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Intrinsic Value is all-important and is the only logical way to evaluate the relative attractiveness of investments and businesses.
Intrinsic Value is all-important and is the only logical way to evaluate the relative attractiveness of investments and businesses.
Good morning. Thanks to everyone joining us for a discussion of our 2022 results. I'm here today with Alexander Krane, our CEO -- CFO, last I checked. Sorry. And on the next page, we have our disclaimer, and then we have the agenda on Page 2. And I'm going to start with just covering the agenda here.
So I will cover a bit on operational performance, including production, costs and reserves. I'll have a bit about some of our promising international growth opportunities and energy transition activities, and then I'll turn it over to Alexander to discuss the financials. But first, just a bit of a reminder of our strategy on this next page.
The strategy has remained unchanged since the merger with Premier in 2021 and even before that, going back to the start of Harbour Energy as a private company. We aim to continue building a global, diverse independent oil and gas company, mainly through M&A, with a focus on creating value, generating cash flow and a disciplined approach to capital allocation.
I think our actions have been consistent with that as a result of 3 multibillion-dollar acquisitions. We're the largest oil and gas producer in the U.K. The last of these transactions was agreed during a global pandemic, which saw Brent oil prices in the 30s. And since then, through our prudent approach to capital allocation, we significantly delevered, and we've announced a total of $1 billion in shareholder returns in the last 15 months.
We also navigated very challenging geopolitical and economic conditions in 2022 that included high and extremely volatile commodity prices as well as the imposition of not 1 but 2 U.K. windfall profits taxes, which, given the fiscal uncertainty they create, triggered a review of our U.K. investment and staff levels.
While our strategy remains unchanged to diversify and grow mainly through M&A, given what happened to commodity prices last year, 2022 was clearly not an easy year to buy low. Instead, we evolved the existing portfolio by focused investment in high-return U.K. drilling while selectively allocating funds to material, promising international opportunities in both Indonesia and Mexico and our Viking CCS project.
As a result, we made progress diversifying organically while continuing to explore opportunities for meaningful but disciplined M&A. And as we've demonstrated over the past year, if we don't see acquisitions that are right for the company and our investors, we'll continue to return excess cash to our shareholders.
Right. Turning now to 2022 highlights. I think the gear was characterized by 3 big themes: strong operational performance, which enabled robust financial results and, around all of this, disciplined capital allocation. We delivered production at the high end of guidance at 208,000 barrels per day, up 19% versus 2021. And we did so safely, with material improvement across most HSE metrics year-on-year.
Operating costs were also lower, and we had generally good execution of our drilling program. While we didn't replace reserves for the year, we did take FID on Talbot in the U.K., matured our material international growth projects and made a significant discovery in Indonesia, opening up a major new gas play in the region.
We also made progress with our net zero strategy, including the setting of an interim target, and we built a lot of momentum in our flagship Viking CCS project. However, the EPL had a big impact, all but wiping out our profit after tax, largely due to a significant one-off noncash deferred tax charge.
If we look beyond that, we delivered a strong set of financials. $4 billion in EBITDAX and $2.1 billion in free cash flow. All in all, I'm proud of what the team delivered, and I thank everyone for their efforts.
Next, I'll talk about some of these highlights in more detail, starting with safety. Here, you see the improvements made year-on-year in 2 important metrics: injury rate and process safety events. We had no significant injuries or environmental incidents during the year. This, together with the results of our first employee engagement survey, which highlighted the strength of our safety culture, indicates we're heading in the right direction after bringing together assets and people from 3 different companies over the past few years. But of course, no room for complacency.
Next, production. As I mentioned earlier, up 19% year-on-year, as we can see in the chart on the left, driven by new wells on stream, including at Tolmount; improved production efficiency; and a full year's contribution from the Premier assets. This graph also illustrates the diversity of our asset base, with material contributions from 10 different producing hubs, most of which we operate.
We also have a balance of oil and gas, around 50-50 in 2022. While we were heavily hedged during this past winter, we'll enter the next with more exposure to U.K. and European natural gas markets and better positioned to benefit should we see another period of higher prices.
On this next page, we see that one of the main drivers of the production increase was our drilling and well intervention program, totaling 65 wells and primarily targeting natural gas. As a result, as the chart on the left shows, our natural gas production was up almost 35% year-on-year. New gas wells include our successful Jade South well in the J-Area, the start-up of Tolmount and the LAD well at our AELE Hub. Given the low-risk, near-field nature of these opportunities, payback is quick, on average, less than 1 year for the new wells brought on stream during 2022.
It wasn't just new wells that supported production during the year. As you can see on the left side of this page, we also had less operational downtime, both planned and unplanned compared to 2021. In fact, operating efficiency accounting for unplanned downtime only was greater than 90% at 3 of our largest hubs, a top quartile performance in the U.K.
Of course, higher production helps unit operating costs, as you can see on the right. Unit OpEx dropped by 9% year-on-year to $13.90 per barrel, well below the U.K. average of $16.50. This was driven by increased volumes and helped by a weaker pound sterling. As we face some of the same inflationary pressures as others, that's a great result from our team.
Managing our cost structure is, of course, an ongoing effort, made even more important given the additional tax burden we now face in the U.K., and a number of ongoing initiatives will help us as we go forward. Having brought together 3 companies, we're still rationalizing and consolidating supplier contracts as they come due for renegotiation. Examples recently concluded were in aviation and onshore supply basis. And that has already borne some fruit, but there's more to come.
Second, our new SAP-based EMS system just went live in November of last year. Now that it's up and running, we have a long list of actions that will leverage this system to help us reduce complexity, reduce the number of processes and automate.
And as I've already mentioned, the reduction of U.K. activity levels resulting from the EPL and the fiscal uncertainty this has created has triggered a review of our U.K. organization. Well, this was a difficult decision, and it's still too early to give precise figures. We would expect to realize annual savings, once fully implemented, on the order of around $40 million per year.
