our second Q&A session. Great. Thank you, and welcome back to our second Q&A session. I'm joined this time, along with Phil and Alexander, also Stuart Wheaton and Bob Fennell, 2 of the key presenters from that last set of presentations, which we hope you enjoyed. I understand during our first Q&A earlier today, there were some technical difficulties that prevented a number of listeners, participants from dialing in or getting their questions into the system. We're hoping that's been resolved. But in the event that it hasn't, and you're unable to get your questions through, please send them through to our Investor Relations, and we'll be sure to get them answered in. And we apologize for the challenges and difficulties. And with that, we'll open it up for Q&A.

[Operator Instructions] We take our first question from Sasikanth Chilukuru from Morgan Stanley.

The first one was related to the presentations on the asset base. And it was mainly related to the production outlook beyond 2024 and the associated CapEx. You've highlighted a big increase in the production coming from the 2C resource base for greater Britannia area and the J-Area. I just wanted to understand if your P&D CapEx guidance of $800 million to $900 million for 2024 includes the CapEx associated with this production upside or whether this will lead to an increase in CapEx as and when these projects are actually sanctioned. If you were to extend these P&D CapEx projections to 2025 and 2026, would it have to be higher than the $800 million, $900 million for the production upside from these 2C resources to be realized?

Yes. Sasi, thanks for the question. I'm glad you got through. I think maybe you were having difficulties in the first session. So it's good to hear from you. Let me see if I can take that. So the CapEx levels that we've set for the company of around $1.3 billion all in, everything for the next 3 years, plus or minus, is a level we feel comfortable spending at given our existing portfolio and a level that we believe will lead to us to maintain productions at around current levels. And I don't think it necessarily makes sense for us to go significantly up from that even if commodity prices were higher because there's some advantage at keeping a stable level of activity. In 2024, we are including capital in that year for things that aren't yet producing. And I believe some of the things you referred to, I'll let Phil kind of confirm that. But also, what's in 2024 is CapEx for things like the development of Tuna in Indonesia and also Zama in Mexico, and quite a material a bit. And so that CapEx is for production that's beyond the years that we're showing today and hopefully would enable us to keep production flatter for longer. And maybe Phil can give some color on what's in those numbers in the outer years in 2024 in the U.K.

Thank you, Linda. Thank you, Sasi. Sorry, you had the problems earlier. And Bob and Stuart's slides are actually quite good because we put production profiles in there that are a little bit further out than just the next 3 years. There is quite a bit of CapEx in some of those outer years that relates to those later years production profiles. And you can see in the medium term, we see J-Area production increasing. And just in the last period, we're going to get the Talbot field, albeit while fingers crossed, coming through. And then if you look at Britannia, you'll see what appears to be a decline, but then we're spending money to appraise and bring forward developments that we have, that we know we've got developments but are not actually going to hit production until '25. We also have some significant process debottlenecking that we'll do on Britannia that should realize more production from fields like Brodgar. And that will go hand in hand with the level of development that we would hope to progress with some of the partners in the area. If that helps, Sasi. We're not giving 10-year guidance, but we're pretty well saying where we are at the moment and what we think we have to spend and what fits with our capital allocation.

No, that's quite helpful. And just related to the production profile and the more nearer term. You did talk about -- you did highlight high underlying production declines in Slide 23, and also, of course, the good line of sight in arresting this decline. But in 2022, we have a big contribution from a start-up. Tolmount coming in, adding 15,000 to 20,000 barrels, around 8% to 10% of the production. If you were to look at 2023 and 2024, are there any specific projects or tiebacks that significantly arrests these decline rates? Or would it be essentially a series of new wells and infill drilling, almost double what was guided for 2021 -- 2022 -- for 2023 and 2024 onwards.

