CFO Haakon Sandborg. After which we will open up for questions from shareholders and analysts. Managing Director Bjørn Dale and Chief Operating Officer Chris Spencer will also be available to provide answers. If you want to pose a question, please raise the tiny virtual hand on top of your screen. When chosen by the organizer, you will be notified on your screen that you are allowed to unmute, after which you will have to remember to unmute yourself too. With that, I leave the stage to the Executive Chairman.
Good morning. You might be wondering where I am and why I'm dressed the way I am. I'm in Kurdistan and in our field office at the Peshkabir field, which of course is one of the two fields in Kurdistan that we operate as part of the Tawke license, the two of Kurdistan's largest fields and very important of course to DNO and DNO's business, as well as to Kurdistan. It's great to be back in Kurdistan. While COVID remains an issue, it's become possible to travel a bit more easily.
I took the opportunity to travel here to see our team and spend some time with our operations people here in Kurdistan, who've done a fantastic job during the pandemic in keeping operations going and in a safe manner, in a healthy manner as much as possible, and they've been quite successful at that. Also to keep operations going, notwithstanding all of the problems that you're familiar with in terms of supply chains and travel restrictions and so on. I'm also here for some visits with the members of the Kurdistan Regional Government and also to visit our fields and our operations.
Peshkabir, of course, we started up our gas gathering and gas transports to Tawke and injection project, which is now humming along. You might occasionally hear in the background noises from the gas plant. Again, I'm pleased to be here and I'm pleased that Kurdistan is back in business and closer to normal following two years of difficult pandemic restrictions that have affected the industry in so many respects. I will start, as I usually do, with some operational and financial highlights, and then turn to Håkon, who will go into much greater detail on the financial results, both for the Q4 of 2021 and for the full year.
Hopefully, most of you have had a chance to either see our press release or to see our slide deck, and also the more detailed reports that were posted this morning on our website. I'll just highlight a number of points at beginning with operations. Jostein Løvås, if you'd please move us on to the next slide. Incidentally, that first cover picture was the signing ceremony with the KRG for the Baeshiqa exploration license, which we've been working on for several years to bring to this point. That was finally signed in December, and we're off and running with our activities in Baeshiqa, and I'll come back to that in a subsequent slide.
Our net production in 2021 was not too far off in Kurdistan compared to the prior year. It was down somewhat in the North Sea, the red part of the bar, but still, I think under the circumstances, given the pandemic constraints, we did quite well, considering also that we didn't do any significant drilling in the Tawke field in 2021 for different reasons that we can go into. Our North Sea production was down in part due to natural field decline, in part to delayed new production and planned maintenance. We were active in the North Sea in terms of exploration.
We were one of the more active companies in the North Sea than in the Norwegian sector, and we will continue to be so in 2022 and beyond. We drilled five exploration wells, four of which were discoveries, two technical discoveries, but two which we feel are very likely to be commercial and will be a focus of our activities in the North Sea. We have not yet released, but we hope to do so before the end of this month, our annual statement on reserves and resources. We do have the preliminary numbers, which we wanted to share with you.
We exited the year 2021 with 2P proven and probable reserves of 321 million barrels of oil equivalent and contingent resources 2C of 189 million barrels of oil equivalent. We are fast tracking now the development of Baeshiqa and expect early production hopefully in this quarter. We're gonna do this fast, the DNO way, and now that we've been given the green light to proceed. The next slide, please. In terms of financial highlights, and again, I'll leave it to Haakon to go into detail on these numbers.
Significantly, our revenues topped $1 billion last year, up 63% from the year earlier on the back of solid production, but also high oil and gas prices. Importantly, high oil and gas prices, and of course, this is the story of our industry overall. But we were also a beneficiary of that, and we were able to hit a $1 billion mark on the 50th anniversary of the founding of the company, and that's an important milestone about which my colleagues can be, and our shareholders can be, justly proud. We exited the year with a net debt of $153 million, which is down from $473 million a year earlier. We resumed the dividend payments.
We of course issued $400 million in new bonds, lowering our average interest rate and extending maturities, all of which, again, other companies by and large have done as well. On a cash basis, we received over $500 million in Kurdistan last year, allocated towards the entitlements and the overrides at payment arrears, but still have on the arrears side outstanding $169 million, which is down from $259 million at the end of 2020. We're chipping away at that.
