Hello, and welcome to Harbour Energy's 2024 full year results presentation and capital markets update. My name is Elizabeth Brooks, and I am Head of Investor Relations for Harbour Energy. In September of last year, as many of you know, we completed the acquisition of a large portfolio of assets from Wintershall Dea. This was our fourth acquisition in seven years and our most transformational, marking a step change in our scale, global presence, and financial strengths. Our objectives today are to showcase the quality and potential of our portfolio, highlight the diversity and sustainability of our business, and outline our priorities for the future. First, Alexander Krane, our Chief Financial Officer, will take you through our 2024 results. Then we'll have our capital markets update hosted by our Chief Executive, Linda Cook, along with other members of our senior leadership team.
There will be plenty of time for Q&A at the end. For now, I'll hand you over to Alexander for our 2024 results. Alexander.
Thank you, and good morning to everyone joining us today. 2024 was a truly transformational year for Harbour Energy with the completion of the Wintershall Dea acquisition. We will hear the significant benefits and optionality this has brought us in our capital markets update later this morning. But I wanted to start with this slide to demonstrate the step change we've seen and will see in full over 2025 as a result of that acquisition. At a point in history when there is a lot of uncertainty, a lot of unrest, and a lot of volatility in financial markets, we are more convinced than ever that the strategy we've set out and kept unchanged for years is the right one for an independent oil and gas company. We have scale, and we are lowering costs and GHG emissions intensity.
We also have diversification, not only geographic diversity, but also diversity in our revenue streams since we sell a mix of crude, European gas, and international gas. We also target low leverage, looking to reduce our debt after each major acquisition, and we hedge actively a significant part of our oil and gas sales, and collectively, this means that we are generating material and resilient cash flow that puts us in a strong financial position with potential for material additional shareholder distributions. Moving to our 2024 highlights. At the same time as completing this transformational acquisition, we also continue to deliver operationally and financially. We materially increased and diversified our production to 258,000 barrels of oil equivalent per day. We more than tripled our reserves and resources, and we made considerable progress with our strategic investment opportunities, of which we'll hear more later.
We increased our revenue and EBITDA to approximately $6 billion and $4 billion, up about 65% and 50% respectively, and as a result of the acquisition, achieved investment-grade credit ratings. This is just the start. Our 2024 results reflect just four months' contribution from the acquired portfolio, with the full benefits of the acquisition coming through in 2025. This slide shows the full potential of the portfolio coming through in the fourth quarter of 2024, with production levels averaging around 500,000 barrels of oil equivalent per day. Furthermore, we maintained these levels in the first two months of 2025. In addition to the acquisition, we also benefited from new wells and projects on stream in the latter part of last year, including in the UK, Norway, and Argentina.
Costs were stable at $16.50 per BOE over the course of 2024, with the addition of the lower-cost acquired portfolio offsetting higher unit operating costs in the UK. Going forward, our operating costs will be materially lower, as you will hear more about shortly. In 2024, total capital expenditure increased to $1.8 billion, compared to $1 billion last year. Of the $800 million increase, 80% is related to the four months' contribution from the Wintershall Dea portfolio. In addition, we accelerated drilling around our operator hubs in the UK, taking advantage of some certainty in the UK fiscal regime ahead of the changes last November. We delivered good results from the capital program, which was mainly focused on infrastructure-led opportunities and converting reserves into production and cash flow.
Notably here, production started up from the Fenix project in our conventional offshore CMA-1 license in Argentina, while here in the UK, we delivered first oil from our Talbot project. In addition, we acquired an interest in an exciting FLNG project in Argentina, which has the potential to accelerate the development of our huge Vaca Muerta resource. We had exploration success in the UK and in Norway, but also further afield in Mexico and Indonesia. This included confirming a 100 million barrel plus oil field at Kan and completing a multi-well campaign in Indonesia, which de-risked a multi-TCF gas play across our Andaman acreage. These successes added to our significantly increased 2C resource base, which now stands at 1.9 billion barrels of oil equivalent, providing significant reserve replacement opportunities and supporting material, long-dated production and cash flow beyond 2030.
Now, I mentioned earlier that we have diversity in our revenue streams, supporting our resilient cash flow. Realized pricing for our oil and European gas volumes improved in 2024, benefiting from higher Brent and European gas prices, but also an improved hedge book, especially on the European gas side compared to 2023. Starting with Brent, our post-hedging realized price for crude oil sales, excluding NGLs, averaged $82 per barrel, compared to the average market price of $81 and to a realized price of $78 in 2023. For our European gas, we realized $11 per MCF, in line with the average market price and up some 60% from $7 per MCF in 2023.
Other gas prices, which relate to our Argentina, North Africa, and Southeast Asia gas volumes, they averaged $4 per MCF, driven by local Argentine and Egyptian contractual pricing and compared to $13 per MCF in 2023, which was solely Southeast Asia, where the price we realized for our gas is correlated to crude prices. Gas in Argentina and Egypt is primarily sold into the domestic market and is stable compared to the international benchmarks. Now, let us turn to the income statements, and as a result of completing the Wintershall Dea transaction in early September, the 2024 financial statements are somewhat complex, with four months of operations included from the acquired portfolio, along with a purchase price allocation exercise that significantly impacts our balance sheets.
As we've seen, EBITDA was 50% higher at $4 billion, with the Wintershall Dea portfolio contributing approximately $2 billion of that, highlighting the high-quality assets that we acquired. There were also a number of period-specific non-cash charges. These largely related to our U.K. business and reflected the impact of the continued fiscal and regulatory uncertainty and challenges here in the U.K. Impairment charges totaled $372 million, of which around half related to revisions to decommissioning estimates on non-producing U.K. assets. The remainder primarily relates to impairments on three U.K. fields due to changes in life of field outlook. In terms of exploration write-offs and expenses, the two biggest components related to a U.K. asset write-off, driven by the operator's decision to exit the U.K. in response to the EPL and some rationalization of Harbour's legacy Norway portfolio. In addition, this is where we account for our pre-FEED CCS projects.
The increase in net G&A reflects the enlarged group, including expansion of our corporate center, and it includes one-off acquisition-related costs of $119 million. We had $0.5 billion of net financing costs this year. This covers $0.2 billion annual unwinding of the discount on balance sheet decommissioning liabilities, $0.1 billion of fair value losses on FX derivatives, and another $0.1 billion of interest on the debt facilities and bonds. The total tax charge of $1.3 billion represents an effective tax rate of 108% compared to the 78% statutory rate, resulting in a loss after tax of $93 million and a loss per share of $0.10. Once again, we are reporting an effective tax rate of around 100%, driven by the effects of the UK Energy Profits Levy. Turning to the balance sheet next. Total assets increased significantly to $30.3 billion as a result of the acquisition.
We now have $5.1 billion of goodwill on the balance sheet here, of which $3.8 billion relates to the most recent acquisition. This primarily reflects the fact that assets and liabilities acquired get recognized on the balance sheet at discounted fair value, whereas deferred taxes are recognized on an undiscounted basis. The deferred tax position predominantly relates to Norway, where we face a 78% tax rate and have long-life assets, meaning the discounting impact is significant. Now, this goodwill is not subject to annual amortization like our other assets. Instead, it will remain on the balance sheet until the deferred tax unwinds, at which point it will come off through impairment charges.
Total liabilities and equity of $30.3 billion included equity of $6.3 billion versus $1.6 billion in 2023, driven again by the issuance of $3.5 billion of equity to Wintershall Dea acquisition and the recognition of the ported $1.6 billion of hybrid notes in equity. Decommissioning provisions increased to $7.1 billion, driven by the acquired portfolio. Importantly, this is a pre-tax number discounted at risk-free rates. Given decommissioning provisions largely relate to liabilities in the U.K. and Norway, where there's a 40% and 78% tax relief on decommissioning spend respectively, on a post-tax basis, this number is materially lower. Deferred tax liabilities amounted to $6.2 billion, compared to $1.3 billion last year, principally due to additional deferred tax liabilities of $5.5 billion taken on from the acquisition. Now, let's turn to cash flow next.
The acquisition of the Wintershall Dea portfolio is expected to deliver a step up in the scale and sustainability of our cash flow. This is underpinned by our improved reserve life and expanded resource base. For 2024, Harbour delivered free cash flow of $0.1 billion before shareholder distributions in one-off acquisition-related costs. Cash flow was impacted by a number of period-specific items. This included material negative working capital movements, driven by the adjustment of our working capital cycle to the increased size of our business, significant planned shutdowns in Norway in the period post-completion, and payment of previously deferred U.K. taxes on 2023 earnings. Now, drilling down a bit into the key drivers for the working capital movement.
At the end of 2023, we had a net working capital asset on the balance sheet reflecting the value of the approximate 200 KBOE per day production pre-year-end, for which the cash was not collected until post-year-end. Roll forward to year-end 2024, and we had a much larger net working capital asset on the balance sheet. This reflected the 500 KBOE per day production produced pre-year-end, but for which the cash was not collected until post-year-end. We paid $1.5 billion in tax, largely made up of $0.9 billion in the UK and $0.6 billion in Norway. The UK tax included $0.7 billion of Energy Profits Levy, of which $0.4 billion again was a balancing payment related to 2023 earnings. Net debt increased from $0.2 billion at the end of 2023 to $4.7 billion at year-end 2024.
This increase came as a result of a combination of porting of Wintershall Dea bonds and new issuances in September last year. Net debt is presented in the financial statements at $4.4 billion after amortized fees. Now, as a reminder, the subordinated notes, or hybrid bonds, are accounted for as equity and are therefore not part of our net debt number. The final slide in my full-year result presentation sets out how we delivered in 2024 and reiterates our guidance for 2025. Looking to 2025, we will benefit from a full year's contribution from the Wintershall Dea assets. This includes another material step up in our production to between 450 to 475 KBOE per day. As I mentioned earlier, we have started the year well with production averaging 500 KBOE per day to the end of February.
We also expect a 15% reduction in unit operating costs and a material step up in scale and longevity of our free cash flow generation as we benefit from our more diverse and low-cost portfolio. In summary, 2024 was another year of solid delivery for us, operationally, financially, and of course, strategically, with the completion of the Wintershall Dea transaction. The acquisition has transformed Harbour into one of the largest and most diversified global oil and gas companies. I'd like to conclude this part with a short video, following which we will move to our capital markets update, where we will provide more insights into our expanded portfolio with plenty of opportunities after or questions. Thank you.
Since 2014, Harbour Energy has built one of the world's largest and most geographically diverse independent oil and gas companies.
We've driven our growth through a strong focus, aiming high and delivering value for all our stakeholders. From fueling transport, powering industry, and heating our homes, our products provide the energy the world needs safely, efficiently, and responsibly. We're passionate about what we do and will keep driving progress. We rise to the challenge and use our deep industry expertise to make technological advances. We care for our communities and are committed to managing the environmental impact of our operations. We're also involved in several European CO2 transportation and storage projects, which could help reduce carbon emissions, and we will continue strengthening and enhancing our portfolio. From the Americas to North Africa and Europe to Southeast Asia, we work together to help fuel the world.
Great, thanks. Welcome back, everyone.
We're going to now move straight into our capital markets update, and you can see the agenda here on the slide. Linda will first give an overview of our strategy and business. Next, Alan Brooks, our EVP Technical Services, will provide insights into the performance and the quality of our portfolio. This will then be followed by several of our leaders who will share some of the exciting opportunities in their businesses. Before Alexander will talk about our approach to capital allocation and priorities, Linda will wrap up the presentation before we take your questions. Linda, over to you.
Thank you, Elizabeth, and welcome everyone to our capital markets update. Alexander's review of last year's results and guidance for 2025 provides a hint of the transformation of our business following the Wintershall Dea transaction.
Now, in our capital markets update, we'll demonstrate the quality of our portfolio today and its potential for the future. In terms of key takeaways, the first thing to note is the consistency of our vision and strategy and our successful execution over the past several years. As an outcome of that strategic delivery, we now have a resilient base of existing production and a portfolio of longer-term organic investment options, which sit alongside our proven M&A capabilities. Today's asset base can sustain significant production, with operating costs holding steady through 2030. At the same time, our disciplined capital allocation and the high grading of our opportunity set mean that capital investment will decline from around $2.5 billion in 2025 to less than $2 billion next year.