This takes us to a summary of reserves and resources. Again, 3 key messages. 2P reserves were reduced by the amount of our annual production. While we were able to move some volumes from 2C to 2P, those and other positive revisions were essentially offset by the previously flagged downward revision at Tolmount. We have been very successful over the past few years, adding reserves to the assets acquired from Shell and Conoco.
Today, we still have almost 600 million barrels of 2P plus 2C volumes in our U.K. portfolio, equivalent to more than 8 years of production. And this is after a thorough technical review of our resource base over the course of 2022. The objective of that review was to scrub the portfolio to ensure we were focused on the opportunities with the best returns and risk profiles, especially in light of the new fiscal regime and related ongoing uncertainty.
This led to the relinquishment of a number of U.K. licenses, where the opportunities no longer met our internal investment criteria or were inconsistent with our emissions reductions goals. One example was our interest in the Bressay heavy oil discovery, which we determined was unlikely to move forward given its high cost and emissions profile.
The second theme is the growth in our international resource base following the Timpan discovery in Indonesia, which added around 80 million barrels to our 2C resources. These volumes represent our share of discovered resources in the Timpan prospect alone and are equivalent to more than 1 year of current produced volumes.
The Timpan volumes added to those associated with the Tuna field and what we have in Mexico at Zama contribute more than 50% of our total 2C resources today, underpinning the potential future reserve replacement and diversification of the company over time.
Finally, you see in the lower right, a new category of reserves and resources disclosure for us. We have officially booked, if you will, 300 million tonnes of CO2 storage capacity in the Viking fields, where we have 100% in the licenses and are the operator of the Viking CCS project. Similar to our oil and gas numbers, the CO2 storage volumes were reviewed and certified by an independent party, who has found our estimate to be fair and reasonable.
Now looking at production. We set production guidance for the year at 185,000 to 200,000 barrels per day. This reflects natural decline of around 15%, similar to the year before and similar levels of planned maintenance. This decline includes the impact of our active program of well interventions and then is further offset through production from new infill wells and near-field tiebacks.
Through the first 2 months of the year, we produced at an average rate of around 202,000 barrels per day. While this is above the top end of our guidance for the year, we were expecting that to be the case for those months given low levels of planned maintenance, in particular, during the winter in the U.K.
Looking ahead, here, we have some examples of opportunities still embedded in our U.K. portfolio that have the potential to at least partially offset decline. First, we have the 2C resource base I already referred to amounting to over 200 million barrels of oil equivalent, shown in the upper right. These volumes largely represent small near-field discoveries that require further technical work to establish the commercial viability and mature them to the drill-ready stage. Oftentimes, they require collaboration with other partners.
This was the case with the Leverett discovery close to our Britannia infrastructure, where we teamed up with NEO to align interests over several licenses that covered that field. This allowed us to jointly work towards approval of the appraisal well, which will be drilled later this year.
Next, we have the opportunity for infrastructure-led exploration. While we chose not to participate in the recent U.K. licensing round, we do have an existing inventory of 15 material prospects close to our existing hubs. Some of these in the success case can be immediately tied into production as we did with Jade South last year. Another example is the Jocelyn South well, which will spud at the back end of this year and, if successful, can be immediately brought on stream through our J-Area infrastructure.
And finally, on the left side, you see some potential that is not yet captured in either our 2P or 2C volumes. The potential to improve ultimate recovery through further technical work or application of new technology. The largest example is at J-Area, where our current booked 2P volumes reflect an ultimate recovery of around 35%. Benchmarks and analogs tell us that a higher recovery could be achievable. Just increasing our recovery factor by 10% could result in the addition of hundreds of millions of barrels.
So you'll not be surprised to hear that our teams are being challenged to address these gaps and ensure we're getting the most we economically can out of our existing resources.
Now turning to international, where we have a growing number of attractive opportunities, starting with Zama in Mexico discovered in 2017. Working with partners, including Pemex, the national oil company, we are now close to agreeing a field development plan and other commercial agreements that, once submitted and approved, will allow us to move into the feed, the last phase before a final investment decision. Upon FID, which could be possible in 2024, we would see about 80 million barrels of 2C move into 2P, replacing over a year's worth of our production today.
Also in Mexico, we have two exploration commitment wells on Block 30 operated by WintershallDea to the southwest of Zama. The drilling of the first of these, the amplitude-supported Kan prospect is nearing completion, but I'm afraid it's too early to provide any insight into the results. Once drilling activities there are complete, the rig will move to drill the second prospect on the block called Ix.
Moving to Indonesia. You may recall, we successfully appraised our Tuna field with 2 wells in 2021. Since then, the team optimized the development concept and submitted the initial plan of development to the regulator, which has now been approved, a key milestone. However, further progress has been impacted by EU, U.K. sanctions, which limit our ability as operator to provide certain engineering services to our partner, Zarubezhneft, a small Russian company, even though they themselves are not sanctioned.
We're in active discussions with both the partner and the Indonesian government regarding options to move the project forward.
On to Norway, while we don't yet have production in the company, we have built a portfolio of exploration acreage, most of it with local partners. Currently, 2 wells are set for drilling towards the end of this year: the Equinor-operated JDE Triassic prospect, with a harbor interest of 40%; and the Vår-operated Ringhorne North prospect, with a harbor interest of 15%.
And that brings me to the Andaman Sea in Indonesia and the next page. The Timpan-1 well discovered a material gas accumulation in the heart of a region with strong natural gas demand. The well's success derisks multiple other analogous prospects across our Andaman licenses.
Following this discovery, we, along with partners, BP and Mubadala, commissioned the acquisition of additional seismic data covering the eastern portion of the Andaman II license and have committed to drill at least 3 additional exploration wells beginning later this year. These 3 wells will each test separate prospects across our Andaman I and Andaman South licenses.