These numbers exclude interest, and we remain in touch in discussions with the KRG to accelerate the payments on this debt and the terms and conditions under which the debt, the accelerated repayment will take place. Next one, please. This is the reserve side. The story remains pretty much as we last discussed it in terms of the composition and then the location of the reserves. Our 2P reserves are largely in Kurdistan. We have 321 million barrels of oil equivalents across the portfolio. Again, largely Kurdistan, but we also have 189 million barrels of oil equivalent, as I said a few minutes ago, in 2C reserves. Most of that is in Norway, but some also in Kurdistan.
Importantly, on Peshkabir, we're looking at a gas reinjection project, but also largely in Norway. We have some numbers, back-of-the-envelope numbers. Our 2P reserves at current production rates should last 9.3 years. You add the contingent, almost 15 years. It's getting harder to replace our reserves because we produce so much. In 2021, we produced over 30 million barrels of oil from our inventory. 30 million barrels is a size of 2P reserves of a lot of companies, small and things, even some mid caps. Finding 30 million, 40 million barrels a year every year consistently is not easy.
Our hope and expectation is that over a period of 3 years or so we're able to make discoveries, add reserves, move from the contingent into the 2P side to keep our reserve replacement ratio constant. The key to this in 2022 will of course be Baeshiqa, which, the contribution here that we have of Baeshiqa, is nominal, but as we start production and get a better sense of the productivity of the wells and the size and scale of the discoveries, I expect full well that we will have a reserve recovery situation. We had the same again understating the reserves, being very conservative, is how we started out with the Peshkabir.
We started very low numbers, and each year, as the field was further developed and we learned more about it, we kept increasing our Peshkabir reserves. This sort of approach is not unusual for us as a company. Again, once we have our year-end statement of reserves and resources completed and signed off on, we will share that, of course, with the market. Next, please.
In Kurdistan, our Tawke license production was largely unchanged, which is a bit of a miracle because we didn't do much drilling in Tawke for about 18 months. Because of the pandemic, we were sorting out budgets and getting budget approvals and preparing to hit the accelerator once again, which we've now done, and we're gonna move quite fast at Tawke this year. I think we have something like 17 or so wells planned in Tawke, and that'll, of course, help to recover Tawke production and hopefully keep our exit rates or average rates for the year where they were in 2021.
We thought maybe a little bit higher, a little bit lower, but we're very confident that the Tawke license will perform well in 2022. Even though we didn't have any significant drilling at Tawke for this 18-month period, we did inject quite a bit of gas from Peshkabir as part of our gas reinjection and carbon capture program. We injected in 2021 7.6 billion cubic feet. That's equivalent of 460,000 tons of CO2. We hit two birds with one stone, both in terms of CO2, but also, like, three birds in one.
Capture of gas for future use for enhanced field recovery and to energize the field, Tawke field, to be able to maintain production levels above where they would be, and that's part of the reason Tawke field did as well as it did during this period. We did some workovers. Our team was very good about going in and finding ways to tweak the plumbing and to do other things shy of drilling to keep production higher than where it would've been. Again, we think this is the DNO way. Again, I'm very proud of our teams for sustaining production under these difficult conditions. I've already discussed the production from the license from Baeshiqa.
We expect that over the course of the year, if we average out the production, once production starts, which I expect will be the case in this quarter, that we will have an average of 4,000 barrels of oil per day from Baeshiqa. That accounts for several months at the start of the year with no production. That means the production is gonna be higher. We're targeting maybe an exit rate twice that, but we don't know. We'll have to see how the Baeshiqa wells will perform. We're again bullish about Baeshiqa. That will be a good addition. We hope to our production portfolio. Of course, it's not just our production portfolio.
We have a partner, but also our most important partner in all these fields and projects is Kurdistan itself. They, like the companies and other governments, are looking for more production at these oil and gas prices, these oil prices in the case of Kurdistan. Everyone's incentivized to do more quickly in this very strong price environment. We're committed to being a part of that process. Next slide, please. I won't go into too much detail on this one. This is the Baeshiqa development. I think what's key here is that we drill two discovery wells on the license, one at Baeshiqa, one at Zartik.
