Hello, and welcome to today's Harbour Energy's Capital Markets Day. I will now hand you over to Linda Cook, CEO, to begin. 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 people on our own team had to self-isolate or quarantine over the past few days. In order to avoid any last-minute surprises with speaker availability, we actually pre-recorded these presentations. 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 two 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.
In part two, 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 two 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 three transactions is that we went from 0 to 200,000 bpd 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 three major transactions in under five years. We're generating material and resilient cash flow, and our leverage ratio is projected to be around 1.0x times 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 GBP 0.16 per share, to be paid in equal semiannual installments.
Our first $100 million distribution or GBP 0.08 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 two 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.
Why invest in Harbour Energy? At a time when major oil companies are de-emphasizing 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.
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 three multi-billion-dollar transactions in less than five 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 mid-term 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. 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 multi-billion- 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 200 pence 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 three 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 number one 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. 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 won't. 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. 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. 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. 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. 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. 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. What have we done so far?
In our first nine 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 tonnes. While we work to bring that down, we've already started to purchase offsets with our first investments anticipated to be in two projects in Brazil: forest conservation and landfill gas capture. The total credits being acquired are 1.2 million tonnes to be purchased for a cost of around $10 per tonne.
We currently intend to apply 1/3 of these to offset our emissions in each of 2021, 2022, and 2023. 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 in finding this in conventional producing assets.
Assets that are accretive from a portfolio standpoint, meaning margins, emissions per barrel, and reserves life. Assets that are accretive financially, meaning cash flow. 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 three transactions. There are similarities in the Shell and Conoco acquisitions, where we purchased assets no longer deemed strategic from two 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, add 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. 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 bpd 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. Phil's 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 gonna 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 gonna take a more detailed dive into the business. Firstly, you'll have already heard we're reiterating 2021 production guidance. On a pro forma basis, we're at 185,000-195,000 on a reported basis, 170,000-180,000 boepd . On the reported basis, we're forecasting 175,000 bbl, 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 at between 195,000 and 210,000 BOE. We've got a good line of sight staying around that 200,000 bbl 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-$16 per BOE range. Again, as we begin to deliver on the organization, the integration, the associated synergies, we're getting 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 three-year short-term plan, are high quality and generate material returns. I'm gonna talk about that a little bit later.
The majority of our projects in 2022 deliver returns at over 50% and potentially even more at current pricing. As I look back at 2021, 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 five years on that, showing around the $300 million mark per year pre-tax spend on decommissioning that we've talked about before. Later on, I'm gonna 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 while 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 hazards 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 covering 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. We're 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.
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 two train as a good example. Now this chart shows production performance by field across the complete Harbour portfolio. We've discussed at our last update some of what happened, but you can see easily on this graph the Elgin-Franklin outage together with the summer shutdown 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 were going on. Production in October and November has been around the 215,000 bbl a day mark, and it looks like we're gonna 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, but hovering around that mark, and that's right across the operated portfolio. We've had new wells coming on stream, Buzzard Phase II, 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. 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. While Tolmount has been the source of some frustration, I can report good progress with getting to the bottom of the previously reported ATEC's 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 inspect and 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 were worried about are now all delivered offshore.
We have the Valaris Norway in place at the 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 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 four wells, development wells, completed and available for production at first gas. As we mentioned in our interim results, the third well encountered a shallower gas water contact than we expected. While initial production rates are gonna be around that 20,000 bbl a day mark, they're unchanged. Unfortunately, the current and preliminary estimate of net reserves is around 20 million-30 million bbl of oil equivalent.
That's around 25%-50% lower than at sanction. 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 Tolmount 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. At Havel, we'll 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 gonna 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 for the group is U.K. gas, which is really accretive barrels. You can see we've been active across the non-operated portfolio. Buzzard Phase II's 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. Then further afield, we've had great results on the Tuna field in Indonesia. 2022 is gonna be a busy year across the portfolio.
Bob and Stuart will say a little bit more later about what we're doing. Now 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 Dunnottar exploration well that we're drilling at the moment on the J- Area. We should have those results in the first quarter, but that's 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 benefiting production. A really interesting well that I look forward to talking to you about in the new year.
Having heard Linda and I speak about the forward guidance 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 2023 and 2024. You can also see where we've come from, how we've grown the portfolio over the last few years, what we're gonna deliver this year in 2021, and then how we actually intend to get to the 2022 guidance that we've told you and the market. We have natural decline. North Sea, if we did nothing with some of the fields, they would 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 2021 to 2022, so we're gonna have less planned downtime. We'd hope with some of the work that we've done, some of the things that we've learned, we'll have less unplanned time too. You can see what we're gonna add with Tolmount, but over on the right, you can also get a flavor for some of the new wells that are gonna be coming on stream through the year. You've heard us talk about the three wells we'll be drilling in the Catcher area. We've got production coming on in South East Asia through an infill program. We've had Buzzard Phase II. We're gonna 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 gonna be coming on around the year end, and we'll see production from that and the rest of the program through in 2022. As you can see also here, we show 2023 and 2024. We've talked quite widely about sustaining CapEx, round about the $12 a barrel mark for the production we take out of the ground to keep delivering on that portfolio. 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 bbl 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. It demands real focus on what's important, spending the right dollars, making sure there isn't waste in the business. That's been done through COVID, that a lot of society has had enormous problems with. I'm really proud of the effort that the team has put in. We've also begun the integration of the two businesses. There are costs in here that I don't intend will be in the operating base for the long term. You may see improvements on the onshore elements of that cost, but it's gonna take a little time to deliver.
Now over the near term, we're targeting that $15-$16 per BOE range. Subject to foreign exchange, you remember the vast majority of our costs in the U.K. and therefore the group are in sterling. Then, subject to that and production performance, I'm confident we're gonna 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. 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.
Now it's gonna take some time to improve on where we are to deliver tangible cost savings. We're aiming to have completed our office and systems rationalization by the end of 2022, and we should have a final state organization in place. The interim reorganization is nearly complete, but it's gonna 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. It's only as the organizations come together that we're gonna 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 the 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-operator portfolio, where we work with other companies and are lucky to have good alignment and good sight of what's coming next. If you go down the list, you can see Greater Britannia Area, J- Area, our U.K. hubs, and Southeast Asia, and you can see the non-operated hubs.