This outlook gives us confidence in our ability to consistently deliver material free cash flow for years to come, securing our annual dividend and providing the potential to return material excess cash flow to our shareholders. We're still a fairly young company, so for those of you who are new to us, just a quick snapshot of Harbour Energy. We're publicly listed in London, and our rapid growth over the past eight years has made us one of the world's largest global independent oil and gas companies. Today, we have a diversified portfolio producing around 500,000 barrels a day, with a large, high-quality resource base, including a pipeline of organic growth options. On top of that, we're involved in CO2 capture and storage, with a leading position in Europe.
Financially, we have a strong balance sheet, investment-grade credit ratings, and a track record of returning excess cash to shareholders through a combination of dividends and buybacks. While we have a global portfolio, the bar chart illustrates that four key countries account for 80% of our production, reserves, and resources today: Norway, the U.K., Argentina, and Mexico. The chart also tells the story of how our portfolio will likely evolve over time. As our asset base in the U.K. continues to mature, its production will be replaced through investment largely in the other three countries. In Norway, we have a successful exploration track record, which drives reserves replacement and growth in our low-cost, low-emissions production. Our licensed inventory in the country means we have plenty of running room. In Argentina, conventional offshore development opportunities sit alongside our position in the very exciting Vaca Muerta region.
Our significant acreage in this onshore unconventional play provides us with a multi-year inventory of drilling locations, both oil and gas. And in Mexico, we have interest in multiple high-quality offshore oil discoveries, including the world-class Zama field, giving us the potential for material longer-term growth. And you'll hear more about all of these later in the presentation. Taking a step back, I think it's helpful for those who are less familiar with Harbour to explain how we got to where we are today. We started as a private investment vehicle in 2014 with a simple, but admittedly ambitious vision: to create value by building a new global independent oil and gas company. At the time, a lot of companies were spending large sums to acquire non-producing shale acreage in the U.S. We took a contrarian approach with a focus on conventional offshore producing assets outside the States. Why?
Because there was less competition, there was a good supply of options, and because we had and still have a focus on cash flow. The journey started with acquisitions of UK North Sea assets from Shell and ConocoPhillips in 2017 and 2019, and that gave us an operating capability, scale in the UK with the ability to drive synergies, and options to reinvest in those assets to extend field life. These were followed by the reverse merger with UK-listed Premier Oil in 2021. This came with some assets and substantial financial synergies in the UK. It also brought assets in Southeast Asia and Mexico, providing us with a starting point for diversification, which had always been part of our strategy, and then, just six months ago, we completed the Wintershall Dea transaction. This transaction transformed our geographic presence and tripled our production.
It also increased our exposure to the attractive European gas market and lowered our unit operating costs, making us more resilient to the inevitable commodity price swings. The acquisition also substantially increased the longevity of our portfolio and added a high-quality set of organic options to underpin future production, cash flow, and value creation. Finally, the transaction enhanced our financial strength, bringing us investment-grade credit ratings and access to cheaper and broader sources of funding. Our ambition, however, is meaningless unless it's backed up by delivery, and we have a good track record in that regard. In addition to increased production and reserves, we've delivered growth in earnings and over $6 billion of cumulative cash flow since inception. Net debt today is under $5 billion, and our leverage is less than one times, a testament to our conservative approach to the balance sheet.
Throughout, we've had a focus on shareholder returns, having distributed $1.2 billion over the past three years through a combination of dividends and buybacks. Now, let's look a bit to the future, starting with a few words about the macro environment. As an upstream producer, a key consideration for us logically is future demand for oil and gas. There's a growing consensus around a few key themes, mainly that energy demand will continue to grow, driven by population growth and economic development. Renewable sources of energy will also continue to grow, but will require higher levels of investment and are increasingly seen to supplement oil and gas rather than displace them, at least in the midterm. Therefore, we believe demand for oil and gas will continue for decades to come. To deliver the supply, substantial levels of investment will be required.
This is especially true given underinvestment over the past several years, when driven in part by industry challenges when it comes to accessing capital, and the renewed focus on oil and gas companies to return cash to shareholders rather than investing in new acreage, exploration, or new developments. We also expect continued volatility in commodity prices, given the uneven pace of the energy transition alongside the geopolitical and global economic events about which we are all familiar. Against this backdrop of uncertainty and volatility, our strategy remains relevant, and we have what it takes to be successful. First, a resolute commitment to safety. This is our license to operate. And without a focus on safety, we can't execute our strategy or, importantly, live up to our commitment to keep our employees and local communities safe. We also aim to produce responsibly by protecting the environment.
This includes in relation to our own greenhouse gas emissions and leveraging our infrastructure and skills where there are attractive opportunities to be involved in CO2 capture and storage. We've improved our margins, making us resilient through the commodity price cycle, and we have scale and diversification, not for the sake of being large or having a global spread, but instead because this lowers our risk profile, supports an investment-grade credit rating, and reduces our cost of capital. And finally, we also have the people with the skills and experience needed to deliver. Our leadership team has grown and evolved with the company. Today, we're at full complement, having recently welcomed Nigel Hearn, our COO. Nigel joins us from Chevron, where his most recent role was as head of global operations, so he brings a tremendous wealth of experience.
Other members of our senior team joined Harbour as a result of our acquisitions. You can see several with ConocoPhillips or Wintershall Dea pedigrees, and some were recruited from outside, like Nigel, Alexander, and Jill Riggs, our head of HR, being drawn to Harbour's strategy, culture, and vision. You'll hear from several of these leaders today. Alexander, who's already covered our 2024 results, will rejoin later to talk about capital allocation. Alan Brooks, who joined Harbour last year as EVP Technical Services, will provide an overview of our portfolio and performance, and you'll hear from four of our business unit leaders, each providing insights from their respective businesses: Mikkel Zechner from Norway, Martin Rueda from Argentina, Gustavo Baquero from Mexico, and Graham Davies, who leads our CCS portfolio. We benefit significantly from the breadth and diversity of this team.
Between us all, we've covered just about every oil and gas producing province. We know what good looks like when it comes to safety, drilling, operational delivery, and major projects. And we know how important it is to manage risk, be it geopolitical, technical, currency, or commodity price. And I'm extremely fortunate to be working alongside each and every one of them. Two final slides before I hand it over. This one shows Harbour in the context of our new global peer group. Before the Wintershall Dea acquisition, our peer set included smaller, mostly UK-based independents. Today, the peer set for Harbour includes other large independent oil and gas companies with portfolios spanning beyond the UK or the U.S. onshore. We're strong in every category and stack up especially well in terms of production, unit costs, and cash flow yield.
But what really differentiates us is our unique combination of attributes: scale, geographic presence. We're not limited to a single country or basin. Material positions in both offshore conventional and onshore unconventional plays. Exposure to the advantaged European gas market, our strong balance sheet, our track record of returning cash to shareholders. And here, I'm admittedly biased: the strength of our team. And these strengths are why we believe Harbour is a compelling investment proposition. In just a few years, we've built from scratch a large and diverse oil and gas company. We have a strong base business with an excellent track record of operational and financial delivery, and we have interest in a variety of attractive organic future development opportunities.
All of this, coupled with our established M&A capability, gives us confidence in our ability to sustain production levels, continue to deliver substantial free cash flow beyond 2030, provide a competitive dividend, and return material excess free cash flow to shareholders over the coming years. Now, I'm going to turn it over to Alan, who'll take you through our portfolio in more detail.
You heard from Linda about the evolution of Harbour. Now, I'd like to delve deeper into the key characteristics of our portfolio. Harbour has grown from a company concentrated in the U.K. to a global, diversified independent. And each acquisition has strengthened our portfolio, increasing its longevity and sustainability, and also creating opportunities to high-grade our capital program. These are the themes we'll keep coming back to. We have a high-quality and globally diversified asset base with low asset concentration.
This provides us with balanced exposure to both international oil and European gas prices. The longevity of our portfolio has increased materially thanks to our significantly higher reserve and resource base, which underpins long-term cash flow. The strength of our 2C resource also means that from a capital allocation perspective, where in the past we relied on M&A for growth, we now have a range of attractive organic opportunities as well. The bulk of our near-term investment is in short-cycle, high-value developments in Norway and the UK. In the longer term, however, increasingly focused on low-cost-of-supply, long-life assets in Argentina and Mexico, sustaining production and cash flow to 2030 and beyond. Before we get into the portfolio details, however, I want to emphasize that at the heart of our operations lies an unwavering commitment to safety and high ESG standards. Let's take safety first.
As you can see, our safety performance has consistently been better than our peer group average. While our performance is good in places, we're never complacent and still have room for improvement. In particular, the uptick in recordable injuries and process safety events in 2024 reflects in part performance in our expanded business. We're very focused on improving, executing work in a controlled manner every single day. Although we're a young company, our organization is a mosaic of legacy companies with deep and rich operational experience from all around the world. Harbour today is capitalizing on that experience to embed the best industry practice across our portfolio. An example of this would be an initiative we currently have ongoing to share lessons learned between our UK and Germany operations.
Having looked across the portfolio at how we manage risk, we recognized an opportunity to strengthen our controls in Germany by applying similar principles to the UK. Efforts are coordinated by our corporate team, and it's a really good example of how we can leverage the experience and capability we have in the organization to drive performance improvement. Sustainability in all aspects of our business is important to Harbour and an integral part of how we're building a company for long-term success. As a data-driven organization, we place strong emphasis on benchmarking to drive continuous performance improvement. With the expansion of our portfolio, the number of relevant metrics has grown, giving us even greater opportunities to reinforce and strengthen our business. In terms of ESG benchmarks, we're outperforming industry average with strong governance and reporting outcomes. We continue to make good progress on reducing emissions.
On a pro forma basis, our portfolio is now less than 15 kilograms of CO2 equivalent per BOE intensity, and our methane intensity is low at around 0.08%. We've captured a host of emissions reduction opportunities with over 50 projects which could potentially reduce emissions by 150,000 tons of CO2e per year by 2030 on a gross operating basis. We evaluate the economics of each of these projects and will be disciplined in our allocation of capital. In terms of our targets, we met our methane intensity target ahead of schedule, and we remain on track to reduce our total emissions by 50% by 2030 from our 2018 baseline. We've set our net zero aspiration to 2050, which aligns with the approach taken by the wider industry. In addition, we have one of the largest CCS portfolios in Europe, which Graham will cover in more detail shortly.
Now, turning to production, our 2025 production guidance is 450,000-475,000 barrels of oil equivalent per day. Although, as Alexander mentioned, I'm pleased to report that we've made a good start in 2025 with production of around 500,000 year to date. Four countries, Norway, the UK, Argentina, and Mexico, drive over 80% of our production. We benefit from exposure to European gas prices and international oil prices, with 40% of our production coming from European gas and 40% from international oil. While we like to operate because it gives us the ability to drive efficiencies and control the pace of capital investment, we're also happy to partner with strong, established operators such as Equinor and Aker BP in Norway and TotalEnergies in Argentina. The key point is that we're not reliant on any one asset, country, or operator to deliver our production.
We now have less exposure to planned turnarounds with our expanded asset base, including highly reliable onshore operations in Argentina, Germany, Egypt, and Algeria. Our average pro forma operating efficiency was 91% in 2024, reflective of our high-quality asset base and our commitment to operational excellence. Strong operating efficiency drives competitive unit cost. Cost competitiveness is critical in a commodity business and remains a focus area for Harbour. Our unit costs have reduced by 15% in 2025, reflecting the improved quality of our portfolio. We believe we can keep it flat for the rest of the decade. We're transitioning from higher-cost mature basins like the UK into earlier-life, highly efficient assets in Norway, Argentina, and Mexico. We're also leveraging our operational experience and our global scale to reduce cost. Let me give you a few examples.
