Good to go? Good. Great. Thank you. Good morning. I'm Linda Cook, CEO of Harbour Energy, and thanks for joining us this morning for Harbour's first full year results presentation. It's really nice to see some of you here in person. I'm gonna get us started with some performance highlights and then turn it over to our CFO, Alexander Krane. Alexander will cover the financial results and guidance. After that, we'll have some time for Q&A, during which we'll be ably assisted by our two business unit leaders, Bob Fennell, who runs the North Sea for us, and Stuart Wheaton, who's in charge of international. If we could go to page four, please. I think we're there. 2021 was a transformational year for Harbour Energy.
The key highlight was, of course, the merger with Premier, completed almost one year ago today, so a little bit hard for some of us to believe. We've accomplished a great deal since. Although we did admittedly have some operational challenges during last year, we did maintain safe and responsible operations with annual production of 175,000 barrels per day. Importantly, we ended the year with a strong fourth quarter, with production well above 200,000 barrels per day, I think highlighting the quality and the potential of our portfolio. Operating costs and CapEx both came in a bit under guidance, which is good. With COVID becoming more manageable, we were able to complete a number of material maintenance campaigns in the second and third quarters and successfully ramped up drilling activity in the second half of the year.
Now we're realizing the benefits of both of those programs. At Tolmount, I'm pleased to say that good progress has been made in spite of the latest COVID variant and the series of bad winter storms that swept across the U.K. over the past few weeks. We're in the process now of starting up as we speak and very close to first production. The project is, of course, an important milestone for Harbour and also for U.K. gas supply. On a gross basis, Tolmount is expected to deliver an increase of 6% to the U.K.'s domestic gas production. Also, during 2021, we took steps to align the portfolio with our strategy, exiting exploration in Brazil, as well as the Sea Lion project in the Falkland Islands.
As I said before, we believe there are lower risk and lower emissions opportunities to replace our reserves and growth than through frontier exploration or multi-billion dollar new developments in remote areas. Harbour is now in a solid position operationally and financially. That's not by accident. We've always been focused on prudent capital allocation and risk management. I think the importance of this has never been more evident than it is today with the triple impact of a global pandemic, an uneven path towards a lower carbon economy, and more recently, the terrible events we've seen unfold in Ukraine. In 2021, we generated almost $700 million of free cash flow, reducing our net debt to $2.3 billion at year-end. In the two months since then, our net debt has reduced further to $1.9 billion at the end of February.
This continues our track record of deleveraging quickly following completion of major acquisitions. With our strong balance sheet and production outlook for 2022, we have significant near-term optionality over capital allocation. One thing we don't plan to do, however, is to increase spending. CapEx is already set to be about 30% higher than it was last year. As we said at our Capital Markets Day in December, we think that's about right for our portfolio today. We like the discipline this enforces. We like the fact that it challenges us to high grade our projects, so we'll remain focused on delivering within our existing CapEx guidance for the year. Beyond that, with the extreme volatility we're currently experiencing, oil price swings of $10 per day haven't been unusual recently.
U.K. natural gas prices were more than GBP 6 a few days ago, and now they're at one-third of that. We have the uncertainty around the global economy in general. It's just hard to predict where we'll end up at year-end from a cash flow standpoint. Having said that, in the event that commodity prices remain elevated and we continue to delever, shareholder returns in 2022 beyond the $200 million dividend announced in December will be considered as we move through the rest of this year, all within the context of our existing capital allocation framework. Next page, please. Now turning to safety, something near and dear to my heart and our company's number one priority. History has shown that safety incident rates increase during times of change and distraction.
We had those conditions in spades during 2021, with the combination of dealing with the pandemic, completion of a merger, and combining two operating organizations in the U.K. Given all of that, while never completely satisfied as long as we're having a single incident, I do feel good about some of the progress we've made. We had no serious injuries during the year, and we worked hard to protect our offshore workforce from a major COVID outbreak. This required quarantine periods for people before heading offshore and then longer offshore shifts, both meaning sacrifice by our staff and their families. For the year, our recordable injury rate was comparable to 2020, even though maintenance and drilling activity were significantly higher. We also had a number of notable achievements, some of which are listed on the chart.
One in particular I'd like to highlight is at the Greater Britannia area, where we took over operatorship in 2019 just prior to the outbreak of COVID. During the year, we completed an extensive maintenance campaign at Greater Britannia. Yes, this impacted production. We all saw that. It enabled us to reach a record low maintenance backlog on the Britannia facility. Completing this maintenance improved reliability, and since then, Greater Britannia has been averaging 97% reliability, top quartile by any standard. Even more important, though, is that completing all of this maintenance improves asset integrity and protects the safety of our workforce. Now on to page six. The merger with Premier made us the largest oil and gas company in the U.K. by production and market cap and resulted in us becoming a public company.
With that listing came a lot of interest in our shareholder register, given the initial Premier creditor position and the lockups associated with the EIG investment investors. An update on this is in the upper right. The shareholder register has evolved over the year, with our stock available to trade increasing from 18% on day one to 63% today. The last remaining lockup, which is over EIG's 37% stake, expires now in just two weeks. While we can't speak for EIG's intentions, what we can say is that they continue as a private equity firm to invest in oil and gas, and they remain supportive of our management and our strategy. While the merger itself was a complex transaction, the integration process that comes afterwards can be equally challenging, especially if doing it while everyone's working from home during a global pandemic.
I'm pleased to say we're now returning to our offices, and all the various integration streams are more or less on track. The reorganization was completed late last year. We're now in one office instead of two in London, and we'll soon be in two offices instead of three in Aberdeen. The new EMS, scalable to accommodate additional acquisitions, has been designed. We're already loading it with data, and we expect implementation to be complete before year-end. The work to consolidate the supply chain by combining and renegotiating contracts, capturing benefits of scale, is also underway. These and other synergies will increasingly flow to our bottom line as we move through the year. With respect to the portfolio, the merger brought together two complementary businesses and diversified our asset base.
Our 2P reserves in creased to 488 million barrels of oil equivalent, reflecting a reserve replacement ratio of 157% for the year, even with the impact of the previously announced revision at Tolmount as a result of the findings from one of the wells in last year's development drilling program. This performance is in line with our strategy. We aim to keep production flat in the near term by investing in our existing asset base, and we aim to grow and diversify longer term through acquisitions, which is exactly how we built the company over the last few years. We understandably get a lot of questions today about what the current environment and high commodity prices might mean for our strategy and, in particular, for further M&A. Our strategy was set for the long term.