The quality is a bit different, at least in the zones from which we produced. We had something on the order of 15,000 barrels. Now, this is not barrels a day, it's 15,000 barrels of 40-degree API oil from Baeshiqa, from the Baeshiqa discovery well, and 22-degree API oil from the Zartik discovery well, which we trucked to market at the time of discovery. We proved that the oil will flow to surface. That gave us a lot of confidence in terms of moving forward with the development plan, which again, has been approved now. Our plan is to re-enter these two discovery wells, put them on production, and then continue with the drilling of additional wells.
I think we have 3 new wells planned in 2022 on the Baeshiqa license. We'll be doing some seismic, but we'll be drilling 3 wells. In the end of the year, we hopefully will have 5 wells on production. That could be significant. Although again, we're cautious and we'll see how these wells perform, and we'll obviously report to the markets as we learn more. In the first instance, we will be trucking this oil to market using test facilities, and with time, we'll be putting in more permanent service facilities.
Eventually, depending on the size of the volume of production, we'll be putting in more permanent pipeline and other facilities to get the oil to the export into the export system. Next slide, please. North Sea, I mentioned that our net production was down, and I explained what some of the reasons were. We can go into more detail if there's interest in the Q&A session. We drilled seven wells. I already mentioned we drilled five exploration wells.
We drilled development wells and, importantly, the two that we believe have commercial potential in terms of size and in terms of proximity to existing infrastructure are the Røver Nord and the deeper Bergknapp discovery that was made in 2020. Importantly, DNO has been taking larger percentage interests in the new licenses. These are more meaningful to us, given the size of the company and our aspirations to grow the size of the company, grow our production levels. We are taking a larger interest in exploration wells and hope that'll pay out. We have several wells planned in 2022. These are in proven basins with moderate risk profiles.
We've continued to plug and abandon some wells and facilities and fields that we inherited at the time we did the Faroe acquisition. That's moving along at a good pace. It's a bit of a nuisance. There are some costs, but we're cleaning up the portfolio that we acquired and trying to sharpen our focus on the growth. Meaningful growth. Next, please. We're closing in on four PDO projects possibilities as part of the 2022 PDO. Brasa, of course, we've talked about quite a bit over the last several years, and you see this cartoon of the Brasa field and what we plan to do with it.
We have 50% of Brasa we operate, so we have some ability to manage that process. Our partner is Vår Energi. We have been in discussions with the host, Equinor, to bring the production into their infrastructure system and bring the Brasa production more rapidly. We reached a subsea frame agreement with TechnipFMC during the sort of low point of the pandemic where the industry activity was lower. We were able to line that up in terms of schedule and in terms of cost. We believe that'll give us an advantage in terms of proceeding with the Brasa project.
Elsewhere, there are other projects which we don't operate. There's the Iris/Hades discovery. There's the Gjøa discovery. Orion are all targets, three targets for 2022 project sanction. We have some statistics below in those boxes that I won't read, but they give you a sense of what's these were Brasa, what our initial targets are and thoughts are as to what Brasa will look like. Next, please. The next slide shows our North Sea 2022 exploration drilling. I referred to seven wells. You see, it's gonna be a busy year for us.
We have, for the most part, large interests in the wells that will be drilled, that are being drilled in our core area. They are drilled near infrastructure. We're hitting, checking all the right boxes, given, again, the size of the company and the circumstances in the markets. We, you know, we're very optimistic that we will again have discoveries and some of them meaningful in terms of the contributions of the companies. Initially resource figures and then ultimately the approved and probable category reserves. We're very excited about this. As I said, we're one of the most, the more and most active explorers in Norway now.
Very pleased to be in this position and committed to Norway and committed to exploration in Norway. Next, please. The biggest prospect that is in our exploration portfolio, we've talked about this before and others have as well, is the Edinburgh prospect that straddles the U.K.-Norway border. We have 45% of that prospect. Shell is the operator. It's a high-pressure, high-temperature well, and it'll drill a spot at least in the Q1 2022. So that's coming on up pretty fast. This is an exciting prospect. It's one of the largest undrilled structures in the North Sea. It's one of the reasons, well, a number of reasons why we were interested in the Faroe portfolio.
There's something, parts of that we weren't very keen on, some parts of it that we were keen on. This was one part that we were quite keen on, and we'll see how that goes. Again, this is being watched by a lot of people in the industry around the world as one of the largest prospects to be drilled and one of the most interesting exploration wells in 2022. I will say a few more words about some of the other activities in the North Sea. There's one last slide on this.