Our share of the cost for this drilling is around $90 million, including testing and data acquisition. The combination of the seismic and the drilling will give us a much better understanding of the full extent of the potential underlying these licenses. So while there's still work -- some work to do given the scale of the potential resource and the proximity to natural gas demand growth centers in the region, I think you can see why we're excited about the play.
All of these activities feed into the 2022 rig schedule, which also reflects the recent cancellation of wells by both Apache and Total as a result of the U.K. EPL. Regarding the development wells on the schedule, they break even at less than $35 per barrel and pay back very quickly. Regarding the exploration wells, they have the potential to help offset U.K. decline to deliver our first discovery in Norway or to support a second development in Mexico, in addition, of course, to the Andaman Sea drilling.
As I think is evident, while most of this year's spending is still in the U.K., our U.K. projects will increasingly have to compete for capital with those in other countries where we are active. Those international opportunities I just discussed support the organic diversification of the business going forward, complementing our M&A strategy, which remains unchanged.
If we go left to right on this page, the external conditions for M&A are much improved versus last year, a year in which very few oil and gas transactions were agreed. This won't be surprising as price expectations of buyers and sellers were difficult to match given the elevated and volatile commodity price environment and the fact that it was simply not possible for buyers like ourselves to hedge material amounts of production at those levels. So while we consider numerous opportunities over the past year, for us, 2022 was about staying disciplined, paying down our debt following the Premier merger and focusing on our existing portfolio.
Today, the conditions for M&A are much better. Oil prices have stabilized within a fairly narrow and lower band. European gas prices have come off their peak, and the outlook is more stable. Our criteria for M&A remain unchanged: accretive to reserves life; cash flow; credit metrics; and supportive of our net zero goals, with a focus outside the U.K. And the objective remains to diversify and continue building a portfolio that can sustain and grow shareholder distributions over time.
Even with growth, we aim to achieve our ambition of net zero by 2035 and our new interim target of a 50% reduction in our absolute emissions by 2030 versus a 2018 baseline. How will we do this? We'll implement emissions reductions projects, almost all of which are economic; responsibly decommission fields as they reach their end of life; and purchase high-quality credits to offset any residual emissions.
While progress was made during 2022 from an emissions intensity standpoint, through the implementation of various emissions reduction projects, it was offset by the addition of the more energy-intensive Premier Oil portfolio. However, from an absolute emissions standpoint, we've reduced emissions already 20% versus our 2018 baseline.
Regarding spending in this area, expenditures and what we refer to as our energy transition category were just shy of $300 million. The biggest part of this is the money we spent to decommission oil and gas infrastructure that has reached the end of its useful life. Smaller categories include spending to acquire offsets, investment in our emissions reduction projects and also on our CCS activities.
We'll talk about CCS in a minute. But first, a few words about decommissioning. Responsibly and cost effectively decommissioning idle oil and gas infrastructure is something we're proud of. This is a key activity as the world moves through the energy transition, and we're one of the leaders in the area.
Over the past 8 years, Harbour has P&A-ed almost 150 idle wells, most of which we acquired as part of our Shell and Conoco transactions, and we've been able to lower the cost per well to do this over time. On top of that, we've removed and recycled 31 platforms with a total weight of 73,000 tonnes. And some of the idle infrastructure we acquired from Conoco now forms a key part of our Viking CCS project.
We're increasingly excited about the potential for this project to make a real difference, including in the U.K. government's ability to meet its emission reduction targets; for the future employment and investment prospects for the heavily industrialized Humber region in England; and for our employees, investors, lenders and other stakeholders.
Our ability to reuse an existing offshore pipeline capable of transporting 30 million tonnes per annum of CO2 helps to lower the cost of CCS. Our knowledge of the depleted offshore Viking fields, which were operated by one of our predecessor companies, helps underpin the confidence level in our offshore storage fields. And the strength of our onshore emitter collaborators, including Vitol, RWE, Phillips 66 and West Burton, who have all expressed a commitment to capture their CO2 and transport it to storage through our Viking system, demonstrate the credibility of our project. And our arrangement with associated British ports at the Port of Immingham gives us access to transport and store CO2 emissions shipped from elsewhere in the U.K. or imported from Europe.
Tremendous progress was made during 2022, including with the permitting process for the onshore pipeline, which will connect the emitters to the inlet of the offshore pipeline as well as with early commercial agreements with the emitters -- industrial emitters named earlier. We are also, we believe, only the third CCS project in the world, joining 2 in Australia that have received independent verification of our CO2 storage potential, which stands at 300 million tonnes.
So what happens next? We need to understand the path to regulatory approval that we are hoping will come from the U.K. government's delayed Track 2 process. If that launches in the coming weeks, it could keep us on track to proceed into the feed stage in the coming months and take FID some time next year, with first CO2 injection as early as 2027. But I repeat, this relies on tangible progress from the government with the regulatory framework.
The Harbour-led Viking project, along with our interest in the Acorn Project in Scotland, makes us one of the potential leaders in U.K. CCS. With government action, we can, with Viking alone, deliver 1/3 of the U.K.'s CO2 capture and storage target by the year 2030.
Okay. Now I will turn it over to Alexander to give a summary and some details on the financials.
Great. Thanks, Linda. And again, good morning to everyone joining. For my financial review today, I have 7 slides to go through, where I will start with a few financial highlights. Next, I'll talk about our hedge book before turning to the income statement and balance sheet. I will then run through our cash flow generation and net debt reduction for 2022 before concluding with some remarks around the 2023 cash flow generation and guidance.
Now as Linda explained, we had operationally a strong year in 2022. We're on Slide 19 now. This is reflected in our 2022 full year financial statements. In particular, our free cash flow was significantly higher as a result of higher production and commodity prices, although our hedging strategy offset some of these gains. The strong cash flow generation enabled us to continue to rapidly deleverage, reducing our net debt by $1.5 billion over the course of the year.