We've recently had a team from Norway and the UK to exchange knowledge, identify areas of overlap, and drive improvements in our development programs. We're working on cost-saving opportunities such as logistics, vessel sharing, and procurement economies of scale. And we're only just getting started. We're driving efficiency improvements across our portfolio. For example, our global scale has allowed us to renegotiate a supplier contract, achieving a $20 million saving this year. And of course, we're still operating under a transitional services agreement. So this year's cost base includes costs associated with the TSA, much of which will go away in 2026. As things stand, we believe we can reduce our net G&A from around $400 million today to $350 million in 2026, a 13% reduction. With integration well advanced, we believe there will be more synergies still to come.
In total, we believe we can deliver $500 million from additional portfolio measures and cost reduction initiatives over the coming three years. Next, I'm going to take a moment to examine our efforts to maximize the value of our UK assets. What we've done in the UK is a good example of how we seek to improve performance on the assets that we own. In 2024, we accelerated investment in short-cycle, high-return projects in and around our operating hubs. This included infill drilling at J-Area, Greater Britannia, and AELE. It helps, of course, being the operator, as this enables us to control the pace of capital investment. We started up the Talbot project in November, which was delivered on schedule and budget, thanks to the dedicated and highly experienced team we have in the UK. And at Jocelyn South, we made a gas condensate discovery late last year.
As we speak, we're in the midst of starting up. This is a great example of a high-return, short-cycle project, with just three months from discovery to first production, and payback expected before the end of the year. These projects have enabled us to keep UK production flat in 2025 compared to 2024, generating strong cash flow. However, with continued fiscal and regulatory uncertainty, it's a challenge for future opportunities in the UK to compete for capital. We expect to see a step down in our capital spending, and we remain laser-focused on continuing our efforts to optimize cost and manage our decommissioning. We have a strong portfolio in the UK, and we'll seek to preserve optionality in the event that fiscal and regulatory conditions change.
The corporate landscape in the UK has evolved quite substantially over the past several years, with a number of mergers, acquisitions, or joint ventures having been created. We know the market well, and we're open to exploring strategic options if they present value. Turning to Germany, our production is around 30,000 barrels of oil equivalent per day, which is around 65% oil. We have a largely operated position in Germany, including 100% operated interest in Mittelplate, Germany's largest and most productive oil field, which delivers more than half of domestic oil production. Mittelplate has a very low emissions intensity, having been converted to renewable power from shore in 2020. Germany represents a long-life, low-decline, and high-margin asset, which generates stable cash flow for years to come. It's a reliable asset with production efficiency of over 95%. But that doesn't mean we don't see opportunities for improvement.
We're leveraging our new organization to get even better. For example, improving our drilling performance so we can deliver greater production at lower cost. Moving on to reserves, our 2P reserves have tripled to almost 1.3 billion barrels of oil equivalent. Technically, reserve replacement was 1,000% in 2024, but it's probably more helpful to consider the compound annual growth in reserves since 2017, which has been 20%. Norway now represents approximately 35% of our 2P reserves and has replaced the UK as our largest country in terms of both production and reserves. We also had added significant reserves in Argentina, which we're really excited about, and as you'll hear from our team later, most of our proven reserves are in our CMA-1 asset offshore Tierra del Fuego.
This is a long-life asset with a current reserve life of 11 years and line of sight to additional resources which could extend production into the 2040s. Now, turning to our capital program, it's worth stating that the bar for investment has gotten higher in Harbour, with projects needing to compete for capital in a much more global and competitive portfolio. Our board and senior executive team are very rigorous about this. All projects have to compete against each other and hit our investment hurdle rates. Over the next three years, we expect to invest approximately $4 billion in production and development opportunities. In the near term, the bulk of this capital is focused on converting reserves into production and cash flow, with around half of the capital allocated to Norway.
Just picking out a few project examples, the MEREA Phase 2 project in Norway, which is predominantly oil, and we are the operator, is expected first production this year. It has a break-even price of close to $30 per barrel. On the gas side in Argentina, the APE unconventional asset has a break-even of less than $2 an MCF. We do have expenditure in other regions where it competes strongly for capital. For example, the Raven West project in Egypt has a break-even of around $2.50 per MCF. On average, break-even of our oil-weighted projects is about $35 per barrel, and it's just under $4 per MCF for gas-weighted projects. Looking longer term, our focus is on converting the best of our 2C resource into 2P reserves.
On this page, you can see the breadth and strength of the projects we have in the portfolio, split roughly between high-value, short-cycle opportunities such as satellite wells and infill drilling, unconventional scalable projects, which is essentially the Vaca Muerta play in Argentina, and finally, other large offshore conventional projects in which we have significant interest in Mexico and Indonesia. What's striking about this chart is the size of the unconventional opportunity in Argentina, but importantly, we're just getting started. We think there could be even more potential in Argentina than we currently have booked as we develop the assets, and we're excited about the potential in Mexico and are working hard to convert our 2C resources into reserves there in the near term.
While these projects aren't yet committed, we're disciplined about our approach to capital allocation and our target break-even price of $40 a barrel or $5 an MCF. Furthermore, we're not opportunity constrained. We have more projects than we're prepared to fund, so competition is high. Finally, this year, we added around 50 million barrels organically, with discoveries at Kveikje in Norway, Gilderoy in the U.K., and Tangkulo in Indonesia. Taken together, our reserves and resource life stands at 19 years, which provide us with options to sustain production and cash flow in the long term. We have a strong exploration track record with a success rate of around 70% over the past five years. In Norway and the U.K., our strategy has been focused on opportunities close to our producing assets, which allows us to quickly turn discoveries into production.
In Mexico, we drilled an appraisal well on the Kan discovery last year, which was completed on schedule and budget and has proven up higher volumes than we previously estimated. In the Andaman Sea, our operated Timpan discovery in 2022 was followed up with discoveries at Layaran in 2023 and Tangkulo in 2024, representing around 145 million barrels of contingent resource. Looking forward, we continue to focus on short-cycle opportunities. We have eight E&A wells close to infrastructure in Norway, which Mikkel will talk about shortly. Studies are continuing on our Andaman Sea discoveries, and we're looking at selected additional opportunities in Egypt and Algeria. Here you can see the evolution of our CapEx over the next few years. In 2025, we're focused on converting 2P reserves into production and cash flow, including in the UK.
Our near-term CapEx is split roughly 75% towards production and development, 10% exploration and appraisal, and 15% decommissioning. As we move to 2026 and 2027, we expect our CapEx to start transitioning towards developing our 2C resource, as outlined a moment ago. It's also worth noting the sizable drop in CapEx to under $2 billion in 2026-2027 due to declining investment in the UK and high grading of our capital spend. Looking further out, we expect CapEx to remain steady at between $1.7 billion and $2 billion. Over time, we have increasing optionality, and we'll make choices depending on the pace of development in Argentina, projects in Mexico, and exploration results. In closing, we've transformed the portfolio. We've delivered a step up not just in the scale of our production, but also the sustainability of our production.
Over the next few years, we expect growth in Norway and Argentina, offsetting decline in the UK, with additional support, for example, from Mexico and Indonesia beyond 2030. This will allow us to maintain a base production of around 450,000 barrels of oil equivalent per day, and we can continue to produce at scale and generate material cash flow well into the next decade, supported by approximately 20 years' reserve and resource life. In addition, there's upside potential in respect of exploration success and M&A. Now, I'm going to hand over to the leaders of several of our business units who will give you some more color on our current and future business plans. I'm going to start by introducing Mikkel Zechner, Managing Director of our Norway business unit, our biggest producer. Mikel.
Thank you, Alan. I'm going to outline the strengths of our operations in Norway and, in particular, what gives us the confidence that we can continue to deliver high-value production over the long term. In Norway, oil and gas are part of the national identity and a source of pride and economic stability for the nation. It is an attractive environment for oil and gas companies to operate in, with its low-cost production, well-developed modern infrastructure, and strong public and political backing. This strong political support is reflected in our supportive and stable fiscal regime. Oil and gas companies pay a 78% tax on net income, but at the same time, get a 78% tax relief on capital expenditure, including exploration costs, meaning that continuous investment is beneficial. Norway is also ranked number one for the GHG intensity of its offshore production.
Significant resources remain, meaning there's plenty of opportunities still to go for in Norway, with the outlook for production levels to be maintained well into the next decade. Norway is Harbour's largest producing country, and we produced around 180,000 barrels per day on a pro forma basis during 2024. Our legacy companies have been active in Norway since 1973 and were the second largest exporter of natural gas and now the largest international independent oil and gas company operating in the country. We have a strong track record of maintaining production and cash flow. This is achieved through the development of high-value, short-cycle projects with great economics, such as infill wells and subsea tie-backs close to existing infrastructure with strong IRRs. This is Harbour's sweet spot. This is what we like to do and know how to do well.
We have significant equity positions in our key host facilities, meaning we are able to unlock additional synergies from these Type X. We also have a large 2C resource base and a proven track record of converting these into reserves and ultimately production and cash flow, as we have done so with our operated subsea fields, MEREA, Dvalin, and Nova. At present, we have a 2P plus 2C resource life of about 12 years. Holding over 100 exploration and production licenses, we also have significant prospective resources. What is more important, we have a high success rate for exploration and appraisal around our existing key host facilities. This record is supported by a well-diversified asset base and access to multiple gas export routes, which enable us to flex to the highest priced market in continental Europe and the UK.
The low cost per BOE of our production means we are able to deliver high margins. With a number of assets already powered from shore, our GHG intensity is low, even by Norwegian standards. On this next slide, you can see three of our key producing host facilities. These are operated by well-established peers and are a key focus for those companies as well. We have a high equity in all these facilities, allowing us to influence the host operators with many current and future tie-back developments operated by Harbour. This means we can influence the pace of development and maximize throughput across the hosts.
Gjøa, operated by Vår Energi, is a highly prospective area with a number of tie-backs, which we operate, such as Vega and Nova and the potential tie-back of Kveikje, which we discovered in 2024, and also Gjøa Nord and Ofelia, which are being matured to an investment decision. Skarv is Harbour's second largest producing hub in Norway and an area with significant development potential. Our subsea tie-backs, Idun Nord and Alve Nord, which are both operated by Aker BP, are developments in execution. Like with Gjøa, the hub strategy at Skarv involves near-term exploration, as well as progressing the recently appraised discoveries at Adriana, Sabina, and Storjo. The last of the three, Aasta Hansteen, is operated by Equinor and provides high production with high reliability. Subsurface outperformance here has helped to support continued high production rates from the hub.
We expect to deliver near-term production growth from our subsea tie-backs to Irpa, which is in development and is expected to reach first gas towards the end of 2026. Future growth is anticipated from an exploration and appraisal campaign due to start in 2026. Our confidence that we can sustain production around current levels and grow reserves in the near and longer term is supported by a steady pipeline of high-quality infrastructure-led projects, which are characterized by short lead times, high returns, and low break-even prices. Our projects, a balance of approved developments and future projects, are mostly subsea tie-backs, which together represent over 200 million barrels of 2P and 2C resources. Remember, this is Harbour's sweet spot, and we have a long history of leveraging existing infrastructure to deliver increased recovery and high margin with these kinds of projects. This is what we do best.
Further, if you look at the selected list of projects, then it is worth pointing out that most of them were discovered that we were part of. Among these approved projects are six subsea Type X sanctioned in 2022, which take advantage of extra tax incentives introduced to encourage investment towards the end of 2022. We plan to bring the operated MEREA Phase 2 project on stream in the summer of this year. This is a four-well subsea Type X to existing infrastructure in the MEREA field. During 2024, the subsea installation was completed, and drilling of the four horizontal wells will continue next month. Our operated Dvalin North field, the largest discovery made in Norway in 2021, is on target to come on stream by the end of 2026, a five-year turnaround from discovery to development. This development consists of a four-slot template and three gas producers.