Since we made our first acquisition in 2017, we've seen Brent range from $35 per barrel to $130, and U.K. gas prices range from around GBP 0.2 to over GBP 6. The large transactions that we make can take months, if not a year, to analyze, discuss, negotiate, agree, and complete. While, of course, it's more difficult to reach a shared view on value when there's this much volatility in the market, we still see the potential for interesting opportunities in the coming years that, as always, will remain very disciplined. Turning now to production on page seven. Production in 2021 averaged 175,000 barrels per day, split roughly 50/50 between oil and gas. Our production level last year reflected three things. First, the addition of the Premier assets from March 31st.
Second, the impact of a low level of drilling activity as a result of our COVID drilling pause during 2020. Third, significant downtime for maintenance, including to address maintenance deferrals from 2020 when we were minimizing offshore staff in order to protect them from COVID during the early stages of the pandemic. As we moved towards the fourth quarter last year with the maintenance largely behind us and the widespread availability of COVID vaccines, we were able to return to more normal operating levels. As a result, production in the fourth quarter averaged 214,000 barrels per day, reflecting limited downtime and improved efficiency, benefiting from the maintenance work as well as from contributions from new wells such as Buzzard Phase Two and the EIG well at Elgin-Franklin. Next page, please.
The strong operational performance has continued into 2022, with production to the end of February averaging 219,000 barrels per day. Our guidance for the year remains unchanged at 195,000-210,000 barrels per day, which at the midpoint is an increase of about 15% over last year. We expect to become a bit gassier as we move through this year, ending at an average of around 55% gas, 45% oil. We're benefiting in 2022 from a full year's contribution from the Premier acquisition and higher production efficiency as we have more normal maintenance plan, with the only significant campaigns being at Catcher, Elgin-Franklin, and J-Area.
Production is also supported by the higher level of investment in the second half of last year and throughout 2022, primarily targeting high value, short cycle investment opportunities within our existing producing fields. We've had some positive performance recently from a number of wells, including Callanish F5 at Britannia, which came on stream in 2021 and continues to outperform, improved results from the ongoing drilling program at Clair, and more recently at Judy South, which was brought on stream in February at levels higher than we previously thought. In addition, of course, we expect Tolmount on stream very soon. Page nine, please. The projects made considerable progress since our Capital Markets Day in December, even though hampered by the latest COVID variant and multiple storms over the past weeks. All of the electrical inspections are now behind us and the necessary repairs complete.
The testing and commissioning of the platform is also essentially complete, and the various startup activities are well underway. These include acceptance of the systems from the EPC contractor by ODE, the duty holder, and a vast majority of these have already been achieved. The remaining steps will be the start of the back gassing of the pipeline with gas from shore, which is imminent, and then the well to pipeline testing, followed by first production. All of this will take a couple weeks, so we're really now in the home stretch. Once on stream, the project will increase U.K. domestic production by about 6%, a timely addition. Our share of production is expected to be 20,000 barrels per day, about 95% of that gas. Turning now to our capital program.
We have significant opportunities in our asset base to support production at current levels in the near term, while continuing to generate material free cash flow. The majority of our CapEx is allocated to these lower risk, high return investments, with over 90% of our 2022 drilling and development spend breaking even at less than $35 per barrel and GBP 0.35 per therm. Today, we have four rigs actively drilling, including one that recently arrived at the Catcher Area, where we continue to see strong reservoir performance. The rig will bring on stream the Catcher North and Laverda satellite tie-backs and add production from the Burgman field. We also currently have two rigs at J-Area, one drilling the JM development well and the other drilling the RD well, our first target from the Judy platform.
Meanwhile, Talbot, which was successfully appraised last year, is being progressed to an FID later this year. The number of rigs across our portfolio will double to eight by mid-year, with the return to drilling at Beryl and the addition of three rigs in Southeast Asia. A busy second half of the year for us from a drilling standpoint. All of this will help support our production levels into 2023 and beyond. On the next page, you see I've mentioned three rigs in Southeast Asia. One of those will arrive in just a few weeks time to drill the Timpan prospect in Indonesia. We, along with our partners, BP and Mubadala, will be testing a very large gas prospect in the heart of a region with significant growth in gas demand.
However, as excited as we are to drill the well, of course, it is an exploration well, called that for a reason, so we just need to wait and see. We have two other material international growth opportunities, Tuna in Indonesia and Zama in Mexico. At Timpan, following last year's successful appraisal campaign, we're now in the midst of assessing the data from the new wells and finalizing the development concept. We aim to submit the development plan later this year, and if all remains on track, could reach FID in 2023. Similarly, at Zama, we're working with Pemex and other partners on the unit operating agreement and the development plan. We expect the unit operating agreement to be finalized soon and assuming alignment with partners, a possible FID next year as well.
These two projects, Zama and Tuna, are key components of our 2C resource base of 460 million barrels of oil equivalent. While our business outside the U.K. today is relatively small, it has embedded in it options to serve as a potential platform for future growth and diversification moving forward. Finally, on page 12, a few words about our environmental performance, focusing on greenhouse gas emissions. We had a busy year on this front as well, as you can see by the list of achievements on the slide. Most importantly, we set a goal to achieve net zero by 2035. There's no silver bullet for this.
It will take commitment, significant effort on many fronts, including reducing our own emissions, considering investments in things like electrification and carbon capture and storage, both of which will likely require government financial support and acquiring offsets. We made progress on all of these fronts during 2021, and our emissions came in under our internal target. We set our investment criteria to include various scenarios for the cost of carbon. We're screening all M&A opportunities based on emissions intensity, and we incorporated targets into our incentive pay and our senior lending facility. Our two CCS projects also continued to progress. The Acorn project in Scotland was awarded reserve status under the U.K. government's phase one process to select projects to fund as part of the country's own net zero goal.