We also continue to invest in our existing portfolio, and we delivered over $0.5 billion in shareholder distributions. All of this is in line with our expressed capital allocation policy. However, we cannot ignore the fact that the energy profits levy or EPL introduced here in the U.K. last year has all but wiped out our profits. We've long argued that the EPL disproportionately impacts independent oil and gas companies like Harbour, and this is only too clear in today's results. The EPL has caused us to reduce investments in the U.K., undertake a review of our U.K. organization and reinforce our strategic ambitions to diversify internationally.
We entered 2023 well placed to deliver on our strategy, supported by a robust balance sheet, prudent risk management and disciplined capital allocation. We will continue to return excess capital to shareholders while safeguarding our balance sheet, investing wisely in our existing portfolio and maintaining capacity for M&A.
As a result of our strong financial position and robust cash flow generation, we have today proposed a final $100 million dividend for 2022, which, given our buybacks over the last year, represents a DPS growth of 9% year-on-year. We've also announced a new $200 million share buyback, which brings total announced shareholder returns to $1 billion since December 2021.
Moving next to Slide 20. In 2022, our realized oil and gas prices and, consequently, our revenues were severely impacted by the historical hedges we put in place to comply with the minimum requirements in our main bank facility at the time. With 63% of our U.K. gas production hedged in 2022 at an average price of 53p per therm, our realized post-hedge price for our U.K. gas sales was 86p per therm, 57% below NBP.
Our pre-hedging realized gas prices were 183p per therm, reflecting the impact of some legacy long-term fixed price gas sales agreements and national grid entry fees. Our 2022 realized post-hedge oil price was 23% below market prices at $78 per barrel, reflecting the fact that 52% of our oil in 2022 was hedged at $61 per barrel. On a pre-hedge basis, we realized $99 per barrel, broadly in line with Brent prices.
With our leverage falling, we have been able to reduce our minimum hedging requirements, providing us with greater flexibility around our hedging strategy. As a result, we were able to be more opportunistic in our approach to hedging, putting in place incremental, very attractive several cost colors on the gas side when available.
On oil, we placed incremental hedges at $100, $84 and $81 per barrel, respectively, for '23, '24 and for '25. We will continue to seek to put in place some longer data hedging, locking in material free cash flow and retaining exposure to upside where pricing is attractive.
For 2023, 2024 and 2025, the percentage of our estimated future global gas production that is currently hedged is approximately 65%, 35% and 10%, respectively. This compares to 70% now in 2022. Our estimated future liquids production that is currently hedged decreases to approximately 30%, 20% and 10%, respectively, compared to the 50% we saw in 2022.
At year-end, our hedging liability stood at around $3.5 billion, rolling off on a monthly basis until March 2025. However, as you can imagine, with the forward price curve shifting down in recent weeks, particularly for U.K. and BP gas, our hedging mark-to-market position will have decreased materially after year-end.
So turning now to our detailed financials, and we will first have a look at our income statement. Now before we get into the details on this slide, you should note that 2022 is the first year with full contribution from the whole portfolio since the merger with Premier completed in March 2021.
The 2021 income statement reflected 12 months of Chrysaor activity and 9 months of Premier activity. The key takeaway from this slide is a significant increased EBITDAX and profit on a pretax basis, supported by higher production and strong realized prices despite significant realized hedging losses of around $3.2 billion recognized here within revenue. However, this profit before tax is all but offset by a material one-off noncash deferred tax charge due to the introduction of the EPL.
Turning to the details. Total post-hedge revenue increased by 50% to $5.4 billion, driven by the increase in production, especially U.K. gas production, which was 34% higher and higher post-hedging realized prices, especially for U.K. gas. As a result, our gas revenue increased by 85% to $2.3 billion and accounted for more than 40% of our total revenue.
Operating costs were broadly stable at $1.1 billion, with a slight increase reflecting the additional 3 months of operating costs from the Premier portfolio and the additions of Tolmount, which came on stream in April. On a unit of production basis and as mentioned by Linda, OpEx was down 9%, driven in equal parts by increased volumes and weaker pound sterling, with more than 90% of Harbour's operating costs being pound sterling-denominated.
The higher revenue, together with stable operating costs, contributed to a significantly higher EBITDAX this year of $4 billion versus $2.4 billion last year. DD&A expense amounted to $1.5 billion, which is $20.40 per BOE on a unit basis, which is pretty much in line with last year.
Now please bear with me as I try to explain the key one-off items impacting this income statement for 2022. First, there's impairments and reversal of impairments. We recognized a net pretax impairment reversal of $170 million. We recognized impairment reversals of $251 million, principally relating to our U.K. gas assets, and they're driven by higher natural gas price assumptions.
We also recognized an impairment credit of $82 million, which is associated with a reduction in our decommissioning estimates on our nonproducing assets as a result of higher risk-free rate being applied. I'll get back to the topic of decom estimates in a couple of minutes. So bear with me here.
These reversals were partially offset by an impairment of $163 million, recognized on one of our North Sea producing fields. This impairment was driven by a revised operating cost profile and the contracted price we realized for our crude sales being impacted by a material negative pricing differential.
Secondly, exploration and evaluation expenses. We expect $106 million for exploration and appraisal activities in 2022. Of this, $64 million related to exploration write-off following a technical evaluation and high grading of our U.K. portfolio, which Linda referred to. And so our U.K. 2C resource base reduced to 204 million barrels of oil equivalents. For our remaining 42 million barrels, 22 million is associated with our U.K. CCS projects, mainly Viking, where we currently expense our spending associated with the project as incurred as we await clarity from the government on commercial framework and business model.
G&A amounted to $120 million, which includes certain one-off expenses like our new SAP-based enterprise management system, again mentioned by Linda. 2022 saw us continue to work hard to integrate our business as culminating in the EMS go live a couple of months before the end of the year. We expect this G&A number to reduce going forward following our U.K. organization review to align with our reduced activity levels here.