The template has already been installed in 2024, and the remaining subsea infrastructure is planned to be put in place during 2025. Drilling will then happen in 2026. In 2024, we appraised the Adriana and Sabina discoveries. We are progressing development studies with a concept select planned for the first half of 2026, a final investment decision in 2027, and first production towards the end of the decade. The base case concept is a subsea Type X to the nearby Skarv FPSO operated by Aker BP. Development synergies with other nearby discoveries, such as the Aker BP operated Storjo discovery, in which we own a 30% working interest, will also be evaluated in the concept selection .
As you can see, we have a series of future projects being matured towards potential finance and investment decisions in the next one to three years, potentially adding another 100 million barrels of oil equivalent to our reserves. At an estimated development cost of around $20 per BOE, this is really efficient CapEx and gives us further confidence that we can maintain material production well into the future. Our strong exploration track record enables us to replenish the development pipeline and ultimately supports reserve replacement and future production. In 2024, we saw significant success with six positive results from the six exploration and appraisal wells drilled. These included the previously mentioned Kveikje discovery, the appraisals of the Adriana and Sabina gas discoveries, and the Storjo discovery.
All of these are good examples of our hub strategy by investing in areas close to our existing infrastructure, with our deep knowledge of the geology and the assets, which gives us the best opportunity to efficiently mature discoveries towards production. We have hugely competitive finding costs. Our five-year average post-tax finding costs are about $1 per BOE, and we have been externally benchmarked as second-best explorer on the Norwegian continental shelf. We are the fifth largest license holder on the shelf, with more than 100 licenses in total, including four exploration licenses awarded in the annual licensing round in early 2025. All are located in core areas close to our existing key host facilities.
This number of licenses gives us the running room for potential additional future exploration, and coupled with our excellent exploration track record, gives us the confidence in our ability to continue to replenish our resources and reserves over time. In the next three years, we plan to continue to build our position with at least eight exploration and appraisal wells planned in Norway. As we have seen, we have a strong track record of sustaining and growing production through incremental near-field developments with really attractive economics. We have a clear line of sight of projects which will support production well into the next decade. In 2025, production is marginally lower as we focus on delivering the next wave of subsea projects that will come on stream in the next two years, enabling us to get production growing again.
Starting from the middle of this year with our MEREA phase II project, we expect a conveyor belt of subsea developments to result in new production being steadily brought online over the coming years. We then expect to see a material contribution from our future projects from 2028, giving us confidence that we can continue to deliver significant production out to 2030 and longer term. Now, from the most northern part of our global portfolio, I will hand over to Martin to talk about the most southern producing assets on the planet. Thank you for your attention.
Thank you, Michael. I'm very pleased to be able to share with you today the significant potential we see in Argentina. It is an exciting moment for the country and, in particular, for international oil and gas companies doing business here. What is particular of Argentina today?
Argentina has a massive world-class and conventional oil and gas resource that is in the early stages of development. It presents an opportunity for the country and for companies like Harbour to become a material exporter of both gas and oil. Support for the oil and gas industry is widely shared by Argentine society and all relevant stakeholders in the country, who see it as an opportunity to enable the much-needed economic growth. President Milei's government is aligned with this view and fully recognizes the benefit that developing the vast resources of the country can bring to Argentina's economy. The strong political support for oil and gas industry and the political will to accelerate growth is reflected in the pro-business legislation recently enacted. A great example is the fiscal incentive regime for large investments known as RIGI.
It offers investment incentives for major infrastructure projects, ensuring fiscal and regulatory stability and easing foreign exchange restrictions. With production growing rapidly and strong growth expected to continue well past 2030, Argentina is both a stable producing region today and a major growth opportunity for a company in the future, and Harbour is well placed as the economy picture unfolds. Let's move now to our position within Argentina. We have three producing assets in Argentina. One, conventional offshore gas in Tierra del Fuego, in the southern tip of Argentina, the Cuenca Marina Austral, and the other two located in the world-class Vaca Muerta shale resource in the Neuquén province, Aguada Pichana Este and San Roque, and last year, we acquired an interest in the first LNG export project in Argentina, known as Southern Energy Floating LNG Project, with Pan American Energy, YPF, Pampa Energía, and Golar LNG as partners.
With over 45 years of operations in the country, we are one of Argentina's largest gas producers. Our Cuenca Marina Austral license, or CMA One, as we call it in Tierra del Fuego, is currently supplying more than 15% of the country's gas demand. While a strong foundation in Argentina is based on our CMA One asset, opportunities in Vaca Muerta are expanding rapidly. Our large 2C position in Vaca Muerta, the largest single component of Harbour's total 2C resource base, provides the opportunity to maintain and increase our production from Argentina, which is currently around 75,000 barrels per day, and opens opportunities for significant growth. So let's look at CMA One in more detail. This prolific offshore conventional gas asset represents around 70% of our production in Argentina today.
It includes two onshore processing plants and six offshore facilities, delivering 140,000 barrels gross production, our share of which is 37.5%. It has consistently delivered a stable level of production with high operational efficiency in excess of 95%. With all of the 200 million barrels of reserves in the asset coming from existing wells, the focus of future plans is bringing forward development of the resources we have across the fields. We plan to mature Type X and progress infill opportunities, and because we can use the existing infrastructure, these are capital-efficient incremental projects and help maintain production level. The $800 million gross Fenix project, an unmanned platform tying back into the CMA-1 facility, is a good example. It came on stream in budget and ahead of schedule in September last year and quickly reached plateau rates of 63,000 barrels gross, with all three wells now on stream.
With the Fenix project now completed, we are looking to the next set of opportunities. With significant targets and Type X potential identified at both the Carina and Fenix fields, plus opportunities to maximize production with compression projects and other similar projects, we expect to maintain material production level past 2040. Moving now to the big growth opportunity we have in country. Many of you will be familiar with Vaca Muerta and the huge potential it offers. It is the world's second largest shale gas and the fourth largest shale oil resource in the world. It covers a vast area with over 2,000 producing wells and 34 active drilling rigs in operation. From a subsurface perspective, the Vaca Muerta formation has minimal geologic uncertainty. It has a consistent layer structure with relatively low complexity, meaning it can theoretically be developed across its vast 7.4 million acres of 30,000 sq km.
Despite this, the basin remains relatively immature, with only around 3% of the potential resources having been produced. Estimated recovered resources represent more than 100 years of Argentinian current consumption of oil and gas. The limitations are not related to the subsurface conditions. Instead, the challenges lie with surface factors such as plant capacity and offtake. However, the industry is making good progress in these areas. This exceptional basin compares well to major U.S. analogs, being as good as, if not better, than the middle basins in the U.S. Permian, but with a lot more running room. As such, the Vaca Muerta formation represents a significant growth opportunity for our company. Harbour is strategically positioned in the Vaca Muerta formation, holding two of the largest licenses in the basin, Aguada Pichana Este, or APE as we call it, in the gas window, and San Roque in the oil window.
Together, they cover more than 400,000 gross drillable acres. Today, our production in Neuquén is around 21,000 barrels of oil equivalent per day, primarily from our APE license. As mentioned before, Vaca Muerta is far less developed than its U.S. counterpart, and challenges remain in infrastructure. Drilling and completion costs are higher, but we expect this to come down with future development and scale. We have made a good start here, but there is plenty still to go for. Let's drill into the two licenses in more depth. In San Roque, we are currently producing a small amount from the conventional license, along with a number of pilot wells that have proven the deliverability of the shale formation. Jointly with our partners, we are now in the process of applying for the unconventional license, where we see greater opportunity in the Vaca Muerta oil window.
There is a huge undeveloped oil block at San Roque. If you look at the map on the left of this slide, you can see a lot of white space, with only four wells currently producing out of a possible more than 1,000. We currently have only circa 70 million barrels of resources booked on the license associated with the identified initial development phase, but we estimate that there are more than 500 million barrels of potential net resources to target. As shown on this slide, you can see that currently our breakeven for these wells is comparable to the Permian. But as we are just getting started, we see potential to reduce costs further as we scale up from the current four towards the potential 1,000 wells.
Development plans also include increasing the processing plant capacity from 20,000 barrels a day up to 80 barrels a day to be completed in three stages over a five-year period. Our second license in Vaca Muerta, APE, is in the gas window. You can see from the map on the left that there has been a lot more activity today in this license, with far more well drilled. We've made a great start with 80 wells currently producing. Well improvements in our drilling campaign have led to significant uplift in estimated ultimate recovery, or EUR, per well with 3.3 million barrels achieved per well in 2024. Our 2025 plan is to drill 12 wells in continuation of the single rig campaign on the asset, which is planned to continue for the next four years, drilling a total of 45 wells.
In addition, we plan to expand the plant capacity from 14 million standard cubic feet per day to 16 million standard cubic feet per day by installing a bypass. There are a further 180 wells that are identified for the continuation of this single rig campaign on the license. With the experience gained through our drilling campaigns, and that being gained basin-wide, there is plenty of opportunity to continue to improve drilling efficiency. There is also scope to increase the scale and pace of development, with line of sight to around 1,300 locations in three landing zones. There is a vast 500 million barrels of 2C resources currently booked, and potential to double this if the scale of development can be expanded to the whole license.
This is why our participation in the Southern Energy Floating LNG Project could prove so important, to enable the increase in pace of development that would allow us to access the full resource potential. Last year, we acquired a 15% interest in the Southern Energy Floating LNG Export Project with the aim of accelerating the potential of the Vaca Muerta basin and delivering significant and long-term cash flows. The Southern Energy Project represents a creative, cost-efficient, and timely solution, taking a floating LNG vessel already in operation, Golar's Hilli Episeyo, and redeploying it off the coast of Rio Negro in southern Argentina. Together with our partners, we continue exploring alternatives for expansion, supporting Argentina's desire to become an important LNG exporter.
The project will take advantage of the benefits of the recent legislation in the country, including investment incentives, legal and regulatory stability, and the dollarization of revenues. Along with our established partners, Harbour is expected to supply the feed gas for the project. There is ongoing investment in regional infrastructure and other new export opportunities, with multiple companies currently looking at building pipelines connecting Vaca Muerta to the coast. These two things would enable us to accelerate the development of Vaca Muerta resource by providing a new way to monetize these molecules in the global LNG markets. My final slide is a reminder of the current scale of our business and where we could get to in terms of production.
In 2025, the development of the Fenix field has increased production from our CMA-1 license, and we will seek to maintain CMA-1 production rates well into the next decades by continuing to develop infill opportunities. Further increase in production will come from resources technically de-risked in Vaca Muerta, where we have considerable reserves replacement potential. The pace of our growth here will depend on how quickly the infrastructure is developed and access to export markets captured. This outlook underpins our confidence and excitement for our operations in Argentina. As we stand, we are producing at scale with a steady outlook that we see continuing into the next decade. The potential for accelerated growth provides us with material upside. And now I will hand over to Gustavo, who will tell you about our business in Mexico.
Thank you, Martin. Let's start with what the oil and gas landscape looks like in Mexico these days. Oil and gas have long played a critical role in the country, being a major driver of Mexico's economy, with taxes and royalties from the oil and gas production funding public services and infrastructure. The new government, led by President Claudia Sheinbaum, who has a PhD in energy systems, announced a new national energy plan and strategy last November. This includes the goal to maintain Mexico's oil production at 1.8 million barrels per day, which is above current levels. Whereas in the past, Mexico's previous administration tried to do this solely with PEMEX, the government now recognizes that it will need the support of international partners and private investments to reverse Mexico's oil production decline.
The country has an estimated ultimate recoverable resource of around 100 million barrels of oil equivalent, incidentally the same as Norway, with large volumes of 2Cs and yet undiscovered resources, meaning there is plenty of potential left in Mexico. Harbour is very well placed to capitalize on this opportunity as the private company with the largest reserves and resource base in Mexico, according to the CNH. Both Harbour, via Premier Oil, and Wintershall Dea were in Mexico, so we now have a bigger, stronger portfolio and are building on each other's expertise. As a result of the Wintershall Dea transaction, Harbour increased its interest in the Zama project to 32.2%, making it the largest private partner in the unit. We also increased our interest and became operator at our 100 million plus barrel of oil equivalent in the Kan discovery in Block 30, which has successfully been appraised.