Our V Net Zero project, which we lead, we were granted the licenses to store CO2 offshore in the depleted Viking fields. We reached agreement with Vitol, Phillips 66, and other Humber area emitters to be their preferred CO2 storage and transport solution. Finally, we took our first steps in the greenhouse gas emissions offset market last year. Today, we've entered into, excuse me, commitments to acquire 1.2 million tons of offsets across a wide range of projects in Latin America. Of these offsets, we retired 400,000 tons, one-third of the total, with respect to our emissions in 2021. This led to an improvement in our net greenhouse gas intensity to 17 kilograms of CO2 equivalent per barrel, well below the U.K. offshore average. Still, though, quite a journey ahead of us, but I think a good start along the path.
Now I'll turn it over to Alexander to talk about financial results and guidance.
Thank you, Linda. Good morning, everyone, and, especially to the folks here in attendance in our office. It is just fantastic to see people face-to-face again. For my presentation today, I'll start by reminding you of our capital allocation priorities, which we are delivering against. I'll talk you through our hedging position and our 2021 financial results. I'll then provide some color on the cash flow potential of our business and how we plan to allocate that cash flow in line with our capital allocation policy before I'll finish just talking about the 2022 outlook and guidance. First, how do we think about capital allocation? Now, as a reminder, we aim to generate robust and resilient cash flow through the cycle, and we have three competing, equally important priorities for our cash flow.
Namely, safeguarding the balance sheets, ensuring a robust and resilient asset base, and delivering shareholder returns. Let's start with number one, safeguarding the balance sheets. Just by looking out the window and reading the daily news, we are reminded about the volatile environment that we operate in. It's a cyclical industry, so ensuring that we have a robust balance sheet that can withstand this volatility and make sure we always have sufficient liquidity through the commodity price cycle is just imperative for us. We upsized our RBL, and we increased our leverage to finance the Premier merger. We were comfortable in doing so as we had good visibility on the forward deleveraging path supported by the hedging program. By year-end, we had reduced net debt by $600 million, down to $2.3 billion, excluding amortized fees, and our leverage was down to 0.9x.
A significant improvement on our position as of March thirty-first, and in line with the target of having less than one and a half times net leverage through the cycle. Now this is evidence of our counter-cyclical approach and how we manage the balance sheet, where we seek to pay down debt when realized commodity prices are high, reducing our leverage, such that we will be well-positioned to take advantage of market opportunities when commodity prices are low. The second priority is to ensure a robust and diverse portfolio. We look to continually invest in our portfolio and allocate capital to the highest return projects to ensure that we have a resilient and diverse asset base supporting near-term cash generation.
More than 90% of our 2022 development and drilling CapEx is delivering breakevens of less than $35 per barrel or GBP 0.35 per therm. Our existing portfolio has embedded in it sufficient, attractive, low-risk drilling and other opportunities that are enabling us to maintain production levels in the near term and delivering positive cash flow. Ultimately, however, as Linda Cook mentioned, we seek to grow and diversify through disciplined and value-accretive M&A. In 2021, we received a 157% 2P reserves replacement, primarily driven by the Premier merger. In line with our strategy, while keeping our leverage broadly flat year-over-year. While our reserve life is perhaps a little lower than where we would like to see it, we are certainly not targeting 15 years plus of reserve life. Thirdly, shareholder returns.
We do believe a commitment to shareholder returns is an important part of our equity story. We announced at the CMD at the end of last year an initial $200 million per annum dividend. We look forward to paying the first distribution in May, which will be the $100 million dividend with respect to 2021. This represents a 15% payout ratio. As it says here on the slide, as Linda has already mentioned, we will consider additional shareholder returns in line with our capital allocation policy as we rapidly de-lever throughout the year. Turning to the next slide. We have an active hedging program in compliance with the minimum and the maximum hedging volume requirements set out in the RBL.
This hedging program has served us well in the past, while today we have an unrealized loss position for our 2022 to 2024 hedges, as both oil and gas prices are significantly higher than our hedge prices. However, as you can see, we expect the bulk of this to unwind over the next 18 months or so, with an exposure to commodity prices increasingly significant over that period. Specifically, we've hedged 70% of our production in 2021, 60% this year, 40% next year, and so far, only 20% of 2024. All of our hedging is carried out at the corporate level and then pushed down into the operating companies based on forecasted production at the time each hedge is placed. But we do not hedge individual assets. The chart here is similar to what you saw at our Capital Markets Day.
The only difference is that we've split out liquids production into oil and NGLs, and our gas production we've split by U.K. and international. We do not hedge the NGLs, and we've currently not hedged any of our international gas. You can see that for 2021, we had hedged pretty much right at the maximum limit as determined for our RBL. In particular, we ended up being almost 100% hedged on our actual U.K. gas production. In part, the higher hedging was deliberate in order to lock in the returns from the Premier deal, maintaining our borrowing base, protecting our balance sheet, and in part, also driven by the lower actual gas production that had been originally forecasted.
For 2022, you can see from this chart that we are forecasting liquids production to be around 5%-6% higher and gas production to be almost 30% higher. Here, we will of course be benefiting from Tolmount coming on stream, plus a few other new wells which are predominantly targeting gas. As such, over 20 kboe per day of our production is exposed to U.K. spot gas prices. We've also taken advantage of the recent increase in commodity prices to put on some additional hedges for 2024. We've sold forward around 4 kboe per day of U.K. gas and around 10 kboe of oil at prices above GBP 1 per therm and $80 per barrel respectively. In doing this, we did consider other option structures, including straight puts, given where our leverage and where our balance sheet is.
These structures were just very, very expensive. By way of context, the equivalent for an at-the-money put option in 2024 is around $17 per barrel or GBP 0.56 per therm. Likewise, the skew on the collars we also deemed unattractive. As we mentioned at our Capital Markets Day, we have removed the minimum hedging requirement in year three, which is helpful, especially on the crude side, where hedging that far out on the curve is now not attractive due to the lack of liquidity there. If we move to a review of the 2021 full year financial statements, I'll start with a couple of thoughts on the income statement.
Now, do keep in mind that the reported 2021 figures here, they're made up of 12 months of legacy Chrysaor and only nine months of legacy Premier from April first until the end of the year. The comparative figures you see here from 2020 are those of Chrysaor alone, as this entity is deemed as the acquirer for accounting purposes. You'll see here that revenue and other income is up 50% year-on-year, increasing from $2.4 billion to $3.6 billion. In here, we had crude sales that accounted for around $2 billion. This is up 40% on the prior year, with higher sales volume more than offsetting the slightly lower post-hedge realized price. Gas sales accounted for $1.3 billion. That's up around 60% from the prior period.