Net financing expense amounted to $79 million, significantly reduced compared to 2021 due to increased finance income of $279 million. This largely reflects foreign exchange gains as a result of the weakening of the pound sterling against the U.S. dollar, arising predominantly on the revaluation of some open pound sterling-denominated U.K. gas hedges.
Financial expenses amounted to $358 million and are broadly flat year-on-year. Profit before tax was $2.5 billion, but this profit is wiped out by the $2.5 billion tax expense for the year. The $2.5 billion tax charge is made up of $0.8 billion of regular current and deferred tax charges, plus an additional $1.7 billion charge because of the energy profits levy. Of that $1.7 billion EPL tax charge, $0.3 billion reflects our current EPL. In other words, our 2022 EPL liability and the balance is a deferred EPL tax charge incorporating a one-off revaluation from 40% to 75% of the deferred tax position on our PP&E values.
The blended headline tax rate for the period is 55%, reflecting 40% until the EPL was introduced in May and 65% thereafter. However, the one-off accounting impact of the EPL increased this rate by 60%, which when combined with other smaller factors, resulted in an effective tax rate for the period of 100%. Our current tax liability for the period was $0.7 billion, split around $650 million for the U.K. and $50 million internationally.
So moving to Slide 22 and our balance sheet. Now I will, for one, start with equity since there are some one-offs effects flowing through here as well. Despite a very modest $8 million profit for the year and shareholder distributions of $553 million, book equity increased from $0.5 billion to $1 billion. The main reason for this is a $1.1 billion deferred tax revaluation arising on our unrealized hedge losses, which sits in other comprehensive income, again as a result of the EPL. The deferred tax asset on these balances is increased to reflect the higher tax rate relief that we will receive on these losses when they realize. This tax credit is booked in equity alongside the hedges. While our net derivative liabilities are stable on a pretax basis at $3.5 billion, on a posttax basis, cash flow hedges were $0.8 billion at year-end, reduced from $2.1 billion at the end of 2021.
The majority of these hedges will mature in 2023 and 2024. On the liability side, total liabilities reduced to $11.6 billion from $14 billion. Our borrowings reduced significantly to $1.2 billion, consisting of our $700 million drawings under the RBL and our $500 million unsecured bond, which matures into 2026. Provisions for decommissioning liabilities of $4.2 billion decreased in the period by around $1.2 billion. There are lots of assumptions going into the estimate of future decom liabilities. One of the inputs here is risk-free rates. As risk-free rates have increased in 2022, this means that the discount rate applied is higher when estimating future liabilities. This has caused a $0.8 billion decrease in this balance.
The $0.8 billion reduction here is also reflected in the other side of the balance sheet, reducing our PP&E balance.
Now again, as a reminder, this will unwind over the next few decades. Following the introduction of the EPL, we've sought to optimize our decom spend and now expect to spend between $200 million and $250 million on decommissioning per annum in the near term compared to previous estimates of $300 million. Other liabilities of $1.5 billion mainly consists of trade and other payables.
Now turning to assets to cover off those movements we haven't already spoken about. We saw a decrease of around $700 million within the net deferred tax assets. Half of this reduction is because of the revaluation of the deferred tax position to reflect the EPL, the one-off income statement charge you saw in the previous slide, net of the aforementioned credits to OCI from the derivative. So $1.5 billion less $1.1 billion. The other half is because of ongoing utilization of tax losses and changes in our balance sheet ARO and PPE positions. I have already mentioned the $0.8 billion effect on PPE from lowered decom estimates. This balance is reduced by another $0.8 billion since depreciations and impairments were higher than capital investments in the period. Other assets of $2 billion consists mainly of receivables, some small inventory and financial assets. Cash balances have been reduced to $500 million, still a significant amount in order to pay hedging settlements at the start of each month.
Now let's move to Slide 23 to have a look at cash flow generation this year. Net debt has been materially reduced from $2.3 billion at the end of 2021 to $0.8 billion at the end of 2022. These amounts exclude amortized fees. We still have our $500 million bond outstanding, which means that the debt reduction this year has reduced the drawn amounts on the RBL. This $1.5 billion repayment of the RBL stems from free cash flow generation of $2.1 billion, net of dividend payments of $0.2 billion and share buybacks of $0.4 billion.
We had gross operating cash flow of almost $4 billion, while we invested $850 million in our asset base, including decom. We spent another $450 million on financing and lease costs. Then we coincidentally had almost identical shareholder distributions and tax payments in the year around $550 million on each. $514 million of taxes were paid in the U.K. and $37 million overseas.
Of our U.K. tax payments, $205 million related to the EPL. So summing up, this gives us free cash flow of $2.1 billion for the year. Liquidity at the end of 2022 amounted to $2.5 billion, from our current RBL and available cash balances.
So moving to Slide 24. Since completing the merger and starting as Harbour Energy on April 1, 2021, we've generated material free cash flow, which has enabled us to reduce net debt by $2.1 billion since then and continues our track record of rapidly paying down debt post large-scale M&A. It is in periods of high prices like we saw last year that we believe is the time to be disciplined and to continue to drive down debt and strengthen our financial position in order to be in a position to act on opportunities when these arise.
In terms of free cash flow generation in 2023, we are forecasting this to be around $1 billion based on $85 per barrel and 150p per therm. We've also provided some price sensitivities to use for analytical purposes. Now importantly, there is a timing effect to consider as it relates to actual cash payments of our 2023 EPL liability. The majority of our 2023 EPL liability does not fall due until 2024, and the positive effect of this delayed tax payment has on our 2020 cash flows is included in the $1 billion forecasted free cash flow.
We're in a strong financial position today. Our BB credit rating has been reaffirmed by Fitch and S&P. We have very low leverage, no near-term debt maturities and a relatively low cost of debt. In addition, we have significant liquidity of $2.5 billion and a supportive bank syndicate.