We will work to identify the optimum development concept for Kan in 2025. Block 30 also has additional exploration upside, and we are planning to apply for an additional exploration period for this block. With interest also in the deeper water discoveries in Block 29 and Block 4, there is the potential for a cluster development in this area, which could include other nearby discoveries. Our total 2C resource base is material at over 400 million barrels of oil equivalent, mainly oil, and provides us with significant reserves replacement potential. While all of these offer long-term optionality and make Mexico a major growth area for Harbour, in the near term, we also have a cash-generative production base, which we can build on through our operated interest in the onshore Ogarrio field and the non-operated interest in the shallow water Hokchi fields.
Let's now take a closer look at our world-class Zama oil field, where we have material opportunity to deliver significant production over the medium term. Many of you will be familiar with Zama. It's one of the largest shallow water oil discoveries made globally in recent years, with over 700 million barrels gross potential resource. In fact, it is the largest undeveloped field in Mexico, and the government has designated the development of the Zama oil field as one of the strategic projects it needs to progress to reach its production goal. Zama sits in around 150-meter water depth. It has been fully appraised with four reservoir penetrations, so we know the reservoir quality is good. In fact, Zama reservoir is excellent quality, more than 300 meters thick, with high porosity and permeability.
Due to its exceptional resource density, the expected recovery factor has been benchmarked at the upper end of analog fields in the region. We now believe that momentum is building for the project with the new administration in Mexico. Furthermore, we have recently entered into discussions with PEMEX and the Block 7 partners, Harbour Energy and Talos Energy, to assume operatorship of the Zama field with the aim to optimize the development and accelerate first oil. We remain excited about Zama as a key strategic investment opportunity within our portfolio, which has the potential to replace a full year of Harbour's annual net production with its reserves booking. Zama gives us optionality and further confidence in our ability to deliver consistently material free cash flow well into the next decade and within our capital allocation. Thank you.
I will now hand it over to Graham to talk about opportunities in our CCS business.
Thank you, Gustavo. I'm Graham Davies, EVP of our carbon capture and storage business. Today, I'll talk to you about our CCS portfolio, which includes a broader range of assets following the Wintershall Dea transaction. We now have a leading position of CO2 storage across Europe and the UK, with net storage resources of over 650 million tons of CO2. CCS offers the potential for long-term and stable cash flows, which are complementary to Harbour's business and provide a diversity of revenue that is not linked to oil and gas prices. CCS projects have to compete for capital across the whole Harbour portfolio. We're focused on progressing our best high-graded projects. These include those CCS projects that can be cost competitive and scalable with low subsurface risk.
We place focus on building simple and robust value chains to connect our CO2 emitters to our stores and prioritize strong creditworthy emitters who we seek to establish relationships with early in the process. We also look to develop projects in countries with supportive government policies and funded support schemes. We work with governments in the countries where we operate to enable a supportive policy environment and an accelerated deployment of CCS at scale. Importantly, we must be able to deliver commercial returns. CCS can provide longer dated and stable cash flow, which when combined with the potential to access external financing can boost returns and reduce the upfront CAPEX requirements from our own balance sheets. Our Greensand project in Denmark is a good example of our strategy and of how projects are able to successfully compete for capital within our enlarged CCS portfolio.
Harbour has a 40% interest in this pilot scale project, which is operated by INEOS. We reached FID on it in December 2024, our first FID on a CCS project, and as such, a very important milestone for Harbour. We're targeting commercial operation from 2026 with an injection rate of around 400,000 tons per year and with a low CapEx requirement of between $10-$20 million net. CO2 will be shipped from the Port of Esbjerg in Denmark to the unmanned Nini platform, which Harbour also has a 40% non-operated interest in. CO2 will then be injected via a former oil producer into the Nini reservoir. Commercially attractive contracts have been secured with our emitters to transport and store the CO2, which provides a stable cash flow for the project.
Greensand could also be the first CO2 storage facility in operation in the EU, supporting both Danish and the EU's climate objectives. The Danish government is strongly supportive, positioning itself as a leader in CCS. In addition to securing an EU grant, which materially reduces Harbour's CapEx exposure, the project creates value through the reuse of infrastructure. This extends the useful life of the Nini facilities, and we expect to therefore defer decommissioning spend associated with the Nini platform for the life of the project, which is foreseen as eight years. Our Greensand project also provides a scalable, low-cost route to develop CCS learnings to deploy across the rest of our portfolio. This slide looks at two of our other CCS projects in more detail. The first, staying in Denmark, is Greenstore.
It's a cost-advantaged new onshore license located near the key industrial region of Aalborg in Denmark. Its location provides the potential to connect both local and European emitters over time. Harbour has a 40% interest and is operator of the project with INEOS as our non-operated partner alongside the Danish state. The project is in the appraisal phase to de-risk the subsurface storage site and preferred development concepts, which we expect will demonstrate lower capital intensity given its onshore location. As we've seen from the Greensand project, there is considerable political support in Denmark towards CCS. In particular, there is strong Danish government support for CO2 imports and the potential to develop a competitive CO2 industry across Europe. The second project on this slide is our large-scale, cost-competitive Viking project in the UK. It's also well located to enable import of CO2.
Led by Harbour, Viking CCS is located in the Humber, the U.K.'s most industrialized region and largest emitter of CO2. We have an exclusive relationship with Associated British Ports to develop a CO2 import terminal at the Port of Immingham. Viking has both high injectivity and, with access to 250 million tons of net CO2 storage resource under license, the ability to scale quickly. As with Greensand, we're able to reuse infrastructure, underpinning our cost advantage. In this case, the LOGGS pipeline, which has a capacity of over 30 million tons of CO2 per year. There's strong interest in the financial markets to provide project finance to the current U.K. CCS business models, which are being brought forward as a regulated asset base.
This can enable material leverage, which can improve Harbour's equity return and lower the upfront draw on our balance sheet to progress large CCS projects at scale. In summary, CCS has the potential to provide a complementary cash flow that is independent to oil and gas pricing and, importantly, demonstrates the critical role our industry can play in the energy transition. We continue to high-grade our CCS portfolio with decisions to either progress or divest based on commerciality and technical maturity. And with that, I'll hand you over to Alexander, who will talk about Harbour's capital allocation priorities and how our investment decisions are made.
Thank you, Graham. The acquisition of the Wintershall Dea upstream assets has not only transformed our asset base, but also the scale, the resilience, and sustainability of our cash flow.
We are today generating material free cash flow and believe we can sustain that cash flow through 2030 and beyond. That gives us a lot of choice and optionality around how we allocate our capital. While the addition of the Wintershall Dea portfolio has transformed our cash flow, our approach to capital allocation, like our strategy, has not changed. So that is, we have consistently adopted a highly disciplined approach to capital allocation, balancing our three priorities of safeguarding the balance sheet, ensuring a robust and resilient portfolio, and delivering competitive shareholder returns. Since 2021, we have materially delivered against our three capital allocation priorities. We have continued to invest in our portfolio. In total, we spent more than $4 billion between 2021 and 2024.
Even with this large amount spent, we generated free cash flow of almost $4 billion, which allowed us to reduce our net debt by about $2.9 billion and supported shareholder returns over and above our base dividend. All of this was before the Wintershall Dea acquisition. The resulting strong financial position gave us the flexibility to execute the Wintershall Dea transaction. While our capital allocation priorities are unchanged, our targets and financial framework that support them have evolved to reflect our much larger portfolio and business. First, in terms of safeguarding our balance sheets, we now have the added commitment of maintaining our investment-grade credit quality. We believe that having investment grade helps to future-proof our strategy, providing stable access to debt markets with more flexible terms, thus lowering our cost of capital.
In addition, we have adjusted our internal through-the-cycle leverage target to one times from one and a half times previously. Secondly, in terms of ensuring a robust and resilient portfolio, we will continue to invest in our asset base, and the good news is that with the Wintershall Dea acquisition, we now have a much broader global opportunity set. Given our portfolio today, we will be investing up to $2 billion per annum to support production at around 450,000 barrels of oil equivalent per day in the near term, and as you've heard throughout today, we are not opportunity constrained, and as we have done following our previous transactions, we will continue to drive cost synergies and optimize the portfolio through farm downs and disposals. Here, we foresee the potential to realize $500 million from these activities.
Similar to our decision to exit Vietnam, if we don't see a path to scale in the country, we will actively consider options. Finally, turning to shareholder returns, we set our annual dividend at a level that we believe is competitive and sustainable through the price cycle. This forms the foundation of our shareholder returns policy. Following the completion of the Wintershall Dea acquisition, we increased our annual dividend to $455 million, signaling the board's ongoing confidence in the scale and the longevity of our free cash flow generation. In addition, like we've done in the past, we will continue to return excess cash flow to shareholders via share buybacks. More on that in a moment. Since Harbour's foundation, we've grown rapidly and completed four major transactions. We've maintained a strong financial position throughout by deleveraging immediately post-acquisitions.
You can see our track record on this slide. As a result, leverage has averaged less than one and a half times through the period. Going forward, we will maintain this prudent approach to balance sheet management, which is the enabler of our growth-oriented strategy. And this has allowed us to act when others couldn't. We are aligning our through-the-cycle leverage threshold with our new credit rating, moving this threshold down to one times from one and a half. Further, in the short term, and like we've done after every acquisition, we will prioritize reducing our debt, this time by between $500 million and $1 billion. Again, this is to maximize flexibility going forward. With each acquisition, we have improved our credit profile. This was especially the case for the Wintershall Dea acquisition.
It's not often that you complete an acquisition multiple times your market cap and end up with a stronger credit rating. But that is what happened here, thanks to how we structured the acquisition, resulting in significant financial synergies. In fact, one of the major benefits of the Wintershall Dea transaction was the attractive debt stack that we acquired through the porting of $3 billion of Euro senior notes at an average coupon of 1.3%, and two hybrid bonds at EUR 1.5 billion at an average coupon of 2.8%. Then, in September, immediately following our completion, we wasted no time in accessing the Euro bond market to successfully refinance the acquisition bridge facility. As a result, today we have a bond portfolio with a weighted average cost of under 3.5% and a well-structured debt maturity profile that we will continue to manage proactively.
With our $2.5 billion of liquidity as at the end of 2024, we continue to be in a very strong financial position, and furthermore, we are now present in euro markets, both for senior and hybrid, and US markets, in addition to having a very supportive 15-bank RCF in place. This access and diversification is a strength and allows us to keep our cost of debt low, then the hybrid capital we have in our capital structure will remain an important element of our financing mix, supporting our credit rating and leverage profile. Our strong financial position and balance sheet is supported by the diversity of our revenue mix. We don't pretend to be able to predict commodity prices, which is why we like to maintain a balance of oil and gas in our portfolio while also actively hedging.
After completing the Wintershall Dea transaction, we have more diversified revenue streams with significant exposure to European gas prices. Today, around 40% of our production is European gas and 40% is linked to Brent pricing. As you can see from the charts on the left, both Brent oil and European gas prices are advantaged relative to Henry Hub and WTI, and they support strong margins. In particular, today, European gas prices are around $14 per MCF, which equates to an oil price of around $80 per barrel, so European gas prices are now trading at a premium to Brent. The remaining 29% of our production is other gas in Argentina and Egypt, for example, which is sold at fixed or domestic prices and therefore are relatively stable and not sensitive to international benchmarks.
Of the 80% of the price-sensitive volume, we look to actively hedge about half of the economic or post-tax exposure on a two-year rolling horizon, using a combination of fixed price and non-linear strategies. By hedging 50% of our exposure to commodity prices in year one and 30% in year two, we lock in value while maintaining upside potential from price appreciation. Further upside can be realized through the use of non-linear hedging instruments such as zero-cost collars. For 2025, we've hedged about 100 KBOE per day of European gas at $13 per MCF and about 50,000 KBOE per day of liquids production at $76 per barrel in 2025. We are foremost value-driven in terms of the choices we make in how we allocate capital, with all investment decisions evaluated against a wide range of metrics, as you can see on this slide.