You go across, you can see the areas that we focus on. Some of the easy wins, where we're doing things to improve performance, plant, and efficiency. Infill drilling targets, and you'd be pleased to know that we have a great sub-surface team working right across the portfolio. 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. 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, but also third-party business.
In some ways, the North Sea has moved on quite some way from 10 years ago. We, as a company, as Harbour, are leading those initiatives, working really closely with other third-party owners where we would hope to bring their volumes across our platforms, thereby improving our own unit cost materially. You'll have seen us do that with the Finlaggan field that's come across Greater Britannia 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 new organization.
We're always asked about decommissioning, and Alexander will talk about managing the balance sheet and our spend profile. We just wanted to reiterate here the significant competence 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, we've 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 competence, we have a real double benefit for Harbour. This slide shows some of our emissions reduction work. We have a $150 million forecast spend on emission reduction activities in 2022, 2023, 2024 across a variety of projects. They've been reviewed as part of our annual budget process, and that's targeted at things like improving process efficiency, power generation and compression upgrades, energy efficiency, plant optimization, finding fugitive emissions, and low carbon design for the future. Most of the projects have low cost and robust returns. As we head into looking deeply at electrification of the key assets in the North Sea, this is gonna need much more.
It's gonna need collaboration between industry, government, and a variety of regulators to make it happen. Harbour has interest in two of the five potential carbon capture clusters in the U.K. We and our partners and our emitters continue to work with the regulators and government to progress our cluster plans, either as Acorn, a reserve to the potential track one process or as V Net Zero, currently in Track 2, but with a 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. V Net Zero is 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. We're 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 three 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. 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 while production has been, and also how we're aiming to convert contingent resource into reserves, and indeed, bring prospective resource near to our hubs and bring 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 Sea Lion, but it does include some other contingent resource that we acquired with the merger as the two companies came together, but from the Premier side. You'll hear more about the successful appraisal results we've had on Tuna and progress we'll be making with the Zama potential development in Mexico.
We've used this slide or similar before to reinforce what we've delivered over our two previous acquisitions, the Shell and ConocoPhillips U.K. portfolios, but 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 and conservative levels of debt to then acquire the ConocoPhillips U.K. portfolio, we more than replace production. That's reiterating the message on the previous slide. We invest to convert resource into reserves while 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 in systems. In the first quarter of 2022, we'll consolidate to one London office and plans are already in train to consolidate in Aberdeen, albeit from three to two offices in the short term. We've seen potential savings across the supply chain, and those benefits will continue to be delivered over the next two years. Thank you. I'll now pass over to Alexander, our CFO, who'll talk us 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 two topics. First, I will cover our guidance, three-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 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 multi-billion 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 break-even 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 resource, thereby extending field 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 three-year period. Let us start at the top with our revenues. We have 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 are marketing some of our products in-house. We do have a mix of grades, where some achieve a premium to Brent and some a discount. On balance, we are probably at Brent pricing, maybe just slightly better. Repaying the $400 million Shell junior facility is 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 two years and in the upcoming three-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 - 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%. 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 three minimum hedging requirement of 30%. We still have the year one and the year two minimum requirements and the same maximum requirements. 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 three years, staying in a range around $15-$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 to a 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 three 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. 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. Any 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 five key operated 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 two 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 one to two wells in the U.K. and two to three wells in Norway. In the international BU, we have the two commitment wells, Wahoo and Pike in Mexico, and then we are excited about the Tuna one well in the Andaman Sea in Indonesia. Looking ahead to 2023 and 2024, we have less visibility, but we do expect P&D 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 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 pre-tax spend. Beyond this, we see the spending level trending downwards. We also expect a significant part of the decommissioning 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 is important to note that this is a pre-tax 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 years' 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. 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 reduce 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. Finally, in this part one guidance section, let's cover the capital structure. Today, our capital structure is quite straightforward. We have one 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 rating this autumn, 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 drawings 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 three years. 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 three equally important priorities. Firstly, safeguard our balance sheets. 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 three capital allocation principles in turn, starting with principle number one, 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 sub-limit, and a borrowing base currently set at $3.3 billion. This borrowing base will be determined at thJune 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 two 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. Both Phil and I have 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 31st, down to $2.6 billion at June 30th. We now expect net debt to end the year in the $2.3 billion-$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 a 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 sheets 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 two 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 at $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 three-year capital allocation outlook. Starting with post-tax cash flow and deducting decommissioning expenditures estimated at 15% of cash flows, we're then looking at capital expenditures to E&A and P&D of around 50%. This leaves us with around one-third 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, we project that net debt will continue to drop every year. Finally, moving to the summary of our guidance for 2022. Now, before we talk about next year's guidance, let's take stock 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 31st, likely around $75 million less, as some of these activities were deferred into 2022. Looking forward to 2022, I think we have an exciting year ahead of us. We are guiding on four items.
Production, we're setting a range of 195,000-210,000 boepd , where the exact timing of Tolmount startup is the largest uncertainty. We expect OpEx to be in the range of $15-$16 per BOE. CapEx is estimated at $1 billion, and we estimate Abex to come in at around $300 million on a pre-tax basis. 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 gonna end it here with a reminder of our investment proposition. I think you've seen evidence around all six 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 two. But we thought this would be a good point to stop and take some questions. We'll turn now to our live session coming to you from our offices in London. Hello, welcome. Now we're coming to you live from London. I'm here with Alexander and Phil Kirk, and, you know, 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 we were 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. With that, let's open it up for questions.
Thank you. As a reminder, if you'd like to ask a question, please press star followed by one on your telephone keypad now. When preparing to ask your question, please ensure your headset is fully plugged in and unmuted locally. That's star one on your telephone keypad. Our first question comes from Nathan Piper of Investec. Nathan, please go ahead.
Afternoon, everyone, and thanks very much for this, 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 us a line of sight on this 200,000 bpd over the next couple of years. I don't wanna put this the wrong way, but is that it? Would we expect to see this portfolio decline quite sharply at that, after that? Or could the existing 2C resources do more? Is the potential to extend that plateau further? Or effectively, do you need to have some either new discoveries at Dunnottar or appraisal success to push out this 200,000 bpd base case? That's my first question.