Following the Røver Nord success, part of our planning has been other wells in this area, which is near the giant Troll field. There are at least two wells that are scheduled in 2022 that have been de-risked somewhat by the Røver Nord discovery. This is again a focus area for us, but we're focusing on it more sharply and quite excited about these wells this year. Again, we have meaningful participating interest in these. If there are discoveries, they will be meaningful in terms of size and scale for DNO.
All in all, a lot of activity in the offshore Norway and with Edinburgh offshore in the UK as well. A lot of activity in Kurdistan with wells in Tawke. We have, I think, a 3-well program in Peshkabir, so we drill more wells in Peshkabir. Of course, the 3 new wells and the re-entry into the Baeshiqa wells in this year as well. It's a very active drilling year for us, very attractive prospects, we believe, and quite excited about what 2022 can bring to the company. With that, I'll ask Haakon to dive into the financial part of the presentation, and we'll be available for questions and answers.
Good. Thank you, Bijan . Hello again, everyone. We thank you for attending this earnings call. I think, with the return we have now of strong financial results last year, it's certainly good to get together again now and discuss the progress we made in 2021, and also, of course, talk a bit about our plans for the coming year. For the financial review, we're starting here with the key annual figures that we'd like to show. I know that it has been duly noted already today, but we are quite pleased and excited about going above $1 billion in revenue for the first time in our company history.
This is an important milestone for us that we will look forward to building on further as we move forward. The substantial revenue increase was driven by our sustained high production and the market recovery last year that really lifted the oil and gas prices from the very low levels that we saw in 2020. With the higher revenues, we also generated strong cash flows last year, including our after-tax net back that we show here. This climbed to a record level at $782 million. On the same basis, our operating profit is back up to a solid level of $321 million. That's compared to the big operating loss we had in 2020.
In short, 2021 was certainly a good year for us in DNO, with an especially strong finish in Q4. With the tighter market balances and increasing oil and gas prices that we see now, we think we have an even better starting point, and then a very promising outlook, for 2022. Next one, please. As we normally do, we look at the P&L table in some detail. We have the Q4 to the left, on the slide, and I will start with that before we go on to the full year. For the Q4, our revenues increased by 56% from Q3 to reach a high level of $396.5 million.
Kurdistan accounted for $180 million of these Q4 revenues, up from $149 million in Q3. Again, this is both on higher oil prices, but also higher entitlement volumes in our Kurdistan production. For our North Sea operations, revenues more than doubled from Q3 to $216 million in Q4. For the North Sea, the main drivers were the higher lifted oil cargoes or overlift in this quarter, with an effect of $62 million in Q4, but also higher gas prices that added $50 million of revenue in the quarter by itself.
This is all good, but as we move down on the left side on the Q4 numbers, you see on the cost side that the movements in overlift, underlift also adds $58.8 million in the cost then to our cost of goods sold, sort of catching up on the actual production cost here, tying that to the revenue. As we go down on the other expenses or costs, we see that the exploration is up from Q3. That's on higher expense well costs. This is for the Gomez and the Munin wells. But we also bought more seismic in the quarter that we expensed immediately.
As you can see, there is an impairment here of $27.3 million for this quarter, mainly on the Ula area in the North Sea. You know, even so, our Q4 operating profits still doubled to $128.2 million, backed by the higher revenues. One other key item I would mention in Q4 is that there is a significant increase in tax expense to $40.1 million, mainly explained by a taxable profit in DNO Norway or DNO Norge during Q4 as a result of the higher oil and gas prices compared to the tax loss we had in Q3 in this company. All in, we have a solid quarterly net income of $64.8 million for the quarter.
If you look on the right side on this slide, you have the full year P&L, and you can see the strong increase in revenues that we have discussed. That was achieved in 2021, up by 63% from 2020. Again, out of these total revenues, Kurdistan accounted for $594 million, up by $225 million from 2020. That was mainly on the higher oil prices. North Sea revenues, $410 million last year. They were up by $164 million from 2020, driven again by higher oil and gas prices, but partly offset by the lower volumes that we produced and sold. On the cost side, on the full year, we maintain our long-term positive profile on a stable and low production cost.
While DD&A costs were significantly reduced in 2021 by lower DD&A charges per barrel produced in the Tawke license. Otherwise, for the full year, exploration expense increased in 2021 on higher exploration well costs and also higher increased seismic purchases, seismic costs. Of course, this reflects our high exploration activity in our North Sea businesses. It's good to see that we have much lower impairments for 2021, and this is a big contribution to the improvement of the operating profit to the level of $320.9 million in 2021 compared to the substantial loss we had in 2020. With lower taxable losses, we show tax expense of $16.3 million last year compared to tax income of close to $140 million in 2020.