Our investment framework is designed to sustain robust free cash flow, targeting returns above 20% IRR and a break-even cost below $40 per BOE for oil and less than $5 per MCF for gas. Although, of course, in markets where we realize lower gas prices, like in Argentina, our hurdle rates would reflect that. Looking at the chart on the left, we've guided to total CapEx in 2025 of between $2.4 and $2.6 billion. Much of our CapEx this year was already committed at the time of completion, and it is largely allocated to short-cycle, high-return projects aiming at converting 2P reserves into production and cash flow. Going forward, we have more discretion, and we expect to reduce CapEx to below $2 billion in 2026 and 2027. We believe this is the right level of spend given the portfolio and opportunity set we have.
The longer-term strategic options within our capital program, including steady investments in Norway and Argentina and development options in Mexico and Indonesia, have the potential to sustain production and underpin material annual free cash flow beyond 2030. The last thing to mention here is the tax effect on our capital program. While total capital expenditure pre-tax is reducing, on a post-tax basis, it stabilizes as our investments are expected to be increasingly in lower tax jurisdictions, resulting in less of a difference on our pre- and post-tax spend. Our approach to shareholder returns has not changed. That is, our annual dividend is set at a level that is competitive and sustainable through the cycle. We then look to return any excess cash flow to shareholders via buybacks. Since 2021, we have returned $1.2 billion to shareholders.
This consisted of $600 million returned via our annual dividend and another $600 million via share buybacks, which resulted in us repurchasing approximately 17% of our issued share capital. This, in turn, drove final dividend per share growth of 18% between 2021 and 2023. Looking ahead, the increased scale and longevity of our business following the Wintershall Dea acquisition has enabled us to more than double our annual dividend to $455 million. We believe that buybacks continue to have a critical role to play in our capital allocation, and furthermore, while BASF remains a significant shareholder in the company, we believe that it is important we have the flexibility to be able to conduct off-market buybacks. To that end, we plan to seek authority from our shareholders at our upcoming AGM to create the option to conduct directed buybacks from BASF.
Of course, we recognize that any such exercise of this authority would depend on BASF's intentions. We plan to seek this authority each year alongside the authority to conduct unmarketed buybacks so long as BASF remains a significant shareholder. In the short term, we expect to prioritize debt reductions over buybacks, but as we've done in the past, we will continue this under continuous review with the potential to commence share buybacks as early as late this year. Now, let me go over how we plan to put our capital allocation framework to work in the coming years. At the range of prices outlined here, we expect to generate between $4 and $6 billion of post-tax cash flow before investments during the 2025 to 2027 time period. Included within this is around $500 million from portfolio measures and cost reduction initiatives referred to earlier.
In terms of uses of our cash flow, then in line with our capital allocation priorities, we're looking to invest around $2 billion post-tax over the three-year period to support our production and future cash flow. After investment, that leaves around $2-$4 billion of free cash flow, or at the midpoint of these price scenarios shown, about $1 billion of free cash flow per year, more than covering our annual dividend of $455 million, even in the low-price scenario. With regards to excess cash in the short term, and like we've done in the past, we are prioritizing debt reduction, reinforcing our financial strength, then as can be seen by this chart, we see the potential to generate significant excess free cash flow over and above investments, debt reductions, and dividends that we would look to return to shareholders.
Now, I leave you with a reminder of our consistent capital allocation priorities and our commitment to delivering returns-focused value through our disciplined capital allocation strategy. We will continue to invest in our business, and we will work hard to improve our portfolio, prioritizing the best and the most profitable projects. We will deliver attractive, through-the-cycle shareholder returns, and we will do this while maintaining our investment grade rating. So thank you for listening, and I will hand you back to Linda.
Thank you, Alexander. I'll wrap it up now with a few words about M&A. It's a core part of Harbour's DNA and the path we've taken to grow the company. But we've only transacted where we saw the potential to create value, and each transaction has brought us something different.
In our first two acquisitions, both in the UK North Sea, we saw the opportunity to achieve scale, drive synergies, and reinvest in assets deemed non-strategic by their previous owners. As a result, we increased reserves by more than 25% compared to estimates at the time of those transactions. With Premier Oil, we secured three key benefits: a public listing, substantial financial synergies in the UK, and our first steps towards international diversification. Finally, with the Wintershall Dea transaction, as shared throughout this presentation, we've transformed our portfolio, making it more diverse, more resilient, and more sustainable. But we're not necessarily at the end of the journey. A successful oil and gas company must continually add to its reserves base, and we're no different. So it's valuable to have those M&A skills in our toolkit to supplement our organic growth options. What will we look for?
Mainly opportunities that continue to expand our reserve life while preserving our margins and our investment-grade credit rating. And the opportunity set remains fairly robust. Large companies looking to refine portfolios following consolidation, private companies looking for liquidity, and smaller independents, like us not that long ago, looking for scale, diversity, and access to capital. We have the financial strength, the operating capability, and the integration skills to transact, but we'll continue to do so only where we see an opportunity to create value. That brings us to the end of the presentation. We hope you found it helpful when it comes to understanding the company we are today.
With the Wintershall Dea transaction now complete, we believe the strength of our producing assets, our reserves and resources, our strong balance sheet and capital returns policy, all led by the fantastic team we now have in place, position us well for the future. And now, Alexander, Alan, and I will be happy to take your questions.
Thank you. There will now be a short break for your convenience. And when we return, we will take your questions. If you would like to ask a question today, you may do so by using the raised hand function on Zoom. To make the session as interactive as possible, we encourage you to have your camera turned on. If dialing in by phone, you can press Star 9 to raise your hand and Star 6 to unmute once prompted. Please remain connected. Welcome back. We will now take your questions.
To reiterate, if you would like to ask a question today, you can do so by using the raised hand function on Zoom. To make the session as interactive as possible, we encourage you to have your camera turned on. If dialing in by phone, you can press Star 9 to raise your hand and Star 6 to unmute once prompted. Our first question is an audio question from Lydia Rainforth. Lydia, please unmute and ask your question.
Thank you. Hello. Hopefully, you can hear me. My video isn't quite working, though. Thank you for the presentation and the very thorough run-through of the businesses. Can I come back to the capital allocation for it? And obviously, you set the CapEx budget. You are seeing efficiencies from 2025 into 2026, 2027. How are you setting that CapEx budget? Is it sort of top-down, or is it bottom-up in terms of that?
And then in terms of how I think about the cash flow and the use of the free cash flow, you said flat dividends coming through. When might you look at what determines the buyback decision effectively?
Yeah. Great. Thanks, Lydia, for the question. I'll start with a few words, and then maybe Alexander can chime in and help me out. I think let me maybe start with the buyback question because I know there have been some comments and questions in particular about that this morning. For those who have followed us over the years, you've seen that what we've consistently done after an acquisition is three things. Number 1, we look after the balance sheet. We want to make sure that we have our consistent approach to managing that and be conservative when it comes to managing our debt levels. Number 2, we reinvest in the asset base.
We continue to do that even while we're paying our dividend and looking after the balance sheet. Then third, we've paid our dividend regularly. This year, it's up 5% year on year. Then finally, with excess free cash flow, we've paid that out in buybacks. We can do all of these things at once. They're not mutually exclusive, as we have shown in past years. There's no change to that approach going forward. We're going to, as Alexander already said, we have a priority to reduce the debt by a certain amount. So that's going to be kind of on our front of mind. At the same time, we're reinvesting $2.5 billion around this year in the balance sheet. So we're doing that. At the same time, we're thinking about debt. We're paying our dividend, of course.
Again, increase 5% this year versus last year on a per-share basis, and then finally, as we've said in the presentation, excess free cash flow, the priority for that is to return it to shareholders and beginning possibly later this year. One of the things that we're doing to enable us to have maximum flexibility and optionality around that is, as Alexander also said, to get the authorization at our upcoming shareholders meeting to do a directed buyback from BASF should the opportunity for that arise and at a point at which it's beneficial for both BASF and we think it's in the best interest of the rest of our shareholders. So that's going to be a discussion that at some point we want to be able to make sure we're in the position to be able to have that discussion.
So that'll be important for us to get that authorization. Then when it comes to the budget and how we set the budget bottoms up, top down, I think it's a mixture of both. But let me turn to Alexander to say a few words about that. Yeah. So starting on that bit, Lydia, thanks for the question.
Yeah, as you would expect, it's a pretty thorough process that we've been through this year with the expanded portfolio. So it's a bottom-up process, but then with plenty of top-down challenge as well. And there's, as I think I showed on one of my slides, it's a lot of elements that goes into the consideration. So it's both on specific projects, assessing those risks, upsides as well. But then it's also the portfolio effects, concentration effects, and how CapEx is phased. So lots of challenge, again, as you would expect.
This year, with the bigger portfolio, there's been plenty of visits around to each of the countries to go through their portfolios and assess those opportunities. So extra emphasis on that this year, I would say. On your buyback question, I think Glenda covered it pretty well. Again, I think there's value in being consistent and being pretty clear on the capital allocation priorities and not changing from year to year. So hopefully, you will agree that we've been fairly consistent year to year and repaying some debts. We've tried to be explicit here as well on CapEx spending, but also what's the amount of debts we now seem to reduce. So we put a number out there, about $500 million-$1 billion, which we think makes sense, gives us the flexibility needed here.
Then, yeah, like we've done in the past, we will look to do buybacks. As lenda said, getting that flexibility to be able to both on-market buybacks, like you've seen us done over the last few years, but now mindful of having a large shareholder in BASF, also securing that off-market buyback authorization, we think is the right thing to do here.
Great. Sam, next question.
Thank you very much.
Thanks, Lydia.
Thank you for your question, Lydia. Our next question comes from Matt Smith from Bank of America. Matt, if you could unmute and ask your question.
Hi, good morning, guys. Thanks for the presentation and for taking my questions. I had a couple as well. Same topics, really, but I think hopefully asking them with a slightly different flavor.
So, I mean, if I did start on CapEx, you're pointing to a pretty significant drop down from 2026. I guess I just wanted to be crystal clear that you thought that sort of level of CapEx was sufficient to sustain production on an organic basis. And given it's quite a tight funnel for all of your projects or potential projects to fit through, I just wanted to sort of explore the implications for M&A, both from a disposal point of view, but also how that necessarily competes with potential acquisitions as well. So if I could wrap that up into one question on the CapEx side of things, organic and inorganic. And then just back to the buyback, I just perhaps useful just to recap timing and quantum.
So, I mean, first of all, would I be right in taking that excess cash or free cash flow is really defined as the free cash flow you've guided, less the dividend, less the deleveraging target as well? So therefore, that remaining pot is all potentially to be directed towards buyback in the coming years. And then I guess the second part was on timing, which I think you've alluded to, whether you have to do that deleveraging first before you commence the buyback, because I suppose the wider question there is how you think about buybacks as a pure return on investment decision given where the current share price is. Thank you.
Yeah. Matt, thanks. I've lost track of exactly how many questions that was, but we'll try to remember and answer as many of them as we can. Let me start with a bit about CapEx.
Alexander may want to supplement that, and then he can talk a bit more about buybacks. I think you're right to first point out that we have quite a material decrease in our total CapEx from 2025 to 2026, going from around $2.5 billion to $2 billion or less over the next couple of years, and I think that's both going back to Lydia's question, both a function of top down and bottoms up. If we think about what's happening underneath the surface of that, we have declining investment in the UK. We had accelerated a lot of investment last year, in particular, some of it going in early this year in the UK in light of what was happening with the fiscal and regulatory situation, so that now is beginning to trail off.
At the same time, we're adding in some additional investment, some of the countries you heard about during the presentation, but we're also taking a look at a more top-down approach to do some high grading on that. We have more flexibility as we get to 2026 and 2027, so we're squeezing that curve, if you will, letting the cream rise to the top and being quite selective and disciplined about the projects that we do decide to invest in, and so what that means is drives us down to around that $2 billion or a bit lower, and we think that's the right level of investment for us, given the size of our company today and the portfolio that we have, that that will support that relatively flat production going forward based on the portfolio we have today, which actually we're quite excited about.