Let me ask you about that first before I move on to the next one.
Great, Nathan. Thank you. I'll take that question. First, I'll remind you that in our 2P resources, our R/P, our reserves life is somewhere between six and seven. We don't have to completely just rely on the 2C to go beyond three years of production. 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 three, 2024. We actually have quite a material amount of forecast spend for both of those projects in that year. That's part of the spend that you see, but not any of the production, because of course, those projects don't start producing till after that time.
Yes, it's possible we can continue to maintain production at a level of 200,000 bpd for longer than the three 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 line of sight for the next three years, given the stage we're at only eight 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 ones there. On a CO2 per barrel basis, you've given us lots of guidance over the next couple of years. Can you give us a kinda direction of travel on that out to the same sort of timeline out towards 2024? The other quicker question. So far not too much in terms of cost pressures from an 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? That'd be interesting to get a bit more color on that, please.
Yeah, thank you. Let me say a little bit about our CO2 intensity, and then Phil can talk about inflation 'cause he's right smack in the middle of all of that in the U.K. Our emissions per barrel are kind of in the mid-20s. Not exactly sure where we're gonna end up this year. Keep in mind that everyone measures them a little bit differently. We're looking at Scope 1, Scope 2, operated and non-operated. That's probably where we're around average in the U.K., maybe a little bit better than that. Doesn't mean that that's satisfactory for us. 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 two or three years ago, in particular in the U.K. As you saw in, I think, one of my charts, you know, 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. Let me let Phil talk about the inflation question 'cause it's one we get a lot.
Thank you. Thank you, Linda. I think our emissions actually include mobile units, which some people don't include. There is another difference. We've obviously stepped up activity in 2021 with less production. In terms of inflation, that's a really interesting question we've been asked a lot recently. 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 will know. We would hope they would stand with us. Linda.
Thanks, Nathan.
Thanks very much, everyone.
The next question is from Chris Wheaton from Stifel. Chris, please go ahead.
Thank you very much indeed. 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, 2023, and then 2024 and hold it there versus 2022. I wondered if you could talk about the drivers. 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. I have a second question to Alexander on the financial strategy, but perhaps I should stop there first, Phil.
Thank you. Thank you, Chris. 2022 we're on a per BOE. We're obviously driven as well by production levels. If we set that aside, in previous years and in 2022, we do have integration costs. We do have other one-off costs feeding through. Simplistically, we have a lot more offices than we would like, a lot more locations, a lot more systems, a lot more ways of working. A lot of effort of the integration as we bring people together is to standardize on the way we work. 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. We have multiple suppliers for all sorts of services.
That takes some time, particularly with COVID and particularly as we just bring in the organization together. I think we're being conservatively realistic about where we're looking at future projections for OpEx. We're already beginning to rationalize offices. Our systems work is going well, despite COVID and all the other challenges everybody is facing. The team working really well. I think through 2022 and into 2023, you're gonna see us deliver more efficiency and more performance on the operating cost side. Hopefully that helped, Chris.
That's great. Thank you. Can I have a follow-up and ask what you're assuming for your uptime over that period you talk about on Slide 36? Is there a material change in uptime and therefore the delivery of production from the portfolio?
Is there material change? We had some disappointed 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 was stepping up from September, that we're all really pleased with. That, as I think I said on the video, our operated assets have been over 90%, and as a portfolio around 90%, which is really good. That is ahead of the U.K. traditional average. We have made slightly less bullish assumptions that performance will be maintained throughout 2022 and 2023. Where we think it's realistic, we do hold ourselves to high standards.
Traditionally, a lot of the platforms would be towards the top quarter, but we've been realistic about our estimates.
That's brilliant. Thank you very much indeed. My last question to Alexander, if I may. Your presentation, Alexander, could you talk about where you think the balance sheet envelope should be at the leverage of 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 EBITDA, that's going to flex with commodity pricing. While 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 EBITDA do you think you ought to be if the oil price is $80, and perhaps more pertinently, we're seeing gas prices like we are on the screen at the moment?
Yeah. No. Thanks, Chris. As you know, it's a 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. I think what we've said is that, you know, just through the cycle and when we think about possible, you know, acquisitions and things that we've seen in the past, we've said that, you know, it should be below 1.5x. I also think, you know, when, if you have commodity prices at $80, so you have, you know, 200p well it's a good, sensible thing to do to, you know, pay down debt in that period when commodity prices are high.
Now going from a little below 1.5x at the closing of the transaction with Premier and Chrysaor now down to closer to 1x. You know, I think that's in line with what we've said and strategy to delever and post such acquisitions. You know, being below 1x when oil prices are high, you know that, yes, that feels comfortable. Again, it's just gonna be a capital allocation decision on, you know, how much money do we wanna spend in new projects, paying down debt and then, you know, introducing the dividend.
Okay. That's great. Thank you very much indeed.
Thank you.
As a reminder, if you'd like to ask a question, dial star one on your telephone keypad. The next question is from Werner Riding from Peel Hunt. Werner, please go ahead.
Afternoon, sorry. 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 isn't ILX or PLX-led. I'm just interested to hear how that fits with 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. 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, you know, almost everything else we talked about today. We believe our existing resource base, the one that has been formed through the combination of the three 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 bpd and generate material free cash flow, and to do that for the next three years. For the near term, maybe longer, too early to say. That's what we tried to lay out today. Beyond that, we've said we wanna 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.
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 years and maintain production levels in a material place. 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. 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's gonna be pretty rich for us in the coming years.
We just believe that's a lower risk and 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. Thank you. Got it. In terms of a new potential hub geography outside of core areas in the U.K., when thinking internationally, you know, 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 a, you know, comparable or a good-sized production base there. Could size M&A happen in Norway as well?
Yeah, we look in a number of regions, and this is a question we oftentimes get. Norway is a logical place for us to look because it's, you know, across the fence, you know, from our main heart of production today. The challenge with it is the good news is, you know, 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 other companies who would love to have higher quality and more assets in that region as well. We would expect there to be competition. That's not a dynamic that, you know, that we tend to like if we have other options. That's Norway. We like it.