Okay. Thanks, Sasi. And I try to answer that decline question earlier where I reminded everybody that, that decline was against the year-end exit rates. And I said there were 2 specific still unknowns, decline on one of the big Callanish wells that we've got on the greater Britannia area that could drop by 5,000 to 6,000 barrels a day and also exactly when we see increasing water on capture that we haven't as yet seen. We do expect that in the future. So there is 2 key elements. Things to look out for, there isn't any one-off projects in the period. As we've always said, there are a lot of infill and tieback. So I say we're going to be -- we will undoubtedly be developing Talbot, which is one of the biggest spends over the period, churns out towards the end of the period with only production from the U.K. project just coming into '24. We're really active in J-Area. So you will see -- and I think in the deck, you can see the increases in the J-Area production profiles. We've obviously got the infill campaign and tieback campaign around Catcher. We're doing a lot of work in Britannia, but not going to see a lot of benefit from that until '25. And then on the NOV portfolio, we continue in a drill on Clair, albeit a smaller equity. But with our partners at Apache on Quad 9, we continue to drill the tertiary play that is semi -- is in the E&A numbers. But actually, we're increasingly confident with some of those targets, and we'll be spending a reasonable amount of development capital for the discovered resource we've already got that will lead to production just at that tail end of that 3-year period, but mainly, I think, outer period. You can probably see it on the chart. Those are the highlights, Sasi. No massive big projects other than the ones we've spoken about. Lots of really high value, high IRR, quick payback, let alone at current commodity price opportunities, which is what we like.

We take our next question from Mark Wilson from Jefferies.

Just a clarity point on the dividend and the AGM, please, first. The AGM next year, that will set the 4Q distribution as well as the 2Q. Is that the case? Or is that flexibility dependent on what -- how commodity prices and operations is going by the time we get to 4Q? I just want to check that.

Mark, thanks. I'm glad you were able to get through. So at the AGM, in the spring of next year, the final dividend for -- with respect to 2021 financial year, will be there for approval. So that'll be the first $100 million distribution that we would pay. The second distribution in calendar year 2022 would be after our interims that we would come out with in Q3 or late Q3 and we expect that interim dividend with respect to the interims would be paid in either October and November, I believe. And that would just be -- would just require Board approval, Mark. So things could be -- there would be an opportunity for the Board to reconsider the level, should they choose to do so at that time.

That's absolutely what I was looking for. And Alexander, just want to check your slide on cash taxes in the future years. Just wanted to confirm, that includes all international cash taxes. Frankly, they look lower than what we were carrying. So always happy just to confirm lower cash taxes.

Yes. Thanks, Mark. Yes. No, we did put up the actual spend. And the decrease that we're expecting is -- that's group level. Now -- and you know the effects in the U.K., but I think what you need to factor in is also the fact that there will be the Norwegian tax refund coming in there. So that will be a debit to that number. So in exploration, when we talk about spending of around $200 million, well, that is pretax Norwegian spending that's included there. So that does bring the overall group cash taxes down.

Not all of the $200 million is Norwegian exploration stat.

Yes. No.

Sorry, Alexander.

No. It's okay. There's some exciting Timpan stuff and other things in there as well.

Got it. Okay. And then last one is the slide on 2P reserves looks like it's -- you mentioned -- Phil described it as flat, and it looks like it's roughly around 500 million barrel level. The pro forma number we've seen in the past is around 600 for the combined company. So can we talk to the moving parts there outside of production? And then if there's that related to Tolmount now, the delta that there is between the range of reserves you speak to.

Yes, Mark. So just to confirm, the slide Phil showed with the estimate of where the CPR might come out at the end of this year does include an estimate of a Tolmount downgrade in it, if I think that was part of your question. And then, of course, there's production, 70 million barrels or something of production comes out of that as well. And there have been a couple other adjustments.

And we were -- sorry, Mark. It's Phil. And obviously, we have shaded this. We're trying to estimate where we're going to get to with the reserves auditor, and there's always some uncertainty around these things. And there's been some good things that have happened recently, but probably won't get those into year-end reserves cutoff. And there's been a couple of things probably through the year that have been more disappointing and then followed by good things. So it's deliberately hatched and hazed while we finish all that work off.

Our next question comes from James Hosie from Barclays.

I guess I'll start just following up on Mark's question a little bit about reserves. Then obviously, you find the reserve cut at Tolmount. I'm just wondering when we could expect some of the reserve upgrades to come elsewhere in the U.K. as you commit to new projects? Is there nothing that kind of is mature enough to be added at the end of this year?