I think you asked about divestments. Yeah, I mean, portfolio management's alive and well in Harbour Energy. We've done it since day one after we completed the Premier Oil transaction. I think we exited Brazil, Falkland Islands, one or two other small positions. I believe we've announced the divestment of Vietnam. Since we've completed Wintershall Dea, we've already exited a couple of the CCS licenses that we don't think can compete for capital in our portfolio. So it's something that we do on an ongoing basis, and that will continue to be the case, whether or not it's country exits or back to the capital investment program, reducing our investment levels by farming down or exiting certain potential projects that don't quite compete for capital in the portfolio would be part of that as well. So now let me turn it to Alexander.
Yeah. Yeah, thanks, Linda.
Yeah, I mean, on the CapEx, but just to add, I mean, there's obviously lots more competition for funding now with the broader portfolio. So we will be disciplined here and we will prioritize the best projects here. On buybacks, I mean, Matt, you've been following us for some years, so you will have seen from the past that we've been deleveraging quite a bit on the back of acquisitions. And after the previous, well, before Wintershall Dea, we were almost down to a net cash position. Now, we don't think that's the right thing to do now with the expanded portfolio and the size of the business now. So deleveraging just down $500 or down to $1 billion, we think that's more the right zip code for us now. But paying down debts and doing buybacks are not mutually exclusive.
We've tried to have two thoughts in our heads at the same time, so we would look to do both there, but in the very short term, we expect to prioritize debt repayments here.
Thanks, Matt.
Thank you very much.
Sam, next question.
Thank you very much. Our next question comes from Chris Wheaton of Stifel. Chris, if you could turn your camera on, unmute and ask your question.
Great. Thanks very much. Linda, Alexander, thank you very much for your presentation this morning. Three questions, if I may. Firstly, let's start on the buyback. Can you expand a little bit more, Alexander, on why you think debt paydown is the right use of cash flow straight away?
If you look at where your leverage is, 0.7 times net debt EBITDAX, even if you were to adjust for the hybrid bond element of the bonds, you're still below one times. Still feels slightly surprising to me you feel you need to pay debt down. You're not owned by private equity anymore, as you have done in the past. You've paid debt down immediately post acquisitions. I wonder you could expand a bit more on that because it doesn't feel like your balance sheet needs deleveraging at this point. And obviously, the use of capital, if not to pay down debt, would be to return it to shareholders, which is my next question. Is there anything in the BASF acquisition agreement that sets the price which a buyback would be an off-market buyback would be made? Obviously, BASF's in-price is $360 a share.
Your share price today is regrettably about half that. Is there a price? Is it $360? Is it somewhere in the middle? Is it subject to negotiation? My last question was going to the portfolio was really on Argentina, which I think is a really interesting growth potential here. As you say, an amazing and untapped shale growth opportunity. There's a lot of growth potential there, but it's reliant on third-party infrastructure. I'm interested in where you see those constraints and how quickly you see those constraints potentially be taken away and therefore to get after that thousand well opportunity that your country manager talked about, rather than just the drilling rate of 15 wells a year at the moment. Those
are my three questions. Thank you. Great. Chris, thanks for the questions. I'll turn it to Alexander to talk a bit more about the buyback question.
On the question about BASF, there's no pre-agreed price at which they might sell shares to us in a directed buyback or otherwise. That would all have to be something that's agreed at the time of any decision made for us to do that. So that's the answer to that question. So I'll let Alexander say a bit more about buybacks and then maybe have Alan talk a bit about Argentina.
Yeah. Yeah. Thanks for the question, Chris. And yeah, I think, again, after each acquisition, we've made sure to just have maximum flexibility, good capital discipline. And now when you see all the volatility out there in markets, we think that is a sensible thing to do to pay down some debt. But as you will see, it's not a very significant amount compared to the outstanding debt there.
Again, you should just expect us to be just a bit proactive on how we're dealing with the debt levels here. And again, yeah, on the buyback to BASF, no, nothing in the BCA or otherwise. And the first opportunity to get shareholder approval here to do off-market buybacks, well, that is the upcoming AGM in just a couple of months' time.
Just to touch on the infrastructure question. Yeah, thank you. As you touched on, we noted in the presentation 2,300 wells and over $1.5 billion barrels of resource. Something that we are super excited about as well. And because we have conventional assets out there already, there's actually some running room leveraging some of the existing infrastructure before we get to the point where we're constrained. That's the first port of call: utilizing the existing infrastructure that exists.
Of course, with the RIGI mechanism in place, there are strong incentives for the development of further infrastructure. So we're seeing good progress on that already. Our participation in the LNG project would be an example of that, and there's further examples ongoing. So as you say, we see really good progress already and great support for continuing to develop up, not just our position, but the broader basin in Argentina.
Yeah. And maybe, Chris, let me just add to that a little bit because it's not just infrastructure that's required. It's also finding a market for the oil and gas that's produced. In terms of the infrastructure, as Alan mentioned, we have a position in Southern Energy LNG, which we're quite excited about.
There are plans already by third-party developers to put a direct connection between where those FLNG vessels will reside in port to connect it to the Falklands to Vaca Muerta shale. That'll enable large amounts of gas to get to the port on a year-round basis, and importantly, it gives us access to other centers of demand in order to help support the continued growth of our production in the Falklands to Vaca Muerta. So we'll be accessing international LNG markets through that. Oh, tons of other benefits with that as well, which include being able to keep your revenues offshore. So dollarization of our revenues there, which reduces some other risks that some people might be familiar with in Argentina. So tons of benefits associated with that. So thank you for that, Chris, for your questions. And Sam, next question, please. Thank you very much.
Our next question comes from James Carmichael of Berenberg. James, please unmute yourself and go ahead with your question.
Hi. Morning, guys. I just had a couple of, if possible. Just wondering if you had any sort of initial take on the U.K.'s oil and gas tax consultation. Appreciate it. It's a bit light on detail at this stage, but if there's anything in there that might give you sort of a bit more encouragement about the long-term outlook for the U.K. And then just a couple on the U.S. I'm just wondering if there's any impact from the tariffs on how you're sort of thinking about your Mexican production and the export options. And then more generally, I guess there's obviously been talk about you're looking at a U.S. listing backed up by some form of corporate transaction over there.
Just interested to get your thoughts on both of those things in relation to the US, I guess, if they've changed over the last month. Thanks.
Yeah. Great. James, thanks for that. Let me see if I can take those in order. So number one, for those of you who may not have seen the news, the UK government yesterday launched their consultation process for both to solicit to engage with industry and the public in general on two topics, both the future of the UK continental shelf from a broader energy standpoint, and then second on the EPL. We welcome the launch of that process.
We're eager to engage, and our message will be what it's been for some time now, that what we need in order to have a healthy oil and gas sector and industry and employment and keep domestic production alive, supporting all the jobs that go into doing that in the country. We need a fair fiscal regime that may tax windfall profits, but not all profits. And we need it before 2030. And that's the message that we're going to be sending in as part of our participation in that consultation. I think the second question was around tariffs. Yeah. Every day, it seems something new is coming at us. Alexander referred to volatility. I think that's one reason why we're a little bit cautious right now about making commitments in some areas.
It's just the volatility in the commodity prices, everything going on from a global economic standpoint and geopolitical standpoint. It's a lot more than the usual amount of background noise, I think, that's impacting our sector, and tariffs are one of those. So far, no specific impact on us. We have very little production in Mexico today. I think longer term, of course, we have ambitions to have much more production in the country, but that's several years away, given that it would only follow the development of both the Kan and Zama oil discoveries, and so I think too early to say if there's going to be any real impact on that. Third question around the US listing. You know, I understand the question. We get it a lot.
I think the fact of the matter is that today our center of gravity, even following the Wintershall Dea transaction, remains in Europe. 70% of our production is here. So I think because of that, London continues to make the most sense for us. In addition, a lot of companies that are thinking about changing their listing or have changed their listing, they all typically have a substantial presence in the U.S. And at this point in time, we don't. So I think we'd struggle a bit, hard to get into some of the indices, even a bit of investor attention. I think for now, it continues to make sense that we keep the listing in London. Thanks for those questions, James. And Sam, next one, please.
Thank you very much. Our next question comes from Sasikanth Chilukuru from Morgan Stanley. Sasikanth, if you could unmute and ask your question.
Hi. Thanks for taking my questions. I had three, please. The first was on the cost and portfolio initiatives, the $500 million that's embedded within your free cash flow guidance. Just wondering if you could give more details on where it's coming from and how quickly you can actually achieve it and where it's actually reflected in the guidance as well. That would be helpful. The second one was on the CapEx. Again, the guidance for 2026 and 2027, if you could split it into how much exploration comes into it, how much is decommissioning costs, and within the development CapEx itself, what are you kind of including for Mexico or potentially for Argentina and also Indonesia in that guidance, at least initially.
The third one was more of a confirmation on the chart that you've provided for shareholder distributions, the buyback bars as well. I was just wondering if that is at range or is that the average, the average buyback that you have indicated in that chart?
Good. Sassy, thanks for the good questions. I think the first one was around the $500 million and what's included in that. The impact of that is included in the models and the forecasts that we've put forward today. I think that's going to come from three different categories. I think the first could be divestments, as I said earlier, portfolio management, alive and well in Harbour Energy. And the criteria, nothing's decided at this point in time. We're not here to announce what it might be, but the criteria remain unchanged.
And that's that if we don't see the opportunity to get to scale in a country over the short to medium term, then typically we start to consider whether or not it might be something better off in the hands of someone else. Second category might be because we're not opportunity constrained when it comes to our capital investment program, selling down interest in some of our key projects where we feel like maybe we don't quite need the exposure we have today. So that's a possibility. And then the third category, it could come from additional savings from cost initiatives that we have underway. And maybe I'll turn to Alan in a minute so that he can put a little bit more color on that, maybe. Your second question was around categories of the CapEx.
I think if we just look over the three-year period, and on average, around 75% of that is P&D, so production and development. So these are mainly near-term opportunities, getting reserves and resources directly into production, mainly reserves, only about 10% on E&A, and then about 15% on DCOM. So that's kind of a broad breakdown on that. And then you had a question, I think, also about buybacks. So maybe first to Alan on cost savings and then Alexander on buybacks. Or to correct anything that I've said that wasn't right.
Great. Thank you. So firstly, on the cost side of things, as we said in the presentation, we expect our G&A to fall from around $400 million to $350 million as we get into 2026. And actually, we see further opportunities into 2027.
To give a bit of color on that, some of the opportunities are in the IT space, for example. We're working on consolidating data centers, consolidating applications, rationalizing the portfolio, one service desk. So we've made really good progress on that, and we're a good way through transitioning off of the sort of transitional services agreement that was in place. So as we move into next year, we'll start to see the full year impact of that and again, further savings in 2027. Your question on the CapEx split over the three-year period, it's roughly sort of 75% to production and development, 10% exploration and appraisal, and about 15% decommissioning. And in that timeframe, it's mostly allocated to Europe. 75%-80% is Europe. And it's not till we get beyond the three-year period we'll start to see greater ramp up in Mexico.
We're starting to see ramp up in Argentina. And the pace of that, of course, will be dependent on fiscal conditions there. And Alexander?
Yeah. So I think your last question, you're referring to a chart. I think it's the one where you're showing or we are showing sources and uses. And the question is, if it's an average, yeah. So what we're trying to illustrate there is what is happening in terms of the price assumptions that you're using on average throughout those years. And you'll see there's a table that specifies just the assumption that goes into it. So it's an average for those years and anything from low up to a mid and then to a high case. But we can follow up with you, Sassy, if that was unclear. Thank you.
Thanks, Sassy. Sam? Thank you very much.
Just to reiterate, if you would like to ask a question today, you may do so by using the raised hand function on Zoom. To make the session as interactive as possible, we encourage you to have your camera turned on. If dialing in by phone, you can press star 9 to raise your hand and star six to unmute once prompted. Our next question comes from Werner Riding of Peel Hunt. Werner, if you could unmute and ask your question.