This came as a result of significantly higher post-hedge realized gas prices more than offsetting the lower production volumes. Specifically, we realized GBP 0.54 per therm for our U.K. gas and the equivalent of GBP 0.83 per therm or $11.70 per Mcf for our international gas. Condensate sales and tariff income was around $0.2 billion. As you will have seen from the previous page, around 5% of our production is NGLs, where we tend to realize a 30% discount to Brent. We also had some one-off items recognized this year as other income. This included a gain on EU emission derivatives of $51 million, and a settlement of $40 million from ConocoPhillips, which related to adjustments to the consideration price paid for ConocoPhillips' U.K. business back in 2019.
Operating costs were $976 million, which equates to $15.20 per BOE, in line with our previous guidance. Costs are a bit higher as we added a Premier portfolio, and we carried out extensive maintenance in 2021 compared to 2020, when all non-safety critical maintenance was deferred into this year. Furthermore, we had some planned outages, and we also had an unfavorable move in this U.K. sterling versus dollar FX rates. G&A amounted to $103 million, up from the prior period. I would say about one-fourth of this is deal cost related. However, by the end of Q4 2021, we had implemented a single integrated organization, which in turn should allow us to realize G&A savings across the group going forward. We had EBITDAX of $2.4 billion for the year.
This is up around 35% on the prior period. DD&A amounted to $1.4 billion. This is equivalent to $21 per BOE on a unit basis. It's higher, so the increase per BOE compared to 2021 is primarily due to higher depreciation rates on the acquired right-of-use lease assets, which is Catcher and J-Area. We had impairments this year of $117 million. This is split broadly evenly between the East Irish Sea and Clair. At East Irish Sea, we took the decision not to restart production from Millom, which was shut down back in 2020. While the small impairment on Clair reflects the poor drilling results in 2020, we've subsequently seen improved performance from the Clair drilling program in 2021. Furthermore, we expensed a number of unsuccessful exploration wells this year.
The expensed exploration costs of $305 million includes the Dunnottar well here in the U.K. and the Norwegian wells, Jerv and Ilder. In addition, also reflected in this number is the write-off of our carrying values for Sea Lion and our Brazilian exploration acreage of $74 million and $56 million respectively. This follows the decision to exit these projects. Net financing costs amounted to $0.3 billion. There's a pretty good note five in the financial statements that provides all the detail on these costs. In that note, you'll see that the main items, they include interest payable of $102 million, quite similar to the previous year, despite borrowing levels going down, but this is offset by a lower interest rate.
You'll also find various bank fees of $63 million, and you'll find an accretion expense related to the decom of $78 million. When it comes to the tax expense this year, we have an effective tax rate of around 68%, which is elevated primarily due to the aforementioned Brazil and Falklands write-downs within the pre-tax profit, which had no associated tax relief. There are also other one-time impacts related to items such as transaction costs. If I were to adjust for these one-time items, the normalized effective tax rate would be closer to 40%. After deducting the tax expense of $214 million, net profits for the period was $101 million, compared to a loss of $778 million last year. Turning to the balance sheet on slide seventeen.
The balance sheet here, they show total assets have increased quite significantly from $9.5 billion last year to $14.5 billion. Again, driven by the merger with Premier Oil. There's an extensive note 12 on business combination that contains all the detailed information on the purchase price accounting. In summary, after accounting for all the additions into PP&E and other intangible assets, we booked $300 million to goodwill. As part of the merger and movement since, we have a $1.9 billion deferred tax asset at the end of the year. This includes $1.3 billion in respect of U.K. tax losses. Again, note eight provides a full breakdown of the goodwill balance of $1.3 billion, and it describes its build-up over the three transactions that Chrysaor and Harbour have undertaken.
Plus, also details around the full review we've done on impairment testing at the end of the year. Provisions for decommissioning liabilities increased to $5.4 billion with the Premier merger. Now, it's important to note that this is a pre-tax number, and it's estimated using a risk-free rate of return. Applying a higher discount rate, like 10%, and looking at this on a post-tax basis will both materially adjust this liability downwards. Again, as a reminder, this will unwind over the next decades, and we estimate around $300 million in spending per year in the medium term. In other liabilities, we've included the unrealized loss position of the group's commodity hedges booked pre-tax with a corresponding post-tax debit to equity. In addition to the commodity hedges, trade and other payables make up this balance of the $5 billion number.
Now let's move to slide 18 and have a look at cash flow. This slide describes the change in net debt together with the cash flow movements for the period. Net debt at the end of 2020 was $1.5 billion, which increased over the year to $2.3 billion, primarily driven as a result of the drawdown of $1.3 billion to fund the merger. Operating cash flow before decommissioning spend and tax payments for the year was $2.1 billion, up 24% on the prior year, and reflecting a negative working capital of approximately $0.6 billion.
With most of our sales done on a thirty-day payment terms, this was primarily driven by the ramp-up in production from around 165,000 barrels per day in December 2020 to well in excess of 200,000 barrels per day in December a year later. This was, of course, combined with significantly higher commodity prices. Investing cash flow comprised of CapEx, decom of $889 million, offset by cash balances from Premier of $97 million. In financing activities, excluding the movements in debt principal, of course, this amounted to $519 million. In this number, we have included things like bank interest and fees of $205 million and lease payments of $160 million, primarily related to the FPSOs. Tax paid was $280 million.
Around $36 million of this was international, with the rest being U.K. tax paid. As a result, we generated $678 million of free cash flow for the year. This was up 21% on the prior year, where we had $562 million free cash flow. Slide 19. As a result of the combination of higher production, and if we assume a continuation of recent strong, recent stronger commodity prices, we currently see significant improved cash flow generation in 2022, which could result in us rapidly deleveraging the balance sheets. This would be in line with our capital allocation priorities to repay debt when commodity prices are high.