Yes. Yes. I'll -- let me let Phil take that.

Sorry, James. I'll try to answer that. It's -- we're pretty strict. So we will look at where we stood at the year-end and the decisions that we made. And there's probably some timing in there. So there are some things we probably won't have sanctioned, but do expect to go ahead, probably won't put those into reserves change. And that was what I was trying to answer before is there's some good things that happened. But whether we have all the information in one place in time, we're not going to have sanctioned some of the developments in time for the year-end.

Okay. And then if I could just turn over to the Tuna and Zama project. Can we take your inclusion of these assets in your '22 to '24 spending plans and indication you intend to retain your current stakes in both of them?

Yes. I would say we're just keeping our options open, James, on that. I mean, right now, they're exciting projects. Preliminary view on economics is they meet or exceed all of our hurdle rates. We're happy to spend money to continue advancing them towards FID. But every project is always a decision, and it comes down to capital allocation and what's the best use of the funding that we have available and Alexander's mantra around making sure we're continuing to always balance the balance sheet versus reinvesting in the portfolio versus distribution to shareholders.

Okay. And could you quantify how much is going to be spent on those assets pre-FID and, I guess, early '23, you said?

Yes. Maybe let me -- let's see if Stuart has an answer to that on feed or other things for the 2 projects. Stuart?

Yes. The magnitude for Tuna is around about $20 million gross to get us to a sanction decision, and Zama will be similar. Zama might actually be a little bit less because we've done a lot of front-end work already, but there will be some reworking with our ideas with Pemex. But yes, that kind of magnitude to get us to a decision.

The next question comes from Matt Smith from Bank of America.

So wanted just to go back to Slide 45, so the 3-year outlook in terms of capital allocation and just sort of wondering about the absolute levels of cash flows that's been highlighted but also sort of sensitivities there. So it looks as though, as we know, the dividend number, the sort of free cash flow pre-dividend looks, roughly speaking, around sort of $800 million per annum on the assumptions that you put in the footnote. So I was wondering if you're able to confirm any sensitivities there, and I guess, particularly one on oil, but also on the gas side to that. And I guess in that light, would you say that there's potential for you to hit your -- to be debt-free before sort of the 2025 target that you put out there in light of what you're showing on that chart taking into account some upside scenarios on the commodities?

Matt, I'll let Alexander take the first shot of that.

Yes. Sure. It's -- Matt, it's an illustration of what we think is achievable just with the -- just looking with forward curves and how we see things developing, just considering all the hedges that are in place and considering the current spending levels and how that is looking. So we haven't guided on a net debt level for each of the years. And -- but we've given most of the building blocks, I think, in just each of the slides before this. So it's -- yes, there's some flexibility in that spending, as you'll see, but it would depend on a variety of factors, not just natural gas prices and oil prices and future hedging levels. Several things going into that estimate and spending levels as well. So 2025, we definitely see that as achievable. And if it would be potentially sooner than that, would depend on a variety of those factors there.

Sure. Perfect. So just to clarify then, sorry, the footnote on the assumptions on commodity prices is the group sort of realized price post hedges, is that what we're saying there?

So yes, it's forward prices for 18 or 24 months that we've used. And yes, we've used the actual hedging position that we spelled out on one of the earlier slides, I think.

But the commodity prices shown in the footnote are just that, The commodity prices that we're using, not our realized price right, Alexander? Yes. Did that make sense, Matt?

Yes, yes. Understood.

Christopher Wheaton from Stifel takes our next question.

First and perhaps an easy question. On Slide 44, you talk about the dividend. You said there'll be a final dividend of $200 million and then an interim dividend of $100 million in November. That's going to make $300 million cash paid in 2022. Is that correct?

No. Sorry, Chris. So the policy is $200 million distributions per annum. Our first distribution will be after the AGM, and it will be $100 million. It is with respect to 2021 financial year. So for the financial year 2021, it's a $100 million dividend. Then the second distribution next year will be after interim. So that'll be another $100 million. So for calendar year 2022, the outflow, if you will, or the total distribution to shareholders will be $200 million.