In 2022, we initiated a dividend policy of $200 million per year. In a volatile year with high commodity prices, we were able to complement this dividend with announced buybacks of $400 million. And today, we are also announcing that the $200 million annual dividend will be complemented with a $200 million buyback program. This brings total announced distributions up to $1 billion from December 2021 to to-date. We're keeping the dividend flat at $200 million in 2022, in line with our annual dividend policy. However, the previous $400 million buyback has resulted in 78.4 million shares being acquired and subsequently canceled, which means that our shareholders will see an increase in dividends per share of around 9% year-on-year. We will continue to return excess capital to shareholders while ensuring we have a robust balance sheet, we can invest in our portfolio and, at the same time, maintain capacity for meaningful but disciplined M&A.
So finally, on Slide 25 and before I turn it back to Linda, just a quick recap on 2022 performance versus guidance and a reminder of our 2023 guidance. We ended 2022 at an average production of 208,000 barrels of oil equivalent per day, towards the top end of our initial production guidance. Operating costs ended a little lower than guided at the outset of $13.9 per BOE while CapEx came in at $0.9 billion versus the $1.3 billion in original estimates.
For 2023, we set our guidance at the beginning of the year, and today, we are not making any changes. That means that our production is still expected to be within 185,000 to 200,000 barrels of oil equivalent per day range and operating costs should come in around $16 per BOE. We're forecasting total CapEx of $1.1 billion, where decom spend is a little lower than last year at around $200 million while P&D and exploration and appraisal spending collectively is around $900 million. A significant part of the $900 million investment will still go towards U.K. opportunities. But a larger part, around 15% of the spend, will go towards the international growth opportunities that Linda went through a few minutes ago.
So with that, I will hand it back to Linda for some closing remarks.
Thanks, Alexander. We've taken a good bit of time. But before opening up for Q&A, let me just try to wrap up quickly. 2022 was a good year for us operationally and financially if we look beyond the one-off charge. The EPL did, however, deal a material blow, including to our share price. In response, we have focused our investment levels and continue to take action to improve our cost structure.
We have organic investment opportunities, both U.K. and international. We focused on strengthening the balance sheet and on returns to our shareholders. And now we have a track record, I think, and company and portfolio that positions us well for potential M&A. But as we have demonstrated, we will remain disciplined as we did during last year and return additional cash to shareholders should we have it in the meantime.
And now over to Q&A.
[Operator Instructions] The first question today comes from the line of James Hosie from Barclays.
I guess I was just wondering if you could perhaps clarify your comments on shareholder returns and the buyback. Is it correct to think, first off, that the $200 million buyback could be increased if current commodity prices persist through 2023? And then how do you define what excess cash flow is in 2023? Is it linked to cash flows with oil and gas prices or above a particular level or just some sort of minimum level of debt repayment that you're targeting this year?
Yes. Thanks, James, for the question. I think we are really trying here to balance the various capital allocation principles that we have. And we went through them in some detail as it relates to paying down debt and having that balance sheet being quite selective, I would say, in terms of what we're investing in organically and not to mention M&A, which I'm sure there will be some questions around, and then, of course, trying to strike that good balance of keeping a predictable dividend level and complementing with the buyback.
So we do think today that having a $200 million plus -- an additional $200 million, it seems like a good level in terms of where we see net debt has been coming down, and we can still have the potential here to be net debt-free but now going into 2024. And that is just based on where we see the portfolio, where we feel comfortable in terms of production, in terms of hedging levels and the predictability that the portfolio gives us.
Now whether this can be increased later in the year, I think that, James, is something we'll come back to when it's in the second half of the year and, again, assess commodity prices, assess cash flows but also where we are in terms of possible inorganic opportunities in addition to those organic ones.
Okay. I mean I guess is getting net debt to 0, is that a target? Or is that just an outcome based on how you see the cash flow is progressing this year?
Yes. No, I think we've never set a target, or we don't have a -- I certainly don't have a KPI on my scorecard on getting to a net debt 0. I think this very much follows just in what we've been saying now for a good part of these 18 months that when prices have been a bit volatile and high, that is the good opportune time to be paying down debt. And having that availability and having that firepower, hopefully, will show to be a sensible good thing when good inorganic opportunities arise.
I think we said earlier on that it was rather staying below 1.5x through the cycle leverage target. So now when there hasn't been M&A taking place, it is good to be on the low side of this. But we didn't start out by saying, yes, we need to get to net cash instead of being in a net debt position.
The next question today comes from the line of Mark Wilson from Jefferies.
Linda, you mentioned on the call that you don't yet have production in Norway, but you are drilling wells in Norway. Now I read that as being Norway production could be one of the areas you could be looking at in terms of international M&A, and you have spoken to that as an area or a country of interest before. Could you, therefore, outline the positives and negatives that goes into how you would see areas you've mentioned for such as Norway, Gulf of Mexico and Southeast Asia as regards looking at potential M&A opportunities and how -- and what they would add to Harbour?
Yes. Thanks, Mark. It really gets to this question we do get around criteria for M&A. And we think about it and have a number of criteria and filters that we run opportunities through to come up with a priority list. And these include, not necessarily in any particular order, I would say, reserves life. We are aware of our 2P reserves life being a bit lower than where we'd like it to be. I outlined, I think, a number of opportunities in the presentation today where we feel like there's scope to improve on that, both in the U.K. and outside, but we would like to add some reserves that are a bit less mature than on average than what we have today.