We've had a very encouraging start to the year, both operationally and financially, and this is reflected in our net debt reducing from $2.3 billion, which excluded unamortized fees at the end of 2021 to $1.9 billion at the end of February. We would, however, normally expect January and February to be strong cash flow months for a number of reasons, but primarily because there is little planned maintenance, and these months are therefore relatively light CapEx months. Based on commodity price sensitivity of 100 barrels for crude and U.K. gas of GBP 2 per therm, free cash generation post a $200 million dividend would be in the range of $1.5 billion-$1.7 billion, assuming a midpoint of our production guidance.
Each $10 per barrel change in crude would move this around by $150 million, and a GBP 0.20 per therm change in gas would move this around by approximately GBP 90 million. Our capital structure is simple but diverse. We have a secured RBL facility of $4.5 billion, including a $1.5 billion carve-out for letters of credit. In October, we completed our debut $500 million bond issuance using those proceeds to repay the junior Shell debt facility, providing us with additional flexibility over the future marketing of our hydrocarbons. At year-end, we had significant liquidity of $1.6 billion. Slide 20. We showed this slide in our Capital Markets Day in December, and we've updated it to reflect commodity price sensitivities.
Specifically on this one, the navy blue bars, they show our cash flow and CapEx expectations at the Capital Markets Day price assumptions of $70 per barrel, GBP 0.90 Per therm in 2022, then moving down to $65 per barrel and GBP 0.60 In 2023, and then $60 and GBP 0.55 In 2023-2024, sorry. The navy plus the gray or light blue bars on top show our expectations at the current price sensitivity of $100 per barrel and GBP 2 per therm. As you can see from this illustration, at higher oil prices, we are not planning on increasing our capital expenditure. We will continue to invest through the commodity price cycle.
As Linda said earlier, our current CapEx is about the right level for a portfolio of our size, and we do like the high-grading prioritization of capital that this enforces. Finally, we announced an initial $200 million per annum dividend in December, which we have not changed. As a result, we expect to generate materially more cash flow if prices stay elevated with the potential to be net debt-free in 2023. If commodity prices do remain elevated and we continue to de-lever our balance sheet, then we will consider additional shareholder returns as we progress through the year. In short, we have significant optionality over our future capital allocation, including additional shareholder return. This final slide shows our summarized outturn versus 2021 guidance and our guidance for 2022. Naturally starting with a wrap-up of 2021.
Production was 175,000 barrels of oil equivalent per day, which is in the middle of the previous guidance of 170-180. This does reflect a strong operational performance at the end of the year, with improved uptime and new wells coming on stream, helping to offset the natural decline. Operating costs, which was the favorable end of the previous guidance of $15-$16 per barrel, ending the year at $15.2. CapEx and decom totaled $935 million compared to previous guidance of $1.1 billion, with savings and released contingencies across the board with no specific single event. Strong finish to the year, together with the lower CapEx and OpEx, benefited our free cash flow generation for the year and our net debt position.
For 2022, we are reiterating our guidance from the Capital Markets Day. Production is expected to be between 195-210, so approximately 15% increase on 2021 due to improved uptime, less planned maintenance programs, and there's a number of new wells coming on stream, including Tolmount, as we continue to invest in our portfolio to maintain production while generating material cash flow. We're guiding to $15-$16 per barrel in OpEx this year. With Tolmount coming on stream, total expenditures are expected to increase. However, the field contributes to lower OpEx per BOE, with the CapEx element of Tolmount tariffs classified as lease costs. This is offset by higher unit operating costs at some of our more mature fields, such as Ailsa, where OpEx is largely fixed.
For 2022, we expect production and development CapEx of around $800 million and exploration and appraisal spending of around $200 million. Most of the 2022 P&D spend is in the U.K., with international only accounting for around $100 million. E&A is a mix of activities and wells across the portfolio, including the Timpan well in the Andaman Sea, which is scheduled to spud in the second quarter this year. I would also just add that we continue to monitor inflation closely. Unlike in some parts of the world, we are currently seeing limited impact on our drilling rig costs, most of which were contracted before the start of this year. We are, however, seeing some pressure on steel costs, subsea equipment, and certainly longer lead items than in the past. With that, I'll turn it back to Linda for some concluding remarks.
Thank you.
Thanks, Alexander. Just a couple of slides now to wrap it up. On this page, we have a summary of our outlook for 2022. We've covered all of this already, so I'm not gonna go through it in detail. I think our main messages are that we ended 2021 in a strong operational and financial position. We're now back to more normal operating conditions and off to a good start in the new year. Alexander updated you on our outlook for cash flow. As we all know, commodity prices remain very volatile, and there's a lot of uncertainty with respect to global supply and demand in the economy in general. We need to keep in mind, it is still only mid-March.
If we find commodity prices remain elevated and continue to de-lever, we'll consider what this might mean for shareholder distributions. As we move through the year, and I realize now this is the fourth, if not fifth time we've said that this morning, but I think we're just anticipating that this will be one of the key questions, so, we wanted to be very clear. In the meantime, we're doing what we can to address energy supply concerns. Production in 2022 is so far up over 20% over 2021 levels in Harbour, and we're continuing to invest in our existing assets to support production in future years. The last page, please. Finally, just a summary of our value proposition, our rationale for why we believe we present a unique investment opportunity.
We're a pure-play upstream oil and gas company, no investments in downstream chemicals or renewables. We have a large, diverse portfolio of producing assets, generating considerable cash flow and with increasing exposure to commodity prices. Finally, a strong balance sheet and optionality around future capital allocation, including the potential for increased shareholder returns. It's been a busy year for us in Harbour Energy, and as I said earlier, hard to believe our first year is nearly behind us, and we remain, I hope you can see that, very excited about the future. I'm gonna leave it there. We hope you found this helpful. We're now gonna take questions from those of you who, we're so pleased were able to join us in person.
For those of you listening in, if you have questions, please do submit them to our investor relations, and we'll be sure to get back to you. As I mentioned at the start, joining us for the Q&A are two business leaders, Bob Fennell, running the North Sea, and Stuart Wheaton, responsible for international. For those in the room, please just raise your hand if you have a question. Someone will bring a mic to you. Please, if you could just introduce yourself first, especially for the people who are listening in, that would be great. Thank you.