Maybe hard to really create value if there's a strong competitive dynamic. Southeast Asia is another place that's a logical place for us to look. We have good production today in both Vietnam and Indonesia. There's strong energy demand for a long time to come, in particular for natural gas in the region. 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. There are still today some pretty strong national oil companies and one or two regional players who can provide competition.
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. 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, you know, TBD. 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. Those, just to give a bit of color around three of the regions that might be of interest to us. Hope that's helpful, Werner.
It is. Yeah. Thanks very much.
The next question comes from Matt Smith of Bank of America. Matt, please go ahead. Great.
Thank you very much, and 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 glance, you know, 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, you know, 40,000 bbl of sort of new projects coming on-line 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 the sort of reason for this, you know, conservatism, if you think that's the right word, is because the natural decline portion perhaps looks larger than the sort of 10%-15% that I think was referenced before. I'm wondering if that is what's playing into the sort of higher CapEx number going forward versus the current year. That'd be my first question for a bit of color around that, if that's okay. 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, you know, why you sort of favored the dividend and, you know, if the buyback could become part of discussions going forward, please?
Thanks, Matt. I'll turn it to Phil to help with the first one, and I'll take the second one. On the first question, just remember the 215,000 bbl we produced in October and November, that's after all the maintenance season. We had really strong reliability and availability during those two months, which over the course of a full year won't be the case. Let Phil talk about natural decline and the guidance for next year.
Thank you, Linda. It is a good question, and Linda's nearly stolen my thunder. 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. 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.
You also know that Catcher has been producing really well. At some point in time, we're gonna get an increase in water cut on Catcher. Some of that water cut is also based into this decline. We've not necessarily seen it yet. That's not me needing to flag anything, but that is part of how we're looking at decline through 2022. There's those two key numbers in that large orange block that you can see. We've always said, as a reminder, you know, there's. At the moment, everything is going really well, fingers crossed, touch wood. We have a portfolio. There'll be some months when everything is working really well and some months where we have two or three problems and production is hit.
We have to take a view as to where we think the range is, and we're very happy with this level of guidance.
Yeah. Great. Matt, back on your question about buybacks. Yeah, of course, the board discussed a whole range of things around, you know, fixed, variable, progressive buybacks, special dividends, you know, et cetera, as we were debating and discussing what to do for our first dividend at Harbour Energy. The decision this time around was let's start out with something simple. Let's make sure that it is sustainable. 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, you know, we say 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-$600 million. We're expecting at current forward curve commodity prices to generate a lot more than that next year. Should all these things play out, depending on what else happens around the world, what's happening with commodity prices, you know, 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 1st of next year.
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. That's just another dimension for us to think about. Okay, Matt.
Sure. Thank you very much.
You're welcome. Thank you.
Nothing further in the queue at present, but as a reminder, that's star one on your telephone keypad now. 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've divided the presentations up into two parts. This was kind of corporate level part, high level view. Starting at 2:00 P.M. U.K. time, the videos for the part two presentation will start. This is mainly Bob Fennell, Stuart Wheaton. They're gonna go through asset by asset all of our key producing fields and talk a lot about the opportunities. They'll help answer some of the questions you've already asked today about our resource base. I think you'll find it interesting. Then we have a couple videos actually coming from location from some of the people who are a bit closer to the coal face 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. That'll happen around 2:30 or 2:35 U.K. time. We hope to see you back then. Thank you. Welcome back from the break and to part two 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. 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 video from some of our asset leaders. 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-1980s as a drilling engineer. I spent the first 20 years of my career in various drilling and 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 and lived in France, Norway, Yemen, Canada, and even in Alaska. Out of 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 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 gonna pick out a couple of key messages from each asset, but firstly, I'd like to highlight four 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, balance the desire for high production efficiency and reliability with cost management, and be proportionate to the lifecycle 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. Finally, heavy investment, such as electrification, where it makes sense. The fourth area is looking at the upside. 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. Moving on to Greater Britannia Area. Greater Britannia Area comprises of the Britannia field and a series of fields called the BritSat. It is our largest producer with sector-leading production efficiency and reliability. The main platform has three-phase separation, gas dehydration and processing, and compression.
The bridge link platform is the access route for the four subsea tiebacks. Liquid export is via the Forties Pipeline System and gas via SAGE. Here to tell you more about GBA is Scott Barr, our Senior Vice President for the operated assets, who's coming to you from Aberdeen Harbour.
Hi, I'm Scott Barr, and I've been managing the Greater Britannia Area for the last six years. The Greater Britannia Area, or GBA, is the largest producer at over 38,000 bbl a day net to Harbour and generates significant free cash flow, which is set to continue well into the next decade. GBA's strong performance is supported by impressive uptime of over 95%. Through targeted utilization and 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've moved to single train operations through plant optimization of our gas processing trains. What does the future hold for GBA? Well, there are three 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 Enochdhu. 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 projections. 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.
Leveret is a discovered field spread across three license areas, and we are progressing this 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. Thirdly, there are also multiple near-field prospects, MacLeod, Shirley, Britannia Midfield, and Bowmore, which our exploration teams are working hard to high-grade and mature. In summary, we continue to optimize production from our high-value hub and have an active infill well program, significant inventory of near-field prospects, leads, and third-party opportunities to pursue.
Thank you, Scott. To reiterate, there is good upside potential in the area which has been refreshed since Harbour took over this asset. This includes both equity production and third-party business, as exemplified by Finlaggan, a two-well tieback which has recently been tied into Britannia. In summary, for Britannia, there are three 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 Palaeocene to the Triassic. It comprises of four fields Judy, Jasmine, Jade, and Joanne, with Judy as the 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 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 continue to maintain strong barriers to ensure we protect our people. Second, we continue to see good reliability from J- Area, and year to date, we are running at over 95% operating efficiency. That's a result of past investments in the asset 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 hopper. 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 J South well. J South was targeting a previously untested part of the Jade field and is the longest well drilled in J- Area thus far and will contribute significantly for the J- Area production next year. Lastly, we spudded the high-impact Northern well in October.
The well targets a Triassic prospect to the east of Judy with a P50/P10 of circa 75 million-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 target. However, the biggest opportunity to reduce emissions is through electrification of J- Area, and this is something that we're 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. 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 on to Catcher. The Catcher area has demonstrated subsurface outperformance and has much further prospectivity. It's 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 from BW Offshore and has full processing for the three fields, which are Catcher, Varadero, and Burgman. Oil offtake is via shuttle tanker and gas goes to St. Fergus via Fulmar.