Morning. Yes, thanks, everyone. Yeah, a lot of focus on cash flow, dividend, buybacks. And so you've covered some of what I wanted to discuss. But I'd be interested to hear, based on your FY25 guidance on production and costs, etc., what combination of oil and gas price does your dividend become just one time covered by free cash flow?
Yeah. Thanks, Werner, for the question. I'm going to turn that to Alexander.
Yeah. Yeah, thanks for the question, Werner. So if you look at the guidance that we've provided for the year and the $1 billion, we were quite explicit on the oil price that we assumed in coming to that. And then we also provided a sensitivity where you could see what does a dollar movement in the gas price or a $5 movement in the oil price do. So it should be a sensitivity on those. If you reduce either one, depending on your outlook on either hydrocarbon stream or both of them, you can use that and you'll get down from the $1 billion to $455 to find that breakeven. Thank you.
Thanks, Werner. Sam?
Thank you very much. Our next question comes from Lydia Rainforth of Barclays again. I'm just waiting for her to join us one moment. Lydia, if you could unmute and ask a question.
Hi there.
Lydia, if you could unmute and ask a question.
Sorry, it took me a little while to get there. And I still haven't sorted out the camera charges. Thank you for taking the extra questions. Just when I'm thinking about sort of the bigger picture for Harbour and sort of you outlined the idea of we've got the next we've got details for the next three years, and then what's kind of the idea of you've got the resource base towards 2030. So when you're thinking of Harbour 2030, and I know you've talked Harbour 3.0, but they've almost Harbour 4.0. So what's that kind of overriding thing of what you want Harbour to be in four, five years' time?
Because I think that's that given everything you've outlined today around the different projects you have, it is still a business that is changing and improving, and it's just got that sense of really the long-term ambition. Thank you.
Thanks, Lydia. Let me have a go at that, and we did try to give a bit of insight into the longevity of the portfolio in the presentation today, so we've highlighted that we have a 19-year life when you look at 2C plus 2P divided by our production today, so quite a substantial portfolio of opportunities and options for us to invest in going forward, and the main idea is to maximize value from that portfolio, so a lot of it, we'll monetize ourselves through capital investment and project development.
You saw some of the highlights of what we're hoping to invest in and plan to invest in over the coming years, in particular in the little vignettes we had from our business unit leaders. So today, if you think about our portfolio today, our biggest producer is Norway, second biggest is UK, and then they trail off after that. I think if you kind of fast forward over time and as investment goes down to $2 billion or a bit under over the next couple of years, things look sort of stable at the top level, but there's a lot going on underneath all of that. And so you have the managed decline in the UK. So that becomes over time a smaller and smaller part of our portfolio.
And that's one reason why we're able to keep unit operating costs relatively flat, because the contribution from the higher cost center of production is getting less and less. And what's replacing that is the lower cost production from places like Norway, like Argentina, and then over time with developments in either Mexico and/or Argentina also kind of feathering in. And so you see sort of a transformation of us. And we get margins, stay the same, unit cost stays the same. Margins, depending on what your view on oil and gas prices do, may also improve. We have the lower CapEx, which spits off more cash flow. And so we become a different company, even though bottom line, top line might look the same. We're actually a different company from a portfolio standpoint. And we get a bit oilier as well, for example, as we make that transition.
So we're excited about that. We think the portfolio can sustain material production beyond 2030 and also cash flow. And that gets back to the confidence in our ability to maintain what is a very competitive dividend today and then also have considerable excess free cash flow for buybacks. Thanks for that, Lydia.
Thank you very much. Our next question comes from Mark Wilson from Jefferies. If you could please use star 6 to unmute. Go ahead and ask your question. Mark, if you could please press star 6 on your keypad on your phone to unmute yourself and then ask your question.
Okay, there we go. There's star six. Thank you for taking my questions. My first one is on the debt. Clearly, the balance sheet and the debt is in the focus for you. So this is to Alexander.
You spoke to volatility in the markets, which is fair enough. And I think you've reduced your leverage target to below one times, which is obviously where you are, but from 1.5 times. Can I just confirm that this is in response to market conditions rather than something you've seen internally? And also, what are the plans with that 2025 debt? So that's the first question. Second, a couple for Linda here. I think I picked up that the operatorship of the Zama Field is under discussion to move back to the actual private operators like yourself. Just comment on that and the timeline. And then finally, you're a company and obviously led by yourself, Linda, who's grown through M&A. Your stock is trading now below what it was heading into the Wintershall. Do you worry about approaches for Harbour in this?
Is that something you think could happen at this valuation? Thank you.
Yeah. Thanks, Mark. Alexander, why don't you take the first one, and then I'll take the last two.
Yeah. Thanks. Yeah. I mean, again, you've been following us for quite some time, Mark. So you know the history and what we've done in the past. So proactive management of the balance sheets is something we've done ever since we became Harbour. And repaying debts after doing an acquisition, having as much flexibility as you can. And we are an oil and gas company which have various commodity prices, anything that's impacting us, which you again see in our approach to financial risk management.
You also saw us hit out of the starting blocks as soon as we could after the completion of the Wintershall Dea transaction back in September to proactively manage that bridge facility we had put in place as part of the consideration for the Wintershall Dea portfolio. So we were quick to act in that regard. As it relates to the 25 bonds and other maturities, again, you should expect us to keep that proactive sense of managing the balance sheet like we've do ne over the last four years.
Thanks, Mark. The question on Mexico, it's a good one. So I think it's now been a couple of years ago when PEMEX was assigned the operatorship of the Zama unit. It's no secret that PEMEX has some financial difficulties. We're a good partner with them in two or three different places in Mexico.
So we're building a good relationship with them. New administration is now in the country. And I give them credit. They seem to be taking quite a practical and realistic approach to how they move forward. The importance of oil and gas production in the country remains extremely high on their radar screen and on their list of priorities. And so they're starting to be a bit more open-minded about how we can move some of the big strategic projects forward. And part of that is a discussion that we're now having about the possibility of maybe asking the Block 7 partners to operate in return for helping to move the project forward. So we think that's a good sign, gives us a bit more excitement about the project. And hopefully, eventually, it means that we have quite a bit of momentum building towards a possible FID.
Your last question was around, are we worried about someone making an offer for Harbour? I mean, that's not something that we worry about on a day-in or day-out basis. What we're really focused on is continued execution of our strategy. So we've just completed the Wintershall Dea transaction six months ago. We're now focused on operating those assets efficiently and responsibly, generating the cash flow from them, reinvesting part of that in the large portfolio we now have of investment options, focusing on the balance sheet and at the same time on shareholder returns, so the dividend, and then excess cash flow to shareholders over time. And that's what myself and the team are focused on. Thanks, Mark.
Thanks for the clarity. Thank you. Hand it over.
Thank you very much, Mark. Our next question comes from James Carmichael of Berenberg. Again, James, please unmute and ask your question.
Hi. Morning again, guys. Thanks for the follow-up. I just had a couple of quick ones. I guess you sort of talked earlier about the increased competition for capital in the enlarged portfolio. And obviously, one project that did get there was the Greensand CCS in Denmark. So just wondering if you could maybe provide a bit more color on the returns in that project and then whether you're still confident that the CCS business more broadly is scalable. And then just secondly on Indonesia, I guess that is an area where you've focused on a bit more in previous presentations, but it was sort of, I thought, notably absent today. So just wondering if your thoughts around Indonesia and the Andaman Sea, I guess in particular, has changed at all.
Yeah. Great, James. Thanks for that. On Indonesia, yeah, it's nothing conspicuous about its absence.
Maybe I'll say that from the presentation. It's that there's not time to cover everything, and given that it's been in the portfolio for some time, we decided instead to focus on the newer things, but I'll let Alan say a bit about the Andaman Sea in a minute. Let me take your first question, so Greensand, yes. Now we're in a situation where we've actually taken the investment decision on the CCS project. That's exciting for us. We have a 40% interest in it. I think Graham mentioned that earlier. The CapEx requirement is actually very low because we're reusing a lot of existing infrastructure. On top of that, we're deferring a lot of decommissioning costs because we're reusing that infrastructure that would otherwise need to be decommissioned in the near future, and we had a large EU grant.
So when you put all of those things together and you come up with a return, it exceeded our hurdle rate by quite a wide margin when it comes to returns. So we were very excited about that, able to get that one over the hurdle. Now it's a small bespoke project. I don't know that we'll find ones with that high of a return elsewhere, but nonetheless, we were excited to be moving it forward. Will we find others that we can invest in? I mean, they're going to have to compete for capital just along with everything else. What CCS does have going for it is that it can attract quite high leverage on a lot of the projects, up to 80%.
And if we factor that in along with a relatively low risk profile, if it's a regulated project, then we do see the potential for CCS projects, some of them, to meet or exceed our hurdle rates. How big will it be a part of our company going forward? It will depend on just that. Can we find ones that are scalable and cost competitive and deserve allocation of our capital? That will be the main consideration. Alan, now for Indonesia.
Yes, thank you. Just real quick on Andaman Sea. So we have made a number of discoveries that we're really excited about over the last several years. And of course, we see lots of follow-on potential there.
The challenge at the moment is just sort of thinking through the balance of the scale of the development and taking into consideration the future potential that exists relative to managing that in our overall financial framework and within our overall capital allocation priorities. So really just working through the various different development concepts that exist, looking at the economics of those, and then we'll decide on sort of what the future strategy is off the back of that. Great. Thanks.
Thanks, James. Sam?
Thank you very much. Our last question comes from Matt Smith from the Bank of America again. Matt, please unmute and ask your question.
Yeah, hi there. Thanks for having me back.
Just a couple to round out, I guess. I think a consistent sort of theme in terms of the close to 20-year reserve or plus resource life that you have at the moment, that being the sort of key step change with the transaction, the sustainability of the portfolio that you have. So I mean, clearly a big part of that will be about converting those 2C barrels today, first into 2P and then into production further down the line. So I just wanted to, what major projects perhaps would you point to in terms of the next events we should look for, whether that's feed, FID, when we reference Indonesia, a couple of projects in Mexico, Tuna, perhaps could you just, which of those projects are most progressed, I guess might be my question.
And then the second related to sort of portfolio sustainability, just wondered if you could clarify how many exploration wells you have assumed in the plan over the next few years, please.
Great. Thanks, Matt. I think I'll turn to Alan to give those a shot.
Sure. Thanks, Linda. Okay, so taking the last one first, eight exploration wells in Norway, and those are over the three-year period. We've got a few this year that we're excited about and following the streamlined strategy in terms of close to infrastructure that we can turn around reasonably quickly. And staying in Norway, as Mikkel mentioned, we have a number of projects that are in the pipeline, and we'll see FID on those over the next several years, probably more heavily weighted in terms of volumes to the 2026-2027 timeframe.
But we should expect to see some reserves booking as we take decisions on those projects. And then larger scale, you touched on some of the key ones, but of course, now that we've appraised Kan and that's looking good, and we have commitment with Zama and the potential future changes there, we're going to be moving those forward in parallel. You touched on Tuna, so it's again at an advanced stage in terms of the subsurface and engineering work. So we'll be in a position to evaluate where we are with that over the course of the next year or two.
And then probably the Andaman Sea is a bit longer term, just as I mentioned in the last question. There's a bit more work that needs to go into assessing the development concepts there, thinking about the requirements for any future appraisal and how it's all going to tie together.
Right. Thanks, Alan. Thanks, Matt, for the questions. Sam, I think you said that was the last question. Is that right?
Yes, that was the last question. I want to hand back over to you, Linda, for closing remarks.
Great. Thank you. Well, thanks everyone for joining today. I hope what you've seen is just a glimpse of the great team that we've assembled here at Harbour Energy and also the excitement we have about the portfolio following the closing of the Wintershall Dea transaction and all the opportunities embedded in it for the future.
It makes us, I know we're excited about what the future holds for the company, and I hope you've seen a bit of that today. So thanks once again for joining, and thanks for all the good questions.