We look at margins, both from an operating cost standpoint and also after-tax margins. We want to make sure what we buy will be -- help us in periods of low commodity prices to make sure we remain robust. We look at emissions per barrel. We want to make sure that we understand the impact and the acquisition will have on our net zero ambition and the costs associated with that. I think those are some of the main things. Of course, we also -- since we're not planning to grow the company relying on greenfield exploration, we're mainly looking in regions where there's established oil and gas production and infrastructure and a supply base and relatively low risk then opportunities to add reserves and create value from assets that we might acquire. So that leads you to -- and that's what we have in the portfolio today, conventional offshore producing assets in established basins in both Southeast Asia and in the U.K. So if you start thinking about what areas meet those criteria, clearly, both Norway and the U.S. Gulf of Mexico tick a lot of those boxes. So I don't -- I wouldn't disown the idea that those areas would be on our list. Does that makes sense, Mark?
Okay. Can I just...
I would say just to add, I think fiscal stability, maybe could I add that. People say, "Well, Norway's tax rate is higher." Yes. But the thing is about Norway is it's stable, and you can rely on it for years to come. So I think what we've had here in the U.K., it's not just the fact that we now have had this windfall profit tax. It's the fact that there's a lot of uncertainty associated with that going forward. It says it's going to last until 2028. No one's certain. That's really the case.
Does the tax rate stay but the investment allowance go away? What happens when -- if Labour comes into power here in the U.K.? And so given all that uncertainty, it's just hard to think about new exploration licenses, major new developments and spending a lot of money pre-FID on those over the coming 2 or 3 years when you don't know what the future is going to bring fiscally in the country.
Very clear. And then my second question, though, and follows on from a lot of what you just said there regarding uncertainty on U.K. fiscal. But at the same time, yourselves in this presentation, a lot of focus on the decommissioning spend and the CCS projects that you have -- potential CCS projects you have in the U.K., are those areas that you would be seeking clarification on potential tax benefits or whatever within the existing EPL? Is that something we may be -- that may be in the discussions with the government?
Yes, absolutely, Mark. I mean we continue both directly ourselves at various levels of government and various departments and also through our industry association, continue to lobby and engage around the EPL and, in particular, in 2 or 3 areas.
Number one, bringing back, reinstating the commitment that the windfall profits tax will go away when we no longer have windfall profits being realized because prices are normal again, number one. Number two, fighting our corner around realized prices that even though market prices might be high, if somebody is hedged and we're not realizing extraordinary oil and gas prices, then why should we view tax at 75%. And then around the allowance, drawing the circle a little bit wider so that it can support investment for things like CCS is another logical area for us to be a proponent of in terms of changes or amendments to that.
The next question today comes from the line of Sasikanth Chilukuru from Morgan Stanley.
I had 2, please. The first was again related to the M&A. You've highlighted the criteria, which is -- which remains unchanged and it's quite clear. I just wanted to understand if there was a change in the potential scale of the acquisition. I was -- it was previously highlighted. Suppose that you're looking at establishing another core region potentially producing around 50,000 barrels of -- per day of production, I was just wondering if whether that was still valid. Is it something that we should be looking in terms of the scale of the acquisition?
Yes. Sasi, it's a good question. I would say, yes, the scale, our ambitions around scale and definition of how we think about scale haven't changed. We're still producing around 200,000 barrels a day. So if we think about what would be material for us is still in that ballpark of 50,000 barrels a day or more. So that ambition hasn't changed. I think you're right. On the one hand, our equity might be worth less. We might have less cash flow because of the tax rate. On the other hand, as Alexander explained, we're approaching net debt free. So we do have quite a bit of liquidity.
And also, as we think about what we might buy, they're going to be producing assets most likely. And those will have their own borrowing base that comes with them. So the combination of all of those things, I think means that we haven't changed our ambition around the size of things we look at.
Great. The second was more related to Slide 10, wherein you kind of presented the production -- our expected movement in production, particularly showing the natural declines offset by contribution from new wells. I was just wondering if you could comment on what to expect, especially regarding the contribution of these new wells as we look into 2024 and beyond.
You did highlight that the 2023 U.K. drilling program had been scaled back. I was wondering if it is scaled even further from 2024 onwards. And as a result, we should be expecting lower contribution from these new wells, and the decline rates of the overall portfolio is more closer to the natural decline rates. So any comments on that would be helpful.
Yes. Thanks, Sasi. If I'm looking at the rig schedule and thinking about the 2022 rig schedule, I think, actually, we're probably going to be bringing on about the same number of wells year-on-year. The one difference we have is Tolmount was in that new well contribution last year, and we don't have a major project coming on stream this year like we did then. So that's why we highlighted, in particular, on the 2022 part of that graph. But I think more -- I don't see material differences year-on-year when it comes to contributions from the new wells.
Looking ahead, it's a bit harder to say. I think it will depend this year on how quickly we're able to progress some of the attractive drilling opportunities we see for drilling in 2024. We did mention that Apache has dropped that drilling rig and Total decided not to drill the one well at Elgin Franklin. Hopefully, we come up with some ideas that will help offset the fact that we've lost those wells in the rig schedule. I just think it's a little bit too early to say at this point what our outlook might be for 2024.
The next question today comes from the line of Chris Wheaton from Stifel.
Three questions from me, please. Firstly, trying to link to Mark's question on M&A. But in terms -- in balance sheet terms, still political risk, as you've identified, Linda in the U.K. We don't know what the Labour party, should they win next election, will do to the windfall tax. We don't know if the windfall tax will be extended even under the current government. We're talking about hundreds of millions of dollars of volatility, therefore, in your posttax cash flows. What do you have to do differently to run your balance sheet now than before in terms of being able to keep capacity for M&A? One, you've got this uncertainty in your ongoing cash flow. That would be my first question, please.
Okay. Thanks, Chris. So I'll try to answer that one. I could answer it in different ways, I suppose. But one of the first big investments we did time-wise in 2021 was to make a big push to enter into the U.S. unsecured high-yield markets, and we did that, well, for different reasons.
First of all, it's just common sense to diversify your sources of funding of liquidity in a company the size of Harbour. But also, it's thinking a bit about the strategy and M&A. So we're very conscious about credit profile, credit rating, what's the feedback that we're getting from credit rating agencies but also diversifying those sources and recognizing that some banks are long term within oil and gas, whereas others are likely not going to be. So we can calculate borrowing base capacity on these things but factoring in geopolitical risks and not being solely reliant on a single geography that -- be that U.K. or the beautiful country of Norway or other places.