Right, okay. That clarifies that bit. And to this $200 million, basically, the second -- the first interim dividend of $100 million is included in that first $200 million. That's very helpful to understand. The second question I had was relating to some of the more project level details, and I thought that was really helpful insight. And you've given us on Slide 37 a breakeven chart by probably spend for '22. Can you show -- could you describe what the shape of that chart will look like in '23 and '24? And if it goes back to the question you had a few questions ago about -- was that incremental return on -- effectively incremental return on capital employed? And actually, is it pretty much the same in '24 that, that -- for that slide on slide -- picture on Slide 37 versus the 2022 numbers? That's kind of what I'm interested in from that slide there.

Just to make sure I understand, Chris, is your question, you're looking at the breakeven chart on that page that shows projects breaking -- most of our projects breaking even at $30 or less in year -- and that's for projects we're executing next year. And your question is, would that look the same for the projects we're executing in '23 and '24?

That's right. Because I think the question before was with picking up on this issue of what's your incremental capital employed look like and pretty constant over the next 3 or 4 years, does it tail off? That's why the '24 number compared to that chart will be cut. It's quite interesting to understand.

Yes. And I think the generic answer is, of course, we know a lot more about the projects we're executing in the next 12 months than we do about the projects we're executing 2 or 3 years from now because for the projects we're executing next year, we already have affirmed cost estimates in. We have AFEs prepared and, in some cases, already approved. And so -- and all of the subsurface technical work has been done. So that's not the case for the later projects, including things like Zama, Tuna, some of the other things we've talked about. But we wouldn't be showing that kind of spend levels in those years if we didn't feel like we had sufficient numbers of projects that more than exceeded our hurdle rates to be able to put into that program and then result in sustaining production for us. But Phil, you want to add?

So just add to Linda, yes, everything that's in this deck is real. There's no -- I mean there might be 1 or 2 wells where we're debating whether to drill the well. But in terms of tangible developments, the P&D CapEx, it has real baked projects underlying it. If anything, we have more projects that we could put in if we were a little bit more blue sky. We've chosen to set where the level of capital is that matches the organization, our appetite at the moment and what we want to execute on. But they are real projects, and we would expect them, obviously, to not just beat hurdles but to be the sort of thing that we want to execute. Don't know if that helps you with that [indiscernible]. Thank you.

That's really great. That's really, really helpful. I guess -- and a follow-up to that would be if you have -- if your CapEx constraint is basically the organization, it's not financial [ that then you're ] charging implications for returns to shareholders because it seems to me that you've got quite [indiscernible] there's quite a bit more cash you could be returning to shareholders should you choose. Given, as you just said so, you're under -- you're being conservative on your project suite. And you don't want to [ transfer ], you want to expand the operating envelope beyond that, that you're absolutely sure you can deliver. I'm interested then in that potential upside in shareholder value and shareholder return of value to shareholders. And so I guess the question is both for you and also for Alexander.

Yes. Thanks. But I understand how you're looking at it because we do say we have $500 million to $600 million of excess free cash flow this year. We're saying for next year, it's going to be even more than that, barring any large unforeseen surprises. Of course, we're hedged a lot going into next year. So we have downside protection as well. I don't think it's practical or makes sense or is the right thing to do to all of a sudden decide to increase CapEx, another $500 million next year. It leads to operational inefficiencies. You can't just spend that much money that quickly anyway. We feel like we're at the right level for our company and able to keep production flat and generate positive cash flow, which is extremely important for us. So we feel good about the spend level. And pulling the reins back on the organization helps us prioritize, and it institutes a bit of discipline into the organization, which I like as well. So we're comfortable with the spend level. So then the question would be, what would we do with the money beyond what we're going to need for that CapEx program, and I think Alexander can talk a little bit more about how we think about then allocating that.

Thanks, Linda. Well, I think you took all the good notes. And we're comfortable operating at the level that we're doing. There's competition for capital, and we've set out the investment hurdles that we want to follow. And if we have projects that breakeven at $25 or $27 per barrel, we think that's -- those are good projects. That's the stuff we want to do. And we shouldn't just massively increase that, try to make that as predictable as we can and do that in a safe and reliable way. So now potentially paying down a bit of debt when commodity prices are reasonable. That's -- we think that's a good idea. And then the question will be for the Board, whether it makes sense to do additional dividends or buybacks or so in addition to paying down debt. So that's something we -- hence, the annual review that we instituted.