On a technical note, it should be said that a big share of the tax income in 2020 was due to the effects of deferred tax on deferred taxes from impairments. Really, that's a big part of the tax income for 2020. Anyway, to repeat, it's good to confirm the remarkable recovery in our P&L results last year and in total we show a solid net income for 2021 of $203.9 million. Go to the next slide. You know, however, as I think is often the case with our earnings presentation, the real fun in my view starts on this slide, where we again show some pretty good cash flow numbers.
As such, our cash flow from operations more than doubled last year to a solid level of $625 million, and that was mainly on the higher revenues. In addition, we received North Sea tax refunds of $175 million, so that the total cash inflow on a cash flow basis was at $800 million. The cash outflows that we show here were primarily for the investment activities at $362 million, split between exploration and CapEx at $276 million, and the North Sea decon at $86 million.
Under the finance outflows of $179 million, these items include the proceeds from our new $400 million bond that we did close in September, a payment of a shorter-dated bond in the same amount. Also, we paid $54 million on our RBL drawdowns in Q4. We had the dividend payment of $22 million also in Q4, and otherwise for the year, mainly transaction costs and interest expense on our bond and bank debt.
The main point here is that the strong cash flow from operations, again, funded these significant investments and finance outflows. With the support from tax refunds, also, we increased our cash balances by $260 million to a high level of $737 million at the year end. Next one. Okay, for the capital structure with this increase in cash balances, but also including the bank debt reduction that we had in Q4. Our net interest-bearing debt was cut by 68% last year to a modest level of $153 million at year-end. Also, important to the much improved earnings strengthened our equity ratio to 35% at the end of the year.
The bond refinancing in Q3 also then, as we have mentioned already, but it served to extend the debt maturities and to lower our debt costs going forward. On this basis, we are pleased to note that we clearly strengthened our balance sheet significantly in 2021. As we look forward now, there is currently an attractive macro environment and a positive outlook over the next years for the oil and gas industry. This is supporting the commodity pricing. With our solid production, we thereby expect to build further on our free cash flow and on our financial strength.
On this basis, we have good flexibility to both maintain our robust balance sheet, a key priority for us, but at the same time also step up investments for further growth, as well as look at ways of optimizing our capital structure going forward. Next one. Consequently for this year's investment program, we plan to ramp up our operational spend as we call it, the sum of these four categories of investments and costs to a level of $800 million, which is a big increase of $136 million from the year before.
Our program is focused on organic growth through extensive development spending, including now the first phase on our Baeshiqa project, and we stepped up the drilling in the Tawke license, as well as work on the four PDOs and ongoing development projects in the North Sea. CapEx thereby is up or will be up a lot this year to $320 million, split about 60/40 between Kurdistan and the North Sea. In addition and building on our successes last year, we also continue our broad North Sea exploration program with some key wells offering quite exciting resource potential this year. Total exploration expenditures amount to $150 million in this program.
While our OpEx, as mentioned, has been stable, there will be some increase this year to a level of around $255 million. This is as we start up the new production from the Baeshiqa license. Finally, we are planning abandonment expenditures or decom, if you want, of $75 million this year. This will be to finish up most of the remaining decom work on the Schooner and Ketch fields in the U.K., and also on the Oseberg field in Norway. It will be good to be done with this work soon. This will also free up the use of cash flow for other purposes going forward. Anyway, that's it for our presentation today. I hope you take away that we have an exciting year ahead of us.
As we see it, really good value creation potential, especially within exploration, but also within development, for this year. I'll hand it back to you, Jostein. I think we're opening up for Q&A at this point.
Thank you. We've already got a question, a person asking a question here, and that's Nikolas Stefanou from Renaissance Capital in London. Please go ahead, Nikolas.
Gentlemen, good morning and congrats on the very strong year. I've got three questions to ask, please. The first one is, if we can go back to Baeshiqa and what's gonna happen this year. I was a bit confused with the guidance. Is it? Are you going to produce from two wells but then drill another three and don't complete them? Or are we going to see five wells producing at the end of the year? Because I think you mentioned something like an 8,000 barrels per day exit rate, which, you know, I mean, sounds very low. How you know what I mean, clarify those comments, please. The second question is, I guess a bit more like, you know, guidance in the next two to three years in the North Sea.