Morning. Thanks very much for the presentation. It's Nathan Piper from Investec. Thanks for the rare treat of being late for our in-person meeting this morning. Thank you for that. Just a few quick questions, if I may. First of all, on the shareholder returns, you've already reached your net debt target to within that or below that range. You've outlined you're gonna make $1.5 billion-$1.7 billion this year. I mean, how much of free cash flow. How much of that money do you need to keep? I mean, what kind of scale of shareholder return could we be thinking about, whether that's buyback or dividend? It's the first question. Maybe I'll go all three, if I may.
Secondly, I guess one of the worries on, or concerns or thoughts on Harbour is around their ability to your ability to convert 2C to 2P, and therefore, maintain the production base. Can you give a kind of a sense of scale of the, of the prospective FIDs through 2022 in terms of what kind of reserves there could be, you can book from the back of those? Then maybe last one on Tolmount. Are we really in the sort of predictable final stages of startup at Tolmount, or are there any significant projects left to complete in order for that gas to start flowing in the next few weeks as you asked, as you outlined? Thanks.
Great. Thank you. I'll let Alexander talk a bit about shareholder distributions, but then I'll take the other two, maybe with some help from Bob. My only comment on the first one is I'm just reminded of this phrase about not counting chickens before they're hatched. Anyway, let me turn it over to Alexander.
Yeah, no, and there are a couple of points probably to make on this. I mean, the 1.5x leverage, you know, the target is to be well below it. All of this sort of starts with the capital allocation policy of safeguarding that balance sheet. I think although we're illustrating here, a $100 crude and GBP 2 per therm scenario, that's not necessarily what we're planning on. This is a sensitivity to show what we think the potential here is. I think we just need to be mindful and just look at where we are.
I mean, the volatility that we're seeing these days, commodity prices going up and down, inflation reaching record levels that we haven't seen, more and more sanctioning, self-sanctioning happening every single day. It's a fairly difficult and unpredictable world we're living in. Not to mention there's a full-on war going on in Europe. It's you know, it's not the responsible thing, we think, to increase that dividend level now. We're going to the Annual General Meeting and you know, asking for a authorization to potentially do buybacks. If this higher commodity environment you know, remains with us, then yes, we'll not have much debt by the end of the year and potentially debt free next year.
That's, you know, we'll reassess and see if it makes sense to either increase dividend levels, buy or institute buybacks. You know, but we think the responsible thing is to have a few months and see, you know, how 2022 develops. It's just, you know, insane volatility sort of thing. The point, the number one out of the three capital allocation principles of having a robust and safeguarding that balance sheet has probably never been more up in the air and more important than what we're seeing today. Yeah.
Good. Thanks, Alexander. On the question about our resource base, as we said at Capital Markets Day, we do have line of sight to the production, to the projects that we would invest in to help us maintain production more or less for the next two or three years, and I think that hasn't changed. Our reserves ended up exactly about where we thought they would at the end of last year. They've been audited now by our independent reserves auditor who came in within 1% of those. We feel we have a really good, solid understanding of where we're starting the year with. Line of sight in terms of exactly which projects. I'll let Bob talk a bit about the things we're either spending on this year or taking FID on this year in the U.K.
As I mentioned, Tuna and Zama are both in our 2C resource space. They're about a third, roughly, of that resource space, and we're hoping if those stay on track that one or both could reach FID next year. Those will be significant movements for us outside of the U.K. Bob, do you wanna say a few words about some of the things you're excited about?
Yep. I will do that. There's plenty to be excited about, there really is, in the portfolio like this. I think, first of all, you know, there's a certain amount of the capital that has been allocated to the North Sea, and we've seen from last year that we tend to underspend that, and there are various reasons for that. What we've wanted to do, and I should also say that when we didn't drill in 2020 for COVID reasons, we saw the impacts last year. You know, it's really good to continue drilling as long as the value's there. Things that we're looking to convert from 2C to 2P this year would be in the Callanish area around Britannia. There's more to do in the J-Area.
Tolva is the obvious one that we're bringing forward this year as well. There's also a field in the Britannia area called Leveret, which is across two blocks. It's very interesting looking and we're looking to do sort of like a joint development with the other owners around that area. If we then sort of look further out, we're looking to the barrels with the tertiary development and also more on Britannia and J-Area. We're seeing with J-Area that recovery factors in certain horizons are lower than analogs, so there's subsurface work being done there to see what can be done to improve recovery factors.
You know, there's other things in the non-operated portfolio with Clair Phase Three and things like that coming through as well. You know, very fortunate with the sort of the large portfolio that there's heaps of opportunity that we're accelerating.
Yeah. I think Bob made a good point about the drilling slowdown and the impact that that has, and it's a little bit hard to quantify. How do we increase reserves from our existing portfolio? It's not just a reservoir engineer sitting there and deciding one day that he's gonna assume that they're higher. They need data. How do they get the data? Two ways. One is through just continued production performance. We're continuing to get that, of course. What we were missing was a lot of the data you get from the drilling program, because we put a complete pause on our drilling activity when COVID broke out for all the right reasons.
We had limited drilling towards the end of 2020, and then through at least the first half, if not first three quarters of last year. We had this gap in being able to accumulate data and continuing to do the analysis required. Now we're back. As I said, four rigs running today, eight by the middle of this year. We're excited about that from a production standpoint, but also because with each of those wells you drill, we're gaining new information about the reservoir, and that'll certainly help us sort of continue to assess and see what can be either added to or moved from one category to another. On Tolmount, I'll let Bob talk about the remaining couple big steps coming, the degassing and the lining up of the wells and testing.
Just to say, you know, we can't be precise. At this stage, it's very difficult to be precise. At any stage, it's difficult to be precise. There's, you know, a few steps that need to get to, that need to happen. It's very difficult to predict exactly what new thing you're gonna find one day or another, but it's going extremely well. We're very pleased with the progress, and somewhere around the end of the month, plus or minus, we should have first gas. Bob, you wanna explain.
Yeah.
Back gassing of the pipeline and.
Yeah, sure.
Looking after the wells.
No, sure. Will do. Thank you. You know, I think everyone's aware, you know, the issue we had middle of last year with ATEX, which were the electrical connections and that work that needed to be done. That's all done for start-up. There's a little bit of follow-up work, but that's but for start-up, it's done. Now we're in the process. When you bring up a new project, it's dead still, but you're making live. We're in that process of making everything live at the moment, so switching things on, making sure that if a sensor over here sees something, that a valve over here closes and there's a lot of communications, connectivity, sort of making the plant live.