Our next question comes from Philipp Duffner from Aurelius.

I have a question on the Slide 53 and 54 for the GBA and the J-Area. Because of those, you show a lot of upside in the '25, '26 framework in terms of production. What would it take to realize that? And to what extent is that already baked into the CapEx guidance, which I realize ends a little bit earlier, but in terms of how we think about CapEx needed to realize that upside?

Great. Phil or Bob?

I'll let Bob answer.

Yes. Yes, thanks for the question. I think if we think about Britannia and J-Area, J-Area, we've got 2 drill rigs working at the moment, and we're seeing the production coming through from that. And Britannia, we're working up all of the options, and there are many around the area at the moment. So subsurface work is going on. And what you see in Britannia in the outer years is the lever at prospect. So that is -- that goes across 3 licenses and has been worked up jointly with another -- a couple of companies. So that's early stages, but we're working that jointly, but we do [ ops ] potential for that to come through. And we continue to work the J-Area as well. So I think the challenge that we have, particularly on Britannia, is to try and accelerate some of this work. So we're looking at the long lead equipment and working with the supply chain to see if we can accelerate these profiles to the left.

Thank you. I'll just add to Bob there, which is completely right. Lever is a discovered resource with 4 wells on it. Actually, we need to rightsize that potential development and actually gives us an option. Another kickup you'll see in production is we may be able to develop lever in a way that will help all of our existing fields that is effectively constrained by process facilities and the temperature that it arrives at. So part of this is the engineering associates, but that real -- these are real volumes. It's not just a blue sky there. It's a plan, and people working on this with the aim of delivering. It just takes some time. And when you're dealing with fields with multi-different compositional issues, then you've got to spend -- you've got to do the work right. Hope that's helpful. Don't know it that helped, Philipp?

Got it. That's helpful. And then I just wanted to ask -- I know that the guidance is -- like what are you assuming for the Tolmount startup? When does it happen during Q1? And lastly, the $500 million to $600 million of free cash flow that you're indicating for this year, how much of that was the like-for-like number for H1?

Yes. So Tolmount startup next year, I think that's one of the reasons for the sort of wide guidance we gave of 195,000 to 210,000 barrels per day for the full year, accounting for whether or not Tolmount starts up at the early part of Q1 or the latter part of Q1. So we've assumed kind of a range around that, if you will. And then on the cash flow number, Alexander, comparing first half to second half maybe, reported versus -- reported.

Yes. The question might be, Philipp, if it's around reported versus pro forma where the $500 million to $600 million that we were alluding to, that was on a reported basis. So I think we had around, was it around $300 million or so in the first half of the year? So perhaps around half of that in Q1, if that's the missing part you're looking for. I'm not sure if that's really the question, Philipp.

Yes. I guess I mean, the follow-on question then would be -- because, obviously, realized prices would be -- should be higher in the second half and your overall production probably as well. So why is the cash generation not stepping up significantly from H1 to H2?

Yes, it's definitely more CapEx. If you remember, when we update this in the interims, we talked about how much the CapEx we had spent in the first half or up until June 30 and then how much was then expected to come in the second half of the year. So CapEx -- back to Phil's point on maintenance and what's been going on in Q3, the spending has definitely been higher. Then also we've had, what is it, more than 60% or so hedged. So we were, unfortunately, not taking advantage of the extremely high natural gas prices that we've seen in the U.K. We've been hedged at lower prices than that. And we also show this at the interims. So those would probably be the 2 main reasons there.

Next, we have a question from Al Stanton from RBC.

The tax slide on 39, as Mark pointed out, is probably lower tax than many of us were expecting. So can you just go through the mechanics as to what reduces your tax numbers in terms of things like the Premier Oil losses? What years do they impact? And also, the hedging. Because you're hedging at $60 and 43p a therm, if you were getting market prices, what would your '22 tax bill look like? And what would your '23 tax bill look like?