Can you give me a sense of what kind of, like, CapEx we should be looking at in the North Sea? You know, assuming that those developments you mentioned do get sanctioned and where that might take production. Then the final one is, I guess for Håkon. Okay, I mean, there's been quite a few impairments over the past two years, which is understandable, but I would have expected some reversals given the sharper, like, rebound in the oil price. Usually, you know, this is the quarter most companies do this. Why have we not seen this? You know what I mean? If you can kind of comment on that as well, please. Thank you.
Yeah. The first one, Bijan.
I believe Bijan has to unmute himself.
Am I okay now?
Yeah.
Somebody muted me. They don't often get to mute me at DNO, but somebody did this time. Anyway, Nicholas, thank you for your questions. Let me address the Baeshiqa one first because it's physically the closest to it, right? It's just next door here. Well, not exactly next door, but I'm in the vicinity. Then I will turn to my other colleagues to comment on the other questions in terms of the North Sea and impairments and so on. On the Baeshiqa, our numbers are quite conservative. Both in terms of what we discuss internally, but certainly what we report to the market.
We've typically been quite conservative in our figures. We underpromise and overproduce rather than the other way around. Yes, we will start production from the two discoveries. Those were left in a temporary status that would allow us to reenter and start producing pretty quickly. We're gonna do that. We're committed to drilling three wells. You'll see that on the chart that's on the screen now. The third well will be spudded in 2022, but may push into 2023, the part of 2023, depending on, again, how much testing we do and what sort of else goes on with the other wells.
Because reentering two wells and drilling two, another two wells creates a scheduling issue. We may go faster, we may go slower. Certainly the intent is to spud Baeshiqa-3. Maybe we can put on production, I don't know. We're being conservative about that. We're not these aren't shale wells where you complete and then walk away from them or not complete. We're gonna, you know, our plan is to drill them, complete them, frack them, complete them. Frack them as necessary, or acidize, perhaps is more appropriate in this context, and put them on production. We wanna get production out as fast as we can. We have every reason to do so. We have every incentive to do so.
We've been encouraged by the government to do so. Everything's fast-tracked. Whether it's 4 wells on production or 3 wells on production, 4 or 5, we'll just see how it goes. Some of that uncertainty also leads to some confusion as to what our production rates are. We've given an average for the year rates. I refer to an exit rates of around 10,000 or so. That's a sort of internal target that I'm sharing with you. There is uncertainty. What is certain is that we have discoveries, at least two important discovery wells drilled on this, which we're gonna put on production. That's for sure. We're committed to a fast development, that's for sure.
We're not gonna wait to drill many wells and then start production once the service facilities are installed, which may take years. That's how large companies typically work. In Kurdistan, our success isn't based on the fact that we come in and we drill. We put a discovery in production and use the revenue to drill the second well and the third well and keep going. In the appropriate time, when we have sufficient size and scale of production to put in more permanent facilities, both on the field and in terms of pipelines and so on. There'll be no holding back. There's no reason to hold back. We'll charge ahead as fast as we can. Again, we'll report to the market as we proceed.
This is a new field for us, and we'll have to wait and see how it performs before we give more definitive numbers, higher or lower or different. If you bear with us, you will find out soon enough, sooner than most companies do. You can also be assured that we are very excited about this, about the Baeshiqa license. The previous operator and owner, Ekton, was very excited about this license and the possibilities. This is part of our business in Kurdistan. Hopefully Baeshiqa will become a very important part of our business in Kurdistan. The Tawke field is a mature field, and it's started to go into decline, as mature fields do.
We've tried to stabilize that decline through gas injection and through, again, some of the plumbing that we do and the work with
With pumps and other sort of tricks of the trade. With the new drilling this year of 17 wells, we hope to stabilize it. Peshkabir is a newer field. It still has some growth potential. We're also looking at deeper Triassic horizon at Peshkabir. We're going to look at the deeper horizon, Triassic in Tawke. Maybe there's something there that would generate some excitement and some additional production. Baeshiqa, we view as the future of an important part of the future of DNO in Kurdistan. We're committed to make that happen and to spend what it takes and build the necessary pipeline to it, which we've done. We're very excited about it. That's it.
Thank you.