We have a heavy-duty jackup arriving early in the new year for a three-well campaign, drilling Catcher North, Laverda and Burgman Far East. 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've seen a material improvement in reliability and uptime from better understanding the production chemistry. There is potential for further improvements in production rates from topside debottlenecking, and this is being engineered between Harbour and BW Offshore. Catcher is a great asset with much future potential if managed correctly. Moving on to Ailie. The AELE Hub comprises of Armada, Everest, Lomond and Erskine, which are late life assets. The focus here is on late life asset optimization to extend life.
Armada is a fully integrated platform of late 1990s vintage and exports back to the CATS tower at North Everest. North Everest and Lomond are early 1990s 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. What does late life asset optimization really mean and how does it differ from the other three 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 decommissioning 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 investment and workforce engagement has materially improved operating efficiencies. For example, Lomond and Erskine had production efficiencies less than 50% and now competes in the high 80%. 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. Now moving on to our non-operated ventures, where we have dedicated subsurface teams to ensure we have an independent view on investment decisions.
We also call on our operated depth to ensure a two-way transfer of knowledge. 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 number 14 out of 36 planned. Clair Phase 1 will go back to drilling at the end of 2022 with a four-well campaign, and Schiehallion is starting planning of a four-well 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 oil line pumps were replaced. 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, having spent most of the 90% working on the exploration and appraisal and development of the fields when I worked for Elf. Interestingly, when we drilled the discovery well on 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. 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 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 PanCanadian 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 oil field with high uptime for the sector. It is a large complex of four bridge-linked platforms with most production wells centrally located and water injectors subsea. Buzzard phase two is now online and was delivered within the revised schedule. This was revised for COVID and within budget. Two of the wells were not completed and form 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 tie-backs. 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, is 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 topsides overhaul in 2025, which is tied to the tertiary development opportunities. There are currently three compression trains on Alpha with old technology and associated reliability. Here we have an opportunity to combine a future development with modernized equipment, which will 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. Now turning to the international portfolio. However, please let me introduce myself first to those not so familiar. I'm Stuart Wheaton, now the Harbour EVP for the international business. Previously, I was with Premier Oil for about five 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 past favorite roles have included subsurface manager in Cairn India throughout the discovery and development planning of Rajasthan, which became the famous 200,000 bpd 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. 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, the Falkland Islands, is progressing positively with ongoing discussions with our partners and the Falkland Islands 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. Starting at existing Chim Sao and Block A, these remaining high performing and attractive cash generative assets, though both are now pre-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%-95%, including planned shutdowns when they're needed, and 96%-98% without the planned shutdowns. This is really excellent and sustained by the strong operating teams in both locations. 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%-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 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 workover at Block A added about 23 million scf a day gross.
In 2022, we'll be back again to do the same at Block A, while at Chim Sao, we've also sanctioned a two-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 on 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 two step out appraisal wells and completed an extensive data acquisition in full. This included three drill string flow tests across the two 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'd 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 and 10 million scf/d gas were delivered in the gas tests and over 3,000 bbl of oil per day in the oil test. Importantly, we also saw high condensate yields in the wet gas tests, higher than expected, about two times 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 at Tuna. On the slide, we have a breakeven of NPV10 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 tree 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 leased FPSO case, we could be looking at around $6-$8 per BOE unit CapEx cost for the scheme, an overall unit technical cost through field life, i.e., CapEx and OpEx and leased altogether of the order of $20-$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 40-50 kboepd , 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 Indonesian regulator, SKK Migas, about our forward project timeline to sanction with their very positive support indicated thus far. We show a summary timeline here, and we believe this is realistic with the 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. 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 of Northern Sumatra, Indonesia, in particular, our 40% operator position on the Andaman II license. Our partners here in the license are BP and Mubadala Petroleum.
We have already contracted a drill ship, the West Capella, to drill the Timpan one 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 depth. The cost of the well, including a DST and setting up the remote logistics, is of the order of $80 million-$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 play opener in the region, but of course, nothing in exploration is a given, but we proceed with good confidence. We've carried out various pre-development 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 infrastructures 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, it's these large depleted fields in the area like Arun, which also potentially open up an exciting scheme of some scale. This could well involve early carbon capture and storage for emissions disposal. You can envisage a carbon zero 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. 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.
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, WDA and Harbour engaged with Pemex and SENER, the Ministry of Energy in Mexico, before 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, WDA 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, we plan currently 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 interests, actually quite near to Block 7, Zama. Here, WDA are the operator.
Plans and rig contracting in place to spur the first of two 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 mid-size oil target, and the second at Pike considered a lower chance of success. If we have success on Block 30, these mid-size 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 area such as Pan American. Looking back, to summarize our current international picture, starting with continued steady performance with incremental investments at Chim Sao and the Tuna, Block A.
A successful appraisal campaign at Tuna I talked briefly about this year, and we started the work to get us to sanction and then first production, an attractive and important project in Indonesia. 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. 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. 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 bpd 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, two 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, and we apologize for the challenges and difficulties. With that, we'll open it up for Q&A.
If you'd like to ask a question, please press star followed by one on your telephone keypad now. And if for any reason you'd like to remove that question, please press star followed by two.
We take our first question from Sasikanth Chilukuru from Morgan Stanley. Your line is open.
Hi, thanks for taking my questions. The first one was related to the presentations on the asset base. It was mainly related to the production outlook beyond 2024 and the associated CapEx. You 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-$900 million for 2024 includes the CapEx associated to this production upside, or whether this will lead to an increase in CapEx as in 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?
Yeah. Hey, 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. The CapEx levels that we've set for the company of around $1.3 billion all-in everything for the next three 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. 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. 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 bit. 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. 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 problems earlier. 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 three years. There is quite a bit of CapEx in some of those outer years that relates to those later years production profiles. You can see in the medium term, we see J- Area production increasing, and just in the last period, we're gonna get the Talbot Field, all being well, fingers crossed, coming through. 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 gonna hit production until 2025.