The second question, that was really a tricky one. So you're going to have to give me some time to think about that one. But the first question on taxes, and I don't know what were in everyone's estimates on this. But clearly, the starting point is that we're probably the biggest investor on the U.K. Continental Shelf, so we are -- we have the biggest program, the biggest spending, which obviously drives a lot of the deductions coming into this, Al. Then yes, there's some tax losses that's being utilized as well. Hedges plays into that, unfortunately, I suppose, but -- this year. And then it's also the fact that it's on a group-wide basis. So if we're spending money on exploration in Norway, we've just decided to show that gross. So you have the gross spending on -- in exploration. And then that tax refund is coming in as a net. So as an example, if you've been -- or we have been now in 2021 a couple of wells in Norway, those will come in as a negative or a debit to that in the next year. And there's also cash tax per year. So when we're saying a bit of the spending is now in January, well, that's because it's the third and last installment of the 2021 tax, and the same will then be for future years. So it's -- those are probably, I'm guessing, the factors that plays in this year. But happy to review that in a bit more detail later.

Could I ask just a really simple question then? So if the prevailing gas price is, let's say, GBP 2.16, you hedged at 43p, that loss goes all the way down to the -- a reduction in taxation?

Yes. Yes.

Nathan Piper from Investec takes our next question.

Just a quick one on Zama. I just wondered if you could give your view on how likely that development is to go ahead given the political situation in Mexico and the length of time you've been dealing with a thorny issue of unitization. Do you think the incumbent government are going to play straight? And do you really think that Zama is a project that's going to go ahead on the time line you've already outlined?

I mean, Nathan, they are good questions, of course. We ponder them all the time ourselves. We're not going to get into kind of the geopolitical kind of aspects of it other than to say we wouldn't be spending money today and working hard to advance the project if we didn't think it was worthwhile to do so. And there are other operators there, and Stuart can talk about them, who are able to work perfectly well in Mexico and within their regulatory environment and with Pemex as their partner. Stuart?

No. I think that's very right. I should say that the engagement with Pemex and the Mexican government in the last few months has been truly genuine. It's been very open. We've had to listen to the requirements and the needs there. And we've been very open. It will all come to a culmination during next year as to whether we're really making true progress. But right now, we feel really quite positive about it. And I listed a few of the issues in the video that we've been covering, and they will all come together really in the unitization agreement. And genuinely, I think you'll be hearing some news about Zama in the next few months from all the parties.

Well, I guess to be specific about unitization, are they following an ecological, internationally recognized process? Or are you trying to budget -- or sorry, [indiscernible] or not?

Yes. No. We -- there's a little bit of art and a little bit of science into figuring out subsurface reserves and how much lie on one license versus the other. Our view always was that it was pretty close to 50-50. A legitimate, independent firm was hired to provide the view on that, and it came out 51% on the Pemex license, 49% ours. Quite honestly, we have a difficult time really arguing with that one way or another. And in any event, Pemex will be the largest interest holder in the field because they own 100% of one license. And on our block, it's split between 3 parties. So as Stuart said, it wasn't a surprise to us that Pemex was named the operator. And what's more important to us are the rules in that unit operating agreement, what role we and our partners on Block 7 will be able to have so that we feel comfortable that all of our expertise and experiences being able to be applied to the field development plan and then the execution of the project should it go ahead. And that's what we're working on now, and as Stuart said, having -- making some good progress.

I suppose the operator, your license wasn't quite so sanguine about, and I guess that's going to be where I'm picking up some of the surprise around what hurdles [indiscernible] played out. But I guess to your point, if you didn't think it was really -- you wouldn't be spending the money, I understand. So I guess I'll wait and see what happens.

Great. Thanks, Nathan.

We go back to Mark Wilson from Jefferies.

Just checking some -- love to talk about the CapEx, but just checking my math as I look at those asset profiles particularly on the U.K. assets out to 2026. I'm looking at production there that's 20% higher than 2022 if all those projects come in. Does that sound roughly correct? And then second question I'd like to ask is electrification of any of these assets given that some of them have got very long lives ahead of them, what are the variables and decision hurdles regarding actually doing electrification of anyone?