It is -- have -- being more diverse is good for that credit profile. So that will help as well, Chris. But we made that push into the U.S. high-yield markets because it's -- it was an investment in our part. So it's also a good source for future funding of any M&A. So that's the debt part. And I think we're also carefully trying to balance what a potential M&A opportunity looks like, the profile of it. And the profile, whether it be lots of production or a longer-dated production profile, well, that will probably factor in if it's more fundable by debt or equity or anything in between those 2.
I think maybe just a couple of things to add, Chris, would be when it comes to M&A, another criteria I should have mentioned in my list was looking for things that are credit-accretive to our own credit rating because, over time, we think it's a very obvious objective for us to have an ambition to get to an investment-grade credit rating, which addresses the question that you've asked. And so we do look at the pro forma credit metrics when we're looking at acquisitions and hoping -- aiming for one that -- acquisitions that take us in that direction.
And second, something that Alexander mentioned during his presentation was around opportunistic hedging. So we do look while we have lower requirements for hedging than we used to. By hedging some of our future volumes, we can lock in some additional borrowing base, and so we look for opportunistic -- very favorable opportunities to do that. So a number of tools, I guess, and things that we're doing.
And the overall amount of leverage you'd want now versus before, that's kind of the -- obviously, what I'm trying to do is think of the envelope in with -- the financial envelope in which M&A could happen, i.e., how much you've actually got to spend.
Yes. I mean we've -- when we set the -- trying to keep leverage between -- below 1.5x, that was thinking, yes, paying down debt, but we would try to stay below 1.5x here through the cycle and post M&A. I think we've said in the past that we could envision scenarios where post closing of such opportunity, we could get above 1.5x. But we'd want to see a pretty rapid path to deleveraging below that 1.5x.
Okay. I think we have time for just -- sorry, Chris, for just 1, maybe 2 more questions. One -- I'm told one.
Okay. I'll do 1 in 2, but I'll do 1 in 2 parts.
Yes. I meant -- sorry, Chris, I meant after you. Go ahead, and then we'll take one more question.
You said you need clarity from the government to progress CCS. Which -- what do you need from the government and by when do you need it in terms of being able to progress Viking and Acorn, which seem to be even really strategic projects with the U.K.? That's my first part of the question.
Secondly is going back to your comment on growing recovery factors. Help me understand what -- if you did want to go after that higher-recovery factor opportunity, what your CapEx and, therefore, decline rate might be on the sort of medium term, 3- to 5-year view in the U.K.
Yes. Thanks. On -- let me take the second question first. I think it's too early to say. In our subsurface group now, they're just really now getting focused on -- so I think we've got a lot of low-hanging fruit over the past few years and did some really fantastic infill and near-field drilling opportunities that have helped us with production. Now the work gets a little bit harder, not surprisingly year after year. But I'm hopeful that a lot of the opportunities could be relatively low CapEx. In fact, some of them could just be well interventions for all that we know at this point in time. Others of them could be things like enhanced oil recovery. So I think a bit too difficult to say at this point in time regarding the capital intensity of those.
On Viking and what do we need in Acorn is in a similar story. But Viking, I think, a bit more far advanced, and so the needs are clearer. The Viking system itself doesn't need government funding. Now our emitters do because they're looking for financial support from the government so that they don't lose money by capturing their CO2 emissions so that they're ready to give to us.
Our role then is transporting and storing them. What we need is the regulatory framework about that because at least part of our project will be regulated in terms of what we can charge. So we need to understand how that model is going to work. We need the government to assign, if you will, the emitters who have indicated support for our project to our project, and then we need the long-term government commitment around the long-term liability related to the storage.
So it's not a long list. We've made our list of needs very clear to the government. We're ready to go for Track 2. We are encouraging them to make the Track 2 process simpler and quicker than the Track 1, which has been fairly protracted. And we've made it clear to them that if we don't have the Track 2 process this year, ourselves and the emitters we're working with will have tough decisions to make about whether or not to continue our spending absence of government clarity because we will then begin outpacing the government and taking a lot more risk and the spend rate goes up as you get closer to FID. So we're trying to make it very clear to government that we need a response this year. And now one more question.
The final question today comes from the line of Matt Smith from Bank of America.
It's only time for one question, perhaps one thing I want -- wish to clarify, if I can, and perhaps one for you, Alexander, would be in relation to the cash tax guidance, the commodity prices that you set out. Just the fact that, I think, due to an idiosyncrasy, the majority of the EPL will be paid in '24, related to 2023. I was just wondering if you could indulge us what that number would be if the EPL payments would have followed the schedule that we would have otherwise expected?
Yes. Thanks, Matt. So just very quick, what is happening here is that as you probably know, Matt, we have different legal entities where production is sitting. And for one of these entities, where we have quite a bit of tax losses as well, there's -- we -- and I think maybe this is in a very tiny footnote on Page 24. But what's happening here is that the EPL payment here, it's -- it will not fall due until, I think, it's October in 2024 as opposed to the normal cycle of 2023. So some of the legal entities will be paying EPL in October 2023. But one of this will probably not -- most likely not pay that until October 2024. I think the amount in question here is approximately $250 million. So that is the sort of the numbers -- yes, the number effect of this. So -- but clearly, of course, it's a forecast, but that is then the adjustment.
Perfect. And I'll stay disciplined and avoid asking another question today.
Well, we can follow up separately with you, Matt.
Yes. Matt, to you and to all the others, please do. We're going to draw a line under this for now, but please do. You know how to reach out to Elizabeth and let her know if you have any other follow-up questions, and one or more of us happy to get on a call with you and take care of those. So thanks again for joining us this morning.