We also have some significant process de-bottlenecking that we'll do on Britannia that should realize more production from fields like Brodgar, and that will go hand in hand with the Leveret development that we would hope to progress with some of the partners in the area. I don't know if that helps, Sasi. We you know, 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. Just related to the production profile and the more nearer term, you did highlight high underlying production declines and in Slide 23, and also of course the good line of sight in arresting this decline. In 2022, we have a big contribution from a startup, Tolmount coming in, adding 15,000-20,000 bbl, around 8%-10% of the production. If you were to look at 2023 and 2024, are there any specific projects or tiebacks that significantly arrest these decline rates?
Would it be essentially a series of new wells and infill drilling, almost double what is guided for 2021 or 2022, for 2023 or 2024 onwards?
Okay. Thanks, Sasi. I tried to answer that decline question earlier, where I reminded everybody that decline was against the year-end exit rates. I said there were two specific still unknowns, a decline on one of the big Callanish wells that we've got on the Greater Britannia Area that could drop by 5,000-6,000 bbl a day, and also exactly when we see increasing water cut on Catcher that we haven't as yet seen. We do expect that in the future. There is two 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 tie-back.
Say we will undoubtedly be developing Talbot, which is one of the biggest spends over the period. Tuna and Zama towards the end of the period, with only production from the U.K. project just coming into 2024. 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 gonna see a lot of benefit from that until 2025. On the NOV portfolio, we're continuing to drill on Clair, albeit a smaller equity.
With our partners at Apache on Quad 9, we continue to drill the tertiary play that is semi, is in the E&A numbers. Actually we're increasingly confident with some of those targets. We'll be spending a reasonable amount of development capital for the discovered resources we've already got that will lead to production just at the tail end of that three-year period. Mainly a think outer period. You can probably see it on the charts. Those are the highlights, Sasi. No massive big projects other than the ones that 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.
Thanks, Sasi.
Great. Thanks. Very helpful. Thank you.
We take our next question from Mark Wilson from Jefferies. Please go ahead, Mark.
Thank you. Yeah, good afternoon. 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 there flexibility depending on how commodity pricing and operations are going by the time we get to 4Q? Just wanna check that. Thank you.
Yeah. Hi Mark, thanks. I'm glad you were able to get through. At the AGM in the spring of next year, the final dividend for, with respect to 2021 financial year will be there for approval. 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. We expect that interim dividend with respect to the interims would be paid in either October or November, I believe. That would just require board approval, Mark. Things could be, there would be an opportunity for the board to reconsider the level should they choose to do so at that time.
No, that's absolutely what I was looking for. Thank you for that. Alexander, if you just wanna 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.
Yeah. Thanks, Mark. Yeah, no, we did put up the actuals there and the decrease that we're expecting is. That's group level. Now, 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. That will be a debit to that number. In exploration, when we talk about spending of around $200, well that is pre-tax Norwegian spending that's included there. That does bring the overall group cash taxes down.
Not all of the $200 is Norwegian exploration spend.
Yeah, no.
Sorry, Alexander.
No, that's okay. There's some exciting Timpan stuff and other things in there as well.
Got it. Okay. Last point. The slide on 2P reserves looks like it's. You mentioned Phil described it as flat, and it looks like it's roughly around the 500 MMb level. You know, the pro forma number we've seen in the past was around 600 for the combined company. Can we talk to the moving parts there outside of production? Then if there's that related to Tolmount now, the delta that there is between the range of reserves you speak to. Thank you.
Yeah, Mark. 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. Yes, I think that was part of your question. Then of course there's production, 70 MMb or something of production comes out of that as well. There have been a couple other adjustments too. Yeah.
Yeah, Mark.
Got it. Okay.
Sorry Mark, it's Phil. Obviously we have shaded this. We're trying to estimate where we're gonna get to with a reserves auditor, and there's always some uncertainty around these things. There's been some good things that have happened recently, but probably won't get those into year-end reserves cutoff. There's been a couple of things probably through the year that have been more disappointing and then followed by good things. It's deliberately hatched and hazed, while we finish all that work off, Mark.
Okay. Thank you. I'll turn over the Q&A for the moment, please.
Thanks Mark.
Our next question comes from James Hosie from Barclays. James, your line is now open.
Hi there. Yeah, I guess I'll start just following up on Mark's question there a little bit, about reserves. Obviously you flagged the reserve cut at Tolmount. I'm just wondering when we can 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?
Oh, yeah. Let me let Phil take that.
I mean, sorry, James, I tried 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've made, and there's probably some timing in there. There are some things we probably won't have sanctioned but do expect to go ahead. Probably won't put those into reserves, James. That was what I was trying to answer before, is that there's some good things have happened, but whether we have all the information in one place, in time. You know, we're not going to have sanctioned some of the developments in time for the year-end.
Okay.
Sorry.
If I could just turn over to the Tuna and Zama projects. Can we take your inclusion of these assets in your 2022 - 2024 spending plans as an indication you intend to retain your current stakes in both of them?
Yeah. 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, you know, 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, you know, mantra around making sure we're continuing to always balance the balance sheet versus reinvesting in the portfolio versus distribution to shareholders so.
Okay. Could you quantify how much is gonna be spent on those assets pre-FID in, I guess, probably 2023 you said?
Yeah. Maybe let me see if Stuart has an answer to that, you know, on FID or other things for the two projects. Stuart?
Yeah. The magnitude for Tuna is around about $20 million gross to get us to a sanctioned decision. Zama will be similar. Zama might actually be a little bit less because we've done a lot of front-end work already. There will be some reworking with our ideas with Pemex. Yeah, of that kind of magnitude to get us to a decision.
Okay. Thank you very much.
Sure, James.
The next question comes from Matt Smith from Bank of America. Matt, your line is now open.
I wanted just to go back to Slide 45, the three-year outlook in terms of capital allocation. Just sort of wondering about the absolute levels of cash flows that's being highlighted, but also sort of sensitivity there. I mean, it looks as though, you know, 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've put in the footnote. 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.
In that light, you know, 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, say, some upside scenarios on the commodities?
Yeah. Matt, I'll let Alexander take first shot at that.