We're right the way through that at the moment. A bunch of systems, 20-odd that need to be handed over. We're well over that. We're vastly through all of that, getting towards the final hurdles of that. Once that is finished, ODE, who the appointed duty holder, then take control, and we can start introducing hydrocarbons into the pipeline. At the moment, the pipeline from shore to the platform is full of nitrogen. We need to fill that full of gas. That would be the next step that we do. Once the gas then gets to the platform, the right pressure, we then open everything up and start flowing the other way.
Obviously the important bit is getting up to plateau production, because that's where the money is.
Good. Thanks, Bob. Next questions. Mic's coming.
Thank you. It's Mark Wilson from Jefferies. Two questions, please. First, when is the AGM? Is that in June, like it was last year? Just check on that. Then, Linda, you mentioned the volatile times. We've moved from a world focused on energy transition to a world reminded of energy security and things like this. Do you see any change in the way that IOCs would look at asset M&A or divestitures given what we're seeing?
Yeah. Thanks. One question easier to answer than the other. AGM, I think May 11th, a bit earlier than last year. We're working on, as we move through this year and next year, you know, being able to do a lot of things a little bit more quickly than we were able to do during what was a complicated year last year. That's one of them. Yeah, major oil companies. Yeah, 40 years in the business, a lot of that spent with a major oil company. You know, you think you've seen it all, and then you see what's happened just in the last two years and even last, you know, eight to 12 months. You know, I can't see especially the European majors changing course.
I mean, I can't speak for them, obviously, but I think it'd be very hard for them to change course. We have to keep in mind, just because prices are high now, it doesn't mean that's where they're gonna be in six months. I mean, people sort of get this mentality of connecting the last two dots and thinking that's the trend that we're gonna see, and so much volatility, and where's the global economy going. What happens in Ukraine, you know, I just can't predict it. The majors take a very long-term view on things. They're much better at it usually than normal or other businesses, so I can't imagine they change course.
Are they enjoying the cash flow they're getting today from their upstream assets that they may otherwise be thinking about divesting at some point? Well, of course, they are. You know, absolutely. A lot of them will plow that back into other areas of the business, though, not into exploration or not into major new multi-billion dollar oil and gas developments that may not pay out for 10 or more years, because I don't think their investors were gonna reward them for that. Are they enjoying increased cash flow? Yes. Will they change long-term strategies? My own guess, of course, you know, just my own personal thoughts are probably not. What does that mean for us, I think, is the corollary to that question. Part of our strategy or long-term strategy around growth is continuing to do acquisitions like we've done in the past.
We still think major oil companies will be the most important probably sources of opportunities for us, and we remain optimistic about that. Thanks, Mark.
Hi, it's Sasikanth from Morgan Stanley. Sticking to the theme around energy security, I was just wondering if there's been any talks of increasing your share of gas production in the U.K. portfolio, whether it's possible for Harbour diverting the gas use for reinjection for oil, perhaps, to cater to more gas production.
Coming back to shareholder distributions again. Again, trying to get a handle on the magnitude of increase. You've highlighted a payout of 15% of free cash flow for 2021. I was just wondering if that was indicative of a payout ratio that we should expect, or will the payout ratio increase because of better balance sheet strength? Slightly related to this, you mentioned buybacks as well. I was just wondering if there's been any talks with legacy shareholders on the potential or introducing a buyback as well, whether there's been anything on that front?
Yeah. Thanks, Sasi. I'll let Bob answer a bit about is there a way to increase gas production. I mean, I think you probably know the answer, that on a material level, I don't know of any oil and gas company these days, right, who just sits there outside of OPEC, maybe, you know, who sits there with production that we can just automatically turn on necessarily. For us, there's nothing material. The best thing we can do, of course, which we're hoping to do in the coming days, is have Tolmount come on stream, which will add a significant amount of gas to our portfolio.
I've heard other companies talk about whether or not they should reconsider reinjection of gas into reservoirs and produce more, but that sacrifice, I mean, the trade-off is, right, you're probably sacrificing long-term oil recovery.
Whether or not we have anything material, I don't think so. Bob.
Yeah. Well, on the material side, obviously Tolmount and LAD is the well in the North Everest area, which is primarily gas that's about to come on as well and boost production in that area. On the gas reinjection, Catcher is the area that we're doing that. Every month we look at the gas we're putting in and what the breakeven would be on price to make it worthwhile producing the gas rather than injecting it. At the moment, it's about GBP 5 per therm, but that gas goes in, and it's very effective at recovering more oil. It's not only accelerating oil, it's also recovering additional oil. We do look at that monthly.
At the moment, it's a no-brainer just to carry on injecting that gas on Catcher, so.
Thanks, Bob. I'll let Alexander talk a bit about distributions.
Yeah. Thanks for that, Sasi. Though I am afraid you'll be underwhelmed by my answer. Yes, the math works out in a way that it's 15% if you take that 100% and you divide it appropriately. When we set the initial dividend policy, it was based on a longer-term view.
It was based on what we saw and business plans and what we think is through the cycle, you know, good starting point. You know, we just need more experience and see how, you know, macro environment and how things develop through the year when we're setting, you know, a potential new level. As for specific discussions with legacy shareholders, I think, you know, we've been, you know, pretty active in meeting investors, old and new. The topic of shareholder return and what shape or form, it's typically a topic that people have opinions on. I think we're humble folks that listen to input that shareholders have.
It's not a topic where we're sitting down specifically and discussing buybacks from select investors. We can't do that. It's more a topic that pops up naturally in meeting yourselves and other analysts as well. It's again going to the shareholders and asking to have that possibility to do it in the future.
Yeah. I think a lot of investors will raise it when we mention to them. Some of them hate them, some of them love them, some of them prefer dividends, some like them. I mean, they're all over the page really, and we thought, well, especially given where cash flow is going, let's secure the option t o do it at the AGM and continue to listen to investors as we think through capital allocation as we move through the course of the year, so.
Hi, I'm Werner Riding from Peel Hunt. First of all, another ops question for Bob, if that's all right, in the U.K. Just looking at the J-Area work program, you've got three months of JM sidetrack penciled in there. So I was just wondering what that's targeting. You know, is it something similar to Jade South, which obviously sounds like it's come on ahead of expectations. Is it could it be something similar to that? Or just talk a little bit about that work program.