Question. Chris, would you like to do it? If you're silent, I'll unmute you.
Yes, thank you. Yes, the question was on the development portfolio in the North Sea, if I remember correctly. As Bijan explained during the presentation, we have a very exciting year in Norway with working very hard to get plans for development and operation delivered on four potential developments. That's really our key focus at the moment. We're working very hard to make sure those are successfully delivered. I think we'll return to guidance with respect to any CapEx and forward and breakeven, and so forth later in the year once we are more confident that those projects will be moving forward. With respect to the production impact, I think we gave some indication on the slide with respect to Brasa. That's maybe of some help.
I think we are focused on also that this year is not a one-off in terms of development portfolio. Bijan mentioned the two exciting discoveries we had last year. We're working hard to make sure that they're moving forward towards development, and we hope to have further discoveries this year to add to that development pipeline.
Thank you.
I guess, yeah, I had a third question, Nicholas, on impairments, and why don't we see any reversals sometime soon. Yeah, that's a good question. We do have at least one very strong candidate on the reversal that we have conservatively sort of wanted to be absolutely sure before we put that into our reporting and financial statements. But there may be others as well, but not quite ready to give you their names or their fields and all that. Once we are sort of through all the decision gates, DG3, et cetera, and things are firmed up, I think we'll be in good position to come back with also announcing at least one reversal, maybe more later in the year.
Around the impairments, of course, we have done quite a few. Some of it has been, you know, tied to the Schooner and Ketch cost situation where we have had impairments. As we talked about, we're mostly done well with the most of the work on those large projects. I think at least that risk goes away quite significantly at the end of this year when we're done with those projects. We'll come back to you on the possible reversals, which is a good discussion.
Thank you.
I think the next question here comes from Teodor Sveen-Nilsen from SpareBank 1 Markets.
Good morning, and thanks for taking my questions. Three quick questions from me. First, on the lifting cost on NCS in Q4, is the level you reported for Q4 something that we should expect going forward? Second question is on Baeshiqa. I just wonder, are there any big differences in the PSA terms compared to the Tawke PSA? Third and last question is just on the OpEx guidance for 2022, is it possible to shed some light on what that corresponds on a per barrel basis? That's all. Thanks.
Could you say that first question again? I didn't catch the full question on the first point, Teodor.
Yes, sure. First question is related to NCS lifting costs. Should we interpret the Q4 lifting cost as a normalized lifting cost going forward, including the cost of the overlift?
Yeah, that's a good question on what it was. RC 14.4 per barrel. I don't know, Chris, the team, do we have a view on that? I would say it's. What's the annual average was, when we count that? 17.9 and going down a bit in Q4. I would think that once we see some of the, maybe not so much this year, but later on when we have new fields coming on stream, the other one that you will see that coming down. I don't know. I think it would be fairly well to a fairly good assumption to assume it's around what we can see and expect for this year, what you have in Q4. I don't know if you had a comment on that, anybody else? Chris?
Well, it's always a tricky one for a dumb engineer like me because it's this variability with the liftings as well that makes it technically a bit difficult to track. Obviously the sort of proportion of revenues that are associated with the lifting costs in the North Sea stay constant. It's just the variability in liftings, I think that make it difficult to track.
I'll answer the question about the Baeshiqa PSC. Yes, there are differences. I think, by and large, the Kurdish PSCs cluster around the same numbers are similar, but with time they've been some changes. The Tawke PSC is one of the first to be signed. The ExxonMobil one's one of the last to be signed. With time, the PSCs have been tightened, and so on. They all cluster roughly around the same place in terms of the economics of these. What makes them different, historically, the different PSCs has been the level of the signature bonuses that have been paid on these PSCs.
ExxonMobil paid a significant signature bonus for the six blocks that it took in Kurdistan, and an important part of that was the Baeshiqa block. Their economics factored that in. Ours hasn't because that was paid by ExxonMobil. In that sense, the same PSC is more attractive to us than it was to the previous operator and the license holder. The PSC is even more attractive to us because the cost pool, ExxonMobil's prior costs that were expended are counted as part of our cost pool. That will make the economics a bit again more attractive.
We didn't have to pay the signature bonus, and we had the opportunity to recover the cost. Our accounts look different, and it should be attractive. Although, if you look at them again, the line items, probably the top PSC on some of the metrics is somewhat more attractive than ExxonMobil's. Again, by and large, the Kurdistan PSCs cluster around the same sort of numbers for cost oil and profit oil and so on.