Sure. It's Matt, it's an illustration of what we think is achievable just with the you know 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. We haven't guided on a net debt level for each of the years. You know, but we've given most of the building blocks I think in just each of the slides before this. It's a yeah, there's some flexibility in that spending as you'll see, but it would depend on a variety of factors, not just you know natural gas prices and oil prices and future hedging levels.
Several things going into that estimate and spending levels as well. 2025, we definitely see that as achievable. You know, if it would be, you know, potentially sooner than that would depend on, you know, a variety of those factors then.
Sure. Perfect. Just to clarify then, sorry. The footnote on the assumptions on commodity prices is a group sort of realized price post hedges. Is that what we're saying there?
It's forward prices for 18 or 24 months that we've used. Yes, we've used the actual hedging position that we spelled out on one of the earlier slides, I think.
The commodity prices shown in the footnote are just that, the commodity prices that we're using, not our realized price. Right, Alexander? Yeah. Did that make sense, Matt?
Yes. Yes. Thanks. Understood. Thank you very much.
Chris Wheaton from Stifel takes our next question. Chris, please go ahead.
Great. Thank you very much indeed. First and perhaps easy question. On Slide 44 you talk about dividend. You said there'll be a final dividend of $200 million and then an interim dividend of $100 in November. That's gonna make $300 million cash paid in 2022. Is that correct?
No. Sorry, sorry, Chris. The policy is $200 million distributions per annum. Our first distribution will be after the AGM, and it'll be $100 million. It is with respect to 2020-2021 financial year. For the financial year 2021, it's a $100 million dividend. Then the second distribution next year will be after interims. That'll be another $100 million. For calendar year 2022, the outflow, if you will, or the total distribution to shareholders will be $200 million.
Right. Okay, that's right. Okay. That clarifies that bit then. It is $200 million that's split. The first interim dividend of $100 million is included in that first $200 million. Okay. That's very helpful to understand. Thank you. The second question I had was relating some of the more project-level details, and I thought that was really helpful insight. Thank you very much indeed to your team for doing those videos. You've given us on Slide 37 a breakeven chart by spend for 2022. Could you describe what the shape of that chart look like in 2023 and 2024?
If it goes back to the question you had a few questions ago about what's that incremental return on, effectively incremental return on capital employed. Actually is it pretty much the same in 2024? That's for that slide on Slide 30. That 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 most of our projects breaking even at $30 or less, and that's for projects we're executing next year. Your question is, would that look the same for the projects we're executing in 2023 and 2024?
That's right, because I think the question before was picking up on this issue of what's your incremental capital employed look like, and is it pretty constant over the next three or four years? Does it tail off? That's why the 24 number compared to that chart would be quite interesting to understand.
Yeah. 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 two or three years from now. Because for the projects we're executing next year, we already have firm cost estimates in, we have AFEs prepared and in some cases already approved. All of the subsurface technical work has been done. That's not the case for the later projects, including things like Zama, Tuna, some of the other things we've talked about. 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.
Phil, you wanna add?
If I just add to Linda. Yeah. Everything that's in this deck is real. There's no I mean, there might be one or two 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. 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. I don't know if that helps you. With that, Alexander.
Thank you. That's really great. That's really, really helpful. Thank you. I guess then the follow-up to that would be if you have, if your capital constraint is basically organization, it's not financial, that then has got to have implications for returns to shareholders. Because it seems to me that you've got quite a bit more cash you could be returning to shareholders should you choose, given, as you just said, Phil, you're being conservative on your project suite. You don't want to expand the operating envelope beyond that which you're absolutely sure you can deliver. I'm interested then in that potential upside in shareholder value, shareholder return of value to shareholders. Which I guess is a question both for you and also for Alexander.
Yeah. Thanks. But I understand how you're looking at it. 'Cause we do say we have, you know, $500 million-$600 million of excess free cash flow this year. We're saying for next year it's gonna be even more than that, you know, 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.
We feel good about the spend level. You know, 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. We're comfortable with the spend level. The question would be, you know, what would we do with the money beyond what we're gonna need for that CapEx program? I think Alexander can talk a little bit more about how we think about then allocating that.
Yeah, thanks, Linda Cook. Well, I think you took all the good notes, and we're comfortable operating at the level that we're doing. You know, there's competition for capital, and you know, we've set out the investment hurdles that we wanna follow. If we have projects that break even at $25 or $27 per barrel, we think that's, you know, those are good projects. That's the stuff we wanna do. You know, 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.
Now potentially paying down a bit of debt when commodity prices are you know reasonable, that's you know that we think that's a good idea. The question will be for the board you know whether it makes sense to you know do you know additional dividends or buybacks or so in addition to paying down debt. That's something we you know hence the annual review that we instituted.
Okay. That's very clear. Great. Thank you very much indeed.
Thank you, Chris.
Thank you.
Our next question comes from Philipp Duffner from Aurelius. Philipp, your line is open.
Hi. Thanks for taking my question. I have a question on the Slide 53 and 54 for the GBA and the J- Area. For both of those, you show a lot of upside in the 2025, 2026 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 you know, in terms of how we think about CapEx needed to realize that upside.
Great. Phil or Bob?
I'm gonna let Bob answer.
Thanks, Philipp, for the question. I think you know, if we think about Britannia and J- Area, we've got two drill rigs working at the moment, and we're seeing the production coming through from that. Britannia, we're working up all of the options, and there are many around the area at the moment. Subsurface work is going on. What you see in Britannia in the outer years is the Leverett prospect. That goes across three licenses and is being worked up jointly with a couple of companies. That's at early stages, but we're working that jointly.
We do see, you know, obvious potential for that to come through. We continue to work the J- Area as well. Well, I think the challenge that we have, particularly on Britannia, is to try and accelerate some of this work. 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. Leverett is a discovered resource with four wells on it. Actually, we need to right-size that potential development, and it actually gives us an option. Another kick that you'll see in production is we may be able to develop Leverett in a way that will help one 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 associated, but they're real. These are real volumes. It's not just a blue sky. There is 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 gotta spend, you've gotta do the work right. Is that helpful, Philipp?
Got it. Thank you. That's helpful. I just wanted to ask, in terms of the guidance, like, what are you assuming for Tolmount startup? When does it happen during Q1? Lastly, the $500 million-$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?