Yeah. If anything, that well is a higher chance of success than Jade South was. Jade South was appraisal-ish development, so we were really happy when that came on at the rates it did. JM is a tough well to drill. The prognosis is, you know, there's a higher chance of success of the well. That's why it's such a long program because of the difficulty of the well we have to go through. I'll not bore you with drilling, but we have to go through low pressure to get to higher pressure below and that causes certain drilling challenges. Yeah, just looking forward to that.
Okay. All right, thanks. On the Beryl area, you've got platform drilling and subsea drilling.
Yes.
Is that just infill drilling? Is that just more? What? Could you explain what that is?
The platform drilling is infill drilling and the semi drilling is the follow-on Storr well. There are, you know, different prospectivity around the Beryl area so that the semis are doing the prospectivity around the area, whereas the platform wells are doing the infill drilling.
Got it. All right. Thanks. Just a separate question on, you know, the events what we're seeing in Ukraine are obviously shocking and international response in terms of sanctions. You know, on Russia, where does that leave you with your JV with Zarubezhneft? You mentioned self sanctions earlier on, Alex. You know, is that a project that you could walk away from? Or what are the implications for you with that project and that partner?
Yeah. Thanks for the question. We do have a Russian partner in our Tuna project in Indonesia, which is pre-development. I'll let Stuart Wheaton say a few words. We have no direct impact from what's happened so far. We're not like the majors, so we don't have investments in Russia, we don't have investments in Russian companies, so ours is a little bit of a second order, third order sort of situation. Let me let Stuart update you on that. Thanks, Werner.
Yeah. Just to add, at the moment, they're able to pay their bills. They've been paying their bills. They're not sanctioned as yet. There is no product. Statement of the obvious, there is no production, there is no revenue. We're working our way through the plan of development, all of the data from last year's appraisal wells. Absolutely, we're looking at options as to where we go in the future, depending on how things develop. We are talking to the Indonesian government about should the project potentially have a freeze stage in it. At the moment, I'd like to emphasize we're carrying on with moving towards plan of development. Then, yes, ultimately, if they were sanctioned or they were unable to pay their cash calls, then we have various contractual rights under the original farming agreements with respect to their share.
Part of me kind of hopes that we don't get to that place, but we certainly keep our options all open so as that we'll enforce them if we need to. Yeah, it's not helpful for the overall schedule of the project, obviously, but that feels like a small issue compared to the bigger things going on. Yeah.
Okay, thanks.
Thanks, Werner.
Hi there. Dan Slater from Arden. I was just wondering if you could give us a little bit more on the movement in the Tolmount reserves. I know it's on the back of the development drilling, but I was wondering if you could just give a little bit more detail around what exactly it is that you have or haven't encountered in the wells that's moved the reserves in the way that it has. Thanks.
Yeah. Do you want me to?
Yeah, go ahead.
Carry on? Sorry. Okay. The four wells have been drilled on Tolmount. Three were pretty much the prognosis in there, and there was one that basically found the water-gas contact higher.
That's changed the volumetrics across the field. That, you know, as we said in the Capital Markets Day, was the reason for the write-down in reserves is the volumetrics in the field that was discovered with the fourth well.
Yeah. Mark?
Yeah. Thanks. Can I just have one follow-up? Can you, if we dare to dream, remind us about the size of the Timpan?
No, we cannot dream.
Whether it's multiple layers, et cetera. Thank you.
Go for it, Stuart.
Can I?
Yes. Remember, it's an exploration well. I just wanna be clear. Thank you. Go back to my phrase about counting chickens before they hatch applies here too, but go ahead, Stuart.
Okay. Well, you've got to have some enthusiasm in life and optimism for sure. Okay. Just to give you a bit of color about Timpan and Andaman Sea. Where are we at? All things being equal, the drill ship is in the shipyard at the moment for its planned refurbishment and recertification exercises in Malaysia. It should be out at the end of April, and sometime in May, we would plan to spud. Okay? About a 60-day well to the reservoir, including coring. All things being equal, then we can stick to plan around the end of Q2. In the success case, there's a drill string test as well. All right? Okay. It's a 1.4, 1.5 TCF P50 type structure by itself.
I think in previous presentations, we've given a few seismic lines and other excitement as well to sort of tempt people. The story of the area, very exciting. 1,300 meters of water, all doable. Up on the coast there, you have the original Arun LNG plant and the onshore field that was produced 13 TCF over the years, now virtually depleted and the LNG plant closed down, but all the infrastructure is there. Yeah, dreaming. The success case leads to quite a lot of follow-on prospectivity in the area. Our partners with Mubadala, with BP and ourselves, we've got a mingling of various equities, et cetera, in the area. I'll be brave enough to say if you have one success, then there's multiple prospects that lead to the very big numbers, Mark. Yeah. Who knows?
I think the main risks really are all about reservoir deliverability and gas composition. Okay? What quality reservoir section will we drill into? We clearly don't know that until we're down there. There are a few legacy wells in the area from the past over in the Thailand side in the play, and they give you enough encouragement to go and give this a go. We've looked at commercialization opportunities that would be there in the success case for early gas to tie ourselves into shore and make use of the infrastructure. The final thing I would say is the real clincher is there's some really beautiful connections to CCS that you can do carbon capture and storage into the depleted fields as well.
If you think about future oil and gas projects that people would want to finance, gas obviously helps, but there's some really very sort of mutually beneficial, sort of almost net zero type development schemes there. I think that's clearly important for us to wanna do projects like this in the future. We've very much got our eye on that as well.
It's all of that is why it's the one sort of greenfield exploration well we've decided to continue to pursue this year out of the portfolio, just because of everything Stuart mentioned about it.
Yeah.
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Oh, we are.
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Yeah.
Yeah. We're 40% on this well. Mubadala operate the block to the south of us as well, which we're 20% non-operated in. Yeah.
Okay. I think we're about out of time, unless there's any last pressing question. I don't see any hands up. Thank you again, really, for joining us in person. For those of you who are listening, thanks for dialing in. As I said, we're off to a good start this year and looking forward to what the rest of the year might bring. Thank you.