So
If we have a good discovery, it'll be very economic to develop.
I believe there are two more people that wanted to ask questions before we
Jostein Løvås, I think the third question, Teodor Sveen-Nilsen, in your OpEx per barrel going forward.
Yes, that's correct.
It looks like it on a per barrel basis will increase somewhat year-over-year. You know, we talked about Kurdistan being stable and low for many years. It's been quite remarkable and good achievement for us. As you know, we're running just over $3 per barrel lifting cost, which is more or less all in OpEx per barrel. That is among the lowest you will see anywhere. We maintain that for the two current producers, Tawke field and Peshkabir field. I don't think there will be any changes on that. There, as I mentioned, there is a new field coming in or fields from the Baeshiqa license. There will be some increase on the average basis for Kurdistan with the new production coming in from Baeshiqa, but not that much.
We expect that once we see that production coming on from our new development, that they will be approaching the very low levels that we have already from our two current producers. We talked about the North Sea OpEx already. I think we covered that question, if that's okay.
Yes, thank you.
Two people wanting to ask questions before we close the meeting. The first one is Fredrik Schjøtt-Pedersen from ABG Sundal Collier. Please.
Hi guys. Thank you for taking my questions. One question regarding the split of CapEx between Baeshiqa or between Peshkabir and Tawke, I guess. Could you elaborate on how CapEx spending is allocated between the two fields? And second, in terms of exploration costs, is that entire amount related to activities in the North Sea?
Yeah. Let me just find that first question. I have that somewhere. You know, I think we guided you on the CapEx for the years. It's around Kurdistan CapEx is around just under $200 million. Most of that will be for drilling on Tawke and Tawke facilities, I mean, Tawke license, including Peshkabir. Out of the $200 or so, you know, large majority is for the development of our existing producers. I'm not really able to give you detail on the Baeshiqa, but say it's around 20% out of that. You know, there's a rough guidance on the $200 for Baeshiqa CapEx spending this year, just to give an idea. You know, plus or minus.
That's okay. If you look at these numbers, it's amazing that, for so little money we're doing so much activity in Kurdistan. I mean, 17 wells somewhere else would cost a lot more than we sort of perfected that in Kurdistan at Tawke field itself. We drill wells for well under $10 million a well now. Peshkabir is deeper, a bit more expensive, although we now got the handle on that and with the experience that the early wells and the new wells that we'll drill at Peshkabir will be more costly, but with time, again, we'll find the right way to do that as well. We're like DNO's like an artificial intelligence machine.
You know, we learn as we go, and we apply the learnings and get better and smarter and more efficient as we go. When you look at those numbers, the level of activity we're doing for those numbers is quite impressive by any standard. That's again to the earlier question about the quality of the PSCs. I mean, the Kurdistan PSCs aren't the most attractive PSCs I've seen in the world. I mean, they're tough. They're tough. What's made Kurdistan special, it's the fact that it hadn't properly been explored. There are opportunities to go in and do the exploration of prospective areas and make discoveries, which DNO did.
Our success has been not because the PSCs are incredibly attractive, and they're not. It's because what we were able to do in finding the oil and putting it on production quickly and at low cost that made it work for us. Notwithstanding the fact that the PSCs aren't the most attractive in the world, and notwithstanding the fact that Kurdistan, as you all know, is landlocked, so we pay quite a discount to get the oil to market. Even considering all of that, we've done very well because we've done things the DNO way, and that keeps coming across, I think, in our presentations and in our activities.
With that, I will go back to my tour of the Peshkabir gas plant and eventually lunch with our operational people. It's a beautiful, cool day here, and it's just great to be back, and it's great to see Kurdistan back again and open for investments. We're looking for other opportunities in Kurdistan as well. This is an important area for us. We're comfortable being here. There are challenges, but I think we feel that we are able to do things, and our efforts are appreciated by the government and by the communities and other stakeholders with whom we work here in Kurdistan.
It's a very welcoming place to DNO, and DNO is doing its part for Kurdistan as well. Thank you for participating. I think we had a large group on the call, and we'll see you on the next call, which I hope will be, I'll be in Norway after 2 or some years, and that, COVID will calm down in Norway and the world will be a lot more normal a place than it's been for the last 2 years. Thank you for your support during this period and your interest in our activities. Okay. Thank you.