On the last, I'll let Phil talk about electrification. But on adding up all those profiles that were in part 2 of the presentation, we did that math ourselves because I asked for it just to make sure we understood what they looked like. And what I believe is the case is that some upside has talked about on some of those. And those are more to-see things, things that have a lot less certainty around them. The timing is a lot less certain. But if you just take the firm things, I'm not sure we get to a number that's quite as high as what you talked about, Mark. But Elizabeth can answer more questions later if you have them about those. But Phil, you want to talk about kind of the challenges of electrification and the parameters around it?

What a great question, and I can talk at length as Linda knows, but I'll wait. It's very complicated. It's like repairing your car in the middle of a field miles away from anywhere with -- and you have to carry everything to go and do the work. It's possible. It's a lot of work offshore. There are multiple regulators who are interested in this. The regulatory landscape is very complicated. Different parties would like to achieve different things out with our industry, maybe reinforcing the grid, maybe enabling future wind, and less, with both governments, both Holyrood and Westminster. So when I talked about regulatory landscape and bringing the regulators together and industry, those are the sort of things that are going to happen. And there's a committee of regulators has been set up. The conversations are beginning to actually happen. People can see the issues, and a lot has been achieved just to get to that point in time. Not all the platforms in the Central North Sea or in the Moray Firth or West of Shetland are as easily electrified. Some -- like Buzzard, it was always potentially contemplated. Others are more difficult. So there is still a lot of work to do. And we'll wait and see. I'm always optimistic, but there are a lot of pieces that need to be in the right place at the right time. And you say we have to look at the remaining life, the economics, what else we can do to improve emissions and what else we can do to get value out of those assets.

We go back to James Hosie from Barclays.

Yes. If I just go and look at Slide 41 and the reference there to a target reserve life of 8 to 12 years, it looks like you're going to be a little under that range by the end of this year. I think I know the answer, but does that create any urgency for you to do further M&A? Or are you quite comfortable and confident you've got enough resources being converted into reserves in the coming years?

Yes. Thanks, James. I think we're comfortable is the answer to that. I mean we laid out a capital investment program for next year. You saw the profile on breakevens for most of that spend. They're very, very attractive projects and I think things that every investor would want us to be doing with the money we have available to us. And we've also demonstrated confidence now that we can keep production relatively flat for the next 3 years, which is kind of the line of sight I know a lot of investors were looking for. And we're happy to be able to demonstrate that we believe we can do that at least for the next 3 years going forward. When it comes to M&A, I've used the phrase before, we're disciplined not desperate. There's no real sense of urgency for us. We've been patient in the past. When we first formed Harbour Energy in 2014, we waited 3 years before doing our first acquisition. We have lots of opportunities in those intervening years to go after, acquire things and, on numerous occasions, walked away or came to the conclusion that value-creation opportunity just wasn't there. And I think we have the reserve base today. Thankfully, that allows to continue to be patient, to be very disciplined, in the meantime, keep production relatively flat, reinvest in the asset base and generate a lot of free cash flow and distribute -- make distributions to our shareholders. And we feel like we're now starting to do all of those things and ending the year in a pretty strong position. So happy to do that.

This now concludes our Q&A session. I will hand it back to Linda for any closing remarks.

Great. Thank you. Thanks to everyone for dialing in. I know it's been a little bit of a long afternoon with the different presentations and the 2 different Q&A sessions. We do hope you found it helpful. And I hope that you now share some of the excitement that the management team and I have around the portfolio and see what it's able to deliver and also our excitement about now introducing a dividend going forward. So thank you so much for joining us. If you have more questions, you know how to reach Investor Relations. So please share them with us. And hope -- sorry, I should have said this. Of course, we wish we could have had this entire event in person. I'm glad we had made the plans not to do so because it looks like we're going down into not quite lockdown next week here in London, but something akin to it. So I just hope everyone is able to stay safe through all of this. We hope to see you in the new year and in an in-person event. But in the meantime, all our best wishes for the holiday season in the new year. Thank you so much.