Tolmount starts up next year. I think that's one of the reasons for the sort of wide guidance we gave of 195,000-210,000 bpd for the full year, accounting for whether or not Tolmount starts up at the early part of Q1 or the latter part of Q1. We've assumed kind of a range around that, if you will. On the cash flow number, Alexander, comparing first half to second half, maybe. I don't know if it's reported versus reported.
Yeah, the question might be, Philipp, if it's around reported versus pro forma, where, you know, the $500 million-$600 million that we were alluding to, that was on the reported basis. I think we had around, was it around $300 million or so in the first half of the year. You know, perhaps around the 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.
Yeah, 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. Why is the cash generation not stepping up significantly from H1 to H2?
Well, yeah, it's definitely more CapEx. If you remember when we updated this in the interims, we talked about how much CapEx we had spent in the first half, or up until June 30th. Then how much was then expected to come in the second half of the year? CapEx, you know, back to Phil's point on maintenance and what's been going on in Q3, then 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, you know, lower prices than that. You know, we also show this on at the interims.
Those would probably be the two main reasons there.
Got it. Thank you.
Next, we have a question from Al Stanton from RBC. Al, your line is open.
Yes. Good evening to you, good afternoon. The tax Slide on 39, as Mark pointed out, it is probably lower tax than many of us were expecting. 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, you know, 'cause you're hedging at $60 and GBP 0.43 a therm. You know, if you were getting market prices, what would your 2022 tax bill look like, and what would your 2023 tax bill look like?
The second question, that was a really tricky one. You, you're gonna have to give me some time to think about that one. The first question on taxes, I don't know where we're in everyone's estimates on this. You know, clearly the starting point is that we're probably the biggest investor on the U.K. continental shelf. So we are, you know, 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. Hedging plays into that, unfortunately, I suppose. This year, then it's also the fact that it's on a groupwide basis.
If we're spending money on exploration in Norway, we've just decided to show that gross. You have the gross spending on exploration, and then that tax refund is coming in as a net. As an example, if you've been or we have been exploring 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. It's also cash tax per year. 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. It's those are probably, I'm guessing, the factors that plays in this year.
You know, happy to review that in a bit more detail later.
Can I ask as well, just a really simple question then. If the prevailing gas price is, let's say, GBP 2.60, and you've hedged at GBP 0. 43, that loss goes all the way down to the reduction in taxation.
Yes. Yes.
Okay. Thank you.
Thank you. Nathan Piper from Investec takes our next question. Please go ahead, Nathan.
Thank you. Just a quick one on Zama. I just wonder 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 gonna play straight? Do you really think that Zama, the project, is going to go ahead on the timeline you've already outlined? Thanks.
I mean, Nathan, they're good questions. Of course, we ponder them all the time ourselves. We're not gonna 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. There are other operators there, and Stuart can talk about them, who are able to work, you know, 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'll all come to a culmination during next year as to whether we're really making true progress. Right now, we feel really quite positive about it. 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. Genuinely, I think you'll be hearing some news about Zama in the next few months from all the parties. Yeah.
Well, I guess to be specific about unitization, are they following a logical, internationally recognized process, or are they trying to fudge it? Or sorry, maybe a bit fudge it or not?
Yeah. No. We, you know, 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, you know, provide the view on that, and it came out 51% Pemex, on the Pemex license, 49% ours.
You know, quite honestly, we have a difficult time really arguing with that one way or another. In any event, Pemex will be the largest interest holder in the field because they own 100% of one license. On our block, it's split between three parties. As Stuart said, it wasn't a surprise to us that Pemex was named the operator. 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 experience is being able to be applied to the field development plan and then the execution of the project, should it go ahead. That's what we're working on now, as Stuart said, having making some good progress.
I suppose the operator of your license wasn't quite so sanguine about it. I guess that's maybe where I'm picking up some of the surprise around how things played out. I guess your point, if you think. If you didn't think it was real, you wouldn't be spending the money, I understand. I guess I'll wait and see what happens.
Great. Thanks, Nathan.
Thank you.
We go back to Mark Wilson from Jefferies. Please go ahead, Mark.
Just checking some. A lot of 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? The 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 any one of them? Thank you.
On that, I'll let Phil talk about electrification, but on adding up all those profiles that were in part two of the presentation, we did that math ourselves because I asked for it just to make sure we understood what they looked like. What I believe is the case is that some upside is talked about on some of those.
Mm-hmm.
You know, those are more, you see, things that have a lot less certainty around them. The timing's a lot less certain. 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. Phil, you wanna talk about kind of the challenges of electrification and the parameters around it?
What a great question. I could talk at length, as Linda knows, but I won't. It's very complicated. It's like repairing your car in the middle of a field miles away from anywhere, 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. That's with both governments, both Holyrood and Westminster. When I talked about regulatory landscape and bringing the regulators together and industry, those are the sort of things that are gonna happen. There's a committee of regulators 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 Western Shetland are as easily electrified. Some, like Buzzard, it was always potentially contemplated. Others are more difficult. There is still a lot of work to do. 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. 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.
Very good. We'll watch this space. Well done.
Thank you.
We go back to James Hosie from Barclays. Please go ahead, James.
Hi there. Yeah, if I just go and look at Slide 41 and the reference there to a target reserve life of 8-12 years. It looks like you're gonna 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?
Yeah. 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. We've also demonstrated confidence now that we can keep production relatively flat for the next three years, which is kind of the line of sight I know a lot of investors were looking for. We're happy to be able to demonstrate that we believe we can do that at least for the next three years going forward. When it comes to M&A, you know, 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 three years before doing our first acquisition. We had lots of opportunities in those intervening years to, you know, go after or acquire things, and on numerous occasions walked away or came to the conclusion the value creation opportunity just wasn't there. I think we have the reserve base today, thankfully, that allows us 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. We feel like, we're now starting to do all of those things and ending the year in a pretty strong position. Happy to do that.
Okay, thank you very much.
This now concludes our Q&A sessions. 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 two 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. 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. 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 'cause it looks like we're going down into not quite lockdown next week here in London, but something akin to it. I just hope everyone's able to stay safe through all of this. We hope to see you in the new year in an in-person event. In the meantime, all our best wishes for the holiday season and the new year. Thank you so much.